As filed with the Securities and Exchange Commission on April 21, 2011

Registration No. 333-            

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form S-4

REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

LG&E and KU Energy LLC

(Exact name of registrant issuer as specified in its charter)

Kentucky	4931	20-0523163
(State or other jurisdiction	(Primary Standard Industrial	(I.R.S. Employer
of organization)	Classification Code Number)	Identification Number)

220 West Main Street
Louisville, Kentucky 40202
(502) 627-2000

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

John R. McCall

Executive Vice President, General Counsel, Corporate Secretary

and Chief Compliance Officer
220 West Main Street
Louisville, Kentucky 40202
(502) 627-2000

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies of communications to:

Catherine C. Hood
Dewey & LeBoeuf LLP
1301 Avenue of the Americas
New York, New York 10019
(212) 259-8000

Approximate date of commencement of proposed exchange offers:  As soon as practicable after this Registration Statement is declared effective.

If the securities being registered on this form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, please check the following box.  ¨

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer x Smaller reporting company ¨

(Do not check if a smaller reporting company)

If applicable, place an X in the box to designate the appropriate rule provision relied upon in conducting this transaction:

Exchange Act Rule 13e-4(i) (Cross-Border Issuer Tender Offer)  ¨

Exchange Act Rule 14d-1(d) (Cross-Border Third-Party Tender Offer)  ¨

CALCULATON OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Amount to be Registered	Proposed Maximum Offering Price per Note	Proposed Maximum Aggregate Offering Price(1)	Amount of Registration Fee
2.125% Senior Notes due 2015	$400,000,000	100%	$400,000,000	$46,440.00
3.750% Senior Notes due 2020	$475,000,000	100%	$475,000,000	$55,147.50

(1)   Estimated solely for the purpose of calculating the registration fee under Rule 457(f) of the Securities Act of 1933, as amended.

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed.  We may not complete the exchange offers or sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED                            , 2011

PRELIMINARY PROSPECTUS

LG&E AND KU ENERGY LLC

Offers to Exchange

$400,000,000 aggregate principal amount of its 2.125% Senior Notes due 2015 and
$475,000,000 aggregate principal amount of its 3.750% Senior Notes due 2020 (together, the Exchange Notes),
each of which have been registered under the Securities Act of 1933, as amended,
for any and all of its outstanding
2.125% Senior Notes due 2015 and 3.750% Senior Notes due 2020 (together, the Outstanding Notes), respectively
(such transactions, collectively, the Exchange Offers).

We are conducting the Exchange Offers in order to provide you with an opportunity to exchange your unregistered Outstanding Notes for the Exchange Notes that have been registered under the Securities Act.

The Exchange Offers

·We will exchange all Outstanding Notes that are validly tendered and not validly withdrawn for an equal principal amount of Exchange Notes that are registered under the Securities Act.

·You may withdraw tenders of Outstanding Notes at any time prior to the expiration of the Exchange Offers.

·The Exchange Offers expire at 5:00 p.m., New York City time, on               , 2011, unless extended.  We do not currently intend to extend the Expiration Date.

·The exchange of Outstanding Notes for Exchange Notes in the Exchange Offers will not be a taxable event for US federal tax purposes.

·The terms of the Exchange Notes to be issued in the Exchange Offers are substantially identical to the Outstanding Notes of the respective series, except that the Exchange Notes will be registered under the Securities Act, and do not have any transfer restrictions, registration rights or liquidated damages provisions.

Results of the Exchange Offers

·Except as prohibited by applicable law, the Exchange Notes may be sold in the over-the-counter market, in negotiated transactions or through a combination of such methods.  There is no existing market for the Exchange Notes to be issued, and we do not plan to list the Exchange Notes on a national securities exchange or market.

·We will not receive any proceeds from the Exchange Offers.

All untendered Outstanding Notes will remain outstanding and continue to be subject to the restrictions on transfer set forth in the Outstanding Notes and in the indenture governing the Outstanding Notes.  In general, the Outstanding Notes 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 Notes under the Securities Act.

Each broker-dealer that receives Exchange Notes for its own account in the Exchange Offers must acknowledge that it will deliver a prospectus in connection with any resale of those Exchange Notes.  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 Notes received in exchange for Outstanding Notes where the broker-dealer acquired such Outstanding Notes 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 12 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 Notes 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.

The date of this prospectus is          , 2011.

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 Notes 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 LG&E and KU Energy LLC specifically or, if the context requires, to LG&E and KU Energy LLC and its subsidiaries, collectively.

TABLE OF CONTENTS

Summary	1
Risk Factors	12
A Warning about Forward-Looking Statements	19
Use of Proceeds	21
Capitalization	21
Selected Consolidated Financial Data	22
Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	56
Quantitative and Qualitative Disclosures about Market Risk	56
Business	57
Management	72
Executive Compensation	74
Transactions with Related Persons	112
The Exchange Offers	113
Description of the Exchange Notes	124
Material U.S. Federal Income Tax Consequences	138
Plan of Distribution	142
Legal Matters	142
Experts	142
Available Information	143
Index to Consolidated Financial Statements	144

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SUMMARY

This summary highlights certain information concerning the Company, the Exchange Offers and the Exchange Notes 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.

LG&E and KU Energy LLC

LG&E and KU Energy LLC, formerly E.ON U.S. LLC, is a wholly owned subsidiary of PPL Corporation.  Formed in 2003, we are a holding company and our energy and utility operations are conducted through our subsidiaries, Kentucky Utilities Company, or KU, and Louisville Gas and Electric Company, or LG&E, which constitute substantially all of our assets.  LG&E and KU are regulated public utilities engaged in the generation, transmission, distribution and sale of electric energy.  LG&E also engages in the distribution and sale of natural gas.  LG&E and KU maintain their separate identities and serve customers in Kentucky under their respective names.  KU also serves customers in Virginia under the Old Dominion Power name, and it serves customers in Tennessee under the Kentucky Utilities name.

KU provides electric service to approximately 514,000 customers in 77 counties in central, southeastern and western Kentucky, to approximately 30,000 customers in five counties in southwestern Virginia and to fewer than 10 customers in Tennessee.  KU also sells wholesale electric energy to 12 municipalities in Kentucky.  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.  During 2010, approximately 98% of the electricity generated by KU, and 95% of that generated by LG&E was produced by their coal-fired electric generating stations.  The remainder was generated by natural gas and oil fueled combustion turbines, or CTs, and hydroelectric power plants.  LG&E’s gas business purchases, transports, distributes or stores natural gas for approximately 320,000 customers in Kentucky.

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

Recent Developments

2010 Electric and Gas Rate Cases

In January 2010, LG&E and KU filed applications with the Kentucky Public Service Commission, or the Kentucky Commission, requesting increases in electric base rates of approximately 12%, or $95 million and $135 million annually, respectively.  In addition, LG&E requested an increase in its gas base rates of approximately 8%, or $23 million annually.  A number of intervenors entered the rate cases, 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 the requested rate increases of LG&E and KU, in whole or in part.  In June 2010, LG&E and KU and all of the intervenors except for the Kentucky Attorney General agreed to stipulations providing for increases in LG&E’s and KU’s electric base rates of $74 million and $98 million annually, respectively, and LG&E’s 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 stipulations, including a return on equity range of 9.75-10.75%.  The new rates became effective on August 1, 2010.

2011 Virginia Rate Case

In April 2011, KU filed an application with the Virginia State Corporation Commission, or the Virginia Commission, requesting an increase in base rates of approximately 14%, or $9 million annually.  The requested rate increase is based on an 11% return on equity, inclusion of expenditures to complete Trimble County Unit 2, or TC2, all new flue gas desulfurization controls in base rates, recovery of a 2009 regulatory asset and various other adjustments to revenue and expenses for the test year ended December 31, 2010.  We cannot predict the outcome of this proceeding.

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PPL Acquisition

On November 1, 2010, we became a wholly owned subsidiary of PPL Corporation when PPL acquired all of our outstanding limited liability company interests from E.ON US Investments Corp.  Following the acquisition, the businesses of our two operating subsidiaries, LG&E and KU, have not changed and they are continuing as our subsidiaries.

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, nor any of our subsidiaries (including LG&E and KU), will be obligated to make payments on, or provide any credit support for, the Exchange Notes.

PPL Acquisition Approvals

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 the Company, LG&E and KU.  In the settlement, the parties agreed that LG&E and KU would commit that no base rate increases would take effect before January 1, 2013.  A rate increase for LG&E and KU 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, LG&E and KU 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 LG&E and KU 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 and KU to each 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.  In October 2010, both the Virginia Commission and the Tennessee Regulatory Authority approved the transfer of control of the Company from E.ON US Investments Corp. to PPL.  The orders of the commissions contained a number of other commitments with regards to operations, workforce, community involvement and other matters.

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In October 2010, the Federal Energy Regulatory Commission, or FERC, approved a September 2010 settlement agreement among KU, LG&E, 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 agreement not to terminate certain KU municipal customer contracts prior to January 2017, an exclusion of any transaction-related costs from wholesale energy and tariff customer rates to the extent that LG&E and KU 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.

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The Exchange Offers

In November 2010, we issued the Outstanding Notes in transactions not subject to the registration requirements of the Securities Act of 1933, as amended, or the Securities Act.  The term “2015 Exchange Notes” refers to the 2.125% Senior Notes due 2015 and the term “2020 Exchange Notes” refers to the 3.750% Senior Notes due 2020, each as registered under the Securities Act, and all of which collectively are referred to as the “Exchange Notes.”  The term “Notes” collectively refers to the Outstanding Notes and the Exchange Notes.

General	In connection with the issuance of the Outstanding Notes, 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 Notes.  You are entitled to exchange in the Exchange Offers your Outstanding Notes for the respective series of Exchange Notes that are identical in all material respects to the Outstanding Notes except:
	·    the Exchange Notes have been registered under the Securities Act and, therefore, will not be subject to the restrictions on transfer applicable to the Outstanding Notes (except as described in “The Exchange Offers — Resale of Exchange Notes” and “Description of the Exchange Notes — Form; Transfers; Exchanges”);
	·    the Exchange Notes are not entitled to any registration rights which are applicable to the Outstanding Notes under the registration rights agreement, including any rights to liquidated damages for failure to comply with the registration rights agreement; and
	·    the Exchange Notes will bear different CUSIP numbers.
The Exchange Offers	We are offering to exchange:
	·   $400,000,000 aggregate principal amount of 2.125% Senior Notes due 2015 that have been registered under the Securities Act for any and all of our existing 2.125% Senior Notes due 2015 and
	·   $475,000,000 aggregate principal amount of 3.750% Senior Notes due 2020 that have been registered under the Securities Act for any and all of our existing 3.750% Senior Notes due 2020.
	You may only exchange Outstanding Notes in minimum denominations of $2,000 and in multiples of $1,000 in excess thereof.  Any untendered Outstanding Notes must also be in a minimum denomination of $2,000.

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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 Notes issued pursuant to the Exchange Offers in exchange for the Outstanding Notes 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 Notes 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 Notes.
	Any holder of Outstanding Notes who:
	·    is our affiliate;
	·    does not acquire Exchange Notes in the ordinary course of its business; or
	·    tenders its Outstanding Notes in the Exchange Offers with the intention to participate, or for the purpose of participating, in a distribution of Exchange Notes
	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 Notes.

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	If you are a broker-dealer and receive Exchange Notes for your own account in exchange for Outstanding Notes 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 Notes and that you are not our affiliate and did not purchase your Outstanding Notes from us or any of our affiliates.  See “Plan of Distribution.”
	Our belief that the Exchange Notes 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 Note 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          , 2011, unless extended by us.  We do not currently intend to extend the Expiration Date.
Withdrawal	You may withdraw the tender of your Outstanding Notes at any time prior to the expiration of the Exchange Offers.  We will return to you any of your Outstanding Notes 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 Notes.  See “The Exchange Offers — Conditions to the Exchange Offers.”

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Procedures for Tendering Outstanding Notes	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 Notes to be exchanged for Exchange Notes, to the exchange agent at the address set forth on the cover page of the letter of transmittal; or
	·    if you hold Outstanding Notes 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 Notes 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 Notes within the meaning of the Securities Act;
	·   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;
	·   if you are not a broker-dealer, that you are not engaged in, and do not intend to engage in, the distribution of the Exchange Notes and;
	·   if you are a broker-dealer, you will receive Exchange Notes for your own account in exchange for Outstanding Notes 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 Notes.
Special Procedures for Beneficial Owners	If you are a beneficial owner of Outstanding Notes that are registered in the name of a broker, dealer,

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	commercial bank, trust company or other nominee, and you wish to tender those Outstanding Notes in any of the Exchange Offers, you should contact the registered holder promptly and instruct the registered holder to tender those Outstanding Notes 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 Notes, either make appropriate arrangements to register ownership of the Outstanding Notes 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 Notes and your Outstanding Notes are not immediately available, or you cannot deliver your Outstanding Notes, 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 Notes according to the guaranteed delivery procedures set forth in this prospectus under “The Exchange Offers — Guaranteed Delivery Procedures.”
Effect on Holders of Outstanding Notes	As a result of the making of, and upon acceptance for exchange of all validly tendered Outstanding Notes 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 Notes under the circumstances described in the registration rights agreement.  If you do not tender your Outstanding Notes in any of the Exchange Offers, you will continue to be entitled to all the rights and limitations applicable to the Outstanding Notes 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 Notes under the registration rights agreement.  To the extent that Outstanding Notes are tendered and accepted in the Exchange Offers, the trading market for Outstanding Notes that are not so tendered and accepted could be adversely affected.
Consequences of Failure to Exchange	All untendered Outstanding Notes will remain

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	outstanding and continue to be subject to the restrictions on transfer set forth in the Outstanding Notes and in the Indenture.  In general, the Outstanding Notes 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 Notes under the Securities Act.
United States Federal Income Tax Consequences	The exchange of Outstanding Notes 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 Notes 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.”

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The Exchange Notes

The summary below describes the principal terms of the Exchange Notes.  Certain of the terms and conditions described below are subject to important limitations and exceptions.  The “Description of the Exchange Notes” section of this prospectus contains more detailed descriptions of the terms and conditions of the Outstanding Notes and Exchange Notes.  The Exchange Notes will have terms identical in all material respects to the respective series of Outstanding Notes, except that the Exchange Notes 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	LG&E and KU Energy LLC, a Kentucky limited liability company.
Securities Offered	$400,000,000 of 2015 Exchange Notes
	$475,000,000 of 2020 Exchange Notes
Maturity Date	The 2015 Exchange Notes will mature on November 15, 2015.
	The 2020 Exchange Notes will mature on November 15, 2020.
Interest Rate and Payment Dates	The 2015 Exchange Notes will bear interest at the rate of 2.125% per annum, payable semi-annually in arrears on each May 15 and November 15, commencing                      15, 2011.
	The 2020 Exchange Notes will bear interest at the rate of 3.750% per annum, payable semi-annually in arrears on each May 15 and November 15, commencing                      15, 2011.
	Interest will accrue on the Exchange Notes of each series from the most recent date to which interest has been paid or, if no interest has been paid, from November 12, 2010.
Optional Redemption	We may redeem the Exchange Notes 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 Notes — Redemption.”
	We may redeem, in whole or in part, Exchange Notes of either or both series.
Ranking	Each series of Exchange Notes will be our senior unsecured indebtedness and will rank equally in right of payment with our other existing and future unsecured senior indebtedness.  We are a holding company and conduct substantially all of our business operations through our subsidiaries.  As a holding company, we have no material assets other than our ownership of the common stock of our subsidiaries.  The Exchange Notes will be effectively subordinated to existing and future liabilities and obligations of our subsidiaries.  At December 31, 2010, we had $875 million of outstanding indebtedness, and our subsidiaries had $3.13 billion of outstanding indebtedness.

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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 Notes, see “Description of the Exchange Notes — Events of Default.”
Further Issuances	We may, without the consent of the holders of a series of the Exchange Notes, increase the principal amount of the series and issue additional Exchange Notes 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 Notes.  Any such additional notes would, together with the existing Exchange Notes of such series, constitute a single series of securities under the Indenture (as defined in “Description of the Exchange Notes — General”) and may be treated as a single class for all purposes under the Indenture, including, without limitation, voting, waivers and amendments.
Company Obligations	Our obligations to pay the principal of, premium, if any, and interest on the Exchange Notes are solely obligations of the Company and neither our parent company nor any of their or our subsidiaries or affiliates will guarantee or provide any credit support for our obligations on the Exchange Notes.
Denominations	Minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof.
Form of Notes	The Exchange Notes will be issued in fully registered book-entry form and each series of Exchange Notes 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 notes, except in limited circumstances described herein.  See “Description of the Exchange Notes — Book-Entry Only Issuance — The Depository Trust Company.”
Trustee	The Bank of New York Mellon
Absence of Established Market for the Exchange Notes	We do not plan to have the Exchange Notes listed on any securities exchange or included in any automated quotation system.  There is no existing trading market for the Exchange Notes.  If no active trading market develops, you may not be able to resell your Exchange Notes at their fair market value or at all.  Future trading prices of the Exchange Notes will depend on many factors including, among other things, prevailing interest rates, our consolidated operating results and the market for similar securities.  No assurance can be given as to the liquidity of or trading market for the Exchange Notes.
Risk Factors	You should refer to the section entitled “Risk Factors” beginning on page 12 for a discussion of material risks you should carefully consider before deciding to exchange your Outstanding Notes.

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RISK FACTORS

An investment in the Notes, including a decision to tender your Outstanding Notes 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 Notes.  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.

Risks related to Our Operations

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

Our business is subject to significant and complex governmental regulation.

Various federal and state entities, including, but not limited to, the FERC, the Kentucky Commission, the Virginia Commission and the Tennessee Regulatory Authority, regulate many aspects of the utility operations of LG&E and KU, including the following:

·the rates that we may charge and the terms and conditions of our service and operations;

·financial and capital structure matters;

·siting and construction of facilities;

·mandatory reliability and safety standards and other standards of conduct;

·accounting, depreciation and cost allocation methodologies;

·tax matters;

·affiliate restrictions;

·acquisition and disposal of utility assets and securities; and

·various other matters.

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 the rate requests of LG&E and KU, and ultimately reduce, alter or limit the rates they seek.

Our profitability is highly dependent on the ability of LG&E and KU to recover the costs of providing energy and utility services to their customers and earn an adequate return on their capital investments.  They currently provide services to their 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 LG&E and KU are allowed to charge may or may not match their 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 the 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 LG&E’s and KU’s costs are not adequately recovered through rates, it could have an adverse affect on our business, results of operations, cash flows or financial condition.

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In connection with the PPL acquisition, each of LG&E and KU has agreed, subject to certain limited exceptions such as fuel and environmental cost recoveries, that no base rate increase would take effect for their Kentucky retail customers before January 1, 2013.  See “Summary — Recent Developments — PPL Acquisition Approvals.”

Transmission and interstate market activities of LG&E and KU, as well as other aspects of the businesses, are subject to significant FERC regulation.

LG&E and KU are 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 the earnings, operations or other activities of LG&E and KU.

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 LG&E and KU 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 businesses are capital intensive and require 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:

·approval, licensing and permitting;

·land acquisition and the availability of suitable land;

·skilled labor or equipment shortages;

·construction problems or delays, including disputes with third party intervenors;

·increases in commodity prices or labor rates;

·contractor performance;

·environmental considerations and regulations;

·weather and geological issues; and

·political, labor and regulatory developments.

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

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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.

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.

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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 businesses are 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 businesses are concentrated in the Midwest United States, specifically Kentucky.

Although KU also operates in Virginia and Tennessee, the businesses of LG&E and KU are 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; aluminum and steel smelting and fabrication; chemical and rubber processing; coal, mineral and ceramic-related activities; educational institutions; health care facilities; paper and pulp processing; 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 businesses efficiently or lead to increased costs, expenses or losses.

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Although we maintain customary insurance coverage for certain of these risks common to utilities, we do not have insurance covering our transmission and distribution system, 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 businesses, through a change in 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 states 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.

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We may incur liabilities in connection with discontinued operations.

In connection with various divestitures, we have indemnified or guaranteed parties against certain liabilities and with respect to certain transactions. These indemnities and guarantees relate to, among other things, liabilities which may arise with respect to the period during which we or our subsidiaries operated the divested business, and to certain ongoing contractual relationships and entitlements with respect to which we or our subsidiaries made commitments in connection with the divestiture. A number of commitments exist in particular with respect to the termination of a transaction in which our subsidiary Western Kentucky Energy Corporation leased and operated a number of generating stations.  Although we have made accruals reflecting our estimates of the net costs and liabilities expected to arise from these discontinued operations, actual liabilities may exceed these amounts.

Risks Related to the Exchange Offers

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

If you do not exchange your Outstanding Notes for Exchange Notes in the Exchange Offers, you will continue to be subject to restrictions on transfer of your Outstanding Notes as set forth in the offering memorandum distributed in connection with the private offering of the Outstanding Notes.  In general, the Outstanding Notes 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 Notes 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 Notes.

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

Your ability to transfer the Exchange Notes 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 Notes.

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

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

Based on interpretations of the staff of the SEC contained in Exxon Capital Holdings Corp., SEC no-action letter (April 13, 1988), Morgan Stanley & Co. Inc., SEC no-action letter (June 5, 1991) and Shearman & Sterling, SEC no-action letter (July 2, 1983), we believe that you may offer for resale, resell or otherwise transfer the Exchange Notes 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 Note 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 Notes will remain obligated to comply with the registration and prospectus delivery requirements of the Securities Act to transfer the Exchange Notes.  If such a holder transfers any Exchange Notes without delivering a prospectus meeting the requirements of the Securities Act or without an applicable exemption from registration

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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.

Risks Related to the Notes

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

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

A rating is not a recommendation to purchase, hold or sell the Notes, inasmuch as the rating does not comment as to market price or suitability for a particular investor. The ratings of the Notes address the rating agencies’ views as to the likelihood of the timely payment of interest and the ultimate repayment of principal of the Notes 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 Notes is subsequently lowered or withdrawn for any reason, the market price of the Notes may be adversely affected.

Our ability to service indebtedness, including the Notes, is largely dependent upon the earnings of our subsidiaries and the distribution of such earnings. The Notes are structurally subordinated to the obligations of our subsidiaries, which may affect your ability to receive payment on the Notes.

We are a holding company and substantially all of the assets shown on our consolidated balance sheet are held by our subsidiaries.  Accordingly, our operating cash flow and our ability to meet our obligations are largely dependent upon the earnings and cash flows of our subsidiaries and the distribution or other payment of such earnings to us in the form of dividends or advances and repayment of loans and advances from us.  Our subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts due on the Notes offered by this prospectus or to make any funds available for such payment.  Our subsidiaries’ ability to pay dividends to us in the future will depend on their future earnings and cash flows and the needs of their businesses, and may be restricted by their obligations to holders of their outstanding debt and other creditors, as well as any contractual or legal restrictions in effect at such time, including the requirements of state corporate and limited liability company law applicable to payment of dividends and distributions, and regulatory requirements.  As a result, our obligations on our debt securities, including the Notes offered by this prospectus, will be effectively subordinated to all existing and future liabilities and obligations of our subsidiaries.  Our rights and the rights of our creditors to participate in the assets of any subsidiary upon the liquidation or reorganization of such subsidiary will be subject to the prior claims of such subsidiary’s creditors.  At December 31, 2010, we had $875 million of outstanding indebtedness, and our subsidiaries had $3.13 billion of outstanding indebtedness.  Our subsidiaries also have other obligations that may not be considered indebtedness.  Although certain agreements to which we and our subsidiaries are parties limit the incurrence of additional indebtedness, we and our subsidiaries retain the ability to incur substantial additional indebtedness and other liabilities.

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A WARNING ABOUT FORWARD-LOOKING STATEMENTS

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:

·fuel supply availability;

·weather conditions affecting generation production, customer energy use and operating costs;

·operation, availability and operating costs of existing generation facilities;

·transmission and distribution system conditions and operating costs;

·collective labor bargaining negotiations;

·the outcome of litigation against us;

·potential effects of threatened or actual terrorism or war or other hostilities;

·our commitments and liabilities;

·market demand and prices for energy, capacity, transmission services, emission allowances and delivered fuel;

·competition in retail and wholesale power and natural gas markets;

·liquidity of wholesale power markets;

·defaults by our counterparties under our energy, fuel or other power product contracts;

·market prices of commodity inputs for ongoing capital expenditures;

·capital market conditions, including the availability of capital or credit, changes in interest rates, and decisions regarding capital structure;

·the fair value of debt and equity securities and the impact on defined benefit costs and resultant cash funding requirements for defined benefit plans;

·interest rates and their effect on pension and retiree medical liabilities;

·volatility in or the impact of changes in financial or commodity markets and economic conditions;

·profitability and liquidity, including access to capital markets and credit facilities;

·new accounting requirements or new interpretations or applications of existing requirements;

·securities and credit ratings;

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·current and future environmental conditions and requirements and the related costs of compliance, including environmental capital expenditures, emission allowance costs and other expenses;

·political, regulatory or economic conditions in states, regions or countries where we conduct business;

·receipt of necessary governmental permits, approvals and rate relief;

·new state or federal legislation, including new tax, environmental, health care or pension-related legislation;

·state or federal regulatory developments;

·the impact of any state or federal investigations applicable to us and the energy industry;

·the effect of any business or industry restructuring;

·development of new projects, markets and technologies;

·performance of new ventures; and

·asset acquisitions and dispositions.

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 12 of this prospectus.

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USE OF PROCEEDS

We will not receive any cash proceeds from the issuance of the Exchange Notes pursuant to the Exchange Offers.  In consideration for issuing the Exchange Notes as contemplated in this prospectus, we will receive in exchange a like principal amount of Outstanding Notes, the terms of which are identical in all material respects to the Exchange Notes of the related series, except that the Exchange Notes 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 Notes surrendered in exchange for the Exchange Notes will be retired and cancelled, and will not be reissued.  Accordingly, the issuance of the Exchange Notes will not result in any increase in our outstanding debt or the receipt of any additional proceeds.

CAPITALIZATION

The following table sets forth our capitalization as of December 31, 2010.  You should read the data set forth below in conjunction with “Selected Consolidated Financial Data,” “Management’s Discussion and Analysis” and our Consolidated 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”).

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

	As of December 31, 2010(in millions)
Cash and cash equivalents	$	11
Long-term debt, including current portion	3,837
Total equity	4,011
Total capitalization	$	7,848

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SELECTED CONSOLIDATED FINANCIAL DATA

The selected consolidated 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 consolidated 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.  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 the Company on November 1, 2010, and are labeled as Predecessor or Successor.  See “Management’s Discussion and Analysis — Overview” for additional information.

You should read the data set forth below in conjunction with “Management’s Discussion and Analysis” and our audited and unaudited consolidated financial statements and related notes included elsewhere in this prospectus.

Dollars are in millions unless otherwise noted.

	Successor		Predecessor
	November 1, 2010 through December 31,		January 1, 2010 through October 31,		Year Ended December 31,
	2010		2010		2009			2008			2007		2006
Operating revenues	$	494	$	2,214	$	2,501		$	2,675		$	2,416	$	2,373
Operating income (loss)	$	96	$	438	$	(1,082	)	$	(1,361	)	$	463	$	426
Income (loss) from continuing operations after income taxes attributable to company(1)	$	45	$	191	$	(1,317	)	$	(1,614	)	$	228	$	207
Total assets	$	10,719	$	9,755	$	9,429		$	11,454		$	12,173	$	11,315
Long-term debt obligations (including amounts due within one year)	$	3,825	$	5,083	$	5,036		$	4,085		$	3,441	$	2,695
Other Financial Data:
Ratio of Earnings to Fixed Charges(2)	3.88		2.75		2.34			2.53			2.92		2.91

(1)The income (loss) from continuing operations after income taxes attributable to the Company for 2009 and 2008 was affected by the recording of goodwill impairment.  We recorded impairment in 2009 based on bids received from parties interested in purchasing the Company.  In 2008 we recorded an impairment based on the estimated discounted present value of our future cash flows.

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See “Management’s Discussion and Analysis” and Note 7 to our 2010 Annual Financial Statements for further discussion.

(2)For purposes of calculating the ratio of earnings to fixed charges, earnings consist of earnings from continuing operations plus fixed charges.  Fixed charges consist of all interest on indebtedness, amortization of debt discount and expense and the portion of rental expense that represents an imputed interest component.  Earnings from continuing operations consist of income before taxes, undistributed income of Electric Energy, Inc. and the mark-to-market impact of derivative instruments.

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MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

We are headquartered in Louisville, Kentucky, and are a wholly owned subsidiary of PPL.  We are a holding company with energy and utility operations conducted through our subsidiaries, LG&E and KU, which constitute substantially all of our assets.  LG&E and KU are regulated utilities engaged in the generation, transmission, distribution and sale of electric energy.  LG&E also engages in the distribution and sale of natural gas.  See “Business” for a description of the business.  The rates LG&E and KU charge their customers require approval of the appropriate regulatory government agency.  See Note 3 to our 2010 Annual Financial Statements for information regarding rate cases, regulatory assets and liabilities and other regulatory matters.

PPL Corporation acquired us 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, our business did not change; both LG&E and KU continue operating as our subsidiaries and we are 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 Consolidated 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:

·“Results of Operations” provides a description of our operating results in 2010, 2009 and 2008, including a review of earnings and a brief outlook for 2011.

·“Financial Condition — Liquidity and Capital Resources” provides an analysis of our liquidity position and credit profile, including our sources of cash (including bank credit facilities and sources of operating cash flow) and uses of cash (including contractual obligations and capital expenditure requirements) and the key risks and uncertainties that impact our past and future liquidity position and financial condition. This subsection also includes a discussion of rating agency action on our credit ratings.

·“Financial Condition — Risk Management” provides an explanation of our risk management activities related to market risk and credit risk.

·“Application of Critical Accounting Policies and Estimates” provides an overview of the accounting policies that are particularly important to our results of operations and our financial condition and that require our management to make significant estimates, assumptions and other judgments.

Predecessor and Successor Financial Presentation

Our financial statements and related financial and operating data include the periods before and after PPL’s acquisition of the Company on November 1, 2010, and are labeled as Predecessor or Successor.  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, our results of operations and cash flows for the Predecessor and Successor periods in 2010 are shown separately, rather than combined, in our audited financial statements.

In the “Management’s Discussion and Analysis” of “Results of Operations” and “Financial Condition,” we have included disclosure of the combined Predecessor and Successor results of operations and cash flows.  Such

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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.

Competition

See “Business—Competition” for information concerning competition.

Environmental Matters

General

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.

Climate Change

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 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 holding company for primarily coal-fired utility companies, could be highly affected by such proceedings.

Other Environmental Regulatory Initiatives

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

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controls, installation of additional emission controls such as flue gas desulfurization, selective catalytic reduction, or SCRs, 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 the Company 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 $3.25 to $3.75 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” and Note 13 to our 2010 Annual Financial Statements for further information.

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Results of Operations

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.

All dollar amounts are in millions unless otherwise noted.

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Net Income

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

	Combined			Successor			Predecessor
	Year Ended December 31,			November 1, 2010 through December 31,			January 1, 2010 through October 31,			Year Ended December 31,
	2010			2010			2010			2009			2008
Total operating revenues	$	2,708		$	494		$	2,214		$	2,501		$	2,675
Total operating expenses	2,174			398			1,776			2,090			2,230
Loss on impairment	—			—			—			(1,493		)	(1,806		)
Operating income (loss)	534			96			438			(1,082		)	(1,361		)
Equity in earnings of unconsolidated venture	3			—			3			—			29
Derivative gain (loss)	19			—			19			18			(37		)
Interest expense	41			20			21			21			46
Interest expense to affiliated companies	135			4			131			155			138
Other income (expense) — net	(10		)	(2		)	(8		)	5			17
Income (loss) from continuing operations, before income taxes	370			70			300			(1,235		)	(1,536		)
Income tax expense	134			25			109			82			78
Income (loss) from continuing operations	236			45			191			(1,317		)	(1,614		)
Loss from discontinued operations net of income tax	(4		)	—			(4		)	(151		)	(173		)
Gain (loss) on disposal of discontinued operations net of income tax	5			2			3			(69		)	—
Net income (loss)	237			47			190			(1,537		)	(1,787		)
Noncontrolling interest-loss from discontinued operations	—			—			—			(5		)	(8		)
Net income (loss) attributable to member	$	237		$	47		$	190		$	(1,542	)	$	(1,795	)

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The change in our net income was as follows:

	Increase (Decrease)
	2010 vs. 2009			2009 vs. 2008
Total operating revenues	$	207		$	(174	)
Total operating expenses	84			(140		)
Loss on impairment	(1,493		)	(313		)
Operating income	1,616			279
Equity in earnings of unconsolidated venture	3			(29		)
Derivative gain (loss)	1			55
Interest expense	20			(25		)
Interest expense to affiliated companies	(20		)	17
Other income (expense) — net	(15		)	(12		)
Income (loss) from continuing operations before income taxes	1,605			301
Income tax expense	52			4
Income (loss) from continuing operations	1,553			297
Loss from discontinued operations net of income tax	(147		)	(22		)
Gain (loss) on disposal of discontinued operations net of income tax	74			(69		)
Net income (loss)	1,774			250
Noncontrolling interest-loss from discontinued operations	5			3
Net income (loss) attributable to member	$	1,779		$	253

Operating Revenues

Operating revenues follow:

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	Combined		Successor		Predecessor
	Year Ended December 31,		November 1, 2010 through December 31,		January 1, 2010 through October 31,		Year Ended December 31,
	2010		2010		2010		2009		2008
Electric	$	2,412	$	409	$	2,003	$	2,147	$	2,223
Natural gas	296		85		211		354		452
	$	2,708	$	494	$	2,214	$	2,501	$	2,675

The changes in operating revenues were as follows:

	Increase (Decrease)
	2010 vs. 2009			2009 vs. 2008
Electric	$	265		$	(76	)
Natural gas	(58		)	(98		)
	$	207		$	(174	)

Electric Revenues

The $265 million increase from 2009 to 2010 and the $76 million decrease from 2008 to 2009 in electric revenues were primarily due to:

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	Increase (Decrease)
	2010 vs. 2009			2009 vs. 2008
Retail sales volumes (a)	$	119		$	(76	)
Base rate price variance (b)	72			(17		)
Demand revenues (c)	30			1
Increased fuel costs billed through the fuel adjustment clause, or FAC	26			11
Sales to municipal customers (d)	12			(1		)
Other operating revenues primarily due to late payment charges	6			14
Transmission revenue	6			—
Increased recoverable program spending billed through the DSM	4			16
Merger surcredit termination in February 2009	2			27
Increased recoverable capital spending billed through environmental cost recovery, or ECR	1			57
Wholesale sales (e)	(13		)	(113		)
Value delivery team process surcredit termination in August 2008	—			5
	$	265		$	(76	)

(a)Retail sales volumes increased during 2010 compared to 2009 as a result of increased consumption primarily due to increased heating degree days during the first and fourth quarters of 2010 and increased cooling degree days during the second and third quarters of 2010.  Additionally, improved economic conditions in 2010 and significant storm outages in 2009 contributed to the increased volumes.

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 Kentucky rate case, the 2001 and 2003 ECR plans were added to rate base, which caused a portion of this increase. 

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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 case.

(c)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.

(d)The increase in sales to municipal customers during 2010 compared to 2009 was primarily due to increased volumes as a result of increased cooling and heating degree days, improved economic conditions and a decline in storm outages.

(e)The decrease in wholesale sales during 2010 compared to 2009 resulted from decreased volumes to third parties and decreased revenues from financial swaps.  The decrease in wholesale volumes was primarily due to increased consumption by residential customers as a result of increased cooling and heating degree days, increased coal-fired generation outages and increased consumption 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.

The decrease in wholesale sales during 2009 compared to 2008 was primarily due to decreased volumes to third parties, due to lower economic capacity caused by lower spot market pricing and higher scheduled coal-fired generation outages.

Natural Gas Revenues

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

	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 decrease due to lower demand	—			(6		)
Other	1			3
	$	(58	)	$	(98	)

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(a)Retail sales volumes increased during 2010 compared to 2009, as a result of increased consumption 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 decreased revenues from the 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 to our 2010 Annual Financial Statements 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.

Operating Expenses

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

	Combined		Successor		Predecessor
	Year Ended December 31,		November 1, 2010 through December 31,		January 1, 2010 through October 31,		Year Ended December 31,
	2010		2010		2010		2009		2008
Fuel for electric generation	$	861	$	138	$	723	$	762	$	859
Power purchased	117		15		102		136		153
Natural gas supply expense	162		53		109		243		349
Other operation and maintenance expenses	750		143		607		678		604
Depreciation and amortization	284		49		235		271		265
	$	2,174	$	398	$	1,776	$	2,090	$	2,230

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The changes in operating expenses were as follows:

	Increase (Decrease)
	2010 vs. 2009			2009 vs. 2008
Fuel for electric generation	$	99		$	(97	)
Power purchased	(19		)	(17		)
Natural gas supply expense	(81		)	(106		)
Other operation and maintenance expenses	72			74
Depreciation and amortization	13			6
	$	84		$	(140	)

Fuel for Electric Generation

The $99 million increase from 2009 to 2010 and $97 million decrease from 2008 to 2009 were primarily due to:

	Increase (Decrease)
	2010 vs. 2009			2009 vs. 2008
Fuel usage volumes (a)	$	94		$	(117	)
Commodity costs for coal and natural gas	8			20
Other	(3		)	—
	$	99		$	(97	)

(a)Fuel usage volumes increased in 2010 compared to 2009 due to increased native load sales.  Fuel usage volumes decreased in 2009 compared to 2008 due to decreased native load and wholesale sales.

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Power Purchased Expense

The $19 million decrease from 2009 to 2010 and $17 million decrease from 2008 to 2009 were primarily due to:

	Increase (Decrease)
	2010 vs. 2009			2009 vs. 2008
Power purchased from Owensboro Municipal Utilities, or OMU	$	(40	)	$	12
Demand payments for third party purchases	(1		)	3
Prices for purchases used to serve retail customers	10			(16		)
Third party purchased volumes for native load (a)	7			(7		)
OMU settlement received in 2009 (b)	6			(6		)
Other	(1		)	(3		)
	$	(19	)	$	(17	)

(a)Third party purchase volumes with counterparties other than OMU increased in 2010 compared to 2009 primarily due to the termination of the OMU agreement.  Third party purchase volumes with counterparties other than OMU decreased in 2009 compared to 2008 primarily due to availability of power for native load customers from the OMU agreement.

(b)See Note 13 to our 2010 Annual Financial Statements for further discussion of the OMU settlement.

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Natural Gas Supply Expense

The $81 million decrease from 2009 to 2010 and $106 million decrease from 2008 to 2009 were primarily due to:

	Increase (Decrease)
	2010 vs. 2009			2009 vs. 2008
Cost of natural gas supply billed to customers due to lower cost per Mcf	$	(95	)	$	(73	)
Natural gas volumes delivered	13			(26		)
Wholesale sales of purchased natural gas volumes	—			(5		)
Other	1			(2		)
	$	(81	)	$	(106	)

Other Operation and Maintenance Expenses

The $72 million increase from 2009 to 2010 and $74 million increase from 2008 to 2009 were primarily due to:

	Increase (Decrease)
	2010 vs. 2009			2009 vs. 2008
Administrative and general expense (a)	$	38		$	6
Steam expense (b)	15			17
Generation expense (c)	8			(2		)
Bad debt expense (d)	6			(1		)
Transmission expense (e)	7			(1		)
DSM program spending	2			19
Legal expenses (f)	—			(6		)
Distribution expense	—			2
Power supply expense	—			(4		)
Pension expense (g)	(6		)	44
Other	2			—
	$	72		$	74

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(a)Administrative and general expense increased in 2010 compared to 2009 primarily due to increased expense related to the purchase of the Company by PPL, higher labor expense and insurance expense, partially offset by lower information technology expense related to the implementation of the Customer Care Solution system in 2009.  Administrative and general expense increased in 2009 compared to 2008 primarily due to increased consulting fees for software training and increased labor and benefit cost.

(b)Steam expense increased in 2010 compared to 2009 primarily due to increased generation, boiler and electric maintenance expense related to outage work.  Steam expense increased in 2009 compared to 2008 due to the utilization of SCRs year-round and increased scope of work related to scheduled outages.

(c)Generation expense increased in 2010 compared to 2009 primarily due to overhaul of Paddy’s Run Unit 13.

