UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

SCHEDULE 14A

Proxy Statement Pursuant to Section 14(a) of
the Securities Exchange Act of 1934 (Amendment No.              )

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Louisville Gas and Electric Company
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June 30, 2006

Dear Louisville Gas and Electric Company Shareholder:

You are cordially invited to attend the Annual Meeting of Shareholders of Louisville Gas and Electric Company to be held on Thursday, July 20, 2006 at 2:00 p.m., local time in the Twelfth Floor Conference Room at the E.ON U.S. Center, Third and Main Streets, Louisville, Kentucky.

Business items to be acted upon at the Annual Meeting are (i) the election of five directors, (ii) the approval of PricewaterhouseCoopers LLP as the independent registered public accounting firm of the Company for 2006 and (iii) the transaction of any other business properly brought before the meeting. Additionally, we will report on the progress of LG&E and shareholders will have the opportunity to present questions of general interest.

We encourage you to read the proxy statement carefully and complete, sign and return your proxy in the envelope provided, even if you plan to attend the meeting. Returning your proxy to us will not prevent you from voting in person at the meeting, or from revoking your proxy and changing your vote at the meeting, if you are present and choose to do so.

If you plan to attend the Annual Meeting, please check the box on the proxy card indicating that you plan to attend the meeting. Please bring the Admission Ticket, which forms the top portion of the form of proxy, to the meeting with you. If you wish to attend the meeting but do not have an Admission Ticket, you will be admitted to the meeting after presenting personal identification and evidence of ownership.

The directors and officers of LG&E appreciate your continuing interest in the business of LG&E. We hope you can join us at the meeting.

Victor A. Staffieri

Chairman of the Board, President and

Chief Executive Officer

NOTICE OF ANNUAL MEETING OF SHAREHOLDERS

The Annual Meeting of Shareholders of Louisville Gas and Electric Company (“LG&E”), a Kentucky corporation, will be held in the Twelfth Floor Conference Room at the E.ON U.S. Center, Third and Main Streets, Louisville, Kentucky, on Thursday, July 20, 2006, at 2:00 p.m., local time. At the Annual Meeting, shareholders will be asked to consider and vote upon the following matters, which are more fully described in the accompanying proxy statement:

1.A proposal to elect five directors for terms expiring in 2007;

2.A proposal to approve and ratify the appointment of PricewaterhouseCoopers LLP as the independent registered public accounting firm of LG&E for 2006; and

3.Such other business as may properly come before the meeting.

The close of business on June 1, 2006 has been fixed by the Board of Directors as the record date for determination of shareholders entitled to notice of and to vote at the Annual Meeting or any adjournment thereof.

You are cordially invited to attend the annual meeting. WHETHER OR NOT YOU PLAN TO ATTEND THE ANNUAL MEETING, PLEASE COMPLETE, SIGN, DATE AND RETURN YOUR PROXY IN THE REPLY ENVELOPE AS SOON AS POSSIBLE. Your cooperation in signing and promptly returning your proxy is greatly appreciated.

	By Order of the Board of Directors, John R. McCall, Secretary Louisville Gas and Electric Company 220 West Main Street Louisville, Kentucky 40202
June 30, 2006

PROXY STATEMENT

ANNUAL MEETING OF SHAREHOLDERS TO BE HELD JULY 20, 2006

The Board of Directors of Louisville Gas and Electric Company (“LG&E” or the “Company”) hereby solicits your proxy, and asks that you vote, sign, date and promptly mail the enclosed proxy card for use at the Annual Meeting of Shareholders to be held July 20, 2006, and at any adjournment of such meeting. The meeting will be held in the Twelfth Floor Conference Room of the E.ON U.S. Center, Third and Main Streets, Louisville, Kentucky. This proxy statement and the accompanying proxy were first mailed to shareholders on or about June 30, 2006.

If you plan to attend the meeting, please check the box on the proxy card indicating that you plan to attend the meeting. Also, please bring the Admission Ticket, which forms the top portion of the form of proxy, to the meeting with you. Shareholders who do not have an Admission Ticket, including beneficial owners whose accounts are held by brokers or other institutions, will be admitted to the meeting upon presentation of personal identification and, in the case of beneficial owners, proof of ownership.

The outstanding stock of LG&E is divided into three classes: Common Stock, Preferred Stock (without par value), and Preferred Stock, par value $25 per share. At the close of business on June 1, 2006, the record date for the Annual Meeting, the following shares of such classes were outstanding:

Common Stock, without par value	21,294,223 shares
Preferred Stock, par value $25 per share, 5% Series	860,287 shares
Preferred Stock, without par value, $5.875 Series	225,000 shares
Auction Series A (stated value $100 per share)	500,000 shares

All of the outstanding LG&E Common Stock is owned by E.ON U.S. LLC (formerly LG&E Energy LLC) (“E.ON U.S.”). Based on information contained in a Schedule 13G originally filed with the Securities and Exchange Commission in October 1998, AMVESCAP PLC, a parent holding company, reported certain holdings in excess of five percent of LG&E’s Preferred Stock. AMVESCAP PLC, with offices at 1315 Peachtree Street, N.W., Atlanta, Georgia 30309, and certain of its subsidiaries reported sole voting and dispositive power as to no shares and shared voting and dispositive power as to 43,000 shares of LG&E Preferred Stock, without par value, $5.875 Series, representing 17.2% of that class of Preferred Stock. The reporting companies indicated that they hold the shares on behalf of other persons who have the right to receive or the power to direct the receipt of dividends or the proceeds of sales of the shares. No other persons or groups are known by management to be beneficial owners of more than five percent of LG&E’s Preferred Stock.

As of June 1, 2006, all directors, nominees for director and executive officers of LG&E as a group beneficially owned no shares of LG&E Preferred Stock and less than 1% of the shares of E.ON AG, the ultimate parent of LG&E.

On December 11, 2000, Powergen plc, a public limited company with registered offices in England and Wales (“Powergen”), completed its acquisition of LG&E Energy Corp., then the parent corporation of LG&E and Kentucky Utilities Company (“KU” and, collectively with LG&E, the “Companies”). In connection with such transaction, certain officers and directors of Powergen were appointed to fill vacancies in the Board of Directors of LG&E occurring by resignation of prior directors. In January 2003, Powergen was reregistered as Powergen Limited.

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On July 1, 2002, E.ON AG, a German corporation (“E.ON”), completed the acquisition of Powergen. In connection with such transaction, certain officers or directors of E.ON and Powergen were appointed to fill vacancies in the Board of Directors of LG&E occurring by resignation of prior directors.

On December 30, 2003, LG&E Energy LLC became the successor, by assignment and subsequent merger, to the assets and liabilities of LG&E Energy Corp.

On December 1, 2005, LG&E Energy LLC was renamed E.ON U.S. LLC.

Required Vote

Owners of record at the close of business on June 1, 2006 of LG&E Common Stock and the 5% Cumulative Preferred Stock, par value $25 per share (the “5% Preferred Stock”) are entitled to one vote per share for each matter presented at the Annual Meeting or any adjournment thereof. In addition, each of such shareholders has cumulative voting rights with respect to the election of directors. Accordingly, in electing directors, each shareholder is entitled to as many votes as the number of shares of stock owned multiplied by the number of directors to be elected. All such votes may be cast for a single nominee or may be distributed among two or more nominees. The persons named as proxies reserve the right to cumulate votes represented by proxies that they receive and to distribute such votes among one or more of the nominees at their discretion.

You may revoke your proxy at any time before it is voted by giving written notice of its revocation to the Secretary of LG&E, by delivery of a later dated proxy, or by attending the Annual Meeting and voting in person. Signing a proxy does not preclude you from attending the meeting in person.

Directors are elected by a plurality of the votes cast by the holders of LG&E’s Common Stock and 5% Preferred Stock at a meeting at which a quorum is present. “Plurality” means that the individuals who receive the largest number of votes cast are elected as directors up to the maximum number of directors to be chosen at the meeting. Consequently, any shares not voted (whether by withholding authority, broker non-vote or otherwise) have no impact on the election of directors except to the extent the failure to vote for an individual results in another individual receiving a larger percentage of votes.

The affirmative vote of a majority of the shares of LG&E Common Stock and 5% Preferred Stock represented at the Annual Meeting is required for the approval of the independent registered public accounting firm and any other matters that may properly come before the meeting. Abstentions from voting on any such matter are treated as votes against, while broker non-votes are treated as shares not voted.

At the meeting, it is intended that the first two items in the accompanying notice will be presented for action by the owners of LG&E’s Common Stock and 5% Preferred Stock. The Board of Directors does not now know of any other matters to be presented at the meeting, but, if any other matters are properly presented to the meeting for action, the persons named in the accompanying proxy will vote upon them in accordance with their best judgment.

E.ON U.S. owns all of the outstanding LG&E Common Stock (representing approximately 96% of the LG&E shares entitled to vote on these proposals), and intends to vote this stock for the nominees for directors as set forth below, thereby ensuring their election to the Board. E.ON U.S. also intends to vote all of the outstanding LG&E Common Stock in favor of the appointment of PricewaterhouseCoopers LLP as the independent registered public accounting firm of LG&E. Nonetheless, the Board encourages you to vote on each of these matters, and appreciates your interest.

The Louisville Gas and Electric Company 2005 Financial Report, containing audited financial statements of LG&E and management’s discussion of such financial statements, are included with this proxy statement (the “Financial Report”), and are incorporated by reference herein. All shareholders are urged to read the accompanying Financial Report.

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PROPOSAL NO. 1

ELECTION OF DIRECTORS

The number of members of the Board of Directors of LG&E is currently fixed at five, pursuant to the Company’s By-Laws and resolutions adopted by the Board of Directors. Generally, directors are elected at each year’s Annual Meeting to serve for one-year terms and to continue in office until their successors are elected and qualified.

On January  31, 2004, in connection with reorganizations in reporting relationships among E.ON, Powergen and LG&E Energy, Messrs. John R. McCall and S. Bradford Rives were appointed to the Board of LG&E to fill the vacancies created by resignations of Dr. Hans Michael Gaul and Mr. Michael Söhlke. Mr. Victor A. Staffieri remained as a director. Effective January 1, 2005, the size of the Board was increased to five and Messrs. Paul W. Thompson and Chris Hermann were appointed as directors.

At this Annual Meeting, the following five persons are proposed for election to the Board of Directors:

For one-year terms expiring at the 2007 Annual Meeting:

Victor A. Staffieri
John R. McCall
S. Bradford Rives
Paul W. Thompson
Chris Hermann

Each of the above nominees currently serves as a director of LG&E and also serves as a director of E.ON U.S. and KU.

The Board of Directors does not know of any nominee who will be unable to stand for election or otherwise serve as a director. If for any reason any nominee becomes unavailable for election, the Board of Directors may designate a substitute nominee, in which event the shares represented on the proxy cards returned to LG&E will be voted for such substitute nominee, unless an instruction to the contrary is indicated on the proxy card.

THE BOARD OF DIRECTORS RECOMMENDS THAT YOU VOTE “FOR” THE ELECTION OF THE FIVE NOMINEES FOR DIRECTOR.

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INFORMATION ABOUT DIRECTORS AND NOMINEES

The following contains certain information concerning the nominees for director:

Nominees for Directors with Terms Expiring at the 2007 Annual Meeting of Shareholders

Victor A. Staffieri (Age 51):Mr. Staffieri is Chairman, President and Chief Executive Officer of E.ON U.S., LG&E and KU, serving from April 2001 to the present. He served as President and Chief Operating Officer of LG&E Energy, LG&E and KU from February 1999 to April 2001; Chief Financial Officer of LG&E Energy and LG&E from May 1997 to February 2000; Chief Financial Officer of KU from May 1998 to February 2000; President, Distribution Services Division of LG&E Energy from December 1995 to May 1997; President of LG&E from January 1994 to May 1997; and Senior Vice President, General Counsel and Public Policy of LG&E Energy and LG&E from November 1992 to December 1993. Mr. Staffieri has been a director of E.ON U.S. (including predecessors), LG&E and KU since April 2001 and was a director of Powergen from April 2001 until January 2004.

John R. McCall (Age 62):Mr. McCall is Executive Vice President, General Counsel and Corporate Secretary of E.ON U.S., LG&E and KU. Mr. McCall has held these positions at E.ON U.S. and LG&E since July 1994 and at KU since May 1998. Mr. McCall has been a director of E.ON U.S. (including predecessors), LG&E and KU since January 2004.

S. Bradford Rives (Age 47):Mr. Rives is Chief Financial Officer of E.ON U.S., LG&E and KU, serving from September 2003 until the present. He served as Senior Vice President—Finance and Controller of LG&E Energy, LG&E and KU from December 2000 until September 2003; Senior Vice President—Finance and Business Development of LG&E Energy and LG&E from February 1999 to December 2000; and Vice President—Finance and Controller of LG&E Energy and LG&E from March 1996 to February 1999. Mr. Rives has been a director of E.ON U.S. (including predecessors), LG&E and KU since January 2004.

Paul W. Thompson (Age 49):Mr. Thompson is Senior Vice President—Energy Services of E.ON U.S., LG&E and KU, serving from June 2000 until the present. He served as Senior Vice President—Energy Services of LG&E Energy from August 1999 until June 2000; Vice President, Retail Electric Business of LG&E from December 1998 to August 1999; and Group Vice President—Energy Marketing of LG&E Energy from June 1998 to August 1999. Mr. Thompson has been a director of E.ON U.S. (including predecessors), LG&E and KU since January 2005.

Chris Hermann (Age 58):Mr. Hermann is Senior Vice President—Energy Delivery of E.ON U.S., LG&E and KU, serving from February 2003 until the present. He served as Senior Vice President—Distribution Operations of LG&E Energy, LG&E and KU from December 2000 until February 2003; Vice President, Supply Chain and Operating Services of LG&E Energy and LG&E from December 1999 to December 2000; and Vice President, Power Generation and Engineering Services of LG&E from May 1998 to December 1999. Mr. Hermann has been a director of E.ON U.S. (including predecessors), LG&E and KU since January 2005.

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INFORMATION CONCERNING THE BOARD OF DIRECTORS

Each member of the Board of Directors of LG&E is also a director of E.ON U.S. and KU, as described above.

During 2005, there were a total of seven meetings of the LG&E Board, including actions taken by unanimous written consent. All directors attended 75% or more of the total number of meetings or consents of the Board of Directors and committees of the Board on which they served.

Compensation of Directors

Directors who are also officers of E.ON U.S. or its subsidiaries receive no compensation in their capacities as directors of LG&E and KU.

Committees

There are currently no formal committees of the Board of Directors of LG&E. Due to the small Board size of five members, the Board as a whole performs the functions that might otherwise be performed by audit or nominating committees.

In July 2002, upon completion of the E.ON-Powergen acquisition, the structures of the LG&E and KU Boards were changed to recognize practical and administrative efficiencies. The LG&E and KU Boards and LG&E Energy Board, respectively, adopted resolutions providing that (i) the functions of the former Audit Committee would be performed by the LG&E and KU Boards as a whole and (ii) certain functions of the former Remuneration Committee under certain E.ON U.S. executive compensation plans would be performed by the Senior Vice President—Corporate Executive Human Resources of E.ON AG, currently Ms. Mirjam Arnold. Through May 2005, this duty was performed by Dr. Stefan Vogg.

Audit and Auditor Matters

Due to the small size of the Board, the Board as a whole performs the functions generally associated with an audit committee. The Board has determined that each of Victor A. Staffieri and S. Bradford Rives is an audit committee financial expert as defined by Item 401(h) of Regulation S-K. All members of the Board are officers or employees of LG&E and therefore are not independent within the meaning of Item 7(d)(3)(iv) of Schedule 14A of the Securities Exchange Act of 1934.

During 2005, the Board maintained direct and indirect contact with LG&E’s independent registered public accounting firm and with LG&E’s internal Audit Services to review the following matters pertaining to LG&E: fees and services relating to the independent registered public accounting firm; the adequacy of accounting and financial reporting procedures; the adequacy and effectiveness of internal accounting controls; the scope and results of the annual audit and any other matters relative to the audit of LG&E’s accounts and financial affairs that the Board, Audit Services or the independent registered public accounting firm deemed necessary. A report of the Board acting as an audit committee is included in the “Report on 2005 Audit Committee Matters” section of this document. A copy of the charter applicable to the Board acting as an audit committee is included as Appendix A of this document.

The Board is responsible for approving all audit and permissible non-audit services to be provided by the independent registered public accounting firm in accordance with LG&E’s Pre-Approval Policy. Under the policy, the Board annually reviews and pre-approves the services that may be provided by the independent registered public accounting firm. These include audit services, audit-related services, tax services and some permissible non-audit services, up to designated fee or budget levels. New services or services exceeding these levels will require separate pre-approval by the Board. Under the policy, the Board may delegate pre-approval authority to one or more of its members, subject to reporting of any decisions by such member to the Board, or may rely upon certain annual or other pre-approvals by the E.ON Audit Committee under its policy, subject to certain reporting to the Board.

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Nominations

Due to the small size of the Board and the fact that E.ON U.S. owns all of LG&E’s common stock and approximately 96% of LG&E’s voting stock, the Board has determined that it is appropriate not to have a standing nominating committee, nominating committee charter or policy regarding consideration of candidates for director, including shareholder nominees. The full Board, with input from E.ON officers, selects director nominees but has not established specific qualifications for nominees or a formal process for identifying and evaluating such nominees. All members of the Boards are officers or employees of LG&E and therefore are not independent within the meaning of Item 7(d)(2)(ii)(D) of Schedule 14A of the Securities Exchange Act of 1934.

Nominations for the election of directors may be made by the Board, a committee thereof or by shareholders entitled to vote in the election of directors generally. Shareholders wishing to nominate someone for director must provide timely written notice to LG&E’s Secretary in accordance with the procedures set forth in the section “Shareholder Proposals and Nominations” of this document. The Board’s chairman may void the nomination of any candidate for election which was not made in compliance with applicable procedures.

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PROPOSAL NO. 2

APPROVAL OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM FOR 2006

The Board of Directors, subject to ratification by shareholders, has selected PricewaterhouseCoopers LLP as the independent registered public accounting firm to audit the accounts of LG&E for the fiscal year ending December 31, 2006. The firm was originally selected as independent auditors for the Company effective April 30, 2001, following the completion of the Powergen-LG&E Energy merger in December 2000. PricewaterhouseCoopers LLP has audited the accounts of E.ON and Powergen for many years.

Representatives of PricewaterhouseCoopers LLP are expected to be present at the annual meeting and available to respond to questions and will be given the opportunity to make a statement, if they so desire.

As previously stated, E.ON U.S. intends to vote all of the outstanding shares of common stock of the Company in favor of approval of the appointment of PricewaterhouseCoopers LLP as the independent registered public accounting firm of LG&E, and since E.ON U.S.’s ownership of such common stock represents over 96% of the voting power of the Company, the approval of such independent registered public accounting firm is assured.

THE BOARD OF DIRECTORS RECOMMENDS THAT YOU VOTE “FOR” THE APPROVAL OF THE APPOINTMENT OF THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM.

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COMPENSATION REPORT

Following the July 1, 2002 completion of E.ON’s acquisition of Powergen, the Remuneration Committee of the Boards of Directors of LG&E was terminated. As stated above, the former LG&E Energy, LG&E and KU Boards adopted resolutions providing that certain functions of the former Remuneration Committee under certain executive compensation plans would be performed by the Senior Vice President—Corporate Executive Human Resources of E.ON, currently Ms. Mirjam Arnold, and prior to May 2005, Dr. Stefan Vogg. This report describes the compensation policies applicable to LG&E’s executive officers for the last completed fiscal year.

With respect to 2005, Dr. Vogg and Ms. Arnold, in consultation with certain officers and the Management Board of E.ON AG and with the Chief Executive Officer of E.ON U.S., LG&E and KU, who is also a member of  LG&E’s Board of Directors (collectively, the “Compensation Group”), arrived at decisions regarding the compensation of LG&E’s executive officers, including the setting of base pay levels for 2005, and the administration and determination of awards under the E.ON Group Stock Option Program (the “E.ON SAR Plan”) and the LG&E Energy Corp. Performance Unit Plan (the “Long-Term Plan”) and of payments under the Short-Term Incentive Plan (the “Short-Term Plan”) as applicable to LG&E.

LG&E’s executive compensation program and the target awards and opportunities for executives are designed to be competitive with the compensation and pay programs of comparable companies, including utilities, utility holding companies and companies in general industry, where appropriate. The executive compensation program has been developed and implemented over time through consultation with, and upon the recommendations of, recognized executive compensation consultants. The Compensation Group and the Board of Directors have continuing access to such consultants as desired, and are provided with independent compensation data for their review.

Set forth below is a report addressing LG&E’s compensation policies during 2005 for its officers, including the executive officers named in the following tables. In many cases, the executive officers also serve in similar capacities for affiliates of LG&E, including E.ON U.S. and KU. For each of the executive officers of LG&E, the policies and amounts discussed below are for all services to LG&E and its affiliates, during the relevant period.

Compensation Philosophy

During 2005, LG&E’s executive compensation program had three major components: (1) base salary; (2) short-term incentives and (3) long-term incentives. LG&E developed the executive compensation program to focus on both short-term and long-term business objectives that are designed to enhance overall shareholder value. The short-term and long-term incentives were premised on the belief that the interests of executives should be closely aligned with those of shareholders. Based on this philosophy, these two portions of each executive’s total compensation package were linked to the accomplishment of specific results that were designed to benefit shareholders in both the short-term and long-term.

The executive compensation program also recognized that compensation practices must be competitive not only with utilities and utility holding companies, but also with companies in general industry to ensure that a stable and successful management team can be recruited and retained.

Pursuant to this competitive market positioning philosophy, in establishing compensation levels for all executive positions for 2005, the Compensation Group reviewed and updated, by applying inflation or market index increases, competitive compensation information previously gathered for United States general industry companies with revenue of approximately $3 billion (the “Survey Group”) and established targeted total direct compensation (base salary plus short-term incentives and long-term incentives) for each executive for 2005 to generally approach the 50th percentile of the competitive range from the Survey

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Group. Salaries, short-term incentives and long-term incentives for 2005 are described below. (The utilities and utility holding companies that were in the Survey Group were not necessarily the same as those in the Dow Jones Utility Average or other comparative indices used in a company performance graph in this proxy statement.)

The 2005 compensation information set forth in other sections of this document, particularly with respect to the tabular information presented, reflects the considerations set forth in this report. The Base Salary, Short-Term Incentives, and Long-Term Incentives sections that follow address the compensation philosophy for 2005 for all executive officers except those serving as Chief Executive Officer. The compensation of the Chief Executive Officer is discussed below under the heading “Chief Executive Officer Compensation.”

Base Salary

The base salaries for LG&E’s executive officers for 2005 were designed to be competitive with the Survey Group at approximately the 50th percentile of the base salary range for executives in similar positions with companies in the Survey Group. Actual base salaries were determined based on a combination of market position, individual performance and experience.

Short-Term Incentives

The Short-Term Plan provided for Company Performance Awards and Individual Performance Awards, each of which is expressed as a percentage of base salary and each of which is determined independent of the other. The Compensation Group established the performance goals for the Company Performance Awards and Individual Performance Awards at the beginning of the 2005 performance year. Payment of Company Performance Awards for executive officers was based on varying performance measures tied to each officer’s responsible areas. These measures and goals included, among others, E.ON, E.ON U.S., LG&E and KU earnings before interest and taxes (“EBIT”) targets and LG&E/KU EBIT targets. The Compensation Group retains discretion to adjust the measures and goals as deemed appropriate. Payment of Individual Performance Awards was based 100% on management effectiveness. As stated, the awards varied within the executive officer group based upon the nature of each individual’s functional responsibilities.

For 2005, the aggregate short term incentive targets for named executive officers were based 60% on Company Performance Award targets and 40% on Individual Performance Award targets. The Company Performance Award targets for named executive officers were established at 30% of base salary, and the Individual Performance Award targets were established at 20% of base salary. Both awards were established to be competitive with the 50th percentile of such awards granted to comparable executives employed by companies in the Survey Group. The individual officers were eligible to receive from 0% to 200% of their targeted Company Performance Award amounts, dependent upon Company performance as measured by the relevant performance goals, and were eligible to receive from 0% to 200% of their targeted Individual Performance Award amounts dependent upon individual performance as measured by management effectiveness.

Using the relevant E.ON, E.ON U.S., LG&E/KU and other subsidiaries’ performance against goals in 2005, the Compensation Group determined relative annual performance against targets for Company Performance Awards. Based upon this determination, Company Performance Awards for 2005 to the named executive officers were 116% of target and 35% of base salary. Based on determinations of management effectiveness, payouts for Individual Performance Awards to the named executive officers ranged from 150% to 165% of target and 30% to 33% of base salary.

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Long-Term Incentives

The Compensation Group made competitive long-term grants under the Long-Term Plan and the E.ON SAR Plan for each executive based on the historic long-term compensation grants. The aggregate expected value of the awards is intended to approach the expected value of long-term incentives payable to executives in similar positions for companies in the 50th percentile of the Survey Group, depending upon achievement of targeted Company and Individual performance.

In 2005, the Compensation Group granted performance units under the Long-Term Plan to executive officers and senior management and stock appreciation rights (“SAR’s”) under the E.ON SAR Plan to executive officers. The amounts of the executive’s long-term award to be delivered in SAR’s and performance units were 25% and 75% respectively. Under the Long-Term Plan, the future value of grants of performance units is dependent upon company performance against a value-added target. The ultimate value of the performance unit can range from 0% to 150% of grant. Under the E.ON SAR Plan, the amount paid to executives when they exercise their SAR’s, after satisfaction of two-year vesting and performance criteria, is the difference between E.ON’s stock price at the time of exercise and the stock price at the time of issuance, multiplied by the number of SAR’s exercised multiplied by the foreign exchange rate of the time of grant. The price at issuance is the average of the XETRA closing quotations for E.ON stock during the December prior to issuance. The future value of the 2005 grants of SAR’s was substantially dependent upon the changing value of E.ON shares in the marketplace.

