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
(Name of Registrant as Specified In Its Charter)
(Name of Person(s) Filing Proxy Statement, if other than the Registrant)
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June 8, 2005

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 Tuesday, June 21, 2005 at 2:00 p.m., local time in the Twelfth Floor Conference Room at the LG&E Building, 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 2005 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 LG&E Building, Third and Main Streets, Louisville, Kentucky, on Tuesday June 21, 2005, 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 2006;

2.A proposal to approve and ratify the appointment of PricewaterhouseCoopers LLP as the independent registered public accounting firm of LG&E for 2005; and

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

The close of business on April 29, 2005 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 8, 2005

PROXY STATEMENT

ANNUAL MEETING OF SHAREHOLDERS TO BE HELD JUNE 21, 2005

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 June 21, 2005, and at any adjournment of such meeting. The meeting will be held in the Twelfth Floor Conference Room of the LG&E Building, Third and Main Streets, Louisville, Kentucky. This proxy statement and the accompanying proxy were first mailed to shareholders on or about June 8, 2005.

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 April 29, 2005, 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 LG&E Energy LLC (“LG&E Energy”). 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 April 29, 2005, 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.

Required Vote

Owners of record at the close of business on April 29, 2005 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.

LG&E Energy 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. LG&E Energy 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 2004 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 2006 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 LG&E Energy 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 2006 Annual Meeting of Shareholders

Victor A.Staffieri (Age 50):   Mr. Staffieri is Chairman, President and Chief Executive Officer of LG&E Energy, 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 LG&E Energy, LG&E and KU since April 2001 and was a director of Powergen from April 2001 until January 2004.

John R. McCall (Age 61):   Mr. McCall is Executive Vice President, General Counsel and Secretary of LG&E Energy and Executive Vice President, General Counsel and Corporate Secretary of LG&E and KU. Mr. McCall has held these positions at LG&E Energy and LG&E since July 1994 and at KU since May 1998. Mr. McCall has been a director of LG&E Energy, LG&E and KU since January 2004.

S. Bradford Rives (Age 46):   Mr. Rives is Chief Financial Officer of LG&E Energy, 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 LG&E Energy, LG&E and KU since January 2004.

Paul W. Thompson (Age 48):   Mr. Thompson is Senior Vice President—Energy Services of LG&E Energy, 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 LG&E Energy, LG&E and KU since January 2005.

Chris Hermann (Age 57):   Mr. Hermann is Senior Vice President—Energy Delivery of LG&E Energy, 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 LG&E Energy, LG&E and KU since January 2005.

INFORMATION CONCERNING THE BOARD OF DIRECTORS

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

During 2004, there were a total of 11 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.

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Compensation of Directors

Directors who are also officers of E.ON, LG&E Energy or their 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, 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 LG&E Energy executive compensation plans would be performed by the Senior Vice President—Corporate Executive Human Resources of E.ON AG. Through May 2005, this duty was performed by Dr. Stefan Vogg and will be assumed by a successor.

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 2004, the Board maintained direct and indirect contact with the 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 2004 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.

Nominations

Due to the small size of the Board and the fact that LG&E Energy 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,

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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. Shareholder nominations must provide timely written notice in writing 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 2005

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, 2005. 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, LG&E Energy 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 LG&E Energy’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 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. Through May 2005, this duty was performed by Dr. Stefan Vogg and will be assumed by a successor. This report describes the compensation policies applicable to LG&E’s executive officers for the last completed fiscal year.

With respect to 2004, Dr. Vogg, in consultation with certain officers of E.ON AG, LG&E Energy, LG&E and KU, including members 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 2004, 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 2004 for their 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 LG&E Energy 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 2004, 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 2004, the Compensation Group reviewed competitive compensation information 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 2004 to generally approach the 50th percentile of the competitive range from the Survey Group. Salaries, short-term incentives and long-term incentives for 2004 are described below. (The utilities and utility holding companies that were in the Survey Group were not necessarily the

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same as those in the Dow Jones Utility Average used in a company performance graph in this proxy statement.)

The 2004 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 2004 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 2004 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 2004 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, LG&E Energy 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 2004, the Company Performance Award targets for named executive officers were 30% of base salary, and the Individual Performance Award targets were 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 175% 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 175% of their targeted Individual Performance Award amounts dependent upon individual performance as measured by management effectiveness.

Using the relevant E.ON, LG&E Energy, LG&E/KU and other subsidiaries’ performance against goals in 2004, the Compensation Group determined relative annual performance against targets for Company Performance Awards. Based upon this determination, Company Performance Awards for 2004 to the named executive officers were paid ranging from 118% to 131% of target and 36% to 39% 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 32% to 71% of base salary.

Long-Term Incentives

The Compensation Group determines the competitive long-term grants under the Long-Term Plan and the E.ON SAR Plan to be awarded for each executive based on the long-term awards for the 50th percentile of the Survey Group. The aggregate expected value of the awards is intended to approach the

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expected value of long-term incentives payable to executives in similar positions with companies in the 50th percentile of the Survey Group, depending upon achievement of targeted Company performance.

In 2004, 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 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 2004 grants of SAR’s was substantially dependent upon the changing value of E.ON shares in the marketplace.

SAR’s are subject to two year vesting and performance requirements.  No regular payouts of performance units under the Long-Term Plan occurred during 2004 as the three-year performance periods had not been completed.

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 or 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 established the minimum levels of Mr. Staffieri’s base compensation, although the Chairman of E.ON retains discretion to increase such compensation. For 2004, the Compensation Group established Mr. Staffieri’s compensation and short-term and long-term awards using comparisons 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 2004 compensation are set forth below.

Base Salary.   Mr. Staffieri was paid a total base salary of $673,236 during 2004, pursuant to the 2000 Agreement, as amended. The Compensation Group, in determining Mr. Staffieri’s 2004 annual salary, including the minimum, considered his individual performance in the prior growth of LG&E Energy and the comparative compensation data described above.

Short-Term Incentives.   Mr. Staffieri’s short-term incentive target award as Chief Executive Officer was 70% of his 2004 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 2004 short-term incentive payouts were based 40% on achievement of Company Performance Award targets and 60% on achievement of Individual Performance Award targets.

For 2004, the Company Performance Award payout for Mr. Staffieri was 131% of target and 37% of his 2004 base salary and the Individual Performance Award payout was 170% of target and 71% of his 2004 base salary. Mr. Staffieri’s Company Performance Award was based on LG&E Energy EBIT. His

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Company Performance Award was calculated based upon annual Company performance as described 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 LG&E Energy, LG&E, KU and other subsidiaries, Company growth and other measures.

Long-Term Incentive Grant.   In 2004, Mr. Staffieri received 883,619 performance units for the 2004-2006 performance period under the Long-Term Plan and 24,778 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 2004 as indicated in the “Option/SAR Exercises and Year-End Value Table.”  As with other executive officers, no regular payouts of performance units under the Long-Term Plan occurred during 2004 as the three-year performance periods had not been completed.

Other.   In 2004, Mr. Staffieri also received a retention payment in connection with a 2002 amendment to his employment and severance agreement in the amount of $872,032, 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 LG&E Energy and, accordingly, there are no trading prices for LG&E’s Common Stock. During 2004, all of the common stock or membership interests of LG&E Energy 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, 1999, through December 31, 2004, 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, 1999, 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 LG&E Energy, 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, 2004, as required, in all capacities in which they served LG&E, KU, LG&E Energy or its subsidiaries during 2002, 2003 and 2004:

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	2004	673,236	728,159	31,572			—		24,778	0	941,069	(3)
Chairman of the Board,	2003	648,902	741,340	39,461			—		25,282	0	902,945	(4)
President and Chief	2002	630,001	650,101	24,282			—		6,250	1,483,377	2,433,735	(5)
Executive Officer
John R. McCall	2004	408,949	296,015	9,365			—		8,600	0	670,532	(3)
Executive Vice	2003	389,475	313,933	198,681	(6)		—		8,671	0	47,529	(4)
President, General	2002	363,975	251,543	144,756	(6)		—		3,611	401,580	1,390,557	(5)
Counsel and Corporate
Secretary
S. Bradford Rives	2004	332,001	230,355	7,293			—		5,586	0	517,626	(3)
Chief Financial Officer	2003	305,495	243,607	6,880			—		5,345	0	423,923	(4)
	2002	280,019	180,145	6,616			—		2,877	204,450	486,491	(5)
Paul W. Thompson	2004	286,258	209,048	8,273			—		4,697	0	435,220	(3)
Senior Vice President—	2003	269,071	187,526	7,232			—		4,792	0	10,151	(4)
Energy Services	2002	262,497	147,944	8,106			—		2,604	290,000	440,486	(5)
Chris Hermann	2004	262,412	179,732	7,891			—		3,311	0	416,884	(3)
Senior Vice President—	2003	252,928	166,267	4,905			—		3,378	0	22,463	(4)
Energy Delivery	2002	246,748	129,505	7,892			—		2,448	204,450	228,722	(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 2004, 2003 or 2002 as the three-year performance periods had not been completed. Amounts for year 2002 reflect acceleration of open performance periods upon the change in control event resulting from the Powergen shareholders’ approval of the E.ON transaction.

(3)Includes employer contributions to 401(k) plan, nonqualified thrift plan, employer paid life insurance premiums, vacation sell back and retention payments in 2004 as follows: Mr. Staffieri $6,500, $35,937, $26,600, $0 and $872,032, respectively; Mr. McCall $6,095, $15,662, $22,050, $2,359 and $613,425,  respectively; Mr. Rives $1,571, $15,736, $1,042, $1,277 and $498,000, respectively; Mr. Thompson, $4,353, $9,861, $2,259, $0 and $418,747, respectively and Mr. Hermann, $6,228, $6,754, $6,250, $4,037 and $393,615, respectively. Mr. McCall’s figure also includes $10,941 representing certain overseas assignment and tax equalization amounts. 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 2003 as follows: Mr. Staffieri, $837,375; Mr. McCall, $0; Mr. Rives, $403,556; Mr. Thompson, $0; and Mr. Hermann, $0.

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(5)Includes retention payments in 2002 as follows: Mr. Staffieri, $2,349,170; Mr. McCall, $1,346,416; Mr. Rives, $87,746; Mr. Thompson, $425,926; and Mr. Hermann, $211,342, respectively.

(6)Includes financial planning, automobile, spouse travel, dues, overseas compensation and tax payments in 2003 ($1,500, $4,000, $7,202, $0, $0 and $178,445) and 2002 ($2,000, $7,586, $50,589, $240, $36,398 and $48,143) respectively.