(d)Bad debt expense increased in 2010 compared to 2009 due to higher billed revenues, higher late payment charges and a higher net charge-off percentage.

(e)Transmission expense increased in 2010 compared to 2009 primarily due to a settlement agreement with a third party and the establishment of a regulatory asset approved by the Kentucky Commission for the East Kentucky Power Cooperative, Inc. settlement in 2009, net of twelve months of amortization expense recorded in 2010.

(f)Legal expenses decreased in 2009 compared to 2008 primarily due to OMU expenses in 2008.  See Note 13 to our 2010 Annual Financial Statements for further information regarding the OMU settlement.

(g)Pension expense decreased in 2010 compared to 2009 primarily due to favorable asset performance in 2009 and increased in 2009 compared to 2008 primarily due to unfavorable asset performance in 2008.

Loss on Impairment of Goodwill

Loss on impairment of goodwill decreased $1,493 million in 2010 compared to 2009 and decreased $313 million in 2009 compared to 2008.  The Company recorded impairment in 2009 based on bids received from parties interested in purchasing the Company including PPL, and recorded impairment in 2008 based on the estimated discounted present value of our future cash flows.  See Note 7 to our 2010 Annual Financial Statements for further information.

Equity in Earnings of Unconsolidated Venture

The $3 million increase in equity in earnings of unconsolidated venture from 2009 to 2010 was primarily due to higher earnings from Electric Energy, Inc. resulting from increased market prices for electric energy and the $29 million decrease from 2008 to 2009 was primarily due to lower earnings resulting from decreased market prices for electric energy.

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Derivative Gain (Loss)

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

	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

(a)See Note 3 to our 2010 Annual Financial Statements for further discussion of the interest rate swap regulatory assets.

Interest Expense

The $20 million increase from 2009 to 2010 and $25 million decrease from 2008 to 2009 were primarily due to:

	Increase (Decrease)
	2010 vs. 2009		2009 vs. 2008
Bond interest expense (a)	$	10	$	(12	)
Senior notes interest expense (b)	4		—
Interest rate swaps (c)	1		(8		)
Other interest expense	5		(5		)
	$	20	$	(25	)

(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)We issued senior notes in November 2010.  See Note 11 to our 2010 Annual Financial Statements for further information.

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(c)See Notes 3 and 5 to our 2010 Annual Financial Statements for further information regarding interest rate swaps.

Interest Expense to Affiliated Companies

Interest expense to affiliated companies decreased by $20 million 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 and due to lower 2010 interest rates on variable rate notes payable to Fidelia Corporation.  Interest expense to affiliate companies increased by $17 million in 2009 compared to 2008 primarily due to increased intercompany debt outstanding.

Other Income (Expense) — Net

The $15 million decrease in other income (expense) — net from 2009 to 2010 and $12 million decrease in other expense — net from 2008 to 2009 were primarily due to:

	Increase (Decrease)
	2010 vs. 2009			2009 vs. 2008
Gain on sale of our property	$	(3	)	$	(6	)
Discontinuance of allowance for funds used during construction on ECR projects as a result of the FERC rate case	(3		)	(2		)
Depreciation expense on TC2 joint-use assets held for future use	(2		)	(1		)
Other	(7		)	(3		)
	$	(15	)	$	(12	)

Discontinued Operations

In July 2009, the Company completed the disposition of the 25-year lease and operating agreements of Western Kentucky Energy Corp., or WKE, for the generating facilities of Big Rivers Electric Corporation, a power-generating cooperative in western Kentucky and a coal-fired generating facility owned by the City of Henderson, Kentucky.

In November 2009, subsidiaries of the Company entered into agreements to sell their direct and indirect interests in Distribuidora de Gas Del Centro S.A. and Distribuidora de Gas Cuyana S.A., two natural gas distribution companies in Argentina, to E.ON Espana S.L. and a subsidiary, both affiliates of E.ON AG, or E.ON.  The transaction was completed on January 1, 2010, for a sale price of $35 million.

The loss from discontinued operations after tax decreased $147 million and $22 million in 2010 and 2009, respectively, primarily due to the disposition of WKE’s operations in July 2009.  The $46 million decrease in WKE’s 2009 operations was partially offset by an impairment charge related to the Argentina operations totaling $12 million.

The gain (loss) on disposal of discontinued operations after tax increased by $74 million in 2010 primarily due to the $69 million loss recognized for the disposal of the WKE operations in July 2009 and the revaluation of certain

39

liabilities in 2010.  The gain (loss) on disposal of discontinued operations after tax decreased in 2009 compared to 2008 by $69 million due to the disposal of the WKE operations in July 2009.

Income Tax Expense

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.

2011 Outlook

We project higher earnings in 2011 compared with 2010 as a result of higher retail revenues and lower financing costs due to lower debt balances resulting from an equity contribution provided by PPL upon the November 1, 2010 acquisition and the issuance in late 2010 of first mortgage bonds which we used to refund higher-cost debt, partially offset by higher operation and maintenance expenses and depreciation.  Retail revenues are expected to increase as a result of the 2010 Kentucky rate cases and recoveries associated with its environmental investments.  Operation and maintenance expenses and depreciation are expected to increase due to commencing dispatch of TC2 in January 2011.  See “Risk Factors” and “A Warning about Forward-Looking Statements” for a discussion of the factors that may impact the 2011 outlook.

Financial Condition

Liquidity and Capital Resources

We expect to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents and our credit facilities.  We remarketed $163 million of LG&E pollution control bonds in January 2011 and expect to remarket an additional $25 million of LG&E pollution control bonds in November 2011.  We currently have no other plans to access debt capital markets in 2011.  See Note 21 to our 2010 Annual Financial Statements for further information.

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:

·unusual or extreme weather that may damage our transmission and distribution facilities or affect energy sales to customers;

·unavailability of generating units (due to unscheduled or longer than anticipated generation outages, weather and natural disasters) and the resulting loss of revenues and additional costs of replacement electricity;

·ability to recover and timeliness and adequacy of recovery of costs associated with regulated utility business;

·costs of compliance with existing and new environmental laws;

·changes in market prices for electricity;

·potential ineffectiveness of the trading, marketing and risk management policy and programs used to mitigate our risk exposure to adverse electricity and fuel prices and interest rates;

·operational and credit risks associated with selling and marketing products in the wholesale power markets;

·any adverse outcome of legal proceedings and investigations with respect to our current and past business activities;

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·deterioration in the financial markets that could make obtaining new sources of bank and capital markets funding more difficult and more costly; and

·a downgrade in our credit ratings that could adversely affect our ability to access capital and increase the cost of credit facilities and any new debt.

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

All dollar amounts are in millions unless otherwise noted.

At December 31, we had the following:

	Successor		Predecessor
	2010		2009
Cash and cash equivalents	$	11	$	7
Available for sale debt securities (a)	163		—
	$	174	$	7
Current portion of long-term debt (b)	$	2	$	348
Current portion of long-term debt to affiliated company (c)	—		358
Notes payable to affiliated company (c)	—		851
Note payable (d)	163		—
	$	165	$	1,557

(a)2010 amount represents tax-exempt bonds issued by Louisville/Jefferson County, Kentucky, on behalf of LG&E that were subsequently purchased by LG&E. Such bonds were remarketed to unaffiliated investors in January 2011.  See Notes 18 and 21 to our 2010 Annual Financial Statements for further information.

(b)2009 amount represents LG&E’s Jefferson County 2001 Series A and B and Trimble County 2001 Series A and B and KU’s Carroll County 2002 Series A and B, 2004 Series A, 2006 Series B and 2008 Series A; Muhlenberg County 2002 Series A; and Mercer County 2000 Series A and 2002 Series A pollution control bonds subject to tender for purchase at the option of the holder and to mandatory tender for purchase upon the occurrence of certain events.  The Successor has classified these bonds as long-term debt because LG&E and KU have the intent and ability to utilize their respective $400 million credit facilities, which mature in December 2014, to fund any mandatory purchases.  The 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 generally accepted accounting principles, or GAAP.  See Notes 1 and 11 to our 2010 Annual Financial Statements for further information.

(c)2009 amounts represent debt owed to E.ON affiliates, which was repaid in November 2010.  See Notes 12 and 15 to our 2010 Annual Financial Statements for further information.

(d)2010 amount represents borrowings on LG&E’s $400 million revolving line of credit with a group of banks.  See Note 12 to our 2010 Annual Financial Statements for further information.

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.

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	Combined			Successor			Predecessor
				November 1, 2010			January 1, 2010			Year Ended
	Year Ended			through			through			December 31,
	December 31, 2010			December 31, 2010			October 31, 2010			2009			2008
Net cash provided by (used in) operating activities	$	514		$	26		$	488		$	(204	)	$	390
Net cash used in investing activities	(637		)	(211		)	(426		)	(706		)	(957		)
Net cash provided by (used in) financing activities	127			167			(40		)	902			568
Change in cash and cash equivalents	$	4		$	(18	)	$	22		$	(8	)	$	1

Operating Activities

Net cash provided by operating activities increased by 352%, or $718 million, in 2010 compared with 2009, primarily as a result of payments made in July 2009 for the WKE unwind, increased earnings excluding an impairment of goodwill and discontinued operation expenses, lower storm expenses and increased collections from the ECR mechanism.  These increases in cash flow were partially offset by changes in working capital, refunds of prior year GSC over-collections, increased pension funding, higher interest payments due to an accelerated settlement with the previous owner and higher income tax payments.

Net cash provided by operating activities decreased by 152%, or $594 million, in 2009 compared with 2008, primarily as a result of payments made in July 2009 for the WKE unwind, higher storm expenses and increased pension funding.  These decreases in cash flow were partially offset by increased GSC recoveries and higher earnings excluding an impairment of goodwill, discontinued operation expenses and pension expense.

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.

Investing Activities

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 10%, or $69 million, in 2010 compared with 2009, primarily as a result of a decrease of $127 million in capital expenditures and an increase of $21 million in proceeds from the sale of discontinued operations.  These increases in cash flow were partially offset by a $61 million loan made to an affiliate, a decrease of $8 million in restricted cash collections, a decrease of $7 million in cash received on the settlement of derivatives and a decrease of $3 million in cash received from the sale of assets.

Net cash used in investing activities decreased by 26%, or $251 million, in 2009 compared with 2008, primarily as a result of a decrease of $233 million in capital expenditures, an increase of $15 million in cash received on the settlement of derivatives and an increase of $9 million in restricted cash collections.  These increases in cash flow were partially offset by a decrease of $6 million in cash received from the sale of assets.

Financing Activities

Net cash provided by financing activities was $127 million in 2010 compared with $902 million in 2009.  In spite of significant new debt issuances associated with the repayments to E.ON affiliates in connection with PPL’s acquisition of the Company, the cash provided by financing in 2010 is lower as a result of new debt issuances exceeding repayments by a smaller amount and by higher dividends paid in 2010.

Net cash provided by financing activities was $902 million in 2009 compared with $568 million in 2008.  The higher level of cash provided by financing in 2009 was the result of increased issuances of debt due to affiliates.

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In the two months of 2010 following the acquisition, cash provided by financing activities of the Successor primarily consisted of the issuance of senior unsecured notes and first mortgage bonds totaling $2,890 million after discounts, the issuance of intercompany notes totaling $2,784 million to a PPL subsidiary to repay debt due to E.ON affiliates upon the closing of the sale, an equity contribution from PPL totaling $1,565 million and a $163 million drawing under a revolving line of credit. These amounts were offset by the repayment of $4,319 million to E.ON affiliates upon the closing of the sale, the repayment of $2,784 million to a PPL affiliate upon the issuance of the senior unsecured notes and first mortgage bonds, a $100 million return of capital to PPL and the payment of $32 million of debt issuance costs.

In 2010, cash used in financing activities by the Predecessor primarily consisted of the payment of $900 million of maturing intercompany loans, $87 million of dividends to E.ON entities and the net repayment of short-term debt due to affiliated companies totaling $3 million.  These amounts were partially offset by the issuance of new intercompany loans totaling $950 million.

In 2009, cash used in financing activities primarily consisted of the issuance of intercompany loans totaling $1,230 million, partially offset by $255 million of maturing intercompany loans, dividends paid to E.ON entities totaling $49 million and the repayment of $22 million of short-term debt to affiliated companies.

In 2008, cash provided by financing activities primarily consisted of the issuance of $575 million of intercompany notes to an E.ON affiliate, an increase in short-term debt to an affiliated company of $237 million, the issuance of $237 million of pollution control revenue bonds, all partially offset by repurchases or retirements of $382 million and $24 million of pollution control revenue bonds and medium term notes, respectively and the payment of $68 million in dividends to E.ON entities.

Our debt financing activity in 2010 was:

	Issuances (a)		Retirements
Issuance of long-term debt	$	2,890	$	—
Issuance of short-term note payable	163		—
Short-term borrowings from affiliated companies — net change	—		(3		)
Other borrowings from affiliated companies	2,784		(2,784		)
Borrowings from E.ON affiliates	950		(5,219		)
Net change in debt financing	$	6,787	$	(8,006	)

(a)Issuances are net of pricing discounts, where applicable.

See Note 11 to our 2010 Annual Financial Statements for further information.

Working Capital Deficiency

As of December 31, 2009, the Company had a working capital deficiency of $1,313 million, primarily due to short-term debt from affiliates totaling $1,209 million and $348 million of tax-exempt bonds which allow the investors to put the bonds back to the Company causing them to be classified as “Current portion of long-term debt.”  As of December 31, 2010, the Company no longer had a working capital deficiency because the short-term debt from affiliates was paid off in conjunction with the PPL acquisition financing, the $348 million of tax-exempt bonds were no longer classified as “Other current liabilities” by the Successor because the Company has the intent and ability to utilize the $400 million credit facilities of LG&E and KU that expire in December 2014 to fund any mandatory purchases, and the $163 million in repurchased LG&E 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 1, 11, 18 and 21 to our 2010 Annual Financial Statements for further information.

Auction Rate Securities

Auctions for auction rate securities issued by LG&E and KU continued to fail throughout 2010.  LG&E held $163 million of its 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

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of 1.90% for an intermediate term.  See Notes 11, 18 and 21 to our 2010 Annual Financial Statements for further discussion.

Forecasted Sources of Cash

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 PPL.  Regulatory approvals are required for LG&E and KU to incur additional debt.  The Virginia Commission and the FERC authorize the issuance of short-term debt while the Kentucky Commission, the Virginia Commission and the Tennessee Regulatory Authority authorize the issuance of long-term debt.  In November 2009, LG&E and KU each received a two-year authorization from the FERC to borrow up to $400 million in short-term funds.  KU also has authorization from the Virginia Commission that expires at the end of 2011, allowing short-term borrowing of up to $400 million.  Short-term funds are made available to LG&E and KU via our participation in an intercompany money pool agreement wherein we and/or KU and/or LG&E make funds available to LG&E and KU at market-based rates (based on highly rated commercial paper issues) up to $400 million.  We also have an intercompany line of credit available up to $300 million from a subsidiary of PPL, and LG&E and KU each maintain $400 million Revolving Credit Agreements discussed below.  We currently believe these authorizations and facilities, together with our credit facilities discussed below, provide the necessary flexibility to address any liquidity needs.

Credit Facilities

On November 1, 2010, LG&E and KU each entered into separate new $400 million unsecured Revolving Credit Agreements with a group of banks.  Under their respective new credit facilities, which expire December 31, 2014, LG&E and KU each 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 the respective borrower’s senior unsecured long-term debt rating.  The new credit facilities contain financial covenants requiring the borrower’s debt to total capitalization to not exceed 70% and other customary covenants.  At December 31, 2010, LG&E’s debt to total capitalization was 43% and KU’s debt to total capitalization was 41%, as calculated pursuant to the respective credit agreements.  Under certain conditions, each of LG&E and KU may request that its facility’s capacity be increased by up to $100 million.  The new LG&E credit facility replaced three bilateral credit facilities totaling $125 million and the new KU credit facility replaced a bilateral line of credit totaling $35 million, each of which were terminated on November 1, 2010.  We entered into a $300 million demand note facility with a PPL subsidiary.  The facility allows for cash borrowings at LIBOR-based rates plus a spread, depending upon our senior unsecured long-term debt rating.  As of December 31, 2010, there were no borrowings outstanding under our new facility, $163 million of borrowings outstanding under the new LG&E credit facility and no borrowings outstanding under KU’s new credit facility, but there were $198 million of letters of credit outstanding to support outstanding bonds totaling $195 million under the KU credit facility.  In January 2011, LG&E successfully remarketed $163 million of its repurchased pollution control bonds and used the proceeds to repay the outstanding balance on LG&E’s credit facility.  We will utilize unused credit facility and money pool balances to fund working capital needs as they arise.

See Note 12 to our 2010 Annual Financial Statements for further information regarding our credit facilities.  Sees Notes 11, 18 and 21 to our 2010 Annual Financial Statements for further information regarding our remarketed bonds.

Contributions from PPL

PPL may make capital contributions to us, which can be used for general corporate purposes.

Long-Term Debt

We currently do not plan to issue any new long-term debt in 2011 other than the Exchange Notes.  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 21 to our 2010 Annual Financial Statements for further information.

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Credit Ratings

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 lowered our corporate credit rating, the rating of the Outstanding Notes and the first mortgage bond and short-term ratings of LG&E and KU, while placing our ratings on negative watch, all as a result of the announcement by PPL of its intent to acquire two electricity distribution networks in the U.K., Central Networks West PLC and Central Networks East PLC, and pending demonstrated progress on execution by PPL of a permanent financing plan.  In April 2011, in connection with the execution of a significant portion of permanent financing, that agency took us, LG&E and KU off of credit watch negative, returned our outlook to stable, raised LG&E’s and KU’s short-term credit ratings and affirmed ratings on the outstanding notes and LG&E’s and KU’s first mortgage bonds.  In October 2010, a rating agency revised downward the short-term credit ratings of LG&E’s and KU’s pollution control bonds and the issuer ratings of the Company, LG&E and KU 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 senior notes and LG&E’s and KU’s 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.

Ratings Triggers

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 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.  At December 31, 2010, if our credit ratings had been below investment grade, we would have been required to prepay or post an additional $99 million of prepayments and collateral to counterparties for both derivative and non-derivative commodity and commodity-related contracts used in generation, marketing and trading operations and interest rate contracts.

Forecasted Uses of Cash

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.

Capital Requirements

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 facilities 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 $2,975 million consisting primarily of the following:

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Construction of environmental controls and capacity replacement	$	1,033
Construction of distribution and metering assets	649
Construction of coal combustion residual storage structures	436
Construction of generation assets	375
Construction of transmission assets	169
Recoverable environmental assets	115
Information technology projects	80
Redevelopment of Ohio Falls hydroelectric facility	67
Other projects	51
	$	2,975

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 $3.25 to $3.75 billion range over the next ten years, although final costs may substantially vary.

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

Contractual Obligations

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 Consolidated Statements of Capitalization in our 2010 Annual Financial Statements.

	Payments Due by Period
	2011		2012		2013		2014		2015		Thereafter		Total
Short-term debt (a)	$	163	$	—	$	—	$	—	$	—	$	—	$	163
Long-term debt (b)	2		—		—		—		900		2,935		3,837
Interest on long-term debt (c)	126		127		134		141		147		2,329		3,004
Operating leases (d)	14		12		10		8		5		4		53
Unconditional power purchase obligations (e)	29		32		32		33		32		372		530
Coal and natural gas purchase obligations (f)	774		309		256		191		191		49		1,770
Pension benefit plan obligation (g)	64		84		98		33		22		159		460
Postretirement benefit plan obligations (h)	13		14		14		15		15		81		152
Construction obligations (i)	230		10		4		—		—		—		244
Other obligations (j)	14		4		—		—		—		—		18
	$	1,429	$	592	$	548	$	421	$	1,312	$	5,929	$	10,231

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

(a)Represents borrowings which are due within one year.

(b)Reflects principal maturities only based on legal maturity dates and includes the current portion of long-term debt.

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(c)Assumes interest payments through maturity. The payments herein are subject to change as payments for debt that is or becomes variable-rate 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.

(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.

(i)Represents construction commitments, including commitments for the Ohio Falls refurbishment, the Brown SCR and the Trimble, Brown and Ghent landfill construction including associated material transport systems for coal combustion residuals.

(j)Represents other contractual obligations including the accrued liability for the WKE — swap agreement and the Southwest Power Pool, Inc., or SPP, and Tennessee Valley Authority, or TVA, coordination agreements.

Pension and Postretirement Benefit Plans

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

Dividends and Distributions

Future distributions may be declared at the discretion of our Board of Directors, payable to our sole member, PPL.  As a holding company, we rely on dividends from our subsidiaries for cash flow.  As discussed in Note 12 to our 2010 Annual Financial Statements, the ability of LG&E and KU to pay dividends may be effectively limited under a covenant in each of their $400 million revolving line of credit facilities.  This covenant restricts their debt to total capital ratio to not be more than 70%.  These limitations did not restrict the ability of LG&E and KU to pay dividends at December 31, 2010.  LG&E and KU 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.  LG&E and KU believe, however, that this statutory restriction, as applied to their 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.

Contributions to LG&E or KU

From time to time we may make capital contributions to LG&E or KU, which can be used for general corporate purposes.

Purchase, Redemption or Remarketing of Debt Securities

In January 2011, LG&E successfully remarketed $163 million of its repurchased pollution control bonds, which were classified as “Available for sale debt securities” on the Consolidated Balance Sheets at December 31, 2010.  LG&E used the proceeds from the remarketed bonds to repay the balance of its 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.

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See Notes 11, 18 and 21 to our 2010 Annual Financial Statements for further information regarding our remarketed bonds.  See Note 12 to our 2010 Annual Financial Statements for discussion regarding our credit facilities.

Off-Balance Sheet Arrangements

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

Risk Management

Market Risk

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.

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” and Note 9 to our 2010 Annual Financial Statements for a discussion of the assumptions and sensitivities regarding our defined benefit pension and postretirement benefit plans assumptions.

Interest Rate Risk.  The Company and its subsidiaries have issued debt to finance their 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.  At December 31, 2010, our annual exposure to increased interest expense, based on a 10% increase in interest rates, was less than $1 million.   See Note 5 to our 2010 Annual Financial Statements for further information.

Commodity Price Risk.  Because our rates are set by regulatory commissions and our prudently incurred fuel costs are directly recoverable from customers, 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 they 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.  See Note 5 to our 2010 Annual Financial Statements for further information.

	Successor			Predecessor
	December 31,			October 31,			December 31,
	2010			2010			2009
Fair value of contracts outstanding at the beginning of the period	$	—		$	—		$	2
Contracts realized or otherwise settled during the period	—			3			10
Fair value of new contracts entered into during the period	—			(4		)	1
Other changes in fair value (a)	(2		)	1			(13		)
Fair value of contracts outstanding at the end of the period	$	(2	)	$	—		$	—

(a)Represents the change in value of outstanding transactions and the value of transactions entered into and settled during the period.

Credit Risk

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

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certain thresholds.  See Note 5 to our 2010 Annual 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” and Notes 1 and 8 to our 2010 Annual 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 for information regarding exposure and the risk management activities.

Related Party Transactions

We and our affiliates engage in related party transactions.  See Notes 12 and 15 to our 2010 Annual 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 entities doing business with us.

Acquisitions, Development and Divestitures

We have been constructing a new 760-Mw capacity base-load, coal-fired unit, TC2, which we jointly own (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.  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.  See Note 13 to our 2010 Annual Financial Statements for further information.

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

Application of Critical Accounting Policies and Estimates

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 its 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.

Price Risk Management

See “— Financial Condition — Risk Management” above.

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Regulatory Mechanisms

LG&E and KU are cost-based rate-regulated utilities.  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, the Kentucky Commission, the Virginia Commission or the Tennessee Regulatory Authority.  See Note 3 to our 2010 Annual Financial Statements for additional detail regarding regulatory assets and liabilities.

Defined Benefits

Our employees benefit from both funded and unfunded retirement benefit plans.  See Note 1 to our 2010 Annual 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:

·Our selection of discount rates is based on the Mercer Pension Discount Yield Curve (Predecessor) and the Towers Watson Yield Curve (Successor).

·Our selection of rate of salary growth is based on historical data that includes employees’ periodic pay increases and promotions, which are used to project employees’ pension benefits at retirement.

·We determine the expected long-term return on plan assets 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.

·Our management projects health care cost trends based on past health care costs, the near-term outlook and an assessment of likely long-term trends.

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 cost was approximately $13 million less than 2009.  We anticipate our 2011 pension cost will be approximately $7 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 plans of $45 million and $33 million in 2010 and 2009, respectively.  In January 2011, we contributed $150 million to our pension plans.  See Note 21 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.

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Asset Impairment

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:

·a significant decrease in the market price of an asset;

·a significant adverse change in the manner in which an asset is being used or in its physical condition;

·a significant adverse change in legal factors or in the business climate;

·an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of an asset;

·a current-period operating or cash flow loss combined with a history of losses or a forecast that demonstrates continuing losses;

·a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its previously estimated useful life; and

·a significant change in the physical condition of an asset.

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 the Company on November 1, 2010, LG&E and KU recorded $607 million and $389 million of goodwill, respectively.  At December 31, 2010, LG&E’s and KU’s 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.  LG&E and KU perform their 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, the Company identifies a potential impairment by comparing the estimated fair value of LG&E and KU (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.

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The Successor 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.

Loss Accruals

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, discontinued operations 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 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:

·Allowances for uncollectible accounts are reduced when accounts are written off after prescribed collection procedures have been exhausted, a better estimate of the allowance is determined or underlying amounts are ultimately collected.

·Environmental and other litigation contingencies are reduced when the contingency is resolved, we make actual payments, a better estimate of the loss is determined or the loss is no longer considered probable.

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.

Asset Retirement Obligations

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 Consolidated 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.

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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 $103 million recorded on the Consolidated Balance Sheets.  Of the total amount, $64 million, or 62%, 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:

	Change in Assumption	Impact on ARO Liability (in millions)
Retirement cost	10%/(10)%	$7/$(7)
Discount rate	0.25%/(0.25)%	$(4)/$3
Inflation rate	0.25%/(0.25)%	$4/$(4)

Income Tax Uncertainties

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

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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 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.

Purchase Price Allocation

On November 1, 2010, PPL completed the acquisition of the Company and its subsidiaries.  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 Consolidated 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 our 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.

New Accounting Guidance

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

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Other Information

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.

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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 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.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Financial Condition — Risk Management—Market Risk” above and Notes 5, 6 and 9 to our 2010 Annual Financial Statements for further information.

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BUSINESS

LG&E and KU Energy LLC became a wholly owned subsidiary of PPL on November 1, 2010, when PPL acquired all of our outstanding limited liability interests from E.ON US Investments Corp.  We are a holding company and our regulated utility operations are conducted through our subsidiaries, Kentucky Utilities Company and Louisville Gas and Electric Company, which constitute substantially all of our assets.  We are registered as a holding company under PUHCA 2005.

LG&E and KU are regulated public utilities engaged in the generation, transmission, distribution and sale of electric energy.  LG&E also engages in the distribution and sale of natural gas.  LG&E and KU maintain their separate identities and serve customers in Kentucky under their respective names. KU also serves customers in Virginia under the Old Dominion Power name, and it serves customers in Tennessee under the KU name.

LG&E and KU engage in the generation, transmission, distribution and sale of electric energy in Kentucky and, in KU’s case, Virginia and Tennessee. KU provides electric service to approximately 514,000 customers in 77 counties in central, southeastern and western Kentucky, to approximately 30,000 customers in five counties in southwestern Virginia and to less than ten customers in Tennessee.  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.  During 2010, approximately 98% of the electricity generated by KU, and 95% of that generated by LG&E was produced by their coal-fired electric generating stations.  The remainder is generated by natural gas and oil fueled CTs and hydroelectric power plants.  In Virginia, KU operates under the name Old Dominion Power Company.  KU also sells wholesale electric energy to 12 municipalities in Kentucky.  LG&E purchases, transports, distributes or stores natural gas for approximately 320,000 customers in Kentucky.

Our subsidiary, LG&E and KU Services Company provides services to affiliated entities, including the Company, LG&E and KU, at cost, as permitted under PUHCA 2005.  Our other subsidiary, LG&E and KU Capital Corp., holds our interests or obligations regarding former non-utility discontinued operations, which primarily relate to a termination arrangement, effective in July 2009, for a prior lease and operation of generating facilities in western Kentucky and to interests in gas distribution companies in Argentina sold in 2010.

Predecessor and Successor

Our historical financial results are presented using “Predecessor” or “Successor” to designate the periods before or after PPL’s acquisition of the Company.  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 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.

Operations  (Dollars are in millions unless otherwise noted.)

For the year ended December 31, 2010, 89% of total operating revenues were derived from electric operations and 11% from natural gas operations.

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

	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	$	163	2,076	$	749	9,698	$	790	10,690	$	763	11,009
Industrial and commercial	187		2,900	939		14,524	1,014		16,200	1,023		17,283
Municipals	15		326	88		1,676	91		1,848	92		1,971
Other retail	37		482	201		2,594	207		2,927	190		3,010
Wholesale	7		118	26		421	45		759	155		3,142
	$	409	5,902	$	2,003	28,913	$	2,147	32,424	$	2,223	36,415

Our all time peak electric load occurred in 2010 and was 7,175 Mw on August 4, 2010, when the temperature reached highs of 102 and 96 degrees Fahrenheit in Louisville and Lexington, respectively.

LG&E’s and KU’s 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 LG&E and KU 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 LG&E and KU 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%.

LG&E and KU contract with the TVA to act as their transmission reliability coordinator and SPP to function as their 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 for further information.

LG&E and KU jointly dispatch their generation units with the lowest cost generation used to serve their retail native load.  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.  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.  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 had a power supply contract with OMU that was terminated by OMU in May 2010.  We own 8.13% of OVEC’s common stock and are contractually entitled to 8.13% of OVEC’s output.  Based on nameplate generating capacity, this would be approximately 194 Mw.  Additional information regarding this relationship is provided in Notes 1 and 13 to our 2010 Annual Financial Statements.

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

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	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	$	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

During 2010, the maximum daily natural gas send out was approximately 416,000 thousand cubic feet, or 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 natural 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 LG&E’s request to make the current WNA mechanism permanent.

LG&E’s natural gas rates contain a GSC, whereby increases or decreases in the cost of natural gas supply are reflected in its 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.

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, LG&E avoids 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, LG&E 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 its purchasing practices, enable LG&E to offer natural gas sales service at competitive rates.  At December 31, 2010, LG&E 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 LG&E’s distribution system.  These large commercial and industrial customers account for approximately one-fourth of LG&E’s 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 per day.  Under mid-winter design conditions, LG&E expects to be able to withdraw about 307,000 Mcf per day from LG&E’s storage facilities.  The deliverability of natural gas from the storage facilities decreases as storage inventory levels are reduced by seasonal withdrawals.

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Seasonality

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.

Properties

Electric.  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	Total Mw Summer Capacity (a)	% Ownership	Ownership or Lease Interest in Mw	Location
Coal (steam)
Ghent	1,918	100.00	1,918	Carroll County, KY
Mill Creek	1,472	100.00	1,472	Jefferson County, KY
E.W. Brown	684	100.00	684	Mercer County, KY
Cane Run	563	100.00	563	Jefferson County, KY
Trimble County (b)	511	75.00	383	Trimble County, KY
Green River	163	100.00	163	Muhlenberg County, KY
Tyrone	71	100.00	71	Woodford County, KY
OVEC - Clifty Creek (c)	1,304	8.13	106	Jefferson County, IN
OVEC - Kyger Creek (c)	1,086	8.13	88	Gallia County, OH
Total steam	7,772		5,448
Natural gas/oil (CTs)
Trimble County	960	100.00	960	Trimble County, KY
E.W. Brown	947	100.00	947	Mercer County, KY
Paddy’s Run	193	100.00	193	Jefferson County, KY
Haefling	36	100.00	36	Fayette County, KY
Zorn	14	100.00	14	Jefferson County, KY
Cane Run	14	100.00	14	Jefferson County, KY
Total CTs	2,164		2,164
Hydro
Ohio Falls Hydroelectric Station	52	100.00	52	Jefferson County, KY
Dix Dam Hydroelectric Station	24	100.00	24	Mercer County, KY
Total hydro	76		76
Total system capacity	10,012		7,688

(a)The capacity of generation units is based on a number of factors, including the operating experience and physical conditions of the units and may be revised periodically to reflect changed circumstances.

(b)Trimble County Unit 1 is jointly owned with the Illinois Municipal Electric Agency and the Indiana Municipal Power Agency.  See Note 14 to our 2010 Annual Financial Statements for further information.

(c)We are contractually entitled to 8.13% of OVEC’s output based on a power purchase agreement which is comprised of annual minimum debt service payments, as well as contractually-required reimbursement of plant operating, maintenance and other expenses.  OVEC’s capacity is shown at unit nameplate ratings.

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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.  We own a 75% interest in TC2.  Unit 2 is coal-fired and has a capacity of 760 Mw, of which our share is 570 Mw.

At December 31, 2010, LG&E and KU’s electric transmission system included 177 substations (86 of which are shared with the distribution system) with transformer capacity of approximately 19,896 Megavolt-ampere, or MVA, and approximately 4,987 miles of lines.  The electric distribution system included 575 substations (86 of which are shared with the transmission system) with transformer capacity of approximately 12,268 MVA and approximately 18,043 miles of overhead lines and 4,571 miles of underground conduit.

KU also owns 20% of the common stock of Electric Energy, Inc., which owns and operates a 1,162-Mw generating station in southern Illinois.  EEI generally sells its production into the wholesale market.

Gas.  LG&E’s natural gas transmission system includes 391 miles of transmission mains, consisting of 255 miles of natural gas transmission lines, 119 miles of natural gas storage lines and 17 miles of natural gas CT lines.  Our natural gas distribution system includes 4,235 miles of distribution mains.

Each series of outstanding KU and LG&E first mortgage bonds is secured, equally and ratably, by a mortgage lien, subject to certain exclusions and exceptions, on substantially all of that company’s respective 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, in the case of the outstanding LG&E bonds, the storage and distribution of natural gas.

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

Construction and Future Capital Requirements

The construction programs of LG&E and KU are designed to ensure that there will be adequate capacity and reliability to meet the electric needs of their service areas 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 LG&E’s capital expenditures for the three-year period ending December 31, 2013 to total approximately $1.6 billion, and we estimated KU’s capital expenditures for the three-year period ending December 31, 2013 to total approximately $1.4 billion.

In addition to the amounts above, evolving environmental regulations will likely increase the level of capital expenditures over the next several years.  At April 15, 2011, we estimated LG&E’s capital expenditures for environmental control facilities to total approximately $34 million in 2011 and approximately $282 million in 2012, and we estimated KU’s capital expenditures for environmental control facilities to total approximately $174 million in 2011 and approximately $387 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 LG&E and KU fund their capital requirements.  LG&E and KU anticipate funding future capital requirements through operating cash flow, debt and/or infusions of capital from the Company.

For a discussion of liquidity, capital resources and financing activities, see “Management’s Discussion and Analysis.”

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Coal Supply

Coal-fired generating units provided approximately 96% of net kilowatt hour generation for 2010.  The remaining net generation was provided by natural gas and oil fueled CTs and hydroelectric plants.  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 0.7% - 3.5% range, from eastern and 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 barge, truck and rail.

Natural Gas Supply

LG&E purchases 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.

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

LG&E participates in rate and other proceedings affecting the regulated interstate natural gas pipelines that provide it service. Both Texas Gas and Tennessee Gas have active proceedings at the FERC in which LG&E is 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, LG&E’s current negotiated rate in its transportation agreement with Tennessee Gas insulates it from the potential impact of increases in base rates as proposed by Tennessee Gas for the duration of that agreement.

LG&E also has a portfolio of supply arrangements of various terms with a number of suppliers designed to meet its 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 LG&E’s natural gas customers.

Rates and Regulation

LG&E and KU are subject to the jurisdiction of the Kentucky Commission and the FERC, and KU is further subject to the jurisdiction of the Virginia Commission and the Tennessee Regulatory Authority, in virtually all

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matters related to electric and natural gas utility regulation, and as such, their accounting is subject to the regulated-operations guidance of the Financial Accounting Standards Board Accounting Standards Codification, or FASB ASC.  Given their competitive position in the marketplace and the status of regulation in Kentucky, Tennessee and Virginia, there are no plans or intentions to discontinue the application of the regulated operations guidance of the FASB ASC.

LG&E’s and KU’s Kentucky 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 Kentucky base rates; therefore, a return is earned on all Kentucky regulatory assets.  KU’s Virginia base rates are calculated based on a return on rate base (net utility plant less deferred taxes and miscellaneous deductions).  All regulatory assets and liabilities are excluded from the return on rate base utilized in the calculation of Virginia base rates.

PPL Acquisition.  On April 28, 2010, PPL entered into a purchase and sale agreement with our former 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 us.  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, Virginia and Tennessee 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, and on June 15, 2010 with the Virginia Commission and the Tennessee Regulatory Authority.  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 the Company, LG&E and KU.  In the settlement, the parties agreed that LG&E and KU would commit that no base rate increases would take effect before January 1, 2013.  The rate increase for LG&E and KU that took effect on August 1, 2010 (as described below) will not be impacted by the settlement.  Under the terms of the settlement, LG&E and KU 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 LG&E and KU 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 and KU to each 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.  In October 2010, both the Virginia Commission and the Tennessee Regulatory Authority approved the transfer of control of the Company from E.ON US Investments Corp. to PPL.  The Commissions’ orders 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 KU, LG&E, 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 agreement not to terminate certain KU municipal customer contracts prior to January 2017, an exclusion of any transaction-related costs from wholesale energy and tariff customer rates to the extent that LG&E and KU 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, LG&E and KU filed applications with the Kentucky Commission requesting increases in electric base rates of approximately 12%, or $95 million and $135 million annually, respectively.  In addition, LG&E requested an increase in its natural gas base rates of approximately 8%, or $23 million annually.  The requested rate increases for both LG&E and KU were based on an 11.5% return on

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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 the requested rate increases of LG&E and KU, in whole or in part.  In June 2010, LG&E and KU and all of the intervenors except for the Kentucky Attorney General agreed to stipulations providing for increases in LG&E’s and KU’s electric base rates of $74 million and $98 million annually, respectively, and LG&E’s 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 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.

Virginia Rate Cases.  In April 2011, KU filed an application with the Virginia Commission, requesting an increase in base rates of approximately 14%, or $9 million annually.  The requested rate increase is based on an 11% return on equity, inclusion of expenditures to complete TC2, all new flue gas desulfurization controls in base rates, recovery of a 2009 regulatory asset and various other adjustments to revenue and expenses for the test year ended December 31, 2010.  We cannot predict the outcome of this proceeding.

In June 2009, KU filed an application with the Virginia Commission requesting an increase in electric base rates for its Virginia jurisdictional customers in an amount of $12 million annually or approximately 21%.  The proposed increase reflected a proposed rate of return on rate base of 8.586% based on a return on equity of 12%.  As permitted pursuant to a Virginia Commission order, KU elected to implement the proposed rates effective November 1, 2009, on an interim basis.  During December 2009, KU and the Virginia Commission Staff agreed to a Stipulation and Recommendation authorizing a base rate revenue increase of $11 million annually and a return on rate base of 7.846% based on a 10.5% return on equity.  In March 2010, the Virginia Commission issued an order approving the stipulation, with the increased rates to be put into effect as of April 1, 2010.  As part of the stipulation, KU refunded approximately $1 million in interim rate amounts in excess of the ultimate approved rates.

FERC Wholesale Rate Case.  In September 2008, KU filed an application with the FERC for increases in electric base rates applicable to wholesale power sales contracts or interchange agreements involving, collectively, twelve Kentucky municipalities. The application requested a shift from an all-in stated unit charge rates to an unbundled formula rate, including an annual adjustment mechanism. In May 2009, the FERC issued an order approving a settlement among the parties in the case, incorporating increases of approximately 3% from prior rates and a return on equity of 11%. In May 2010, KU submitted to the FERC the proposed current annual adjustments to the formula rates, which incorporated certain proposed increases. Updated rates, including certain further adjustments from a review process involving wholesale requirements customers, became effective as of July 1, 2010.

By mutual agreement, the parties’ settlement of the 2008 application left outstanding the issue of whether KU must allocate to the municipal customers a portion of renewable resources it may be required to procure on behalf of its retail ratepayers.  An order was issued by the FERC in July 2010, indicating that KU is not required to allocate a portion of any renewable resources to the twelve municipalities, thus resolving the remaining issue.