Chief Executive Officer Compensation

Mr. Victor A. Staffieri was appointed Chief Executive Officer of LG&E and KU effective May 1, 2001. Mr. Staffieri’s compensation was governed by the terms of an Employment and Severance Agreement entered into on February 25, 2000 as amended (including upon his appointment as Chief Executive Officer) (the “2000 Agreement”). The 2000 Agreement was for an initial term of two years commencing on December 11, 2000, with automatic annual extensions thereafter unless E.ON, the Companies or Mr. Staffieri give notice of non-renewal. During 2004, Mr. Staffieri entered into an amendment to his employment and severance agreement.

The 2000 Agreement, as amended, established the minimum levels of Mr. Staffieri’s base compensation, although the Chairman of E.ON retains discretion to increase such compensation. For 2005, the Compensation Group established Mr. Staffieri’s compensation and short-term and long-term awards using  adjusted comparisons (as described above under the heading “Compensation Philosophy”) to relevant officers of companies in the Survey Group, including utilities, and survey data from various compensation consulting firms. Mr. Staffieri also received Company contributions to the savings plan, similar to those of other officers and employees. Details of Mr. Staffieri’s 2005 compensation are set forth below.

Base Salary.Mr. Staffieri was paid a total base salary of $700,164 during 2005, pursuant to the 2000 Agreement, as amended. The Compensation Group, in determining Mr. Staffieri’s 2005 annual salary, considered the general rate of growth in compensation levels as described above.

Short-Term Incentives.Mr. Staffieri’s short-term incentive target award as Chief Executive Officer was 70% of his 2005 base salary. As with other executive officers receiving short-term incentive awards, Mr. Staffieri was eligible to receive more or less than the targeted amount, based on Company performance and individual performance. His 2005 aggregate short-term incentive target was based 60% on achievement of Company Performance Award targets and 40% on achievement of Individual Performance Award targets.

For 2005, the Company Performance Award payout for Mr. Staffieri was 116% of target and 49% of his 2005 base salary, and the Individual Performance Award payout was 170% of target and 48% of his

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2005 base salary. Mr. Staffieri’s Company Performance Award was based on E.ON’s and E.ON U.S.’s  EBIT and was calculated based upon annual Company performance as described above under the heading “Short-Term Incentives.”  In determining the Individual Performance Award, the Compensation Group considered Mr. Staffieri’s effectiveness in several areas, including the financial and operational performance of E.ON U.S., LG&E, KU and other subsidiaries and satisfaction of individual goals such as implementing regulatory strategy and overall management of E.ON U.S.

Long-Term Incentive Grant.In 2005, Mr. Staffieri received 918,964 performance units for the 2005-2007 performance period under the Long-Term Plan and 16,372 SAR’s under the E.ON SAR Plan. These amounts were determined pursuant to the terms of his 2000 Agreement, as amended, with an aggregate expected value representing approximately 175% of his base salary. The terms of the performance units and SAR’s for Mr. Staffieri are the same as for other executive officers, as described under the heading “Long-Term Incentives.”

Long-Term Incentive Payout.Mr. Staffieri exercised SAR’s during 2005 as indicated in the “Option/SAR Exercises and Year-End Value Table.”

Other.In 2005, Mr. Staffieri also received a retention payment in connection with a 2002 amendment to his employment and severance agreement in the amount of $891,670, including interest, as indicated in the Summary Compensation Table.

Members of LG&E’s Board of Directors

Victor A. Staffieri
John R. McCall
S. Bradford Rives
Paul W. Thompson
Chris Hermann

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COMPANY PERFORMANCE

All of the outstanding Common Stock of LG&E is owned by E.ON U.S. and, accordingly, there are no trading prices for LG&E’s Common Stock. During 2005, all of the common stock or membership interests of E.ON U.S. were indirectly owned by E.ON. The following graph reflects a comparison of the cumulative total return (change in stock price plus reinvested dividends) to holders of American Depositary Shares (“ADS’s”) of E.ON AG from December 31, 2000, through December 31, 2005, with the Standard & Poor’s 500 Composite Index and the Dow Jones’ Utility Average. The comparisons in this table are required by the Securities and Exchange Commission and, therefore, are not intended to forecast or be indicative of possible future performance.

COMPARISON OF FIVE YEAR CUMULATIVE
TOTAL SHAREHOLDER RETURN (1)

DATA POINTS (IN $)

(1)Total Shareholder Return assumes $100 invested on December 31, 2000, with reinvestment of dividends.

1While similar, the utilities and holding companies that were in the Survey Group were not necessarily the same as those in the Dow Jones’ Utility Average used in the Company Performance Graph.

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EXECUTIVE COMPENSATION AND OTHER INFORMATION

The following table shows the cash compensation paid or to be paid by LG&E, KU or E.ON U.S., as well as certain other compensation paid or accrued for those years, to the Chief Executive Officer and the next four highest compensated executive officers of LG&E who were serving as such at December 31, 2005, as required, in all capacities in which they served LG&E, KU, E.ON U.S. or its subsidiaries during 2003, 2004 and 2005:

SUMMARY COMPENSATION TABLE

						Long-Term Compensation
		Annual Compensation				Awards		Payouts
Name and Principal Position	Year	Salary ($)	Bonus ($)	Other Annual Comp. ($)		Restricted Stock Awards ($)		Securities Underlying Options/SAR (#)(1)		LTIP Payouts ($)(2)		All Other Compen- sation ($)
Victor A. Staffieri	2005	700,164	674,985	38,011			—		16,372		0		950,900	(3)
Chairman of the Board,	2004	673,236	728,159	31,572			—		24,778		0		941,069	(4)
President and Chief	2003	648,902	741,340	39,461			—		25,282		0		902,045	(5)
Executive Officer
John R. McCall	2005	425,401	288,677	15,020			—		5,684		0		47,642	(3)
Executive Vice	2004	408,949	296,015	9,365			—		8,600		0		670,532	(4)
President, General	2003	389,475	313,933	198,681	(6)		—		8,671		0		47,529	(5)
Counsel and Corporate
Secretary
S. Bradford Rives	2005	345,301	223,962	9,429			—		3,691		0		48,312	(3)
Chief Financial Officer	2004	332,001	230,355	7,293			—		5,586		0		517,626	(4)
	2003	305,495	243,607	6,880			—		5,345		0		423,923	(5)
Paul W. Thompson	2005	322,303	215,490	7,702			—		3,445		0		21,801	(3)
Senior Vice President—	2004	286,258	209,048	8,273			—		4,697		0		435,220	(4)
Energy Services	2003	260,071	187,526	7,232			—		4,792		0		10,151	(5)
Chris Hermann	2005	273,004	177,068	9,830			—		2,188		0		25,228	(3)
Senior Vice President—	2004	262,412	179,732	7,891			—		3,311		0		416,884	(4)
Energy Delivery	2003	252,928	166,267	4,905			—		3,378		0		22,463	(5)

(1)Amounts for all years reflect E.ON SAR Plan grants.

(2)No regular payouts were made under the Long-Term Plan during years 2005, 2004 or 2003 as the three-year performance periods had not been completed.

(3)Includes employer contributions to 401(k) plan, nonqualified thrift plan, employer paid life insurance premiums, vacation sell back and retention payments in 2005 as follows: Mr. Staffieri $6,300, $36,550, $16,380, $0 and $891,670, respectively; Mr. McCall $6,300, $13,036, $23,398, $4,908 and $0, respectively; Mr. Rives $6,300, $40,970, $1,042, $0 and $0, respectively; Mr. Thompson, $4,883, $11,157, $2,430, $3,331 and $0, respectively and Mr. Hermann, $6,300, $7,408, $7,320, $4,200 and $0, respectively. The retention payments above are discussed in the “Compensation Report” and “Employment Contracts and Termination of Employment Arrangements and Change in Control Provisions”.

(4)Includes retention payments in 2004 as follows: Mr. Staffieri, $872,032; Mr. McCall, $613,425; Mr. Rives, $498,000; Mr. Thompson, $418,747; and Mr. Hermann, $393,615, respectively.

(5)Includes retention payments in 2003 as follows: Mr. Staffieri, $837,375; Mr. McCall, $0; Mr. Rives, $403,556; Mr. Thompson, $0; and Mr. Hermann, $0, respectively.

(6)Includes overseas compensation or tax payments in 2003 of $178,445.

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OPTION/SAR GRANTS TABLE
Option/SAR Grants in 2005 Fiscal Year

The following table contains information at December 31, 2005, with respect to grants of E.ON AG stock appreciation rights (“SAR’s”) to the named executive officers:

	Individual Grants
	Number of		Percent of
	Securities		Total					Potential Realizable Value At
	Underlying		Options/SAR’s			Exercise		Assumed Annual Rates of Stock
	Options/SAR’s		Granted to			Or Base		Price Appreciation For Option Term
	Granted		Employees in			Price		Expiration
Name	(#)(1)		Fiscal Year(2)			($/Share)		Date	0% ($)		5% ($)	10% ($)
Victor A. Staffieri		16,372		38.8	%		88.27	12/31/2011		0	588,324	1,371,045
John R. McCall		5,684		13.5	%		88.27	12/31/2011		0	204,253	475,997
S. Bradford Rives		3,691		8.7	%		88.27	12/31/2011		0	132,635	309,096
Paul W. Thompson		3,445		8.2	%		88.27	12/31/2011		0	123,795	288,496
Chris Hermann		2,188		5.2	%		88.27	12/31/2011		0	78,625	183,230

(1)E.ON SAR’s were awarded with an exercise price at issuance equal to the average XETRA closing quotations for E.ON stock during the December prior to issuance. The SAR’s are exercisable over a seven-year period from their issuance date, assuming satisfaction of an included initial two-year vesting and performance criteria period.

(2)Represents percentage grants to E.ON U.S., LG&E and KU officers only.

OPTION/SAR EXERCISES AND YEAR-END VALUE TABLE
Aggregated Option/SAR Exercises in 2005 Fiscal Year
And FY-End Option/SAR Values

The following table sets forth information with respect to the named executive officers concerning the value of unexercised E.ON SAR’s held by them as of December 31, 2005:

Name	Shares Acquired On Exercise (#)(1)		Value Realized ($)		Number of Securities Underlying Unexercised Options/SAR’s at FY-End (#) Exercisable/Unexercisable		Value of Unexercised In-The-Money Options/SAR’s  at FY-End ($) Exercisable/Unexercisable
Victor A. Staffieri		25,282		599,233		0/41,150		0/1,286,048
John R. McCall		8,671		228,164		0/14,284		0/446,388
S. Bradford Rives		5,345		126,687		0/9,277		0/289,930
Paul W. Thompson		7,396		157,147		0/8,142		0/249,009
Chris Hermann		5,826		109,839		0/5,499		0/171,854

(1)Amounts shown are E.ON SAR’s exercised. Under the E.ON SAR Plan no actual shares of E.ON are acquired.

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LONG-TERM INCENTIVE PLAN AWARDS TABLE
Long-Term Incentive Plan Awards in 2005 Fiscal Year

The following table provides information concerning awards of performance units made in fiscal year 2005 to the named executive officers under the Long-Term Plan.

	Number
	of	Performance or
	Shares,	Other Period		Estimated Future Payouts under
	Units or	Until		Non-Stock Price Based Plans
	Other	Maturation		(number of shares)
Name	Rights	Or Payout		Threshold (#)		Target (#)		Maximum (#)
Victor A. Staffieri	918,964		12/31/2007		459,482		918,964		1,378,446
John R. McCall	319,050		12/31/2007		159,525		319,050		478,575
S. Bradford Rives	207,180		12/31/2007		103,590		207,180		310,770
Paul W. Thompson	193,380		12/31/2007		96,690		193,380		290,070
Chris Hermann	122,850		12/31/2007		61,425		122,850		184,275

Each performance unit awarded under the Long-Term Plan represented the right to receive an amount payable in cash on the date of payout. The amount of the payout is determined by company performance over a three-year cycle. For awards made in 2005, the Long-Term Plan awards were intended to reward executives on a three-year rolling basis dependent upon the achievement of a value-added target by E.ON U.S.

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Pension Plans

The following table shows the estimated pension benefits payable to a covered participant at normal retirement age under E.ON U.S.’s qualified defined benefit pension plans, as well as non-qualified supplemental pension plans that provide benefits that would otherwise be denied participants by reason of certain Internal Revenue Code limitations for qualified plan benefits, based on the remuneration that is covered under the plan and years of service with E.ON U.S. and its predecessors and subsidiaries:

2005 PENSION PLAN TABLE

	Years of Service
Remuneration	15		20		25		30 or more
$   100,000	$	41,512	$	41,512	$	41,512	$	41,512
$   200,000	$	105,512	$	105,512	$	105,512	$	105,512
$   300,000	$	169,512	$	169,512	$	169,512	$	169,512
$   400,000	$	233,512	$	233,512	$	233,512	$	233,512
$   500,000	$	297,512	$	297,512	$	297,512	$	297,512
$   600,000	$	361,512	$	361,512	$	361,512	$	361,512
$   700,000	$	425,512	$	425,512	$	425,512	$	425,512
$   800,000	$	489,512	$	489,512	$	489,512	$	489,512
$   900,000	$	553,512	$	553,512	$	553,512	$	553,512
$1,000,000	$	617,512	$	617,512	$	617,512	$	617,512
$1,100,000	$	681,512	$	681,512	$	681,512	$	681,512
$1,200,000	$	745,512	$	745,512	$	745,512	$	745,512
$1,300,000	$	809,512	$	809,512	$	809,512	$	809,512
$1,400,000	$	873,512	$	873,512	$	873,512	$	873,512
$1,500,000	$	937,512	$	937,512	$	937,512	$	937,512
$1,600,000	$	1,001,512	$	1,001,512	$	1,001,512	$	1,001,512
$1,700,000	$	1,065,512	$	1,065,512	$	1,065,512	$	1,065,512
$1,800,000	$	1,129,512	$	1,129,512	$	1,129,512	$	1,129,512
$1,900,000	$	1,193,512	$	1,193,512	$	1,193,512	$	1,193,512

A participant’s remuneration covered by the Retirement Income Plan (the “Retirement Income Plan”) is his or her average base salary and short-term incentive payment (as reported in the Summary Compensation Table) for the five calendar plan years during the last ten years of the participant’s career for which such average is the highest. The years of service for each named executive employed by E.ON U.S. at December 31, 2005 were as follows: 13 years for Mr. Staffieri; 11 years for Mr. McCall; 22 years for Mr. Rives; 14 years for Mr. Thompson; and 35 years for Mr. Hermann. Benefits shown are computed as a straight life single annuity beginning at age 65.

Current Federal law prohibits paying benefits under the Retirement Income Plan in excess of $165,000 per year. Officers of E.ON U.S., LG&E and KU with at least one year of service with any company are eligible to participate in LG&E Energy’s Supplemental Executive Retirement Plan (the “Supplemental Executive Retirement Plan”), which is an unfunded supplemental plan that is not subject to the $165,000 limit. Presently, participants in the Supplemental Executive Retirement Plan consist of all of the eligible officers of E.ON U.S., LG&E and KU. This plan provides generally for retirement benefits equal to 64% of average current earnings during the highest 36 consecutive months prior to retirement, reduced by Social Security benefits, by amounts received under the Retirement Income Plan and by benefits from other employers. As with all other officers, Mr. Staffieri participates in the Supplemental Executive Retirement Plan described above.

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Estimated annual benefits to be received under the Retirement Income Plan and the Supplemental Executive Retirement Plan upon normal retirement at age 65 and after deduction of Social Security benefits will be $860,577 for Mr. Staffieri; $398,253 for Mr. McCall; $327,169 for Mr. Rives; $280,971 for Mr. Thompson; and $246,952 for Mr. Hermann.

EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT
ARRANGEMENTS AND CHANGE IN CONTROL PROVISIONS

In connection with the E.ON-Powergen merger, Messrs. Staffieri and McCall entered into amendments to their employment and severance agreements and Mr. Staffieri entered into a further amendment in early 2004. The original agreements, effective upon the LG&E Energy-Powergen merger for two year terms, contained change in control provisions and the benefits described below. Pursuant to the amended agreements, Mr. Staffieri received certain retention payments during 2003, 2004 and 2005 described in the Compensation Report and the Summary Compensation Table.

Under the terms of his revised employment and severance agreement, Mr. Staffieri was entitled to additional retentions payment of $800,570, plus interest, on each of July 1, 2004 and January 1, 2005 (the two year and thirty month anniversaries of the E.ON-Powergen merger), which was initially to be credited into a deferred compensation account and which was then payable in a lump sum in cash. If during the term of his agreement, which is automatically extended for subsequent one year terms unless terminated upon 90 days notice, and within twenty-four months following a change in control, Mr. Staffieri’s employment is terminated for reasons other than cause, disability or death, or for good reason, Mr. Staffieri shall be entitled to a severance amount equal to 2.99 times the sum of (1) his annual base salary and (2) his bonus or “target” award paid or payable. If during the term of his agreement but prior to a change in control, Mr. Staffieri’s employment is terminated for reasons other than cause, disability or death, or for good reason, Mr. Staffieri will be entitled an amount equal to two times his annual base salary and target annual bonus.

Under the terms of his revised employment and severance agreement, on July 1, 2004, Mr. McCall received a lump sum cash payment equal to his annual salary plus target annual bonus. If during the term of his agreement, which is automatically extended for subsequent one year terms unless terminated upon 90 days notice, and within twenty-four months following a change in control or within forty-eight months of the E.ON-Powergen merger, Mr. McCall’s employment is terminated for reasons other than cause, disability or death, or for good reason, Mr. McCall shall be entitled to a severance amount equal to 2.99 times the sum of (1) his annual base salary and (2) his bonus or “target” award paid or payable.

During 2002, in connection with the E.ON-Powergen merger, Messrs. Thompson, Rives and Hermann entered into new retention agreements under which these officers were entitled to a payment equal to the sum of (1) their annual base salary and (2) their annual bonus or “target” award, in the event of their continued employment through the second anniversary of the E.ON-Powergen merger. During 2001, Messrs. Thompson, Rives and Hermann also entered into change of control agreements with terms of twenty-four months, with automatic one year renewals if not terminated, which provide that, in the event of termination of employment for reasons other than cause, disability or death, or for good reason within the twenty-four months following a change in control, these officers shall be entitled to a severance amount equal to 2.99 times the sum of (1) their annual base salary and (2) their bonus or “target” award paid or payable.

Pursuant to the employment and change in control agreements, payments may be made to executives which would equal or exceed an amount which would constitute a nondeductible payment pursuant to Section 280G of the Internal Revenue Code, if any. Additionally, executives receive continuation of certain welfare benefits and payments in respect of accrued but unused vacation days and for out-placement assistance. A change in control encompasses certain merger and acquisition events, changes in board membership and acquisitions of voting securities.

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EQUITY COMPENSATION PLAN INFORMATION

The executive officers of LG&E do not participate in any compensation plans under which equity securities of LG&E, KU or any affiliate are authorized for issuance.

REPORT ON 2005 AUDIT COMMITTEE MATTERS

The Board of Directors, consisting of five members, performed the functions of an audit committee (“Audit Committee”). The Audit Committee is governed by a charter adopted by the Board of Directors, which sets forth the responsibilities of the Audit Committee members. The Audit Committee held six meetings during 2005.

The financial statements of Louisville Gas and Electric Company are prepared by management, which is responsible for their objectivity and integrity. With respect to the financial statements for the calendar year ended December 31, 2005, the Audit Committee reviewed and discussed the audited financial statements and the quality of the financial reporting with management and the independent registered public accounting firm. It also discussed with the independent registered public accounting firm the matters required to be discussed by Statement on Auditing Standards No. 61, Communication with Audit Committees, as amended, and received and discussed with the independent registered public accounting firm the matters in the written disclosures required by Independence Standards Board Standard No. 1, Independence Discussions with Audit Committees.

Based upon the reviews and discussions referred to above, the Audit Committee recommended to the Board of Directors the inclusion of the audited financial statements in Louisville Gas and Electric Company’s Annual Report on Form 10-K for the year ended December 31, 2005, for filing with the Securities and Exchange Commission.

The following information on independent audit fees and services is being provided in compliance with the Securities and Exchange Commission rules on auditor independence.

1.     PricewaterhouseCoopers LLP fees for the periods ended December 31, 2005 and December 31, 2004 are as follows:

	LG&E
	2005		2004
·  Audit Fees
·  Audit Fees	$	200,000	$	188,333
·  Internal Controls	$	—	$	16,667
·  Comfort Letter Procedures	$	37,565	$	—
·  Total Audit Fees	$	237,565	$	205,000
·  Audit-Related Fees
·  Pension Plan Audits	$	1,042	$	36,667
·  Compliance Related Software	$	12,400	—
·  Total Audit-Related Fees	$	13,442	$	36,667
·  Tax Fees
·  Sales Tax Services	—		$	11,200
·  Total Tax Fees	$	—	$	11,200
·  All Other Fees
·  Assorted Fees	$	—	$	405
·  Total All Other Fees	$	—	$	405

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2.     The Audit Committee considered whether the independent registered public accounting firm’s provision of non-audit services is compatible with maintaining the independent registered public accounting firm’s independence.

3.     The Audit Committee has been advised by PricewaterhouseCoopers LLP that hours expended on the audit engagement were entirely performed by PricewaterhouseCoopers’ personnel.

This report has been provided by the Board of Directors performing the functions of the Audit Committee.

Victor A. Staffieri, Chairman
John R. McCall
S. Bradford Rives
Paul W. Thompson
Chris Hermann

SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING

LG&E has in place procedures to assist its directors and officers in complying with Section 16(a) of the Exchange Act of 1934, which includes assisting the director or officer in preparing forms for filing. Based upon information provided to LG&E by individual directors and officers, LG&E believes that in respect of the year ended December 31, 2005, all filing requirements have been complied with.

SHAREHOLDER PROPOSALS AND NOMINATIONS

Any shareholder may submit a proposal for consideration at the 2007 annual meeting. Any shareholder desiring to submit a proposal for inclusion in the proxy statement for consideration at the 2007 annual meeting should forward the proposal so that it will be received at LG&E’s principal executive offices no later than March 31, 2007. Proposals received by that date that are proper for consideration at the annual meeting and otherwise conform to the rules of the Securities and Exchange Commission will be included in the 2007 proxy statement.

Under LG&E’s By-laws, shareholders intending to nominate a director for election at, or otherwise bring business before, the annual meeting must provide advance written notice. In general, such notice must be received by the Secretary of LG&E (a) not less than 90 days prior to the meeting date or (b) if the meeting date is not publicly announced more than 100 days prior to the meeting, by the tenth day following such announcement.

To be proper, written notice must generally include (a) the name and address of the shareholder and of each nominee, (b) a representation that the shareholder is a holder of record entitled to vote at such meeting and intends to appear in person or by proxy, (c) a description of all arrangements between the shareholder and each nominee, (d) such other information regarding each nominee as would be required to be included in a proxy statement under the Securities and Exchange Commission rules had the nominee been nominated by the Board and (e) the consent of the each nominee to serve if elected. LG&E shareholder proponents must also include the class and number of shares beneficially owned by the proponent. Proposals not properly submitted will be considered untimely.

SHAREHOLDER COMMUNICATIONS

Shareholders can communicate with the Board by submitting a letter or writing addressed to a director care of:  John R. McCall, Secretary, Louisville Gas and Electric Company, P.O. Box 32010, 220 West Main Street, Louisville, KY  40232. The Secretary may initially review communications with directors and transmit a summary to the directors, but has discretion to exclude from transmittal any

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communications that are commercial advertisements or other forms of solicitation or individual service or billing complaints (although all communications are available to the directors upon request). The Secretary will forward to the directors any communications raising substantial issues.

We encourage all directors to attend our annual meeting. Three of our five directors were in attendance at the LG&E annual meeting in 2005.

OTHER MATTERS

At the annual meeting, it is intended that the first two items set forth in the accompanying notice and described in this proxy statement will be presented. Should any other matter be properly presented at the annual meeting, the persons named in the accompanying proxy will vote upon them in accordance with their best judgment. Any such matter must comply with those provisions of LG&E’s Articles of Incorporation requiring advance notice for new business to be acted upon at the meeting. The Board of Directors knows of no other matters that may be presented at the meeting.

LG&E will bear the costs of printing and preparing this proxy solicitation. LG&E will provide copies of this proxy statement, the accompanying proxy and the Financial Report to brokers, dealers, banks and voting trustees, and their nominees, for mailing to beneficial owners, and upon request therefore, will reimburse such record holders for their reasonable expenses in forwarding solicitation materials. In addition to using the mails, proxies may be solicited by directors, officers and regular employees of LG&E, in person or by telephone.

Any shareholder may obtain without charge a copy of LG&E’s Annual Report on Form 10-K, as filed with the Securities and Exchange Commission for the year 2005 by submitting a request in writing to: John R. McCall, Secretary, Louisville Gas and Electric Company, P.O. Box 32010, 220 West Main Street, Louisville, Kentucky 40232.