OPTION/SAR GRANTS TABLE
Option/SAR Grants in 2004 Fiscal Year

The following table contains information at December 31, 2004, with respect to grants of E.ON AG stock appreciation rights (“SAR’s”) to the named executive officers:

	Individual Grants
	Number of Securities Underlying Options/SAR’s		Percent of Total Options/SAR’s Granted to			Exercise Or Base Price		Potential Realizable Value At Assumed Annual Rates of Stock Price Appreciation For Option Term
Name	Granted (#)(1)		Employees in Fiscal Year(2)			($/ Share)		Expiration Date	0% ($)		5% ($)	10% ($)
Victor A. Staffieri		24,778		39.1	%		61.76	12/31/2010		0	622,981	1,451,812
John R. McCall		8,600		13.6	%		61.76	12/31/2010		0	216,226	503,898
S. Bradford Rives		5,586		8.8	%		61.76	12/31/2010		0	140,446	327,299
Paul W. Thompson		4,697		7.4	%		61.76	12/31/2010		0	118,094	275,210
Chris Hermann		3,311		5.2	%		61.76	12/31/2010		0	83,247	194,001

(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.

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

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OPTION/SAR EXERCISES AND YEAR-END VALUE TABLE
Aggregated Option/SAR Exercises in 2004 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, 2004:

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		6,250		51,969		0/50,060		0/1,913,016
John R. McCall		3,611		30,025		0/17,271		0/659,088
S. Bradford Rives		2,877		23,922		0/10,931		0/414,603
Paul W. Thompson		0		0		2,604/9,489		107,649/362,612
Chris Hermann		0		0		2,448/6,689		101,200/255,613

(1)   Amounts shown are E.ON SAR’s.

LONG-TERM INCENTIVE PLAN AWARDS TABLE
Long-Term Incentive Plan Awards in 2004 Fiscal Year

The following table provides information concerning awards of performance units made in fiscal year 2004 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	883,619		12/31/2006		441,810	883,619		1,325,429
John R. McCall	306,712		12/31/2006		153,356	306,712		460,068
S. Bradford Rives	199,200		12/31//2006		99,600	199,200		298,800
Paul W. Thompson	167,499		12/31/2006		83,750	167,499		251,249
Chris Hermann	118,084		12/31/2006		59,042	118,084		177,126

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 2004, 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 LG&E Energy.

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Pension Plans

The following table shows the estimated pension benefits payable to a covered participant at normal retirement age under LG&E Energy’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 LG&E Energy and its subsidiaries:

2004 PENSION PLAN TABLE

	Years of Service
Remuneration	15		20		25		30 or more
$   100,000	$	42,592	$	42,592	$	42,592	$	42,592
$   200,000	$	106,592	$	106,592	$	106,592	$	106,592
$   300,000	$	170,592	$	170,592	$	170,592	$	170,592
$   400,000	$	234,592	$	234,592	$	234,592	$	234,592
$   500,000	$	298,592	$	298,592	$	298,592	$	298,592
$   600,000	$	362,592	$	362,592	$	362,592	$	362,592
$   700,000	$	426,592	$	426,592	$	426,592	$	426,592
$   800,000	$	490,592	$	490,592	$	490,592	$	490,592
$   900,000	$	554,592	$	554,592	$	554,592	$	554,592
$1,000,000	$	618,592	$	618,592	$	618,592	$	618,592
$1,100,000	$	682,592	$	682,592	$	682,592	$	682,592
$1,200,000	$	746,592	$	746,592	$	746,592	$	746,592
$1,300,000	$	810,592	$	810,592	$	810,592	$	810,592
$1,400,000	$	874,592	$	874,592	$	874,592	$	874,592
$1,500,000	$	938,592	$	938,592	$	938,592	$	938,592
$1,600,000	$	1,002,592	$	1,002,592	$	1,002,592	$	1,002,592
$1,700,000	$	1,066,592	$	1,066,592	$	1,066,592	$	1,066,592
$1,800,000	$	1,130,592	$	1,130,592	$	1,130,592	$	1,130,592
$1,900,000	$	1,194,592	$	1,194,592	$	1,194,592	$	1,194,592

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 LG&E Energy at December 31, 2004 were as follows:  12 years for Mr. Staffieri; 10 years for Mr. McCall; 21 years for Mr. Rives; 13 years for Mr. Thompson; and 34 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 LG&E Energy, 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 LG&E Energy, 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 $803,702 for Mr. Staffieri; $375,678 for Mr. McCall; $294,765 for Mr. Rives; $254,564 for Mr. Thompson; and $231,544 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 and 2004 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) his annual base salary and (2) his 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 24 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 24 months following a change in control, these officers 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.

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

REPORT ON 2004 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 four meetings during 2004.

The financial statements of Louisville Gas and Electric Company and Subsidiary 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, 2004, 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, 2004, 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, 2004 and December 31, 2003 are as follows: (Certain amounts for 2003 have been reclassified to conform to 2004 presentation.)

	LG&E
	2004		2003
·  Audit Fees
·  Audit Fees	$	188,333	$	128,862
·  Internal Controls	$	16,667	$	—
·  Comfort Letter Procedures	$	—	$	51,154
·  Regulatory Work	$	—	$	4,665
·  Total Audit Fees	$	205,000	$	182,681
·  Audit-Related Fees
·  Pension Plan Audits	$	36,667	$	17,200
·  Total Audit-Related Fees	$	36,667	$	17,200
·  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, 2004, all filing requirements have been complied with.

SHAREHOLDER PROPOSALS AND NOMINATIONS

Any shareholder may submit a proposal for consideration at the 2006 annual meeting. Any shareholder desiring to submit a proposal for inclusion in the proxy statement for consideration at the 2006 annual meeting should forward the proposal so that it will be received at LG&E’s principal executive offices no later than March 31, 2006. 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 2006 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 communications that are commercial advertisements or other forms of solicitation or individual service or

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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. Two of our five directors were in attendance at the LG&E annual meeting in 2004.

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 2004 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 March 24, 2005)

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 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 audit:

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 judgement 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  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.

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.

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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

2004 FINANCIAL REPORT

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LOUISVILLE GAS AND ELECTRIC COMPANY

2004 FINANCIAL REPORT

TABLE OF CONTENTS

Market for the Registrant’s Common Equity and Related Stockholder Matters

Consolidated Statements of Income

Consolidated Statements of Retained Earnings

Consolidated Statements of Comprehensive Income

Consolidated Balance Sheets

Consolidated Statements of Cash Flows

Consolidated Statements of Capitalization

Notes to Consolidated Financial Statements

Report of Management

Report of Registered Independent Public Accounting Firm

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INDEX OF ABBREVIATIONS

AFUDC	Allowance for Funds Used During Construction
ARO	Asset Retirement Obligation
Capital Corp.	LG&E Capital Corp.
Clean Air Act	The Clean Air Act, as amended in 1990
CCN	Certificate of Public Convenience and Necessity
CO2	Carbon Dioxide
CT	Combustion Turbines
CWIP	Construction Work in Progress
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
EPA	U.S. Environmental Protection Agency
ESM	Earnings Sharing Mechanism
F	Fahrenheit
FAC	Fuel Adjustment Clause
FERC	Federal Energy Regulatory Commission
FGD	Flue Gas Desulfurization
FPA	Federal Power Act
FT and FT-A	Firm Transportation
GSC	Gas Supply Clause
IBEW	International Brotherhood of Electrical Workers
IMEA	Illinois Municipal Electric Agency
IMPA	Indiana Municipal Power Agency
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
Kva	Kilovolt-ampere
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 (as successor to LG&E Energy Corp.)
LG&E R	LG&E Receivables LLC
LG&E Services	LG&E Energy Services Inc.
LNG	Liquefied Natural Gas
Mcf	Thousand Cubic Feet
MGP	Manufactured Gas Plant
MISO	Midwest Independent Transmission System Operator
MMBtu	Million British thermal units
Moody’s	Moody’s Investor Services, Inc.
Mw	Megawatts
Mwh	Megawatt hours
NNS	No-Notice Service
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	Public Utility Holding Company Act of 1935
ROE	Return on Equity
RTO	Regional Transmission Organization

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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
Tennessee Gas	Tennessee Gas Pipeline Company
Texas Gas	Texas Gas Transmission LLC
Trimble County	LG&E’s Trimble County Unit 1
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

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Louisville Gas and Electric Company and Subsidiary

Selected Financial Data

The 2000 consolidated financial data were derived from financial statements audited by Arthur Andersen LLP, independent accountants, who expressed an unqualified opinion on those financial statements in their report dated January 26, 2001, before the revisions required by EITF 02-03 and the reclassification of income taxes.  Arthur Andersen LLP has ceased operations.  The amounts shown below for such period, reclassified pursuant to the adoption of EITF 02-03 and reclassified due to the change in presentation of income taxes, are unaudited.

	Years Ended December 31
(in thousands)	2004		2003		2002		2001		2000
LG&E:
Operating revenues	$	1,172,768	$	1,093,521	$	1,003,735	$	964,547	$	931,704
Net operating income	$	185,031	$	178,752	$	172,949	$	205,225	$	213,295
Net income	$	95,618	$	90,839	$	88,929	$	106,781	$	110,573
Total assets	$	2,966,552	$	2,882,082	$	2,768,930	$	2,448,354	$	2,226,084
Long-term obligations (including amounts due within one year)	$	871,804	$	798,054	$	616,904	$	616,904	$	606,800
Dividends declared per common share	$	2.68	$	—	$	3.24	$	1.08	$	2.35

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.

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Louisville Gas and Electric Company and Subsidiary

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 2004, 2003, and 2002 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 certain 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 Exhibit No. 99.01 to its report on Form 10-K.

EXECUTIVE SUMMARY

Our Business

LG&E and KU are each subsidiaries of LG&E Energy LLC, 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 318,000 customers and electricity to approximately 390,000 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 gas service in limited additional areas.  LG&E’s coal-fired electric generating plants, all equipped with systems to reduce sulfur dioxide 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 gas service to customers. 

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Our Customers

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

	LG&E				2004 % Retail Revenues
Customers (000s)	Electric		Gas		LG&E
Retail Customer Data	2004	2003	2004	2003	Electric		Gas
Residential	343	337	293	287	39	%	65	%
Industrial & Commercial	41	41	24	24	51	%	30	%
Other	6	6	1	1	10	%	5	%
Total Retail	390	384	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:

•Execute all our business processes to secure a world-class competitive advantage

•Develop and transfer best practices in generation, customer service, distribution and supply

•Operate our commercial hub to enhance margins and manage risks across the company

•Pursue flexible asset portfolio management

•Attract, retain and develop the best people

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 top amongst large electric utilities in the Midwest for the 5^th time in six years in the J.D. Power and Associates 2004 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, 2004:

Source: Edison Electric Institute, Summer 2004 Typical Bills and Average Rates Report; Residential rates in effect July 1, 2004, based on 1,000 Kwh monthly usage.