Refund of Over-Collected Amounts.  On July 15, 2010, we submitted, on behalf of LG&E and KU, an informational filing indicating we 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.  We, along with LG&E 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.  LG&E 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 LG&E’s and KU’s service areas causing approximately 404,000 customer outages, followed closely by a severe wind storm in February 2009,

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causing approximately 81,000 customer outages. LG&E and KU filed applications with the Kentucky Commission in April 2009, requesting approval to establish regulatory assets and defer for future recovery approximately $107 million in incremental operation and maintenance expenses related to the storm restoration.  In September 2009, the Kentucky Commission issued orders allowing the establishment of regulatory assets of up to $107 million based on actual costs for storm damages and service restoration due to the January and February 2009 storms.  In September 2009, LG&E and KU established regulatory assets of $101 million for actual costs incurred.  LG&E and KU received approval in their 2010 base rate cases to recover these assets 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, LG&E and KU filed applications with the Kentucky Commission requesting approval to establish regulatory assets and defer for future recovery approximately $27 million of expenses related to the storm restoration.  In December 2008, the Kentucky Commission issued orders allowing LG&E and KU to establish regulatory assets for these amounts based on their actual costs for storm damages and service restoration due to Hurricane Ike.  In December 2008, LG&E and KU established regulatory assets of $26 million for actual costs incurred.  LG&E and KU received approvals in their 2010 base rate cases to recover these assets over a ten year period beginning August 1, 2010.

In December 2009, a significant snow storm passed through KU’s Virginia service area causing approximately 30,000 customer outages.  KU filed a base rate application with the Virginia Commission requesting approval to establish a regulatory asset and defer for future recovery approximately $7 million of expenses related to the storm restoration.  In March 2011, the staff of the Virginia Commission recommended that KU begin amortizing these costs over five years concurrent with the effective date of the rates in KU’s 2011 rate case.  As the Virginia Commission has not yet approved this recovery, we cannot predict the outcome of this proceeding.

2008 Electric and Gas Rate Cases.  In July 2008, LG&E and KU filed applications with the Kentucky Commission requesting increases in electric and natural gas base rates.  In January 2009, LG&E, KU, the Kentucky Attorney General, the Kentucky Industrial Utility Consumers, Inc. and all other parties to the rate cases filed settlement agreements with the Kentucky Commission, under which LG&E’s natural gas base rates increased by $22 million annually and LG&E’s and KU’s electric base rates $13 million and $9 million annually, respectively.  Orders approving the settlement agreements were received in February 2009.  The new rates were implemented effective February 2009.

Rate Mechanisms

WNA.  LG&E’s gas billings include a WNA mechanism which adjusts the distribution cost component of the natural gas billings 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.  LG&E’s natural gas rates contain a GSC, whereby increases or 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 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.  LG&E’s and KU’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 LG&E and KU 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.

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ECR.  Kentucky law permits LG&E and KU 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%.

DSM.  The rates of LG&E and KU 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 LG&E and KU 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.

Environmental Matters

General.  Protection of the environment is a major priority for LG&E and KU, and a significant element of their business activities.  The properties and operations of LG&E and KU 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, they must conduct their 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, LG&E and KU, as primarily coal-fired utilities, 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 73% coal-fired, 26% oil/natural gas-fired and 1% hydroelectric based on capacity.  During 2010, we produced approximately 96% of our electricity from coal, 3% from natural gas combustion and 1% from hydroelectric generation, based on Mw hours.  During 2010, our emissions of GHGs were approximately 32.6 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.

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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 LG&E’s and KU’s 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 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 entirely intrastate trading or 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 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.  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 LG&E and KU, to obtain information on their ash ponds and other impoundments.  In addition,

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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 and KU’s impoundments, which the EPA found to be in satisfactory condition except for certain impoundments at LG&E’s 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 EPA and the subsequent implementation of the rule by the states.  The EPA has also announced plans to develop revised effluent limitations guidelines governing discharges from power plants.  The EPA has further announced plans to develop revised standards governing the use of PCBs 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.

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 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 emissions reductions 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, the Company 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 $3.25 to $3.75 billion range over the next ten years, although final costs may substantially vary.  With respect to potential developments in water standards, 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.

Discontinued Operations

WKE Termination.  Through WKE and its subsidiaries, the Company had a 25-year lease on and operated the generating facilities of Big Rivers Electric Corporation, a power-generating cooperative in western Kentucky, and a coal-fired generating facility owned by the City of Henderson, Kentucky.

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In 2007, we entered into a termination agreement to terminate the lease, which closed in 2009, prior to PPL acquiring us.  As part of the lease termination, we were obligated to pay a former customer, an aluminum smelter, an aluminum production payment in lieu of a lump-sum cash consent payment, as well as the difference between the electricity prices charged by WKE under the previous long-term sales contract and the electricity prices charged by the current electricity supplier.  This obligation is partially mitigated by the opportunity to make off-system sales, when economic, for the contractual demand not used by the aluminum smelter. The total amount of the obligation to this smelter was limited to $82 million, with any amount we paid over the limit has been recorded as an interest-bearing receivable, which is required to be repaid only if certain conditions occur by 2028. Such exposure expired on December 31, 2010. During the years ended December 31, 2010 and December 31, 2009, the Company made payments totaling $65 million and $26 million, respectively, as part of the transaction. Since the former customer posted a letter of credit supporting payment to its current electricity supplier, we reversed a portion of the accrual associated with our guarantee of payment by the former customer.  The estimated remaining payments were accrued at December 31, 2010 including an obligation to another aluminum smelter, also a former customer, to make an escrow payment of $4 million in January 2011.  The change in fair value of the derivative contract since acquisition along with the reversal of the accrual resulted in the income statement impact reflected in “Gain(loss) on disposal of discontinued operations.”  See also Notes 6, 10 and 13 to our 2010 Annual Financial Statements for further discussion of these or of additional elements of the WKE lease termination transaction.

Argentine Gas Distribution.  At December 31, 2009, we owned interests in two natural gas distribution companies in Argentina: 45.9% of Distribuidora de Gas Del Centro S.A., or Centro, and 14.4% of Distribuidora de Gas Cuyana S.A., or Cuyana.  These two entities served a combined customer base of approximately one million customers.  The Centro investment was consolidated due to our majority ownership in the holding company of Centro.  The Cuyana investment was accounted for using the equity method due to the ownership influence we exerted on the businesses.

In November 2009, our subsidiaries entered into agreements to sell their direct and indirect interests in Centro and Cuyana to E.ON Spain and a subsidiary, both affiliates of E.ON.  On January 1, 2010, the parties completed the transfer of the interests for a sale price of $35 million. In December 2009, we recorded an impairment loss of $12 million before income taxes.  The impairment loss represented the difference between the carrying values of our interests in Centro and Cuyana and the sales price.  We classified the assets, liabilities and results of operations of the Argentine natural gas distribution companies, including the impairment loss, as discontinued operations for all periods presented effective December 31, 2009. In connection with the reorganization transaction, E.ON Spain assumed rights and obligations relating to claims and liabilities associated with the former Argentine businesses or indemnified us with respect to such matters.

State Executive or Legislative Matters

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:

·Improve the energy efficiency of Kentucky’s homes, buildings, industries and transportation fleet

·Increase Kentucky’s use of renewable energy

·Sustainably grow Kentucky’s production of biofuels

·Develop a coal-to-liquids industry in Kentucky to replace petroleum-based liquids

·Implement a major and comprehensive effort to increase natural gas supplies, including coal-to-natural gas in Kentucky

·Initiate aggressive carbon capture/sequestration projects for coal-generated electricity in Kentucky

·Examine the use of nuclear power for electricity generation in Kentucky

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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.

Employees and Labor Relations

We had 3,160 employees at December 31, 2010, consisting of 3,122 full-time employees and 38 part-time employees.  Of the total employees, 831, or 26%, were operating, maintenance and construction employees represented by the International Brotherhood of Electric Workers Local 2100 and the United Steelworkers of America Local 9447-01.  In November 2008, LG&E and its 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.  In August 2009, KU and its 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 and annual wage re-openers.  In August 2008, KU and its employees represented by the USWA Local 9447-01 entered into a three-year collective bargaining agreement that provides for negotiated increases or changes to wages, benefits or other provisions and annual wage re-openers.

Competition

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.  Virginia, formerly a competitive jurisdiction, has enacted legislation which implements a hybrid model of cost-based regulation.  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 LG&E’s annual throughput is purchased by large commercial and industrial customers directly from alternate suppliers for delivery through LG&E’s distribution system.  Since LG&E does not profit from its sale of natural gas as a commodity, 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 LG&E’s 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

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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.

Legal Proceedings

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

In connection with an administrative proceeding alleging a violation by a former Argentine subsidiary under that country’s 2002-2003 emergency currency exchange laws, claims were brought against the subsidiary’s then directors, including two individuals who are executive officers of the Company, in a specialized Argentine financial criminal court.  Under applicable Argentine laws, directors of a local company may be liable for monetary penalties for a subject company’s violations of the currency laws.  In February 2011, the Argentine court issued an order acquitting the former subsidiary and its directors of all claims, which order has become final.

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.

Franchises and Licenses

LG&E and KU provide electric delivery service, and LG&E provides natural gas distribution service, in their 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.

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MANAGEMENT

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 the Company, LG&E and KU.

Listed below are the executive officers and directors at April 1, 2011.

Name	Age	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

A brief biography of each director and executive officer follows:

Victor A. Staffieri has been Chairman, President and Chief Executive Officer of the Company, LG&E and KU 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 Company, from February 1999 to April 2001 and President of LG&E and KU from June 2000 to April 2001.  He served as Chief Financial Officer of LG&E Energy  and LG&E 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 LG&E from January 1994 to December 1995 and Senior Vice President of Public Policy of LG&E Energy and LG&E from November 1992 to December 1993 and General Counsel.  Mr. Staffieri has been a Director of the Company, LG&E and KU 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, LG&E and KU since 2003 and serves as its Principal Accounting Officer.  Before he was elected to his current position, Mr. Rives was Senior Vice President—Finance and Controller of LG&E Energy, LG&E and KU from December 2000 to September 2003.  He has been a Director of the Company since December 2004 and LG&E and KU since January 2004.  Mr. Rives is a certified public accountant and 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, LG&E and KU since 2006 and Executive Vice President, General Counsel and Corporate Secretary of the Company and LG&E since July 1994 and of KU since May 1998.  Mr. McCall has been a Director of the Company since December 2003 and LG&E 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

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Chris Hermann has been Senior Vice President—Energy Delivery of the Company, LG&E and KU since 2003.  Before he was elected to his current position, Mr. Hermann was Senior Vice President—Distribution Operations, of LG&E Energy, LG&E and KU from December 2000 to February 2003.  Mr. Hermann has been a Director of the Company, LG&E and KU 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, LG&E and KU 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 LG&E from December 1998 to August 1999.  Mr. Thompson served as Vice President—Retail Electric Business for LG&E 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, LG&E and KU 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 LG&E, 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 LG&E, KU, PPL Electric Utilities Corporation and PPL Energy Supply, LLC. Mr. Spence has been a director of the Company since November 2010.

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EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Overview

On November 1, 2010, PPL acquired us and our subsidiaries, including LG&E and KU, 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 us, LG&E and KU.  The information we are providing relates to total compensation for our named executive officers for 2010, without any allocation among the companies.

Our named executive officers are:

·Victor A. Staffieri - chairman of the board, president and chief executive officer of us, LG&E and KU

·S. Bradford Rives - chief financial officer of us, LG&E and KU

·John R. McCall - executive vice president, general counsel, corporate secretary and chief compliance officer of us, LG&E and KU

·Chris Hermann - senior vice president — energy delivery of us, LG&E and KU and

·Paul W. Thompson - senior vice president — energy services of us, LG&E and KU.

The named executive officers also serve as directors of us, LG&E and KU.

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 and we 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:

·current base salary

·2010 short-term and long-term incentive awards and targets

·accelerated vesting of outstanding long-term incentive awards made in 2008, 2009 and 2010, which were paid in cash upon the acquisition

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·a cash divestiture incentive payment, previously approved by the E.ON AG Board of Management

·all other payments made to Mr. Staffieri during 2010 relating to benefit plans or perquisites and

·a new grant of PPL restricted stock units to be made for retention purposes.

The Compensation, Governance and Nominating Committee also ratified Mr. Staffieri’s amended and restated employment and severance agreement with us 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 purposesand approved payment of their 2010 short-term incentive awards in January 2011.

Compensation Elements

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.

Direct Compensation

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

	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

(1) Percentages based on target award levels as a percentage of total target direct compensation.  Actual amounts earned for short-term and long-term incentives are reflected in the Summary Compensation Table.

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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.

Table 2

2010 Base Salary Adjustments by Position — Effective January 1, 2010

	2009 Base Salary		2010 Base Salary		% Change
Victor A. Staffieri	$	811,220	$	811,220	0%
S. Bradford Rives	$	402,300	$	414,400	3%
John R. McCall	$	493,100	$	507,900	3%
Chris Hermann	$	316,600	$	326,100	3%
Paul W. Thompson	$	375,500	$	386,800	3%

Short-Term Incentive Awards

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

Position	Targets as a % of Base Salary
Victor A. Staffieri	75%
S. Bradford Rives	50%
John R. McCall	50%
Chris Hermann	50%
Paul W. Thompson	50%

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

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Table 4

2010 Short-Term Incentive Goals and Weightings before Change in Control

	E.ON AG  Adjusted EBIT	E.ON U.S.  Adjusted EBIT	Lost-Time  Injury  Frequency /  Safety	Management  Effectiveness
Victor A. Staffieri	20%	30%	10%	40%
S. Bradford Rives	20%	30%		50%
John R. McCall	20%	30%	7%	43%
Chris Hermann	20%	30%	10%	40%
Paul W. Thompson	20%	30%		50%

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.

Table 5

2010 Short-Term Incentive Goals and Weightings after Change in Control

	Combined LG&E and  KU Energy Adjusted  EBIT + PPL EPS	LG&E and KU  Energy  Adjusted EBIT	Lost-Time Injury  Frequency /  Safety	Management  Effectiveness
Victor A. Staffieri	20%	30%	10%	40%
S. Bradford Rives	20%	30%	10%	40%
John R. McCall	20%	30%	10%	40%
Chris Hermann	20%	30%	10%	40%
Paul W. Thompson	20%	30%	10%	40%

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.

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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 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:

Table 6

2010 Short-Term Incentive Goals and Results

Goal	Weighting as % of Total Target Award	Target	Actual Results	Results as % of Total Target Award
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

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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:

·successfully prosecute 2010 rate case before the Kentucky Commission, as measured by annualized revenue increase granted.  Consideration would be given, as appropriate, to the impact of strategic initiatives, financing costs, depreciation expense and other regulatory proceedings

·maintain good regulatory relations and full recovery of Environmental Cost Recovery surcharge for regulated expenditures

·effectively manage investment program, balancing capital constraints with internal and regulatory expectations of providing safe and reliable service and

·develop scenarios to understand effects of possible carbon dioxide (CO2) requirements.

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:

·we achieved the successful rate case goal with annualized revenue increase exceeding goal target of $187 million

·the quality of our operations’ regulatory relations, as reflected in the Kentucky Commission approval of the rate case settlement without adjustments

·the achievement of the Environmental Cost Recovery surcharge recovery which fell short of the maximum target of $221 million and the GAAP budget capital spending at $610 million and

·we successfully updated the long-term financing planning model to adjust for the various tenets of proposed CO2 legislation and calculated the impact of various proposals throughout the year.  This effort was expanded to cover a number of new proposed Environmental Protection Agency regulations.

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.

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

·support company goals and initiatives for safety, wellness, diversity, affirmative action and model company values and behaviors.  Ensure performance management and individual development plans are completed for each employee, and that job performance and behaviors align with position expectations and support company goals and objectives.  Ensure succession planning is considered in creating development plans, promotions, reassignments, and hiring decisions.  Inform, evaluate and discuss employee opinion survey results and implement action plans

·successfully prosecute 2010 rate case before the Kentucky Commission, as measured by annualized revenue increase granted.  Consideration would be given, as appropriate, to the impact of strategic initiatives, financing costs, depreciation expense and other regulatory proceedings

·develop scenarios to understand effects of possible CO2 requirements

·effectively manage working capital

·effectively manage information technology function through transition and hire a new chief information officer and

·advance strategic initiatives as directed by Mr. Staffieri and E.ON AG including refinancing intercompany debt.

The assessment of Mr. Rives’ performance took into consideration that he:

·provided significant contributions relating to the November 1, 2010 change in control

·provided key testimony, settlement position development and management oversight of the rate case that was settled in July 2010

·oversaw the completion of the refinancing activity in the fourth quarter

·coordinated a search for and hired a new chief information officer in 2010 and provided financial oversight of the capital and expense budgets throughout the organization, effectively managing changing priorities

·was involved in the environmental scenario development incorporated into the 2011-2015 business plan and

·supervised the tax department in reaching settlements of state and federal tax matters.

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:

·support company goals and initiatives for safety, wellness, diversity, affirmative action and model company values and behaviors.  Ensure performance management and individual development plans are completed for each employee, and that job performance and behaviors align with position expectations and support company goals and objectives.  Ensure succession planning is

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considered in creating development plans, promotions, reassignments, and hiring decisions.  Inform, evaluate and discuss employee opinion survey results and implement action plans

·advance strategic initiatives as directed by Mr. Staffieri and E.ON AG

·resolve litigation and

·deliver 2010 regulatory compliance oversight.

The performance assessment of Mr. McCall took into consideration that he:

·led the strategy and implementation efforts for early regulatory approval of the change in control

·worked with Mr. Rives’ team to reach a successful settlement of the rate case proceeding

·was heavily involved in fourth quarter refinancing efforts

·worked with the tax department to settle matters with state and federal tax authorities

·oversaw the successful representation of company interests during the last Kentucky legislative session and

·provided effective oversight of the regulatory compliance program and supported corporate responsibility and diversity efforts and communication strategy.

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:

·support company goals and initiatives for safety, wellness, diversity, affirmative action and model company values and behaviors.  Ensure performance management and individual development plans are completed for each employee, and that job performance and behaviors align with position expectations and support company goals and objectives.  Ensure succession planning is considered in creating development plans, promotions, reassignments, and hiring decisions.  Inform, evaluate and discuss employee opinion survey results and implement action plans

·achieve overall energy delivery employee recordable injury rate. Reinforce the safety culture in energy delivery, through leadership, communications, performance monitoring and maximizing employee involvement. Drive sustained improvement in the safety performance of energy delivery and contractor companies

·achieve energy delivery budget and capital commitments.  Continue to identify and implement process improvements in energy delivery.  Implement supplier related initiatives to reduce cost and improve supplier diversity and relationships.  Manage energy delivery budget to address unexpected shortfalls due to storm restoration efforts and

·maintain high reliability and achieve availability and reliability targets.

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

·received the Edison Electric Institute’s Emergency Recovery Award for outstanding restoration efforts related to the 2009 Kentucky ice storm, which was characterized by Kentucky’s governor as the worst storm in the Commonwealth’s history

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·achieved 2010 reliability and availability results that improved over 2009 results, although they did not meet target in 2010

·achieved energy delivery budget and commitments

·successfully launched major technology and service improvement initiatives that enhanced work efficiency and resulted in positive business and customer impacts and

·received eleven state, national and international awards for safety performance.

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:

·achieve upstream generation results for safety, unplanned unavailability, achievement of financial availability deviation and successful delivery of new build project

·support company goals and initiatives for safety, wellness, diversity, affirmative action and model company values and behaviors.  Ensure performance management and individual development plans are completed for each employee, and that job performance and behaviors align with position expectations and support company goals and objectives.  Ensure succession planning is considered in creating development plans, promotions, reassignments, and hiring decisions.  Inform, evaluate and discuss employee opinion survey results and implement action plans

·lead strategic issues to include environmental, political, regulatory, transmission and long-term investments and

·strengthen personal network and relationships with all other E.ON AG officers.  Spend time each quarter in the field, build local, state and federal community network and relationships.

The performance assessment of Mr. Thompson took into consideration that he:

·oversaw the successful completion of the Trimble County construction

·oversaw the operations of the generating fleet which performed effectively during record breaking summer peak demand, achieved safety results better than target and managed budgets well

·developed a good management team

·was a key player in developing strategy on environmental issues, scenario planning and communications and

·was effective in settling transmission related issues with customers in 2010.

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

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

Table 7

Short-Term Incentive Goals and Results as Percent of Award Earned

Name	Combined LG&E and KU Energy LLC Adjusted EBIT + PPL EPS (%)	LG&E and KU Energy LLC Adjusted EBIT (%)	Lost-Time Injury Frequency / Safety (%)	Management Effectiveness (%)	Total Goal Result as % of Target Award Earned
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

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

2010 Base Salary (Table 2) X Incentive Target Percentage (Table 3) X Total Goal Results (Table 7) = 2010 Short-Term
Incentive Award
Payment (Table 8)

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.”

Table 8

Short-Term Incentive Awards for 2010 Performance

	Salary Basis for Award	Target as a % of Salary	Total Goal Results	2010 Short-Term Incentive Award Payment
Victor A. Staffieri	$811,220	75%	127.93%	$778,400
S. Bradford Rives	$414,400	50%	143.93%	$298,200
John R. McCall	$507,900	50%	143.93%	$365,500
Chris Hermann	$326,100	50%	141.93%	$231,400
Paul W. Thompson	$386,800	50%	143.93%	$278,400

Long-Term Incentive Awards Granted in 2010 Prior to the Change in Control

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:

·75 percent of the total target award opportunity was comprised of performance units with a 2010-2012 performance period granted under the LG&E Energy Corp. Long-Term Performance Unit Plan and

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·25 percent of the total target award opportunity was comprised of share performance rights with a 2010-2013 performance period granted under the E.ON Share Performance Plan.

Performance Units

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.

Share Performance Rights

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    x    Performance Factor    x    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:

Table 9
E.ON Share Performance Rights Performance Factor

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

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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.”

Table 10

2010 Long-Term Incentive Award Targets

	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%

Payment of Long-Term Incentive Awards Granted in 2007

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.

Performance Units

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.

Share Performance Rights

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.

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

Table 11

Long-Term Incentive Awards Granted in 2007 and Paid in 2010

	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

(1) E.ON AG share performance rights payments are included in the Option Exercises and Stock Vested table in the column headed “Value Realized on Vesting.”

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.

Performance Units

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.

Table 12

LG&E Energy Corp. Long-Term Performance Unit Plan Award Summary

Share Performance Rights

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

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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.

Table 13

 Long-Term Incentive Award Payments Made in 2010

	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

(1)	E.ON AG share performance rights payments 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.”
(2)	LG&E Energy performance unit payments are included in the Summary Compensation Table in the column headed “All Other Compensation.”

Divestiture Incentive Awards Paid in 2010

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 us.  Payment of the award opportunity depended upon objective factors - the price paid for the company - 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.

Table 14
Earned Divestiture Incentive Award Payments

Name	Threshold ($)	Target ($)	Maximum ($)	Amount Earned ($)(1)
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

(1) Amounts earned are included in the Summary Compensation Table in the column headed “Non-Equity Incentive Plan Compensation.”

Retention Agreements and Restricted Stock Unit Awards Granted by PPL in 2010

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

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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 by affiliates of PPL and to compensate Mr. Staffieri for the loss of these perquisites.

The named executive officers received the following awards:

Table 15
2010 Restricted Stock Unit Awards

Name	Number of Restricted Stock Units Granted (#)	Grant Date Fair Value ($)(1)	Vesting Date
Victor A. Staffieri	80,940	2,129,531	December 1, 2012
Bradford Rives	23,630	621,705	December 1, 2012
John R. McCall	28,960	761,938	December 1, 2011
Chris Hermann	18,590	489,103	December 1, 2012
Paul W. Thompson	22,050	580,136	December 1, 2012

(1) The grant date fair value of the restricted stock units 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 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.

Perquisites and Other Benefits

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.

·annual $15,000 auto allowance to lease a vehicle and personal use of that vehicle.  If the total lease cost is less than the annual allowance, the difference is paid in cash to the named executive officer

·country club membership for Mr. Staffieri

·personal financial planning and tax preparation services

·company-paid reserved parking

·supplemental executive term life insurance for all named executive officers, except Mr. McCall who received a cash payment instead and

·travel on the company aircraft for spouses of Messrs. Staffieri and McCall when the executive traveled on the aircraft for business purposes.

We 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,

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country/luncheon club membership, tax preparation fees and financial planning services and spousal air travel, and for Mr. Staffieri, life insurance benefits.

Matching Contributions on Nonqualified Deferred Compensation

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.  We match executive contributions to the E.ON U.S. LLC Nonqualified Savings Plan equal to 70 percent of the first six percent deferred.

Employment Agreements

In October 2010, we 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 us 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 us.  The 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 us 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.

Tax and Accounting Considerations

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, we 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.  We have determined that it is appropriate to provide protection to the named executives from adverse consequences of the additional tax.

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Executive Compensation Tables

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 us, LG&E and KU.  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 LG&E and KU during 2010, but received no compensation for board service.

Summary Compensation Table for 2010

Name and Principal Position (a)	Year(b)	Salary ($)(c)	Bonus ($)(d)	Stock Awards ($)(1)(e)	Option Awards ($)(f)	Non-Equity Incentive Plan Compensation ($)(2)(g)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)(3)(h)	All Other Compensation ($)(4)(i)	Total ($)(j)
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

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	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	401(k) Match ($)	Non- Qualified Deferred Compensation Employer Contributions ($) (a)	Change in Control — Accelerated Payments ($)(b)	Executive Auto Personal Usage ($)(c)	Executive Auto Lease Allowance Cash Difference ($)(c)	Company -Paid Reserved Parking ($)	Country/ Luncheon Club ($)	Gift Card ($)	Executive Life Insurance ($)(d)		Financial Planning ($)	Spousal Air Travel ($)(f)	Tax Preparation ($)	Vacation Sell Back ($)	Tax Gross- Up ($)(g)
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

(a)	We match executive contributions to the E.ON U.S. LLC Nonqualified Savings Plan equal to 70 percent of the first six percent deferred.
(b)	Vesting of all outstanding awards granted in 2008, 2009 and 2010 under the E.ON Share Performance Plan and the LG&E Energy Corp. Long-Term Performance Unit Plan was accelerated upon the November 1, 2010 change in control, and the awards were paid in cash as follows:

Name	2010 E.ON Share Performance Rights ($)	2009 E.ON Share Performance Rights ($)	2008 E.ON Share Performance Rights ($)	2010 LG&E Energy Corp. Long- Term Performance Units ($)	2009 LG&E Energy Corp. Long- Term Performance Units ($)	2008 LG&E Energy Corp. Long- Term Performance Units ($)
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

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(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 us 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)	We 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.

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Grants of Plan-Based Awards During 2010

		Board or	LG&E Energy Corp. Long-Term Performance Unit:	Estimated Possible Payouts Under Non- Equity Incentive Plan Awards			Estimated Possible Payouts Under Equity Incentive Plan Awards			All Other Stock Awards: Number of Shares of Stock	All Other Option Awards: Number of Securities Underlying	Exercise or Base Price of Option	Grant Date Fair Value of Stock and Option
Name (a)	Grant Date (b)	Committee Approval Date	Number of Units (#)	Threshold ($) (c)	Target ($) (d)	Maximum ($) (e)	Threshold ($) (f)	Target ($) (g)	Maximum ($) (h)	or Units (#) (i)	Options (#) (j)	Awards ($/sh) (k)	Awards (6) (l)
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

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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

Short-Term Incentive Awards

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.

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Long-Term Incentive Awards Granted in 2010 Prior to the Change in Control

The long-term incentive awards granted in 2010 had two components:

·75 percent of the total target award opportunity was comprised of performance units with a 2010-2012 performance period granted under the LG&E Energy Corp. Long-Term Performance Unit Plan and

·25 percent of the total target award opportunity was comprised of share performance rights with a 2010-2013 performance period granted under the E.ON Share Performance Plan.

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.

Divestiture Incentive Awards Paid in 2010

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 us.  We describe these divestiture incentive awards in the Compensation Discussion and Analysis.

Retention Agreements and Restricted Stock Unit Awards Granted by PPL in 2010

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.

Employment Agreements

In October 2010, we 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.

Salary and Bonus as a Proportion of Total Compensation

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

Name	Salary ($)	Total Compensation ($)	Salary as % of Total Compensation
Staffieri	811,220	11,682,606	6.94
Rives	414,215	3,839,712	10.79
McCall	507,674	4,619,118	10.99
Hermann	326,102	2,624,862	12.42
Thompson	386,624	3,613,711	10.70

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Outstanding Equity Awards at Fiscal-Year End 2010

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.

	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

(1)Restrictions lapse on these awards on December 1, 2011 for Mr. McCall and on December 1, 2012 for Messrs. Staffieri, Rives, Hermann and Thompson assuming the named executive officer remains continually employed by affiliates of PPL until then.

(2)The fair market value of the units was based on the closing price of PPL common stock on the New York Stock Exchange on December 31, 2010, which was $26.32.

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Option Exercises and Stock Vested in 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.

	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

(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.

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Pension Benefits in 2010

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

Name (a)	Plan Name (b)(1)	Number of Years Credited Service (#) (c)	Present Value of Accumulated Benefit ($) (d)	Payments During Last Fiscal Year ($) (e)
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

(1)   E.ON U.S. LLC Retirement Plan (Retirement) and LG&E Energy Corp. Supplemental Executive Retirement Plan (SERP).

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.

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.

Benefit formula

The plan provides monthly retirement income equal to the greater of

·1.58 percent of average monthly earnings plus 0.40 percent of average monthly earnings in excess of covered compensation, such sum multiplied by years of credited service and

·1.68 percent of average monthly earnings multiplied by years of credited service.

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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.

Early retirement

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:

Age	Early Retirement Factor
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

Form of payment

Participants may choose whether their benefits will be in the form of:

·a single life annuity

·a survivor annuity payable to the participant’s designated relative equal to 50 percent, 66 2/3 percent, 75 percent or 100 percent of the participant’s benefit. Under the survivor annuity options, the benefit payments are reduced to allow payments for the longer of two lives. The reduction factor is determined by the age difference between the participant and the participant’s relative or

·a level income form equal to the actuarial equivalent of the participant’s normal retirement benefit, but increased for each month prior to the participant’s attainment of age 62 and decreased after age 62 so that the participant’s total monthly plan benefit and social security retirement benefit are approximately level during the participant’s lifetime.

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LG&E Energy Corp. Supplemental Executive Retirement Plan

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 the company’s creditors in the event of bankruptcy.  The purpose of the SERP is to provide additional retirement income to selected executives.

Benefit formula

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:

·100 percent of the monthly E.ON U.S. LLC Retirement Plan benefit payable at age 65

·100 percent of the primary social security benefit payable at age 65

·100 percent of any matching contribution or other employer contribution for those participants where the defined contribution is the primary retirement vehicle and

·100 percent of any other employer-provided benefit payable at age 65 as a life annuity from any qualified defined benefit plan or defined contribution plan sponsored by previous employers, provided such qualified defined contribution plan was the employer’s primary vehicle for retirement.

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 and early retirement

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:

Age at Commencement	Percentage of Benefit Payable
61	96
60	92
59	86
58	80
57	74
56	68
55	62

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Forms of payment

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.

SERP Payments upon Separation from Service as of December 31, 2010

Name	Separation from Service (Other Than Death or Disability) ($)	Death ($)	Disability ($)
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

(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.

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Non-Qualified Deferred Compensation in 2010

Name (a)	Executive Contributions in Last FY ($)(1) (b)	Registrant Contributions in Last FY ($)(1) (c)	Aggregate Earnings in Last FY ($) (d)	Aggregate Withdrawals / Distributions ($) (e)		Aggregate Balance at Last FYE ($) (f)
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

(1)Executive contributions to the E.ON U.S. LLC Nonqualified Savings Plan are reported in the salary column of the Summary Compensation Table for 2010.  Registrant contributions to the E.ON U.S. LLC Nonqualified Savings Plan are reported in the All Other Compensation column of the Summary Compensation Table for 2010.  Contributions to the LG&E Energy Corp. Nonqualified Savings Plan have not been previously reported in a Summary Compensation Table.

(2)Paid in accordance with Mr. Staffieri’s deferral election under the E.ON U.S. LLC Nonqualified Savings Plan.

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.

Participation

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.

Deferrals

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

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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.

Interest

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.

Distributions

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.

Employment-Related Arrangements

Messrs. Staffieri’s and McCall’s Agreements

In connection PPL’s acquisition of us, we 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 us 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 we or any subsidiary 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:

·a position of chairman of the board of directors, chief executive officer and president of LG&E and KU Energy LLC for Mr. Staffieri and a position of executive vice president, general counsel and corporate secretary of LG&E and KU Energy LLC for Mr. McCall

·a base salary of at least $811,220 for Mr. Staffieri and at least $507,900 for Mr. McCall, which were their base salaries at the time of the change in control

·a divestiture incentive award payment of $2,129,453 for Mr. Staffieri and $1,142,775 for Mr. McCall, which was paid upon closing of the change in control

·a retention agreement, which is described below

·short-term incentive award opportunities with a target of not less than 75 percent of base salary for Mr. Staffieri and not less than 50 percent for Mr. McCall

·long-term incentive award opportunities with a target of not less than 175 percent of base salary for Mr. Staffieri and not less than 100 percent for Mr. McCall

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·participation in employee benefit programs and in the LG&E Energy Corp. Supplemental Executive Retirement Plan and the E.ON U.S. LLC Nonqualified Savings Plan

·term life insurance for Mr. Staffieri of at least $2,000,000 and a full gross-up with respect to any taxes paid by Mr. Staffieri imposed as a result of such life insurance, the gross-up of which was given up by Mr. Staffieri, as discussed below

·a supplemental life insurance annual payment of $29,255 for Mr. McCall in lieu of a supplemental life insurance policy and

·perquisites:

·for Mr. Staffieri and Mr. McCall: an automobile allowance, financial planning, tax preparation, company-paid reserved parking and executive physical examination

·for Mr. Staffieri only: an employer-paid country club membership, company-paid use of air transportation for non-business purposes and full tax gross-up payments on Mr. Staffieri’s perquisites, all of which were given up by Mr. Staffieri as discussed below and

·for Mr. McCall only: a luncheon club membership.

If, within two years following our 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 us for reasons other than cause, disability or death, which includes notice by us not to extend the term of the agreement, the executive would be entitled to:

·earned, but unpaid salary and vacation pay at the time of termination

·a lump sum cash payment equal to 2.99 times the sum of annual base salary and the greater of (i) most recent annual bonus, (ii) the annual bonus paid or payable under the annual bonus plan for 2009 or the year before a future change in control occurs and (iii) the target award for 2009 or the year before a future change in control occurs

·an amount for outplacement services equal to 20 percent of base salary

·benefit continuation for a period of three years and

·a gross-up payment to reimburse the executive for any excise tax on excess parachute payments made under the agreement or otherwise that is imposed by Internal Revenue Code Section 4999, as well as any additional income and employment taxes resulting from such reimbursement.

Change in control is defined as:

·acquisition by any person of securities representing more than 50 percent of the combined voting power of our then outstanding securities entitled to vote in the election of directors, unless PPL continues to own more than 50 percent of the combined voting power of our voting securities

·consummation of a merger or similar transaction of us, any parent of us, other than PPL or any parent of PPL, or any subsidiary with any other entity, unless the voting securities outstanding before the merger represent at least 50 percent of the voting power of the surviving entity

·stockholder approval of our liquidation or dissolution or

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·sale or disposition of all or substantially all of our and our subsidiaries’ assets.

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

·earned, but unpaid salary and vacation pay at the time of termination

·an amount equal to two times the sum of annual base salary and the greater of (i) most recent annual bonus, (ii) the annual bonus paid or payable under the annual bonus plan for 2009 and (iii) the target award for 2009

·an amount for outplacement services equal to 20 percent of his base salary and

·benefit continuation for a period of two years.

Termination for cause is defined as a termination evidenced by a resolution approved by at least 75 percent of our 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.

Good reason is defined as follows:

·base salary or annual or long-term target bonus percentages have been reduced

·place of employment has been relocated more than 50 miles

·authorities, duties, responsibilities or reporting are materially reduced from those in effect prior to November 1, 2010 or

·employment and severance agreement has been materially breached by us or any of our subsidiaries.

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 us or our subsidiary and we have 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:

·earned, but unpaid salary and vacation pay on the date of death or termination due to disability

·a prorated payment of the restricted stock unit award described below

·if Mr. Staffieri dies, benefit continuation for a period of three years for his dependents and beneficiaries

·if Mr. Staffieri is terminated due to disability, until age 65 a benefit equal to 60 percent of his base salary, less any social security disability benefits and amounts payable under any disability insurance policy that we maintain during the term of his agreement and

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·for Mr. McCall, a lump sum cash payment equal to his target long-term incentive award, prorated for his actual period of service, and the greater of his most recent annual bonus, the annual bonus paid or payable under the annual bonus plan for 2009 and the target award for 2009.

Messrs. Rives’, Hermann’s and Thompson’s Agreements

In 2010, we 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 we or any subsidiary 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 us for reasons other than cause, disability or death, the executive would be entitled to:

·earned, but unpaid salary and vacation pay at the time of termination

·a lump sum cash payment equal to 2.99 times the sum of annual base salary and the executive’s target annual bonus at the time of payment

·an amount for outplacement services equal to 20 percent of base salary

·benefit continuation for the lesser of 24 months and the number of months remaining until the executive’s 65th birthday and

·a gross-up payment to reimburse the executive for any excise tax on excess parachute payments made under the agreement or otherwise that is imposed by Internal Revenue Code Section 4999, as well as any additional income and employment taxes resulting from such reimbursement.

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

·earned, but unpaid salary and vacation pay at the time of termination

·an amount equal to the sum of his annual base salary and target annual bonus at the time of payment and

·an amount for outplacement services equal to 20 percent of his base salary.

Termination for cause is defined as a termination evidenced by a resolution approved by at least 75 percent of our 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.

Good reason is defined as follows:

·base salary or annual or long-term bonus opportunities have been reduced or

·within two years following PPL’s acquisition of us or another change in control,

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·present place of employment has been relocated more than 100 miles

·authorities or responsibilities have been materially reduced or

·retention and severance agreement has been materially breached us or any of our subsidiaries.

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 we or our 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.

Retention Agreements

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 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 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.

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Potential Payments upon Termination or Change in Control

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

·retirement or a voluntary termination without good reason

·death

·disability and

·involuntary termination for reasons other than cause or voluntary termination for good reason, whether or not such termination follows a change in control.

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.

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Name	Retirement or Voluntary Termination without Good Reason ($)	Death ($)		Disability ($)		Involuntary Termination Not for Cause or Voluntary Termination with Good Reason ($)
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 us 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.

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(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, we would at our 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 us 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 we maintain 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.

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Director Compensation

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.

Compensation Committee Interlocks and Insider Participation

We are wholly owned by PPL, 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.

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TRANSACTIONS WITH RELATED PERSONS

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 our parent, 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.

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THE EXCHANGE OFFERS

Purpose and Effect of the Exchange Offers

The Outstanding Notes were issued on November 12, 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 Notes 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 Notes in which we agreed, under certain circumstances, to file a registration statement relating to offers to exchange the Outstanding Notes for Exchange Notes 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 Notes 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 Notes.  The Exchange Notes will have terms identical in all material respects to the Outstanding Notes of the related series, except that the Exchange Notes 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 Notes 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 Notes, or such shorter period as described in the registration rights agreement.  These circumstances include:

·if a change in law or in applicable interpretations of the staff of the SEC does not permit us to effect a registered exchange offer;

·if a registered exchange offer is not consummated within 315 days after the date of issuance of the Outstanding Notes;

·any initial purchaser of the Outstanding Notes so requests with respect to Notes not eligible to be exchanged for Exchange Notes in the Exchange Offer and held by it following consummation of the Exchange Offer; or

·any holder notifies us during the 20 business days following consummation of the Exchange Offer that it was not eligible to participate in the Exchange Offer or any holder who participates in the Exchange Offer does not receive freely tradeable Exchange Notes in the Exchange Offer.