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APPENDIX A

LOUISVILLE GAS AND ELECTRIC COMPANY

AND

KENTUCKY UTILITIES COMPANY

AUDIT COMMITTEE CHARTER

(Revised and Approved January 20, 2006)

Mission Statement

The Audit Committee (the “Committee”) is a Committee, respectively, of the Boards of Directors (each, separately, the “Board”) of Louisville Gas and Electric Company and of Kentucky Utilities Company (each, separately, the “Company”). Its primary function is to assist the Board in fulfilling its oversight responsibilities by reviewing the integrity and internal controls over the Company’s financial reporting process, and other systems of internal controls which management and the Board of Directors have established; the independence and performance of the Independent Registered Public Accounting Firm (independent accountant),  and the Audit Services function; and the process for monitoring compliance with the Code of Business Conduct and the Code of Ethics for the Chief Executive Officer (CEO) and Senior Financial Officers. Although operating as a combined Committee, actions of the Committee related to an individual Company only are applicable to such Company only, as appropriate.

Composition

The Committee will be composed of at least three members of the Board of Directors who shall serve at the pleasure of the Board. At least one member of the Committee shall be designated as a financial expert. In the event that the Board of Directors does not appoint a Committee, the functions of the Committee shall be performed by the Board of Directors or its members.

Audit Committee members will be appointed by the Board of Directors. One of the members will be designated as the Committee’s Chairman. The Chairman will preside over the Committee meetings and report Committee actions to the Board of Directors.

Meetings

The Committee will meet on a regular basis, but not less than quarterly, and will call special meetings as circumstances require. It will meet privately, as necessary, with the Director of Audit Services and the independent public accountant in separate executive sessions to discuss any matters that the Committee, the Director of Audit Services, or the independent accountant believe should be discussed privately. The Committee may ask members of management or others to attend meetings and provide pertinent information, as necessary.

Responsibilities

1.Provide an open avenue of communication between the internal auditors, the independent accountant, and the Board of Directors.

2.Review and update, where appropriate, the Committee’s charter annually.

3.Recommend to the Board of Directors on an annual basis the independent accountant to be nominated, approve the compensation of the independent accountant, and review and approve the discharge of the independent accountant. The independent accountant is ultimately responsible to the Board of Directors and the Audit Committee.

A-1

4.Pre-approve the audit and non-audit services performed by the independent accountant as prescribed under the Sarbanes-Oxley Act of 2002, and related regulations of the Securities and Exchange Commission.

5.Review and concur in the appointment, replacement, reassignment or dismissal of the Director of Audit Services.

6.Require the independent accountant to submit to the Committee on a periodic basis a formal written statement regarding independence of such independent accountant and all facts and circumstances relevant thereto; discuss with the independent accountant its independence; confirm and assure the independence of the Audit Services Department and the independent accountant, including a review of management consulting services and related fees provided by the independent accountant; and recommend to the Board of Directors actions necessary to ensure independence of the Audit Services Department and the independent accountant. Ascertain that the lead audit partner for the independent accountant(s) serves in that capacity for no more than five years. In addition, ascertain that any partner other than the lead or concurring partner serves no more than seven years at the partner level on the Company’s audit.

7.Monitor the Company’s practices relative to the hiring of current or former employees of the independent accountant.

8.Inquire of management, the Director of Audit Services, and the independent accountant about significant risks or exposures, assess the steps management has taken to minimize such risk to the Company, and periodically review compliance with such steps.

9.Approve the annual audit plan, ensuring provisions are made for the monitoring of the independent accountant’s services as required by the Audit Committee Pre-Approval Policy, and review the three-year plan of the internal auditing function. Review the independent accountant’s proposed audit plan, including coordination with Audit Services’ annual audit plan.

10.Review with the Director of Audit Services and the independent accountant the coordination of audit effort to assure completeness of coverage, reduction of redundant efforts, and the effective use of audit resources.

11.Consider with management and the independent accountant the rationale for employing audit firms other than the principal independent accountant.

12.Consider and review with the independent accountant and the Director of Audit Services:

a.The adequacy of the Company’s internal controls, including computerized information system controls and security;

b.Any related significant issues identified by the independent accountant and Audit Services, together with management’s responses thereto;

c.Material written communications between the independent accountant and management, such as any management letter or schedule of unadjusted audit differences; and

d.Significant deficiencies and/or material weaknesses in the internal controls over financial reporting identified during the process of management’s assessment of such internal controls or by the independent accountant in their testing of management’s assessment to determine the proper disposition of deficiencies and/or weaknesses identified.

13.Review with management and the independent accountant at the completion of the annual 10Qs and 10K audits:

a.The Company’s annual financial statements and related footnotes;

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b.The independent accountant’s audit of the financial statements and the report thereon;

c.The independent accountant’s judgment about the quality and appropriateness of the Company’s accounting principals as applied to its financial reporting;

d.Any significant changes required in the independent accountant’s audit plan and scope;

e.Any serious difficulties or disputes with management encountered during the course of the audit; and

f.Other matters related to the conduct of the audit which are to be communicated to the Committee under generally accepted auditing standards.

14.Review with management such appropriate notices or reports as may be required to be filed on behalf of the Committee with the regulatory authorities, exchanges or included in the Company’s proxy materials or otherwise, pursuant to law or exchange regulations. Review with management and the independent accountant the effect of any regulatory and accounting initiatives, as well as off-balance sheet structures, if any.

15.Consider and review with management and the Director of Audit Services:

a.Any difficulties encountered in the course of their audits, including any restrictions on the scope of their work or access to required information;

b.Any significant changes required in their audit plan;

c.Any significant audit findings and management’s responses thereto;

d.The Audit Services Department budget, staffing, and staff qualifications;

e.The Audit Services Department charter; and

f.Audit Services’ compliance with the Institute of Internal Auditors’ Standards for the Professional Practice of Internal Auditing.

16.Provide oversight of the Company’s Code of Business Conduct, Code of Ethics for the CEO and Senior Financial Officers, and anti-fraud programs. The Committee’s oversight role includes:

a.Periodic review, reassessment, and approval of the Company’s Code of Business Conduct and Code of Ethics for the CEO and Senior Financial Officers;

b.A review, with the Director of Audit Services, of the results of the annual Code of Business Conduct questionnaire;

c.Creation, maintenance, and review of procedures for:

i.Receipt, retention, and treatment of complaints received by the Company through the employee helpline, whistleblower process, or any other means regarding accounting, internal accounting controls, or auditing matters that may be submitted by any party internal or external to the organization;

ii.Confidential, anonymous submissions by employees of concerns regarding questionable accounting or auditing matters; and

iii.Review of any complaints received for appropriate, timely follow-up and resolution by management.

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17.Review the results of any audits of officers’ expense reimbursements, perquisites, and officer use of corporate assets by Audit Services or the independent accountant. As considered necessary by the Committee, review policies and procedures governing these areas.

18.Review legal and regulatory matters that may have a material impact on the financial statements, related Company compliance policies and programs, and reports received from regulators.

19.Report Committee actions to the Board of Directors with such recommendations as the Committee may deem appropriate.

20.Conduct or authorize investigations into any matters within the Committee’s scope of responsibilities, and retain independent counsel, accountants or others to assist it in the conduct of any investigation.

21.Conduct a periodic review of the Committee’s effectiveness and performance.

22.Assume such other duties and considerations as may be delegated to the Committee by the Board of Directors, or required of the Committee upon the request of the Board of Directors from time to time pursuant to a duly adopted resolution of the Board of Directors.

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LOUISVILLE GAS AND ELECTRIC COMPANY

2005 FINANCIAL REPORT

LOUISVILLE GAS AND ELECTRIC COMPANY

2005 FINANCIAL REPORT

TABLE OF CONTENTS

Index of Abbreviations	3
Selected Financial Data	5
Management’s Discussion and Analysis of Financial Condition and Results of Operations	6
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	27
Statements of Income	28
Statements of Retained Earnings	28
Statements of Comprehensive Income	29
Balance Sheets	30
Statements of Cash Flows	32
Statements of Capitalization	33
Notes to Financial Statements	34
Report of Management	64
Report of Registered Independent Public Accounting Firm	65

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[ This page intentionally left blank. ]

2

INDEX OF ABBREVIATIONS

AEP	American Electric Power Company, Inc.
AFUDC	Allowance for Funds Used During Construction
AG	Attorney General of Kentucky
APBO	Accumulated Postretirement Benefit Obligation
ARO	Asset Retirement Obligation
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
Capital Corp.	E.ON U.S. Capital Corp. (formerly LG&E Capital Corp.)
CAVR	Clean Air Visibility Rule
Clean Air Act	The Clean Air Act, as amended in 1990
CCN	Certificate of Public Convenience and Necessity
CO2	Carbon Dioxide
Company	LG&E or KU, as applicable
Companies	LG&E and KU
CT	Combustion Turbines
CWIP	Construction Work in Progress
DOE	Department of Energy
DOJ	Department of Justice
DSM	Demand Side Management
ECAR	East Central Area Reliability Region
ECR	Environmental Cost Recovery
EEI	Electric Energy, Inc.
EITF	Emerging Issues Task Force Issue
E.ON	E.ON AG
E.ON U.S.	E.ON U.S. LLC. (formerly LG&E Energy LLC and LG&E Energy Corp.)
E.ON U.S. Services	E.ON U.S. Services Inc. (formerly LG&E Energy Services Inc.)
EPA	U.S. Environmental Protection Agency
EPAct 2005	Energy Policy Act of 2005
ERISA	Employee Retirement Income Security Act of 1974, as amended
ESM	Earnings Sharing Mechanism
Fidelia	Fidelia Corporation (an E.ON affiliate)
FAC	Fuel Adjustment Clause
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FSP	FASB Staff Position
FT and FT-A	Firm Transportation
FTR	Financial Transmission Right
GSC	Gas Supply Clause
GFA	Grandfathered Transmission Agreement
IBEW	International Brotherhood of Electrical Workers
IMEA	Illinois Municipal Electric Agency
IMPA	Indiana Municipal Power Agency
IRC	Internal Revenue Code of 1986, as amended
IRP	Integrated Resource Plan
ITP	Independent Transmission Provider
Kentucky Commission	Kentucky Public Service Commission
KIUC	Kentucky Industrial Utility Consumers, Inc.
KU	Kentucky Utilities Company
KU Energy	KU Energy Corporation
KU R	KU Receivables LLC
Kv	Kilovolts
Kw	Kilowatts
Kwh	Kilowatt hours
LEM	LG&E Energy Marketing Inc.
LG&E	Louisville Gas and Electric Company
LG&E Energy	LG&E Energy LLC (now E.ON U.S. LLC)
LG&E R	LG&E Receivables LLC

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LG&E Services	LG&E Energy Services Inc. (now E.ON U.S. Services Inc.)
LMP	Locational Marginal Pricing
LNG	Liquefied Natural Gas
Mcf	Thousand Cubic Feet
MGP	Manufactured Gas Plant
MISO	Midwest Independent Transmission System Operator, Inc.
MMBtu	Million British thermal units
Moody’s	Moody’s Investor Services, Inc.
Mva	Megavolt-ampere
Mw	Megawatts
Mwh	Megawatt hours
NOPR	Notice of Proposed Rulemaking
NOx	Nitrogen Oxide
OATT	Open Access Transmission Tariff
OMU	Owensboro Municipal Utilities
OVEC	Ohio Valley Electric Corporation
PBR	Performance-Based Ratemaking
PJM	Pennsylvania, New Jersey, Maryland Interconnection
Powergen	Powergen Limited (formerly Powergen plc)
PUHCA 1935	Public Utility Holding Company Act of 1935
PUHCA 2005	Public Utility Holding Company Act of 2005
ROE	Return on Equity
RTO	Regional Transmission Organization
RTOR	Regional Through and Out Rates
S&P	Standard & Poor’s Rating Services
SCR	Selective Catalytic Reduction
SEC	Securities and Exchange Commission
SERP	Supplemental Executive Retirement Plan
SFAS	Statement of Financial Accounting Standards
SIP	State Implementation Plan
SMD	Standard Market Design
SO2	Sulfur Dioxide
SPP	Southwest Power Pool, Inc.
TEMT	Transmission and Energy Markets Tariff
Tennessee Gas	Tennessee Gas Pipeline Company
Texas Gas	Texas Gas Transmission LLC
Trimble County	LG&E’s Trimble County Unit 1
TVA	Tennessee Valley Authority
USWA	United Steelworkers of America
Utility Operations	Operations of LG&E and KU
VDT	Value Delivery Team Process
Virginia Commission	Virginia State Corporation Commission
Virginia Staff	Virginia State Corporation Commission Staff
WNA	Weather Normalization Adjustment

4

Louisville Gas and Electric Company
Selected Financial Data

	YearsEnded December 31
	2005		2004		2003		2002		2001
	(in millions)
LG&E:
Operating revenues	$	1,424	$	1,173	$	1,094	$	1,004	$	965
Net operating income	$	230	$	185	$	179	$	173	$	205
Net income	$	129	$	96	$	91	$	89	$	107
Total assets	$	3,146	$	2,967	$	2,882	$	2,769	$	2,448
Long-term obligations (including amounts due within one year)	$	821	$	872	$	798	$	617	$	617

LG&E’s Management’s Discussion and Analysis of Financial Condition and Results of Operation and LG&E’s Notes to Financial Statements should be read in conjunction with the above information.

5

Louisville Gas and Electric Company
Management’s Discussion and Analysis of Financial Condition and Results of Operations

GENERAL

The following discussion and analysis by management focuses on those factors that had a material effect on LG&E’s financial results of operations and financial condition during 2005, 2004 and 2003 and should be read in connection with the financial statements and notes thereto.

Some of the following discussion may contain forward-looking statements that are subject to risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “expect,” “estimate,” “objective,” “possible,” “potential” and similar expressions. Actual results may materially vary. Factors that could cause actual results to materially differ include: general economic conditions; business and competitive conditions in the energy industry; changes in federal or state legislation; unusual weather; actions by state or federal regulatory agencies; actions by credit rating agencies; and other factors described from time to time in LG&E’s reports to the SEC, including Risk Factors in Item 1A of the report on Form 10-K and in Exhibit No. 99.01 to the report on Form 10-K.

EXECUTIVE SUMMARY

Our Business

LG&E and KU are each subsidiaries of E.ON U.S., which is an indirect subsidiary of E.ON, a German company. LG&E and KU maintain separate corporate identities and serve customers in Kentucky, Virginia and Tennessee under their respective names.

LG&E, incorporated in 1913 in Kentucky, is a regulated public utility that supplies natural gas to approximately 321,000 customers and electricity to approximately 394,000 customers in Louisville and adjacent areas in Kentucky. LG&E’s service area covers approximately 700 square miles in 17 counties and has an estimated population of one million. LG&E also provides natural gas service in limited additional areas. LG&E’s coal-fired electric generating plants, all equipped with systems to reduce SO2 emissions, produce most of LG&E’s electricity. The remainder is generated by a hydroelectric power plant and combustion turbines. Underground natural gas storage fields help LG&E provide economical and reliable natural gas service to customers.

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Our Customers

The following table provides statistics regarding LG&E retail customers:

	LG&E						2005 % Retail Revenues
	Electric			Gas			LG&E
Retail Customer Data	2005	2004	2003	2005	2004	2003	Electric		Gas
	Customers (in thousands)
Residential	347	343	337	296	293	287	40	%	64	%
Industrial & Commercial	41	41	41	24	24	24	50	%	31	%
Other	6	6	6	1	1	1	10	%	5	%
Total Retail	394	390	384	321	318	312	100	%	100	%

Our Mission

The mission of LG&E is to build on our tradition and achieve world-class status providing reliable, low-cost energy services and superior customer satisfaction; and to promote safety, financial success and quality of life for our employees, communities and other stakeholders.

Our Strategy

LG&E’s strategy focuses on the following:

·Achieve scale as an integrated U.S. electric and gas business through organic growth;

·Maintain excellent customer satisfaction;

·Maintain best-in-class cost position versus U.S. utility companies;

·Develop and transfer best practices throughout the company;

·Invest in infrastructure to meet expanding load and comply with increasing environmental requirements;

·Achieve appropriate regulated returns on all investment;

·Attract, retain and develop the best people; and

·Act with a commitment to corporate social responsibility that enhances the well being of our employees, demonstrates environmental stewardship, promotes quality of life in our communities and reflects the diversity of the society we serve.

Low Rates

LG&E believes it is well positioned in the regulated Kentucky market. LG&E and KU continue to sustain high customer satisfaction, ranking first among all large Midwest utilities for the 6th time in 7 years in the J.D. Power and Associates 2005 survey of residential electric customers. This excellent performance is balanced with cost control. The customer benefits of the LG&E culture of cost management are evident in rate comparisons among U.S. utilities. The following chart compares the total residential average rate per thousand Kwh of U.S. investor-owned utilities as of July 1, 2005:

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Source: Edison Electric Institute, Summer 2005 Typical Bills and Average Rates Report; Residential
rates in effect July 1, 2005, based on 1,000 kWh monthly usage.

LG&E must continue to address new cost pressures. The Kentucky Commission accepted the settlement agreements reached by the majority of the parties in the rate cases filed by LG&E in December 2003. New rates, implemented in July 2004, produced approximately $55 million of revenue for LG&E for a full year. Under the settlement agreements, the LG&E utility base electric rates have increased approximately $43 million (7.7%) and base natural gas rates have increased approximately $12 million (3.4%) annually. The 2004 increases were the first increases in electric base rates for LG&E in 13 years; the last natural gas rate increase for the LG&E natural gas utility took effect in September 2000. Competitors also face these same cost pressures that caused LG&E to initiate rate cases (e.g., pensions, benefits and reliability expenditures) and many other utility companies already have rate cases in process. Despite these increases, LG&E rates remain significantly lower than the national average.

Commodity Prices: Fuel and Electricity

Natural gas prices have risen dramatically in 2005, averaging over $8/MMBtu and spiking as high as $15/MMBtu in late September following the hurricanes that interrupted natural gas production activities in the Gulf of Mexico. Although the supply problems created by the hurricanes have improved significantly, the underlying and fundamental U.S. supply-demand imbalance shows no sign of easing. While U.S. natural gas reserves are in structural decline, natural gas demand is increasing. The natural gas outlook is projected to maintain this pattern until significant new supply, in the form of LNG or new discoveries, enters the marketplace.

Coal price increases continued during 2005, up nearly 60% overall since the beginning of 2004, with modest increases projected over the near term. The rise in oil and natural gas prices, combined with the supply of coal not keeping pace with demand, have resulted in substantially higher coal prices over the last two years.

8

The graph displays the LG&E, KU and combined utility average utility natural gas and coal purchase prices.

Actual natural gas costs are recovered from customers through the GSC. The GSC also contains an incentive component, the PBR component, which is determined for each 12-month period ending October 31.

Actual fuel costs associated with retail electric sales are recovered from customers through the FAC. The Utilities’ base rates contain an embedded fuel cost component. The FAC reconciles the difference between this fuel cost component 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.

With respect to wholesale electricity prices, generation over-capacity in the Midwest United States is forecasted to persist, with reserve margins over 23% for ECAR in 2006. However, the over-capacity results largely from the construction of natural gas-fired units. High natural gas prices have supported higher wholesale electricity prices, providing advantages to coal-fired generation. While the regional reserve margin is expected to decline over time as new capacity construction slows and demand grows, natural gas-fired generation is expected to set prices, particularly during times of higher loads. This expectation, combined with the expectation that natural gas prices will remain high, indicates that peak electricity prices are expected to remain high.

Generation Reliability

Generation reliability also remains a key aspect to meeting our strategy. LG&E believe that it has maintained good performance and reliability in the key area of utility generation operation. While maintaining low cost levels, LG&E has also been able to generate increasing volumes and expect to continue high levels of availability and low outage levels. This performance is also important to maintaining margins from off-system sales.

Generation Capacity

The installation of Trimble County Units 7-10, completed in 2004, increased total system capability by 9%. However, the IRP submitted by LG&E and KU to the Kentucky Commission in 2005, outlining the least cost alternative to meet Kentucky’s needs, indicated the requirement for additional base-load capacity by 2010. Consequently, LG&E and KU have begun development efforts for another base-load coal-fired unit at the Trimble County site. LG&E and KU believe this is the least cost alternative to meet the future needs of

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customers. Trimble County Unit 2, with a 750 MW capacity rating, is expected to be jointly owned by LG&E and KU (75% owners of the unit) and IMEA and IMPA (25% owners). Trimble County Unit 2 is expected to cost $1.1 billion and be completed by 2010. LG&E’s and KU’s aggregate 75% share of the total Trimble County Unit 2 capital cost is approximately $885 million and is estimated to be approximately $120 million and $510 million, respectively, through 2008.

An application for a construction CCN was filed with the Kentucky Commission in December 2004 and initial CCN applications for three transmission lines were filed in early 2005, with further applications submitted in December 2005. The proposed air permit was filed with the Kentucky Division for Air Quality in December 2004. In November 2005, the Kentucky Commission approved the application of LG&E and KU to expand the Trimble County generating plant. Kentucky Commission approval for one transmission line CCN was granted in September 2005 and a ruling that a second transmission line was not subject to the CCN process was received in February 2006. LG&E and KU hope to obtain approval for the remaining transmission line CCN during 2006. The transmission lines are also subject to routine regulatory filings and the right-of-way acquisition process. In November 2005, the Kentucky Division for Air Quality issued the final air permit, which was challenged in December 2005 by an environmental advocacy group. Administrative proceedings with respect to the challenge are expected to commence during the first quarter of 2006.

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 intends to spend approximately $76 million to refurbish the facility and add approximately 20 Mw of generating capacity over the next seven years.

Environmental Matters

In addition to the Trimble County Unit 2 project, the second major area of utility investment is environmental expenditures. LG&E and KU are subject to SO2 and NOx emission limits on their electric generating units pursuant to the Clean Air Act. LG&E and KU placed into operation significant NOx controls for their generating units prior to the 2004 summer ozone season. As of December 31, 2005, LG&E and KU have incurred total capital costs of approximately $188 million and $217 million, respectively, since 2000 to reduce their NOx emissions below required levels. In addition, LG&E and KU have incurred additional operating and maintenance costs in operating the new NOx controls.

In March 2005, the EPA issued the final CAIR which requires substantial additional reductions in SO2 and NOx emissions from electric generating units. The CAIR provides for a two-phased reduction program with Phase I reductions in NOx and SO2 emissions in 2009 and 2010, respectively, and Phase II reductions in 2015. On March 15, 2005, the EPA issued a related regulation, the final CAMR, which requires substantial mercury reductions from electric generating units. CAMR also provides for a two-phased reduction, with the Phase I target in 2010 achieved as a “co-benefit” of the controls installed to meet CAIR. Additional control measures will be required to meet the Phase II target in 2018. Both CAIR and CAMR establish a cap and trade framework, in which limits are set on total emissions and allowances can be bought or sold on the open market, to be used for compliance, unless the state chooses another approach.

In order to meet these new regulatory requirements, KU has implemented a plan for adding significant additional SO2 controls to its generating units. Installation of additional SO2 controls will proceed on a phased basis, with construction of controls (i.e., FGDs) having commenced in September 2005, and continuing through the final installation and operation in 2009. KU estimates that it will incur approximately $560 million in capital

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costs related to the construction of the FGDs over the next three years to achieve compliance with current emission limits on a company-wide basis. In addition, KU will incur additional operating and maintenance costs in operating the new SO2 controls. LG&E currently has FGDs on all its units but will continue to evaluate improvements to further reduce SO2 emissions.

Kentucky law permits LG&E and KU to recover the costs of complying with the Federal Clean Air Act, including a return of operating expenses, and a return of and on capital invested, through the ECR mechanism. Approximately 80% of the applicable environmental costs, including investment and operating costs, are recoverable through the ECR. The remaining 20%, attributable to off-system and non-Kentucky jurisdictional sales, are not recoverable through the ECR.

COMPANY STRUCTURE

As contemplated in their regulatory filings in connection with the E.ON acquisition of Powergen in 2002, E.ON, Powergen and E.ON U.S. completed an administrative reorganization to move the LG&E Energy Corp. group from an indirect Powergen subsidiary to an indirect E.ON subsidiary. This reorganization was effective in March 2003. In early 2004, E.ON U.S. began direct reporting arrangements to E.ON.

Effective December 30, 2003, LG&E Energy LLC became the successor, by assignment and subsequent merger, to all the assets and liabilities of LG&E Energy Corp.

Effective December 1, 2005, LG&E Energy LLC was renamed E.ON U.S. LLC.

The utility operations of E.ON U.S. have continued their separate identities as LG&E and KU. The preferred stock and debt securities of LG&E and KU were not affected by these transactions.

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RESULTS OF OPERATIONS

LG&E

Net Income

LG&E’s net income in 2005 increased $33.3 million (34.8%) compared to 2004. The increase resulted primarily from higher electric revenues due to increased retail sales volumes resulting from warmer summer weather and increased base rates implemented for service rendered on and after July 1, 2004. Wholesale revenues also increased due to higher volumes and higher prices. These increases were partially offset by increased fuel and power purchased costs largely due to MISO Day 2 costs.

LG&E’s net income in 2005 related to the electric business increased $32.2 million (36.9%) compared to 2004. Electric operating revenues increased $171.7 million (21.0%), partially offset by higher fuel for electric generation and power purchased of $122.6 million (40.8%). Income tax and depreciation expense increased $11.7 million (24.2%) and $6.2 million (6.2%), respectively.

LG&E’s net income in 2005 related to the natural gas business increased $1.1 million (13.1%) compared to 2004. Natural gas operating revenues increased $79.8 million (22.3%) offset by higher natural gas supply expenses of $73.4 million (27.6%). Other natural gas operations and maintenance expenses increased $3.6 million (7.2%) and depreciation expense increased $1.3 million (7.8%).

During 2005, LG&E made out-of-period adjustments for estimated over/under collection of ECR revenues to be billed in subsequent periods. The adjustments related to the reporting periods of March 2003 through December 2004. As a result, LG&E revenues for 2005 increased by $5.3 million and net income for 2005 increased by $3.2 million. LG&E revenues for 2004 and 2003 were understated by $2.4 million and $2.9 million, respectively, and net income was understated by $1.4 million and $1.8 million, respectively.