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The company 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, produce $55.3 million of revenue for LG&E for a full year.  Under the ruling, the LG&E utility base electric rates have increased $43.4 million (7.7%) and base gas rates have increased $11.9 million (3.4%), on an annual basis.  The 2004 increases were the first increases in electric base rates for LG&E in 13 years; the last gas rate increase for the LG&E 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

Wholesale natural gas prices stayed around the $6/MMBtu level during summer 2004.  The U.S. supply-demand imbalance problem has continued, with U.S. reserves in decline and gas demand for electric generation continuing to increase.

Coal prices, which moderated after increases in 2001-2002, rose in late 2003 and maintained strength during 2004.  Coal production in the U.S. has not kept pace with demand, and mining companies are exercising market discipline in their production decisions.  Lower sulfur Central Appalachian coal led the price increases.  Prices for Powder River Basin (“PRB”) low sulfur coal from the western U.S. have risen much less than eastern coals, largely due to transportation constraints between the mines and eastern markets.  However, LG&E generation plants are limited in the amount of PRB coal that can be burned.

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

Actual 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. 

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With respect to wholesale electricity prices, generation overcapacity in the Midwest is forecasted to persist, with reserve margins still topping 25% for ECAR in 2005. However, the overcapacity resulted largely from the construction of high-cost simple cycle gas-fired units.  Therefore, high gas prices have supported higher wholesale electricity prices, advantaging coal-fired generation.  While the regional reserve margin is expected to decline over time as new capacity construction slows and demand grows, gas-fired generation is expected to set prices, particularly during times of higher loads. This expectation, combined with the expectation that gas prices will remain high, indicates that on-peak electricity prices are expected to remain high.

Generation Reliability

Generation reliability also remains a key aspect to meeting our strategy. LG&E believes 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

With the recent installation of four combustion turbines at Trimble County, near-term regulated load growth in Kentucky is expected to be satisfied. The installation of Trimble County Units 7-10 increased total system capability by 9%. However, the IRP submitted by LG&E and KU to the Kentucky Commission in 2002, outlining the least cost alternative to meet Kentucky’s needs, indicated the requirement for additional base-load capacity in the longer-term.  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 customers.  Trimble County Unit 2, with a 732 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).  An application for a construction CCN was filed with the Kentucky Commission in December 2004, and the proposed air permit was filed with the Kentucky Department of Air Quality in December 2004.  LG&E’s and KU’s share of the total capital cost of $885 million for Trimble County Unit 2 is estimated to be $168 million and $717 million, respectively, through 2010.

Environmental Pressures

In addition to the Trimble County Unit 2 project, the second major utility investment area is environmental expenditures.  The need for additional FGD units is continuously assessed based on the expected changes in SO₂ allowance prices, coal cost, and environmental legislation.  The analysis supports building additional FGD units to mitigate the declining SO₂ allowance bank at KU over the next several years.  The LG&E utility fleet is fully scrubbed.  SO₂ allowance prices have risen significantly and, coupled with the high price of low sulfur coal, indicate the need for FGDs on three of KU’s Ghent units and at E.W. Brown.  In December 2004, KU filed with the Kentucky Commission an application for a CCN to construct four FGDs; a decision is expected by late June 2005.

LG&E and KU completed the NOx SCR projects before the May 2004 deadline.  Expenditures on NOx investments, totaling approximately $186 million at LG&E and $219 million at KU, are being recovered currently through the companies’ ECR mechanism (see “Rates and Regulation”).

Additional environmental regulations are probable in the areas of New Source Review (a preconstruction permitting program established as part of the Clean Air Act), mercury and CO₂. The mercury standard will most likely be achieved through the operation of conventional air pollution control equipment (FGDs). The

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Companies believe that CO₂ regulation is a longer-term issue as there is no current nationwide consensus to adopt Kyoto-like restrictions. 

Kentucky law permits LG&E 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. The mechanism permits LG&E to earn a reasonable return on these capital investments outside of base rates.  Related operation and maintenance expenses are also recoverable.  Approximately 80% of the applicable environmental costs, including investment and operating costs, are recoverable through ECR. The remaining 20%, attributable to off-system and FERC-jurisdictional sales, are not recoverable through the ECR, but can be included in the determination of base rate cases.

Weather

The utility business is affected by various weather patterns.  Seasonal weather patterns can cause extreme variability in load due to higher or lower temperatures than normal.  The Companies maintain generation reserve margins and natural gas storage fields to accommodate higher than normal loads.  Lower than normal loads can impact the profitability of the Companies due to lower revenues.  A WNA mechanism, effective November through April, adjusts for the over- and under-recovery of costs associated with natural gas in periods of abnormal winter usage.

Severe snow and ice storms, thunderstorms, tornadoes and flooding can result in extensive damage to the infrastructure of the Companies’ transmission and distribution systems.  The Companies maintain a comprehensive storm management plan for efficient and timely restoration of service to customers after major storm events.

Business Disruption Risks

LG&E faces certain operational risks common to the electric and gas utility industries, as applicable.  These include, without limitation, the risk of disruptions or outages relating to major operating or delivery facilities, such as generating units, transmission or distribution assets and information technology or data processing components, whether due to terrorist or other attack, civil unrest or labor action, break-down or mechanical failure, severe weather or other acts of God.

While LG&E believes it has appropriate prevention or mitigation measures in place, where possible, with respect to these potential business disruptions, no assurances can be given that such events will not occur in the future or will not negatively affect its financial condition or results of operations.

MERGERS AND ACQUISITIONS

LG&E is a subsidiary of LG&E Energy.  On December 11, 2000, LG&E Energy Corp., now LG&E Energy LLC, was acquired by Powergen plc, now known as Powergen Limited, for cash of approximately $3.2 billion and the assumption of all of LG&E Energy’s debt.  As a result of the acquisition, LG&E Energy became a wholly owned subsidiary of Powergen and, as a result, LG&E became an indirect subsidiary of Powergen. 

On July 1, 2002, E.ON, a German company, completed its acquisition of Powergen plc (now Powergen Limited).  As a result, LG&E and KU became indirect subsidiaries of E.ON.  E.ON had announced its pre-conditional cash offer of £5.1 billion ($7.3 billion) for Powergen on April 9, 2001. 

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

The utility operations of LG&E Energy 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.

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.

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RESULTS OF OPERATIONS

LG&E

Net Income

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 $22.6 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 (6.3%).

LG&E’s net income in 2004 related to the gas business decreased $1.9 million (18.2%) compared to 2003.  Gas operating revenues increased $31.7 million (9.8%) offset by higher gas supply expenses of $32.4 million (13.9%).  Other gas operations and maintenance expenses increased $2.0 million (4.2%).

LG&E’s net income in 2003 increased $1.9 million (2.1%) as compared to 2002.  The increase resulted primarily from increased electric sales.

LG&E’s net income in 2003 related to the electric business increased $1.4 million (1.8%) compared to 2002.  Electric operating revenues increased $32.1 million (4.4%), offset by higher fuel for electric generation and power purchased of $19.8 million (7.8%).  Other electric operations expense increased $2.2 million (1.3%).  Electric depreciation expense increased $6.2 million (7.0%).  Other income decreased $1.6 million (126.6%) and interest expense increased $0.9 million (3.5%).

LG&E’s net income in 2003 related to the gas business increased $0.5 million (5.7%) compared to 2002.  Gas operating revenues increased $57.6 million (21.6%) offset by higher gas supply expenses of $51.5 million (28.3%).  Other gas operations expense increased $3.1 million (8.4%) and maintenance expense increased $0.3 million (4.4%).  Gas depreciation increased $1.1 million (7.3%).  Other income decreased $0.5 million (112.4%).

Revenues

The following table presents a comparison of operating revenues for the years 2004 and 2003 with the immediately preceding year.

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	Increase (Decrease) From Prior Period
(in thousands)	Electric Revenues						Gas Revenues
Cause	2004			2003			2004			2003
Retail sales:
Fuel and gas supply adjustments	$	1,093		$	6,620		$	33,546		$	50,972
LG&E/KU Merger surcredit	(2,329		)	(2,288		)	—			—
Environmental cost recovery surcharge	12,747			(269		)	—			—
Earnings sharing mechanism	4,489			9,768			—			—
Demand side management	403			1,362			(555		)	267
VDT surcredit	(1,140		)	(3,394		)	87			(1,283		)
Weather normalization	—			—			3,188			(506		)
Rate changes	16,824			—			6,947			—
Variation in sales volumes and other	11,809			(18,451		)	(5,773		)	12,070
Provision for Rate Collections (Refunds)	(11,006		)	(12,067		)	—			—
Total retail sales	32,890			(18,719		)	37,440			61,520
Wholesale	15,781			49,230			(5,083		)	(4,106		)
Gas transportation-net	—			—			95			(186		)
Other	(1,162		)	1,635			(714		)	412
Total	$	47,509		$	32,146		$	31,738		$	57,640

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.  Electric revenues increased in 2003 primarily due to an increase in wholesale sales due to both higher market prices and higher sales volume as compared to 2002.  Retail revenues decreased due to 2.6% lower sales volume, primarily in the residential sector due to milder summer weather than 2002.  Cooling degree days decreased 33% compared to 2002 and were 14% below the 20-year average. 

Gas revenues in 2004 increased due to higher gas supply cost billed to customers through the gas supply clause and increased gas rates. New 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. Gas revenues in 2003 increased compared to 2002, due to higher gas supply cost billed to customers through the gas supply clause and increased gas retail sales due to cooler winter weather, offset by lower off-system gas sales.  Heating degree days increased 5% as compared to 2002 and were the same as the 20-year average. 

The decrease in the provision for rate collections (refunds) in 2004 from 2003 ($11.0 million) results primarily from a decrease in the ESM accrual ($12.7 million) and a decrease in 2004 ECR accruals ($5.4 million), partially offset by an increase in fuel accruals ($7.1 million). The decrease in the provision for rate collections (refunds) in 2003 from 2002 ($12.1 million) results primarily from ESM revenues billed to customers during 2003 ($10.0 million), a decrease in the ESM accrual ($2.4 million) and a decrease in fuel accruals ($2.6 million), partially offset by an increase in ECR accruals ($2.9 million).

Expenses

Fuel for electric generation and gas supply expenses comprise a large component of LG&E’s total operating costs. The retail electric rates contain a FAC and gas rates contain a GSC, whereby increases or decreases in the cost of fuel and 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 $10.1 million (5.1%) in 2004 due to increased generation ($3.7 million) and higher cost of fuel burned ($6.4 million).  Fuel for electric generation increased $2.1 million (1.1%) in

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2003 due to increased generation ($5.8 million) offset by lower cost of fuel burned ($3.7 million), primarily due to greater percentage of steam generation vs. combustion turbine generation in 2003.  The average delivered cost per MMBtu of coal purchased was $1.15 in 2004, $1.12 in 2003 and $1.11 in 2002.