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

·neither a registration statement relating to offers to exchange the Outstanding Notes for Exchange Notes nor a shelf registration statement with respect to the resale of the Outstanding Notes (if required) is filed by us within the applicable time periods specified above;

·neither the Exchange Offer registration statement nor a shelf registration statement (if required) is declared effective by the SEC within the applicable time periods specified above;

·the Exchange Offer is not consummated within 315 days after the initial issuance of the Outstanding Notes (or if the 315th day is not a business day, by the first business day thereafter); or

·after the Exchange Offer registration statement or the shelf registration statement, as the case may be, is declared effective, such registration statement thereafter ceases to be effective or usable (subject to

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certain exceptions) in connection with resales of Outstanding Notes or Exchange Notes as provided in and during the periods specified in the registration rights agreement.

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 Notes 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 Notes 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 Notes and Exchange Notes.

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

·you are not our affiliate within the meaning of Rule 405 of the Securities Act;

·you have no arrangement or understanding with any person to participate in a distribution (within the meaning of the Securities Act) of the Exchange Notes in violation of the provisions of the Securities Act;

·you are not engaged in, and do not intend to engage in, a distribution of the Exchange Notes; and

·you are acquiring the Exchange Notes in the ordinary course of your business.

Each broker-dealer that receives Exchange Notes for its own account in exchange for Outstanding Notes, where the broker-dealer acquired the Outstanding Notes 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 Notes and that it did not purchase its Outstanding Notes from us or any of our affiliates.  See “Plan of Distribution.”

Resale of Exchange Notes

We have not requested, and do not intend to request, an interpretation by the staff of the SEC as to whether the Exchange Notes issued pursuant to this Exchange Offer in exchange for the Outstanding Notes 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 Notes issued in the Exchange Offers without complying with the registration and prospectus delivery provisions of the Securities Act if:

·you are acquiring the Exchange Notes in the ordinary course of your business;

·you have no arrangements or understanding with any person to participate in the distribution of the Exchange Notes within the meaning of the Securities Act;

·you are not our “affiliate,” as defined in Rule 405 of the Securities Act; and

·you are not engaged in, and do not intend to engage in, a distribution of the Exchange Notes.

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 Notes, or are not acquiring the Exchange Notes in the ordinary course of your business:

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·you cannot rely on the position of the SEC set forth in Morgan Stanley & Co. Incorporated (available June 5, 1991) and Exxon Capital Holdings Corporation (available May 13, 1988), as interpreted in the SEC’s letter to Shearman & Sterling, dated July 2, 1993, or similar no-action letters; and

·in the absence of an exception from the position stated immediately above, you must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale of the Exchange Notes.

This prospectus may be used for an offer to resell or transfer the Exchange Notes only as specifically set forth in this prospectus.  With regard to broker-dealers, only broker-dealers that acquired the Outstanding Notes as a result of market-making activities or other trading activities may participate in the Exchange Offers.  Each broker-dealer that receives Exchange Notes for its own account in exchange for Outstanding Notes, where such Outstanding Notes 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 Notes.  Read “Plan of Distribution” for more details regarding the transfer of Exchange Notes.

Our belief that the Exchange Notes 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 Note 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.

Terms of the Exchange Offers

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 Notes that are validly tendered and not validly withdrawn prior to the Expiration Date.  Outstanding Notes 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 Notes must also be in a minimum denomination of $2,000.  We will issue Exchange Notes in principal amount identical to Outstanding Notes surrendered in the Exchange Offers.

The form and terms of the Exchange Notes will be identical in all material respects to the form and terms of the Outstanding Notes of the related series except the Exchange Notes 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 Notes will evidence the same debt as the Outstanding Notes of the related series.  The Exchange Notes will be issued under and entitled to the benefits of the Indenture.  For a description of the Indenture, see “Description of the Exchange Notes.”

No interest will be paid in connection with the exchange.  The Exchange Notes will bear interest from and including the last Interest Payment Date (as defined under “Description of the Exchange Notes — Maturity; Interest”) on the Outstanding Notes, or if one has not yet occurred, the issuance date of the Outstanding Notes.  Accordingly, the holders of Outstanding Notes that are accepted for exchange will not receive accrued but unpaid interest on Outstanding Notes at the time of tender.  Rather, that interest will be payable on the Exchange Notes delivered in exchange for the Outstanding Notes 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 Notes being tendered for exchange.

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As of the date of this prospectus, $400 million aggregate principal amount of the 2.125% Senior Notes due 2015 and $475 million aggregate principal amount of the 3.750% Senior Notes due 2020 are outstanding.  This prospectus and the letters of transmittal are being sent to all registered holders of Outstanding Notes.  There will be no fixed record date for determining registered holders of Outstanding Notes 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 Notes 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 Notes except we will not have any further obligation to you to provide for the registration of the Outstanding Notes under the registration rights agreement.

We will be deemed to have accepted for exchange properly tendered Outstanding Notes 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 Notes from us and delivering Exchange Notes 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 Notes upon the occurrence of any of the conditions specified below under “— Conditions to the Exchange Offers.”

If you tender your Outstanding Notes 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 Notes.  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 Notes for your own account in exchange for Outstanding Notes 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 Notes and that you did not purchase your Outstanding Notes from us or any of our affiliates.  Read “Plan of Distribution” for more details regarding the transfer of Exchange Notes.

We make no recommendation to you as to whether you should tender or refrain from tendering all or any portion of your Outstanding Notes 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 Notes 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.

Expiration Date, Extensions and Amendments

The Exchange Offers expire at 5:00 p.m., New York City time, on          , 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 Notes 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 Notes previously tendered will remain subject to this Exchange Offer unless validly withdrawn.

We also reserve the right, in our sole discretion:

·to delay accepting for exchange any Outstanding Notes (only in the case that we amend or extend the Exchange Offers);

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·to extend the Expiration Date and retain all Outstanding Notes tendered in the Exchange Offers, subject to your right to withdraw your tendered Outstanding Notes as described under “— Withdrawal Rights”;

·to terminate any of the Exchange Offers if we determine that any of the conditions set forth below under “— Conditions to the Exchange Offers” have not been satisfied; and

·to amend the terms of any of the Exchange Offers in any manner or waive any condition to the Exchange Offers.

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 Notes.  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 Notes 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 Notes previously tendered and not accepted for payment will be returned promptly to the tendering holders.

Conditions to the Exchange Offers

Despite any other term of the Exchange Offers, we will not be required to accept for exchange, or to issue Exchange Notes in exchange for, any Outstanding Notes 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:

·the Exchange Offers or the making of any exchange by a holder violates any applicable law or interpretation of the SEC; or

·any action or proceeding has been instituted or threatened in writing in any court or by or before any governmental agency with respect to the Exchange Offers that, in our judgment, would reasonably be expected to impair our ability to proceed with the Exchange Offers.

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

·the representations described under “— Purpose and Effect of the Exchange Offers”; or

·any other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to make available to us an appropriate form for registration of the Exchange Notes under the Securities Act.

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 Notes by giving oral or written notice of such extension to the holders.  We will return any Outstanding Notes 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 Notes 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 Notes 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 Notes.  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

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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 Notes tendered, and will not issue Exchange Notes in exchange for any such Outstanding Notes, 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.

Procedures for Tendering Outstanding Notes

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

·complete, sign and date the letter of transmittal, or a facsimile of the letter of transmittal, have the signature(s) on the letter of transmittal guaranteed if required by the letter of transmittal and mail or deliver such letter of transmittal or facsimile thereof to the exchange agent at the address set forth below under “— Exchange Agent” prior to the Expiration Date; or

·comply with DTC’s Automated Tender Offer Program procedures described below.

In addition:

·the exchange agent must receive certificates for Outstanding Notes along with the letter of transmittal prior to the expiration of the Exchange Offers;

·the exchange agent must receive a timely confirmation of book-entry transfer of Outstanding Notes into the exchange agent’s account at DTC according to the procedures for book-entry transfer described below and a properly transmitted Agent’s Message (defined below) prior to the expiration of the Exchange Offers; or

·you must comply with the guaranteed delivery procedures described below.

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:

·DTC has received an express acknowledgment from a participant in its Automated Tender Offer Program that is tendering Outstanding Notes that are the subject of the book-entry confirmation;

·the participant has received and agrees to be bound by the terms of the letter of transmittal or, in the case of an Agent’s Message relating to guaranteed delivery, that such participant has received and agrees to be bound by the notice of guaranteed delivery; and

·we may enforce that agreement against such participant.

DTC is referred to herein as a “book-entry transfer facility.”

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 Notes, 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

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

·make appropriate arrangements to register ownership of the Outstanding Notes in your name; or

·obtain a properly completed bond power from the registered holder of Outstanding Notes.

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 Notes surrendered for exchange are tendered:

·by a registered holder of the Outstanding Notes who has not completed the box entitled “Special Registration Instructions” or “Special Delivery Instructions” on the letter of transmittal; or

·for the account of an eligible guarantor institution.

If the letter of transmittal is signed by a person other than the registered holder of any Outstanding Notes listed on the Outstanding Notes, such Outstanding Notes 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 Notes, and an eligible guarantor institution must guarantee the signature on the bond power.

If the letter of transmittal, any certificates representing Outstanding Notes 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 Notes.  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 Notes for exchange by causing DTC to transfer the Outstanding Notes 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.

Book-Entry Delivery Procedures

Promptly after the date of this prospectus, the exchange agent will establish an account with respect to the Outstanding Notes 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 Notes by causing the book-entry transfer facility to transfer those Outstanding Notes 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 Notes requires receipt of a confirmation of a book-entry transfer, or a “book-entry confirmation,” prior to the Expiration Date.

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In addition, in order to receive Exchange Notes for tendered Outstanding Notes, 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 Notes who are unable to deliver confirmation of the book-entry tender of their Outstanding Notes 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 Notes 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.

Guaranteed Delivery Procedures

If you wish to tender your Outstanding Notes but your Outstanding Notes are not immediately available or you cannot deliver your Outstanding Notes, 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 Notes, prior to the Expiration Date, you may still tender if:

·the tender is made through an eligible guarantor institution;

·prior to the Expiration Date, the exchange agent receives from such eligible guarantor institution either a properly completed and duly executed notice of guaranteed delivery, by facsimile transmission, mail, or hand delivery or a properly transmitted Agent’s Message and notice of guaranteed delivery, that (1) sets forth your name and address, the certificate number(s) of such Outstanding Notes and the principal amount of Outstanding Notes tendered; (2) states that the tender is being made thereby; and (3) guarantees that, within three New York Stock Exchange trading days after the Expiration Date, the letter of transmittal, or facsimile thereof, together with the Outstanding Notes or a book-entry confirmation (including an Agent’s Message), and any other documents required by the letter of transmittal, will be deposited by the eligible guarantor institution with, or transmitted by the eligible guarantor to, the exchange agent; and

·the exchange agent receives the properly completed and executed letter of transmittal or facsimile thereof, with any required signature guarantees, as well as certificate(s) representing all tendered Outstanding Notes in proper form for transfer or a book-entry confirmation of transfer of the Outstanding Notes (including an Agent’s Message) into the exchange agent’s account at DTC and all other documents required by the letter of transmittal within three New York Stock Exchange trading days after the Expiration Date.

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

Acceptance of Outstanding Notes for Exchange

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

·Outstanding Notes or a timely book-entry confirmation of such Outstanding Notes into the exchange agent’s account at the book-entry transfer facility; and

·a properly completed and duly executed letter of transmittal and all other required documents or a properly transmitted Agent’s Message.

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In addition, each broker-dealer that is to receive Exchange Notes for its own account in exchange for Outstanding Notes must represent that such Outstanding Notes 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 Notes.  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 Notes 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 Notes not properly tendered or to not accept any particular Outstanding Notes 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 Notes prior to the expiration of the Exchange Offers.

Unless waived, any defects or irregularities in connection with tenders of Outstanding Notes 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 Notes for exchange, nor will any of them incur any liability for any failure to give notification.  Any certificates representing Outstanding Notes 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.

Withdrawal Rights

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

For a withdrawal to be effective:

·the exchange agent must receive a written notice, which may be by telegram, telex, facsimile or letter, of withdrawal at its address set forth below under “— Exchange Agent”; or

·you must comply with the appropriate procedures of DTC’s Automated Tender Offer Program system for such withdrawal.

Any notice of withdrawal must:

·specify the name of the person who tendered the Outstanding Notes to be withdrawn;

·identify the Outstanding Notes to be withdrawn, including the certificate numbers and principal amount of the Outstanding Notes; and

·where certificates for Outstanding Notes have been transmitted, specify the name in which such Outstanding Notes were registered, if different from that of the withdrawing holder.

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

·the serial numbers of the particular certificates to be withdrawn; and

·a signed notice of withdrawal with signatures guaranteed by an eligible institution unless you are an eligible guarantor institution.

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If Outstanding Notes 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 Notes 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 Notes so withdrawn will be deemed not to have been validly tendered for exchange for purposes of the Exchange Offers.  Any Outstanding Notes 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 Notes 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 Notes may be retendered by following the procedures described under “— Procedures for Tendering Outstanding Notes” above at any time prior to the expiration of the Exchange Offers.

Exchange Agent

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:

By Mail, Hand or Courier The Bank of New York Mellon c/o The Bank of New York Mellon Corporation Corporate Trust – Reorganization Unit 480 Washington Boulevard – 27th Floor Jersey City, New Jersey 07310 Attn:                - Processor By Facsimile Transmission (eligible institutions only) (212) 298-1915 To Confirm by Telephone (212) 815-5920

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.

Fees and Expenses

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 Notes 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 Notes 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 Notes pursuant to the Exchange Offers.

Accounting Treatment

We will record the Exchange Notes in our accounting records at the same carrying value as the Outstanding Notes, 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.

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Transfer Taxes

We will pay all transfer taxes, if any, applicable to the exchanges of Outstanding Notes 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:

·certificates representing Outstanding Notes for principal amounts not tendered or accepted for exchange are to be delivered to, or are to be issued in the name of, any person other than the registered holder of Outstanding Notes tendered;

·tendered Outstanding Notes are registered in the name of any person other than the person signing the letter of transmittal; or

·a transfer tax is imposed for any reason other than the exchange of Outstanding Notes under the Exchange Offers.

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 Notes for exchange will not be required to pay any transfer taxes.  However, holders who instruct us to register Exchange Notes in the name of, or request that Outstanding Notes 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.

Consequences of Failure to Exchange

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

·as set forth in the legend printed on the Outstanding Notes as a consequence of the issuance of the Outstanding Notes pursuant to the exemptions from, or in transactions not subject to, the registration requirements of the Securities Act and applicable state securities laws; and

·as otherwise set forth in the offering memorandum distributed in connection with the private offerings of the Outstanding Notes.

In general, you may not offer or sell your Outstanding Notes 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 Notes under the Securities Act.

Other

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

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DESCRIPTION OF THE EXCHANGE NOTES

The following summary description sets forth certain terms and provisions of the Exchange Notes.  Because this description is a summary, it does not describe every aspect of the Exchange Notes or the Indenture (as defined below) under which the Exchange Notes will be issued, and which is filed as an exhibit to the registration statement of which this prospectus is a part.  The Indenture 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 Notes and the Indenture, including definitions of certain terms used in the Indenture.  We also include references in parentheses to certain sections of the Indenture.  Whenever we refer to particular sections or defined terms of the Indenture in this prospectus, such sections or defined terms are incorporated by reference herein.

General

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

·be registered under the Securities Act;

·not be subject to the restrictions on transfer applicable to the Outstanding Notes (except for the limited restrictions described below under “— Form; Transfers; Exchanges”);

·not be entitled to any registration rights which are applicable to the Outstanding Notes under the registration rights agreement, including any right to liquidated damages; and

·bear different CUSIP numbers.

We will issue each series of the Exchange Notes under our Indenture, dated as of November 1, 2010 (as such indenture may be amended and supplemented from time to time, the “Indenture”), to The Bank of New York Mellon, as Trustee.  We may issue an unlimited amount of Exchange Notes or other debt securities under the Indenture.  The Exchange Notes and all other debt securities hereafter issued under the Indenture are collectively referred to herein as the “Indenture Securities.”

The Exchange Notes will be our unsecured and unsubordinated obligations.

The Exchange Notes will be issued in fully registered form only, without coupons.  The Exchange Notes 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 Notes will be $2,000 and any larger amount that is an integral multiple of $1,000.  Except in limited circumstances described below, the Exchange Notes will not be exchangeable for Exchange Notes in definitive certificated form.

The 2015 Exchange Notes will be issued as part of the same series of debt securities under the Indenture as the 2015 Outstanding Notes.  The 2020 Exchange Notes will be issued as part of the same series of debt securities under the Indenture as the 2020 Outstanding Notes.  We may, without the consent of the holders of the applicable series of Notes, increase the principal amount of either series of Notes and issue additional notes of the applicable series having the same ranking, interest rate, maturity and other terms (other than the date of issuance, public offering price and, in some circumstances, the initial interest accrual date and initial interest payment date) as the Exchange Notes, but we do not intend to reopen a series unless, for U.S. federal income tax purposes, such additional notes are issued in a “qualified reopening” within the meaning of the Internal Revenue Code of 1986, as amended.  Any such additional notes would, together with the Exchange Notes of the applicable series offered by this prospectus and any Outstanding Notes of such series, constitute a single series of securities under the Indenture and may be treated as a single class for all purposes under the Indenture, including, without limitation, voting, waivers and amendments.

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Maturity; Interest

The 2015 Exchange Notes will mature on November 15, 2015 and will bear interest from                     at a rate of 2.125% per annum.  The 2020 Notes will mature on November 15, 2020 and will bear interest from                    at a rate of 3.750% per annum.  Interest will be payable on each series of Notes on May 15 and November 15 of each year, commencing on               15, 2011, and at maturity (whether at the applicable stated maturity date, upon redemption or acceleration, or otherwise).  Subject to certain exceptions, the Indenture provides for the payment of interest on an Interest Payment Date only to persons in whose names the Exchange Notes 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 Notes 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.

Payment

So long as the Exchange Notes are registered in the name of DTC, as depository for the Exchange Notes as described herein under “— Book-Entry Only Issuance — The Depository Trust Company” or DTC’s nominee, payments on the Exchange Notes will be made as described therein.

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

·to holders as of a special record date between 10 and 15 days before the proposed payment; or

·in any other lawful manner of payment that is consistent with the requirements of any securities exchange on which the Exchange Notes may be listed for trading. (See Section 307.)

We will pay principal of and interest and premium, if any, on the Exchange Notes at Maturity upon presentation of the Exchange Notes 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 Notes, 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 602.)

If any Interest Payment Date, Redemption Date or Maturity of an Exchange Note 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. (See Section 113.)

“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 Note is located, are generally authorized or required by law, regulation or executive order to remain closed. (See Section 101.)

Form; Transfers; Exchanges

So long as the Exchange Notes are registered in the name of DTC, as depository for the Exchange Notes 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 Notes will be made as described therein.  In the event that the book-entry only system is discontinued, and the Exchange Notes are issued in certificated form, you may exchange or transfer Exchange Notes at the corporate trust office of the Trustee.

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You may have your Exchange Notes divided into Exchange Notes of smaller denominations (of at least $2,000 and any larger amount that is an integral multiple of $1,000) or combined into Exchange Notes 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 Notes, 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 Notes during a period of 15 days prior to giving any notice of redemption or (2) any Exchange Note selected for redemption in whole or in part, except the unredeemed portion of any Exchange Note being redeemed in part. (See Section 305.)

The Trustee acts as our agent for registering Exchange Notes in the names of holders and transferring Exchange Notes.  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 Notes and may designate a different entity as the Security Registrar (including us or one of our affiliates).  (See Sections 305 and 602.)

Redemption

We may, at our option, redeem the 2015 Exchange Notes, 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 Notes 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 Notes 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 2015 Exchange Notes to be so redeemed to the Redemption Date.

We may, at our option, redeem the 2020 Exchange Notes, in whole at any time or in part from time to time.  If the 2020 Exchange Notes are redeemed before August 15, 2020 (the date that is three months prior to the stated maturity of the 2020 Exchange Notes), the 2020 Exchange Notes will be redeemed by us at a redemption price equal to the greater of (1) 100% of the principal amount of the 2020 Exchange Notes 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 2020 Exchange Notes 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 25 basis points; plus, in either case, accrued and unpaid interest on the principal amount of the 2020 Exchange Notes to be so redeemed to the Redemption Date.  If the 2020 Exchange Notes are redeemed on or after August 15, 2020, the 2020 Exchange Notes may be redeemed by us at a redemption price equal to 100% of the principal amount of the 2020 Exchange Notes to be so redeemed, plus accrued and unpaid interest on the principal amount of the 2020 Exchange Notes 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 Notes 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 Notes being redeemed.

“Comparable Treasury Price” means, with respect to any Redemption Date:

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·the average of five Reference Treasury Dealer Quotations for that Redemption Date, after excluding the highest and lowest Reference Treasury Dealer Quotations; or

·if the Quotation Agent obtains fewer than five Reference Treasury Dealer Quotations, the average of all of those quotations received.

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

“Reference Treasury Dealer” means:

·each of Credit Suisse Securities (USA) LLC, and Merrill Lynch, Pierce, Fenner & Smith Incorporated, and their respective successors, unless any of them ceases to be a primary U.S. Government securities dealer in the United States, in which case we will substitute another Primary Treasury Dealer; and

·any other Primary Treasury Dealers selected by us (after consultation with the Quotation Agent).

“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 Notes 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 Notes will be redeemable upon notice of redemption to each holder of Exchange Notes to be redeemed by mail between 30 days and 60 days prior to the Redemption Date.  If less than all of the Exchange Notes are to be redeemed, the Trustee will select the Exchange Notes 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 403 and 404.)

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 Notes.  (See Section 404.)

If money sufficient to pay the redemption price has been received by the Paying Agent, Exchange Notes 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 Note for redemption.  (See Section 405.)  If only part of an Exchange Note is redeemed, the Trustee will deliver to you a new Exchange Note of the same series for the remaining portion without charge.  (See Section 406.)

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

Certain Covenants

Limitation on Secured Debt.  So long as any of the Exchange Notes remain outstanding, we will not create, incur or assume any Lien upon the common stock of Kentucky Utilities Company or Louisville Gas and Electric Company to secure Debt (in each case, as defined below) other than Permitted Liens (as described below), without the consent of the holders of a majority in aggregate principal amount of each series of the outstanding Exchange Notes.  This covenant will not, however, prohibit the creation, issuance, incurrence or assumption of any Lien if either:

·we make effective provision whereby all Exchange Notes then outstanding will be secured equally and ratably with all other Debt then outstanding under such Lien; or

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·we deliver to the Trustee bonds, notes or other evidences of indebtedness secured by the Lien which secures such Debt in an aggregate principal amount equal to the aggregate principal amount of the outstanding Exchange Notes and meeting certain other requirements set forth in the Indenture.

This covenant applies to property held directly by LG&E and KU Energy LLC and will not restrict the ability of our subsidiaries and affiliates to create, incur or assume any Lien upon their assets, either in connection with project financings or otherwise.

As used herein:

“Debt,” with respect to any entity, means:

·indebtedness of the entity for borrowed money evidenced by a bond, debenture, note or other similar written instrument or agreement by which the entity is obligated to repay such borrowed money; and

·any guaranty by the entity of any such indebtedness of another entity.

“Debt” does not include, among other things:

·indebtedness of the entity under any installment sale or conditional sale agreement or any other agreement relating to indebtedness for the deferred purchase price of property or services;

·trade obligations (including obligations under agreements relating to the purchase and sale of any commodity, including power purchase or sale agreements and any commodity hedges or derivatives regardless of whether any such transaction is a “financial” or physical transaction) or other obligations of the entity in the ordinary course of business;

·obligations of the entity under any lease agreement (including any lease intended as security), whether or not such obligations are required to be capitalized on the balance sheet of the entity under U.S. generally accepted accounting principles; or

·liabilities secured by any Lien on any property owned by the entity if and to the extent the entity has not assumed or otherwise become liable for the payment thereof.

“Lien” means any lien, mortgage, deed of trust, pledge or security interest, in each case, intended to secure the repayment of Debt, except for any Permitted Lien.

“Permitted Liens” means any

·Liens existing at November 12, 2010, the original issue date of the Outstanding Notes;

·Liens securing Debt which matures less than one year from the date of issuance or incurrence thereof and is not extendible at the option of the issuer, and any refundings, refinancings and/or replacements of any such Debt by or with similar secured Debt;

·other Liens securing Debt the principal amount of which does not exceed 10% of the total assets of the Company and our consolidated subsidiaries as shown on our most recent audited balance sheet; and

·Liens granted in connection with extending, renewing, replacing or refinancing, in whole or in part, the Debt secured by liens described above (to the extent of such Debt so extended, renewed, replaced or refinanced).

(See Supplemental Indenture No. 1.)

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Consolidation, Merger and Conveyance of Assets as an Entirety; No Financial Covenants

Subject to the provisions described below, we have agreed in the Indenture to preserve our existence as a limited liability company (or corporation or other business entity permitted by the Indenture). (See Section 604.)

We have agreed not to consolidate with or merge with or into any other entity or convey or otherwise transfer or lease our properties and assets as or substantially as an entirety to any entity unless:

·the entity formed by such consolidation or into which we merge, or the entity which acquires or which leases (for a term extending beyond the last stated maturity of Indenture Securities then outstanding) our property and assets as or substantially as an entirety is an entity organized and existing under the laws of the United States of America or any State thereof or the District of Columbia, and expressly assumes, by supplemental indenture, the due and punctual payment of the principal of and premium, if any, and interest, if any, on all outstanding Indenture Securities and the performance of all of our covenants under the Indenture; and

·immediately after giving effect to such transaction, no Event of Default, and no event which after notice or lapse of time or both would become an Event of Default, will have occurred and be continuing. (See Section 1101.)

In the case of the conveyance or other transfer of our properties and assets 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 Indenture and on the Indenture Securities then outstanding unless we elect to waive such release and discharge. (See Section 1103.)

The Indenture does not prevent or restrict:

·any consolidation or merger after the consummation of which we would be the surviving or resulting entity;

·any conveyance or other transfer, or lease of any part of our properties which does not constitute the entirety, or substantially the entirety thereof; or

·our approval of, or consent to, any consolidation or merger of any direct or indirect subsidiary or affiliate or any conveyance, transfer or lease by any such subsidiary or affiliate of any of its assets. (See Section 1104.)

The Indenture does not contain any financial covenants.

Agreement to Provide Information

So long as any Exchange Notes are outstanding under the Indenture, 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 Notes by means of posting on our website or other similar means:

·as soon as reasonably available and in any event within 120 days after the end of each fiscal year, our audited consolidated balance sheet, income statement and cash flow statement for such fiscal year prepared in accordance with United States generally accepted accounting principles (with notes to such financial statements), together with an audit report thereon by an independent accounting firm of established national reputation, and a management’s narrative analysis of the results of operations explaining the reasons for material changes in the amount of revenue and expense items between the most recent fiscal year presented and the fiscal year immediately preceding it, as described in Instruction I(2)(a) of Form 10-K; and

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·as soon as reasonably available and in any event within 60 days after the end of each of the first three fiscal quarters of each fiscal year, our unaudited consolidated balance sheet, unaudited consolidated income statement and unaudited consolidated cash flow statement for such fiscal quarter prepared in accordance with United States generally accepted accounting principles (with notes to such consolidated financial statements) and a management’s narrative analysis of the results of operations explaining the reasons for material changes in the amount of revenue and expense items between the most recent fiscal year-to-date period presented and the corresponding year-to-date period in the preceding fiscal year, as described in Instruction H(2)(a) to Form 10-Q.

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, at our expense, will furnish them to the holders of the Exchange Notes.

Events of Default

An “Event of Default” with respect to the Exchange Notes will occur if

·we do not pay any interest on any Exchange Note within 30 days of the due date;

·we do not pay principal or premium, if any, on any Exchange Note on the due date;

·we remain in breach of any other covenant (excluding a covenant specifically dealt with elsewhere in this section or a covenant or warranty solely applicable to one or more series of Indenture Securities other than the Exchange Notes) for 90 days after we receive a written notice of default stating we are in breach and requiring remedy of the breach; the notice must be sent by either the Trustee or holders of 25% of the principal amount of the outstanding Exchange Notes; the Trustee or such holders can agree to extend the 90-day period and such an agreement to extend will be automatically deemed to occur if we initiate corrective action within such 90-day period and we are diligently pursuing such action to correct the default;

·we file for bankruptcy or certain other events in bankruptcy, insolvency, receivership or reorganization occur.

(See Section 801.)

No Event of Default with respect to the Exchange Notes necessarily constitutes an Event of Default with respect to the Indenture Securities of any other series issued under the Indenture.

Remedies

Acceleration

Any One Series.  If an Event of Default occurs and is continuing with respect to any one series of Indenture Securities, then either the Trustee or the holders of not less than 25% in principal amount of the outstanding Indenture Securities of such series may declare the principal amount of all of the Indenture Securities of such series to be due and payable immediately.

More Than One Series.  If an Event of Default occurs and is continuing with respect to more than one series of Indenture Securities, then either the Trustee or the holders of 25% of the aggregate principal amount of the outstanding Indenture Securities of all such series, considered as one class, may make such declaration of acceleration. Thus, if there is more than one series affected, the action by the holders of 25% of the aggregate principal amount of the outstanding Indenture Securities of any particular series will not, in itself, be sufficient to make a declaration of acceleration. (See Section 802.)

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Rescission of Acceleration

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:

·we pay or deposit with the Trustee a sum sufficient to pay:

·all overdue interest;

·the principal of and premium, if any, which have become due otherwise than by such declaration of acceleration and interest thereon;

·interest on overdue interest to the extent lawful; and

·all amounts due to the Trustee under the Indenture; and

·all Events of Default, other than the nonpayment of the principal which has become due solely by such declaration of acceleration, have been cured or waived as provided in the Indenture. (See Section 802.)

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

Control by Holders; Limitations

Subject to the Indenture, if an Event of Default with respect to the Indenture Securities of any one series occurs and is continuing, the holders of a majority in principal amount of the outstanding Indenture Securities of that series will have the right to

·direct the time, method and place of conducting any proceeding for any remedy available to the Trustee, or

·exercise any trust or power conferred on the Trustee with respect to the Indenture Securities of such series.

If an Event of Default is continuing with respect to more than one series of Indenture Securities, the holders of a majority in aggregate principal amount of the outstanding Indenture Securities of all such series, considered as one class, will have the right to make such direction, and not the holders of the Indenture Securities of any one of such series.

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

·the holders’ directions may not conflict with any law or the Indenture; and

·the holders’ directions may not involve the Trustee in personal liability where the Trustee believes indemnity is not adequate.

The Trustee may also take any other action it deems proper which is not inconsistent with the holders’ direction. (See Sections 812 and 903.)

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

·that holder has previously given the Trustee written notice of a continuing Event of Default;

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·the holders of 25% in aggregate principal amount of the outstanding Indenture Securities of all affected series, considered as one class, have made written request to the Trustee to institute proceedings in respect of that Event of Default and have offered the Trustee reasonable indemnity against costs, expenses and liabilities incurred in complying with such request; and

·for 60 days after receipt of such notice, request and offer of indemnity, the Trustee has failed to institute any such proceeding and no direction inconsistent with such request has been given to the Trustee during such 60-day period by the holders of a majority in aggregate principal amount of outstanding Indenture Securities of all affected series, considered as one class.

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 such holders. (See Sections 807 and 903.)

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 and 808.)

Notice of Default

The Trustee is required to give the holders of the Exchange Notes notice of any default under the Indenture 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 902.)  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 Indenture. (See Section 605.)

Waiver of Default and of Compliance

The holders of a majority in aggregate principal amount of the outstanding Exchange Notes of either series may waive, on behalf of the holders of all outstanding Exchange Notes of such series, any past default under the Indenture with respect to such series, except a default in the payment of principal, premium, if any, or interest, or with respect to compliance with certain provisions of the Indenture that cannot be amended without the consent of the holder of each outstanding Exchange Note of such series affected.  (See Section 813.)

Compliance with certain covenants in the Indenture or otherwise provided with respect to Indenture Securities may be waived by the holders of a majority in aggregate principal amount of the affected Indenture Securities, considered as one class. (See Section 606.)

Modification of Indenture

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

·to evidence the succession of another entity to us;

·to add one or more covenants or other provisions for the benefit of the holders of all or any series or tranche of Indenture Securities, or to surrender any right or power conferred upon us;

·add any additional Events of Default, which may be stated to (i) apply with respect to all or any series of Indenture Securities (and if such additional Events of Default are to be for the benefit of less than all series of Indenture Securities, stating that such additional Events of Default are expressly being

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included solely for the benefit of such series) and/or (ii) remain in effect only so long as the Indenture Securities of any one more particular series remains outstanding;

·to change or eliminate any provision of the Indenture or to add any new provision to the Indenture that does not adversely affect the interests of the holders in any material respect;

·to provide security for the Indenture Securities of any series;

·to establish the form or terms of Indenture Securities of any series or tranche as permitted by the Indenture;

·to provide for the issuance of bearer securities;

·to evidence and provide for the acceptance of appointment of a separate or successor Trustee;

·to provide for the procedures required to permit the utilization of a noncertificated system of registration for any series or tranche of Indenture Securities;

·to change any place or places where

·we may pay principal, premium, if any, and interest,

·Indenture Securities may be surrendered for transfer or exchange, and

·notices and demands to or upon us may be served;

·to amend and restate the Indenture as originally executed, and as amended from time to time, with such additions, deletions and other changes that do not adversely affect the interest of the holders in any material respect; or

·to cure any ambiguity, defect or inconsistency or to make any other changes that do not adversely affect the interests of the holders in any material respect.

In addition, if the Trust Indenture Act is amended after the date of the Indenture so as to require changes to the Indenture or so as to permit changes to, or the elimination of, provisions which, at the date of the Indenture or at any time thereafter, were required by the Trust Indenture Act to be contained in the Indenture, the Indenture 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. (See Section 1201.)

With Holder Consent.  Except as provided above, the consent of the holders of at least a majority in aggregate principal amount of the Indenture 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 Indenture pursuant to a supplemental indenture.  However, if less than all of the series of outstanding Indenture 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 Indenture Securities of all directly affected series, considered as one class.  Moreover, if the Indenture 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 Indenture 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 Indenture 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 Indenture Security directly affected thereby,

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·change the stated maturity of the principal or interest on any Indenture Security (other than pursuant to the terms thereof), or reduce the principal amount, interest or premium payable (or the method of calculating such rates), or change the currency in which any Indenture Security is payable, or impair the right to bring suit to enforce any payment;

·reduce the percentages of holders whose consent is required for any supplemental indenture or waiver of compliance with any provision of the Indenture or of any default thereunder and its consequences, or reduce the requirements for quorum and voting under the Indenture; or

·modify certain of the provisions in the Indenture relating to supplemental indentures and waivers of certain covenants and past defaults.

A supplemental indenture which changes or eliminates any provision of the Indenture expressly included solely for the benefit of holders of Indenture Securities of one or more particular series or tranches will be deemed not to affect the rights under the Indenture of the holders of Indenture Securities of any other series or tranche. (See Section 1202.)

Satisfaction and Discharge

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

·money sufficient, or

·in the case of a deposit made prior to the maturity of such Exchange Notes, non-redeemable Government Obligations (as defined in the Indenture) sufficient, or

·a combination of the items listed in the preceding two bullet points, which in total are sufficient,

to pay when due the principal of, and any premium, and interest due and to become due on such Exchange Notes or portions thereof on and prior to the Maturity thereof.  (See Section 701.)

The Indenture will be deemed satisfied and discharged when no Indenture Securities remain outstanding and when we have paid all other sums payable by us under the Indenture. (See Section 702.)

All moneys we pay to the Trustee or any Paying Agent on Exchange Notes 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 Note may look only to us for payment.  (See Section 603.)

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 Indenture at the request of any holder of Indenture 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 resign at any time by giving written notice to us.

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

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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 Indenture.

Under certain circumstances, we may appoint a successor trustee and if the successor accepts, the Trustee will be deemed to have resigned. (See Section 910.)

Notices

Notices to holders of the Exchange Notes will be given by mail to the addresses of the holders as they may appear in the Security Register. (See Section 106.)

Title

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

Evidence to be Furnished to the Trustee

Compliance with Indenture 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 accountant or other expert (who in some cases must be independent) must be furnished.  In addition, the Indenture 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 Indenture.

Miscellaneous Provisions

The Indenture provides that certain Indenture 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 Indenture Securities have given or taken any demand, direction, consent or other action under the Indenture 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 Indenture Securities of any series entitled to give or take any demand, direction, consent or other action under the Indenture, in the manner and subject to the limitations provided in the Indenture. 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 Indenture Securities, such action may be taken only by persons who are holders of such Indenture Securities at the close of business on the record date.  (See Section 104.)

Governing Law

The Indenture and the Exchange Notes will be governed by and construed in accordance with the laws of the State of New York, except to the extent the Trust Indenture Act shall be applicable and except to the extent that the law of any other jurisdiction shall mandatorily govern.  (See Section 112.)

Regarding the Trustee

The Trustee under the Indenture 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.

Book-Entry Only Issuance — The Depository Trust Company

DTC will act as the initial securities depository for the Exchange Notes.  The Exchange Notes issued in exchange for Outstanding Notes will be issued as fully-registered securities registered in the name of Cede & Co.

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(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 Notes, and an additional certificate will be issued with respect to any remaining principal amount of Exchange Notes.  The global notes 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 Notes under the DTC system must be made by or through Direct Participants, which will receive a credit for the Exchange Notes 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 transactions.  Transfers of ownership interests on the Exchange Notes 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 Notes, except in the event that use of the book-entry system for the Exchange Notes is discontinued.

To facilitate subsequent transfers, all Exchange Notes 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 Notes 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 Notes; DTC’s records reflect only the identity of the Direct Participants to whose accounts the Exchange Notes 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 Notes 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 Notes 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 Notes.

Payments of principal and interest on the Exchange Notes 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

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any statutory or regulatory requirements as may be in effect from time to time.  Payment of 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 Notes.  Accordingly, each Beneficial Owner must rely on the procedures of DTC to exercise any rights under the Exchange Notes.

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

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

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 Notes 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 Notes 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 Notes 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 Notes that is for U.S. federal income tax purposes:

·an individual who is a citizen or resident of the U.S.;

·a corporation created or organized  in or under the laws of the United States, any state thereof or the District of Columbia;

·an estate the income of which is subject to U.S. federal income taxation regardless of its source; or

·a trust, if (i) a U.S. court is able to exercise primary supervision over the administration of the trust and one or more United States persons have the authority to control all substantial decisions of the trust or (ii) the trust has a valid election in place to be treated as a United States person.

For purposes of the following discussion, the term “Non-U.S. Holder” means a beneficial owner of the Exchange Notes (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 Notes.

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 NOTES.  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

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JURISDICTION OR ANY APPLICABLE TAX TREATIES, AND THE POSSIBLE EFFECT OF CHANGES IN APPLICABLE TAX LAW.

The Exchange Offers

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

·a holder will not recognize taxable gain or loss as a result of the exchange of its Outstanding Notes for the Exchange Notes pursuant to the Exchange Offers;

·the holding period of the Exchange Notes will include the holding period of the Outstanding Notes surrendered in exchange therefor; and

·a holder’s adjusted tax basis in the Exchange Notes will be the same as the holder’s adjusted tax basis in the Outstanding Notes surrendered therefor.

Effect of Certain Additional Payments

In certain circumstances (for example, see “Description of the Exchange Notes — Redemption”) we may be obligated to pay amounts on the Exchange Notes that are in excess of stated interest or principal on the Exchange Notes.  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 Notes 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 Notes should not cause the Exchange Notes 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 Notes in excess of stated interest, and to treat any income realized on the taxable disposition of an Exchange Note as ordinary income rather than capital gain.  The remainder of this discussion assumes that the Exchange Notes 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 Notes.

U.S. Holders

Stated Interest

The Exchange Notes will be issued without any original issue discount for U.S. federal income tax purposes.  Accordingly, stated interest on the Exchange Notes 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.

Sale, Taxable Exchange, Redemption or Other Taxable Disposition of the Exchange Notes

Upon a sale, taxable exchange, redemption (including any optional redemption) or other taxable disposition of an Exchange Note, 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 Note.  A U.S. Holder’s adjusted tax basis in an Exchange Note generally will equal the purchase price of the Outstanding Note exchanged for the Exchange Note. 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 Note 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.

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Medicare Tax

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 Notes and its net gains from the disposition of the Exchange Notes, 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 Notes.

Information Reporting and Backup Withholding

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 Notes, 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.

Non-U.S. Holders

Stated Interest

Subject to the discussion of backup withholding below, payments of interest on the Exchange Notes 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 Notes 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 Notes 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 Notes 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

140

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.