LG&E’s net income in 2004 increased $4.8 million (5.3%) compared to 2003. The increase resulted primarily from higher electric revenues due to increased base rates implemented for service rendered on and after July 1, 2004, following the electric rate case order and higher wholesale revenues, somewhat offset by higher maintenance expenses related to storm restoration costs. Operating expenses for 2004 reflect $12.7 million in expenses related to severe May and July storms.

LG&E’s net income in 2004 related to the electric business increased $6.6 million (8.2%) compared to 2003. Electric operating revenues increased $47.5 million (6.2%), offset by higher fuel for electric generation and power purchased of $22.8 million (8.2%). Other electric operations and maintenance expenses increased $11.1 million (4.9%). Electric depreciation expense increased $3.5 million (3.6%). Interest expense increased $1.6 million (6.2%).

LG&E’s net income in 2004 related to the natural gas business decreased $1.8 million (17.6%) compared to 2003. Natural gas operating revenues increased $31.8 million (9.8%) offset by higher natural gas supply expenses of $32.4 million (13.9%). Other natural gas operations and maintenance expenses increased $2.0 million (4.2%).

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Revenues

The following table presents a comparison of operating revenues for the years 2005 and 2004 with the immediately preceding year.

	Increase (Decrease) From Prior Period
	Electric Revenues						Gas Revenues
Cause	2005			2004			2005			2004
	(in millions)
Retail sales:
Fuel and gas supply adjustments	$	23.3		$	5.8		$	66.6		$	33.6
LG&E/KU Merger surcredit	(1.0		)	(2.3		)	—			—
Environmental cost recovery surcharge	10.0			7.3			—			—
Earnings sharing mechanism	(5.6		)	(5.8		)	—			—
Demand side management	(0.3		)	0.4			—			(0.6		)
VDT surcredit	(0.9		)	(1.1		)	(0.6		)	0.1
Weather normalization adjustment	—			—			(2.7		)	3.2
Rate changes	24.8			16.8			4.9			7.0
Variation in sales volumes and other	27.5			11.8			(0.1		)	(5.8		)
Total retail sales	77.8			32.9			68.1			37.5
Wholesale	73.7			15.8			11.8			(5.1		)
MISO Day 2	18.2			—			—			—
Gas transportation-net	—			—			(0.7		)	0.1
Other	2.0			(1.2		)	0.6			(0.7		)
Total	$	171.7		$	47.5		$	79.8		$	31.8

Electric revenues increased in 2005 primarily due to higher wholesale sales and MISO related revenues, higher fuel costs billed to the customer through the fuel adjustment clause and new rates implemented in July 2004. These increases were partially offset by the discontinuation of the ESM in the second quarter of 2005. Retail revenues increased 5.4% due to higher sales volume, primarily due to warmer summer weather than experienced in 2004. Cooling degree days increased 13% compared to 2004 and were 14% higher than the 20-year average. Wholesale revenues increased due to the combination of a 29% increase in prices and 11% higher volumes. The price increase was largely due to higher fuel prices and the volume increase was primarily due to increased demand for LG&E generation in the region.

Electric revenues increased in 2004 primarily due to new rates implemented in July 2004. Retail revenues increased 2.0% due to higher sales volume, primarily due to warmer summer weather than 2003. Cooling degree days increased 21% compared to 2003 and were 2% higher than the 20-year average.

Natural gas revenues in 2005 increased due to higher gas supply cost billed to customers through the gas supply clause and increased natural gas rates. New natural gas rates took effect in July 2004 increasing revenues by 1.3% in 2005. Despite remaining 1% lower than the 20-year average, the number of heating degree days in 2005 increased 6% as compared to 2004. This increase in heating degree days was offset by the effect of higher natural gas prices which curtailed natural gas usage and resulted in slightly lower natural gas sales volumes.

Natural gas revenues in 2004 increased due to higher gas supply cost billed to customers through the gas supply clause and increased gas rates. New natural gas rates took effect in July 2004 increasing revenues by 2.3% in 2004. These increases were partially offset by lower retail sales due to warmer winter weather and lower wholesale sales. Heating degree days decreased 8% as compared to 2003 and were 8% lower than the 20-year average.

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Expenses

Fuel for electric generation and natural gas supply expenses comprise a large component of LG&E’s total operating costs. The retail electric rates contain an FAC and natural gas rates contain a GSC, whereby increases or decreases in the cost of fuel and natural gas supply are reflected in the FAC and GSC factors, subject to approval by the Kentucky Commission, and passed through to LG&E’s retail customers.

Fuel for electric generation increased $74.1 million (35.6%) in 2005 primarily due to:

·Increased cost of fuel burned ($61.8 million) due to the MISO’s dispatch of natural gas-fired units and higher coal and natural gas prices

·Increased generation ($12.3 million) due to increased demand and the dispatch of units for MISO Day 2

Fuel for electric generation increased $10.3 million (5.2%) in 2004 primarily due to:

·Increased cost of fuel burned ($6.4 million) due to higher fuel prices

·Increased generation ($3.7 million) due to increased demand

Power purchased increased $48.5 million (52.7%) in 2005 primarily due to:

·Increased unit cost per Mwh of purchases ($40.7 million) due to higher fuel prices

·Increased volumes purchased ($7.7 million) due to increased demand and unit outages

oPurchased power costs from the MISO due to unit outages totaled $9.8 million

Power purchased increased $12.5 million (15.7%) in 2004 primarily due to:

·Increased unit cost per Mwh of purchases ($9.0 million) due to higher fuel prices

·Increased volumes purchased ($3.4 million) due to increased demand and unit outages

Gas supply expenses increased $73.4 million (27.6%) in 2005 primarily due to:

·Increased cost of net gas supply ($61.7 million) due to the increase in natural gas prices in 2005

·Increased volumes of natural gas delivered to the distribution system ($11.7 million)

Gas supply expenses increased $32.4 million (13.9%) in 2004 primarily due to:

·Increased cost of net gas supply ($52.2 million) due to the increase in natural gas prices in 2004

·Decreased volumes of natural gas delivered to the distribution system ($19.8 million)

Other operation and maintenance expenses increased $3.1 million (1.0%) in 2005 primarily due to higher other operation expense ($10.6 million) and higher property taxes ($1.7 million), partially offset by lower maintenance expense ($9.2 million).

Other operation expenses increased $10.6 million (4.9%) in 2005 primarily due to:

·Increased other power supply costs ($17.2 million) due largely to MISO Day 2 costs ($18.2 million) for administrative and allocated charges from the MISO for Day 2 operations

·Increased steam generation expenses ($3.5 million) primarily for scrubber reactant and waste disposal

·Increased employee benefit costs ($3.3 million)

·Increased customer service and collection expenses ($2.0 million)

·Decreased transmission costs ($10.5 million), due largely to MISO Day 2 ($13.4 million). Prior to the MISO Day 2 market, most bilateral transactions required the purchase of transmission; however, with the Day 2 market, most transactions are handled directly with the MISO and no additional transmission is necessary

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·Decreased distribution operating costs ($5.0 million) due to fewer storms in 2005

Maintenance expenses decreased $9.2 million (12.7%) in 2005 primarily due to:

·Decreased distribution maintenance ($8.5 million) due to fewer storms in 2005

·Decreased steam generation expense ($2.1 million)

·Increased administrative and general maintenance expenses ($1.3 million)

Other operation and maintenance expenses increased $14.6 million (5.0%) in 2004 primarily due to higher maintenance expenses ($15.6 million) and higher property and other taxes ($1.6 million), partially offset by lower operation expenses ($2.5 million).

Maintenance expenses increased $15.6 million (27.3%) in 2004 primarily due to:

·Increased distribution maintenance expense ($10.0 million) primarily due to restoration costs related to severe May and July storms

·Increased natural gas system maintenance and administrative and general expenses ($2.6 million)

·Increased steam generation expense due to timing of scheduled maintenance ($1.4 million)

·Increased combustion turbine and hydro generation maintenance ($1.6 million)

Other operation expenses decreased $2.5 million (1.2%) in 2004 primarily due to:

·The KU/LG&E merger costs and the One Utility initiative costs were fully amortized in 2003, resulting in $2.8 million lower expense in 2004

·Decreased benefits expense ($1.7 million), primarily due to lower pension expense ($2.1 million) as a result of the $34.5 million pension funding in January 2004, partially offset by higher medical insurance expense

·Decreased steam generation expense ($1.2 million)

·Increased operations expense due to storm restoration costs related to severe storms in May and July 2004 ($3.1 million)

Depreciation and amortization increased $7.5 million (6.4%) in 2005 and $3.3 million (2.9%) in 2004 due to additional plant in service.

Other income (expense)—net increased $4.0 million (121.2%) in 2005 primarily due to:

·Increased non-operating income ($2.3 million)

·Decreased income deductions ($1.3 million)

·Increased interest income ($0.3 million)

Other income (expense)—net increased $3.9 million (54.2%) in 2004 primarily due to:

·Decreased income deductions ($3.0 million) primarily for 2003 write-offs of terminated projects

·Increased other income ($0.9 million)

Interest expense increased $4.0 million (12.2%) in 2005 primarily due to:

·Increased interest rates on variable-rate debt ($6.4 million)

·Increased borrowing from the money pool ($1.5 million)

·Decreased cost of interest rate swaps ($3.2 million)

·Decreased costs due to refinancing fixed rate debt with variable rate debt ($0.8 million)

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Interest expense increased $2.1 million (6.8%) in 2004 primarily due to:

·Increased borrowing from Fidelia ($6.9 million)

·Increased cost of interest rate swaps ($3.0 million)

·Increased cost of variable-rate debt ($0.8 million)

·Decreased cost due to lower first mortgage debt ($7.2 million)

·Decreased borrowing from the money pool ($1.4 million)

Details of LG&E’s exposure to variable interest rates on long-term debt are shown in the table below:

	2005			2004			2003
Unswapped variable rate debt ($in millions)	$	363.0		$	306.0		$	306.0
Percentage of unswapped variable rate debt to total long-term debt	44.2		%	35.1		%	38.3		%
Weighted average interest rate on variable rate debt for the year	2.49		%	1.28		%	1.10		%
Weighted average interest rate on total long-term debt at year-end, including expense amortization and interest rate swaps	4.13		%	3.92		%	3.58		%

See Note 8 of LG&E’s Notes to the Financial Statements under Item 8.

Variations in income tax expenses are largely attributable to changes in pre-tax income. LG&E’s 2005 effective income tax rate decreased to 33.5% from the 35.8% rate in 2004 primarily due to the reduction in tax accruals after the conclusion of IRS audits. See Note 7 of LG&E’s Notes to Financial Statements under Item 8.

The rate of inflation may have a significant impact on LG&E’s operations, its ability to control costs and the need to seek timely and adequate rate adjustments. However, relatively low rates of inflation in the past few years have moderated the impact on current operating results.

CRITICAL ACCOUNTING POLICIES/ESTIMATES

Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, 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 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. Specific risks for these critical accounting policies are described in the following paragraphs. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Events rarely develop exactly as forecasted and the best estimates routinely require adjustment. See also Note 1 of LG&E’s Notes to Financial Statements under Item 8.

Unbilled Revenue—At each month end LG&E prepares a financial estimate that projects electric and natural gas usage by customers that has not been billed. The estimated usage is based on allocating the daily system net deliveries between billed volumes and unbilled volumes. The allocation is based on a daily ratio of the number of meter reading cycles remaining in the month to the total number of meter reading cycles in each month. Each day’s ratio is then multiplied by each day’s system net deliveries to determine an estimated billed and unbilled volume for each day of the accounting period. At December 31, 2005, a 10% change in these estimated quantities would cause revenue and accounts receivable to change by approximately $8.2 million,

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including $3.2 million for electric usage and $5.0 million for natural gas usage. See also Note 1 of LG&E’s Notes to Financial Statements under Item 8.

Allowance for Doubtful Accounts—At December 31, 2005 and 2004, the LG&E allowance for doubtful accounts was $1.1 million and $0.8 million, respectively. The allowance 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.

Pension and Post-retirement Benefits—LG&E has both funded and unfunded non-contributory defined benefit pension and post-retirement benefit plans that together cover substantially all of its employees. The plans are accounted for under SFAS No. 87, Employers’ Accounting for Pensions, and SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other than Pensions.

The pension and other post-retirement benefit plan costs and liabilities are determined on an actuarial basis and are dependent upon numerous economic assumptions, such as discount rates, rates of compensation increases, estimates of the expected return on plan assets and health care cost trend rates and demographic and economic assumptions. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower health care costs or turnover, or longer or shorter life spans of participants. These differences may result in a significant impact on the amount of expenses recorded in future periods. The underlying assumptions and estimates related to the pension and post-retirement benefit plan costs and liabilities are reviewed annually.

The assumed discount rate, expected return on assets and rate of compensation increases generally have the most significant impact on the pension costs and liabilities. The discount rate is used to calculate the actuarial present value of the benefits provided by the plans. LG&E bases its discount rate assumption on Moody’s Aa Corporate Bond Rate rounded to the nearest 25 basis points, which has a duration comparable to the weighted average duration of the plans.

The expected long-term rate of return on assets is used to calculate the net periodic pension costs for the plans. To develop the expected long-term rate of return on assets assumption, consideration is given to the current level of expected returns on risk free investments (primarily government bonds), the historical performance of the asset managers versus their respective benchmarks, 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 a target asset allocation. For 2005, the actual return on pension assets was comparable to the assumed expected rate of return.

The following describes the effects on pension benefits by changing the major actuarial assumptions discussed above:

·A 1% change in the assumed discount rate could have an approximate $48.8 million positive or negative impact to the 2005 accumulated benefit obligation of LG&E.

·A 25 basis point change in the expected rate of return on assets would have an approximate $0.8 million positive or negative impact on 2005 pension expense.

Compensation rate increases are used to calculate service costs and the projected benefit obligation. Such rates are based on a review of LG&E’s actual historical salaries, promotion and bonus increases. For 2005 net periodic

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pension benefit costs, LG&E used an assumption of 4.50%. Based on plan experience, the rate was increased to 5.25% for the projected benefit obligation at December 31, 2005.

When the plan experience differs from the actuarial assumptions, a portion of the difference may be deferred and is subject to amortization at rates based on the estimated average years of participants’ future service. LG&E’s deferred losses on these assumptions were $24.4 million (35%) higher in 2005 than 2004 and $14.0 million (25%) higher in 2004 than 2003, primarily due to declining discount rate assumptions during these years.

The assumptions related to the discount rate, retirement, turnover and healthcare cost trends, which represent expected rates of increase in health care claim payments, generally have the most significant impact on LG&E’s post-retirement benefit plan costs and liabilities. Unlike pensions, however, assumptions about per capita claims cost by age and participation rates also significantly impact post-retirement liability computations. A 1% change in the healthcare cost trend rates could have a positive or negative impact on the 2005 post-retirement benefit obligation and post-retirement expense of approximately $3.0 million and $0.3 million, respectively.

Additionally, demographic and other economic assumptions affect the pension and post-retirement computations. Beginning with the December 31, 2005 liability, LG&E replaced the 1983 Group Annuity Mortality tables for males and females with the RP 2000 combined tables for males and females projected to 2006. These updated healthy mortality tables will be used for the 2006 expense.

The benefit obligation is compared with the plan asset values to determine a net position. Asset values are increased primarily by actual rates of return on plan assets and by employer contributions. For explanation of the investment policy including targeted asset allocations, see Note 6 of LG&E’s Notes to Financial Statements under Item 8.

The pension plans are funded in accordance with all applicable requirements of the ERISA and the IRC. In accordance with the ERISA guidelines, LG&E made discretionary contributions to the pension plans of $89.1 million in 2003 and $34.5 million in 2004. No contributions were made in 2005. LG&E made a discretionary contribution of $17.5 million during 2006 and anticipates making additional contributions as deemed necessary. Additionally, LG&E made a contribution of $0.7 million to the post-retirement plan in 2005, representing the maximum employer contribution under IRC Section 401(h) requirements for all plan years through 2004. LG&E may continue to make subsequent contributions in accordance with the maximum funding limitation governed by tax laws.

As prescribed by SFAS No. 87, LG&E was required to recognize an additional minimum pension liability of $19.2 million and $10.2 million during 2005 and 2004, respectively, since the fair value of the plan assets was less than the accumulated benefit obligation at that time. This additional minimum pension liability was recorded as a reduction to other comprehensive income and did not affect net income. Historically low corporate bond rates, used to determine the discount rate, significantly increased the potential value of the pension liabilities above the actual value of the plan assets. If the fair value of the plan assets exceeds the accumulated benefit obligation, the recorded liability will be reduced and other comprehensive income will be restored in the balance sheet. In 2003, LG&E recognized a reduction of the minimum pension liability of $3.1 million.

Should poor market conditions return or should interest rates decline further, LG&E’s unfunded accumulated benefit obligations and future pension expense could increase. The Company believes that such increases are recoverable in whole or in part under future rate proceedings or mechanisms.

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See also Note 6 and Note 14 of LG&E’s Notes to Financial Statements under Item 8.

Regulatory Mechanisms—Judgments and uncertainties include future regulatory decisions, the impact of deregulation and competition on ratemaking process, and external regulatory decisions. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates based upon Kentucky Commission orders. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections based upon orders by the Kentucky Commission. Management believes, based on orders, the existing regulatory assets and liabilities are probable of recovery. This determination reflects the current regulatory climate in the state. If future recovery of costs ceases to be probable the assets and liabilities would be required to be recognized in current period earnings.

See also Note 3 of LG&E’s Notes to Financial Statements under Item 8.

Income Taxes—Incometaxes are accounted for under SFAS No. 109, Accounting for Income Taxes. In accordance with this statement, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, as measured by enacted tax rates that are expected to be in effect in the periods when the deferred tax assets and liabilities are expected to be settled or realized. Significant judgment is required in determining the provision for income taxes, and there are transactions for which the ultimate tax outcome is uncertain.

To provide for these uncertainties or exposures, an allowance is maintained for tax contingencies based on management’s best estimate of probable loss. Tax contingencies are analyzed periodically and adjustments are made when events occur to warrant a change. On September 19, 2005, LG&E received notice from the Congressional Joint Committee on Taxation approving the Internal Revenue Service’s audit of LG&E’s income tax returns for the periods December 1999 through December 2003. As a result of resolving numerous tax matters during these periods, LG&E reduced income tax accruals by $3.8 million during 2005.

H. R. 4520, known as the “American Jobs Creation Act of 2004” allows electric utilities to take a deduction of up to 3% of their qualified production activities income in 2005. This deduction reduced LG&E’s effective tax rate by less than 1% for 2005.

Kentucky House Bill 272, also known as “Kentucky’s Tax Modernization Plan,” was signed into law in March 2005. This bill contains a number of changes in Kentucky’s tax system, including the reduction of the Corporate income tax rate from 8.25% to 7% effective January 1, 2005, and a further reduction to 6% effective January 1, 2007. As a result of the income tax rate change, LG&E’s deferred tax reserve amount will exceed its actual deferred tax liability attributable to existing temporary differences since the new statutory rates are lower than the rates were when the deferred tax liability originated. This excess amount is referred to as excess deferred income taxes. In June 2005, LG&E received approval from the Kentucky Commission to establish and amortize a regulatory liability ($16.3 million) for its net excess deferred income tax balances. Under this accounting treatment, LG&E will amortize its depreciation-related excess deferred income tax balances under the average rate assumption method. The average rate assumption method matches the amortization of the excess deferred income taxes with the life of the timing differences to which it relates. Excess deferred income tax balances related to non-depreciation timing differences will be expensed in the current year due to their immaterial amount.

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LG&E expects to have adequate levels of taxable income to realize its recorded deferred taxes.

For further discussion of income tax issues, see Note 1 and Note 7 of LG&E’s Notes to Financial Statements under Item 8.

NEW ACCOUNTING PRONOUNCEMENTS

The following recent accounting pronouncements affected LG&E in 2005 and 2004:

FIN 47

LG&E adopted Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143 (FIN 47) effective December 31, 2005. FIN 47 expands the term “conditional asset retirement obligation” as used in SFAS No. 143, Accounting for Asset Retirement Obligations, to refer to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. An entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred; generally, upon acquisition, construction, or development and through the normal operation of the asset.

As a result of the implementation of FIN 47, LG&E recorded additional ARO net assets and liabilities during the fourth quarter of 2005 in the amount of $1.0 million and $15.7 million, respectively. LG&E also recorded a cumulative effect adjustment in the amount of $12.3 million to reflect the accumulated depreciation and accretion of ARO assets at the transition date less amounts previously accrued under regulatory depreciation. A $2.4 million reduction in the accumulated cost of removal regulatory liability was also recorded for this previously accrued cost of removal. LG&E recorded offsetting regulatory assets of $12.3 million, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, as the costs of removal are allowed under Kentucky Commission ratemaking.

Had FIN 47 been in effect at the beginning of the 2004 reporting period, LG&E would have established asset retirement obligations as described in the following table (in millions):

	2005		2004
Provision at beginning of the year	$	14.8	$	14.0
Accretion expense	0.9		0.8
Provision at end of the year	$	15.7	$	14.8

See Note 1 of LG&E’s Notes to Financial Statements under Item 8 for further discussion of FIN 47.

LIQUIDITY AND CAPITAL RESOURCES

LG&E uses net cash generated from its operations and external financing (including financing from affiliates) to fund construction of plant and equipment and the payment of dividends. LG&E believes that such sources of funds will be sufficient to meet the needs of its business in the foreseeable future.

As of December 31, 2005, LG&E is in a negative working capital position in part because of the classification

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of certain variable-rate pollution control bonds totaling $246.2 million that are subject to tender for purchase at the option of the holder as current portion of long-term debt. Backup credit facilities totaling $185 million are in place to fund such tenders if necessary. LG&E has never needed to access these facilities. LG&E expects to cover any working capital deficiencies with cash flow from operations, money pool borrowings and borrowings from Fidelia.

Operating Activities

Cash provided by operations was $150.4 million, $171.6 million and $163.3 million in 2005, 2004 and 2003, respectively.

The 2005 decrease of $21.2 million was primarily the result of changes in:

·Inventory ($60.6 million) largely the result of increased coal and gas prices

·Deferred income taxes ($19.8 million)

·Accounts receivable ($18.1 million) primarily due to colder December weather

·Gas supply recovery ($13.5 million) primarily due to higher natural gas prices

·Prepayments and other ($9.3 million)

·ESM recovery ($8.1 million) due to termination of the ESM program

These decreases were partially offset by changes in:

·Accounts payable ($48.8 million) primarily from the increase in natural gas prices

·Earnings ($33.3 million)

·Pension funding ($24.7 million)

The 2004 increase of $8.3 million was primarily the result of changes in:

·Pension funding ($54.6 million)

·Gas supply cost recovery ($15.0 million)

·ESM ($10.1 million)

·Prepayments and other ($5.9 million)

·Receipt of a litigation settlement ($7.0 million)

These increases were partially offset by changes in:

·Accounts receivable ($66.3 million), including the termination of the accounts receivable securitization program

·Accrued income taxes ($22.4 million)

See Note 4 of LG&E’s Notes to Financial Statements under Item 8 for a discussion of accounts receivable securitization.

Investing Activities

LG&E’s primary use of funds for investing activities continues to be for capital expenditures. Capital expenditures were $138.9 million, $148.3 million and $213.0 million in 2005, 2004 and 2003, respectively. LG&E expects its capital expenditures for the three-year period ending December 31, 2008, to total approximately $530 million, which consists primarily of construction estimates associated with the redevelopment of the Ohio Falls hydro facility totaling approximately $26 million, construction of Trimble County Unit 2 totaling approximately $120 million and on-going construction related to generation and distribution assets.

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Net cash used for investing activities decreased $21.1 million in 2005 compared to 2004 and $53.7 million in 2004 compared to 2003, primarily due to the level of construction expenditures.

Financing Activities

Net cash inflows (outflows) for financing activities were $(12.1) million, $(7.4) million and $34.2 million in 2005, 2004 and 2003, respectively.

Redemptions and maturities of long-term debt for 2005, 2004 and 2003 are summarized below:

Year	Description	Principal Amount		Rate		Secured/ Unsecured	Maturity
		($ in millions)
2005	Pollution control bonds	$	40.0	5.90	%	Secured	Apr 2023
2005	Due to Fidelia	$	50.0	1.53	%	Secured	Jan 2005
2005	Mandatorily Redeemable Preferred Stock	$	1.3	5.875	%	Unsecured	Jul 2005
2004	Due to Fidelia	$	50.0	1.53	%	Secured	Jan 2005
2004	Mandatorily Redeemable Preferred Stock	$	1.3	5.875	%	Unsecured	Jul 2004
2003	Pollution control bonds	$	102.0	5.625	%	Secured	Aug 2019
2003	Pollution control bonds	$	26.0	5.45	%	Secured	Oct 2020
2003	First Mortgage Bonds	$	42.6	6.00	%	Secured	Aug 2003
2003	Mandatorily Redeemable Preferred Stock	$	1.3	5.875	%	Unsecured	Jul 2003

Issuances of long-term debt for 2005, 2004 and 2003 are summarized below:

Year	Description	Principal Amount		Rate		Secured/ Unsecured	Maturity
		($ in millions)
2005	Pollution control bonds	$	40.0	Variable		Secured	Feb 2035
2004	Due to Fidelia	$	25.0	4.33	%	Secured	Jan 2012
2004	Due to Fidelia	$	100.0	1.53	%	Secured	Jan 2005
2003	Pollution control bonds	$	128.0	Variable		Secured	Oct 2033
2003	Due to Fidelia	$	100.0	4.55	%	Unsecured	Apr 2013
2003	Due to Fidelia	$	100.0	5.31	%	Secured	Aug 2013

Future Capital Requirements

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, market entry of competing electric power generators, changes in environmental regulations and other regulatory requirements. LG&E anticipates funding future capital requirements through operating cash flow, debt, and/or infusions of capital from its parent.