Power purchased increased $12.4 million (15.6%) in 2004 due to a 4% increase in purchases to meet off-system sales requirements ($3.4 million), and an 11% higher unit cost of purchases ($9.0 million).  Power purchased expenses increased $17.7 million (28.7%) in 2003 due to an increase in purchases to meet off-system sales requirements ($9.0 million), and a 12% higher unit cost of purchases ($8.7 million).

Gas supply expenses increased $32.4 million (13.9%) in 2004 due to an increase in cost of net gas supply ($52.2 million) offset by a decrease in the volume of gas delivered to the distribution system ($19.8 million). Gas supply expenses increased $51.5 million (28.3%) in 2003 due to an increase in cost of net gas supply ($50.2 million) and an increase in the volume of gas delivered to the distribution system ($4.1 million), partially offset by lower cost of purchases for wholesale sales ($2.8 million).

Other operations and maintenance expenses increased $14.7 million (5.1%) in 2004.

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 steam generation expense ($1.2 million).

•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.

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

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

•Increased maintenance expense due to storm restoration costs related to severe May and July storms ($9.3 million).

•Increased distribution maintenance, excluding the storm restoration costs ($0.7 million).

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

•Increased combustion turbine maintenance ($1.1 million).

•Increased hydro generation maintenance, primarily due to Ohio Falls rehabilitation ($0.5 million).

Property and other taxes increased $1.6 million (10.2%) in 2004 primarily due to:

•Increased property taxes ($1.2 million).

•Increased payroll taxes ($0.4 million).

Other operations and maintenance increased $5.3 million (1.9%) in 2003.

Other operation expenses increased $8.7 million (4.2%) in 2003 primarily due to:

•Increased electric transmission and distribution expense ($5.4 million).

•Increased employee benefits costs ($4.0 million).

•Increased demand side management program expenses ($2.5 million).

•Increased uncollectible customer accounts ($1.6 million).

•Decreased amortization of regulatory assets ($3.5 million).

•Decreased injury and damage liabilities ($2.1 million).

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Maintenance expenses for 2003 decreased $3.0 million (5.0%) primarily due to:

•Decreased maintenance of electric distribution ($1.1 million) and gas distribution ($0.8 million).

•Decreased communications maintenance expenses ($0.9 million).

Property and other taxes decreased $0.4 million (2.3%) in 2003 primarily due to: 

•Reduced property taxes due to a $1.2 million coal credit ($1.1 million).

•Increased payroll taxes ($0.7 million).

Depreciation and amortization increased $3.3 million (2.9%) in 2004 and $7.4 million (7.0%) in 2003 due to additional utility plant in service.

Other income (expense) - net increased $3.9 million (53.7%) in 2004.  In 2003, write-offs of $3.0 million decreased other income (see below).  Other income (expense) - net decreased $5.7 million (367.2%) in 2003 due primarily to the write-off of amounts from CWIP for a terminated plant project ($2.4 million) and a terminated software project ($0.6 million) partially offset by a decrease in benefit costs ($1.7 million). 

Total interest expense for 2004 increased $2.1 million (7.0%) due to increased borrowing from Fidelia ($6.9 million), higher cost of the interest rate swaps ($3.0 million) resulting from the first full year of an additional $128 million of swaps and higher interest rates on variable-rate debt ($0.8 million), partially offset by savings from retired first mortgage debt ($7.2 million) and reduced borrowing from the money pool ($1.4 million).

Interest charges for 2003 increased $0.8 million (2.8%) due to new fixed-rate debt with Fidelia ($5.0 million) offset by a decrease in average outstanding balances borrowed from the money pool ($0.4 million) and savings from lower average interest rates on variable-rate long-term bonds ($3.7 million). 

The weighted average interest rate on variable-rate long-term bonds for 2004, 2003 and 2002 was 1.28%, 1.10% and 1.54%, respectively.  At December 31, 2004, 2003 and 2002, LG&E’s percentage of long-term bonds having a variable-rate, including the impact of interest rate swaps, was 35.1% at $306.0 million, 38.3% at $306.0 million and 46.8% at $289.0 million, respectively.  LG&E’s weighted average cost of long-term debt, including amortization of debt expense and interest rate swaps, was 3.92%, 3.58%, and 3.87% at December 31, 2004, 2003 and 2002, respectively.  See Note 9 of LG&E’s Notes to Financial Statements under Item 8.

Variations in income tax expenses are largely attributable to changes in pre-tax income. LG&E’s 2004 effective income tax rate increased to 35.8% from the 35.5% rate in 2003.  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

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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 forecast and the best estimates routinely require adjustment.  See also Note 1 of LG&E’s Notes to Financial Statements under Item 8.

Financial Instruments - LG&E uses over-the-counter interest-rate swap agreements to hedge its exposure to fluctuations in the interest rates it pays on variable-rate debt.  Gains and losses on interest-rate swaps used to hedge interest rate risk are reflected in other comprehensive income.  LG&E uses sales of market-traded electric forward contracts for periods less than one year to hedge the price volatility of its forecasted peak electric off-system sales.  Gains and losses resulting from ineffectiveness are shown in other income (expense) and to the extent that the hedging relationship has been effective, gains and losses are reflected in other comprehensive income.  Wholesale sales of excess asset capacity and wholesale purchases to be used to serve native load are treated as normal sales and purchases under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities and SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, and are not marked-to-market.  See Note 4 and Note 15 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 gas usage that has been used by customers, but not 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, 2004, a 10% change in these estimated quantities would cause revenue and accounts receivable to change by approximately $6.3 million, including $2.7 million for electric usage and $3.6 million for gas usage.  See also Note 1 of LG&E’s Notes to Financial Statements under Item 8.

Allowance for Doubtful Accounts – At December 31, 2004 and 2003, the LG&E allowance for doubtful accounts was $0.8 million and $3.5 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.

Benefit Plan Accounting – LG&E’s costs of providing defined-benefit pension retirement plans is dependent upon a number of factors, such as the rates of return on plan assets, healthcare cost trend rates, discount rate, contributions made to the plan, and other actuarial assumptions used to value benefit obligations.  In 2002, LG&E was required to recognize an additional minimum liability of $26.0 million as prescribed by SFAS No. 87 Employers’ Accounting for Pensions since the fair value of the plan assets was less than the accumulated benefit obligation at that time.  During 2002, the combination of poor market performance and historically low corporate bond rates created a divergence in the potential value of the pension liabilities and the actual value of the pension assets.  The liability was recorded as a reduction to other comprehensive income, and did not affect net income.  In 2003, LG&E recognized a reduction of the minimum pension liability of $3.1 million.  During 2004 LG&E recognized an additional minimum pension liability of $10.2 million.  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 consolidated balance sheet.

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Should poor market conditions return, these conditions could result in an increase in LG&E’s unfunded accumulated benefit obligations and future pension expense.  The primary assumptions that drive the value of the unfunded accumulated benefit obligations are the discount rate and expected return on plan assets. 

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

	2004		2003		2002
Discount rate	6.25	%	6.75	%	7.25	%
Expected long-term return on plan assets	8.50	%	9.00	%	9.50	%
Rate of compensation increase	3.50	%	3.75	%	4.25	%

LG&E made contributions to the pension plan of $34.5 million in January 2004 and $89.1 million during 2003.

A 1% increase or decrease in the assumed discount rate could have an approximate $39.9 million positive or negative impact to the accumulated benefit obligation of LG&E. 

See also Note 6 and Note 15 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 regulator 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 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 - Income taxes 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 many transactions for which the ultimate tax outcome is uncertain. 

To provide for these uncertainties or exposures, an allowance is maintained for tax contingencies, the balance of which management believes is adequate.  Tax contingencies are analyzed periodically and adjustments are made when events occur to warrant a change. The company is currently in the examination phase of IRS audits for the years 1999 to 2003 and expects some or all of these audits to be completed within the next 12 months.  The results of audit assessments by taxing authorities are not anticipated to have a material adverse effect on cash flows or results of operations.

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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 generation taxable income in 2005. On a stand-alone basis, LG&E expects to generate a deduction in 2005 which will reduce LG&E’s effective tax rate by less than 1%.

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.  The impact of these reduced rates is expected to decrease LG&E’s income tax expense in future periods.  Furthermore, these reduced rates will result in the reversal of accumulated temporary differences at lower rates than originally provided.  LG&E is presently evaluating the impact of this and other changes to the Kentucky tax system, however, no material adverse impacts on cash flows or results of operations are expected.

LG&E is subject to periodic changes in state tax law, regulation or interpretation, as well as enforcement proceedings.  LG&E is currently undergoing a routine Kentucky sales tax audit for the period October 1997 through 2001.  The possible assessment or amount at issue is not known at this time, but is not expected to have a material adverse effect on cashflows or results of operations. 

See Note 1 and Note 7 of LG&E’s Notes to Financial Statements under Item 8.

Deferred Income Taxes - LG&E expects to have adequate levels of taxable income to realize its recorded deferred tax assets.  See Note 7 of LG&E’s Notes to Financial Statements under Item 8 for a breakdown of deferred tax assets.

NEW ACCOUNTING PRONOUNCEMENTS

The following recent accounting pronouncements affected LG&E in 2004 and 2003:

SFAS No. 143

SFAS No. 143, Accounting for Asset Retirement Obligations was issued in 2001.  SFAS No. 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. 

The effective implementation date for SFAS No. 143 was January 1, 2003.  Management has calculated the impact of SFAS No. 143 and FERC Final Order No. 631 issued in Docket No. RM02-7, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations.  As of January 1, 2003, LG&E recorded ARO assets in the amount of $4.6 million and liabilities in the amount of $9.3 million.  LG&E also recorded a cumulative effect adjustment in the amount of $5.3 million to reflect the accumulated depreciation and accretion of ARO assets at the transition date less amounts previously accrued under regulatory depreciation.  LG&E recorded offsetting regulatory assets of $5.3 million, pursuant to regulatory treatment prescribed under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation.  Also pursuant to SFAS No. 71, LG&E recorded regulatory liabilities in the amount of $0.1 million offsetting removal costs previously accrued under regulatory accounting in excess of amounts allowed under SFAS No. 143. 