Sale, Taxable Exchange, Redemption or Other Taxable Disposition of the Exchange Notes

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 Notes 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.

Information Reporting and Backup Withholding

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 Notes 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 Notes. 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

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 Notes 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 NOTE SHOULD CONSULT ITS OWN TAX ADVISOR AS TO THE PARTICULAR TAX CONSEQUENCES TO IT OF ACQUIRING, OWNING AND DISPOSING OF THE EXCHANGE NOTES 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.

141

PLAN OF DISTRIBUTION

Each broker-dealer that receives Exchange Notes 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 Notes.  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 Notes received in exchange for Outstanding Notes where such Outstanding Notes 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 Notes may be required to deliver a prospectus.

We will not receive any proceeds from any sale of Exchange Notes by broker-dealers.  Exchange Notes 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 Notes 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 Notes.  Any broker-dealer that resells Exchange Notes 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 Notes may be deemed to be an “underwriter” within the meaning of the Securities Act, and any profit on any such resale of Exchange Notes 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 Notes) 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.

LEGAL MATTERS

The validity of the Exchange Notes will be passed upon for us by Dewey & LeBoeuf LLP, New York, New York and John R. McCall, Executive Vice President, General Counsel, Corporate Secretary and Chief Compliance Officer to the Company.

EXPERTS

Our consolidated 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.

142

AVAILABLE INFORMATION

We have filed with the SEC a registration statement on Form S-4 under the Securities Act with respect to the Exchange Notes.  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 Notes, 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 Notes, as described under “Description of the Exchange Notes — 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 Notes, 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:

LG&E and KU Energy LLC
220 West Main Street
Louisville, Kentucky 40202
Attention: Corporate Secretary
Telephone: (502) 627-2000

143

LG&E and KU Energy LLC

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

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

Report of Independent Registered Public Accounting Firm	F-1
Consolidated Statements of Income	F-4
Consolidated Statements of Retained Earnings (Deficit)	F-6
Consolidated Statements of Comprehensive Income (Loss)	F-7
Consolidated Balance Sheets	F-8
Consolidated Statements of Cash Flows	F-12
Consolidated Statements of Capitalization	F-15
Notes to Consolidated Financial Statements	F-21

144

LG&E and KU Energy LLC

CONSOLIDATED FINANCIAL STATEMENTS

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

F-i

Index of Abbreviations

AG	Attorney General of Kentucky
ARO	Asset Retirement Obligation
ASC	Accounting Standards Codification
BART	Best Available Retrofit Technology
Big Rivers	Big Rivers Electric Corporation
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CATR	Clean Air Transport Rule
CCN	Certificate of Public Convenience and Necessity
Centro	Distribuidora de Gas Del Centro S.A.
Clean Air Act	The Clean Air Act, as amended in 1990
CMRG	Carbon Management Research Group
Company	LG&E and KU Energy LLC and Subsidiaries (formerly E.ON U.S. LLC and Subsidiaries)
CT	Combustion Turbine
Cuyana	Distribuidora de Gas Cuyana S.A.
DSM	Demand Side Management
ECR	Environmental Cost Recovery
EEI	Electric Energy, Inc.
EKPC	East Kentucky Power Cooperative, Inc.
E.ON	E.ON AG
E.ON Spain	E.ON Espana S.L
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
GAC	Group Annuity Contract
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

F-ii

Index of Abbreviations

LEM	LG&E Energy Marketing Inc.
LG&E	Louisville Gas and Electric Company
LIBOR	London Interbank Offered Rate
LKC	LG&E and KU Capital LLC (formerly LG&E Capital Corp. and E.ON U.S. Capital Corp.)
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
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
NGHH	Natural Gas-Henry Hub
NO2	Nitrogen Dioxide
NOV	Notice of Violation
NOx	Nitrogen Oxide
OATT	Open Access Transmission Tariff
OMU	Owensboro Municipal Utilities
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
VEBA	Voluntary Employee Beneficiary Association
Virginia Commission	Virginia State Corporation Commission
WKE	Western Kentucky Energy Corp. and its Affiliates
WNA	Weather Normalization Adjustment

F-iii

Table of Contents

Consolidated Financial Statements:
Report of Independent Registered Public Accounting Firm		F-1
	Consolidated Statements of Income	F-4
	Consolidated Statements of Retained Earnings (Deficit)	F-6
	Consolidated Statements of Comprehensive Income (Loss)	F-7
	Consolidated Balance Sheets	F-8
	Consolidated Statements of Cash Flows	F-12
	Consolidated Statements of Capitalization	F-15
Notes to Consolidated Financial Statements:		F-21
	Note 1 - Summary of Significant Accounting Policies	F-21
	Note 2 - Acquisition by PPL	F-34
	Note 3 - Rates and Regulatory Matters	F-36
	Note 4 - Asset Retirement Obligations	F-55
	Note 5 - Derivative Financial Instruments	F-56
	Note 6 - Fair Value Measurements	F-61
	Note 7 - Goodwill and Intangible Assets	F-64
	Note 8 - Concentrations of Credit and Other Risk	F-67
	Note 9 - Pension and Other Postretirement Benefit Plans	F-68
	Note 10 - Income Taxes	F-78
	Note 11 - Long-Term Debt	F-83
	Note 12 - Notes Payable and Other Short-Term Obligations	F-88
	Note 13 - Commitments and Contingencies	F-89
	Note 14 - Jointly Owned Electric Utility Plant	F-100
	Note 15 - Related Party Transactions	F-101
	Note 16 - Selected Quarterly Data (Unaudited)	F-102
	Note 17 - Accumulated Other Comprehensive Income (Loss)	F-103
	Note 18 - Available for Sale Debt Securities	F-104
	Note 19 - Discontinued Operations	F-104
	Note 20 - Share Performance Plan	F-106
	Note 21 - Subsequent Events	F-107
Schedule I - LG&E and KU Energy LLC Unconsolidated Financial Statements		F-108

F-iv

Report of Independent Registered Public Accounting Firm

To the Member of LG&E and KU Energy LLC

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of income, retained earnings (deficit), comprehensive income (loss), cash flows, and capitalization present fairly, in all material respects, the financial position of LG&E and KU Energy LLC and its subsidiaries (formerly E.ON U.S. LLC, Predecessor Company) at December 31, 2009 and the results of their operations and their 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.  In addition, in our opinion, the financial statement schedule listed in the accompanying index present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.  These financial statements and financial statement schedule are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements and financial statement schedule 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.

PricewaterhouseCoopers LLP, 500 West Main Street, Ste. 1800, Louisville, KY 40202-2941

T: (502) 589 6100, F: (502) 585 7875, www.pwc.com/us

F-1

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 consolidated 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.

Louisville, Kentucky

February 25, 2011

F-2

Report of Independent Registered Public Accounting Firm

To the Member of LG&E and KU Energy LLC

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of income, retained earnings, comprehensive income, cash flows, and capitalization present fairly, in all material respects, the financial position of LG&E and KU Energy LLC and its subsidiaries (Successor Company) at December 31, 2010 and the results of their operations and their 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.  In addition, in our opinion, the financial statement schedule listed in the accompanying index present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.  These financial statements and financial statement schedule are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit.  We conducted our audit in 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.

As discussed in Note 2 to the consolidated 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.

Louisville, Kentucky

February 25, 2011

PricewaterhouseCoopers LLP, 500 West Main Street, Ste. 1800, Louisville, KY 40202-2941

T: (502) 589 6100, F: (502) 585 7875, www.pwc.com/us

F-3

LG&E and KU Energy LLC

Consolidated Statements of Income

(millions)

	Successor			Predecessor
	November 1, 2010 through			January 1, 2010 through			Year Ended  December 31,
	December 31, 2010			October 31, 2010			2009			2008
Operating revenues	$	494		$	2,214		$	2,501		$	2,675
Operating expenses:
Fuel for electric generation	138			723			762			859
Power purchased (Note 13)	15			102			136			153
Natural gas supply expenses	53			109			243			349
Other operation and maintenance expenses	143			607			678			604
Depreciation and amortization	49			235			271			265
Total operating expenses	398			1,776			2,090			2,230
Loss on impairment	—			—			(1,493		)	(1,806		)
Operating income (loss)	96			438			(1,082		)	(1,361		)
Equity in earnings of unconsolidated venture	—			3			—			29
Derivative gain (loss) (Note 5)	—			19			18			(37		)
Interest expense (Notes 5, 11 and 12)	20			21			21			46
Interest expense to affiliated companies (Notes 11, 12 and 15)	4			131			155			138
Other income (expense) - net	(2		)	(8		)	5			17
Income (loss) from continuing operations, before income taxes	70			300			(1,235		)	(1,536		)
Income tax expense (Note 10)	25			109			82			78
Income (loss) from continuing operations	45			191			(1,317		)	(1,614		)

The accompanying notes are an integral part of these consolidated financial statements.

F-4

LG&E and KU Energy LLC

Consolidated Statements of Income (continued)

(millions)

	Successor			Predecessor
	November 1, 2010 through			January 1, 2010 through			Year Ended December 31,
	December 31, 2010			October 31, 2010			2009			2008
Discontinued operations (Note 19):
Loss from discontinued operations before tax	$	—		$	(7	)	$	(222	)	$	(287	)
Income tax benefit from discontinued operations	—			3			71			114
Income (loss) from discontinued operations before noncontrolling interest	—			(4		)	(151		)	(173		)
Gain (loss) on disposal of discontinued operations before tax	4			5			(114		)	—
Income tax benefit (expense) from disposal of discontinued operations	(2		)	(2		)	45			—
Gain (loss) on disposal of discontinued operations	2			3			(69		)	—
Net income (loss)	47			190			(1,537		)	(1,787		)
Noncontrolling interest - loss from discontinued operations	—			—			(5		)	(8		)
Net income (loss) attributable to member	$	47		$	190		$	(1,542	)	$	(1,795	)

The accompanying notes are an integral part of these consolidated financial statements.

F-5

LG&E and KU Energy LLC

Consolidated Statements of Retained Earnings (Deficit)

(millions)

	Successor			Predecessor
	November 1, 2010 through			January 1, 2010 through			Year Ended December 31,
	December 31, 2010			October 31, 2010			2009			2008
Balance at beginning of period	$	(2,654	)	$	(2,763	)	$	(1,172	)	$	691
Effect of PPL acquisition	2,654			—			—			—
Balance at November 1, 2010	—			—			—			—
Net income (loss) attributable to member	47			190			(1,542		)	(1,795		)
Cash dividends declared (Note 15)	—			(81		)	(49		)	(68		)
Balance at end of period	$	47		$	(2,654	)	$	(2,763	)	$	(1,172	)

The accompanying notes are an integral part of these consolidated financial statements.

F-6

LG&E and KU Energy LLC

Consolidated Statements of Comprehensive Income (Loss)

(millions)

	Successor		Predecessor
	November 1, 2010 through		January 1, 2010 through			Year Ended  December 31,
	December 31, 2010		October 31, 2010			2009			2008
Net income (loss)	$	47	$	190		$	(1,537	)	$	(1,787	)
Other comprehensive income (loss):
Defined-benefit pension and postretirement plans, net of tax benefit (expense) of $(3), $13, $(11) and $31, respectively (Note 9)	6		(18		)	18			(46		)
Gain (loss) on derivative instruments, net of tax benefit (expense) of $0, $(7), $(2) and $0, respectively (Notes 1 and 5)	—		10			3			(2		)
Equity investee’s other comprehensive income (loss), net of tax benefit benefit of $0, $1, $0 and $0, respectively (Note 1)	—		(2		)	—			—
Foreign currency translation adjustment, net of tax benefit of $0, $0, $2 and $2, respectively (Note 19)	—		—			(6		)	(7		)
Comprehensive income (loss)	53		180			(1,522		)	(1,842		)
Noncontrolling interest - loss from discontinued operations	—		—			(5		)	(8		)
Other comprehensive (income) loss allocable to noncontrolling interest:
Foreign currency translation adjustment	—		—			4			4
Income tax benefit related to items of other comprehensive income	—		—			(1		)	(1		)
Comprehensive income (loss) attributable to member	$	53	$	180		$	(1,524	)	$	(1,847	)

The accompanying notes are an integral part of these consolidated financial statements.

F-7

LG&E and KU Energy LLC

Consolidated Balance Sheets

(millions)

	Successor			Predecessor
	December 31,			December 31,
	2010			2009
Assets
Current assets:
Cash and cash equivalents	$	11		$	7
Accounts receivable (less allowance for doubtful accounts: 2010, $17; 2009, $4):
Customer	160			145
Affiliated companies	2			—
Other	33			34
Unbilled revenues	170			141
Fuel, materials and supplies:
Fuel (predominantly coal)	163			158
Natural gas stored underground	60			56
Other materials and supplies	75			72
Notes receivable from affiliated companies	61			—
Income taxes receivable	40			8
Deferred income taxes - net (Note 10)	66			10
Assets of discontinued operations (Note 19)	—			90
Regulatory assets (Note 3)	22			46
Available for sale debt securities	163			—
Other intangible assets	58			—
Prepayments and other current assets	26			28
Total current assets	1,110			795
Investment in unconsolidated venture (Note 1)	31			21
Property, plant and equipment:
Regulated utility plant — electric and natural gas	6,230			9,092
Non-regulated property, plant and equipment	4			19
Property, plant and equipment in service, gross	6,234			9,111
Accumulated depreciation	(31		)	(3,560		)
Construction work in progress	1,340			1,599
Property, plant and equipment - net	7,543			7,150

The accompanying notes are an integral part of these consolidated financial statements.

F-8

LG&E and KU Energy LLC

Consolidated Balance Sheets (continued)

(millions)

	Successor		Predecessor
	December 31,		December 31,
	2010		2009
Deferred debits and other assets:
Regulatory assets (Notes 3 and 9):
Pension and postretirement benefits	$	330	$	309
Other regulatory assets	259		242
Goodwill (Notes 2 and 7)	996		837
Cash surrender value of key man life insurance	39		38
Other intangible assets (Notes 2 and 7)	356		—
Other assets	55		37
Total deferred debits and other assets	2,035		1,463
Total assets	$	10,719	$	9,429

The accompanying notes are an integral part of these consolidated financial statements.

F-9

LG&E and KU Energy LLC

Consolidated Balance Sheets (continued)

(millions)

	Successor		Predecessor
	December 31,		December 31,
	2010		2009
Liabilities and Equity
Current liabilities:
Current portion of long-term debt (Note 11)	$	2	$	348
Current portion of long-term debt to affiliated company (Notes 11 and 12)	—		358
Notes payable to affiliated company (Notes 12 and 15)	—		851
Note payable	163		—
Accounts payable	189		222
Accounts payable to affiliated companies (Note 15)	3		43
Customer deposits	46		44
Accrued taxes	27		22
Liabilities of discontinued operations (Note 19)	—		7
Regulatory liabilities (Note 3)	92		42
Derivative liabilities (Note 5)	4		76
Accrued interest	17		5
Employee accruals	69		59
Other current liabilities	32		31
Total current liabilities	644		2,108
Long-term debt:
Long-term debt (Note 11)	3,823		416
Long-term debt to affiliated companies (Notes 11 and 15)	—		3,063
Total long-term debt	3,823		3,479
Deferred credits and other liabilities:
Deferred income taxes (Note 10)	240		87
Accumulated provision for pensions (Note 9)	449		540
Investment tax credits (Note 10)	150		152
Asset retirement obligations (Note 4)	103		65
Regulatory liabilities (Note 3):
Accumulated cost of removal of utility plant	623		594
Other regulatory liabilities	394		69
Derivative liabilities (Note 5)	32		28
Other liabilities	250		83
Total deferred credits and other liabilities	2,241		1,618

The accompanying notes are an integral part of these consolidated financial statements.

F-10

LG&E and KU Energy LLC

Consolidated Balance Sheets (continued)

(millions)

	Successor		Predecessor
	December 31,		December 31,
	2010		2009
Equity:
Membership units, without par value — authorized 10,000,000 units, outstanding 1,001 units	$	—	$	774
Additional paid-in capital	3,958		4,224
Retained earnings:
Retained earnings (deficit)	47		(2,763		)
Accumulated other comprehensive income (loss) (Note 17)	6		(43		)
Total member’s equity	4,011		2,192
Noncontrolling interest	—		32
Total equity	4,011		2,224
Total liabilities and equity	$	10,719	$	9,429

The accompanying notes are an integral part of these consolidated financial statements.

F-11

LG&E and KU Energy LLC

Consolidated Statements of Cash Flows

(millions)

	Successor			Predecessor
	November 1, 2010			January 1, 2010			Year Ended
	through			through			December 31,
	December 31, 2010			October 31, 2010			2009			2008
Cash flows from operating activities:
Net income	$	47		$	190		$	(1,537	)	$	(1,787	)
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	49			235			271			265
Deferred income taxes — net	52			67			46			(14		)
Investment tax credits (Note 10)	—			(2		)	(3		)	(4		)
Provision for pension and postretirement benefits	13			52			83			41
Loss on impairment of goodwill	—			—			1,493			1,806
Unrealized (gain) loss on derivatives	—			14			(33		)	48
Undistributed earnings of unconsolidated venture	—			(3		)	11			1
Loss from discontinued operations — net of tax	(2		)	1			225			181
Regulatory asset for unrealized gain on interest rate swaps (Note 5)	—			(22		)	—			—
Other — net	3			2			(3		)	(2		)
Change in current assets and liabilities:
Accounts receivable	(16		)	12			69			14
Unbilled revenues	(70		)	41			4			(13		)
Fuel, materials and supplies	15			(28		)	31			(69		)
Regulatory assets	(2		)	10			—			—
Other current assets	(3		)	9			(3		)	(1		)
Accounts payable	(15		)	(34		)	(44		)	25
Accounts payable to affiliates	4			(7		)	(20		)	35
Accrued taxes	(36		)	16			(76		)	(4		)
Regulatory liabilities	14			(21		)	—			—
Other current liabilities	(25		)	49			1			(16		)
Pension and postretirement funding (Note 9)	(8		)	(57		)	(51		)	(18		)
Storm restoration regulatory asset	—			—			(101		)	(26		)
Other regulatory assets	—			15			40			(20		)
Deferred income taxes — net	11			27			11			12
Other regulatory liabilities	2			(26		)	(52		)	10
Discontinued operations	—			13			(655		)	(69		)
Change in smelter contract liability	(15		)	(51		)	75			—
Other — net	8			(14		)	14			(5		)
Net cash provided by (used in) operating activities	26			488			(204		)	390

The accompanying notes are an integral part of these consolidated financial statements.

F-12

LG&E and KU Energy LLC

Consolidated Statements of Cash Flows (continued)

(millions)

	Successor			Predecessor
	November 1, 2010			January 1, 2010			Year Ended
	through			through			December 31,
	December 31, 2010			October 31, 2010			2009			2008
Cash flows from investing activities:
Construction expenditures	$	(152	)	$	(447	)	$	(703	)	$	(931	)
Construction expenditures — discontinued operations	—			—			(23		)	(28		)
Proceeds from sales of discontinued operations	—			21			—			—
Proceeds from sale of assets	—			—			3			9
Change in restricted cash	2			—			10			1
Loans to affiliates	(61		)	—			—			—
Cash settlement on derivatives	—			—			7			(8		)
Net cash provided by (used in) investing activities	(211		)	(426		)	(706		)	(957		)
Cash flows from financing activities:
Issuance of long-term debt (Note 11)	2,890			—			—			78
Issuance of short-term note payable (Note 12)	163			—			—			—
Short-term borrowings from affiliated company — net (Notes 11 and 15)	—			(3		)	(22		)	237
Other borrowings from affiliated companies (Notes 11 and 15)	2,784			950			1,230			575
Repayments on other borrowings to affiliated companies (Notes 11, 12 and 15)	(2,784		)	(900		)	(255		)	—
Repayments to E.ON affiliates	(4,319		)	—			—			—
Debt issuance costs	(32		)	—			—			—
Retirement of long-term debt	—			—			—			(67		)
Acquisition of outstanding bonds	—			—			—			(339		)
Reissuance of reacquired bonds	—			—			—			159
Distributions to noncontrolling interests — discontinued operations	—			—			(2		)	(7		)
Payment of dividends (Note 15)	—			(87		)	(49		)	(68		)
Capital contribution from member (Note 2)	1,565			—			—			—
Distribution to member	(100		)	—			—			—
Net cash provided by (used in) financing activities	167			(40		)	902			568
Change in cash and cash equivalents	(18		)	22			(8		)	1

The accompanying notes are an integral part of these consolidated financial statements.

F-13

LG&E and KU Energy LLC

Consolidated Statements of Cash Flows (continued)

(millions)

	Successor			Predecessor
	November 1, 2010			January 1, 2010		Year Ended
	through			through		December 31,
	December 31, 2010			October 31, 2010		2009			2008
Cash and cash equivalents at beginning of period	$	29		$	7	$	15		$	14
Cash and cash equivalents at end of period	$	11		$	29	$	7		$	15
Supplemental disclosures of cash flow information:
Cash paid (received) during the year for:
Interest — net of amount capitalized	$	41		$	153	$	161		$	163
Income taxes — net	(1		)	9		(8		)	61

The accompanying notes are an integral part of these consolidated financial statements.

F-14

LG&E and KU Energy LLC

Consolidated Statements of Capitalization

(millions)

	Successor		Predecessor
	December 31,		December 31,
	2010		2009
Long-term debt (Note 12):
Louisville Gas and Electric Company:
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 LG&E first mortgage bonds	535		—
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
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
Trimble Co. 2007 Series A, due June 1, 2033, 4.60%	60		60
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 LG&E pollution control bonds including reacquired bonds	574		574
Less reacquired bonds	—		163
Total LG&E pollution control bonds	574		411

The accompanying notes are an integral part of these consolidated financial statements.

F-15

LG&E and KU Energy LLC

Consolidated Statements of Capitalization (continued)

(millions)

	Successor		Predecessor
	December 31,		December 31,
	2010		2009
Due to affiliates:
Fidelia, due January 16, 2012, 4.33%, unsecured	$	—	$	25
Fidelia, due April 30, 2013, 4.55%, unsecured	—		100
Fidelia, due August 15, 2013, 5.31%, unsecured	—		100
Fidelia, due November 23, 2015, 6.48%, unsecured	—		50
Fidelia, due July 25, 2018, 6.21%, unsecured	—		25
Fidelia, due November 26, 2022, 5.72%, unsecured	—		47
Fidelia, due April 13, 2031, 5.93%, unsecured	—		68
Fidelia, due April 13, 2037, 5.98%, unsecured	—		70
Total LG&E due to affiliates	—		485
Total LG&E debt outstanding	1,109		896

The accompanying notes are an integral part of these consolidated financial statements.

F-16

LG&E and KU Energy LLC

Consolidated Statements of Capitalization (continued)

(millions)

	Successor		Predecessor
	December 31,		December 31,
	2010		2009
Kentucky Utilities Company:
First mortgage bonds:
First mortgage bond 2015 Series, due November 1, 2015, 1.625%	$	250	$	—
First mortgage bond 2020 Series, due November 1, 2020, 3.25%	500		—
First mortgage bond 2040 Series, due November 1, 2040, 5.125%	750		—
Total KU first mortgage bonds	1,500		—
Pollution control series:
Mercer Co. 2000 Series A, due May 1, 2023, variable %	13		13
Carroll Co. 2007 Series A, due February 1, 2026, 5.75%	18		18
Carroll Co. 2002 Series A, due February 1, 2032, variable %	21		21
Carroll Co. 2002 Series B, due February 1, 2032, variable %	2		2
Mercer Co. 2002 Series A, due February 1, 2032, variable %	8		8
Muhlenberg Co. 2002 Series A, due February 1, 2032, variable %	2		2
Carroll Co. 2008 Series A, due February 1, 2032, variable %	78		78
Carroll Co. 2002 Series C, due October 1, 2032, variable %	96		96
Carroll Co. 2004 Series A, due October 1, 2034, variable %	50		50
Carroll Co. 2006 Series B, due October 1, 2034, variable %	54		54
Trimble Co. 2007 Series A, due March 1, 2037, 6.00%	9		9
Total KU pollution control bonds	351		351

The accompanying notes are an integral part of these consolidated financial statements.

F-17

LG&E and KU Energy LLC

Consolidated Statements of Capitalization (continued)

(millions)

	Successor		Predecessor
	December 31,		December 31,
	2010		2009
Due to affiliates:
Fidelia, due November 24, 2010, 4.24%, unsecured	$	—	$	33
Fidelia, due January 16, 2012, 4.39%, unsecured	—		50
Fidelia, due April 30, 2013, 4.55%, unsecured	—		100
Fidelia, due August 15, 2013, 5.31%, unsecured	—		75
Fidelia, due December 19, 2014, 5.45%, unsecured	—		100
Fidelia, due July 8, 2015, 4.735%, unsecured	—		50
Fidelia, due December 21, 2015, 5.36%, unsecured	—		75
Fidelia, due October 25, 2016, 5.675%, unsecured	—		50
Fidelia, due April 24, 2017, 5.28%, unsecured	—		50
Fidelia, due June 20, 2017, 5.98%, unsecured	—		50
Fidelia, due July 25, 2018, 6.16%, unsecured	—		50
Fidelia, due August 27, 2018, 5.645%, unsecured	—		50
Fidelia, due December 17, 2018, 7.035%, unsecured	—		75
Fidelia, due July 29, 2019, 4.81%, unsecured	—		50
Fidelia, due October 25, 2019, 5.71%, unsecured	—		70
Fidelia, due November 25, 2019, 4.445%, unsecured	—		50
Fidelia, due February 7, 2022, 5.69%, unsecured	—		53
Fidelia, due May 22, 2023, 5.85%, unsecured	—		75
Fidelia, due September 14, 2028, 5.96%, unsecured	—		100
Fidelia, due June 23, 2036, 6.33%, unsecured	—		50
Fidelia, due March 30, 2037, 5.86%, unsecured	—		75
Total KU due to affiliates	—		1,331
Total KU debt outstanding	1,851		1,682
LKC:
Medium term notes, due November 1, 2011, 7.47%	2		2
Total LKC debt outstanding	2		2

The accompanying notes are an integral part of these consolidated financial statements.

F-18

LG&E and KU Energy LLC

Consolidated Statements of Capitalization (continued)

(millions)

	Successor		Predecessor
	December 31,		December 31,
	2010		2009
LKE:
Senior notes:
Senior unsecured note, 2015 Series, due November 15, 2015, 2.125%	$	400	$	—
Senior unsecured note, 2020 Series, due November 15, 2020, 3.75%	475		—
Total LKE senior notes	875		—
Due to affiliates:
Fidelia, due April 30, 2010, 4.64%, unsecured	—		150
Fidelia, due June 28, 2010, variable, unsecured	—		100
Fidelia, due October 15, 2010, 7.01%, unsecured	—		75
Fidelia, due January 6, 2011, 7.784%, unsecured	—		50
Fidelia, due July 5, 2011, variable, unsecured	—		300
Fidelia, due April 24, 2012, variable, unsecured	—		50
Fidelia, due November 19, 2012, variable, unsecured	—		75
Fidelia, due November 26, 2012, variable, unsecured	—		50
Fidelia, due December 19, 2012, 5.52%, unsecured	—		100
Fidelia, due December 21, 2012, variable, unsecured	—		100
Fidelia, due January 15, 2014, 6.044%, unsecured	—		75
Fidelia, due June 20, 2014, variable, unsecured	—		50
Fidelia, due June 23, 2014, variable, unsecured	—		50
Fidelia, due October 27, 2014, variable, unsecured	—		50
E.ON North America, due October 27, 2014, 4.63%, unsecured	—		50
Fidelia, due March 25, 2015, variable, unsecured	—		75
Fidelia, due February 17, 2016, variable, unsecured	—		80
Fidelia, due December 20, 2016, variable, unsecured	—		50
Fidelia, due April 25, 2017, 5.71%, unsecured	—		75
Total LKE due to affiliates	—		1,605
Total LKE debt outstanding	875		1,605

The accompanying notes are an integral part of these consolidated financial statements.

F-19

LG&E and KU Energy LLC

Consolidated Statements of Capitalization (continued)

(millions)

	Successor			Predecessor
	December 31,			December 31,
	2010			2009
Total debt outstanding	$	3,837		$	4,185
Purchase accounting adjustments and discounts	(12		)	—
Less current portion of long-term debt	2			706
Long-term debt	3,823			3,479
Equity:
Membership units, without par value - Authorized 10,000,000 units, outstanding 1,001 units	—			774
Additional paid-in capital	3,958			4,224
Accumulated other comprehensive income (loss) (Note 17)	6			(43		)
Retained earnings (deficit)	47			(2,763		)
Total member’s equity	4,011			2,192
Noncontrolling interest	—			32
Total equity	4,011			2,224
Total capitalization	$	7,834		$	5,703

The accompanying notes are an integral part of these consolidated financial statements.

F-20

LG&E and KU Energy LLC and Subsidiaries

Notes to Consolidated Financial Statements

Note 1 - Summary of Significant Accounting Policies

General

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

Business

LKE is a holding company with regulated utility operations through its subsidiaries, LG&E and KU. LKE became a wholly owned subsidiary of PPL when PPL acquired all of the Company’s limited liability company interests from E.ON US Investments Corp. on November 1, 2010. LKE is a holding company under PUHCA 2005.

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 and KU, which constitute substantially all of LKE’s assets, are regulated utilities engaged in the generation, transmission, distribution and sale of electric energy. LG&E also engages in the distribution and sale of natural gas. LG&E and KU maintain their separate identities and serve customers in Kentucky under their respective names. KU also serves customers in Virginia under the Old Dominion Power name and it serves customers in Tennessee under the KU name.

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. KU provides electric service to approximately 514,000 customers in 77 counties in central, southeastern and western Kentucky, to approximately 30,000 customers in five counties in southwestern Virginia and to less than ten customers in Tennessee. KU also sells wholesale electric energy to 12 municipalities in Kentucky. During 2010, approximately 95% of the electricity generated by LG&E and 98% of that generated by KU was produced by their coal-fired electric generating stations. The remainder is generated by natural gas and oil fueled CTs and hydroelectric power plants. LG&E purchases, transports, distributes or stores natural gas for 320,000 customers in Kentucky.

LKC has been the primary holding company for the Company’s non-utility businesses. Its businesses included:

·WKE. WKE had a 25-year lease of and operated the generating facilities of Big Rivers, a power generation cooperative in western Kentucky and a coal-fired facility owned by Henderson Municipal Power and Light, which is owned by the City of Henderson, Kentucky. The Company classified WKE as discontinued operations effective December 31, 2005 and it terminated the WKE lease and disposed of the operations in July 2009.

F-21

·Argentine Natural Gas Distribution. Through its Argentine natural gas distribution operations, LKC owned interests in entities which distribute natural gas to approximately one million customers in Argentina through two distribution companies (Centro and Cuyana). The Company classified its Argentine natural gas distribution operations as discontinued operations effective December 31, 2009 and it sold the operations on January 1, 2010.

For further discussion of the WKE lease and the Argentine natural gas distribution matters, see Note 13, Commitments and Contingencies and Note 19, Discontinued Operations.

Servco provides services to affiliated entities, including LKE, LG&E, KU, LKC and LEM, at cost, as permitted under PUHCA 2005.

Consolidation and Basis of Accounting

The consolidated financial statements include the following companies: LKE, LG&E, KU, LEM, Servco and LKC and their wholly owned subsidiaries. All intercompany balances and transactions have been eliminated. Investments in business entities in which the Company does not control, but has the ability to exercise significant influence over operating and financial policies, are accounted for by the equity method.

LKE’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. LKE’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 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, for information regarding the acquisition and the purchase accounting adjustments.

Changes in Classification

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 consist mainly of those necessary to present the Company’s Argentine natural gas distribution businesses as discontinued operations and to identify amounts for prior periods that are separately disclosed in the financial statements. See Note 19, Discontinued Operations, for further information.

Regulatory Accounting

LG&E and KU are cost-based rate-regulated utilities. 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

F-22

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, the Kentucky Commission, the Virginia Commission or the Tennessee Regulatory Authority. See Note 3, Rates and Regulatory Matters, for additional detail regarding regulatory assets and liabilities.

Management’s Use of Estimates

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.

Derivative Financial Instruments

LKE enters into interest rate swap contracts to hedge exposure to variability in expected cash flows associated with existing debt instruments. LKE 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 Consolidated 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 Consolidated 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 Consolidated Balance Sheets. The Predecessor and Successor 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 Consolidated Balance Sheets. Energy trading contracts classified as non-current are recognized in “Other assets” or long-term “Derivative liabilities” on the Consolidated

F-23

Balance Sheets. Cash inflows and outflows related to derivative instruments are included as a component of operating activity on the Consolidated Statements of Cash Flows due to the underlying nature of the hedged items.

The Company does not net collateral against derivative instruments.

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

Revenue and Accounts Receivable

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

	Successor		Predecessor
	November 1, 2010		January 1, 2010		Year Ended
	through		through		December 31,
	December 31, 2010		October 31, 2010		2009		2008
Residential	$	219	$	886	$	1,020	$	1,044
Industrial and commercial	209		997		1,112		1,159
Municipals	15		88		91		92
Other retail	42		212		227		213
Wholesale	9		31		51		167
	$	494	$	2,214	$	2,501	$	2,675

Revenue Recognition

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

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

Allowance for Doubtful Accounts

The allowance for doubtful accounts included in “Accounts receivable — customer accounts” 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” accounts receivable is composed of accounts aged more than four months. Accounts are written off as management determines them uncollectible.

F-24

The changes in the allowance for doubtful accounts were:

	Successor		Predecessor
	December 31, 2010		October 31, 2010			December 31, 2009			December 31, 2008
Balance at beginning of period (a)	$	—	$	4		$	4		$	4
Charged to income	10		(10		)	(8		)	(6		)
Charged to balance sheets	7		10			8			6
Balance at end of period	$	17	$	4		$	4		$	4

(a)Successor beginning balance reflects revaluation of accounts receivable due to purchase accounting.

Cash

Cash Equivalents

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

Restricted Cash

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 Consolidated Statements of Cash Flows. On the Consolidated 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”. LKE’s December 31, 2010, balance of restricted cash is $23 million, consisting primarily of cash collateral posted to counterparties related to LKE’s interest rate swap contracts.

Fair Value Measurements

LKE 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, Predecessor share performance plan liabilities and cash and cash equivalents. LKE 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.

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LKE 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:

·Level 1 - Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

·Level 2 - Other inputs that are directly or indirectly observable in the marketplace.

·Level 3 - Unobservable inputs which are supported by little or no market activity.

Assessing the significance of a particular input requires judgment that considers factors specific to the asset or liability. As such, LKE’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.

Investments

Investments in Debt Securities

At December 31, 2010 and December 31, 2009, LKE had $163 million of bonds classified as “Long-term debt” on the Consolidated Balance Sheets that LKE 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 Successor presentation and the Predecessor presentation are both appropriate under GAAP.

Available for sale debt securities are carried at fair value and are classified as current assets on the Consolidated 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, LKE 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:

·if there is intent to sell the security or a requirement to sell the security before recovery, the other-than-temporary impairment is recognized currently in earnings;

·if there is no intent to sell the security or requirement to sell the security before recovery, the portion of the other-than-temporary impairment that is considered a credit loss is recognized currently in earnings and the remainder of the other-than-temporary impairment is reported in other comprehensive income, net of tax; or

·if there is no intent to sell the security or requirement to sell the security before recovery and there is no credit loss, the unrealized loss is reported in other comprehensive income, net of tax.

See Note 21, Subsequent Events, for the current status of reacquired bonds.

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Equity Method Investment

LKE’s equity method investment, included in “Investment in unconsolidated venture” on the Consolidated Balance Sheets, consists of its investment in EEI. LKE owns 20% of the common stock of EEI, which owns and operates a 1,002 Mw summer capacity coal-fired plant and a 74 Mw summer capacity natural gas facility in southern Illinois. Through a power marketer affiliated with its majority owner, EEI sells its output to third parties. Although LKE holds investment interest in EEI, it is not the primary beneficiary and is therefore not consolidated into the Company’s financial statements. LKE’s investment in EEI is accounted for under the equity method of accounting and as of December 31, 2010 and 2009, totaled $30 million and $21 million, respectively. LKE’s direct exposure to loss as a result of its involvement with EEI is generally limited to the value of its investment. See Note 2, Acquisition by PPL, for further discussion regarding purchase accounting adjustments recognized for LKE’s investment in EEI.

The results of operations and financial position of EEI, LKE’s equity method investment, are summarized below.

Condensed income statement information for the years ended December 31 is as follows:

	2010
	(unaudited)		2009		2008
Net sales	$	343	$	297	$	514
Net income	16		10		142
LKE’s equity in earnings of EEI	3		1		30

Condensed balance sheet information as of December 31 is as follows:

	2010 (unaudited)		2009
Current assets	$	62	$	84
Long-lived assets	181		178
Total assets	$	243	$	262
Current liabilities	$	113	$	166
Long-term liabilities	72		50
Equity	58		46
Total liabilities and equity	$	243	$	262

Cost Method Investment

LKE’s cost method investment, included in “Investment in unconsolidated venture” on the Consolidated Balance Sheets, consists of the Utilities’ investment in OVEC. The Utilities and ten 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 the Utilities and 12 other companies affiliated with the various owners. Pursuant to current contractual agreements, the Utilities own 8.13% of OVEC’s common stock and are contractually entitled to 8.13% of OVEC’s output. Based on nameplate generating capacity, this would be approximately 194Mw.

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As of December 31, 2010 and 2009, LKE’s investment in OVEC totaled less than $1 million. LKE 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, LKE 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.

Long-Lived and Intangible Assets

Regulated Utility Plant

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. LKE determined that fair value was equal to net book value at the acquisition date since LKE’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. LKE has not recorded significant 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.

Capitalized Software Cost

Included in “Property, plant and equipment” on the Consolidated 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:

Successor				Predecessor
December 31, 2010				December 31, 2009
Carrying Amount		Accumulated Amortization (a)		Carrying Amount		Accumulated Amortization
$	84	$	2	$	119	$	35

(a)The accumulated amortization as of November 1, 2010, was netted against the carrying amount of the software as the fair value was determined to be equal to net book value for property, plant and equipment.

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Amortization expense of capitalized software costs was as follows:

Successor		Predecessor
November 1, 2010		January 1, 2010		Year Ended
through		through		December 31,
December 31, 2010		October 31, 2010		2009		2008
$	2	$	12	$	14	$	12

The amortization of capitalized software is included in “Depreciation and amortization” on the Consolidated Statements of Income.

Depreciation and Amortization

Utility 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 follows:

Year	Percentage
2010	4.7	%
2009	2.8	%
2008	3.0	%

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

Year	Percentage
2010	0.7	%
2009	0.5	%
2008	0.5	%

Goodwill, Intangible Assets and Asset Impairment

LKE 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.

As the result of PPL’s acquisition, LKE recorded the fair value of its coal contracts, emission allowances, EEI investment 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. See Note 2, Acquisition by PPL, for methods used to determine the long-lived intangible assets’ fair values. When determining the useful life of an intangible asset, including intangible assets that are renewed or extended, LKE considers the expected use of the asset, the expected useful life of other assets to which the useful life of

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the intangible asset may relate and legal, regulatory, or contractual provisions that may limit the useful life. 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 Consolidated Balance Sheets.

The Predecessor reported emission allowances in “Other materials and supplies” on the Consolidated 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, the carrying value of goodwill as of October 31, 2010, was eliminated.

In connection with PPL’s acquisition of LKE, LG&E and KU recorded goodwill, representing the excess of the purchase price paid over the estimated fair value of the assets acquired and liabilities assumed in the acquisition of the businesses. 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.

Asset Retirement Obligations

LKE 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 Consolidated 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.

Defined Benefits

LKE 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 on LG&E and KU. Consequently, the funded status of all defined benefit plans is fully recognized on the Consolidated 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.

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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.

Other

Loss Accruals

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.” LKE continuously assesses potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events.

LKE does not record the accrual of contingencies that might result in gains unless recovery is assured.

Income Taxes

For the periods ended on or before October 31, 2010, a consolidated federal income tax return is filed by LKE’s former direct parent, E.ON US Investments Corp. On November 1, 2010, LKE became a part of PPL’s consolidated U.S. federal income tax return.

Significant management judgment is required in developing LKE’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.

LKE 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

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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 LKE.

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.

LKE records valuation allowances to reduce deferred tax assets to the amounts that are more likely than not to be realized. LKE 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 LKE 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 LKE 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 LKE’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 Consolidated Balance Sheets in “Regulatory liabilities”.