LG&E has a variety of funding alternatives available to meet its capital requirements. LG&E maintains a series of bilateral credit facilities with banks totaling $185 million. Several intercompany financing arrangements are also available. LG&E participates in an intercompany money pool agreement wherein E.ON U.S. and/or KU

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make funds available to LG&E at market-based rates up to $400 million. Fidelia also provides long-term intercompany funding to LG&E. See Note 9 of LG&E’s Notes to Financial Statements under Item 8.

Regulatory approvals are required for LG&E to incur additional debt. The FERC authorizes the issuance of short-term debt while the Kentucky Commission authorizes issuance of long-term debt. In February 2006, LG&E received a two-year authorization from the FERC to borrow up to $400 million in short-term funds.

LG&E’s debt ratings as of December 31, 2005, were:

	S&P	Moody’s
First mortgage bonds	A1	A-
Preferred stock	Baa1	BBB-
Commercial paper	P-1	A-2

These ratings reflect the views of Moody’s and S&P. 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.

Contractual Obligations

The following is provided to summarize LG&E’s contractual cash obligations for periods after December 31, 2005. LG&E anticipates cash from operations and external financing will be sufficient to fund future obligations. Future interest obligations cannot be quantified because most of LG&E’s debt is variable rate. (See LG&E’s Statements of Capitalization)

	Payments Due by Period
Contractual Cash Obligations	2006		2007		2008		2009		2010		Thereafter			Total
	(in millions)
Short-term debt(a)	$	141.2	$	—	$	—	$	—	$	—	$	—		$	141.2
Long-term debt	1.3		1.3		18.7		—		—		799.3		(b)	820.6
Operating lease(c)	3.5		3.6		3.7		3.8		3.8		18.5			36.9
Unconditional power purchase obligations(d)	11.1		10.9		11.0		11.3		11.5		215.1			270.9
Coal and gas purchase obligations(e)	248.0		197.6		201.2		174.2		188.6		199.8			1,209.4
Retirement obligations(f)	36.7		36.3		35.7		35.0		34.3		166.1			344.1
Other obligations(g)	23.0		—		—		—		—		—			23.0
Total contractual cash obligations	$	464.8	$	249.7	$	270.3	$	224.3	$	238.2	$	1,398.8		$	2,846.1

(a)Represents borrowings from affiliated company due within one year.

(b)Includes long-term debt of $246.2 million classified as current liabilities 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. Maturity dates for these bonds range from 2013 to 2027. LG&E does not expect to pay these amounts in 2006.

(c)Operating lease represents the lease of LG&E’s administrative office building.

(d)Represents future minimum payments under OVEC purchased power agreements through 2024.

(e)Represents contracts to purchase coal and natural gas.

(f)Represents currently projected cash flows for pension plans and other post-employment benefits as calculated by the actuary.

(g)Represents construction commitments.

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Off-Balance Sheet Arrangements

In the ordinary course of business LG&E has operating leases for various vehicles, equipment and real estate. See Note 10 of LG&E’s Notes to Financial Statements under Item 8 for further discussion of leases.

Sale and Leaseback Transaction

LG&E is a participant in a sale and leaseback transaction involving its 38% interest in two jointly-owned CTs at KU’s E.W. Brown generating station (Units 6 and 7). Commencing in December 1999, LG&E and KU entered into a tax-efficient, 18-year lease of the CTs. LG&E and KU have provided funds to fully defease the lease, and have executed an irrevocable notice to exercise an early purchase option contained in the lease after 15.5 years. The financial statement treatment of this transaction is no different than if LG&E had retained its ownership. The leasing transaction was entered into following receipt of required state and federal regulatory approvals.

In case of default under the lease, LG&E 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, 2005, the maximum aggregate amount of default fees or amounts, which decrease over the term of the lease, was $8.2 million, of which LG&E would be responsible for $3.1 million (38%). LG&E has made arrangements with E.ON U.S., via guarantee and regulatory commitment, for E.ON U.S. to pay LG&E’s full portion of any default fees or amounts.

MARKET RISKS

LG&E is exposed to market risks from changes in interest rates and commodity prices. To mitigate changes in cash flows attributable to these exposures, LG&E uses various financial instruments including derivatives. Derivative positions are monitored using techniques that include market value and sensitivity analysis. See Note 1 and Note 4 of LG&E’s Notes to Financial Statements under Item 8.

Interest Rate Sensitivity

LG&E has short-term and long-term variable-rate debt obligations outstanding. At December 31, 2005, the potential change in interest expense associated with a 1% change in base interest rates of LG&E’s unhedged debt is estimated at $3.6million.

Interest rate swaps are used to hedge LG&E’s underlying variable-rate debt obligations. These swaps hedge specific debt issuances and, consistent with management’s designation, are accorded hedge accounting treatment. See Note 4 of LG&E’s Notes to Financial Statements under Item 8.

As of December 31, 2005, LG&E had swaps with a combined notional value of $211.3 million. The swaps exchange floating-rate interest payments for fixed rate interest payments to reduce the impact of interest rate changes on LG&E’s pollution control bonds. The potential loss in fair value resulting from a hypothetical 1% adverse movement in base interest rates is estimated at approximately $17.6million as of December 31, 2005. This estimate is derived from third-party valuations. Changes in the market value of these swaps if held to

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maturity, as LG&E intends to do, will have no effect on LG&E’s net income or cash flow. See Note 4 of LG&E’s Notes to Financial Statements under Item 8.

In February 2005, an LG&E interest rate swap with a notional amount of $17.0 million matured. The swap was fully effective upon expiration. As a result, the impact on earnings and other comprehensive income from the swap maturity was less than $0.1 million.

Commodity Price Sensitivity

LG&E is exposed to the market price volatility of coal, natural gas and oil (the fuels used to generate electricity) in its wholesale activities. It has limited exposure to such market price volatility as the result of its retail FAC and GSC commodity price pass-through mechanisms.

Energy & Risk Management Activities

LG&E conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns. Certain energy trading activities are accounted for on a mark-to-market basis in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Wholesale sales of excess asset capacity are treated as normal sales under SFAS No. 133, as amended, and are not marked to market.

Since the inception of the MISO Day 2 market in April 2005, LG&E has been eligible to receive FTRs from the MISO. FTRs are assigned by the MISO to market participants for a twelve-month period of time beginning June 1, 2006, for off-peak and peak periods based on each market participant’s share of generation. FTRs are utilized to manage price risk associated with transmission congestion. The value of FTRs is determined by the transmission congestion charges that arise when the transmission grid is congested in the day-ahead market. FTRs are obtained through an allocation from the MISO at zero cost, however, they can also be bought and sold. FTRs are derivatives and their fair value is insignificant due to the lack of liquidity in the forward market.

The fair value of LG&E’s energy trading and risk management contracts as of December 31, 2005 and 2004, was less than $1.0 million. No changes to valuation techniques for energy trading and risk management activities occurred during 2005 or 2004. Changes in market pricing, interest rate and volatility assumptions were made during both years. The outstanding mark-to-market value is sensitive to changes in prices, price volatilities, and interest rates. The Company estimates that a movement in prices of $1 and a change in interest and volatilities of 1% would result in a change of less than $0.1 million. All contracts outstanding at December 31, 2005, have a maturity of less than one year and are valued using prices actively quoted for proposed or executed transactions or quoted by brokers.

LG&E maintains policies intended to minimize credit risk and revalues credit exposures daily to monitor compliance with those policies. At December 31, 2005, 100% of the trading and risk management commitments were with counterparties rated BBB-/Baa3 equivalent or better.

Accounts Receivable Securitization

LG&E terminated its accounts receivable securitization program in January 2004, and in May 2004, dissolved its inactive accounts receivable securitization-related subsidiary, LG&E R. No material pre-tax gains or losses resulted from the sale of the receivables in 2004 and 2003. LG&E’s net cash flows from LG&E R were reduced

25

by $58.1 million and $6.2 million for 2004 and 2003, respectively. The allowance for doubtful accounts associated with the eligible securitized receivables at December 31, 2003 was $1.4 million. This allowance was based on historical experience of LG&E. Each securitization facility contained a fully funded reserve for uncollectible receivables.

RATES AND REGULATION

LG&E is subject to the jurisdiction of the Kentucky Commission in virtually all matters related to electric and natural gas utility regulation, and as such, its accounting is subject to SFAS No. 71. Given LG&E’s competitive position in the marketplace and the status of regulation in Kentucky, LG&E has no plans or intentions to discontinue its application of SFAS No. 71. See Note 3 and Note 10 of LG&E’s Notes to Financial Statements under Item 8 for a discussion of rates and regulation.

FUTURE OUTLOOK

Competition and Customer Choice

At this time, 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 the ultimate legislative or regulatory actions regarding industry restructuring and their impact on LG&E, which may be significant, cannot currently be predicted. Some states that have already deregulated have begun discussions that could lead to re-regulation.

In February 2005, Kentucky’s Governor signed an executive order directing the Kentucky Commission, in conjunction with the Commerce Cabinet and the Environmental and Public Protection Cabinet, to ‘develop a Strategic Blueprint for the continued use and development of electric energy.’ This Strategic Blueprint is designed to promote future investment in electric infrastructure for the Commonwealth of Kentucky, to protect Kentucky’s low-cost electric advantage, to maintain affordable rates for all Kentuckians, and to preserve Kentucky’s commitment to environmental protection.

Over the last several years, LG&E has taken many steps to keep its rates low while maintaining high levels of customer satisfaction, including: an increase in focus on commercial, industrial and residential customers; an increase in employee involvement and training; and continuous modifications of its organizational structure. LG&E also strives to control costs through competitive bidding and process improvements. LG&E’s performance in national customer satisfaction surveys continues to be high.

26

Louisville Gas and Electric Company
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities

All LG&E common stock, 21,294,223 shares, is held by E.ON U.S. Therefore, there is no public market for LG&E’s common stock.

The following table sets forth LG&E’s cash distributions on common stock paid to E.ON U.S. during 2005:

	(in millions)
First quarter	$	29
Second quarter	10
Third quarter	—
Fourth quarter	—

LG&E paid cash distributions on common stock to E.ON U.S. in the amount of $57 million in 2004 and $0 in 2003.

27

Louisville Gas and Electric Company
Statements of Income
(Millions of $)

	Years Ended December 31
	2005			2004		2003
OPERATING REVENUES:
Electric (Note 13)	$	987.4		$	815.7	$	768.2
Gas	436.9			357.1		325.3
Total operating revenues	1,424.3			1,172.8		1,093.5
OPERATING EXPENSES:
Fuel for electric generation	282.4			208.3		198.0
Power purchased (Notes 10 and 13)	140.6			92.1		79.6
Gas supply expenses	339.4			266.0		233.6
Other operation and maintenance expenses	307.9			304.8		290.2
Depreciation and amortization (Note 1)	124.1			116.6		113.3
Total operating expenses	1,194.4			987.8		914.7
Net operating income	229.9			185.0		178.8
Other (income) expense—net	(0.7		)	3.3		7.2
Interest expense (Notes 8 and 9)	24.1			20.6		23.9
Interest expense to affiliated companies (Note 13)	12.7			12.2		6.8
Income before income taxes	193.8			148.9		140.9
Federal and state income taxes (Note 7)	64.9			53.3		50.1
Net income	$	128.9		$	95.6	$	90.8

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

Statements of Retained Earnings
(Millions of $)

		Years Ended December 31
		2005		2004		2003
Balance January 1		$	534.0	$	497.4	$	409.3
Add net income		128.9		95.6		90.8
		662.9		593.0		500.1
Deduct:	Cash dividends declared on stock:
	5% cumulative preferred	1.1		1.1		1.1
	Auction rate cumulative preferred	1.8		0.9		0.9
	$5.875 cumulative preferred	—		—		0.7
	Common	39.0		57.0		—
		41.9		59.0		2.7
Balance December 31		$	621.0	$	534.0	$	497.4

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

28

Louisville Gas and Electric Company
Statements of Comprehensive Income
(Millions of $)

	Years Ended December 31
	2005			2004			2003
Net income	$	128.9		$	95.6		$	90.8
Gain (loss) on derivative instruments and hedging activities, net of tax benefit (expense) of $0, $0.9 and $(0.4) for 2005, 2004 and 2003, respectively (Notes 1 and 4)	(0.1		)	(1.4		)	0.5
Additional minimum pension liability adjustment, net of tax benefit (expense) of $6.7, $4.1 and $(1.2) for 2005, 2004 and 2003, respectively (Note 6)	(12.5		)	(6.1		)	1.9
Other comprehensive income (loss), net of tax (Note 14)	(12.6		)	(7.5		)	2.4
Comprehensive income	$	116.3		$	88.1		$	93.2

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

29

Louisville Gas and Electric Company
Balance Sheets
(Millions of $)

	December 31
	2005		2004
ASSETS:
Current assets:
Cash and cash equivalents (Note 1)	$	7.1	$	6.8
Accounts receivable—less reserve of $1.1 million in 2005 and $0.8 million in 2004 (Note 4)	267.5		167.0
Materials and supplies (Note 1):
Fuel (predominantly coal)	38.7		21.8
Gas stored underground	124.9		77.5
Other materials and supplies	27.7		26.1
Prepayments and other current assets	5.8		3.9
Total current assets	471.7		303.1
Other property and investments—less reserve of $0.1 million in 2005 and 2004 (Note 1)	0.7		0.5
Utility plant, at original cost (Note 1):
Electric	3,179.9		3,113.7
Gas	511.6		487.8
Common	198.8		177.5
Total utility plant, at original cost	3,890.3		3,779.0
Less: reserve for depreciation	1,508.7		1,396.3
Total utility plant, net	2,381.6		2,382.7
Construction work in progress	158.8		136.8
Total utility plant and construction work in progress	2,540.4		2,519.5
Deferred debits and other assets:
Restricted cash (Note 1)	9.8		10.9
Unamortized debt expense (Note 1)	8.6		8.4
Regulatory assets (Note 3)	84.5		91.9
Other assets	30.7		32.2
Total deferred debits and other assets	133.6		143.4
Total Assets	$	3,146.4	$	2,966.5

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

30

Louisville Gas and Electric Company
Balance Sheets (continued)
(Millions of $)

	December 31
	2005			2004
LIABILITIES AND EQUITY:
Current liabilities:
Current portion of long-term debt:
Long-term bonds (Note 8)	$	247.5		$	247.4
Long-term notes to affiliated company (Note 8)	—			50.0
Total current portion of long term debt	247.5			297.4
Notes payable to affiliated company (Notes 9 and 13)	141.2			58.2
Accounts payable	140.5			106.1
Accounts payable to affiliated companies (Note 13)	52.4			31.7
Accrued income taxes	6.2			6.2
Customer deposits	16.7			14.0
Other current liabilities	15.2			18.6
Total current liabilities	619.7			532.2
Long-term debt:
Long-term bonds (Note 8)	328.1			328.1
Long-term notes to affiliated company (Note 8)	225.0			225.0
Mandatorily redeemable preferred stock (Note 8)	20.0			21.3
Total long term debt	573.1			574.4
Deferred credits and other liabilities:
Accumulated deferred income taxes (Note 7)	321.7			347.2
Investment tax credit, in process of amortization	42.1			46.2
Accumulated provision for pensions and related benefits (Note 6)	143.5			120.6
Asset retirement obligations	26.6			10.3
Regulatory liabilities (Note 3):
Accumulated cost of removal of utility plant	218.9			220.2
Regulatory liability deferred income taxes	41.7			37.2
Other regulatory liabilities	20.2			14.9
Other liabilities	41.3			40.1
Total deferred credits and other liabilities	856.0			836.7
Commitments and contingencies (Note 10)
Cumulative preferred stock	70.4			70.4
COMMON EQUITY:
Common stock, without par value—
Authorized 75,000,000 shares, outstanding 21,294,223 shares	424.4			424.4
Additional paid-in capital	40.0			40.0
Accumulated other comprehensive income (Note 14)	(58.2		)	(45.6		)
Retained earnings	621.0			534.0
Total common equity	1,027.2			952.8
Total Liabilities and Equity	$	3,146.4		$	2,966.5

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

31

Louisville Gas and Electric Company
Statements of Cash Flows
(Millions of $)

	Years Ended December 31
	2005			2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	128.9		$	95.6		$	90.8
Items not requiring cash currently:
Depreciation and amortization	119.3			116.6			113.3
Deferred income taxes—net	(14.3		)	5.5			20.1
Investment tax credit—net	(4.1		)	(4.1		)	(4.2		)
VDT amortization	30.2			30.1			30.4
Unrealized gain (loss) on derivatives	—			2.6			(1.1		)
Other	7.8			(2.0		)	10.8
Change in certain current assets and liabilities:
Accounts receivable	(100.5		)	(82.4		)	(16.1		)
Materials and supplies	(65.9		)	(5.3		)	(7.6		)
Accounts payable	55.1			6.3			8.7
Accrued income taxes	—			(5.3		)	17.2
Prepayments and other	(2.5		)	6.8			0.9
Pension funding	(9.8		)	(34.5		)	(89.1		)
Gas supply clause receivable, net	(3.2		)	10.3			(4.7		)
Litigation settlement	—			7.0			—
Earnings sharing mechanism receivable	2.1			10.2			0.1
Other	7.3			14.2			(6.2		)
Net cash provided by operating activities	150.4			171.6			163.3
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures	(138.9		)	(148.3		)	(213.0		)
Change in restricted cash	1.1			(10.9		)	—
Other	(0.2		)	0.1			0.2
Net cash used for investing activities	(138.0		)	(159.1		)	(212.8		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term borrowings from affiliated company	—			125.0			200.0
Repayment of long-term borrowings from affiliated company	(50.0		)	(50.0		)	—
Short-term borrowings from affiliated company	788.6			552.8			602.7
Repayment of short-term borrowings from affiliated company	(705.6		)	(574.9		)	(715.4		)
Retirement of first mortgage bonds	—			—			(42.6		)
Issuance of pollution control bonds	40.0			—			128.0
Issuance expense on pollution control bonds	(1.9		)	(0.1		)	(5.9		)
Retirement of pollution control bonds	(40.0		)	—			(128.0		)
Retirement of mandatorily redeemable preferred stock	(1.3		)	(1.3		)	(1.3		)
Payment of dividends	(41.9		)	(58.9		)	(3.3		)
Net cash (used for) provided by financing activities	(12.1		)	(7.4		)	34.2
Change in cash and cash equivalents	0.3			5.1			(15.3		)
Cash and cash equivalents at beginning of year	6.8			1.7			17.0
Cash and cash equivalents at end of year	$	7.1		$	6.8		$	1.7
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Income taxes	$	83.3		$	52.1		$	24.9
Interest on borrowed money	20.9			18.1			23.8
Interest to affiliated companies on borrowed money	12.7			11.3			4.2

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

32

Louisville Gas and Electric Company
Statements of Capitalization
(Millions of $)

	December 31
	2005		2004
LONG-TERM DEBT (Note 8):
Pollution control series:
S due September 1, 2017, variable%	$	31.0	$	31.0
T due September 1, 2017, variable%	60.0		60.0
U due August 15, 2013, variable%	35.2		35.2
X due April 15, 2023, 5.90%	—		40.0
Y due May 1, 2027, variable%	25.0		25.0
Z due August 1, 2030, variable%	83.3		83.3
AA due September 1, 2027, variable%	10.1		10.1
BB due September 1, 2026, variable%	22.5		22.5
CC due September 1, 2026, variable%	27.5		27.5
DD due November 1, 2027, variable%	35.0		35.0
EE due November 1, 2027, variable%	35.0		35.0
FF due October 1, 2032, variable%	41.7		41.7
GG due October 1, 2033, variable%	128.0		128.0
HH due February 1, 2035, variable%	40.0		—
Notes payable to Fidelia:
Due January 6, 2005, 1.53%, secured	—		50.0
Due January 16, 2012, 4.33%, secured	25.0		25.0
Due April 30, 2013, 4.55%, unsecured	100.0		100.0
Due August 15, 2013, 5.31%, secured	100.0		100.0
Mandatorily redeemable preferred stock:
$5.875 series, outstanding shares of 212,500 in 2005 and 225,000 in 2004	21.3		22.5
Total long-term debt outstanding	820.6		871.8
Less current portion of long-term debt	247.5		297.4
Long-term debt	573.1		574.4

CUMULATIVE PREFERRED STOCK:

	Shares Outstanding	Current Redemption Price
$25 par value, 1,720,000 shares authorized—5% series	860,287	$	28.00	21.5		21.5
Without par value, 6,750,000 shares authorized—Auction rate	500,000	$	100.00	50.0		50.0
Preferred stock expense, net				(1.1	)	(1.1	)
				70.4		70.4

COMMON EQUITY:
Common stock, without par value—Authorized 75,000,000 shares, outstanding 21,294,223 shares	425.2			425.2
Common stock expense	(0.8		)	(0.8		)
Additional paid-in capital	40.0			40.0
Accumulated other comprehensive income (Note 14)ff	(58.2		)	(45.6		)
Retained earnings	621.0			534.0
Total common equity	1,027.2			952.8
Total capitalization	$	1,670.7		$	1,597.6

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

33

Louisville Gas and Electric Company
Notes to Financial Statements

Note 1—Summary of Significant Accounting Policies

LG&E, a subsidiary of E.ON U.S. (formerly LG&E Energy) and an indirect subsidiary of E.ON, is a regulated public utility engaged in the generation, transmission, distribution and sale of electric energy and the storage, distribution and sale of natural gas in Louisville and adjacent areas in Kentucky. E.ON U.S. is a public utility holding company with wholly owned subsidiaries including LG&E, KU, Capital Corp., LEM and E.ON U.S. Services. All of LG&E’s common stock is held by E.ON U.S. In May 2004, LG&E dissolved its accounts receivable securitization-related subsidiary, LG&E R. Prior to May 2004, the consolidated financial statements included the accounts of LG&E and LG&E R with the elimination of intercompany accounts and transactions.

Effective December 30, 2003, LG&E Energy LLC became the successor, by assignment and subsequent merger, to all assets and liabilities of LG&E Energy Corp. Effective December 1, 2005, LG&E Energy LLC was renamed E.ON U.S. LLC.

Certain reclassification entries have been made to the previous years’ financial statements to conform to the 2005 presentation with no impact on net assets, liabilities and capitalization or previously reported net income and cash flows.

During 2005, LG&E made out-of-period adjustments for estimated over/under collection of ECR revenues to be billed in subsequent periods. The adjustments were related to the reporting periods of March 2003 through December 2004. As a result, LG&E revenues for 2005 were increased $5.3 million and net income for 2005 was increased $3.2 million. LG&E revenues for 2004 and 2003 were understated by $2.4 million and $2.9 million, respectively, and net income was understated by $1.4 million and $1.8 million, respectively.

Regulatory Accounting.LG&E is subject to SFAS No. 71 under which costs that would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates. Likewise, credits that would otherwise be reflected as income are deferred as regulatory liabilities based on expected return to customers in future rates. LG&E’s current or expected recovery of deferred costs and expected return of deferred credits is based on specific ratemaking decisions or precedent for each item as prescribed by the FERC or the Kentucky Commission. See Note 3, Rates and Regulatory Matters, for additional detail regarding regulatory assets and liabilities.

Cash and Cash Equivalents.LG&E considers all debt instruments purchased with an original maturity of three months or less to be cash equivalents.

Allowance for Doubtful Accounts.   The allowance for doubtful 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.

Materials and Supplies.Fuel, gas stored underground and other materials and supplies inventories are accounted for using the average-cost method. Emission allowances are included in inventory at cost and are not currently traded by LG&E. At December 31, 2005 and 2004, the emission allowances inventory was less than $0.1 million.

Other Property and Investments.Other property and investments on the balance sheet consists of LG&E’s investment in OVEC and non-utility plant. LG&E and 11 other electric utilities are participating owners of

34

OVEC, located in Piketon, Ohio. OVEC owns and operates two power plants that burn coal to generate electricity, Kyger Creek Station in Ohio and Clifty Creek Station in Indiana. Through March 2006, LG&E is entitled to receive 7% of OVEC’s output, and thereafter is entitled to receive 5.63%, representing approximately 124 Mw.

As of December 31, 2005 and 2004, LG&E’s investment in OVEC totaled $0.6 and $0.5 million, respectively. LG&E is not the primary beneficiary of OVEC, and, therefore, it is not consolidated into the financial statements of LG&E and is accounted for under the cost method of accounting. LG&E’s maximum exposure to loss as a result of its involvement with OVEC is limited to the value of its investment. In the event of the inability of OVEC to fulfill its power provision requirements, LG&E would substitute such power supply with either owned generation or market purchases and would generally recover associated incremental costs through regulatory rate mechanisms. See Note 10, Commitments and Contingencies, for further discussion of developments regarding LG&E’s ownership interest and power purchase rights.

Utility Plant.LG&E’s utility plant is stated at original cost, which includes payroll-related costs such as taxes, fringe benefits, and administrative and general costs. Construction work in progress has been included in the rate base for determining retail customer rates. LG&E has not recorded any allowance for funds used during construction, in accordance with Kentucky Commission regulations.

The cost of plant retired or disposed of in the normal course of business is deducted from plant accounts and such cost, plus removal expense less salvage value, 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.