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Had SFAS No. 143 been in effect for the 2002 reporting period, LG&E would have established asset retirement obligations as described in the following table:

(in thousands)
Provision at January 1, 2002	$	8,752
Accretion expense	578
Provision at December 31, 2002	$	9,330

As of December 31, 2004, LG&E had ARO assets, net of accumulated depreciation, of $3.3 million and liabilities of $10.3 million.  As of December 31, 2003, LG&E had ARO assets, net of accumulated depreciation, of $3.5 million and liabilities of $9.7 million.  LG&E recorded offsetting regulatory assets of $6.9 million and $6.0 million and regulatory liabilities of $0.1 million as of both December 31, 2004 and 2003, respectively.

For the year ended December 31, 2004, LG&E recorded ARO accretion expense of approximately $0.7 million, ARO depreciation expense of $0.2 million and an offsetting regulatory credit in the income statement of $0.9 million, pursuant to regulatory treatment prescribed under SFAS No. 71.  For the year ended December 31, 2003, LG&E recorded ARO accretion expense of approximately $0.6 million, ARO depreciation expense of $0.1 million and an offsetting regulatory credit in the income statement of $0.7 million.  Removal costs incurred and charged against the ARO liability during 2004 and 2003 were $0.1 million and $0.2 million, respectively.  SFAS No. 143 has no impact on the results of operations of LG&E.

LG&E AROs are primarily related to final retirement of assets associated with generating units.  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, 2004 and 2003, LG&E recorded immaterial amounts (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 also continues to include a cost of removal component in depreciation for assets that do not have a legal ARO.  As of December 31, 2004 and 2003, LG&E has segregated this cost of removal, embedded in accumulated depreciation, of $220.2 million and $216.5 million, respectively, in accordance with FERC Order No. 631. For reporting purposes in its Consolidated Balance Sheets included in Item 8, LG&E has presented this cost of removal as a regulatory liability pursuant to 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.

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EITF No. 02-03

LG&E adopted EITF No. 98-10, Accounting for Energy Trading and Risk Management Activities, effective January 1, 1999.  This pronouncement required that energy trading contracts be marked to market on the balance sheet, with the gains and losses shown net in the income statement.  Effective January 1, 2003, LG&E adopted EITF No. 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.  EITF No. 02-03 established the following:

•     Rescinded EITF No. 98-10,

•     Contracts that do not meet the definition of a derivative under SFAS No. 133 should not be marked to fair market value, and

•     Revenues should be shown in the income statement net of costs associated with trading activities, whether or not the trades are physically settled.

With the rescission of EITF No. 98-10, energy trading contracts that do not also meet the definition of a derivative under SFAS No. 133 must be accounted for as executory contracts.  Contracts previously recorded at fair value under EITF No. 98-10 that are not also derivatives under SFAS No. 133 must be restated to historical cost through a cumulative effect adjustment.  The rescission of this standard had no impact on financial position or results of operations of LG&E since all forward and option contracts marked to market under EITF No. 98-10 were also within the scope of SFAS No. 133.

As a result of EITF No. 02-03, LG&E has netted the power purchased expense for trading activities against electric operating revenue to reflect this accounting change.  LG&E applied this guidance to previously reported 2002 balances as shown below. The reclassifications had no impact on previously reported net income or common equity.

(in thousands)
Gross electric operating revenues as previously reported	$	1,026,184
Less costs reclassified from power purchased	22,449
Net electric operating revenues	$	1,003,735
Gross power purchased as previously reported	$	84,330
Less costs reclassified to revenues	22,449
Net power purchased	$	61,881

SFAS No. 150

In May 2003, the Financial Accounting Standards Board issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.  SFAS No. 150 was effective immediately for financial instruments entered into or modified after May 31, 2003, and otherwise was effective for interim reporting periods beginning after June 15, 2003, except for certain instruments and certain entities which have been deferred by the FASB.  Such deferrals do not affect LG&E.

LG&E has $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, 2003 and 2004, leaving 225,000 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 portion of long-term debt.  Dividends accrued beginning July 1, 2003, are charged as interest expense.

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FIN 46

In January 2003, the Financial Accounting Standards Board issued Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 (“FIN 46”).  FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties.  FIN 46 was effective immediately for all new variable interest entities created or acquired after January 31, 2003.  For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must have been applied for the first interim or annual period beginning after June 15, 2003. 

In December 2003, FIN 46 was revised, delaying the effective dates for certain entities created before February 1, 2003, and making other amendments to clarify application of the guidance.  For potential variable interest entities other than special purpose entities, the revised FIN 46 (“FIN 46R”) was required to be applied no later than the end of the first fiscal year or interim reporting period ending after March 15, 2004.  The original guidance under FIN 46 was applicable, however, for all special purpose entities created prior to February 1, 2003, at the end of the first interim or annual reporting period ending after December 15, 2003.  FIN 46R may be applied prospectively with a cumulative-effect adjustment as of the date it is first applied, or by restating previously issued financial statements with a cumulative-effect adjustment as of the beginning of the first year restated.  FIN 46R also requires certain disclosures of an entity’s relationship with variable interest entities. The adoption of FIN 46 and FIN 46R had no impact on the financial position or results of operations for LG&E.

Although LG&E holds an investment interest in OVEC, it is not the primary beneficiary of OVEC and, therefore, OVEC is not consolidated into the financial statements of LG&E.  LG&E and 11 other electric utilities are participating owners of 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.  LG&E’s share is 7%, representing approximately 155 Mw of generation capacity.

LG&E’s original investment in OVEC was made in 1952. As of December 31, 2004, LG&E’s investment in OVEC totaled $0.5 million.  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 an increase in LG&E ownership in OVEC from 4.9% to 5.63%.  LG&E’s investment in OVEC 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 the investments.  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 11 of LG&E’s Notes to Financial Statements under Item 8 for further discussion of developments regarding LG&E’s ownership interest and power purchase rights.

FSP 106-2

In May 2004, the FASB finalized FSP 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“Medicare Act”) with guidance on accounting for subsidies provided under the Medicare Act which became law in December 2003.  FSP No. 106-2 is effective for the first interim or annual period beginning after June 15, 2004.  FSP 106-2 does not have a material impact on LG&E.

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FSP 109-1

In December 2004, the FASB finalized FSP 109-1, Accounting for Income Taxes, Application of FAS 109 to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004, whichrequires the tax deduction on qualified production activities to be treated as a special deduction in accordance with FAS 109.  FSP 109-1 became effective December 21, 2004, and does not have a material impact on LG&E.

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, 2004, LG&E is in a negative working capital position in part because of the classification of certain variable-rate pollution control bonds 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 had 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 $171.6 million, $163.3 million and $212.4 million in 2004, 2003, and 2002, respectively.  The 2004 increase of $8.3 million compared to 2003 resulted largely from the reduction in pension funding of $54.6 million, higher gas supply cost recovery of $15.0 million, higher earnings sharing mechanism of $10.1 million and receipt of a litigation settlement of $7.0 million. These increases were largely offset by a reduction in accounts receivable of $66.3 million, including the termination of the accounts receivable securitization program, and a reduction in accrued income taxes of $22.4 million. The 2003 decrease compared to 2002 of $49.1 million resulted primarily from pension funding in 2003 of $89.1 million and an increase in accounts receivable balances of $33.4 million, including the sale of accounts receivable through the accounts receivable securitization program, partially offset by an increase in accounts payable and accrued income taxes of $35.0 million and $36.0 million, respectively.  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 $148.3 million, $213.0 million and $220.4 million in 2004, 2003, and 2002, respectively.  LG&E expects its capital expenditures for 2005 and 2006 to total approximately $268 million, which consists primarily of construction estimates associated with the redevelopment of the Ohio Falls hydro facility, totaling $19.6 million, construction of Trimble County Unit 2, totaling $8.8 million, and on-going construction related to generation and distribution assets.

Net cash used for investing activities decreased $64.6 million in 2004 compared to 2003, primarily due to the level of construction expenditures.  NOx equipment expenditures were approximately $5.3 million in 2004 and $29.6 million in 2003, while CT expenditures were approximately $8.1 million in 2004 and $71.4 million in 2003.  Net cash used for investing activities decreased $7.2 million in 2003 compared to 2002 primarily due to the level of construction expenditures. 

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Financing Activities

Net cash inflows (outflows) for financing activities were $(18.3) million in 2004, $34.2 million in 2003 and $22.5 million in 2002. 

In January 2004, LG&E entered into two long-term loans from Fidelia, one totaling $25 million with an interest rate of 4.33% that matures in January 2012, and one totaling $100 million with an interest rate of 1.53% that matured in January 2005.  The loans are collateralized by a pledge of substantially all assets of LG&E that is subordinated to the first mortgage bond lien. The proceeds were used to fund a pension contribution and to repay other debt obligations.  In April 2004, LG&E prepaid $50 million of the $100 million 1.53% note payable to Fidelia.  The prepayment was paid out of cash balances.  The remaining $50 million under this note was paid at maturity in January 2005.

In November 2003, LG&E issued $128 million variable-rate pollution control bonds due October 1, 2033, and exercised its call option on the $102 million, 5.625% pollution control bonds due August 15, 2019 and on the $26 million, 5.45% pollution control bonds due October 15, 2020.

During 2003, LG&E entered into two long-term loans from Fidelia totaling $200 million.  $100 million of this total is unsecured and the remaining $100 million is collateralized by a pledge of substantially all assets of LG&E that is subordinated to the first mortgage bond lien.

LG&E first mortgage bond, 6% Series of $42.6 million matured in August 2003 and was retired.

In March 2002, LG&E refinanced its $22.5 million and $27.5 million unsecured pollution control bonds, both due September 1, 2026.  The replacement bonds, due September 1, 2026, are variable-rate bonds and are secured by first mortgage bonds. LG&E also refinanced its two $35 million unsecured pollution control bonds due November 1, 2027.  The replacement variable-rate bonds are secured by pollution control series bonds treated as first mortgage bonds and will mature November 1, 2027.

In October 2002, LG&E issued $41.7 million variable-rate pollution control bonds due October 1, 2032, and exercised its call option on $41.7 million, 6.55% pollution control bonds due November 1, 2020.

Under the provisions of certain variable-rate pollution control bonds totaling $246.2 million, the bonds are subject to tender for purchase by LG&E 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.  Backup credit facilities totaling $185 million are in place to fund such tenders if necessary.  LG&E has never had to access these facilities.

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.  The Company 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 LG&E Energy and KU make funds available to LG&E at market-based rates up to $400 million.  Fidelia also provides

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long-term intercompany funding to LG&E. 

Certain regulatory approvals are required for the Company to incur additional debt.  The SEC authorizes the issuance of short-term debt while the Kentucky Commission authorizes issuance of long-term debt.  As of December 31, 2004 the Company has received approvals from the SEC to borrow up to $400 million in short-term funds.

LG&E’s debt ratings as of December 31, 2004, were:

	Moody’s	S&P
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, 2004.  LG&E anticipates cash from operations and external financing will be sufficient to fund future obligations.