LKE defers investment tax credits when the credits are utilized and amortizes the deferred amounts over the average lives of the related assets.

See Note 10, Income Taxes, for further discussion regarding income taxes.

Leases

LKE evaluates whether arrangements entered into contain leases for accounting purposes.

Materials and Supplies

Fuel, natural gas stored underground and other materials and supplies inventories are accounted for using the average-cost method.

Fuel and Natural Gas Costs

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.

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Debt

The Company’s long-term debt includes $348 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 the Utilities’ aggregate $800 million credit facilities, which mature in December 2014, to fund any mandatory purchases. The Predecessor classified these bonds as current portion of long-term debt due to the tender for purchase provisions. The Successor presentation and the Predecessor 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.

Unamortized Debt Expense

Debt expense is capitalized and amortized over the lives of the related note or 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.

Guarantees

Generally, the initial measurement of a guarantee liability is the fair value of the guarantee at its inception. However, there are certain guarantees excluded from the scope of accounting guidance and other guarantees that are not subject to the initial recognition and measurement provisions of accounting guidance. See Note 13, Commitments and Contingencies, for further discussion of recorded and unrecorded guarantees.

Recent Accounting Pronouncements

The following recent accounting pronouncement affected LKE:

Fair Value Measurements

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.

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Note 2 - Acquisition by PPL

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 and its subsidiaries at the acquisition date.

The fair value of the consideration paid by PPL to E.ON for LKE was as follows:

Aggregate enterprise consideration	$	7,614
Less: funds made available to E.ON U.S. LLC to repay pre-acquisition affiliate indebtedness	4,349
Less: fair value of assumption of long-term debt outstanding, net	772
Cash consideration paid for E.ON U.S. LLC equity interest	$	2,493

The allocation of the purchase price to the fair value of assets acquired and liabilities assumed is as follows:

Current assets	$	1,035
Investments	31
Property, plant and equipment	7,469
Other intangible assets	361
Regulatory and other non-current assets	689
Current liabilities (excluding current portion of long-term debt)	(516		)
Affiliated debt	(4,349		)
Debt (current and non-current)	(934		)
Other non-current liabilities	(2,289		)
Net identifiable assets acquired	1,497
Goodwill	996
Purchase price	2,493
Capital contribution on November 1, 2010	1,565
Total investment on November 1, 2010	$	4,058

Goodwill represents value paid for the rate regulated businesses of LG&E and KU, which are 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 and KU’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.

Adjustments to LKE’s assets and liabilities that contributed to goodwill are as follows:

The fair value adjustment on the EEI investment was calculated using the discounted cash flow valuation method. The result was an increase in LKE’s value of the investment in EEI; the fair value of EEI was calculated to be $30 million. LKE’s carrying value for EEI was $12 million and a fair value adjustment of $18 million was recorded. The fair value adjustment to EEI is amortized over the expected remaining useful life of plant and equipment at EEI, which is estimated to be over 20 years.

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The pollution control bonds, excluding the reacquired bonds, had a fair value of $770 million compared to a carrying value of $762 million on November 1, 2010, which resulted in an adjustment of $8 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 value of OVEC was determined to be $126 million based upon an announced transaction by another owner. LKE’s stock was valued at approximately $1 million and the power purchase agreement has been valued at $125 million. An intangible asset was recorded with the offset to regulatory liability and will be amortized using the units of production method until the power purchase agreement ends in March 2026.

·LKE recorded an emission allowance intangible asset and regulatory liability as the result of adjusting the fair value of the emission allowances at LG&E and KU. The emission allowance intangible of $17 million represents allocated and purchased SO2 and NOx emission allowances that are unused as of the valuation date or allocated for use in future years. LKE had previously recorded emission allowances as other materials and supplies. To conform to PPL’s accounting policy all emission allowances are now recorded as intangible assets. The emission allowance intangible asset is amortized as the emission allowances are consumed, which is expected to occur through 2040.

·LKE recorded a coal contract intangible asset of $269 million and a non-current liability of $33 million on the Consolidated Balance Sheets. An offsetting regulatory asset was recorded for those contracts with unfavorable terms relative to market. An offsetting regulatory liability was recorded for those contracts that had favorable terms relative to market. All coal contracts held by the Utilities, wherein they had entered into arrangements to buy amounts of coal at fixed prices from counterparties at a future date, were fair valued. The intangible assets and other liabilities, as well as the regulatory assets and liabilities, are being amortized over the same terms as the related contracts, which expire through 2016.

·Adjustments on November 1, 2010 were made to record LKE pension assets at fair value, remeasure its pension and postretirement benefit obligations at current discount rates and eliminate accumulated other comprehensive income (loss). An increase of $4 million in the liability balances of the Utilities was recorded, due to the lowering of the discount rate; this was credited to their respective pension and postretirement liability balances with offsetting adjustments made to the related regulatory assets and liabilities

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 Consolidated Balance Sheets with offsetting regulatory assets or liabilities. Prior to the acquisition, LKE 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. LKE’s customer rates will continue to reflect these items (e.g. coal, purchased power, emission allowances) at their original contracted prices.

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LKE also considered whether a separate fair value should be assigned to LKE’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.

Note 3 - Rates and Regulatory Matters

LG&E and KU are subject to the jurisdiction of the Kentucky Commission and the FERC and KU is further subject to the jurisdiction of the Virginia Commission and the Tennessee Regulatory Authority 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 their position in the marketplace and the status of regulation in Kentucky and Virginia, there are no plans or intentions to discontinue the application of the regulated operations guidance of the FASB ASC.

LG&E’s and KU’s Kentucky 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 Consolidated Balance Sheets with offsetting regulatory assets or liabilities. Prior to the acquisition, LKE 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. LKE’s customer rates will continue to reflect these items (e.g. coal, purchased power, emission allowances) at their original contracted prices.

KU’s Virginia base rates are calculated based on a return on rate base. All regulatory assets and liabilities are excluded from the return on rate base utilized in the calculation of Virginia base rates.

KU’s wholesale requirements rates for municipal customers are calculated based on annual updates to a rate formula that utilizes a return on rate base. All regulatory assets and liabilities are excluded from the return on rate base utilized in the development of municipal rates.

2010 Purchase and Sale Agreement with PPL

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, Virginia and Tennessee and the FERC) and the absence of injunctions or restraints imposed by governmental entities.

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Change of control and financing-related applications were filed on May 28, 2010, with the Kentucky Commission and on June 15, 2010, with the Virginia Commission and the Tennessee Regulatory Authority. 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 and KU committed that no base rate increases would take effect before January 1, 2013. The LG&E and KU rate increases that took effect on August 1, 2010, were not impacted by the settlement. Under the terms of the settlement, the Utilities 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 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 the Utilities 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 and KU via the acquisition of E.ON U.S. by PPL, incorporating the terms of the submitted settlement. On October 19, 2010 and October 21, 2010, respectively, Orders approving the acquisition of E.ON U.S. by PPL were received from the Virginia Commission and the Tennessee Regulatory Authority. The Commissions’ Orders contained a number of other commitments with regard to operations, workforce, community involvement and other matters.

In mid-September 2010, LG&E and KU and other applicants in the FERC change of control proceeding reached an agreement with the protesters, whereby such protests have been 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 agreement not to terminate certain KU municipal customer contracts prior to January 2017, an exclusion of any transaction-related costs from wholesale energy and tariff customer rates to the extent that the Company 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.

2010 Kentucky Rate Cases

In January 2010, LG&E and KU filed applications with the Kentucky Commission requesting increases in electric base rates of approximately 12%, or $95 million and $135 million annually, respectively. In addition, LG&E requested an increase in its natural gas base rates of approximately 8%, or $23 million annually. In June 2010, LG&E and KU and all of the intervenors, except the AG, agreed to stipulations providing for increases in LG&E’s electric base rates of $74 million annually, LG&E’s natural gas base rates of $17 million annually and KU’s electric base rates of $98 million annually, respectively. All parties, except the AG, jointly 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.

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Virginia Rate Case

In June 2009, KU filed an application with the Virginia Commission requesting an increase in electric base rates for its Virginia jurisdictional customers in an amount of $12 million annually or approximately 21%. The proposed increase reflected a proposed rate of return on rate base of 8.586% based on a return on equity of 12%. During December 2009, KU and the Virginia Commission Staff agreed to a Stipulation and Recommendation authorizing base rate revenue increases of $11 million annually and a return on rate base of 7.846% based on a 10.5% return on common equity. In March 2010, the Virginia Commission issued an Order approving the stipulation, with the increased rates to be put into effect as of April 1, 2010. As part of the stipulation, KU refunded $1 million in interim rate amounts in excess of the ultimate approved rates.

FERC Wholesale Rate Case

In September 2008, KU filed an application with the FERC for increases in electric base rates applicable to wholesale power sales contracts or interchange agreements involving, collectively, twelve Kentucky municipalities. The application requested a shift from an all-in stated unit charge rates to an unbundled formula rate, including an annual adjustment mechanism. In 2009, the FERC issued an Order approving a settlement among the parties in the case, incorporating increases of approximately 3% from prior rates and a return on equity of 11%. In May 2010, KU submitted to the FERC the proposed current annual adjustments to the formula rates which incorporated certain proposed increases. Updated rates, including certain further adjustments from a review process involving wholesale requirements customers, became effective as of July 1, 2010, subject to certain review procedures by the wholesale requirements customers and the FERC.

By mutual agreement, the parties’ settlement of the 2008 application left outstanding the issue of whether KU must allocate to the municipal customers a portion of renewable resources it may be required to procure on behalf of its retail ratepayers. An Order was issued by the FERC in July 2010, indicating that KU is not required to allocate a portion of any renewable resources to the twelve municipalities, thus resolving the remaining issue.

2008 Kentucky Rate Case

In July 2008, LG&E and KU filed an application with the Kentucky Commission requesting increases in electric and natural gas base rates. In January 2009, LG&E, KU, 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 LG&E’s and KU’s electric base rates decreased by $13 million and $9 million annually, respectively. An Order approving the settlement agreement was received in February 2009. The new rates were implemented effective February 6, 2009.

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Regulatory Assets and Liabilities

The following regulatory assets and liabilities were included in the Consolidated Balance Sheets as of December 31:

	Successor		Predecessor
	2010		2009
Current regulatory assets:
GSC and PBR (a)	$	4	$	3
ECR (b)	5		35
FAC (b)	3		1
Coal contracts (c)	5		—
MISO exit (d)	—		3
Other (d) (e)	5		4
Total current regulatory assets	$	22	$	46
Non-current regulatory assets:
Pension and postretirement benefits (f)	$	330	$	309
Other non-current regulatory assets:
Storm restoration (d)	122		126
Mark-to-market impact of interest rate swaps (g)	34		—
ARO (h)	9		60
Unamortized loss on bonds (d)	34		34
Swap termination (d)	9		—
Coal contracts (c)	22		—
Unamortized debt expense	9		—
MISO exit (d)	6		13
Other (e)	14		9
Subtotal other non-current regulatory assets	259		242
Total non-current regulatory assets	$	589	$	551
Current regulatory liabilities:
Coal contracts	$	47	$	—
GSC	9		34
ECR	12		—
FAC	2		—
DSM	10		7
Emission allowances	12		—
Other (i)	—		1
Total current regulatory liabilities	$	92	$	42

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	Successor		Predecessor
	2010		2009
Non-current regulatory liabilities:
Accumulated cost of removal of utility plant	$	623	$	594
Other non-current regulatory liabilities:
Coal contracts	213		—
OVEC power purchase contract	124		—
Deferred income taxes — net	40		50
Postretirement benefits	10		9
Other (i)	7		10
Subtotal other non-current regulatory Liabilities	394		69
Total non-current regulatory liabilities	$	1,017	$	663

(a)The GSC and natural gas PBR regulatory assets have separate recovery mechanisms with recovery within eighteen months.

(b)The FAC and ECR regulatory assets have separate recovery mechanisms with recovery within twelve months.

(c)Offsetting regulatory asset for fair value purchase accounting adjustment. 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:

·The Virginia levelized fuel factor, which is a separate recovery mechanism with recovery within twelve months.

·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.

·The FERC jurisdictional portion of the EKPC FERC transmission settlement agreement is recovered through the annual FERC formula rate updates.

·FERC jurisdictional pension expense, which will be requested in the next FERC rate case.

·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 and KU generally recover this asset through pension expense included in the calculation of Kentucky 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 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 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 includes the Virginia levelized fuel factor, emission allowance purchase accounting offset, MISO exit and a change in accounting method for FERC jurisdictional spare parts.

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GSC

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.

ECR

LG&E and KU recover 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

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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, LG&E and KU filed applications for a new ECR plan with the Kentucky Commission seeking approval to recover investments in environmental upgrades and operations and maintenance costs at their generating facilities. During 2009, LG&E and KU reached a unanimous settlement with all parties to the case and the Kentucky Commission issued an Order approving their application. Recovery on customer bills through the monthly ECR surcharge for these projects began with the February 2010 billing cycle. At December 31, 2009, KU had a regulatory asset of $28 million, which changed to a regulatory liability in the first quarter of 2010, as a result of these roll-in adjustments to base rates. At December 31, 2010, the regulatory liability balance was $7 million.

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.

FAC

LG&E’s and KU’s 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 LG&E and KU 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 and May/June 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 and October 2007, respectively. In January 2009, the Kentucky Commission initiated a routine examination 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.

KU also employs an FAC mechanism for Virginia customers using an average fuel cost factor based primarily on projected fuel costs. The Virginia levelized fuel factor allows fuel recovery based on projected fuel costs for the coming year plus an adjustment for any over- or under-recovery of fuel

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expenses from the prior year. At December 31, 2010 and 2009, KU had a regulatory asset of $5 million and less than $1 million, respectively.

In February 2010, KU filed an application with the Virginia Commission seeking approval of a decrease in its fuel cost factor beginning with service rendered in April 2010. An Order was issued in April 2010, resulting in an agreed upon decrease of 23% from the fuel factor in effect for April 2009 through March 2010.

In February 2009, KU filed an application with the Virginia Commission seeking approval of a 29% increase in its fuel cost factor beginning with service rendered in April 2009. In February 2009, the Virginia Commission issued an Order allowing the requested change to become effective on an interim basis. The Virginia Staff testimony filed in April 2009 recommended a slight decrease in the factor filed by KU. The Company indicated the Virginia Staff proposal was acceptable. A hearing was held in May 2009, with general resolution of remaining issues. In May 2009, the Virginia Commission issued an Order approving the revised fuel factor, representing an increase of 24%, effective May 2009.

In February 2008, KU filed an application with the Virginia Commission seeking approval of a decrease in its fuel cost factor applicable during the billing period, April 2008 through March 2009. The Virginia Commission allowed the new rates to be in effect for the April 2008 customer billings. In April 2008, the Virginia Commission Staff recommended a change to the fuel factor KU filed in its application, to which KU agreed. Following a public hearing and an Order in May 2008, the recommended change became effective in June 2008, resulting in a decrease of 0.482 cents/kWh from the factor in effect for the April 2007 through March 2008 period.

Coal Contracts

In November 2010, purchase accounting adjustments were recorded for the fair value of LG&E’s and KU’s coal contracts. Offsetting regulatory assets or liabilities for fair value purchase accounting adjustments eliminate any ratemaking impact of the fair value adjustments.

MISO

Following receipt of applicable FERC, Kentucky Commission and other regulatory Orders, related to proceedings that had been underway since July 2003, LG&E and KU withdrew from the MISO effective September 1, 2006. Since the exit from the MISO, LG&E and KU have been operating under a FERC approved OATT. LG&E and KU now contract with the TVA to act as their transmission reliability coordinator and SPP to function as the independent transmission operator, pursuant to FERC requirements. The contractual obligations with TVA extend through August 2011 and with SPP through August 2012.

LG&E and KU and the MISO agreed upon overall calculation methods for the contractual exit fee to be paid by the utilities following their withdrawal. In October 2006, LG&E and KU paid a combined $33 million to the MISO and made related FERC compliance filings. The Utilities’ payments of these exit fees were with reservation of their rights to contest the amount, or components thereof, following a continuing review of the fee’s calculation and supporting documentation. LG&E and KU and the MISOresolved their dispute regarding the calculations of the exit fees and, in November 2007, filed applications with the FERC for approval of recalculation agreements. In March 2008, the FERC approved the parties’ recalculations of the exit fees and the approved agreements providing LG&E and

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KU with recovery of a combined $6 million, of which $2 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 and KU established regulatory assets 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, LG&E and KU established reserves during the fourth quarter of 2008 of a combined $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 receivables were established for amounts already paid of $1 million for LG&E and KU, which the MISO began refunding back to LG&E and KU in June 2009 and which were fully collected by 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. Accruals had previously been recorded in 2008 for the rate mismatch issue for the time period April 25, 2006 to August 9, 2007, but no accruals had been recorded for the time period November 5, 2007 to November 9, 2008 based on the prior Order. Accordingly, the accruals for the former time period were reversed and accruals for the latter time period were recorded in June 2009, with a net effect of $1 million for LG&E and KU, 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

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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.

Pension and Postretirement Benefits

LG&E and KU account 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 Consolidated 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 and KU can defer recoverable costs that would otherwise be charged to expense or equity by non-regulated entities. Current rate recovery in Kentucky and Virginia 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 plans that is expected to be recovered. LG&E has recorded a regulatory asset representing the change in funded status of its postretirement benefit plan that is expected to be recovered and KU has recorded a regulatory liability representing the change in funded status of its postretirement benefit plan. The regulatory asset and liability will be adjusted annually as prior service cost and actuarial gains and losses are recognized in net periodic benefit cost.

Storm Restoration

In January 2009, a significant ice storm passed through LKE’s service areas causing approximately 404,000 customer outages, followed closely by a severe wind storm in February 2009, causing approximately 81,000 customer outages. Applications were filed with the Kentucky Commission in April 2009, requesting approval to establish regulatory assets and defer for future recovery, approximately $107 million in incremental operation and maintenance expenses related to the storm restoration. In September 2009, the Kentucky Commission issued Orders allowing the establishment of regulatory assets of up to $107 million based on actual costs for storm damages and service restoration due to the January and February 2009 storms. In September 2009, regulatory assets of $101 million were

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established for actual costs incurred and approval was received in LG&E’s and KU’s 2010 base rate cases to recover these assets 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, applications were filed with the Kentucky Commission requesting approval to establish regulatory assets and defer for future recovery, approximately $27 million of expenses related to the storm restoration. In December 2008, the Kentucky Commission issued an Order allowing the establishment of regulatory assets of up to $27 million, based on actual costs for storm damages and service restoration due to Hurricane Ike. In December 2008, regulatory assets of $26 million were established for actual costs incurred and LG&E and KU received approval in their 2010 base rate cases to recover these assets over a ten year period, beginning August 1, 2010.

Interest Rate Swaps

LG&E’s 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.

Unamortized Loss on Bonds

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.

CMRG and KCCS Contributions

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 and KU received approval from the Kentucky Commission in the Utilities’ 2010 Kentucky base rate case to recover these regulatory assets over the requested period beginning August 1, 2010.

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Rate Case Expenses

LG&E and KU incurred $1 million each in expenses related to the development and support of the 2008 Kentucky base rate cases. 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 and KU incurred $1 million and $2 million, respectively, in expenses related to the development and support of the 2010 Kentucky base rate cases. The Kentucky Commission approved the establishment of a regulatory asset for these expenses and authorized amortization over three years beginning in August 2010.

FERC Jurisdictional Pension Costs

Other regulatory assets include pension costs of $5 million incurred by KU and allocated to its FERC jurisdictional ratepayers. KU will seek recovery of this asset in the next FERC rate proceeding.

Deferred Storm Costs

Based on an Order from the Kentucky Commission in June 2004, KU reclassified from maintenance expense to a regulatory asset $4 million related to costs not reimbursed from the 2003 ice storm. These costs were amortized through June 2009. KU earned a return of these amortized costs, which were included in jurisdictional operating expenses.

DSM

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. The rates of LG&E and KU 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 and KU 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.

Emission Allowances

In November 2010, purchase accounting adjustments were recorded for the fair market value of LG&E’s and KU’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 and KU are granted SO2 emission allowances through 2040 and NOx ozone season and NOx annual emission allowances through 2011.

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Accumulated Cost of Removal of Utility Plant

As of December 31, 2010 and 2009, the Utilities segregated the cost of removal, previously embedded in accumulated depreciation, of $623 million and $594 million, respectively, in accordance with FERC Order No. 631. For reporting purposes on the Consolidated Balance Sheets, the Utilities presented this cost of removal as a “Regulatory liability” pursuant to the regulated operations guidance of the FASB ASC.

OVEC Power Purchase Contract

In November 2010, purchase accounting adjustments were recorded for the fair value of the power purchase agreement between the Utilities and OVEC. Offsetting regulatory liabilities for fair value purchase accounting adjustments eliminate any ratemaking impact of the fair value adjustments.

Deferred Income Taxes — Net

These regulatory liabilities represent the future revenue impact from the reversal of deferred income taxes required for unamortized investment tax credits, the allowance for funds used during construction and deferred taxes provided at rates in excess of currently enacted rates.

Other Regulatory Matters

Kentucky Commission Report on Storms

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, LG&E and KU 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.

Wind Power Agreements

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

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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 LG&E and KU to withdraw their pending application.

Trimble County Asset Purchase and Depreciation

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, the Utilities 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.

TC2 CCN Application and Transmission Matters

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. 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, 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.

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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.

Utility Competition in Virginia

The Commonwealth of Virginia passed the Virginia Electric Utility Restructuring Act in 1999. This act gave customers the ability to choose their electric supplier and capped electric rates through December 2010. KU subsequently received a legislative exemption from the customer choice requirements of this law. In April 2007, however, the Virginia General Assembly amended the Virginia Electric Utility Restructuring Act, thereby terminating this competitive market and commencing re-regulation of utility rates. The new act ended the cap on rates at the end of 2008. Pursuant to this legislation, the Virginia Commission adopted regulations revising the rules governing utility rate increase applications. As of January 2009, a hybrid model of regulation is being applied in Virginia. Under this model, utility rates are reviewed every two years. KU’s exemption from the requirements of the Virginia Electric Utility Restructuring Act in 1999, however, discharges KU from the requirements of the new hybrid model of regulation. In lieu of submitting an annual information filing, KU has the option of requesting a change in base rates to recover prudently incurred costs by filing a traditional base rate case. KU is also subject to other utility regulations in Virginia, including, but not limited to, the recovery of prudently incurred fuel costs through an annual fuel factor charge and the submission of integrated resource plans.

Arena

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

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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.

Market-Based Rate Authority

In July 2006, the FERC issued an Order in LG&E’s and KU’s market-based rate proceedings accepting their further proposal to address certain market power issues the FERC claimed would arise upon an exit from the MISO. In particular, LG&E and KU 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 and KU of power at market-based rates in the LG&E and KU and Big Rivers 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 LG&E’s and KU’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 and KU must comply with applicable affiliate restrictions set forth in the FERC regulation. During September 2008, LG&E and KU 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 LG&E’s and KU’s September 2008 application for market-based rate authority. During July 2009, affiliates of LG&E and KU completed a transaction terminating certain prior generation and power marketing activities in the Big Rivers balancing area, which termination should ultimately allow a filing to request a determination that LG&E and KU no longer are deemed to have market power in such balancing area.

LG&E and KU conduct certain of their 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. LG&E’s and KU’s sales under market-based rate authority totaled $21 million and less than $1 million, respectively, for the year ended December 31, 2010.

Mandatory Reliability Standards

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. LG&E and KU are members of the SERC, which acts as LG&E’s and KU’s RRO. During December 2009 and April, July and August 2010, LG&E and KU submitted ten self-reports relating to various standards, which self-reports remain

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in the early stages of RRO review and therefore, LG&E and KU 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 SERC proceed to NERC and the FERC review before becoming final. While LG&E and KU believe they are in compliance with the mandatory reliability standards, events of potential non-compliance may be identified from time-to-time. LG&E and KU cannot predict such potential violations or the outcome of self-reports described above.

Natural Gas Customer Choice Study

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 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.

Integrated Resource Planning

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. Pursuant to the Virginia Commission’s December 2008 Order, KU filed its IRP in July 2009. The filing consisted of the 2008 Joint IRP filed by LG&E and KU with the Kentucky Commission along with additional data. The Virginia Commission has not established a procedural schedule for this proceeding. The Utilities expect to file their next IRP in April 2011.

PUHCA 2005

PPL, LG&E’s and KU’s ultimate parent, is a holding company under PUHCA 2005. PPL, its utility subsidiaries, including LG&E and KU, 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. PPL, LG&E and KU believe they have adequate authority, including financing authority, under existing FERC Orders and regulations to conduct their business and will seek additional authorization when necessary.

EPAct 2005

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 totransmission, pollution control and renewable generation assets; increasing funding for clean coal

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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 and KU developed real-time pricing pilot programs 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 within approximately eight months. 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 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.

Hydro Upgrade

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.

Green Energy Riders

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 and KU 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 application, as filed.

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Home Energy Assistance Program

In July 2007, LG&E and KU filed applications with the Kentucky Commission for the establishment of a Home Energy Assistance program. During September 2007, the Kentucky Commission approved the five-year programs as filed, effective in October 2007. The programs were scheduled to terminate in September 2012 and are 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 programs are 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 programs were extended to September 2015.

Collection Cycle Revision

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 agreement approved in the rate case in February 2009 changed the due date for customer bill payments to 12 days after bill issuance for both LG&E and KU and permitted KU’s implementation of a late payment charge if payment is not received within 15 days from the bill issuance date.

Depreciation Study

In December 2007, LG&E and KU filed depreciation studies with the Kentucky Commission as required by previous Orders. In August 2008, the Kentucky Commission issued Orders consolidating the depreciation studies with the base rate case proceedings. The approved settlement agreements in the rate cases established new depreciation rates effective February 2009. KU also filed the depreciation study with the Virginia Commission which approved the implementation of the new depreciation rates effective February 2009. Approval by the Virginia Commission does not preclude the rates from being raised as an issue by any party in KU’s future base rate cases in Virginia.

Brownfield Development Rider Tariff

In March 2008, LG&E and KU 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.

Interconnection and Net Metering Guidelines

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 and KU do not expect any

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financial or other impact as a result of this Order. In April 2009, LG&E and KU 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 and KU. Following this conference, the intervenors and LG&E and KU resolved all issues and LG&E and KU filed revised net metering tariffs with the Kentucky Commission. In August 2009, the Kentucky Commission issued an Order approving the revised tariffs.

EISA 2007 Standards

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.

Note 4 - Asset Retirement Obligations

A summary of the Company’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			ARO			Regulatory
	Assets			Liabilities			Assets
As of December 31, 2008, Predecessor	$	9		$	(63	)	$	57
ARO accretion and depreciation	(2		)	(4		)	5
ARO settlements	—			1			(2		)
Removal cost incurred	—			1			—
As of December 31, 2009, Predecessor	7			(65		)	60
ARO accretion and depreciation	—			(4		)	4
Reclassification for retired assets	(2		)	—			2
ARO revaluation - change in estimates	51			(54		)	3
Removal cost incurred	—			1			—
As of October 31, 2010, Predecessor	56			(122		)	69
ARO accretion and depreciation	(2		)	—			2
Purchase accounting - fair value adjustment	43			19			(62		)
As of December 31, 2010, Successor	$	97		$	(103	)	$	9

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As of September 30, 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 Consolidated Statements of Income for the Successor of $2 million in 2010 and $4 million for the Predecessor for the ARO accretion and depreciation expense. The offsetting regulatory credit recorded was $4 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.

LKE’s AROs are primarily related to the final retirement of assets associated with generating units and natural gas mains and wells. LKE 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.

Note 5 - Derivative Financial Instruments

The Company 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 December 31, 2010, LKE’s potential annual exposure to increased interest expense, based on a 10% increase in interest rates, was less than $1 million.

The Company does not net collateral against derivative instruments.

Interest Rate Swaps

LKE uses over-the-counter interest rate swaps to limit exposure to market fluctuations in interest expense. Pursuant to Company policy, use of these financial instruments is intended to mitigate risk, earnings and cash flow volatility and is not speculative in nature.

LKE’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, LKE 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.

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The fair value of the interest rate swaps is determined by a quote from the counterparty. This value is verified monthly by LKE 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 LKE. LKE considered the impact of its own credit risk and that of counterparties by evaluating credit ratings and financial information, adjusting market valuations to reflect such credit risks. LKE and all counterparties had strong investment grade ratings at December 31, 2010. In addition, LKE 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 asset” in the accompanying Consolidated Balance Sheets.

The table below shows the fair value and balance sheet location of interest rate swap derivatives:

	Fair Value
	Successor		Predecessor
Balance Sheet Location	December 31, 2010		December 31, 2009
Current derivative liability	$	2	$	—
Long-term derivative liability	32		28
	$	34	$	28

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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, LKE 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
Gain (Loss) Recognized		November 1, 2010 through		January 1, 2010 through			Year Ended December 31,
in Income	Location	December 31, 2010		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 loss on terminated swap	Derivative gain (loss)	—		9			—			—
Realized gain (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 LKE’s interest rate swaps by $28 million.

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Energy Trading and Risk Management Activities

The Company 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:

Non-Hedging Derivatives:

	Fair Value
	Successor		Predecessor
Balance Sheet Location	December 31, 2010		December 31, 2009
Asset derivative
Prepayments and other current assets (a)	$	—	$	2
Liability derivative
Other current liabilities	$	2	$	2

(a)The amount recorded in prepayments and other current assets totals less than $1 million

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.

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, the Company seeks to enter into netting agreements or require cash deposits, letters of credit and parental company guarantees as security from counterparties. The Company uses 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, the Company 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 December 31, 2010 100% of the trading and risk management commitments were with counterparties rated BBB-/Baa3 equivalent or better. The Company has

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reserved against counterparty credit risk based on LKE’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 998,300 Mwh and 631,200 Mwh, respectively. Cash collateral related to the energy trading and risk management contracts at December 31, 2010 and December 31, 2009 was $3 million and $2 million, respectively. Cash collateral related to the energy trading and risk management contracts is recorded in “Prepayments and other current assets” on the Consolidated Balance Sheets.

The Company 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 in the Consolidated Statements of Income.

The following table presents the effect of market-traded forward contract derivatives not designated as hedging instruments on income:

		Successor			Predecessor
Gain (Loss) Recognized in		November 1, 2010 through			January 1, 2010 through		Year Ended December 31,
Income	Location	December 31, 2010			October 31, 2010		2009			2008
Realized gain	Electric revenues	$	—		$	3	$	11		$	4
Unrealized gain (loss)	Electric revenues	(2		)	—		(2		)	2
		$	(2	)	$	3	$	9		$	6

Credit Risk Related Contingent Features

Certain of LKE’s derivative contracts contain credit contingent provisions which would permit the counterparties with which LKE is in a net liability position to require the transfer of additional collateral upon a decrease in LKE’s credit rating. Some of these provisions would require LKE to transfer additional collateral or permit the counterparty to terminate the contract if LKE’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 LKE’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 LKE on derivative instruments in net liability positions.

Additionally, certain of LKE’s derivative contracts contain credit contingent provisions that require LKE to provide “adequate assurance” of performance if the other party has reasonable grounds for insecurity regarding LKE’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

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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, LKE 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 LKE 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, LKE would have been required to post an additional $6 million of collateral to its counterparties.

See Note 6, Fair Value Measurements, Note 13, Commitments and Contingencies and Note 19, Discontinued Operations, for a discussion of the WKE sales contract.

Note 6 - Fair Value Measurements

The Company 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 the Company’s non-trading financial instruments as of December 31, 2010 and December 31, 2009, follow:

	Successor				Predecessor
	December 31, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Long-term bonds	$	3,825	$	3,607	$	764	$	764
Long-term debt to affiliated company	—		—		3,421		3,553
Derivative liabilities — interest rate swaps	32		32		28		28
Derivative liabilities — smelter contract	—		—		75		75

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 companies 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 the Company’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

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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, cash surrender value of key man life insurance, accounts payable and notes payable are substantially the same as their carrying values.

The Company 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 Company classified its liability for the E.ON share performance plan within level 2 because it is valued using a model that considers the quoted market price of E.ON’s common shares traded on the Frankfurt Stock Exchange as well as the performance of E.ON stock compared to the change in the Dow Jones STOXX Utilities Index (Total Return EUR). See Note 5, Derivative Financial Instruments, for further information. See Note 20, Share Performance Plan, for discussion of the PPL stock based compensation plan.

Prior to its termination in 2009, the Company classified its liability for WKE’s long-term sales contracts within level 3. The contracts were with an electric cooperative and two aluminum smelters. The valuation was calculated on a monthly basis using market prices from Platts’ (provider of daily price assessments used as benchmarks in both physical and futures markets) on-line pricing service for the current and forward four years and a forecast for the outer years where market prices are not available. The outer year pricing was extrapolated from an annual forecast from the Energy Information Administration for NGHH pricing based on historical ratios of around-the-clock electricity prices to NGHH prices.

After the termination of WKE’s lease with Big Rivers, the Company had an obligation through the end of 2010 to pay one of the aluminum smelters it had previously served the difference between the electricity prices charged by WKE under the previous long-term sales contract and the electricity prices charged by its current electricity supplier. The valuation was calculated on a quarterly basis using monthly Northern East Central Area Reliability Cinergy Hub forward prices by peak-type. As of December 31, 2010, the swap was terminated. See Note 13, Commitments and Contingencies and Note 19, Discontinued Operations, for further information.

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The following tables set forth, by level within the fair value hierarchy, the Company’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	$	11	$	—	$	—	$	11
Short-term investments - municipal debt securities	163		—		—		163
Restricted cash:
Energy trading and risk management contract cash collateral	3		—		—		3
Interest rate swaps cash collateral	19		—		—		19
Total financial assets	$	196	$	—	$	—	$	196
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
Smelter contract	—		—		75		75
E.ON share performance plan	—		2		—		2
Total financial liabilities	$	—	$	32	$	75	$	107

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The following table presents the changes in net liabilities measured at fair value using significant unobservable inputs (level 3) as defined in FASB ASC for the following periods:

	Successor			Predecessor
	November 1, 2010 through			January 1, 2010 through			Year Ended December 31,
	December 31, 2010			October 31, 2010			2009			2008
Balance at beginning of period	$	24		$	75		$	908		$	832
Realized losses included in earnings	—			6			5			—
Unrealized losses included in earnings	—			2			108			581
Unrealized gains included in earnings	(3		)	(5		)	(1,026		)	(505		)
Issuances	—			—			106			—
Settlements	(21		)	(54		)	(26		)	—
Balance at end of period	$	—		$	24		$	75		$	908

See Note 2, Acquisition by PPL, for discussion of fair value of other assets and liabilities for purchase accounting.

Note 7 - Goodwill and Intangible Assets

In connection with PPL’s acquisition of LKE, the carrying value of LKE’s goodwill as of October 31, 2010, was eliminated and new goodwill was recorded on November 1, 2010, as a result of the acquisition. 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.

Goodwill

Goodwill is attributable to the Company’s regulated utilities, LG&E and KU as these are the two operating companies and constitute substantially all of LKE’s assets. The following table sets forth the carrying amount of goodwill as of and for the two years ended December 31, 2010.

				Accumulated
	Cost			Impairment			Net
Goodwill, January 1, 2009	$	4,136		$	(1,806	)	$	2,330
Impairment loss	—			(1,493		)	(1,493		)
Balance at December 31, 2009 and October 31, 2010	4,136			(3,299		)	837
Disposition of goodwill, November 1, 2010 (a)	(4,136		)	3,299			(837		)
Purchase accounting adjustments (b)	996			—			996
Balance at December 31, 2010	$	996		$	—		$	996

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(a)Predecessor goodwill as of October 31, 2010 was eliminated as of November 1, 2010, in purchase accounting.

(b)Recognized as a result of the Company’s acquisition by PPL on November 1, 2010. Represents the purchase accounting allocation process established as of November 1, 2010, in conjunction with PPL’s acquisition of LKE. 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 regulated utilities’ 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, the carrying value of LKE’s goodwill as of October 31, 2010, was eliminated. New goodwill was recorded on November 1, 2010 on LG&E and KU for $389 million and $607 million, respectively. The allocation of the goodwill was based on the net asset value of each 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 investment, future earnings and cash flow growth, as well as the talented and experienced workforce. LG&E’s and KU’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.

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 the Utilities, 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 and KU 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 each of LG&E and KU. No impairment resulted from the fourth quarter test, as the determined fair value of the Utilities was greater than its carrying value.

For the 2009 annual impairment test, the estimated fair value of the Utilities was based on a combination of the income approach, which estimates the fair value of the reporting unit based on discounted future cash flows and the market approach, which estimates the fair value of the reporting unit based on market comparables. The discounted cash flows for LG&E and KU were based on discrete financial forecasts developed by management for planning purposes and consistent with those given to E.ON. Cash flows beyond the discrete forecasts were estimated using a terminal-value calculation, which incorporated historical and forecasted financial trends for each of LG&E and KU and considered long-term earnings

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growth rates for publicly-traded peer companies. The level 3 income-approach valuations included a cash flow discount rate of 6.3% and a terminal-value growth rate of 1.1%. In addition, subsequent to 2009 but prior to the issuance of the 2009 financial statements, discussions were held with interested parties for the possible sale of the Company, including the regulated utilities. Data from this process was used for evaluating the carrying value of goodwill as of December 31, 2009.

Based on information represented by bids received from interested parties, including PPL, the Company completed a goodwill impairment analysis as of December 31, 2009. Step 1 of the impairment test indicated a possible impairment, so the Company completed step 2. The implied fair value of goodwill in the step 2 calculation was determined in the same manner utilized to estimate the amount of goodwill recognized in a business combination. The Company concluded that the fair values of LG&E and KU assets and liabilities equaled their book values, due to the regulatory environment in which they operate. The Kentucky and Virginia Commissions allow LG&E and KU to earn returns on the book values of their regulated asset bases at rates the Commissions determine to be fair and reasonable. Since there is no current prospect for deregulation, the Company assumed LG&E and KU will remain in a regulated environment for the foreseeable future. As a result of the impairment analysis described above, the Company recorded a 2009 goodwill impairment charge of $1.493 billion.

The primary factors contributing to the goodwill impairment charges in 2009 were the significant economic downturn, which caused a decline in the volume of projected sales of electricity to commercial customers and an increase in the implied discount rate due to higher risk premiums. In addition, a lower control premium was assumed, based on observable market data.

Other Intangible Assets

The gross carrying amount and the accumulated amortization of other intangible assets were as follows:

	Successor
	December 31, 2010
	Gross Carrying Amount		Accumulated Amortization
Subject to amortization:
Coal contracts (a)	$	269	$	9
Land rights (b)	14		—
Emission allowances (c)	18		2
OVEC power purchase agreement (d)	126		2
Total intangible assets	$	427	$	13

(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 3 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 14 years. See Note 1, Summary of Significant Accounting Policies, for further information.

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(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 3 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 Consolidated Balance Sheets in 2010. Intangible assets resulting from purchase accounting adjustments are not recoverable in rates.

Amortization expense, excluding consumption of emission allowances, was $11 million for the Successor in 2010. The estimated aggregate amortization expense for each of the next five years is as follows:

	Estimated Expense in Period Ended
	2011		2012		2013		2014		2015
Aggregate amortization expense	$	88	$	48	$	52	$	47	$	50

Note 8 - Concentrations of Credit and Other Risk

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. All of KU’s customer receivables arise from deliveries of electricity. During 2010, LG&E’s ten 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. During 2010, KU’s ten largest customers accounted for less than 19% of volumes.

Effective November 2008, LG&E and its employees represented by the IBEW Local 2100 signed 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 LG&E’s workforce at December 31, 2010.

Effective August 4, 2009, KU and its employees represented by the IBEW Local 2100 entered into a three-year collective bargaining agreement. The agreement provides for negotiated increases or changes to wages, benefits or other provisions and for annual wage re-openers. KU and its employees represented by the USWA Local 9447-01 entered into a three-year collective bargaining agreement in August 2008. This agreement provides for negotiated increases or changes to wages, benefits or other

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provisions and for annual wage re-openers. The employees represented by these two bargaining units comprise approximately 15% of KU’s workforce at December 31, 2010.

Note 9 - Pension and Other Postretirement Benefit Plans

LKE 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.