Depreciation and Amortization.Depreciation is provided on the straight-line method over the estimated service lives of depreciable plant. The amounts provided were approximately 3.2% in 2005 (3.0% electric, 2.4% gas, and 8.0% common); 3.1% in 2004 (2.9% electric, 2.8% gas and 7.6% common); and 3.3% for 2003 (2.9% electric, 2.8% gas and 9.4% common), of average depreciable plant. Of the amount provided for depreciation, at December 31, 2005, approximately 0.4% electric, 0.8% gas and 0.02% common were related to the retirement, removal and disposal costs of long lived assets.  Of the amount provided for depreciation, at December 31, 2004, approximately 0.4% electric, 0.9% gas and 0.04% common were related to the retirement, removal and disposal costs of long lived assets.

Restricted Cash.A deposit in the amount of $9.8 million, used as collateral for an $83.3 million interest rate swap expiring in 2020, is classified as restricted cash on LG&E’s balance sheet.

Unamortized Debt Expense.Debt expense is capitalized in deferred debits and amortized over the lives of the related bond issues.

Income Taxes.Income taxes are accounted for under SFAS No.109. In accordance with this statement, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, as measured by enacted tax rates that are expected to be in effect in the periods when the deferred tax assets and liabilities are expected to be settled or realized. Significant judgment is required in determining the provision for income taxes, and there are transactions for which the ultimate tax outcome is uncertain. To provide for these uncertainties or exposures, an allowance is maintained for tax contingencies based on management’s best estimate of probable loss. Tax contingencies are analyzed periodically and adjustments are made when events occur to warrant a change. See Note 7, Income Taxes.

35

Deferred Income Taxes.Deferred income taxes are recognized at currently enacted tax rates for all material temporary differences between the financial reporting and income tax bases of assets and liabilities.

Investment Tax Credits.Investment tax credits resulted from provisions of the tax law that permitted a reduction of LG&E’s tax liability based on credits for construction expenditures. Deferred investment tax credits are being amortized to income over the estimated lives of the related property that gave rise to the credits.

Revenue Recognition.Revenues are recorded based on service rendered to customers through month-end. LG&E accrues an estimate for unbilled revenues from each meter reading date to the end of the accounting period based on allocating the daily system net deliveries between billed volumes and unbilled volumes. The allocation is based on a daily ratio of the number of meter reading cycles remaining in the month to the total number of meter reading cycles in each month. Each day’s ratio is then multiplied by each day’s system net deliveries to determine an estimated billed and unbilled volume for each day of the accounting period. The unbilled revenue estimates included in accounts receivable were approximately $81.8 million and $63.0 million at December 31, 2005 and 2004, respectively.

Fuel and 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 implemented a Kentucky Commission-approved performance-based ratemaking mechanism related to natural gas procurement activity. See Note 3, Rates and Regulatory Matters.

Management’s Use of Estimates.The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported assets and liabilities and disclosure of contingent items at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Accrued liabilities, including legal and environmental, are recorded when they are probable and estimable. Actual results could differ from those estimates.

New Accounting Pronouncements.The following accounting pronouncement was issued that affected LG&E in 2005:

FIN 47

LG&E adopted FIN 47,  effective December 31, 2005. FIN 47 expands the term “conditional asset retirement obligation” as used in SFAS No. 143, to refer to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. An entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred; generally, upon acquisition, construction or development and through the normal operation of the asset.

As a result of the implementation of FIN 47, LG&E recorded additional ARO net assets and liabilities during the fourth quarter of 2005 in the amount of $1.0 million and $15.7 million, respectively. LG&E also recorded a cumulative effect adjustment in the amount of $12.3 million to reflect the accumulated depreciation and accretion of ARO assets at the transition date less amounts previously accrued under regulatory depreciation. A $2.4 million reduction in the accumulated cost of removal regulatory liability was also recorded for this previously accrued cost of removal. LG&E recorded offsetting regulatory assets of $12.3 million, pursuant to

36

regulatory treatment prescribed under SFAS No. 71 as the costs of removal are allowed under Kentucky Commission ratemaking.

Had FIN 47 been in effect at the beginning of the 2004 reporting period, LG&E would have established asset retirement obligations as described in the following table (in millions):

	2005		2004
Provision at beginning of the year	$	14.8	$	14.0
Accretion expense	0.9		0.8
Provision at end of the yearb	$	15.7	$	14.8

Note 2—Company Structure

On July 1, 2002, E.ON completed its acquisition of Powergen, including E.ON U.S. (formerly LG&E Energy), for approximately £5.1 billion ($7.3 billion). As a result of the acquisition, E.ON U.S. became a wholly owned subsidiary of E.ON and, as a result, LG&E also became an indirect subsidiary of E.ON. LG&E has continued its separate identity and serves customers in Kentucky under its existing name. The preferred stock and debt securities of LG&E were not affected by this transaction and the Company continues to file SEC reports.

Note 3—Rates and Regulatory Matters

Electric and Gas Rate Cases

In December 2003, LG&E filed an application with the Kentucky Commission requesting adjustments in LG&E’s electric and natural gas rates. LG&E asked for general adjustments in electric and natural gas rates based on the twelve month test period ended September 30, 2003. The revenue increases requested were $63.8 million for electric and $19.1 million for natural gas. In June 2004, the Kentucky Commission issued an order approving increases in LG&E’s annual electric base rates of approximately $43.4 million (7.7%) and annual natural gas base rates of approximately $11.9 million (3.4%). The rate increases took effect on July 1, 2004.

During 2004 and 2005, the AG conducted an investigation of LG&E, as well as of the Kentucky Commission and its staff, requesting information regarding allegedly improper communications between LG&E and the Kentucky Commission, particularly during the period covered by the rate cases. Concurrently, the AG had filed pleadings with the Kentucky Commission requesting rehearing of the rate cases on computational components of the increased rates, including income taxes, cost of removal and depreciation amounts. In August 2004, the Kentucky Commission denied the AG’s rehearing request on the cost of removal and depreciation issues and granted rehearing on the income tax component. The Kentucky Commission further agreed to hold in abeyance further proceedings in the rate case, until the AG filed its investigative report regarding the allegations of improper communication.

In January 2005 and February 2005, the AG filed a motion summarizing its investigative report as containing evidence of improper communications and record-keeping errors by LG&E in its conduct of activities before the Kentucky Commission or other state governmental entities and forwarded such report to the Kentucky Commission under continued confidential treatment to allow it to consider the report, including its impact, if any, on completing its investigation and any remaining steps in the rate case. To date, LG&E has neither seen nor requested copies of the report or its contents.

In December 2005, the Kentucky Commission issued an order noting completion if its inquiry, including review of the AG’s investigative report. The order concludes no improper communications occurred during the rate proceedings. The order further established a procedural schedule through the first quarter of 2006 for

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considering the sole issue for which rehearing was granted: state income tax rates used in calculating the granted rate increases. This issue is estimated at less than $1 million annually. Upon resolution of this issue on rehearing, the initial rate increase order could be subject to judicial appeal.

LG&E believes no improprieties have occurred in its communications with the Kentucky Commission and has cooperated with the proceedings before the AG and the Kentucky Commission. LG&E is currently unable to determine the ultimate impact, if any, of, or any possible future actions of the AG or the Kentucky Commission arising out of, the AG’s report and investigation, including whether there will be further actions to appeal, review or otherwise challenge the granted increases in rates.

Regulatory Assets and Liabilities

The following regulatory assets and liabilities were included in LG&E’s Balance Sheets as of December 31:

	2005		2004
	(in millions)
VDT Costs	$	7.5	$	37.7
Unamortized loss on bonds	20.6		20.3
ARO	20.0		6.9
Gas supply adjustments	25.4		13.3
Merger surcredit	3.5		4.8
Other	7.5		8.9
Total regulatory assets	$	84.5	$	91.9
Accumulated cost of removal of utility plant	$	218.9	$	220.2
Deferred income taxes—net	41.7		37.2
Gas supply adjustments	17.3		8.4
ECR	—		4.0
Other	2.9		2.5
Total regulatory liabilities	$	280.8	$	272.3

LG&E currently earns a return on all regulatory assets except for gas supply adjustments, FAC, gas performance based ratemaking and DSM, all of which are separate rate mechanisms with recovery within twelve months. Additionally, no current return is earned on the ARO regulatory asset. This regulatory asset will be offset against the associated regulatory liability, ARO asset, and ARO liability at the time the underlying asset is retired. See Note 1, Summary of Significant Accounting Policies.

VDT.During the first quarter of 2001, LG&E recorded a $144.0 million charge for a workforce reduction program. Primary components of the charge were separation benefits, enhanced early retirement benefits and healthcare benefits. The result of this workforce reduction was the elimination of approximately 700 positions, accomplished primarily through a voluntary enhanced severance program.

In December 2001, the Kentucky Commission issued an order approving a settlement agreement allowing LG&E to set up a regulatory asset of $141.0 million for the workforce reduction costs and begin amortizing these costs over a five-year period starting in April 2001. Some employees rescinded their participation in the voluntary enhanced severance program, which thereby decreased the charge to the regulatory asset from $144.0 million to $141.0 million. The order reduced revenues by approximately $26.0 million through a surcredit on bills to ratepayers over the same five-year period. The surcredit represents savings, net of the amortization of the costs, stipulated by LG&E and shared 40% with ratepayers and with LG&E retaining 60% of the net savings.

The five-year VDT amortization period is scheduled to expire in March 2006. As part of the settlement

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agreements in the electric and natural gas rate cases, LG&E was required to file, and did file on September 30, 2005, with the Kentucky Commission a plan for the future ratemaking treatment of the VDT surcredit and costs. The surcredit will remain in effect until the Commission enters an order on the future disposition of VDT-related issues.

On February 27, 2006, the AG, KIUC, LG&E and KU reached a settlement agreement on the future ratemaking treatment of the VDT surcredits and costs and subsequently submitted a joint motion to the Kentucky Commission to approve the unanimous settlement agreement. Under the terms of the settlement agreement, the VDT surcredit will continue at the current level until such time as LG&E files for a change in electric or gas base rates. The Kentucky Commission held a public hearing in the proceeding on March 21, 2006 and issued an order thereafter approving the settlement agreement.

Unamortized Loss on Bonds.Thecosts of early extinguishment of debt, includingcall premiums, legaland other expenses, and any unamortized balance of debt expense are amortized over the life of either replacement debt (in the case of re-financing) or the original life of the extinguished debt.

ARO.A summary of LG&E’s net ARO assets, regulatory assets, liabilities and cost of removal established under FIN 47 and SFAS No. 143 follows:

	ARO Net Assets			ARO Liabilities			Regulatory Assets		Regulatory Liabilities			Accumulated Cost of Removal		Cost of Removal Depreciation
	(in millions)
As of December 31, 2003	$	3.5		$	(9.7	)	$	6.0	$	(0.1	)	$	0.5	$	—
ARO accretion	—			(0.7		)	0.7		—			—		—
ARO depreciation	(0.2		)	—			0.2		—			—		—
Removal cost incurred	—			0.1			—		—			—		—
Cost of removal depreciation	—			—			—		—			—		—
As of December 31, 2004	3.3			(10.3		)	6.9		(0.1		)	0.5		—
FIN 47 net asset additions	1.0			(15.7		)	12.3		—			2.4		—
ARO accretion	—			(0.7		)	0.7		—			—		—
ARO depreciation	(0.1		)	—			0.1		—			—		—
Removal cost incurred	—			0.1			—		—			—		—
Cost of removal depreciation	—			—			—		(0.1		)	—		0.1
As of December 31, 2005	$	4.2		$	(26.6	)	$	20.0	$	(0.2	)	$	2.9	$	0.1

Pursuant to regulatory treatment prescribed under SFAS No. 71, an offsetting regulatory credit was recorded in Depreciation and amortization in the income statement of $0.8 million in 2005 and $0.9 million in 2004 for the ARO accretion and depreciation expense. LG&E AROs are primarily related to the final retirement of assets associated with generating units and natural gas wells. For assets associated with AROs, the removal cost accrued through depreciation under regulatory accounting is established as a regulatory asset or liability pursuant to regulatory treatment prescribed under SFAS No. 71. For the years ended December 31, 2005 and 2004, LG&E recorded less than $0.1 million of depreciation expense related to the cost of removal of ARO related assets. An offsetting regulatory liability was established pursuant to regulatory treatment prescribed under SFAS No. 71.

LG&E transmission and distribution lines largely operate under perpetual property easement agreements which do not generally require restoration upon removal of the property. Therefore, under SFAS No. 143, no material asset retirement obligations are recorded for transmission and distribution assets.

Merger Surcredit.As part of the LG&E Energy merger with KU Energy in 1998, LG&E estimated non-fuel savings over a ten-year period following the merger. Costs to achieve these savings were deferred and amortized over a five-year period pursuant to regulatory orders. In approving the merger, the Kentucky

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Commission adopted LG&E’s proposal to reduce its retail customers’ bills based on one-half of the estimated merger-related savings, net of deferred and amortized amounts, over a five-year period. The surcredit mechanism provides that 50% of the net non-fuel cost savings estimated to be achieved from the merger be provided to ratepayers through a monthly bill credit, and 50% be retained by LG&E and KU, over a five-year period. The surcredit was allocated 53% to KU and 47% to LG&E. In that same order, the Commission required LG&E and KU, after the end of the five-year period, to present a plan for sharing with ratepayers the then-projected non-fuel savings associated with the merger. The Companies submitted this filing in January 2003, proposing to continue to share with ratepayers, on a 50%/50% basis, the estimated fifth-year gross level of non-fuel savings associated with the merger. In October 2003, the Kentucky Commission issued an order approving a settlement agreement reached with the parties in the case. LG&E’s merger surcredit will remain in place for another five-year term beginning July 1, 2003 and the merger savings will continue to be shared 50% with ratepayers and 50% with shareholders.

ESM.Prior to 2004, LG&E’s retail electric rates were subject to an ESM. The ESM, initially in place for three years beginning in 2000, set an upper (12.5%) and lower (10.5%) limit for rate of return on equity. If earnings were above the upper limit, the excess earnings were shared 40% with ratepayers and 60% with shareholders; if earnings were below the lower limit, the earnings deficiency was recovered 40% from ratepayers and 60% from shareholders. By order of the Kentucky Commission, rate changes prompted by the ESM filing went into effect in April of each year subject to a balancing adjustment in successive periods.

In November 2002, LG&E filed a revised ESM tariff which proposed continuance of the existing ESM through December 2005. In addition, the Kentucky Commission initiated a focused management audit to review the ESM plan and reassess its reasonableness. LG&E filed its final 2003 ESM calculations with the Kentucky Commission on March 1, 2004, and applied for recovery of $13.0 million. Based upon estimates, LG&E previously accrued $8.9 million for the 2003 ESM as of December 31, 2003. In June 2004, the Kentucky Commission issued an order largely accepting proposed settlement agreements by LG&E and all intervenors regarding the ESM. Under the ESM settlements, LG&E continued to collect approximately $13.0 million of previously requested 2003 ESM revenue amounts through March 2005. As part of the settlement, the parties agreed to a termination of the ESM mechanism relating to all periods after 2003.

FAC.LG&E’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. In January 2003, the Kentucky Commission reviewed KU’s FAC and, as part of the order in that case, required that an independent audit be conducted to examine operational and management aspects of both LG&E’s and KU’s fuel procurement functions. The final report was issued in February 2004. The report’s recommendations related to documentation and process improvements. Management Audit Action Plans were agreed upon by LG&E and the Kentucky Commission Staff in the second quarter of 2004. LG&E filed its first Audit Progress Report with the Kentucky Commission Staff in November 2004. A second Audit Progress Report was filed May 2005. The third Audit Progress Report was filed in December 2005. In January 2006, the Kentucky Commission staff informed LG&E and KU that reporting on all of the original recommendations, but one, has been concluded. LG&E and KU are to file another Audit Progress Report on the remaining open recommendation on August 15, 2006.

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. No significant issues have been identified as a result of these reviews.

In December 2004, the Kentucky Commission initiated a two-year review of LG&E’s past operations of the

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fuel clause and transfer of fuel costs from the fuel adjustment clause to base rates. A public hearing on the matter was held on March 17, 2005. An order by the Kentucky Commission was issued in May 2005 approving LG&E’s base fuel component of 13.49 mills/kwh as filed. Revised tariff schedules for LG&E were filed to reflect the change in the base fuel component.

On July 7, 2005, the Kentucky Commission initiated the six-month review of the LG&E fuel adjustment clause for the period of November 2004 through April 2005. During November 2005, the Kentucky Commission approved the charges and credits billed and the fuel procurement practices of LG&E.

On December 27, 2005, the Kentucky Commission initiated the six-month review of the LG&E fuel adjustment clause for the period of May 2005 through October 2005. Initial discovery was completed on January 17, 2006, and a hearing was held on March 16, 2006. LG&E anticipates Kentucky Commission approval of the charges and credits billed and the fuel procurement practices of LG&E during the second quarter of 2006.

DSM.LG&E’s rates contain a DSM provision. The provision includes a rate mechanism that provides for concurrent recovery of DSM costs and provides an incentive for implementing DSM programs. The provision allows LG&E to recover revenues from lost sales associated with the DSM programs based on program plan engineering estimates and post-implementation evaluations.

Gas Supply Adjustments.Since November 1, 1997, LG&E has operated under an experimental PBR mechanism related to its natural gas procurement activities. LG&E’s rates are adjusted annually to recover (or refund) its portion of the savings (or expenses) incurred during each PBR year (12 months ending October 31). During the PBR year ending in 2005, LG&E achieved $10.8 million in savings. Of that total savings amount, LG&E’s portion was $2.7 million and the ratepayers’ portion was $8.1 million. 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 ratepayers 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 ratepayers. LG&E filed a report and assessment with the Kentucky Commission in December 2004, seeking modification and extension of the mechanism. Following a review by the Kentucky Commission, the current natural gas supply cost PBR mechanism was extended through 2010 without further modification.

Accumulated Cost of Removal of Utility Plant.As of December 31, 2005 and 2004, LG&E has segregated the cost of removal, embedded in accumulated depreciation, of $218.9 million and $220.2 million, respectively, in accordance with FERC Order No. 631. For reporting purposes in the balance sheets, LG&E has presented this cost of removal as a regulatory liability pursuant to SFAS No. 71.

Deferred Income Taxes—Net.Deferred income taxes represent the future income tax effects of recognizing the regulatory assets and liabilities in the income statement. Deferred income taxes are recognized at currently enacted tax rates for all material temporary differences between the financial reporting and income tax bases of assets and liabilities.

ECR.   LG&E’s retail rates contain an ECR surcharge which recovers costs incurred by LG&E that are required to comply with the Clean Air Act and other environmental regulations.  In January 2003, the Kentucky Commission initiated a six-month review of LG&E’s environmental surcharge. A final order was issued in April 2003, in which LG&E was ordered to refund $2.9 million it had previously over-collected from customers. In July 2003, the Kentucky Commission initiated a two-year review of LG&E’s environmental surcharge. A final order was issued in December 2003 in which LG&E was ordered to roll $15.2 million of environmental assets into base rates and make corresponding adjustments to the monthly environmental surcharge filings to reflect that portion

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of environmental rate base now included in base rates going forward. Additionally, LG&E was ordered to collect $0.2 million to correct for amounts under-collected from customers. The rates of return for LG&E’s 1995 and post-1995 plans were reset to 3.32% and 10.92%, respectively.

In June 2004, the Kentucky Commission issued an order approving a settlement agreement that, among other things, revised the rate of return for LG&E’s post-1995 plan to 10.72%, with an 11% return on common equity. The order also approved the elimination of LG&E’s 1995 plan from its ECR billing mechanism, with all remaining costs associated with that plan to be included in their entirety in base rates.

In December 2004, LG&E filed an application with the Kentucky Commission to amend its compliance plan to allow recovery of costs associated with new and additional environmental compliance facilities, including the expansion of the landfill facility at the Mill Creek station. The estimated capital cost of the additional facilities for the next three years is approximately $40.0 million. LG&E requested an overall rate of return of 10.72%, including an 11% return on common equity. Hearings in these cases occurred during May 2005 and final orders were issued in June 2005, granting approval of the amendments to LG&E’s compliance plans.

Other Regulatory Matters

MISO.The MISO is a non-profit independent transmission system operator that controls approximately 97,000 miles of transmission lines over 947,000 square miles in 15 northern Midwest states and one Canadian province. The MISO operates the regional power grid and wholesale electricity market in an effort to optimize efficiency and safeguard reliability in accordance with federal energy policy.

LG&E is now involved in proceedings with the Kentucky Commission and the FERC seeking the authority to exit the MISO. A timeline of events regarding the MISO and various proceedings is as follows:

·September 1998—The FERC granted conditional approval for the formation of the MISO. LG&E was a founding member.

·October 2001—The FERC ordered that all bundled retail loads and grandfathered wholesale loads of each member transmission owner be included in the calculation of the MISO “cost adder,” the Schedule 10 charges designed to recover the MISO’s cost of operation, including start-up capital (debt) costs. LG&E and several owners opposed the FERC order and filed suit with the United States Court of Appeals.

·February 2002—The MISO began commercial operations.

·February 2003—The FERC reaffirmed its position on the Schedule 10 charges and the order was subsequently upheld by the U.S. Court of Appeals.

·July 2003—The Kentucky Commission opened an investigation into LG&E’s MISO membership. Testimony was filed by LG&E that supported an exit from the MISO, under certain conditions. This proceeding remains open.

·August 2004—The MISO filed its FERC-required TEMT. LG&E and other owners filed opposition to certain conditions of the TEMT and sought to delay the implementation. Such opposition was denied by the FERC.

·December 2004—LG&E provided the MISO its required one-year notice of intent to exit the grid.

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·April 2005—The MISO implemented its day-ahead and real-time market (MISO Day 2), including a congestion management system.

·October 2005—LG&E filed documents with the FERC seeking authority to exit the MISO. This proceeding remains open.

·November 2005—LG&E requested a Kentucky Commission order authorizing the transfer of functional control of its transmission facilities from the MISO to LG&E, for the purpose of exiting the MISO. The request stated that the TVA would have control to the extent necessary to act as LG&E’s Reliability Coordinator and for the SPP to perform its function as LG&E’s Independent Transmission Organization. This proceeding remains open.

Based on various financial analyses performed internally, in response to the July 2003 Kentucky Commission investigation into MISO membership, and particularly in light of the financial impacts following MISO’s implementation of the new day-ahead and real-time markets, LG&E determined that the costs of MISO membership, both now and in the future, outweigh the benefits.

Should LG&E be allowed to exit the MISO, an aggregate exit fee of up to $41.0 million (approximately $16.0 million for LG&E and approximately $25.0 million for KU) could be imposed, depending on the timing and circumstances of the actual exit. LG&E estimates that, over time, such fee could be more than offset by savings resulting from exit from the MISO. Conversely, should LG&E be ordered to remain in the MISO, costs are expected to continue to exceed benefits, currently without mechanisms for immediate recovery.

On March 17, 2006, the FERC issued an order conditionally approving the request of LG&E and KU to exit the MISO. For further discussion, see Note 16, Subsequent Events.

Market-Based Rate Authority.Since April 2004, the FERC has initiated proceedings to modify its methods which assess generation market power and has established more stringent interim market screen tests. During 2005, in connection with LG&E’s and KU’s tri-annual market-based rate tariff renewals, although disputed by LG&E and KU, the FERC continued to contend that LG&E and KU failed such market screens in certain regions. In January 2006, in order to resolve the matter, LG&E and KU submitted proposed tariff schedules to the FERC containing a mitigation mechanism with respect to applicable power sales into an adjacent western Kentucky control area where a non-utility affiliate company is active. Prices for such sales will be capped at a relevant MISO power pool index price. Should LG&E and KU exit the MISO, they could additionally be deemed to have market power in their own joint control area, potentially requiring a similar mitigation mechanism for power sales into such region. LG&E and KU cannot predict the ultimate impact of the current or potential mitigation mechanisms on their future wholesale power revenues.

IRP.In April 2005, LG&E and KU filed their 2005 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 AG and the KIUC were granted intervention in the IRP proceeding. The Kentucky Commission issued its staff report on February 15, 2006, with no substantive issues noted and closed the case by Order dated February 24, 2006.

Kentucky Commission Administrative Case for System Adequacy.In June 2001, Kentucky’s Governor issued Executive Order 2001-771, which directed the Kentucky Commission to review and study issues relating to the need for and development of new electric generating capacity in Kentucky. In response to that Executive Order, in July 2001 the Kentucky Commission opened Administrative Case No. 387 to review the adequacy of

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Kentucky’s generation capacity and transmission system. Specifically, the items reviewed were the appropriate level of reliance on purchased power, the appropriate reserve margins to meet existing and future electric demand, the impact of spikes in natural gas prices on electric utility planning strategies, and the adequacy of Kentucky’s electric transmission facilities. In December 2001, the Kentucky Commission issued an order in which it noted that LG&E is responsibly addressing the long-term supply needs of native load customers and that current reserve margins are appropriate. However, due to the rapid pace of change in the industry, the order also requires LG&E to provide an annual assessment of supply resources, future demand, reserve margin and the need for new resources.

Regarding the transmission system, the Kentucky Commission concluded that the transmission system within Kentucky can reliably serve native load and a significant portion of the proposed new unregulated power plants. However, it will not be able to handle the volume of transactions envisioned by the FERC without future upgrades, the costs of which should be borne by those for whom the upgrades are required.

The Kentucky Commission pledged to continue to monitor all relevant issues and advocate Kentucky’s interests at all opportunities.

EPAct 2005.The EPAct 2005 was enacted on August 8, 2005. Among other matters, this comprehensive legislation contains provisions mandating improved electric reliability standards and performance; providing economic and other incentives relating to transmission, pollution control and renewable generation assets; increasing funding for clean coal generation incentives; repealing PUHCA 1935; enacting PUHCA 2005 and expanding FERC jurisdiction over public utility holding companies and related matters via the FPA and PUHCA 2005.