(in thousands)	Payments Due by Period
Contractual Cash Obligations	2005		2006		2007		2008		2009		Thereafter			Total
Short-term debt (a)	$	58,220	$	—	$	—	$	—	$	—	$	—		$	58,220
Long-term debt	297,450		1,250		1,250		18,750		—		553,104		(b)	871,804
Operating lease (c)	3,469		3,538		3,609		3,681		3,754		22,375			40,426
Unconditional power purchase obligations (d)	11,230		10,098		9,726		9,932		10,145		181,089			232,220
Coal and gas purchase obligations (e)	202,450		95,478		52,656		49,396		6,037		6,037			412,054
Retirement obligations (f)	9,250		10,106		13,305		10,992		15,839		—			59,492
Other long-term obligations (g)	14,767		—		—		—		—		—			14,767
Total contractual cash obligations	$	596,836	$	120,470	$	80,546	$	92,751	$	35,775	$	762,605		$	1,688,983

(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 2005.

(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.

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.

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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, 2004, the maximum aggregate amount of default fees or amounts, which decrease over the term of the lease, was $9.5 million, of which LG&E would be responsible for $3.6 million (38%).  LG&E has made arrangements with LG&E Energy, via guarantee and regulatory commitment, for LG&E Energy to pay its 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 Notes 1 and 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, 2004, the potential change in interest expense associated with a 1% change in base interest rates of LG&E’s unhedged debt is estimated at $3.6 million after the impact of interest rate swaps.

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, 2004, LG&E had swaps with a combined notional value of $228.3 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 $25.7 million as of December 31, 2004.  This estimate is derived from third-party valuations. Changes in the market value of these swaps if held to 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.

Commodity Price Sensitivity

LG&E has limited exposure to market price volatility in prices of fuel and electricity, since its retail tariffs include the FAC and GSC commodity price pass-through mechanisms.  LG&E is exposed to market price volatility of fuel and electricity in its wholesale activities.

Energy Trading & Risk Management Activities

LG&E conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns, in addition to the wholesale sale of excess asset capacity.  Certain energy trading activities are accounted for on a mark-to-market basis in accordance with SFAS No. 133, SFAS No. 138and SFAS No. 149.  Wholesale sales of excess asset capacity are treated as normal sales under these pronouncements and are not marked to market.  To be eligible for the normal sales exclusion under SFAS No. 133, sales are limited to the forecasted excess capacity of LG&E’s generation assets over what is needed to

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serve native load.  To be eligible for the normal purchases exclusion under SFAS No. 133 purchases must be used to serve LG&E’s native load.  Without the normal sales and purchases exclusion these transactions would be considered derivatives and marked to market under SFAS No. 133.

The rescission of EITF No. 98-10 for fiscal periods ending after December 15, 2002, had no impact on LG&E’s energy trading and risk management reporting as all forward and option contracts marked to market under EITF No. 98-10 are also within the scope of SFAS No. 133. 

The table below summarizes LG&E’s energy trading and risk management activities for 2004 and 2003:

(in thousands)	2004			2003
Fair value of contracts at beginning of period, net asset (liability)	$	572		$	(156	)
Fair value of contracts when entered into during the period	(75		)	2,654
Contracts realized or otherwise settled during the period	(858		)	(569		)
Changes in fair values due to changes in assumptions	164			(1,357		)
Fair value of contracts at end of period, net (liability) asset	$	(197	)	$	572

No changes to valuation techniques for energy trading and risk management activities occurred during 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 not result in a change of a material amount.  All contracts outstanding at December 31, 2004, 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, 2004, 100% of the trading and risk management commitments were with counterparties rated BBB-/Baa3 equivalent or better.

Accounts Receivable Securitization

On February 6, 2001, LG&E implemented an accounts receivable securitization program.  LG&E terminated the accounts receivable securitization program in January 2004, and in May 2004, dissolved its inactive accounts receivable securitization-related subsidiary, LG&E R. The purpose of this program was to enable LG&E to accelerate the receipt of cash from the collection of retail accounts receivable, thereby reducing dependence upon more costly sources of working capital.  The securitization program allowed for a percentage of eligible receivables to be sold.  Eligible receivables were generally all receivables associated with retail sales that had standard terms and were not past due.  LG&E was able to terminate the program at any time without penalty. 

As part of the program, LG&E sold retail accounts receivable to LG&E R.  Simultaneously, LG&E R entered into two separate three-year accounts receivable securitization facilities with two financial institutions and their affiliates whereby LG&E R could sell, on a revolving basis, an undivided interest in certain of its receivables and receive up to $75 million from unrelated third-party purchasers.  The effective cost of the receivables program was comparable to LG&E’s lowest cost source of capital, and was based on prime rated commercial paper.  LG&E retained servicing rights of the sold receivables through two separate servicing agreements with the third-party purchasers.  LG&E obtained an opinion from independent legal counsel indicating these transactions qualified as a true sale of receivables. 

To determine LG&E’s retained interest, the proceeds on the sale of receivables to the financial institutions was netted against the amount of eligible receivables sold by LG&E to LG&E R.  Interest expense, program fees, and facility fees paid to the financial institutions and an allowance for doubtful accounts were deducted to arrive

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at the future value of retained interest.  The future value was discounted using the prime rate plus 25 basis points, assuming a 45-day receivable life.  No material pre-tax gains or losses from the sale of the receivables occurred in 2004, 2003, and 2002.  LG&E’s net cash flows from LG&E R were $(58.1) million, $(6.2) million, and $20.2 million for 2004, 2003 and 2002, respectively.

The allowance for doubtful accounts associated with the eligible securitized receivables at December 31, 2003 and 2002 was $1.4 million and $1.9 million, respectively.  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 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 of LG&E’s Notes to Financial Statements under Item 8.

Electric and Gas Rate Cases.  In December 2003, LG&E filed applications with the Kentucky Commission requesting adjustments in LG&E’s electric and gas rates.  LG&E requested general adjustments in electric and gas rates based on the twelve month test year ended September 30, 2003.  The revenue increases requested were $63.8 million for electric and $19.1 million for gas. 

In June 2004, the Kentucky Commission issued an order approving increases in the base electric and gas rates of LG&E.  The Kentucky Commission’s order largely accepted proposed settlement agreements filed in May 2004 by LG&E and a majority of the parties to the rate case proceedings.  The rate increases took effect on July 1, 2004. 

In the Kentucky Commission’s order, LG&E was granted increases in annual base electric rates of approximately $43.4 million (7.7%) and in annual base gas rates of approximately $11.9 million (3.4%).  Other provisions of the order include decisions on certain depreciation, gas supply clause, ECR and VDT amounts or mechanisms and a termination of the ESM with respect to all periods after 2003.  The order also provided for a recovery before March 31, 2005, by LG&E of previously requested amounts relating to the ESM during 2003.

During July 2004, the AG served subpoenas on LG&E, as well as on 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. The Kentucky Commission has procedurally reopened the rate cases for the limited purpose of taking evidence, if any, as to the communication issues. Subsequently, the AG filed pleadings with the Kentucky Commission requesting rehearing of the rate cases on certain computational components of the increased rates, including income tax, 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, with the effect that the rate increase order is final as to these matters, subject to the parties’ rights to judicial appeals. The Kentucky Commission further agreed to hold in abeyance further proceedings in the rate cases, including the AG’s concerns about alleged improper communications, until the AG could file with the Kentucky Commission an investigative report regarding the latter issue. In addition, the Kentucky Commission granted a rehearing on the income tax component once the abeyance discussed above is lifted.

In September and October 2004, various proceedings were held in circuit courts in Franklin and Jefferson Counties, Kentucky regarding the scope and timing of document production or other information required or agreed to be produced under the AG’s subpoenas and matters were consolidated into the Franklin County court. In October 2004, the AG filed a motion with the Kentucky Commission requesting that the previously granted

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rate increases be set aside, that LG&E resubmit any applications for rate increases and that relevant Kentucky Commission personnel be recused from participation in rate case proceedings.  In November 2004, the Franklin County, Kentucky court denied an AG request for sanctions on LG&E relating to production matters and narrowed the AG’s permitted scope of discovery.  In January 2005, the AG conducted interviews of certain Company individuals.

In January 2005, the AG submitted its report to the Franklin County, Kentucky Circuit Court in confidence.  Concurrently the AG filed a motion summarizing the 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 requesting release of the report to such agencies.  During February 2005 the court ruled that the report be forwarded 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 cases, including ending the current abeyance.  To date, LG&E has neither seen nor requested copies of the report or its contents.

LG&E believes no improprieties have occurred in its communications with the Kentucky Commission and is cooperating 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 base rates.

VDT Costs - Kentucky Commission Settlement Order.  During the first quarter 2001, LG&E recorded a $144 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 June 2001, LG&E filed an application (“VDT case”) with the Kentucky Commission to create a regulatory asset relating to these first quarter 2001 charges.  The application requested permission to amortize these costs over a four-year period.  The Kentucky Commission also opened a case to review a new depreciation study and resulting depreciation rates implemented in 2001.

In December 2001, the Kentucky Commission approved a settlement in the VDT case as well as other cases involving the depreciation rates and ESM.  The order approving the settlement allowed LG&E to set up a regulatory asset of $141 million for the workforce reduction costs and begin amortizing these costs over a five year period starting in April 2001.  The first quarter 2001 charge of $144 million represented all employees who had accepted a voluntary enhanced severance program.  Some employees rescinded their participation in the voluntary enhanced severance program, thereby decreasing the original charge to the regulatory asset from $144 million to $141 million.  The settlement reduces revenues approximately $26 million through a surcredit on bills to ratepayers over the same five-year period.  The surcredit represents net savings stipulated by LG&E.

As mentioned, the current five-year VDT amortization period is scheduled to expire in March 2006.  As part of the settlement agreements in the electric and gas rate cases, LG&E shall file with the Kentucky Commission a plan for the future ratemaking treatment of the VDT surcredits and costs six months prior to the March 2006 expiration.  The surcredit shall remain in effect following the expiration of the fifth year until the Commission enters an order on the future disposition of VDT-related issues.

Merger Surcredit.  As part of the LG&E Energy merger with KU Energy in 1998, LG&E Energy estimated non-fuel savings over a ten-year period following the merger.  Costs to achieve these savings for LG&E of

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$50.2 million were recorded in the second quarter of 1998, $18.1 million of which was deferred and amortized over a five-year period pursuant to regulatory orders.  Primary components of the merger costs were separation benefits, relocation costs, and transaction fees, the majority of which were paid by December 31, 1998.  LG&E expensed the remaining costs associated with the merger ($32.1 million) in the second quarter of 1998.