Obligations and Funded Status

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 plans 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:

	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	$	1,230		$	1,085		$	1,013		$	206		$	199		$	185
WKE’s obligation previously in discontinued operations	—			—			33			—			—			7
Service cost	4			17			22			1			3			4
Interest cost	11			54			63			1			9			11
Plan amendments	—			—			—			—			—			1
Curtailment gain or (loss)	—			—			1			—			—			(3		)
Settlement loss	—			—			2			—			—			—
Benefits paid, net of retiree contributions	(8		)	(42		)	(62		)	(2		)	(9		)	(12		)
Actuarial (gain) loss and other	(8		)	116			13			(2		)	4			6
Benefit obligation at end of period	$	1,229		$	1,230		$	1,085		$	204		$	206		$	199

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	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	$	764		$	696		$	577		$	42		$	37		$	24
WKE’s fair value of plan assets previously in discontinued operations	—			—			21			—			—			1
Actual return on plan assets	22			65			126			1			3			5
Employer contributions	—			46			35			8			11			19
Benefits paid, net of retiree contributions	(8		)	(42		)	(62		)	(2		)	(9		)	(12		)
Administrative expenses and other	—			(1		)	(1		)	—			—			—
Fair value of plan assets at end of period	$	778		$	764		$	696		$	49		$	42		$	37
Funded status at end of period	$	(451	)	$	(466	)	$	(389	)	$	(155	)	$	(164	)	$	(162	)

Amounts Recognized in the Consolidated Balance Sheets

The following tables provide the amounts recognized in the Consolidated 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:

	Pension Benefits									Other Postretirement Benefits
	Successor			Predecessor						Successor			Predecessor
	2010			2010			2009			2010			2010			2009
Regulatory assets	$	314		$	334		$	293		$	16		$	17		$	16
Regulatory liabilities	—			—			—			(10		)	(9		)	(9		)
Accrued benefit liability (current)	(2		)	(3		)	(7		)	(1		)	(1		)	(4		)
Accrued benefit liability (non-current)	(449		)	(463		)	(382		)	(154		)	(163		)	(158		)

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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:

	Pension Benefits						Other Postretirement Benefits
	Successor		Predecessor				Successor			Predecessor
	2010		2010		2009		2010			2010			2009
Transition obligation	$	—	$	—	$	—	$	3		$	4		$	5
Prior service cost	30		32		37		6			6			8
Accumulated loss (gain)	284		302		256		(3		)	(2		)	(6		)
Total regulatory assets	$	314	$	334	$	293	$	6		$	8		$	7

Amounts recognized in accumulated other comprehensive income 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:

	Pension Benefits								Other Postretirement Benefits
	Successor		Predecessor						Successor		Predecessor
	2010		2010			2009			2010		2010			2009
Prior service (cost)	$	—	$	(18	)	$	(21	)	$	—	$	(1	)	$	1
Accumulated gain (loss)	8		(94		)	(59		)	1		2			(1		)
Total accumulated other comprehensive income	$	8	$	(112	)	$	(80	)	$	1	$	1		$	—

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:

	Pension Benefits						Other Postretirement Benefits
	Successor		Predecessor				Successor		Predecessor
	2010		2010		2009		2010		2010		2009
Benefit obligation	$	1,229	$	1,230	$	1,085	$	204	$	206	$	199
Accumulated benefit obligation	1,043		1,039		919		—		—		—
Fair value of plan assets	778		764		696		49		42		37

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The 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:

	Pension Benefits									Other Postretirement Benefits
	Successor			Predecessor						Successor			Predecessor
	2010			2010			2009			2010			2010			2009
Net (gain) loss arising during the period	$	(14	)	$	59		$	(49	)	$	(1	)	$	4		$	3
Amortization of prior service (cost)	(1		)	(5		)	(7		)	—			(1		)	(2		)
Amortization of transitional obligation	—			—			—			—			(2		)	(2		)
Amortization of (loss) gain	(5		)	(13		)	(21		)	—			—			1
Total amounts recognized in regulatory assets and liabilities	$	(20	)	$	41		$	(77	)	$	(1	)	$	1		$	—

The amounts recognized in accumulated other comprehensive income 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:

	Pension Benefits									Other Postretirement Benefits
	Successor			Predecessor						Successor			Predecessor
	2010			2010			2009			2010			2010			2009
Prior service cost recognized due to curtailment	$	—		$	—		$	(2	)	$	—		$	—		$	(1	)
Settlement recognition of net loss	—			—			(2		)	—			—			—
Net (gain) loss arising during period	(8		)	37			(17		)	(1		)	(1		)	(1		)
Amortization of prior service cost	—			(2		)	(2		)	—			—			—
Amortization of loss	—			(3		)	(4		)	—			—			—
Total amounts recognized in accumulated other comprehensive income	$	(8	)	$	32		$	(27	)	$	(1	)	$	(1	)	$	(2	)

For discussion of the pension and postretirement regulatory assets and liabilities, see Note 3, Rates and Regulatory Matters.

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Components of Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost for pension and other postretirement benefit plans 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:

	Pension Benefits						Other Postretirement Benefits
	Successor			Predecessor			Successor		Predecessor
	2010			2010			2010		2010
Service cost	$	4		$	17		$	1	$	3
Interest cost	11			54			1		9
Expected return on plan assets	(9		)	(45		)	—		(2		)
Amortization of prior service costs	1			7					2
Amortization of actuarial loss	5			16			—		—
Amortization of transitional obligation	—			—			—		1
Net periodic benefit cost	$	12		$	49		$	2	$	13

The following tables provide the components of net periodic benefit cost for pension and other postretirement benefit plans for the years ended December 31, 2009 and 2008 for the Predecessor:

	Pension Benefits						Other Postretirement Benefits
	2009			2008			2009			2008
Service cost	$	20		$	19		$	4		$	4
Interest cost	62			60			11			11
Expected return on plan assets	(47		)	(65		)	(2		)	(2		)
Amortization of prior service cost	9			9			3			2
Amortization of actuarial (gain) loss	27			3			(1		)	2
Amortization of transitional obligation	—			—			2			—
Net periodic benefit cost	$	71		$	26		$	17		$	17

The estimated amounts that will be amortized from regulatory assets and liabilities and accumulated other comprehensive income into net periodic benefit cost in 2011 are shown in the following table:

	Pension Benefits		Other Postretirement
Regulatory assets and liabilities:
Net actuarial loss	$	22	$	—
Prior service cost	5		2
Transitional obligation	—		2
Total regulatory assets and liabilities amortized during 2011	$	27	$	4
Accumulated other comprehensive income:
Net actuarial loss	$	—	$	—
Prior service cost	—		—
Total accumulated other comprehensive income amortized during 2011	$	—	$	—

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The weighted average assumptions used in the measurement of the Company’s pension and postretirement benefit obligations are shown in the following table:

	Successor		Predecessor
	2010		2010		2009
Discount rate — LG&E union plan	5.39	%	5.32	%	6.08	%
Discount rate — WKE union plan	5.09	%	5.00	%	5.00	%
Discount rate — nonunion plan	5.52	%	5.46	%	6.13	%
Discount rate — SERP plan	5.11	%	4.96	%	5.79	%
Discount rate — officer SERP plan	5.46	%	5.41	%	6.14	%
Discount rate — restoration plan	5.66	%	5.66	%	6.31	%
Discount rate — postretirement	5.12	%	4.96	%	5.82	%
Rate of compensation increase	5.25	%	5.25	%	5.25	%

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 the Company’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:

	Successor		Predecessor
	2010		2010		2009		2008
Discount rate — pension benefits	5.40	%	6.11	%	6.25	%	6.66	%
Discount rate — postretirement benefits	4.94	%	5.82	%	6.36	%	6.56	%
Expected long-term return on plan assets	7.25	%	7.75	%	8.25	%	8.25	%
Rate of compensation increase	5.25	%	5.25	%	5.25	%	5.25	%

To develop the expected long-term rate of return on assets assumption, the Company 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

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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:

·A 1% change in the assumed discount rate would have a $133 million positive or negative impact to the 2010 accumulated benefit obligation and an approximate $172 million positive or negative impact to the 2010 projected benefit obligation.

·A 25 basis point change in the expected rate of return on assets would have a $2 million positive or negative impact to 2010 pension expense.

·A 25 basis point increase in the rate of compensation increase would have a $11 million negative impact to the 2010 projected benefit obligation.

Assumed Health Care Cost Trend Rates

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 $6 million in year end 2010 postretirement benefit obligations.

Expected Future Benefit Payments and Medicare Subsidy Receipts

The following list provides the amount of expected future benefit payments, which reflect expected future service costs and the estimated gross amount of Medicare subsidy receipts:

	Pension Benefits		Other Postretirement Benefits		Medicare Subsidy Receipts
2011	$	54	$	14	$	1
2012	51		14		—
2013	53		15		1
2014	54		15		—
2015	57		15		1
2016-2020	353		84		3

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Plan Assets

The following table shows the pension plans’ weighted average asset allocation by asset category at December 31:

	Target	Successor		Predecessor
	Range	2010		2009
Equity securities	45%-75%	56	%	59	%
Debt securities	30%-50%	37	%	40	%
Other	0%-10%	7	%	1	%
Total		100	%	100	%

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. 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 of at least three to five years or a complete market cycle. 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

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of short-term, high-quality fixed income securities issued by banks, corporations and the U.S. government.

The Company 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:

Money market funds: These investments are public investment vehicles valued using $1 for the net asset value. The money market funds are classified within level 2 of the valuation hierarchy.

Common/collective trusts: Valued based on the beginning of year value of the plan’s interests in the trust plus actual contributions and allocated investment income (loss) less actual distributions and allocated administrative expenses. Quoted market prices are used to value investments in the trust, with the exception of the GAC. The fair value of certain other investments for which quoted market prices are not available are valued based on yields currently available on comparable securities of issuers with similar credit ratings. The common/collective trusts are classified within level 2 of the valuation hierarchy.

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.

Prior to the acquisition, the GAC was considered an immediate participation guarantee contract which was not included in the fair value table. In accordance with the plan accounting guidance of the FASB ASC, the cost incurred to purchase the GAC prior to March 20, 1992, was permitted to be carried at contract value, since it is a contract with an insurance company and prior to the acquisition it was excluded from the table above. The cost incurred to fund the GAC after March 20, 1992, was carried at contract value in accordance with the plan accounting guidance of the FASB ASC, since it is a contract that incorporates mortality and morbidity risk. Contract value represents cost plus interest income less distributions for benefits and administrative expenses. To conform to PPL’s accounting methods, the John Hancock GAC was classified in the fair value table as a level 3 and as “other” rather than “debt securities” in the asset allocation table for the period ended December 31, 2010.

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The following table sets forth, by level within the fair value hierarchy, the plan’s assets at fair value at December 31:

	Successor						Predecessor
	Total						Total
	2010		Level 2		Level 3		2009		Level 2		Level 3
Money market funds	$	8	$	8	$	—	$	6	$	6	$	—
Common/collective trusts	772		772		—		678		678		—
John Hancock — GAC	47		—		47		—		—		—
Total investments at fair value	$	827	$	780	$	47	$	684	$	684	$	—

The following table sets forth a reconciliation of changes in the fair value of the plan’s level 3 assets for the following period:

	Successor
Balance at November 1, 2010	$	—
Purchases	1
Transfers into level 3	46
Balance at December 31, 2010	$	47

There are no assets categorized as level 1 as of December 31, 2010 and December 31, 2009.

Contributions

The Company made discretionary contributions to its pension plans of $45 million in 2010 and $33 million in 2009. Total contributions were $46 million in 2010 and $35 million in 2009. 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. The Company made contributions totaling $150 million in January 2011. See Note 21, Subsequent Events, for further information.

The Company made contributions to its other postretirement benefit plan totaling $19 million in 2010 and 2009. In 2011, the Company plans on making voluntary contributions to fund VEBA trusts to match the annual postretirement expense and funding the 401(h) plan up to the maximum amount allowed by law.

Pension Legislation

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.

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Thrift Savings Plans

The Company has thrift savings plans under section 401(k) of the Internal Revenue Code. Under these plans, eligible employees may defer and contribute to the plans a portion of current compensation in order to provide future retirement benefits. The Company makes contributions to the plans by matching a portion of the employees’ contributions. The costs of this matching were approximately $9 million and $10 million for 2010 and 2009, respectively.

The Company also makes contributions to RIAs within its 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 $1 million in 2010 and 2009.

Health Care Reform

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.

During 2010, KU recorded an income tax expense of less than $1 million to recognize the impact of the elimination of the tax deduction related to the Medicare Retiree Drug Subsidy that becomes effective in 2013.

Specific provisions within Health Care Reform that may impact the Company include:

·Beginning in 2011, requirements extend dependent coverage up to age 26, remove the $2 million lifetime maximum and eliminate cost sharing for certain preventative care procedures.

·Beginning in 2018, a potential excise tax is expected on high-cost plans providing health coverage that exceeds certain thresholds.

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 plan. 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.

Note 10 - Income Taxes

LKE’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

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consolidated tax group 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 $25 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.

The following table shows additions and reductions of unrecognized tax benefits for the twelve months ended December 31:

	Successor			Predecessor
	2010			2009
Balance at beginning of year	$	1		$	8
Additions based on tax positions related to current year	3			—
Reductions due to expiration of statute of limitations	(1		)	(7		)
Balance at end of year	$	3		$	1

No uncertain tax positions are scheduled to decrease within the next twelve months.

The amount LKE 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. LKE records the interest as “Interest expense” and penalties, if any, as “Operating expenses” on the Consolidated Statements of Income and “Other current liabilities” on the Consolidated Balance Sheets, on a pre-tax basis. No penalties have been accrued by the Company through December 31, 2010.

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Components of income tax expense are shown in the table below:

	Successor			Predecessor
	November 1, 2010  through			January 1, 2010  through			Year Ended December 31,
	December 31, 2010			October 31, 2010			2009			2008
Current	$	(27	)	$	44		$	39		$	96
Deferred	52			67			46			(14		)
Amortization of investment tax credits	—			(2		)	(3		)	(4		)
Total income tax expense	$	25		$	109		$	82		$	78

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 investment tax credits 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 credits. A final IRS certification required to obtain the investment tax credits was received in August 2007. In September 2007, LG&E and KU received an Order from the Kentucky Commission approving the accounting of the investment tax credits, which includes a full depreciation basis adjustment for the amount of the credits. The LG&E and KU portion of the TC2 tax credits is $125 million. Based on eligible construction expenditures incurred, the Company recorded investment tax credits of $25 million and $33 million in 2009 and 2008, respectively. As of December 31, 2009, the Company had recorded its maximum credits of $125 million. The income tax expense impact from amortizing these credits 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.

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Components of deferred income taxes included in the Consolidated Balance Sheets are shown below:

	Successor			Predecessor
	December 31, 2010			December 31, 2009
Deferred income tax liabilities:
Depreciation and other plant-related items	$	789		$	694
Regulatory assets and other	166			—
Accruals and other assets	57			72
Investments and other financial assets	12			14
Total deferred income tax liabilities	1,024			780
Deferred income tax assets:
Net operating loss carryforward	319			371
Advanced coal and other tax credits	169			156
Regulatory liabilities and other	166			—
Pensions and similar obligations	69			93
Federal and state capital loss carryforward	60			7
Accruals and other liabilities	28			38
Income taxes due to customers	30			28
Investment tax credit	10			10
Investments and other financial assets	5			7
	856			710
Valuation allowance	(6		)	(7		)
Total deferred income tax assets	850			703
Net deferred income tax liabilities	$	174		$	77
Balance sheet classification:
Deferred income taxes — net (current)	$	(66	)	$	(10	)
Deferred income taxes (non-current)	240			87
Net deferred income tax liabilities	$	174		$	77

Based on the Company’s net deferred income tax liability position and the realization period for net operating loss carryforwards, the Company expects to have adequate levels of taxable income to realize its deferred income tax assets associated with the net operating losses. The net operating loss carryforwards start to expire in 2028. Alternative minimum tax credits of $20 million do not expire, wind credits of $11 million start to expire in 2016, investment tax credits of $125 million start to expire in 2025 and other general business credits of $13 million start to expire in 2018.

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In January 2010, the Company completed the sale of its Centro and Cuyana natural gas distribution interests resulting in a $106 million estimated capital loss. This and other remaining federal capital losses are expected to be realized within the carry forward period. Federal valuation reserves related to these losses were reversed as part of the purchase accounting valuation. Valuation reserves remain for state capital loss tax benefits.

The Company incurred losses in connection with the termination of the WKE lease. As a result, federal tax loss carryforwards were $280 million and $336 million as of December 31, 2010 and 2009, respectively, and state tax net operating loss carryforwards were $39 million and $35 million as of December 31, 2010 and 2009, respectively.

A reconciliation of differences between the income tax expense at the statutory U.S. federal income tax rate and the Company’s actual income tax expense follows:

	Successor			Predecessor
	November 1, 2010  through			January 1, 2010  through			Year Ended December 31,
	December 31, 2010			October 31, 2010			2009			2008
Statutory federal income tax expense	$	25		$	105		$	(432	)	$	(538	)
State income taxes — net of federal benefit	2			9			7			3
Equity investments	—			—			(3		)	(8		)
Reduction of income tax reserve	—			—			(4		)	(3		)
Investment and other tax credits	(1		)	(2		)	(3		)	(4		)
Reversal of excess deferred taxes	(1		)	(2		)	(3		)	(2		)
Goodwill impairment	—			—			523			632
Other differences — net	—			(1		)	(3		)	(2		)
Income tax expense	$	25		$	109		$	82		$	78
Effective income tax rate	35.7		%	36.3		%	(6.6		)%	(5.1		)%

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. LKE benefited from these new provisions by reducing its 2010 current federal income tax expense. This reduction in federal taxable income for LKE does, however, result in a reduction of LKE’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, LKE 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.

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Note 11 - Long-Term Debt

As summarized below, at December 31, 2010, long-term debt consists of first mortgage bonds, secured pollution control bonds, senior notes and a medium-term note. At December 31, 2009, long-term debt and the current portion of long-term debt consisted primarily of pollution control bonds, long-term loans from affiliated companies and a medium-term note. Utility debt issuance expense is capitalized in regulatory assets and amortized over the lives of the related bond issues for LG&E and KU consistent with regulatory practices. Non-utility issuance expense is amortized using the straight line method. Provided below is a summary of the long-term debt as of December 31:

	Successor			Predecessor
	2010			2009
Current portion of long-term debt - medium term note	$	2		$	—
Long-term debt - medium term note	—			2
Current portion of long-term debt to affiliates	—			358
Long-term debt to affiliated companies	—			3,063
Unsecured senior notes payable	875			—
Secured first mortgage bonds, net of debt discount and amortization of debt discount	2,035			—
Pollution control revenue bonds, collateralized by first mortgage bonds	925			762
Fair value adjustment from purchase accounting	8			—
Unamortized discount	(20		)	—
Total long-term debt	3,825			4,185
Less current portion	2			706
Long-term debt, excluding current portion	$	3,823		$	3,479

	Stated Interest Rates	Maturities	Debt Amounts
Successor
Outstanding at December 31, 2010:
Current portion	7.471%	2011	$	2
Non-current portion	Variable – 6.00%	2015-2040	3,823
Predecessor
Outstanding at December 31, 2009:
Current portion	Variable - 7.01%	2010-2034	$	706
Non-current portion	Variable - 7.78%	2011-2037	3,479

As of December 31, 2009, long-term debt for LKE includes $348 million 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; Trimble County 2001 Series A and B; Carroll County 2002 Series A and B, 2004 Series A, 2006 Series B and 2008 Series A; Muhlenberg County 2002 Series A; and Mercer County 2000 Series A and 2002 Series A. Maturity dates for these bonds range from 2023 to 2034. As of December 31, 2009, the bonds were classified as current portion of long-term debt because investors could put the

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bonds back to the Company within a 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 or KU, issued in connection with tax-exempt pollution control bonds by various counties in Kentucky. A loan agreement obligates LG&E or KU, as the case may be, 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 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, each of LG&E and KU issued first mortgage bonds to the pollution control bond trustees. The 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 or KU, as the case may be, 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 LKE’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, LKE had an aggregate $925 million of outstanding pollution control indebtedness, of which $231 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 average annualized interest rates on the auction rate bonds follow:

	Successor		Predecessor
	November 1, 2010 through December 31, 2010		January 1, 2010 through October 31, 2010		December 31, 2009
LG&E	0.47	%	0.43	%	0.38	%
KU	0.53	%	0.51	%	0.44	%

The instruments governing these auction rate bonds permit LKE 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.

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As of December 31, 2010, LKE continued to hold repurchased bonds in the amount of $163 million. As of December 31, 2009, the repurchased bonds were reported net (excluded from long-term debt). As of December 31, 2010, the accounting treatment changed and the repurchased bonds were reported gross (included in long-term debt). See Note 1, Summary of Significant Accounting Policies, for changes in classification. See Note 18, Available for Sale Debt Securities, and Note 21, Subsequent Events, 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 LG&E’s or KU’s rating, the debt ratings of LG&E’s or KU’s insured pollution control bonds are all based on LG&E’s or KU’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, LKE 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, LKE borrowed approximately $968 million from a PPL subsidiary and received an equity contribution from PPL of $1.5 billion in order to repay loans from subsidiaries of E.ON. LG&E and KU borrowed $485 million and $1,331 million, respectively, from a PPL subsidiary, in order to repay loans from a subsidiary of E.ON.

In November 2010, LG&E and KU issued first mortgage bonds totaling $2,035 million and used the proceeds to repay the loans from a PPL subsidiary mentioned above and for general corporate purposes. Also in November 2010, LKE issued senior notes totaling $875 million and used the proceeds to repay loans from a PPL subsidiary and to return $100 million of capital to PPL. The first mortgage bonds and senior notes were issued to the initial purchasers at a discount as described in the table below:

LG&E First Mortgage Bonds	Principal		Discount Price		First Mortgage  Bonds Proceeds (a)
Series due 2015	$	250	99.647	%	$	249
Series due 2040	285		98.912	%	282
Total	$	535			$	531

KU First Mortgage Bonds	Principal		Discount Price		First Mortgage  Bonds Proceeds (a)
Series due 2015	$	250	99.650	%	$	249
Series due 2020	500		99.622	%	498
Series due 2040	$	750	98.915	%	$	742
Total	1,500				1,489

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LKE First Mortgage Bonds	Principal		Discount Price		First Mortgage  Bonds Proceeds (a)
Series due 2015	$	400	99.557	%	$	398
Series due 2020	475		99.217	%	471
Total	$	875			$	869

(a)Before expenses other than discount to purchaser

The first mortgage bonds and senior notes were issued by the respective issuer in accordance with the rules in Section 144A of the Securities Act of 1933. Each issuer 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, or senior notes, as the case may be, for registered, publicly tradable securities having substantially identical terms or, in certain circumstances, a registration statement with respect to the bonds or notes issued. If ultimate registration and/or certain milestones are not completed by certain dates in mid- and late 2011, the respective issuer has agreed to pay liquidated damages to the bondholders. The liquidated damages would accrue at a rate of 0.25% per annum of the principal amount of the bonds or notes for the first 90 days and 0.50% per annum of the principal amount thereafter until the conditions described above have been cured.

Redemptions and maturities of long-term debt for 2010 and 2009 are summarized below:

Year	Company	Description	Principal  Amount		Rate	Secured/  Unsecured	Maturity
Successor
2010	LG&E	Due to PPL Investment Corp.	$	485	4.33%-6.48%	Unsecured	2012-2037
2010	KU	Due to PPL Investment Corp.	1,331		4.24%-7.035%	Unsecured	2012-2037
2010	LKE	Due to E.ON affiliates	1,330		Variable-7.78%	Unsecured	2010-2037
2010	LG&E	Due to E.ON affiliates	485		4.33%-6.48%	Unsecured	2012-2037
2010	KU	Due to E.ON affiliates	1,331		4.24%-7.035%	Unsecured	2010-2037
Predecessor
2010	LKE	Due to E.ON affiliates	75		7.01%	Unsecured	2010
2010	LKE	Due to E.ON affiliates	150		4.64%	Unsecured	2010
2010	LKE	Due to E.ON affiliates	100		Variable	Unsecured	2010
2009	LKE	Due to E.ON affiliates	50		3.98%	Unsecured	2009
2009	LKE	Due to E.ON affiliates	80		Variable	Unsecured	2009
2009	LKE	Due to E.ON affiliates	50		Variable	Unsecured	2009
2009	LKE	Due to E.ON affiliates	75		4.07%	Unsecured	2009

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Issuances of long-term debt for 2010 and 2009 are summarized below:

Year	Company	Description	Principal  Amount		Rate	Secured/  Unsecured	Maturity
Successor
2010	LG&E	Due to PPL Investment Corp.	$	485	4.33%-6.48%	Unsecured	2012-2037
2010	KU	Due to PPL Investment Corp.	1,331		4.24%-7.035%	Unsecured	2010-2037
2010	KU	First mortgage bonds	250		1.625%	Secured	2015
2010	KU	First mortgage bonds	500		3.25%	Secured	2020
2010	KU	First mortgage bonds	750		5.125%	Secured	2040
2010	LG&E	First mortgage bonds	250		1.625%	Secured	2015
2010	LG&E	First mortgage bonds	285		5.125%	Secured	2040
2010	LKE	Senior Notes	400		2.125%	Unsecured	2015
2010	LKE	Senior Notes	475		3.75%	Unsecured	2020
Predecessor
2010	LKE	Due to E.ON affiliates	50		Variable	Unsecured	2013
2009	LKE	Due to E.ON affiliates	50		7.784%	Unsecured	2011
2009	LKE	Due to E.ON affiliates	50		Variable	Unsecured	2012
2009	LKE	Due to E.ON affiliates	50		Variable	Unsecured	2012
2009	LKE	Due to E.ON affiliates	100		Variable	Unsecured	2012
2009	LKE	Due to E.ON affiliates	75		6.044%	Unsecured	2014
2009	LKE	Due to E.ON affiliates	50		Variable	Unsecured	2014
2009	LKE	Due to E.ON affiliates	50		Variable	Unsecured	2014
2009	LKE	Due to E.ON affiliates	80		Variable	Unsecured	2016
2009	KU	Due to E.ON affiliates	50		4.445%	Unsecured	2019
2009	KU	Due to E.ON affiliates	50		4.81%	Unsecured	2019
2009	KU	Due to E.ON affiliates	50		5.28%	Unsecured	2017

As of December 31, 2010, LG&E’s and KU’s first mortgage bonds are secured by first mortgage liens on substantially all of their respective real and tangible personal property located in Kentucky. The remaining long-term debt for the Company is unsecured. Long-term debt maturities for the Company are shown in the following table:

2011	$	2
2012	—
2013	—
2014	—
2015	900
Thereafter	2,935
	$	3,837

LKE and its subsidiaries, where applicable, were in compliance with all debt covenants at December 31, 2010.

See Note 1, Summary of Significant Accounting Policies, for certain debt refinancing and associated transactions completed by LKE 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.

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Note 12 - Notes Payable and Other Short-Term Obligations

Intercompany Revolving Lines of Credit

The Company maintained 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 Company maintained a facility with another subsidiary of PPL. The Company pays the subsidiary an annual commitment fee on the unused portion of the commitment based on the Utilities’ current bond rating. 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:

	Total		Amount		Balance		Average
	Available		Outstanding		Available		Interest Rate
December 31, 2010, Successor	$	300	$	—	$	300	N/A
December 31, 2009, Predecessor	313		276		37		1.25	%

Notes Payable to Affiliated Company

In addition to the revolving line of credit, the Company entered into the following short-term loans in 2010 and 2009, which were eventually replaced by a portion of the senior notes that were issued in November 2010:

Year	Company	Description	Principal  Amount		Rate	Secured/  Unsecured	Maturity
Successor
2010	LKE	Due to PPL Investment Corp.	$	968	2.00%	Unsecured	2010
Predecessor
2010	LKE	Due to E.ON affiliates	75		Variable	Unsecured	2010
2010	LKE	Due to E.ON affiliates	150		Variable	Unsecured	2010
2010	LKE	Due to E.ON affiliates	100		Variable	Unsecured	2010
2010	LKE	Due to E.ON affiliates	575		Variable	Unsecured	2010
2009	LKE	Due to E.ON affiliates	575		Variable	Unsecured	2010

Bank Revolving Lines of Credit

As of December 31, 2010, LG&E and KU each maintained a $400 million revolving credit agreement with a group of banks maturing in December 2014. The revolving lines of credit allow LG&E and KU to issue letters of credit or borrow funds up to $400 million each. Outstanding letters of credit reduce the facility’s available borrowing capacity. LG&E and KU pay the banks an annual commitment fee on the unused portion of the commitment based on the respective company’s current senior unsecured bond rating. At December 31, 2010, there was $163 million borrowed under this facility for LG&E at an average interest rate of 2.27% and none for KU. However, letters of credit totaling $198 million have been issued under KU’s facility. These credit agreements each contain financial covenants requiring the respective borrower’s debt to total capitalization ratio to not exceed 70%, as calculated pursuant to the credit agreements and other customary covenants.

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As of December 31, 2009, KU maintained a $35 million bilateral line of credit with an unaffiliated financial institution, maturing in June 2012. As of December 31, 2009, LG&E maintained bilateral lines of credit, with unaffiliated financial institutions, totaling $125 million maturing in June 2012. LG&E and KU 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 for LKE. These facilities were terminated on November 1, 2010, in conjunction with the PPL acquisition.

On December 1, 2010, KU replaced the letters of credit issued under prior letter of credit facilities with letters of credit of the same amount issued under the new revolving credit agreement. The four letter of credit facilities were subsequently terminated.

LKE and its subsidiaries, where applicable, were in compliance with all lines of credit covenants at December 31, 2010.

See Note 1, Summary of Significant Accounting Policies, for certain debt refinancing and associated transactions completed by LKE in connection with the PPL acquisition and Note 15, Related Party Transactions, for long-term debt payable to affiliates.

Note 13 - Commitments and Contingencies

Operating Leases

LKE leases office space, office equipment, plant equipment, real estate, railcars, telecommunications, vehicles and a helicopter and accounts for these leases as operating leases. Lease expense equaled $17 million in 2010, $16 million in 2009 and $15 million in 2008. The future minimum annual lease payments for operating leases for years subsequent to December 31, 2010, are shown in the following table:

2011	$	14
2012	12
2013	10
2014	8
2015	5
Thereafter	4
	$	53

Owensboro Contract Litigation and Contract Termination

In May 2004, the City of Owensboro, Kentucky and OMU commenced a suit against KU concerning a long-term power supply contract (the “OMU Agreement”) with KU. In May 2009, KU and OMU executed a settlement agreement resolving the matter on a basis consistent with prior court rulings and KU has received the agreed settlement amounts. Pursuant to the settlement’s operation, the OMU Agreement terminated in May 2010.

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Sale and Leaseback Transaction

LG&E and KU are participants in a sale and leaseback transaction involving their two jointly-owned CTs at 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 the same as if the Utilities had retained their ownership interests. The leasing transaction was entered into following receipt of required state and federal regulatory approvals. At December 31, 2010, the Consolidated Balance Sheets included these assets at a value of $104 million, which is reflected in “Regulated utility plant — electric and natural gas.”

In case of default under the lease, LKE 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 this amount, LG&E would be responsible for approximately $3 million (38%) and KU would be responsible for approximately $4 million (62%). LG&E and KU have made arrangements with LKE, via guarantee and regulatory commitment, for LKE to pay any default fees or amounts that LG&E or KU may incur.

Letters of Credit

LKE has issued letters of credit as of December 31, 2010 and December 31, 2009, for off-balance sheet obligations totaling $4 million and $12 million, respectively. LKE has issued letters of credit for on-balance sheet obligations as of December 31, 2010 and December 31, 2009, for $198 million to support outstanding bonds of $195 million.

Commodity Purchases

OVEC

The Utilities have a contract for power purchases with OVEC, terminating in 2026, for various Mw capacities. The Utilities hold an 8.13% investment interest in OVEC, with nine other electric utilities. LG&E and KU are not the primary beneficiary; therefore, the investment is not consolidated into LKE’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. LKE is contractually entitled to 8.13% of OVEC’s output, approximately 194 Mw of nameplate generation capacity. Pursuant to the OVEC power purchase contract, LKE may be conditionally responsible for 8.13% pro-rata shares 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. LKE’s contingent potential proportionate share of OVEC’s December 31, 2010 outstanding debt was $113 million. Future obligations for power purchases from OVEC are demand payments, comprised of annual minimum debt

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service payments, as well as contractually required reimbursement of plant operating, maintenance and other expenses and are as shown in the following table:

2011	$	29
2012	32
2013	32
2014	33
2015	32
Thereafter	372
	$	530

Coal and Natural Gas Purchase Obligations

LKE has contracts to purchase coal, natural gas and natural gas transportation. Future obligations are shown in the following table:

2011	$	774
2012	309
2013	256
2014	191
2015	191
Thereafter	49
	$	1,770

Construction Program

LKE had approximately $244 million of commitments in connection with its construction programs at December 31, 2010.

In June 2006, LKE 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, LKE 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, LKE 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 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. LKE cannot currently estimate the ultimate outcome of these matters.

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TC2 Air Permit

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 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.

Environmental Matters

The Company’s operations are subject to a number of environmental laws and regulations in each of the jurisdictions in which they operate, 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.

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 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

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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 LG&E’s and KU’s 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, LKE’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.

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 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.

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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.

Acid Rain Program

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.

Regional Haze

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.

Installation of Pollution Controls

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. KU met its Phase I SO2 requirements primarily through installation of FGD equipment on Ghent Unit 1. 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. KU’s strategy for its Phase II SO2 requirements, which commenced in 2000, includes the installation of additional FGD equipment, as well as using accumulated emission allowances and fuel switching to defer certain additional capital expenditures. LG&E and KU believe their costs in reducing SO2, NOx and mercury emissions to be comparable to those of similarly situated utilities with like generation assets. LG&E’s and KU’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 and KU will continue to monitor these developments to ensure

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that its environmental obligations are met in the most efficient and cost-effective manner. LKE expects to incur additional capital expenditures currently approved in its ECR plans totaling approximately $600 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.

GHG Developments

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.

GHG Legislation

LKE 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.

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GHG Regulations

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, the company is unable to assess the potential impact of any future regulation.

GHG Litigation

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 5th 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 Company’s former parent, 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. LKE continues to monitor relevant GHG litigation to identify judicial developments that may be potentially relevant to their operations.

Ghent Opacity NOV

In September 2007, the EPA issued a NOV alleging that KU had violated certain provisions of the Clean Air Act’s operating rules relating to opacity during June and July of 2007 at Units 1 and 3 of KU’s Ghent generating station. The parties have met on this matter and KU has received no further communications from the EPA. The Company is not able to estimate the outcome or potential effects of these matters, including whether substantial fines, penalties or remedial measures may result.

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Ghent New Source Review NOV

In March 2009, the EPA issued a NOV alleging that KU violated certain provisions of the Clean Air Act’s rules governing new source review and prevention of significant deterioration by installing FGD and SCR controls at its Ghent generating station without assessing potential increased sulfuric acid mist emissions. KU contends that the work in question, as pollution control projects, was exempt from the requirements cited by the EPA. In December 2009, the EPA issued a Section 114 information request seeking additional information on this matter. In March 2010, KU received an EPA settlement proposal providing for imposition of additional permit limits and emission controls and anticipates continued settlement negotiations with the EPA. Negotiations between the EPA and KU are ongoing. Depending on the provisions of a final settlement or the results of litigation, if any, resolution of this matter could involve significant increased operating and capital expenditures. The Company is currently unable to determine the final outcome of this matter or the impact of an unfavorable determination upon the Company’s financial position or results of operations.

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 LG&E and KU, 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 and KU’s impoundments, which the EPA found to be in satisfactory condition except for certain impoundments at LG&E’s 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

The EPA has also announced plans to develop revised effluent limitations 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.

Impact of Pending and Future Environmental Developments

As a company with significant coal-fired generating assets, LKE 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

F-97

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 emissions reductions 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, 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 byproduct disposal and storage and possible early replacement of coal-fired units. Capital expenditures for LKE associated with such actions are preliminarily estimated to be in the $3.0 to $3.5 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.

TC2 Water Permit

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.

General Environmental Proceedings

From time to time, LKE 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 generation units and KU’s Ghent Unit 2, a completed settlement with state regulators regarding compliance with particulate limits in the air permit for KU’s Tyrone generating station, 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 LG&E’s Cane Run station and claims regarding GHG emissions from LKE’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.

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Argentina Matters

During November 2008, the Argentine Central Bank commenced an administrative proceeding alleging a violation of certain emergency currency exchange laws in place during the country’s economic crisis in connection with a December 2002 refinancing by Centro of $35 million of a previously-existing, maturing loan. Under applicable Argentine laws, directors of a local company may be liable for monetary penalties for a subject company’s violations of the currency laws. Centro and its then-seated directors, including two current officers of the company, have filed responsive pleadings in the matter and requested dismissal at the administrative phase. In April 2010, the Argentine Central Bank staff issued a ruling declining to dismiss the case at the conclusion of the administrative stage and therefore forwarded the matter to a specialized Buenos Aires-domiciled financial criminal court where further proceedings are on-going. A ruling in the matter may occur during 2011. The Company has standard indemnification arrangements with its officers. E.ON Spain has assumed relevant rights and obligations with respect to claims and liabilities relating to the Argentine businesses in connection with its purchase of the business in 2010.

Guarantees

In connection with various divestitures, the Company has indemnified/guaranteed respective parties against certain liabilities that may arise in connection with these transactions and business activities. The terms of these indemnifications/guarantees vary, as do the expiration terms. The Company has issued direct financial guarantees to parties involved in the WKE lease termination, which occurred in July 2009. These guarantees cover the due and punctual payment, performance and discharge by each party of its respective present and future obligations. The most comprehensive of these guarantees is a guarantee covering operational, regulatory and environmental commitments and indemnifications made by WKE under the WKE Transaction Termination Agreement. This guarantee has a term of 12 years beginning on July 16, 2009 and a cumulative maximum exposure of $200 million. Certain items, such as non-excluded government fines and penalties, fall outside the cumulative cap. Another guarantee with a maximum exposure of $100 million covering other indemnifications expires in 2023. The Company is not aware of claims made by any party at this time, although one matter is currently in arbitration, the outcome of which cannot be predicted at this time. See Note 19, Discontinued Operations, for further information. Additionally, the Company has indemnified various third parties related to historical obligations for divested subsidiaries and affiliates. The indemnifications vary by entity and the maximum amounts range from being capped at the sale price to no specified maximum; however, the Company is not aware of claims made by any party at this time. The Company could be required to perform on these indemnifications in the event of covered losses or liabilities being claimed by an indemnified party. No additional material loss is anticipated by reason of such indemnifications. LKE has recorded liabilities for all guarantees totaling $11 million.

Other Contractual Obligations

As described in Note 19, Discontinued Operations, WKE issued a swap agreement to a third party customer, which expired on December 31, 2010. The swap was accounted for as a derivative until its expiration date and had a liability at December 31, 2010 of $9 million, which was paid in January 2011.

F-99

Note 14 - Jointly Owned Electric Utility Plant

Trimble County Unit 1

LKE 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):

	TC1
	LKE		IMPA		IMEA		Total
Ownership interest	75	%	12.88	%	12.12	%	100	%
Mw capacity	425		73		68		566

LKE’s 75% ownership:
Cost	$	288
Construction work in progress	17
Accumulated depreciation	(9		)
Net book value	$	296

Trimble County Unit 2

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 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. 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

LKE’s 75% ownership:
Plant held for future use	$	64
Construction work in progress	890
Accumulated depreciation	(1		)
Net book value	$	953

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Note 15 - Related Party Transactions

The Company’s balances with affiliates as of December 31, 2010, were with PPL and its affiliates. The Company’s balances with affiliates as of December 31, 2009, were with E.ON and its affiliates. See Note 10, Income Taxes, Note 11, Long-Term Debt, and Note 12, Notes Payable and Other Short-Term Obligations, for further information.

LKE relies on dividends from its subsidiaries to fund its dividends to its sole member. The net assets of LG&E and KU 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. LG&E and KU believe, however, that this statutory restriction, as applied to their 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. Also, under Virginia law, KU is prohibited from making loans to affiliates without the prior approval of the Virginia Commission. There are no comparable statutes under Kentucky law applicable to LG&E and KU. However, Orders from the Kentucky Commission require LG&E and KU to obtain prior regulatory consent or approval before loaning funds to any affiliates.