The FERC was directed by the EPAct 2005 to adopt rules to address many areas previously regulated by the other agencies under other statutes, including PUHCA 1935. The FERC is in various stages of rulemaking on these issues and LG&E is monitoring these rulemaking activities and actively participating in these and other rulemaking proceedings. LG&E is still evaluating the potential impacts of the EPAct 2005 and the associated rulemakings and cannot predict what impact the EPAct 2005, and any such rulemakings, will have on its operations or financial position.

Kentucky Commission Strategic Blueprint.In February 2005, Kentucky’s Governor signed an executive order directing the Kentucky Commission, in conjunction with the Commerce Cabinet and the Environmental and Public Protection Cabinet, to ‘develop a Strategic Blueprint for the continued use and development of electric energy.’ This Strategic Blueprint is designed to promote future investment in electric infrastructure for the Commonwealth of Kentucky, to protect Kentucky’s low-cost electric advantage, to maintain affordable rates for all Kentuckians and to preserve Kentucky’s commitment to environmental protection. In March 2005, the Kentucky Commission established Administrative Case No. 2005-00090 to collect information from all jurisdictional utilities in Kentucky, including LG&E, pertaining to Kentucky electric generation, transmission and distribution systems. LG&E responded to the Kentucky Commission’s first set of data requests at the end of March 2005 and to a second set of data requests in May 2005. The Commission held a Technical Conference on June 14, 2005, in which all parties participated in a panel discussion. A final report was provided on August 22, 2005 from the Kentucky Commission to the Governor. The Kentucky Commission issued an order and closed this proceeding on September 15, 2005. Some of the key findings from the report are:

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·Kentucky’s electric utilities currently have adequate infrastructure as well as adequate planning to serve the needs of customers through 2025;

·Kentucky will need 7,000 megawatts of additional generating capacity by 2025;

·Kentucky’s electric transmission is reliable but intrastate power transfers are limited;

·Additional incentives to use renewable energy and educate the public on the benefits of renewables are needed;

·Financial incentives should be available for coal purification and other clean air technologies;

·A cautious approach should be taken toward deregulation; and

·Kentucky must be involved in federal decisions that impact its status as a low cost energy provider.

Note 4—Financial Instruments

The cost and estimated fair values of LG&E’s non-trading financial instruments as of December 31, 2005, and 2004 follow:

	2005						2004
	Carrying Value			Fair Value			Carrying Value			Fair Value
	(in millions)
Preferred stock subject to mandatory redemption	$	21.3		$	21.4		$	22.5		$	22.8
Long-term debt (including current portion)	$	574.3		$	574.3		$	574.3		$	575.4
Long-term debt from affiliate	$	225.0		$	224.8		$	275.0		$	280.7
Interest-rate swaps—liability	$	(18.6	)	$	(18.6	)	$	(18.5	)	$	(18.5	)

All of the above valuations reflect prices quoted by exchanges except for the swaps and intercompany loans. The fair values of the swaps and intercompany loans reflect price quotes from dealers or amounts calculated using accepted pricing models. The fair values of cash and cash equivalents, accounts receivable, accounts payable and notes payable are substantially the same as their carrying values.

Interest Rate Swaps.   LG&E uses over-the-counter interest rate swaps to hedge exposure to market fluctuations in certain of its debt instruments. 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. Management has designated all of the interest rate swaps as hedge instruments. Financial instruments designated as cash flow hedges have resulting gains and losses recorded within other comprehensive income and stockholders’ equity. See Note 14, Accumulated Other Comprehensive Income. Financial instruments designated as fair value hedges and the underlying hedged items are periodically marked to market with the resulting net gains and losses recorded directly into net income. Upon termination of any fair value hedge, the resulting gain or loss is recorded into net income.

LG&E was party to various interest rate swap agreements with aggregate notional amounts of $211.3 million and $228.3 million as of December 31, 2005 and 2004. Under these swap agreements, LG&E paid fixed rates averaging 4.38% and received variable rates based on LIBOR or the Bond Market Association’s municipal swap index averaging 3.15% and 1.74% at December 31, 2005 and 2004, respectively. The swap agreements in effect at December 31, 2005 have been designated as cash flow hedges and mature on dates ranging from 2020 to 2033. The cash flow designation was assigned because the underlying variable rate debt has variable future cash flows. The hedges have been deemed to be fully effective resulting in a pretax loss of $0.1million for 2005 and $2.3 million in 2004, recorded in other comprehensive income. Upon expiration of these hedges, the amount recorded in other comprehensive income will be reclassified into earnings. The amount expected to be

45

reclassified from other comprehensive income to earnings in the next twelve months is less than $0.1 million. A deposit in the amount of $9.8 million, used as collateral for one of the interest rate swaps, is classified as restricted cash on LG&E’s Balance Sheet. The amount of the deposit required is tied to the market value of the swap.

Energy Risk Management Activities.LG&E conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns. Certain energy trading activities are accounted for on a mark-to-market basis in accordance with SFAS No. 133, as amended. Wholesale sales of excess asset capacity  are treated as normal sales under SFAS No. 133, as amended and are not marked to market.

No changes to valuation techniques for energy trading and risk management activities occurred during 2005 and 2004. Changes in market pricing, interest rate and volatility assumptions were made during both years. All contracts outstanding at December 31, 2005, have a maturity of less than one year and are valued using prices actively quoted for proposed or executed transactions or quoted by brokers.

LG&E maintains policies intended to minimize credit risk and revalues credit exposures daily to monitor compliance with those policies. At December 31, 2005, 100% of the trading and risk management commitments were with counterparties rated BBB-/Baa3 equivalent or better.

LG&E hedges the price volatility of its forecasted electric off-system sales with the sales of market-traded electric forward contracts for periods of less than one year. These electric forward sales have been designated as cash flow hedges and are not speculative in nature. Gains or losses on these instruments, to the extent that the hedging relationship has been effective, are deferred in other comprehensive income. Gains and losses resulting from ineffectiveness are shown in LG&E’s Statements of Income in other (income) expense—net. Upon completion of the underlying hedge transaction, the amount recorded in other comprehensive income is recorded in earnings. No material pre-tax gains and losses resulted from these cash flow hedges in 2005, 2004 and 2003.  See Note 14, Accumulated Other Comprehensive Income.

Accounts Receivable Securitization.LG&E terminated its accounts receivable securitization program in January 2004, and in May 2004, LG&E dissolved its inactive accounts receivable securitization-related subsidiary, LG&E R. No material pre-tax gains and losses resulted from the sale of the receivables in 2004 and 2003. LG&E’s net cash flows from LG&E R were reduced by $58.1 million and $6.2 million for 2004 and 2003, respectively. The allowance for doubtful accounts associated with the eligible securitized receivables at December 31, 2003, was $1.4 million. This allowance was based on historical experience of LG&E. Each securitization facility contained a fully funded reserve for uncollectible receivables. LG&E was able to terminate this program at any time without penalty.

Note 5—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 and gas and electric revenues arise from deliveries of natural gas to approximately 321,000 customers and electricity to approximately 394,000 customers in Louisville and adjacent areas in Kentucky. For the year ended December 31, 2005, 69% of total revenue was derived from electric operations and 31% from natural gas operations. For the year ended December 31, 2004, 70% of total revenue was derived from electric operations and 30% from natural gas operations.

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In November 2005, LG&E and IBEW Local 2100 employees, that represent approximately 69% of LG&E’s workforce, entered into a three-year collective bargaining agreement with annual benefits re-openers.

Note 6—Pension and Other Post Retirement Benefit Plans

LG&E has both funded and unfunded non-contributory defined benefit pension plans and other post-retirement benefit plans that together cover substantially all of its employees. The healthcare plans are contributory with participants’ contributions adjusted annually. LG&E 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 plan’s benefit obligations and fair value of assets over the three-year period ending December 31, 2005, and a statement of the funded status as of December 31, 2005, 2004 and 2003 for LG&E’s sponsored defined benefit plan:

	2005			2004			2003
	(in millions)
Pension Plans:
Change in projected benefit obligation
Projected benefit obligation at beginning of year	$	402.4		$	378.7		$	364.8
Service cost	3.7			2.8			1.7
Interest cost	22.3			22.7			23.2
Plan amendments	3.2			3.3			4.0
Change due to transfers	0.3			(1.1		)	(2.8		)
Benefits paid	(29.9		)	(30.5		)	(33.5		)
Actuarial (gain) or loss and other	24.7			26.5			21.3
Projected benefit obligation at end of year	$	426.7		$	402.4		$	378.7
Change in plan assets
Fair value of plan assets at beginning of year	$	338.2		$	297.8		$	196.3
Actual return on plan assets	26.6			39.3			47.2
Employer contributions	—			34.5			89.1
Change due to transfers	—			(1.1		)	0.2
Benefits paid	(29.9		)	(30.5		)	(33.5		)
Administrative expenses	(1.8		)	(1.8		)	(1.5		)
Fair value of plan assets at end of year	$	333.1		$	338.2		$	297.8
Reconciliation of funded status
Funded status	$	(93.6	)	$	(64.2	)	$	(80.9	)
Unrecognized actuarial (gain) or loss	94.7			70.3			56.2
Unrecognized transition (asset) or obligation	(0.7		)	(1.5		)	(2.2		)
Unrecognized prior service cost	30.4			31.5			32.3
Net amount recognized at end of year	$	30.8		$	36.1		$	5.4
Other Benefits:
Change in benefit obligation
Benefit obligation at beginning of year	$	113.0		$	108.0		$	93.2
Service cost	1.0			0.9			0.6
Interest cost	5.6			6.5			6.9
Plan amendments	2.2			0.4			7.4
Benefits paid	(8.1		)	(7.1		)	(9.3		)
Actuarial (gain) or loss	(7.5		)	4.3			9.2
Benefit obligation at end of year	$	106.2		$	113.0		$	108.0

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	2005			2004			2003
	(in millions)
Change in plan assets
Fair value of plan assets at beginning of year	$	0.8		$	0.7		$	1.5
Actual return on plan assets	0.2			(2.0		)	2.1
Employer contributions	9.8			9.3			6.4
Change due to transfers	—			(0.1		)	—
Benefits paid	(8.1		)	(7.1		)	(9.3		)
Fair value of plan assets at end of year	$	2.7		$	0.8		$	0.7
Reconciliation of funded status
Funded status	$	(103.5	)	$	(112.2	)	$	(107.3	)
Unrecognized actuarial (gain) or loss	21.5			29.4			23.7
Unrecognized transition (asset) or obligation	4.7			5.4			6.0
Unrecognized prior service cost	10.4			10.0			11.5
Net amount recognized at end of year	$	(66.9	)	$	(67.4	)	$	(66.1	)

Amounts Recognized in Statement of Financial Position.The following tables provide the amounts recognized in the balance sheet and information for plans with benefit obligations in excess of plan assets as of December 31, 2005, 2004 and 2003:

	2005			2004			2003
	(in millions)
Pension Plans:
Amounts recognized in the balance sheet consisted of:
Accrued benefit liability	$	(76.6	)	$	(53.2	)	$	(74.5	)
Intangible asset	30.4			31.5			32.3
Accumulated other comprehensive income	77.0			57.8			47.6
Net amount recognized at year-end	$	30.8		$	36.1		$	5.4
Increase (decrease) in minimum liability included in other comprehensive income	$	19.2		$	10.2		$	(3.1	)
Additional year-end information for plans with accumulated benefit obligations in excess of plan assets:
Projected benefit obligation	$	426.7		$	402.4		$	378.7
Accumulated benefit obligation	409.7			391.4			372.3
Fair value of plan assets	333.1			338.2			297.8
Other Benefits:
Amounts recognized in the balance sheet consisted of:
Accrued benefit liability	$	(66.9	)	$	(67.4	)	$	(66.1	)
Additional year-end information for plans with benefit obligations in excess of plan assets:
Benefit obligation	$	106.2		$	113.0		$	108.0
Fair value of plan assets	2.7			0.8			0.7

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Components of Net Periodic Benefit Cost.The following table provides the components of net periodic benefit cost for the plans for 2005, 2004 and 2003:

	2005			2004			2003
	(in millions)
Pension Plans:
Components of net periodic benefit cost
Service cost	$	3.7		$	2.8		$	1.8
Interest cost	22.3			22.7			23.2
Expected return on plan assets	(26.5		)	(27.0		)	(22.8		)
Amortization of prior service cost	4.3			4.1			3.8
Amortization of transition (asset) or obligation	(0.7		)	(0.7		)	(1.0		)
Amortization of actuarial (gain) or loss	2.3			1.9			2.2
Net periodic benefit cost	$	5.4		$	3.8		$	7.2
Other Benefits:
Components of net periodic benefit cost
Service cost	$	1.0		$	0.9		$	0.6
Interest cost	5.6			6.5			6.9
Expected return on plan assets	—			—			(0.1		)
Amortization of prior service cost	1.8			1.8			1.8
Amortization of transition (asset) or obligation	0.7			0.7			0.7
Amortization of actuarial (gain) or loss	0.3			0.7			0.5
Net periodic benefit cost	$	9.4		$	10.6		$	10.4

The assumptions used in the measurement of LG&E’s pension benefit obligation are shown in the following table:

	2005		2004		2003
Weighted-average assumptions as of December 31:
Discount rate	5.50	%	5.75	%	6.25	%
Rate of compensation increase	5.25	%	4.50	%	3.00	%

The assumptions used in the measurement of LG&E’s net periodic benefit cost are shown in the following table:

	2005		2004		2003
Discount rate	5.75	%	6.25	%	6.75	%
Expected long-term return on plan assets	8.25	%	8.50	%	9.00	%
Rate of compensation increase	4.50	%	3.50	%	3.75	%

To develop the expected long-term rate of return on assets assumption, LG&E considered the current level of expected returns on risk free investments (primarily government bonds), the historical level of the risk premium associated with the other asset classes in which the portfolio is invested and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based on the target asset allocation to develop the expected long-term rate of return on assets assumption for the portfolio.

Assumed Healthcare Cost Trend Rates.For measurement purposes, an 11.0% annual increase in the per capita cost of covered healthcare benefits was assumed for 2005. The rate was assumed to decrease gradually to 5.0% by 2015 and remain at that level thereafter.

Assumed healthcare cost trend rates have a significant effect on the amounts reported for the healthcare plans. A 1% change in assumed healthcare cost trend rates would have the following effects:

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	1% Decrease			1% Increase
	(in millions)
Effect on total of service and interest cost components for 2005	$	(0.2	)	$	0.3
Effect on year-end 2005 postretirement benefit obligations	$	(2.8	)	$	3.1

Expected Future Benefit Payments.The following list provides the amount of expected future benefit payments, which reflect expected future service, as appropriate:

	Pension Plans		Other Benefits
	(in millions)
2006	$	29.0	$	7.7
2007	$	28.3	$	8.0
2008	$	27.6	$	8.1
2009	$	26.7	$	8.3
2010	$	25.9	$	8.4
2011-2015	$	123.4	$	42.7

Plan Assets.The following table shows LG&E’s weighted-average asset allocation by asset category at December 31:

	Target Range		2005		2004		2003
Pension Plans:
Equity securities	45% - 75%		57	%	66	%	66	%
Debt securities	30% - 50%		42	%	33	%	33	%
Other	0% - 10%		1	%	1	%	1	%
Totals			100	%	100	%	100	%
Other Benefits:
Equity securities	—	%	—	%	—	%	—	%
Debt securities	100	%	100	%	100	%	100	%
	100	%	100	%	100	%	100	%

The investment policy of the pension plans was developed in conjunction with financial consultants, investment advisors and legal counsel. The goal of the investment policy is to preserve the capital of the fund 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, Lehman Aggregate, and Lehman Long Duration Gov/Corporate 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 holdings 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,

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non-dollar and emerging market debt and asset backed securities. The cash investments should be in securities that either are of 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, 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 post retirement 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 post retirement funds are invested in a prime cash money market fund that invests primarily in a portfolio of short-term, high-quality fixed income securities issued by banks, corporations and the U.S. government.

Contributions.LG&E made discretionary contributions to the pension plan of $89.1 million during 2003 and $34.5 million in January 2004. LG&E made a discretionary contribution to the pension plan for $17.5 million in January 2006. There were no contributions during 2005.

FSP 106-2.FSP 106-2, which provided guidance on accounting for subsidies provided under the Medicare Act, was effective for the first interim or annual period beginning after June 15, 2004. The following table reflects the impact of the subsidy in 2004:

	(in millions)
Reduction in APBO	$	3.2
Effect of the subsidy on the measurement of the net periodic postretirement benefit cost:
Amortization of the actuarial experience gain/(loss)	$	0.2
Reduction in service cost due to the subsidy	—
Resulting reduction in interest cost on the APBO	0.2
Total	$	0.4

Thrift Savings Plans.LG&E has a thrift savings plan under section 401(k) of the Internal Revenue Code. Under the plan, eligible employees may defer and contribute to the plan a portion of current compensation in order to provide future retirement benefits. LG&E makes contributions to the plan by matching a portion of the employee contributions. The costs of this matching were approximately $1.3 million for 2005, $1.4 million for 2004 and $1.8 million for 2003.

Note 7—Income Taxes

Components of income tax expense are shown in the table below:

		2005			2004			2003
		(in millions)
Current	—federal	$	73.2		$	33.9		$	25.8
	—state	10.1			13.0			10.0
Deferred	—federal—net	(12.6		)	11.4			16.8
	—state—net	(1.7		)	(0.8		)	1.7
Amortization of investment tax credit		(4.1		)	(4.2		)	(4.2		)
Total income tax expense		$	64.9		$	53.3		$	50.1

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Deferred federal income tax expense during 2003 and 2004 included significant deductions attributable to federal bonus depreciation that ended after December 2004.

Components of net deferred tax liabilities included in the balance sheet are shown below:

	2005		2004
	(in millions)
Deferred tax liabilities:
Depreciation and other plant-related items	$	390.9	$	397.8
Regulatory assets and other	22.5		33.3
Total deferred tax liabilities	413.4		431.1
Deferred tax assets:
Investment tax credit	16.6		18.6
Income taxes due to customers	16.5		15.0
Pensions and related benefits	39.2		32.2
Liabilities and other	19.4		18.1
Total deferred tax assets	91.7		83.9
Net deferred income tax liability	$	321.7	$	347.2

A reconciliation of differences between the statutory U.S. federal income tax rate and LG&E’s effective income tax rate follows:

	2005		2004		2003
Statutory federal income tax rate	35.0	%	35.0	%	35.0	%
State income taxes, net of federal benefit	4.1		5.3		5.4
Reduction of income tax accruals	(1.9	)	(0.7	)	(0.4	)
Investment and other credits	(2.1	)	(3.6	)	(3.0	)
Other differences	(1.6	)	(0.2	)	(1.5	)
Effective income tax rate	33.5	%	35.8	%	35.5	%

On September 19, 2005, LG&E received notice from the Congressional Joint Committee on Taxation approving the Internal Revenue Service’s audit of LG&E’s income tax returns for the periods December 1999 through December 2003. As a result of resolving numerous tax matters during these periods, LG&E reduced income tax accruals by $3.8 million during 2005.

Kentucky House Bill 272, also known as “Kentucky’s Tax Modernization Plan”, was signed into law in March 2005. This bill contains a number of changes in Kentucky’s tax system, including the reduction of the Corporate income tax rate from 8.25% to 7% effective January 1, 2005, and a further reduction to 6% effective January 1, 2007. As a result of the income tax rate change, LG&E’s deferred tax reserve amount will exceed its actual deferred tax liability attributable to existing temporary differences since the new statutory rates are lower than the rates were when the deferred tax liability originated. This excess amount is referred to as excess deferred income taxes. In June 2005, LG&E received approval from the Kentucky Commission to establish and amortize a regulatory liability ($16.3 million) for its net excess deferred income tax balances. Under the accounting treatment, LG&E will amortize its depreciation-related excess deferred income tax balances under the average rate assumption method. The average rate assumption method matches the amortization of the excess deferred income taxes with the life of the timing differences to which they relate. Excess deferred income tax balances related to non-depreciation timing differences will be expensed in the current year due to their immaterial amount.

LG&E expects to have adequate levels of taxable income to realize its recorded deferred taxes.

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Note 8—Long-Term Debt

As of December 31, 2005, long-term debt and the current portion of long-term debt consist primarily of pollution control bonds and long-term loans from affiliated companies as summarized below.

	Stated Interest Rates	Maturities	Principal Amounts
			(in millions)
Outstanding at December 31, 2005:
Noncurrent portion	Variable - 5.90%	2008-2035	$	573.1
Current portion	Variable	2006-2027	247.5
Outstanding at December 31, 2004:
Noncurrent portion	Variable - 5.90%	2008-2033	$	574.4
Current portion	Variable	2005-2027	297.4

Under the provisions for LG&E’s variable-rate pollution control bonds, Series S, T, U, BB, CC, DD and EE, the 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, causing the bonds to be classified as current portion of long-term debt in the balance sheets. The average annualized interest rate for these bonds during 2005 and 2004 was 2.50% and 1.29%, respectively.

Pollution control series bonds are first mortgage bonds that have been issued by LG&E in connection with tax-exempt pollution control revenue bonds issued by various governmental entities, principally counties in Kentucky. A loan agreement obligates LG&E to make debt service payments to the county that equate to the debt service due from the county on the related pollution control revenue bonds. The county’s debt is also secured by an equal amount of LG&E’s first mortgage bonds (the pollution control series bonds) that are pledged to the trustee for the pollution control revenue bonds, and that match the terms and conditions of the county’s debt, but require no payment of principal and interest unless LG&E defaults on the loan agreement.

Substantially all of LG&E’s utility assets are pledged as security for its first mortgage bonds. LG&E’s first mortgage bond indenture, as supplemented, provides that portions of retained earnings will not be available for the payment of dividends on common stock, under certain specified conditions. No portion of retained earnings was restricted by this provision as of either December 31, 2005 or 2004.

Interest rate swaps are used to hedge LG&E’s underlying variable-rate debt obligations. These swaps hedge specific debt issuances and, consistent with management’s designation, are accorded hedge accounting treatment. The swaps exchange floating-rate interest payments for fixed rate interest payments to reduce the impact of interest rate changes on LG&E’s pollution control bonds.  As of December 31, 2005 and 2004, LG&E had swaps with a combined notional value of $211.3 million and $228.3 million, respectively. See Note 4, Financial Instruments.

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Redemptions and maturities of long-term debt for 2005, 2004 and 2003 are summarized below:

Year	Description	Principal Amount		Rate		Secured/ Unsecured	Maturity
		($ in millions)
2005	Pollution control bonds	$	40.0	5.90	%	Secured	Apr 2023
2005	Due to Fidelia	$	50.0	1.53	%	Secured	Jan 2005
2005	Mandatorily Redeemable Preferred Stock	$	1.3	5.875	%	Unsecured	Jul 2005
2004	Due to Fidelia	$	50.0	1.53	%	Secured	Jan 2005
2004	Mandatorily Redeemable Preferred Stock	$	1.3	5.875	%	Unsecured	Jul 2004
2003	Pollution control bonds	$	102.0	5.625	%	Secured	Aug 2019
2003	Pollution control bonds	$	26.0	5.45	%	Secured	Oct 2020
2003	First mortgage bonds	$	42.6	6.00	%	Secured	Aug 2003
2003	Mandatorily Redeemable Preferred Stock	$	1.3	5.875	%	Unsecured	Jul 2003

Issuances of long-term debt for 2005, 2004 and 2003 are summarized below:

Year	Description	Principal Amount		Rate		Secured/ Unsecured	Maturity
		($ in millions)
2005	Pollution control bonds	$	40.0	Variable		Secured	Feb 2035
2004	Due to Fidelia	$	25.0	4.33	%	Secured	Jan 2012
2004	Due to Fidelia	$	100.0	1.53	%	Secured	Jan 2005
2003	Pollution control bonds	$	128.0	Variable		Secured	Oct 2033
2003	Due to Fidelia	$	100.0	4.55	%	Unsecured	Apr 2013
2003	Due to Fidelia	$	100.0	5.31	%	Secured	Aug 2013

LG&E has existing $5.875 series mandatorily redeemable preferred stock outstanding having a current redemption price of $100 per share. The preferred stock has a sinking fund requirement sufficient to retire a minimum of 12,500 shares on July 15 of each year commencing with July 15, 2003, and the remaining 187,500 shares on July 15, 2008 at $100 per share. LG&E redeemed 12,500 shares in accordance with these provisions on July 15, 2005, 2004 and 2003, leaving 212,500 shares currently outstanding. Beginning with the three months ended September 30, 2003, LG&E reclassified its $5.875 series preferred stock as long-term debt with the minimum shares mandatorily redeemable within one year classified as current.

Long-term debt maturities for LG&E are shown in the following table:

	(in millions)
2006	$	1.3
2007	1.3
2008	18.7
2009	—
2010	—
Thereafter	799.3		(a)
Total	$	820.6

(a)Includes long-term debt of $246.2 million classified as current liabilities 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. Maturity dates for these bonds range from 2013 to 2027. LG&E does not expect to pay these amounts in 2006.

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Note 9—Notes Payable and Other Short-Term Obligations

LG&E participates in an intercompany money pool agreement wherein E.ON U.S. and/or KU make funds available to LG&E at market-based rates (based on an index of highly rated commercial paper issues) up to $400.0 million.

Total Money	Amount Pool Available		Balance Outstanding		Average Available		Interest Rate
	($ in millions)
December 31, 2005	$	400.0	$	141.2	$	258.8	4.21	%
December 31, 2004	$	400.0	$	58.2	$	341.8	2.22	%

E.ON U.S. maintains a revolving credit facility totaling $200.0 million with an affiliated company, E.ON North America, Inc., to ensure funding availability for the money pool. The balance outstanding on this facility at December 31, 2005, was $104.7 million, leaving $95.3 million available. At December 31, 2004, the facility totaled $150.0 million with a balance of $65.4 million outstanding, leaving $84.6 million available.