In approving the merger, the Kentucky 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 Kentucky 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 and lower point for rate of return on equity, whereby if LG&E’s rate of return for the calendar year fell within the range of 10.5% to 12.5%, no action was necessary.  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 and interested parties had the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.

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.

On June 30, 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 will continue 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 relating to all periods after 2003.

As a result of the settlement, LG&E accrued an additional $4.1 million in June 2004, related to 2003 ESM revenue.

FAC.  LG&E’s retail electric rates contain a FAC, whereby increases or 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

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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 is due in May 2005.

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 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 is expected in April 2005.  LG&E is seeking to increase the fuel component of base rates.  LG&E does not anticipate any issues will arise during the regulatory proceeding.

DSM.  LG&E’s rates contain a DSM provision.  The provision includes a rate mechanism that provides concurrent recovery of DSM costs and provides an incentive for implementing DSM programs.  This provision allowed LG&E to recover revenues from lost sales associated with the DSM programs.  In May 2001, the Kentucky Commission approved LG&E’s plan to continue DSM programs.  This plan called for the expansion of the LG&E DSM programs into the service territory served by KU and proposed a mechanism to recover revenues from lost sales associated with DSM programs based on program plan engineering estimates and post-implementation evaluations.

Gas Supply Cost PBR Mechanism.  Since November 1, 1997, LG&E has operated under an experimental PBR mechanism related to its gas procurement activities.  LG&E’s rates are adjusted annually to recover its portion of the savings (or expenses) incurred during each PBR year (12 months ending October 31). Since its implementation on November 1, 1997, through October 31, 2004, LG&E has achieved $60.7 million in savings. Of that total savings amount, LG&E’s portion has been $22.7 million and the ratepayers’ portion has been $38.0 million.  Pursuant to the extension of LG&E’s gas supply cost PBR mechanism effective November 1, 2001, the sharing mechanism under PBR requires savings (and expenses) to be shared 25% with shareholders and 75% with ratepayers up to 4.5% of the benchmarked gas costs.  Savings (and expenses) in excess of 4.5% of the benchmarked 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.

ECR.  In May 2002, the Kentucky Commission initiated a periodic two-year review of LG&E’s environmental surcharge.  The review included the operation of the surcharge mechanism, determination of the appropriateness of costs included in the surcharge mechanism, recalculation of the cost of debt to reflect actual costs for the period under review, final determination of the amount of environmental revenues over-collected from customers, and a final determination of the amount of environmental costs and revenues to be “rolled-in” to base rates.  A final order was issued in October 2002, in which LG&E was ordered to refund $0.3 million to customers over the four month period beginning November 2002 and ending February 2003.  Additionally, LG&E was ordered to roll $4.1 million into base rates and make corresponding adjustments to the monthly environmental surcharge filings to reflect that portion of environmental rate base now included in base rates.

In August 2002, LG&E filed an application with the Kentucky Commission to amend its compliance plan to allow recovery of the cost of new and additional environmental compliance facilities.  The estimated capital cost of the additional facilities is $71.1 million. A final order was issued in February 2003, approving recovery of four new environmental compliance facilities totaling $43.1 million.  A fifth project, expansion of the landfill facility at the Mill Creek Station, was denied without prejudice with an invitation to reapply for recovery when

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required construction permits are approved.  Cost recovery through the environmental surcharge of the four approved projects began with bills rendered in April 2003.

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 of environmental rate base now included in base rates on a going-forward basis.  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 the cost of new and additional environmental compliance facilities, including the expansion of the Mill Creek landfill. The estimated capital cost of the additional facilities is $40.2 million.  LG&E requested an overall rate of return of 10.72%, including an 11% return on common equity.  A final order in the case is anticipated in June 2005.

MISO.  LG&E is a founding member of the MISO.  Membership was obtained in 1998 in response to and consistent with federal policy initiatives.  In February 2002, LG&E turned over operational control of its high voltage transmission facilities (100kV and above) to the MISO.  The MISO currently controls over 100,000 miles of transmission over 1.1 million square miles located in the northern Midwest between Manitoba, Canada and Kentucky.  In September 2002, FERC granted a 12.88% ROE on transmission facilities for LG&E and the rest of the MISO owners.  On February 18, 2005, the United States Court of Appeals for the District of Columbia Circuit ruled that FERC did not provide proper notice that it would consider an incentive adder of 50 basis points, but affirmed the September 2002 FERC order in all other respects.  Effective ROE, retroactive to February 1, 2002, is 12.38% for LG&E and the original MISO owners.

In October 2001, the FERC issued an order requiring that the bundled retail load and grandfathered wholesale load of each member transmission owner be included in the current calculation of the MISO’s “cost-adder,” the Schedule 10 charges designed to recover the MISO’s costs of operation, including start-up capital (debt) costs.  LG&E, along with several other transmission owners, opposed the FERC’s ruling on this matter. The opposition was rejected by the FERC in 2002.  Later that year, the MISO’s transmission owners, appealed the FERC’s decision to the United States Court of Appeals for the District of Columbia Circuit.  In response, in November 2002, the FERC requested that the Court issue a partial remand of its challenged orders to allow the FERC to revisit certain issues, and requested that the case be held in abeyance pending the agency’s resolution of such issues.  The Court granted the FERC’s petition in December 2002.  In February 2003, FERC issued an order reaffirming its position concerning the calculation of the Schedule 10 charges and in July 2003 denied a rehearing.  LG&E, along with several other transmission owners, again petitioned the District Court of Columbia Circuit for review. In July 2004 the court affirmed the FERC ruling.

In August 2004, the MISO filed its FERC-required proposed Transmission and Energy Markets Tariff (“TEMT”).  In September and October 2004, many MISO-related parties (including LG&E) filed proposals with the FERC regarding pending MISO-filed changes to transmission pricing principles, including the TEMT

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and elimination of Regional Through and Out Rates (“RTORs”). Additional filings of the companies before FERC in September 2004 sought to address issues relating to the treatment of certain “grandfathered” transmission agreements (“GFA’s”) should TEMT become effective. The utility proposals generally seek to appropriately delay the RTORs and TEMT effective dates based upon errors in administrative or procedural processes used by FERC or to appropriately limit potential reductions in transmission revenues received by the utilities should the RTORs, TEMT or GFA structures be implemented.  At present, existing FERC orders conditionally approve elimination of RTORs and implementation of general TEMT rates in the MISO by spring 2005.  At this time, LG&E cannot predict the outcome or effects of the various FERC proceedings described above, including whether such will have a material impact on the financial condition or results of operations of the companies. Financial consequences (changes in transmission revenues and costs) associated with the upcoming transmission market tariff changes are subject to varying assumptions and calculations and are therefore difficult to estimate. Changes in revenues and costs related to broader shifts in energy market practices and economics are not currently estimable.  Should LG&E be ordered to exit MISO, current MISO rules may also impose an exit fee.  LG&E is not able to predict the estimated outcome or economic impact of any of the MISO-related matters.  While LG&E believes legal and regulatory precedent should permit most or many of the MISO-related costs to be recovered in their rates charged to customers, they can give no assurance that state or federal regulators will ultimately agree with such position with respect to all costs, components or timing of recovery.

The MISO plans to implement a Day-ahead and Real-time market, including a congestion management system in April 2005. This system will be similar to the Locational Marginal Pricing (“LMP”) system currently used by the PJM RTO and contemplated in FERC’s SMD NOPR, currently being discussed.  The MISO filed with FERC a mechanism for recovery of costs for the congestion management system.  They proposed the addition of two new Schedules, 16 and 17.  Schedule 16 is the MISO’s cost recovery mechanism for the Financial Transmission Rights Administrative Service it will provide.  Schedule 17 is the MISO’s mechanism for recovering costs it will incur for providing Energy Marketing Support Administrative Service.  The MISO transmission owners, including LG&E, have objected to the allocation of costs among market participants and retail native load. FERC ruled in 2004 in favor of the MISO.

The Kentucky Commission opened an investigation into LG&E’s membership in the MISO in July 2003. The Kentucky Commission directed LG&E to file testimony addressing the costs and benefits of the MISO membership both currently and over the next five years and other legal issues surrounding continued membership.  LG&E engaged an independent third-party to conduct a cost benefit analysis on this issue.  The information was filed with the Kentucky Commission in September 2003.  The analysis and testimony supported the exit from the MISO, under certain conditions.  The MISO filed its own testimony and cost benefit analysis in December 2003.  A final Kentucky Commission order was expected in the second quarter of 2004; that ruling has since been delayed until summer 2005 due to the Kentucky Commission’s request for additional testimony on the MISO’s Market Tariff filing at FERC.

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 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

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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 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.

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 will be 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.  The Kentucky Commission must provide its Strategic Blueprint to the Governor in early August 2005.  LG&E must respond to the Kentucky Commission’s first set of data requests by the end of March 2005.

FERC SMD NOPR.  In July 2002, the FERC issued a NOPR in Docket No. RM01-12-000 which would substantially alter the regulations governing the nation’s wholesale electricity markets by establishing a common set of rules, defined as SMD. The SMD NOPR would require each public utility that owns, operates, or controls interstate transmission facilities to become an Independent Transmission Provider (“ITP”), belong to an RTO that is an ITP, or contract with an ITP for operation of its transmission assets. It would also establish a standardized congestion management system, real-time and day-ahead energy markets, and a single transmission service for network and point-to-point transmission customers. Review of the proposed rulemaking is underway and no time frame has been established by the FERC for adoption of a final rule.  While it is expected that the SMD final rule will affect LG&E’s revenues and expenses, the specific impact of the rulemaking is not known at this time.

Kentucky Commission Administrative Case for Affiliate Transactions.  In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates.  The Kentucky Commission intended to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility.  In early 2000, the Kentucky General Assembly enacted legislation, House Bill 897, which authorized the Kentucky Commission to require utilities that provide nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission.  In the same bill, the General Assembly set forth provisions to govern a utility’s activities related to the sharing of information, databases, and resources between its employees or an affiliate involved in the marketing or the provision of nonregulated activities and its employees or an affiliate involved in the provision of regulated services. The legislation became law in July 2000 and LG&E has been operating pursuant thereto since that time.  In February 2001, the Kentucky Commission published notice of their intent to promulgate new administrative regulations under the auspices of the new law.  This effort is still ongoing.

33

Wholesale Natural Gas Prices.  On September 12, 2000, the Kentucky Commission issued an order establishing Administrative Case No. 384 – “An Investigation of Increasing Wholesale Natural Gas Prices and the Impacts of such Increase on the Retail Customers Served by Kentucky’s Jurisdictional Natural Gas Distribution Companies”.

Subsequent to this investigation, the Kentucky Commission issued an order on July 17, 2001, encouraging the natural gas distribution companies in Kentucky to take various actions, among them to propose a natural gas hedge plan, consider performance-based ratemaking mechanisms, and to increase the use of storage.