Interest Charges

LKE’s interest expense to affiliated companies was as follows:

	Successor		Predecessor
	November 1, 2010 through		January 1, 2010 through		Year Ended December 31,
	December 31, 2010		October 31, 2010		2009		2008
Interest on PPL loans	$	4	$	—	$	—	$	—
Interest on E.ON loans	—		131		155		138

Intercompany Balances

The Company had the following balances with PPL and its affiliates as of December 31, 2010 and with E.ON and its affiliates as of December 31, 2009:

	Successor		Predecessor
	December 31, 2010		December 31, 2009
Accounts receivable	$	2	$	—
Notes receivable	61		—
Accounts payable	3		43
Notes payable	—		851
Long-term debt	—		3,421

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In 2010, prior to the PPL acquisition, the Company paid dividends of $87 million to its sole member, E.ON US Investments Corp. The Company also paid dividends of $43 million and $68 million in 2009 and 2008, respectively, to E.ON US Investments Corp.

The Company made a $100 million return of capital distribution in November 2010, to its sole member, PPL Corporation.

Note 16 - Selected Quarterly Data (Unaudited)

	For the 2010 Periods Ended (a)
	Predecessor										Successor
	March 31			June 30		September 30		October 31			December 31
Operating revenues	$	713		$	603	$	719	$	179		$	494
Operating income	147			106		175		10			96
Income (loss) from continuing operations after income taxes	63			31		102		(5		)	45
Income (loss) from discontinued operations	(3		)	1		—		1			2
Net income (loss)	60			32		102		(4		)	47
Net income (loss) attributable to member	60			32		102		(4		)	47

(a)Periods ended March 31, June 30 and September 30 represent three months then ended. Period ended October 31 represents one month then ended and period ended December 31 represents two months then ended.

	For the 2009 Quarters Ended
	Predecessor
	March 31			June 30			September 30			December 31
Operating revenues	$	750		$	548		$	595		$	608
Operating income (loss)	27			78			211			(1,398		)
Income (loss) from continuing operations after income taxes	—			35			101			(1,453		)
Loss from discontinued operations	(35		)	(93		)	(71		)	(21		)
Net income (loss)	(35		)	(58		)	30			(1,474		)
Net income (loss) attributable to member	(36		)	(59		)	28			(1,475		)

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Note 17 - Accumulated Other Comprehensive Income (Loss)

	Funded Status Of																		Equity
	Pension And						Accumulated												Investee’s
	Postretirement						Derivative						Foreign Currency						Accum Other
	Plans						Gain or Loss						Translation Adj.						Comp Income						Totals
	Pretax			Tax			Pretax			Tax			Pretax			Tax			Pretax			Tax			Pretax			Tax			Net
Balance at December 31, 2007, Predecessor	$	(32	)	$	12		$	(11	)	$	4		$	22		$	(4	)	$	—		$	—		$	(21	)	$	12		$	(9	)
Change in funded status of defined- benefit pension and postretirement plans	(77		)	31			—			—			—			—			—			—			(77		)	31			(46		)
Gains (losses) on derivative instruments- designated and qualifying as cash flow hedging instruments	—			—			(2		)	—			—			—			—			—			(2		)	—			(2		)
Foreign currency translation adjustment	—			—			—			—			(5		)	1			—			—			(5		)	1			(4		)
Balance at December 31, 2008, Predecessor	(109		)	43			(13		)	4			17			(3		)	—			—			(105		)	44			(61		)
Change in funded status of defined- benefit pension and postretirement plans	29			(11		)	—			—			—			—			—			—			29			(11		)	18
Gains (losses) on derivative instruments- designated and qualifying as cash flow hedging instruments	—			—			5			(2		)	—			—			—			—			5			(2		)	3
Foreign currency translation adjustment	—			—			—			—			(4		)	1			—			—			(4		)	1			(3		)
Balance at December 31, 2009, Predecessor	(80		)	32			(8		)	2			13			(2		)	—			—			(75		)	32			(43		)
Change in funded status of defined- benefit pension and postretirement plans	(31		)	13			—			—			—			—			—			—			(31		)	13			(18		)
Gains (losses) on derivative instruments- designated and qualifying as cash flow hedging instruments	—			—			17			(7		)	—			—			—			—			17			(7		)	10
Foreign currency translation adjustment	—			—			—			—			(13		)	2			—			—			(13		)	2			(11		)
Equity investee’s other comprehensive income (loss)	—			—			—			—			—			—			(3		)	1			(3		)	1			(2		)
Balance at October 31, 2010, Predecessor	(111		)	45			9			(5		)	—			—			(3		)	1			(105		)	41			(64		)
Effect of PPL acquisition	111			(45		)	(9		)	5			—			—			3			(1		)	105			(41		)	64
Successor
Balance November 1, 2010, Successor
Change in funded status of defined- benefit pension and postretirement plans	9			(3		)	—			—			—			—			—			—			9			(3		)	6
Balance at December 31, 2010, Successor	$	9		$	(3	)	$	—		$	—		$	—		$	—		$	—		$	—		$	9		$	(3	)	$	6

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Note 18 - Available for Sale Debt Securities

LKE’s available for sale debt securities include the following pollution control bonds, which were repurchased from the remarketing agent in 2008:

	December 31,
	2010			2009
Louisville Metro 2003 Series A, due October 1, 2033, variable %	$	128		$	—
Louisville Metro 2007 Series B, due June 1, 2033, variable %	35			—
	$	163	(a)	$	—	(b)

(a)No realized or unrealized gains (losses) were recorded on these securities as the difference between the carrying value and the fair value was insignificant.

(b)Prior to the PPL acquisition, repurchased bonds were not accounted for as “Available for sale debt securities” and were presented on a net basis on the Consolidated Balance Sheets. See Note 1, Summary of Significant Accounting Policies, and Note 11, Long-Term Debt, for further discussion.

In January 2011, LKE remarketed these bonds to unaffiliated investors. See Note 21, Subsequent Events, for further discussion regarding the remarketing of these bonds.

Note 19 - Discontinued Operations

WKE

Through WKE and its subsidiaries, the Company had a 25-year lease on and operated the generating facilities of Big Rivers, a power-generating cooperative in western Kentucky, and a coal-fired generating facility owned by the City of Henderson, Kentucky.

In 2007, LKE entered into a termination agreement to terminate the lease, which closed in 2009, prior to PPL acquiring LKE. As part of the lease termination, LKE was obligated to pay a former customer, an aluminum smelter, an aluminum production payment in lieu of a lump-sum cash consent payment, as well as the difference between the electricity prices charged by WKE under the previous long-term sales contract and the electricity prices charged by the current electricity supplier. This obligation is partially mitigated by the opportunity to make off-system sales, when economic, for the contractual demand not used by the aluminum smelter. The total amount of the obligation to this smelter was limited to $82 million, with any amount paid by LKE over the limit has been recorded as an interest-bearing receivable, which is required to be repaid only if certain conditions occur by 2028. Such exposure expired on December 31, 2010. During the years ended December 31, 2010 and December 31, 2009, the Company made payments totaling $65 million and $26 million, respectively, as part of the transaction. Since the former customer posted a letter of credit supporting payment to its current electricity supplier, LKE reversed a portion of the accrual associated with its guarantee of payment by the former customer. The estimated remaining payments were accrued at December 31, 2010 including an obligation to another aluminum smelter, also a former customer, to make an escrow payment of $4 million in January 2011. The change in fair value of the derivative contract since acquisition along with the reversal of the accrual resulted in the income statement impact shown below. These amounts are reflected in “Gain (loss) on disposal of discontinued operations” on the Consolidated Statements of Income. See also Note

F-104

6, Fair Value Measurements, Note 10, Income Taxes, and Note 13, Commitments and Contingencies, for further discussion of these or of additional elements of the WKE lease termination transaction.

The table below provides selected income statement information for the WKE discontinued operations:

	Successor			Predecessor
	November 1, 2010 through			January 1, 2010 through			Year Ended December 31,
	December 31, 2010			October 31, 2010			2009			2008
Revenues	$	—		$	—		$	128		$	300
Loss before taxes	—			(7		)	(222		)	(309		)
Income tax benefit	—			3			79			120
Loss from discontinued operations	—			(4		)	(143		)	(189		)
Gain (loss) on disposal of discontinued operations before tax	4			5			(114		)	—
Income tax benefit (expense) from (disposal) of discontinued operations	(2		)	(2		)	45			—
Gain (loss) on disposal of discontinued operations	$	2		$	3		$	(69	)	$	—

Argentine Natural Gas Distribution

At December 31, 2009, the Company owned interests in two natural gas distribution companies in Argentina: 45.9% of Centro and 14.4% of Cuyana. These two entities served a combined customer base of approximately one million customers. The Centro investment was consolidated due to the Company’s majority ownership in the holding company of Centro. The Cuyana investment was accounted for using the equity method due to the ownership influence the Company exerted on the businesses.

In November 2009, subsidiaries of the Company entered into agreements to sell their direct and indirect interests in Centro and Cuyana to E.ON Spain and a subsidiary, both affiliates of E.ON. On January 1, 2010, the parties completed the transfer of the interests for a sale price of $35 million. In December 2009, the Company recorded an impairment loss of $12 million before income taxes. The impairment loss represented the difference between the carrying values of the Company’s interests in Centro and Cuyana and the sales price. The Company classified the assets, liabilities and results of operations of the Argentine natural gas distribution companies, including the impairment loss, as discontinued operations for all periods presented effective December 31, 2009. In connection with the reorganization transaction, E.ON Spain assumed rights and obligations relating to claims and liabilities associated with the former Argentine businesses or indemnified the Company with respect to such matters.

F-105

The table below provides summarized income statement information for the Argentine natural gas distribution discontinued operations:

	Year Ended			Year Ended
	December 31,			December 31,
	2009			2008
Revenues	$	60		$	69
Income before taxes	$	—		$	22
Income tax expense	(8		)	(6		)
Noncontrolling interest	(5		)	(8		)
Net income	$	(13	)	$	8

The table below provides summarized balance sheet information for the Argentine natural gas distribution discontinued operations as of December 31, 2009:

Assets:
Current assets	$	25
Property, plant and equipment	52
Investments in unconsolidated ventures	7
Deferred income taxes	6
Total assets	$	90
Liabilities:
Other liabilities	$	7

Note 20 - Share Performance Plan

In 2006, the Company introduced a stock-based compensation system, the E.ON Share Performance Plan, and virtual shares were granted under the Plan to certain executives of the Company. The Plan was a stock-based compensation plan based on the value of E.ON’s shares, and it entitled each participant to receive a payment at the end of a three-year and four-year vesting period equal to a target value per share times the number of virtual shares granted. The number of virtual shares did not change during the three-year and four-year vesting periods, but the target value per share could change based on E.ON’s stock price and the performance of E.ON stock during the three-year and four-year periods compared to the change in the Dow Jones STOXX Utilities Index (Total Return EUR). The Company used the fair-value method to account for the Plan. See Note 6, Fair Value Measurements, for further information.

The 2007 grant under E.ON Share Performance Plan of 6,820 virtual shares with target prices of €96.52 each was paid out in January 2010. The total of the payouts was less than $1 million. In the second quarter of 2010, the Company issued 27,643 virtual shares to Plan participants with a target price of €27.25.

F-106

All virtual shares vested on October 31, 2010, with the closing of the PPL acquisition. All shares were paid out in November 2010; the total of the payout was less than $1 million.

The Company recorded expense of less than $1 million related to the Plan in the year ended October 31, 2010 and less than $1 million in 2009.

Starting November 1, 2010, certain compensation of selected employees is provided by PPL, the expense related to this compensation was less than $1 million for 2010.

Note 21 - Subsequent Events

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.

On January 31, 2011, KU filed a notice of intent to file a rate case with the Virginia Commission for the test year ended December 31, 2010. The case is expected to be filed on or after April 1, 2011.

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 14, 2011, LKE contributed $150 million to its pension plans.

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 Consolidated 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. LKE used the proceeds from the remarketed bonds to repay the balance of its credit facility.

F-107

SCHEDULE I — LG&E AND KU ENERGY LLC

CONDENSED UNCONSOLIDATED STATEMENTS OF INCOME

(Millions of dollars)

	Successor		Predecessor
	Two Months		Ten Months
	Ended		Ended			Twelve Months Ended
	December 31,		October 31			December 31,			December 31,
	2010		2010			2009			2008
Operating revenues	$	—	$	—		$	—		$	—
Operating expenses:
Operation and maintenance expenses (benefit)	—		(3		)	(1		)	(1		)
Total operating expenses (benefit)	—		(3		)	(1		)	(1		)
Loss on impairment of goodwill	—		—			1,493			1,806
Operating income (loss)	—		3			(1,492		)	(1,805		)
Equity in earnings of subsidiaries	48		204			(61		)	38
Other income (expense) – net	—		(1		)	—			1
Interest income from affiliated companies	5		29			31			31
Interest expense to affiliated companies	1		47			60			60
Interest expense	4		—			—			—
Income (loss) from continuing operations, before income taxes	48		188			(1,582		)	(1,795		)
Income tax expense (benefit)	1		(2		)	(6		)	(6		)
Income (loss) from continuing operations	47		190			(1,576		)	(1,789		)
Discontinued operations	—		—			39			2
Net income (loss)	47		190			(1,537		)	(1,787		)
Noncontrolling interest - loss from discontinued operations	—		—			5			8
Net income (loss) attributable to member	$	47	$	190		$	(1,542	)	$	(1,795	)

The accompanying Notes to Condensed Unconsolidated Financial Statements are an integral part of the financial statements.

F-108

SCHEDULE I — LG&E AND KU ENERGY LLC

CONDENSED UNCONSOLIDATED BALANCE SHEETS

(Millions of dollars)

	Successor		Predecessor
	December 31,		December 31,
	2010		2009
Assets:
Current assets:
Cash and cash equivalents	$	2	$	—
Accounts receivable — affiliated companies	61		141
Income tax receivable	—		4
Notes receivable from affiliated companies	787		1,283
Total current assets	850		1,428
Other assets:
Investment in unconsolidated venture	—		9
Investments in subsidiaries	3,998		2,318
Deferred income taxes	166		148
Notes receivable from affiliated companies	670		720
Goodwill	—		837
Other long-term assets	6		8
Total other assets	4,840		4,040
Total assets	$	5,690	$	5,468

The accompanying Notes to Condensed Unconsolidated Financial Statements are an integral part of the financial statements.

F-109

SCHEDULE I — LG&E AND KU ENERGY LLC

CONDENSED UNCONSOLIDATED BALANCE SHEETS (CONT.)

(Millions of dollars)

	Successor		Predecessor
	December 31,		December 31,
	2010		2009
Liabilities and Equity:
Current liabilities:
Current portion of long-term debt - affiliated company	$	—	$	325
Accounts payable to affiliated companies	606		578
Notes payable to affiliated companies	—		1,059
Other current liabilities	7		1
Total current liabilities	613		1,963
Long-term debt - affiliated companies	—		1,280
Long-term debt	870		—
Notes payable to affiliated companies	196		—
Total long-term debt	1,066		1,280
Other long-term liabilities	—		1
Equity:
Common stock	—		774
Additional paid-in capital	3,958		4,224
Accumulated other comprehensive income (loss)	6		(43		)
Retained earnings	47		(2,763		)
Total member’s equity	4,011		2,192
Noncontrolling interest	—		32
Total equity	4,011		2,224
Total liabilities and equity	$	5,690	$	5,468

The accompanying Notes to Condensed Unconsolidated Financial Statements are an integral part of the financial statements.

F-110

SCHEDULE I — LG&E AND KU ENERGY LLC

CONDENSED UNCONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions of dollars)

	Successor			Predecessor
	Two Months			Ten Months
	Ended			Ended			Twelve Months Ended
	December 31,			October 31			December 31,			December 31,
	2010			2010			2009			2008
Cash flows from operating activities:
Net cash provided by operating activities	$	53		$	156		$	63		$	107
Cash flows from investing activities:
Investments in subsidiaries	(3		)	(525		)	(75		)	(174		)
Net decrease (increase) in notes receivable from affiliates	313			234			(742		)	(359		)
Net cash flows provided by (used in) investing activities	310			(291		)	(817		)	(533		)
Cash flows from financing activities:
Net increase (decrease) in debt with affiliates	(208		)	243			803			493
Repayment of short-term borrowings	(2,103		)	—			—			—
Retirement of long-term debt	(400		)	—			—			—
Issuance of long-term debt	870			—			—			—
Debt-issuance costs	(6		)	—			—			—
Contribution from member	1,565			—			—			—
Distribution to member	(100		)	—			—			—
Payment of dividends	—			(87		)	(49		)	(68		)
Net cash (used in) provided by from financing activities	(382		)	156			754			425
Change in cash and cash equivalents	(19		)	21			—			(1		)
Cash and cash equivalents at beginning of period	21			—			—			1
Cash and cash equivalents at end of period	$	2		$	21		$	—		$	—
Supplemental disclosures of cash flow information:
Cash dividends received from consolidated subsidiaries	$	—		$	105		$	80		$	40

The accompanying Notes to Condensed Unconsolidated Financial Statements are an integral part of the financial statements.

F-111

Schedule I — LG&E and KU Energy LLC

Notes to Condensed Unconsolidated Financial Statements

1.Basis of Presentation

LG&E and KU Energy LLC (LKE) is a holding company and conducts substantially all of its business operations through its subsidiaries.  These condensed financial statements and related footnotes have been prepared in accordance with Reg. §210.12-04 of Regulation S-X.  These statements should be read in conjunction with the consolidated financial statements and notes thereto of LKE.

LKE indirectly or directly owns all of the ownership interests of its significant subsidiaries.  LKE relies on dividends from its subsidiaries to fund LKE’s dividends to its common shareholders and to meet its other cash requirements.

2.Commitments and Contingencies

See Note 13 to LKE’s consolidated financial statements for commitments and contingencies of its subsidiaries.

Guarantees

In connection with various divestitures, the Company has indemnified/guaranteed respective parties against certain liabilities that may arise in connection with these transactions and business activities. The terms of these indemnifications/guarantees vary, as do the expiration terms. The Company has issued direct financial guarantees to parties involved in the WKE lease termination, which occurred in July 2009. These guarantees cover the due and punctual payment, performance and discharge by each party of its respective present and future obligations. The most comprehensive of these guarantees is a guarantee covering operational, regulatory and environmental commitments and indemnifications made by WKE under the WKE Transaction Termination Agreement. This guarantee has a term of 12 years beginning on July 16, 2009 and a cumulative maximum exposure of $200 million. Certain items, such as non-excluded government fines and penalties, fall outside the cumulative cap. Another guarantee with a maximum exposure of $100 million covering other indemnifications expires in 2023. The Company is not aware of claims made by any party at this time, although one matter is currently in arbitration, the outcome of which cannot be predicted at this time. See Note 19, Discontinued Operations, for further information. Additionally, the Company has indemnified various third parties related to historical obligations for divested subsidiaries and affiliates. The indemnifications vary by entity and the maximum amounts range from being capped at the sale price to no specified maximum; however, the Company is not aware of claims made by any party at this time. The Company could be required to perform on these indemnifications in the event of covered losses or liabilities being claimed by an indemnified party. No additional material loss is anticipated by reason of such indemnifications. A subsidiary of LKE has recorded liabilities for all guarantees totaling $11 million with respect to which LKE has certain guarantee obligations.

F-112

LG&E AND KU ENERGY LLC

Offers to Exchange

$400,000,000 aggregate principal amount of its 2.125% Senior Notes due 2015
and $475,000,000 aggregate principal amount of its 3.750% Senior Notes due 2020,
each of which have been registered under the Securities Act of 1933, as amended,

for any and all of its outstanding

2.125% Senior Notes due 2015 and
3.750% Senior Notes due 2020, respectively

PROSPECTUS

              , 2011

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 20.Indemnification of Directors and Officers.

LG&E and KU Energy LLC is a limited liability company formed under the Kentucky Limited Liability Company Act, or the Act.  Our Amended and Restated Operating Agreement provide, in general, for mandatory indemnification of directors and officers by the registrant to the fullest extent permitted by law.

Kentucky Limited Liability Company Act

Section 275.180 of the Act provides that a limited liability company may, through its written operating agreement, (1) eliminate or limit the personal liability of a member or manager for monetary damages for breach of any duty provided for in Section 275.170 of the Act; and (2) provide for indemnification of a member or manager for judgments, settlements, penalties, fines, or expenses incurred in a proceeding to which a person is a party because the person is or was a member or manager.

Insurance

Our officers and directors are covered by insurance policies purchased by us under which they are insured (subject to exceptions and limitations specified in the policies) against expenses and liabilities arising out of actions, suits or proceedings to which they are parties by reason of being or having been such directors or officers.

Item 21.Exhibits and Financial Statement Schedules.

The following Exhibits indicated by an asterisk preceding the Exhibit number have heretofore been filed with the Commission and pursuant to Rule 12(b)-32 are incorporated herein by reference.  The balance of the Exhibits are filed herewith.  Exhibits indicated by a [   ] are management contracts or compensatory arrangements that are filed or listed pursuant to Item 601(b)(10)(iii) of Regulation S-K.

3(a)	-	Articles of Organization of LG&E and KU Energy LLC
3(b)	-	Amended and Restated Operating Agreement of LG&E and KU Energy LLC
*4(a)-1	-	Indenture, dated as of October 1, 2010, between Kentucky Utilities Company and The Bank of New York Mellon, as Trustee (Exhibit 4(q)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(a)-2	-	Supplemental Indenture No. 1, dated as of October 15, 2010, to said Indenture (Exhibit 4(q)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(a)-3	-	Supplemental Indenture No. 2, dated as of November 1, 2010, to said Indenture (Exhibit 4(q)-3 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(b)-1	-	Indenture, dated as of October 1, 2010, between Louisville Gas and Electric Company and The Bank of New York Mellon, as Trustee (Exhibit 4(r)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(b)-2	-	Supplemental Indenture No. 1, dated as of October 15, 2010, to said Indenture (Exhibit 4(r)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(b)-3	-	Supplemental Indenture No. 2, dated as of November 1, 2010, to said Indenture (Exhibit 4(r)-3 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).

II-1

*4(c)-1	-	Indenture, dated as of November 1, 2010, between LG&E and KU Energy LLC and The Bank of New York Mellon, as Trustee (Exhibit 4(s)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(c)-2	-	Supplemental Indenture No. 1, dated as of November 1, 2010, to said Indenture (Exhibit 4(s)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
4(c)-3	-	Form of 2015 Exchange Note
4(c)-4	-	Form of 2020 Exchange Note
*4(d)	-	Registration Rights Agreement, dated November 12, 2010, between LG&E and KU Energy LLC and the Initial Purchasers (Exhibit 4(t) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(e)	-	Registration Rights Agreement, dated November 16, 2010, between Louisville Gas and Electric Company and the Initial Purchasers (Exhibit 4(u) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(f)	-	Registration Rights Agreement, dated November 16, 2010, between Kentucky Utilities Company and the Initial Purchasers (Exhibit 4(v) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(g)-1	-	2002 Series A Carroll County Loan Agreement, dated February 1, 2002, by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(w)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(g)-2	-	Amendment No. 1 dated as of September 1, 2010 to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(w)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(h)-1	-	2002 Series B Carroll County Loan Agreement, dated February 1, 2002, by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(x)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(h)-2	-	Amendment No. 1 dated as of September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(x)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(i)-1	-	2002 Series C Carroll County Loan Agreement, dated July 1, 2002, by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(y)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(i)-2	-	Amendment No. 1 dated as of September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(y)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(j)-1	-	2004 Series A Carroll County Loan Agreement, dated October 1, 2004 and amended and restated as of September 1, 2008, by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(z)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(j)-2	-	Amendment No. 1 dated as of September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(z)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).

II-2

*4(k)-1	-	2006 Series B Carroll County Loan Agreement, dated October 1, 2006 and amended and restated September 1, 2008, by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(aa)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(k)-2	-	Amendment No. 1 dated as of September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(aa)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(l)-1	-	2007 Series A Carroll County Loan Agreement, dated March 1, 2007, by and between Kentucky Utilities Company and County of Carroll, Kentucky (Exhibit 4(bb)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(l)-2	-	Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(bb)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(m)-1	-	2008 Series A Carroll County Loan Agreement, dated August 1, 2008 by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(cc)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(m)-2	-	Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(cc)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(n)-1	-	2000 Series A Mercer County Loan Agreement, dated May 1, 2000 and amended and restated as of September 1, 2008, by and between Kentucky Utilities Company, and County of Mercer, Kentucky (Exhibit 4(dd)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(n)-2	-	Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Mercer, Kentucky (Exhibit 4(dd)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(o)-1	-	2002 Series A Mercer County Loan Agreement, dated February 1, 2002, by and between Kentucky Utilities Company, and County of Mercer, Kentucky (Exhibit 4(ee)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(o)-2	-	Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Mercer, Kentucky (Exhibit 4(ee)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(p)-1	-	2002 Series A Muhlenberg County Loan Agreement, dated February 1, 2002, by and between Kentucky Utilities Company, and County of Muhlenberg, Kentucky (Exhibit 4(ff)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(p)-2	-	Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Muhlenberg, Kentucky (Exhibit 4(ff)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(q)-1	-	2007 Series A Trimble County Loan Agreement, dated March 1, 2007, by and between Kentucky Utilities Company, and County of Trimble, Kentucky (Exhibit 4(gg)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).

II-3

*4(q)-2	-	Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Trimble, Kentucky (Exhibit 4(gg)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(r)-1	-	2000 Series A Louisville/Jefferson County Metro Government Loan Agreement, dated May 1, 2000 and amended and restated as of September 1, 2008, by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(hh)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(r)-2	-	Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(hh)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(s)-1	-	2001 Series A Jefferson County Loan Agreement, dated July 1, 2001, by and between Louisville Gas and Electric Company, and Jefferson County, Kentucky (Exhibit 4(ii)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(s)-2	-	Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Jefferson County, Kentucky (Exhibit 4(ii)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(t)-1	-	2001 Series A Jefferson County Loan Agreement, dated November 1, 2001, by and between Louisville Gas and Electric Company, and Jefferson County, Kentucky (Exhibit 4(jj)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(t)-2	-	Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Jefferson County, Kentucky (Exhibit 4(jj)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(u)-1	-	2001 Series B Jefferson County Loan Agreement, dated November 1, 2001, by and between Louisville Gas and Electric Company, and Jefferson County, Kentucky (Exhibit 4(kk)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(u)-2	-	Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Jefferson County, Kentucky (Exhibit 4(kk)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(v)-1	-	2003 Series A Louisville/Jefferson County Metro Government Loan Agreement, dated October 1, 2003, by and between Louisville Gas and Electric Company and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(ll)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(v)-2	-	Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(ll)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(w)-1	-	2005 Series A Louisville/Jefferson County Metro Government Loan Agreement, dated February 1, 2005 and amended and restated as of September 1, 2008, by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(mm)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).

II-4

*4(w)-2	-	Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(mm)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(x)-1	-	2007 Series A Louisville/Jefferson County Metro Government Loan Agreement, dated as of March 1, 2007 and amended and restated as of September 1, 2008, by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(nn)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(x)-2	-	Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(nn)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(y)	-	2007 Series B Louisville/Jefferson County Metro Government Amended and Restated Loan Agreement, dated November 1, 2010, by and between Louisville Gas and Electric Company and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(oo) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(z)-1	-	2000 Series A Trimble County Loan Agreement, dated August 1, 2000, by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(pp)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(z)-2	-	Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(pp)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(aa)-1	-	2001 Series A Trimble County Loan Agreement, dated November 1, 2001, by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(qq)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(aa)-2	-	Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and the County of Trimble, Kentucky (Exhibit 4(qq)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(bb)-1	-	2001 Series B Trimble County Loan Agreement, dated November 1, 2001, by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(rr)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(bb)-2	-	Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(rr)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(cc)-1	-	2002 Series A Trimble County Loan Agreement, dated July 1, 2002, by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(ss)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(cc)-2	-	Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(ss)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).

II-5

*4(dd)-1	-	2007 Series A Trimble County Loan Agreement, dated March 1, 2007, by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(tt)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
*4(dd)-2	-	Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(tt)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed February 28, 2011).
5(a)	-	Opinion of John R. McCall, Esq.
5(b)	-	Opinion of Dewey & LeBoeuf LLP.
8(a)	-	Opinion of Dewey & LeBoeuf LLP regarding tax matters (included as part of Exhibit 5(b)).
*10(a)	-	Purchase and Sale Agreement, dated as of April 28, 2010, by and between E.ON US Investments Corp., PPL Corporation and E.ON AG (Exhibit No. 99.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated April 28, 2010, filed on April 30, 2010).
*10(b)	-	$400,000,000 Revolving Credit Agreement, dated as of November 1, 2010, among Kentucky Utilities Company, the Lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent, Swingline Lender and Issuing Lender (Exhibit 10.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated November 1, 2010, filed on November 1, 2010).
*10(c)	-	$400,000,000 Revolving Credit Agreement, dated as of November 1, 2010, among Louisville Gas and Electric Company, the Lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent, Swingline Lender and Issuing Lender (Exhibit 10.2 to PPL Corporation Form 8-K Report (File No. 1-11459) dated November 1, 2010, filed on November 1, 2010).
*[  ]10(d)	-	Retention Agreement, effective as of December 1, 2010, entered into between PPL Corporation and Victor A. Staffieri (Exhibit 10(rr) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed on February 28, 2011).
*[  ]10(e)	-	Amended and Restated Employment and Severance Agreement, dated as of October 29, 2010, between E.ON U.S. LLC and Victor A. Staffieri (Exhibit 10(ss) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010, filed on February 28, 2011).
[  ]10(f)	-	Amended and Restated Employment and Severance Agreement, dated as of October 29, 2010, between E.ON U.S. LLC and John R. McCall.
[  ]10(g)	-	Retention and Severance Agreement, dated as of October 28, 2010, between E.ON U.S. LLC and S. Bradford Rives.
[  ]10(h)	-	Retention Agreement, effective December 1, 2010, between PPL Corporation and Chris Hermann.
[  ]10(i)	-	Retention Agreement, effective December 1, 2010, between PPL Corporation and John R. McCall.
[  ]10(j)	-	Retention Agreement, effective December 1, 2010, between PPL Corporation and S. Bradford Rives.
[  ]10(k)	-	Retention Agreement, effective December 1, 2010, between PPL Corporation and Paul W. Thompson.

II-6

[  ]10(l)	-	Powergen Short-Term Incentive Plan, effective January 1, 2001.
[  ]10(m)-1	-	LG&E Energy Corp. Long-Term Performance Unit Plan, adopted April 25, 2003, effective January 1, 2003.
[  ]10(m)-2	-	Form of Certificate of Award under LG&E Energy Long-Term Performance Unit Plan.
[  ]10(n)-1	-	LG&E Energy LLC Nonqualified Savings Plan, effective January 1, 2005.
[  ]10(n)-2	-	First Amendment, dated as of March 16, 2007, to LG&E Energy LLC Nonqualified Savings Plan.
[  ]10(n)-3	-	Second Amendment, dated as of December 19, 2008, to LG&E Energy LLC Nonqualified Savings Plan.
*[  ]10(o)-1	-	E.ON Share Performance Plan (i) Terms and Conditions for the 1. Tranche (2006-2008) and (ii) Technical Annex, each dated as of June 2006. (Exhibit 10.1 to Louisville Gas and Electric Company Form 10-Q Report (File No. 1-02893) for the quarter ended September 30, 2006, filed on November 13, 2006).
*[  ]10(o)-2	-	Form of Certificate of Award under E.ON Share Performance Plan. (Exhibit 10.02 to Louisville Gas and Electric Company Form 10-Q Report (File No. 1-02893) for the quarter ended September 30, 2006, filed on November 13, 2006).
[  ]10(p)-1	-	E.ON Share Performance Plan for the 5th Tranche (2010-2013), dated as of January 2010 together with Supplemental Terms and Conditions.
[  ]10(p)-2	-	Form of Certificate of Award under E.ON Share Performance Plan for the 5th Tranche.
[  ]10(q)-1	-	PPL Corp. Incentive Compensation Plan, amended and restated effective January 1, 2003
[  ]10(q)-2	-	Amendment No. 1 to PPL Corp. Incentive Compensation Plan, effective January 1, 2005
*[  ]10(q)-3	-	Amendment No. 2 to PPL Corp. Incentive Compensation Plan, effective October 27, 2006 (Exhibit 10(dd)-3 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2006, filed on February 28, 2007).
*[  ]10(q)-4	-	Amendment No. 3 to PPL Corp. Incentive Compensation Plan, effective January 1, 2007 (Exhibit 10(f) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2007, filed on May 3, 2007).
*[  ]10(q)-5	-	Amendment No. 4 to PPL Corp. Incentive Compensation Plan, effective December 1, 2007 (Exhibit 10(a) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended September 30, 2008, filed on November 4, 2008).
*[  ]10(q)-6	-	Amendment No. 5 to PPL Corp. Incentive Compensation Plan, effective January 1, 2009 (Exhibit 10(bb)-6 to PPL Corporation Form 10-K Report (File 1-11459) for the year ended December 31, 2008, filed on February 27, 2009).
[  ]10(r)-1	-	PPL Corp. Incentive Compensation Plan for Key Employees, amended and restated effective January 1, 2003.

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[  ]10(r)-2	-	Amendment No. 1 to PPL Corp. Incentive Compensation Plan for Key Employees, effective January 1, 2005.
*[  ]10(r)-3	-	Amendment No. 2 to PPL Corp. Incentive Compensation Plan for Key Employees, effective October 27, 2006 (Exhibit 10(ee)-3 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2006, filed on February 28, 2007).
*[  ]10(r)-4	-	Amendment No. 3 to PPL Corp. Incentive Compensation Plan for Key Employees, effective January 1, 2007 (Exhibit 10(q) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2007, filed on May 3, 2007).
*[  ]10(r)-5	-	Amendment No. 4 to PPL Corp. Incentive Compensation Plan for Key Employees, effective December 1, 2007 (Exhibit 10(cc)-5 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2008, filed on February 27, 2009).
[  ]10(s)-1	-	LG&E Energy Corp. Supplemental Executive Retirement Plan, dated March 16, 2007, effective January 1, 1998, as amended and restated, composite copy as of September 2, 1998.
[  ]10(s)-2	-	First Amendment, dated as of December 19, 2008, to LG&E Energy Corp. Supplemental Executive Retirement Plan.
[  ]10(t)	-	Retention and Severance Agreement, dated as of October 29, 2010, between E.ON U.S. LLC and Chris Hermann.
[  ]10(u)	-	Retention and Severance Agreement, dated as of October 29, 2010, between E.ON U.S. LLC and Paul W. Thompson.
[  ]10(v)-1	-	Louisville Gas and Electric Company Nonqualified Savings Plan, effective January 1, 1992.
[  ]10(v)-2	-	Amendment No. 1 of Louisville Gas and Electric Company Nonqualified Savings Plan, dated March 4, 1992.
[  ]10(v)-3	-	Resolutions of the Board of Directors of Louisville Gas and Electric Company Re: Amendment of Nonqualified Savings Plan, dated December 8, 1994.
[  ]10(v)-4	-	Resolutions of the Board of Directors of LG&E Energy Corp. Re: Amendment of Nonqualified Savings Plan, dated December 6, 1995.
[  ]10(v)-5	-	Amendment to LG&E Energy Corp. Nonqualified Savings Plan, effective October 1, 1999.
[  ]10(v)-6	-	Amendment to LG&E Energy Corp. Nonqualified Savings Plan, effective December 1, 1999.
[  ]10(w)-1	-	Employment and Severance Agreement, dated as of February 25, 2000, between LG&E Energy Corp., Powergen, plc and Victor A. Staffieri.
[  ]10(w)-2	-	First Amendment to the Employment and Severance Agreement of Victor A. Staffieri, dated as of December 8, 2000.
[  ]10(w)-3	-	Second Amendment to the Employment and Severance Agreement of Victor A. Staffieri, effective April 30, 2001.
[  ]10(w)-4	-	Third Amendment to the Employment and Severance Agreement of Victor A. Staffieri, dated as of July 1, 2002, among LG&E Energy Corp., Powergen, plc, E.ON AG and Victor A. Staffieri.

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[  ]10(w)-5	-	Fourth Amendment to the Employment and Severance Agreement of Victor A. Staffieri, dated as of February 1, 2004, between LG&E Energy LLC, Powergen Limited, E.ON AG and Victor A. Staffieri.
[  ]10(x)-1	-	Employment and Severance Agreement, dated as of February 25, 2000, between LG&E Energy Corp., Powergen, plc and John R. McCall.
[  ]10(x)-2	-	First Amendment to the Employment and Severance Agreement of John R. McCall, dated as of December 8, 2000 between LG&E Energy Corp., Powergen, plc and John R. McCall.
[  ]10(x)-3	-	Second Amendment to the Employment and Severance Agreement of John R. McCall, dated as of May 20, 2002, among LG&E Energy Corp., Powergen, plc, E.ON AG and John R. McCall.
[  ]10(y)	-	Form of Retention and Severance Agreement, dated as of April 29, 2002, among LG&E Energy Corp., E.ON AG and S. Bradford Rives (dated as of April 29, 2002), Chris Hermann (dated as of May 6, 2002) and Paul W. Thompson (dated as of May 6, 2002).
[  ]10(z)	-	Form of Change in Control Agreement, dated as of February 6, 2001, between LG&E Energy Corp. and S. Bradford Rives, Chris Hermann and Paul W. Thompson.
[  ]10(aa)	-	Description of Divestiture Incentive Awards Granted in 2008.
12(a)	-	LG&E and KU Energy LLC Computation of Ratio of Earnings to Fixed Charges
16(a)	-	Letter from PricewaterhouseCoopers LLP regarding change in certifying accountant.
21(a)	-	Subsidiaries of LG&E and KU Energy LLC
23(a)	-	Consent of PricewaterhouseCoopers LLP
23(b)	-	Consent of John R. McCall, Esq. (included as part of Exhibit 5(a))
23(c)	-	Consent of Dewey & LeBoeuf LLP (included as part of Exhibit 5(b))
24(a)	-	Power of Attorney
25(a)	-	Statement of Eligibility of Trustee on Form T-1 with respect to the Indenture dated as of November 1, 2010 between LG&E and KU Energy LLC and The Bank of New York Mellon, as Trustee.
99(a)	-	Form of Letter of Transmittal
99(b)	-	Form of Letter to Brokers, Dealers, Commercial Banks, Trust Companies and Other Nominees
99(c)	-	Form of Letter to Clients
99(d)	-	Form of Notice of Guaranteed Delivery

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Item 22.Undertakings

(a)           The undersigned registrant hereby undertakes:

(1)to file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

i.to include any prospectus required by Section 10(a)(3) of the Securities Act;

ii.to reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement.  Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the SEC pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more that a 20 percent change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement; and

iii.to include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

(2)that, for the purpose of determining any liability under the Securities Act, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof;

(3)to remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering;

(4)that, for the purpose of determining liability under the Securities Act to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness; provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use; and

(5)that, for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, the undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

i.any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

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ii.any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

iii.the portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

iv.any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

(b)Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of any registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable.  In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of any registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

(c)The undersigned registrant hereby undertakes to respond to requests for information that is incorporated by reference into the prospectus pursuant to Item 4, 10(b), 11 or 13 of this form, within one business day of receipt of such request, and to send the incorporated documents by first-class mail or other equally prompt means.  This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request.

(d)The undersigned registrant hereby undertakes to supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, LG&E and KU Energy LLC has duly caused this Registration Statement on Form S-4 to be signed on its behalf by the undersigned, hereunto duly authorized, in Louisville, Kentucky, on the 21st day of April, 2011.

LG&E AND KU ENERGY LLC
By:	/s/ John R. McCall
Name:	John R. McCall
Title:	Executive Vice President, General Counsel, Corporate Secretary and Chief Compliance Officer

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons on behalf of the registrant and in their capacities as of the 21st day of April, 2011.

Signature	Title
/s/ Victor A. Staffieri	Chairman, President, Chief Executive Officer and Director
Victor A. Staffieri	(Principal Executive Officer)
/s/ S. Bradford Rives	Chief Financial Officer and Director (Principal Financial Officer
S. Bradford Rives	and Principal Accounting Officer)
/s/ John R. McCall	Executive Vice President, General Counsel, Corporate Secretary,
John R. McCall	Chief Compliance Officer and Director
/s/ Chris Hermann
Chris Hermann	Senior Vice President—Energy Delivery and Director
/s/ Paul W. Thompson
Paul W. Thompson	Senior Vice President—Energy Services and Director
/s/ Paul A. Farr
Paul A. Farr	Director
/s/ William H. Spence
William H. Spence	Director