During June 2005, LG&E renewed five revolving lines of credit with banks totaling $185.0 million. These credit facilities expire in June 2006, and there was no outstanding balance under any of these facilities at December 31, 2005.

The covenants under these revolving lines of credit include:

·The debt/total capitalization ratio must be less than 70%;

·E.ON AG must own at least 66.667% of voting stock of LG&E directly or indirectly;

·The corporate credit rating of the company must be at or above BBB- and Baa3; and

·A limitation on disposing of assets aggregating more than 15% of total assets as of December 31, 2004.

Note 10—Commitments and Contingencies

Operating Leases.LG&E leases office space, office equipment and vehicles and accounts for these leases as operating leases. Total lease expense for 2005, 2004 and 2003, less amounts contributed by affiliated companies occupying a portion of the office space leased by LG&E, was $3.0 million, $2.8 million and $2.2 million, respectively. The future minimum annual lease payments under LG&E’s office space lease agreement for years subsequent to December 31, 2005, are shown in the following table:

	(in millions)
2006	$	3.5
2007	3.6
2008	3.7
2009	3.8
2010	3.8
Thereafter	18.5
Total	$	36.9

Sale and Leaseback Transaction.LG&E is a participant in a sale and leaseback transaction involving its 38% interest in two jointly-owned CTs at KU’s E.W. Brown generating station (Units 6 and 7). Commencing in December 1999, LG&E and KU entered into a tax-efficient, 18-year lease of the CTs. LG&E and KU have provided funds to fully defease the lease, and have executed an irrevocable notice to exercise an early purchase option contained in the lease after 15.5 years. The financial statement treatment of this transaction is no

55

different than if LG&E had retained its ownership. The leasing transaction was entered into following receipt of required state and federal regulatory approvals.

In case of default under the lease, LG&E 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, 2005, the maximum aggregate amount of default fees or amounts, which decrease over the term of the lease, was $8.2 million, of which LG&E would be responsible for $3.1 million (38%). LG&E has made arrangements with E.ON U.S., via guarantee and regulatory commitment, for E.ON U.S. to pay LG&E’s full portion of any default fees or amounts.

Letters of Credit.LG&E has provided letters of credit totaling $3.0 million to support certain obligations related to landfill reclamation.

Purchased Power.LG&E has a contract for purchased power with OVEC for various Mw capacities. LG&E has an investment of 5.63% ownership in OVEC’s common stock, which is accounted for on the cost method of accounting. In March 2005, LG&E purchased from AEP an additional 0.73% interest in OVEC for a purchase price of approximately $0.1 million, which resulted in the increase in LG&E ownership in OVEC from 4.9% to 5.63%. Through March 2006, LG&E is entitled to purchase 7% of OVEC’s output, and thereafter is entitled to purchase 5.63%, representing approximately 124 Mw of generation capacity. In April 2004, OVEC and its shareholders, including LG&E, entered into an Amended and Restated Inter-Company Power Agreement, to be effective beginning March 2006, upon the expiration of the current power contract among the parties. The parties received SEC approval under PUHCA 1935 of the Amended and Restated Inter-Company Power Agreement in February 2005. Future obligations for power purchases are shown in the following table:

	(in millions)
2006	$	11.1
2007	10.9
2008	11.0
2009	11.3
2010	11.5
Thereafter	215.1
Total	$	270.9	(a)

(a)Represents future minimum payments under OVEC purchased power agreements through 2024.

Construction Program.LG&E had approximately $23.0 million of commitments in connection with its construction program at December 31, 2005. Construction expenditures for the three year period ending December 31, 2008, are estimated to total approximately $530.0 million, although all of this amount is not currently committed, including future expenditures related to the construction of Trimble County Unit 2.

Environmental Matters.LG&E is subject to SO2 and NOx emission limits on its electric generating units pursuant to the Clean Air Act. LG&E was exempt from Phase I SO2 requirements due to its low emission rates. LG&E opted into the Phase I NOx program to take advantage of the less stringent requirements and installed burner modifications as needed to meet these limitations. LG&E’s strategy for Phase II SO2 reductions, which commenced January 1, 2000, is to increase FGD removal efficiency to delay additional capital expenditures and may also include fuel switching or upgrading FGDs. LG&E met the initial NOx emission requirements of the

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Act through installation of low-NOx burner systems. LG&E’s compliance plans are subject to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control technology. LG&E will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.

In September 1998, the EPA announced its final “NOx SIP Call” rule requiring states to impose significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged ozone transport impacts on the Northeast region. The Commonwealth of Kentucky SIP, which was approved by the EPA on June 24, 2003, requires reductions in NOx emissions from coal-fired generating units to the 0.15 lb./MMBtu level on a system-wide basis. In related proceedings in response to petitions filed by various Northeast states, in December 1999, the EPA issued a final rule pursuant to Section 126 of the Clean Air Act directing similar NOx reductions from a number of specifically targeted generating units including all LG&E units. As a result of appeals to both rules, the compliance date was extended to May 31, 2004. All LG&E generating units are in compliance with these NOx emissions reduction rules.

LG&E has added significant NOx controls to its generating units through the installation of SCR systems, advanced low-NOx burners and neural networks. The NOx control project commenced in late 2000 with the controls being placed into operation prior to the 2004 summer ozone season. As of December 31, 2005, LG&E incurred total capital costs of approximately $188.0 million to reduce its NOx emissions below the 0.15 lb./MMBtu level on a company-wide basis. In addition, LG&E will incur additional operating and maintenance costs in operating new NOx controls. LG&E believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. LG&E anticipated that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanism and believed that a significant portion of such costs could be recovered. In April 2001, the Kentucky Commission granted recovery of these costs for LG&E.

On March 10, 2005, the EPA issued the final CAIR which requires substantial additional reductions in SO2 and NOx emissions from electric generating units. The CAIR provides for a two-phased reduction program with Phase I reductions in NOx and SO2 emissions in 2009 and 2010, respectively, and Phase II reductions in 2015. On March 15, 2005, the EPA issued a related regulation, the final CAMR, which requires substantial mercury reductions from electric generating units. CAMR also provides for a two-phased reduction, with the Phase I target in 2010 achieved as a “co-benefit” of the controls installed to meet CAIR. Additional control measures will be required to meet the Phase II target in 2018. Both CAIR and CAMR establish a cap and trade framework, in which a limit is set on total emissions and allowances can be bought or sold on the open market to be used for compliance, unless the state chooses another approach. LG&E currently has FGDs on all its units but will continue to evaluate improvements to further reduce SO2 emissions.

LG&E is also monitoring several other air quality issues which may potentially impact coal-fired power plants, including EPA’s revised air quality standards for ozone and particulate matter and measures to implement the EPA’s CAVR. From time to time, LG&E has conducted negotiations with the relevant regulatory authorities to address various environmental matters, including remedial measures aimed at controlling particulate matter emissions from its Mill Creek plant. LG&E previously settled a number of property damage claims from residents adjacent to the plant and completed significant remedial measures as part of its ongoing capital construction program. LG&E has converted the Mill Creek Station to wet stack operation in an effort to resolve all outstanding issues related to particulate matter emissions. In addition, LG&E has periodically conducted negotiations with the relevant regulatory authorities to resolve potential liability for cleanup of off-site facilities that allegedly handled materials associated with company operations.

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LG&E owns or formerly owned three properties which are the location of past MGP operations. Various contaminants are typically found at such former MGP sites and environmental remediation measures are frequently required. With respect to the sites, LG&E has substantially completed cleanups, obtained regulatory approval of site management plans, or reached agreements for other parties to assume responsibility for cleanup. Based on currently available information, management estimates that it could incur additional costs of $0.4 million for additional cleanup. Accordingly, an accrual for this amount has been recorded in the accompanying financial statements at December 31, 2005 and 2004.

Note 11—Jointly Owned Electric Utility Plant

LG&E owns a 75% undivided interest in Trimble County Unit 1 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:

	Trimble County
	LG&E			IMPA		IMEA		Total
Ownership interest	75		%	12.88	%	12.12	%	100	%
Mw capacity	383			66		62		511
LG&E’s 75% ownership:
(in millions)
Cost	$	599.2
Accumulated depreciation	(221.1		)
Net book value	$	378.1
Construction work in progress (included above)	$	9.1

LG&E and KU jointly own the following combustion turbines:

		LG&E			KU			Total
		($ in millions)
Paddy’s Run 13	Ownership %	53		%	47		%	100		%
	Mw capacity	84			74			158
	Cost	$	34.0		$	30.1		$	64.1
	Depreciation	(5.2		)	(4.6		)	(9.8		)
	Net book value	$	28.8		$	25.5		$	54.3
E.W. Brown 5	Ownership %	53		%	47		%	100		%
	Mw capacity	62			55			117
	Cost	$	24.0		$	20.2		$	44.2
	Depreciation	(3.5		)	(3.0		)	(6.5		)
	Net book value	$	20.5		$	17.2		$	37.7
E.W. Brown 6	Ownership %	38		%	62		%	100		%
	Mw capacity	59			95			154
	Cost	$	25.3		$	38.9		$	64.2
	Depreciation	(4.2		)	(7.9		)	(12.1		)
	Net book value	$	21.1		$	31.0		$	52.1
E.W. Brown 7	Ownership %	38		%	62		%	100		%
	Mw capacity	59			95			154
	Cost	$	24.9		$	39.7		$	64.6
	Depreciation	(6.4		)	(8.2		)	(14.6		)
	Net book value	$	18.5		$	31.5		$	50.0

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Trimble 5	Ownership %	29		%	71		%	100		%
	Mw capacity	46			114			160
	Cost	$	16.4		$	39.7		$	56.1
	Depreciation	(1.9		)	(4.7		)	(6.6		)
	Net book value	$	14.5		$	35.0		$	49.5
Trimble 6	Ownership %	29		%	71		%	100		%
	Mw capacity	46			114			160
	Cost	$	16.2		$	39.7		$	55.9
	Depreciation	(1.9		)	(4.7		)	(6.6		)
	Net book value	$	14.3		$	35.0		$	49.3
Trimble 7	Ownership %	37		%	63		%	100		%
	Mw capacity	59			101			160
	Cost	$	19.3		$	33.3		$	52.6
	Depreciation	(1.0		)	(1.7		)	(2.7		)
	Net book value	$	18.3		$	31.6		$	49.9
Trimble 8	Ownership %	37		%	63		%	100		%
	Mw capacity	59			101			160
	Cost	$	19.2		$	32.8		$	52.0
	Depreciation	(1.0		)	(1.7		)	(2.7		)
	Net book value	$	18.2		$	31.1		$	49.3
Trimble 9	Ownership %	37		%	63		%	100		%
	Mw capacity	59			101			160
	Cost	$	19.2		$	32.8		$	52.0
	Depreciation	(1.0		)	(1.6		)	(2.6		)
	Net book value	$	18.2		$	31.2		$	49.4
Trimble 10	Ownership %	37		%	63		%	100		%
	Mw capacity	59			101			160
	Cost	$	19.1		$	32.8		$	51.9
	Depreciation	(0.9		)	(1.6		)	(2.5		)
	Net book value	$	18.2		$	31.2		$	49.4
Trimble CT Pipeline	Ownership %	29		%	71		%	100		%
	Cost	$	2.0		$	4.9		$	6.9
	Depreciation	(0.2		)	(0.6		)	(0.8		)
	Net book value	$	1.8		$	4.3		$	6.1
Trimble CT Substation 5 & 6	Ownership %	29		%	71		%	100		%
	Cost	$	1.5		$	3.6		$	5.1
	Depreciation	(0.1		)	(0.3		)	(0.4		)
	Net book value	$	1.4		$	3.3		$	4.7
Trimble CT Substation 7 - 10	Ownership %	37		%	63		%	100		%
	Cost	$	3.1		$	4.9		$	8.0
	Depreciation	(0.1		)	(0.2		)	(0.3		)
	Net book value	$	3.0		$	4.7		$	7.7

In addition to these generating units, LG&E and KU share joint ownership in the Brown Inlet Air Cooling system. LG&E owns 10% of the system, attributable to Brown Unit 5, which provides an additional 10 Mw of capacity.

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Note 12—Segments of Business and Related Information

LG&E is a regulated public utility engaged in the generation, transmission, distribution and sale of electricity and the storage, distribution and sale of natural gas. LG&E is regulated by the Kentucky Commission and files electric and natural gas financial information separately with the Kentucky Commission. The Kentucky Commission establishes rates specifically for the electric and natural gas businesses. Therefore, management reports and analyzes financial performance based on the electric and natural gas segments of the business. Financial data for business segments follow:

	Electric		Gas		Total
	(in millions)
2005
Operating revenues	$	987.4	$	436.9	$	1,424.3
Depreciation and amortization	106.2		17.9		124.1
Income taxes	60.0		4.9		64.9
Interest income	0.5		0.1		0.6
Interest expense	30.3		6.5		36.8
Net income	119.4		9.5		128.9
Total assets	2,475.0		671.4		3,146.4
Construction expenditures	96.5		42.4		138.9
2004
Operating revenues	$	815.7	$	357.1	$	1,172.8
Depreciation and amortization	100.0		16.6		116.6
Income taxes	48.3		5.0		53.3
Interest income	0.2		—		0.2
Interest expense	27.3		5.5		32.8
Net income	87.2		8.4		95.6
Total assets	2,416.5		550.0		2,966.5
Construction expenditures	113.4		34.9		148.3
2003
Operating revenues	$	768.2	$	325.3	$	1,093.5
Depreciation and amortization	96.5		16.8		113.3
Income taxes	44.7		5.4		50.1
Interest income	—		—		—
Interest expense	25.7		5.0		30.7
Net income	80.6		10.2		90.8
Total assets	2,338.9		543.2		2,882.1
Construction expenditures	178.0		35.0		213.0

Note 13—Related Party Transactions

LG&E, subsidiaries of E.ON U.S. and other subsidiaries of E.ON engage in related party transactions. Transactions between LG&E and its subsidiary LG&E R are eliminated upon consolidation with LG&E. Transactions between LG&E and E.ON U.S. subsidiaries are eliminated upon consolidation of E.ON U.S. Transactions between LG&E and E.ON subsidiaries are eliminated upon consolidation of E.ON. These transactions are generally performed at cost and are in accordance with the prior SEC regulations under PUHCA 1935 and the applicable FERC and Kentucky Commission regulations. Amounts payable to and receivable from related parties are netted and presented as accounts payable to affiliated companies on the balance sheet of LG&E, as allowed due to the right of offset. Obligations related to intercompany debt arrangements with E.ON U.S. and Fidelia are presented as separate line items on the balance sheet, as appropriate. The significant related party transactions are disclosed below.

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Electric Purchases

LG&E and KU purchase energy from each other in order to effectively manage the load of their retail and off-system customers. In addition, LG&E sells energy to LEM, a subsidiary of E.ON U.S. These sales and purchases are included in the Statements of Income as Electric Operating Revenues and Purchased Power Operating Expense. LG&E intercompany electric revenues and purchased power expense for the years ended December 31, 2005, 2004 and 2003 were as follows:

	2005		2004		2003
	(in millions)
Electric operating revenues from KU	$	91.6	$	58.7	$	53.7
Electric operating revenues from LEM	—		0.4		9.4
Purchased power from KU	95.5		61.7		46.7

Interest Charges

See Note 9, Notes Payable and Other Short-Term Obligations, for details of intercompany borrowing arrangements. Intercompany agreements do not require interest payments for receivables related to services provided when settled within 30 days.

LG&E’s intercompany interest income and expense for the years ended December 31, 2005, 2004 and 2003 were as follows:

	2005		2004		2003
	(in millions)
Interest on money pool loans	$	1.8	$	0.3	$	1.8
Interest on Fidelia loans	10.9		11.9		5.0

Other Intercompany Billings

E.ON U.S. Services provides LG&E with a variety of centralized administrative, management and support services. These charges include payroll taxes paid by E.ON U.S. on behalf of LG&E, labor and burdens of E.ON U.S. Services employees performing services for LG&E and vouchers paid by E.ON U.S. Services on behalf of LG&E. The cost of these services are directly charged to LG&E, or for general costs which cannot be directly attributed, charged based on predetermined allocation factors, including the following ratios: number of customers, total assets, revenues, number of employees and other statistical information. These costs are charged on an actual cost basis.

In addition, LG&E and KU provide services to each other and to E.ON U.S. Services. Billings between LG&E and KU relate to labor and overheads associated with union employees performing work for the other utility, charges related to jointly-owned combustion turbines, and other miscellaneous charges. Billings from LG&E to E.ON U.S. Services related to information technology-related services provided by LG&E employees, cash received by E.ON U.S. Services on behalf of LG&E and services provided by LG&E to other non-regulated businesses which are paid through E.ON U.S. Services.

Intercompany billings to and from LG&E for the years ended December 31, 2005, 2004 and 2003 were as follows:

61

	2005		2004		2003
	(in millions)
E.ON U.S. Services billings to LG&E	$	208.4	$	190.7	$	196.1
LG&E billings to KU	100.5		59.5		77.2
KU billings to LG&E	28.6		7.2		16.6
LG&E billings to E.ON U.S. Services	8.2		12.5		23.7

The increase in 2005 billings between LG&E and KU is largely due to the increase in the unit cost of purchased power resulting from the 2005 increases in fuel costs.

Note 14—Accumulated Other Comprehensive Income

Accumulated other comprehensive income (loss) consisted of the following:

	Minimum Pension Liability Adjustment			Accumulated Derivative Gain or Loss			Pre-Tax			Income Taxes			Net
	(in millions)
Balance at December 31, 2002	$	(50.7	)	$	(17.2	)	$	(67.9	)	$	27.4		$	(40.5	)
Minimum pension liability adjustment	3.1			—			3.1			(1.2		)	1.9
Gains (losses) on derivative instruments designated and qualifying as cash flow hedging instruments	—			0.9			0.9			(0.4		)	0.5
Balance at December 31, 2003	(47.6		)	(16.3		)	(63.9		)	25.8			(38.1		)
Minimum pension liability adjustment	(10.2		)	—			(10.2		)	4.1			(6.1		)
Gains (losses) on derivative instruments designated and qualifying as cash flow hedging instruments	—			(2.3		)	(2.3		)	0.9			(1.4		)
Balance at December 31, 2004	$	(57.8	)	$	(18.6	)	$	(76.4	)	$	30.8		$	(45.6	)
Minimum pension liability adjustment	(19.2		)	—			(19.2		)	6.7			(12.5		)
Gains (losses) on derivative instruments designated and qualifying as cash flow hedging instruments	—			(0.1		)	(0.1		)	—			(0.1		)
Balance at December 31, 2005	$	(77.0	)	$	(18.7	)	$	(95.7	)	$	37.5		$	(58.2	)

Note 15—Selected Quarterly Data (Unaudited)

Selected financial data for the four quarters of 2005 and 2004 are shown below. Because of seasonal fluctuations in temperature and other factors, results for quarters may fluctuate throughout the year.

	Quarters Ended
	March		June		September		December
	(in millions)
2005
Operating revenues	$	402.4	$	280.7	$	318.6	$	422.6
Net operating income	61.6		52.5		65.9		49.9
Net income	33.9		28.0		42.0		25.0
2004
Operating revenues	$	362.0	$	236.2	$	261.8	$	312.8
Net operating income	47.6		34.6		62.8		40.0
Net income	24.2		17.1		32.5		21.8

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Note 16—Subsequent Events

On January 20, 2006, LG&E made a discretionary contribution to the pension plan in the amount of $17.5 million.

On February 27, 2006, the AG, KIUC, LG&E and KU reached a settlement agreement on the future ratemaking treatment of the VDT surcredits and costs and subsequently submitted a joint motion to the Kentucky Commission to approve the unanimous settlement agreement. Under the terms of the settlement agreement, the VDT surcredit will continue at the current level until such time as LG&E files for a change in electric or gas base rates. The Kentucky Commission held a public hearing in the proceeding on March 21, 2006 and issued an order thereafter approving the settlement agreement.

On March 17, 2006, the FERC issued an order conditionally approving the request of LG&E and KU to exit the MISO.

The Companies must satisfy a number of conditions to effect their exit from the MISO including:

·Submission of various compliance filings addressing:

·the Companies’ hold-harmless obligations under the MISO Transmission Owners’ Agreement, and the amount of the MISO exit fee to be paid by the Companies as calculated under the approved methodology;

·the Companies’ anticipated arrangements with SPP and TVA, including revisions to address certain independence and transmission planning considerations, and reciprocity arrangements to ensure certain KU requirements customers do not incur pancaked rates for transmission and ancillary services;

·the Companies’ proposed OATT, as revised to address possible capacity hoarding, available transmission calculation methodology, curtailment priority and pricing, among other matters; and

·the Companies’ finalized arrangements with the SPP and TVA.

·The Companies must also file an application of the proposed OATT under Section 205 of the Federal           Power Act including a proposed return on equity.

While LG&E and KU believe they can reasonably achieve all of the conditions imposed by the FERC order, completion of a number of the conditions is dependent upon the actions or agreement of third parties. There is also a risk that the FERC decision will be challenged by intervenors with a request for rehearing, which could happen within 30 days of the decision. The Companies are currently unable to estimate the time period, if any, in which the conditions of the FERC order might be satisfied, the Companies might receive Kentucky Commission approval and, thereafter, exit the MISO.

63

Louisville Gas and Electric Company
REPORT OF MANAGEMENT

The management of Louisville Gas and Electric Company (“LG&E”) is responsible for the preparation and integrity of the financial statements and related information included in this Annual Report. These statements have been prepared in accordance with accounting principles generally accepted in the United States applied on a consistent basis and, necessarily, include amounts that reflect the best estimates and judgment of management.

LG&E’s financial statements for the three years ended December 31, 2005, have been audited by Pricewaterhouse-Coopers LLP, an independent registered public accounting firm. Management made available to Pricewaterhouse-Coopers LLP all LG&E’s financial records and related data as well as the minutes of shareholders’ and directors’ meetings.

Management has established and maintains a system of internal controls that provides reasonable assurance that transactions are completed in accordance with management’s authorization, that assets are safeguarded and that financial statements are prepared in conformity with generally accepted accounting principles. Management believes that an adequate system of internal controls is maintained through the selection and training of personnel, appropriate division of responsibility, establishment and communication of policies and procedures and by regular reviews of internal accounting controls by LG&E’s internal auditors. Management reviews and modifies its system of internal controls in light of changes in conditions and operations, as well as in response to recommendations from the internal and external auditors. These recommendations for the year ended December 31, 2005, did not identify any material weaknesses in the design and operation of LG&E’s internal control structure.

LG&E is not an accelerated filer under the Sarbanes-Oxley Act of 2002 and associated rules (the “Act”) and consequently anticipates issuing Management’s Report on Internal Controls over Financial Reporting pursuant to Section 404 of the Act in their first periodic reports covering the fiscal year ended December 31, 2007, as permitted by SEC rulemaking.

In carrying out its oversight role for the financial reporting and internal controls of LG&E, the Board of Directors meets regularly with LG&E’s independent registered public accounting firm, internal auditors and management. The Board of Directors reviews the results of the independent registered public accounting firm’s audit of the financial statements and their audit procedures, and discusses the adequacy of internal accounting controls. The Board of Directors also approves the annual internal auditing program and reviews the activities and results of the internal auditing function. Both the independent registered public accounting firm and the internal auditors have access to the Board of Directors at any time.

LG&E maintains and internally communicates a written code of business conduct and a senior financial officer code of ethics which address, among other items, potential conflicts of interest, compliance with laws, including those relating to financial disclosure, and the confidentiality of proprietary information.

S. Bradford Rives
Chief Financial Officer

Louisville Gas and Electric Company
Louisville, Kentucky

Date: March 29, 2006

64

Report of Independent Registered Public Accounting Firm

To the Shareholder of Louisville Gas and Electric Company:

In our opinion, the accompanying balance sheet and the related statement of capitalization, income, retained earnings, cash flows and comprehensive income present fairly, in all material respects, the financial position of Louisville Gas and Electric Company at December 31, 2005 and December 31, 2004, and the results ofitsoperations and itscash flows for each of the three years in the period ended December 31, 2005 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 index appearing under Item 15(a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related  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. 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 1 to the financial statements, effective December 31, 2005, Louisville Gas and Electric Company adopted Statement of Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations.

/s/ PricewaterhouseCoopers LLP
Louisville, Kentucky
February 8, 2006

65

Admission Ticket

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Annual Meeting Admission Ticket

Louisville Gas and Electric Company

Louisville Gas and Electric

Annual Meeting of Shareholders

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02 - John R. McCall

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04 - Paul W. Thompson

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05 - Chris Hermann

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July 20, 2006

Victor A. Staffieri, John R. McCall and S. Bradford Rives are hereby appointed as proxies, with full power of substitution to vote the shares of the shareholder(s) named on the reverse side hereof at the Annual Meeting of Shareholders of Louisville Gas and Electric Company to be held on July 20, 2006 and at any adjournment thereof, as directed on the reverse side hereof, and in their discretion to act upon any other matters that may properly come before the meeting or any adjournment thereof.

THIS PROXY IS SOLICITED ON BEHALF OF THE BOARD OF DIRECTORS AND WILL BE VOTED AS YOU SPECIFY. IF NOT SPECIFIED, THIS PROXY WILL BE VOTED FOR ALL OF THE PROPOSALS. A VOTE FOR PROPOSAL 1 INCLUDES DISCRETIONARY AUTHORITY TO CUMULATE VOTES SELECTIVELY AMONG THE NOMINEES AS TO WHOM AUTHORITY TO VOTE HAS NOT BEEN WITHHELD.

Please mark, sign and date this proxy on the reverse side and return the completed proxy promptly in the enclosed envelope.