In May 2004, in Case No. 2004-148, LG&E proposed a hedge plan for the 2004/2005 winter heating season relying upon LG&E’s storage to mitigate customer exposure to price volatility. In August 2004, the Kentucky Commission approved LG&E’s proposed hedge plan, validating the effectiveness of storage to mitigate potential volatility associated with high winter gas prices by approving this natural gas hedge plan.  The Kentucky Commission also ordered that LG&E need not file hedge plans in the future unless it intended to utilize financial hedging instruments.

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 NOx emission requirements of the 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 controls project commenced in late 2000 with the controls being placed into operation prior to the 2004 Summer Ozone Season. As of December 31, 2004, LG&E incurred total capital costs of approximately $186 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.

34

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, measures to implement EPA’s regional haze rule, and EPA’s Clean Air Mercury Rule which regulates mercury emissions from steam electric generating units and reductions in emissions of SO₂ and NOx required under the Clean Air Interstate Rule.  In addition, LG&E has worked with local regulatory authorities to review the effectiveness of remedial measures aimed at controlling particulate matter emissions from its Mill Creek Station.  LG&E previously settled a number of property damage claims from adjacent residents 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.

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 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, 2004 and 2003.

See Note 11 of LG&E’s Notes to Financial Statements under Item 8 for an additional discussion of environmental issues.

FUTURE OUTLOOK

Competition and Customer Choice

In the last several years, LG&E has taken many steps to keep its rates low while maintaining high levels of customer satisfaction, including a reduction in the number of employees; aggressive cost cutting; 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 will take additional steps to better position itself should retail competition come to Kentucky.

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 will be 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.  The Kentucky Commission must provide its Strategic Blueprint to the Governor in early August 2005.  LG&E must respond to the Kentucky Commission’s first set of data requests by the end of March 2005.

35

Louisville Gas and Electric Company and Subsidiary

Market for the Registrant’s Common Equity and Related Stockholder Matters.

All LG&E common stock, 21,294,223 shares, is held by LG&E Energy.  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 LG&E Energy during 2004.

(in thousands)
First quarter	$	—
Second quarter	21,000
Third quarter	21,000
Fourth quarter	15,000

LG&E had no cash distributions on common stock paid to LG&E Energy in 2003. In 2002, LG&E paid $69 million in cash distribution on common stock to LG&E Energy.

36

Louisville Gas and Electric Company and Subsidiary

Consolidated Statements of Income

(Thousands of $)

	Years Ended December 31
	2004			2003			2002
OPERATING REVENUES:
Electric (Note 14)	$	815,697		$	768,188		$	736,042
Gas	357,071			325,333			267,693
Total operating revenues (Note 1)	1,172,768			1,093,521			1,003,735
OPERATING EXPENSES:
Fuel for electric generation	207,092			196,965			194,900
Power purchased (Note 14)	92,047			79,621			61,881
Gas supply expenses	266,013			233,601			182,108
Other operation and maintenance expenses	306,008			291,295			285,991
Depreciation and amortization (Note 1)	116,577			113,287			105,906
Total operating expenses	987,737			914,769			830,786
Net operating income	185,031			178,752			172,949
Other income (expense) - net (Note 8 and Note 14)	(3,332		)	(7,193		)	(1,536		)
Interest expense (Notes 9 and 10)	20,545			23,863			27,630
Interest expense to affiliated companies (Note 14)	12,242			6,784			2,175
Income before income taxes	148,912			140,912			141,608
Federal and state income taxes (Note 7)	53,294			50,073			52,679
Net income	$	95,618		$	90,839		$	88,929

Consolidated Statements of Retained Earnings

(Thousands of $)

		Years Ended December 31
		2004		2003		2002
Balance January 1		$	497,441	$	409,319	$	393,636
Add net income		95,618		90,839		88,929
		593,059		500,158		482,565
Deduct:	Cash dividends declared on stock:
	5% cumulative preferred	1,075		1,075		1,075
	Auction rate cumulative preferred	962		908		1,702
	$5.875 cumulative preferred	—		734		1,469
	Common	57,000		—		69,000
		59,037		2,717		73,246
Balance December 31		$	534,022	$	497,441	$	409,319

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

37

Louisville Gas and Electric Company and Subsidiary

Consolidated Statements of Comprehensive Income

(Thousands of $)

	Years Ended December 31
	2004			2003		2002
Net income	$	95,618		$	90,839	$	88,929
Gain/(losses) on derivative instruments and hedging activities, net of tax benefit/(expense) of $947, $(368) and $3,457 for 2004, 2003 and 2002, respectively (Notes 1 and 4)	(1,399		)	544		(5,107		)
Additional minimum pension liability adjustment, net of tax benefit/(expense) of $4,128, $(1,257) and $10,493 for 2004, 2003 and 2002, respectively (Note 6)	(6,100		)	1,857		(15,505		)
Other comprehensive (loss) income, net of tax (Note 15)	(7,499		)	2,401		(20,612		)
Comprehensive income	$	88,119		$	93,240	$	68,317

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

38

Louisville Gas and Electric Company and Subsidiary

Consolidated Balance Sheets

(Thousands of $)

	December 31
	2004		2003
ASSETS:
Current assets:
Cash and cash equivalents (Note 1)	$	6,809	$	1,706
Accounts receivable - less reserve of $785 in 2004 and $3,515 in 2003 (Note 4)	166,990		84,585
Materials and supplies - at average cost:
Fuel (predominantly coal) (Note 1)	21,771		25,260
Gas stored underground (Note 1)	77,503		69,884
Other (Note 1)	26,159		24,971
Prepayments and other	3,921		5,281
	303,153		211,687
Other property and investments – less reserve of $63 in 2004 and 2003 (Note 1)	507		611
Utility plant, at original cost (Note 1):
Electric	3,113,653		2,809,957
Gas	487,771		468,504
Common	177,538		186,556
	3,778,962		3,465,017
Less:  reserve for depreciation	1,396,341		1,326,899
	2,382,621		2,138,118
Construction work in progress	136,842		339,166
	2,519,463		2,477,284
Deferred debits and other assets:
Restricted cash (Note 1)	10,943		—
Unamortized debt expense (Note 1)	8,453		8,753
Regulatory assets (Note 3)	91,866		143,626
Other	32,167		40,121
	143,429		192,500
	$	2,966,552	$	2,882,082

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

39

Louisville Gas and Electric Company and Subsidiary

Consolidated Balance Sheets (continued)

(Thousands of $)

	December 31
	2004		2003
CAPITAL AND LIABILITIES:
Current liabilities:
Current portion of long-term debt:
Long-term bonds (Note 9)	$	246,200	$	246,200
Long-term notes to affiliated company (Note 9)	50,000		—
Mandatorily redeemable preferred stock (Note 9)	1,250		1,250
	297,450		247,450
Notes payable to affiliated company (Notes 10 and 14)	58,220		80,332
Accounts payable	106,090		93,118
Accounts payable to affiliated companies (Note 14)	31,709		38,343
Accrued income taxes	6,208		11,472
Customer deposits	14,016		10,493
Other	18,624		16,533
	234,867		250,291
	532,317		497,741
Long-term debt (see statements of capitalization):
Long-term bonds (Note 9)	328,104		328,104
Long-term notes to affiliated company (Note 9)	225,000		200,000
Mandatorily redeemable preferred stock (Note 9)	21,250		22,500
	574,354		550,604
Deferred credits and other liabilities:
Accumulated deferred income taxes (Notes 1 and 7)	347,233		337,704
Investment tax credit, in process of amortization	46,176		50,329
Accumulated provision for pensions and related benefits (Note 6)	120,566		140,598
Asset retirement obligations	10,266		9,747
Regulatory liabilities (Note 3):
Accumulated cost of removal of utility plant	220,214		216,491
Other	52,150		51,822
Other	40,105		32,957
	836,710		839,648
Commitments and contingencies (Note 11)
Cumulative preferred stock (see statements of capitalization)	70,425		70,425
Common equity (see statements of capitalization)	952,746		923,664
	$	2,966,552	$	2,882,082

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

40

Louisville Gas and Electric Company and Subsidiary

Consolidated Statements of Cash Flows

(Thousands of $)

	Years Ended December 31
	2004			2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	95,618		$	90,839		$	88,929
Items not requiring cash currently:
Depreciation and amortization	116,577			113,287			105,906
Deferred income taxes - net	5,533			20,123			11,915
Investment tax credit - net	(4,153		)	(4,207		)	(4,153		)
VDT amortization	30,135			30,400			30,000
Mark-to-market financial instruments	2,576			(1,149		)	8,512
Other	(2,023		)	10,812			11,226
Change in certain net current assets:
Accounts receivable	(24,405		)	(10,945		)	(3,973		)
Materials and supplies	(5,318		)	(7,598		)	(15,048		)
Accounts payable	6,338			8,690			(26,299		)
Accrued income taxes	(5,264		)	17,165			(18,807		)
Prepayments and other	6,827			906			321
Sale of accounts receivable (Note 4)	(58,000		)	(5,200		)	21,200
Pension funding	(34,492		)	(89,125		)	336
Gas supply clause receivable, net	10,296			(4,712		)	3,873
Litigation settlement	6,972			—			—
Earnings sharing mechanism receivable	10,241			142			—
Other	14,178			(6,178		)	(1,557		)
Net cash provided by operating activities	171,636			163,250			212,381
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sales of securities	103			153			412
Construction expenditures	(148,306		)	(212,957		)	(220,416		)
Net cash used for investing activities	(148,203		)	(212,804		)	(220,004		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in restricted cash	(10,943		)	—			—
Long-term borrowings from affiliated company	125,000			200,000			—
Repayment of long-term borrowings from affiliated company	(50,000		)	—			—
Repayment of short-term borrowings	—			—			(29,944		)
Short-term borrowings from affiliated company	552,800			602,700			652,300
Repayment of short-term borrowings from affiliated company	(574,912		)	(715,421		)	(523,500		)
Retirement of first mortgage bonds	—			(42,600		)	—
Issuance of pollution control bonds	—			128,000			161,665
Issuance expense on pollution control bonds	(135		)	(5,843		)	(3,030		)
Retirement of pollution control bonds	—			(128,000		)	(161,665		)
Retirement of mandatorily redeemable preferred stock	(1,250		)	(1,250		)	—
Payment of dividends	(58,890		)	(3,341		)	(73,300		)
Net cash (used for) provided by financing activities	(18,330		)	34,245			22,526
Change in cash and cash equivalents	5,103			(15,309		)	14,903
Cash and cash equivalents at beginning of year	1,706			17,015			2,112
Cash and cash equivalents at end of year	$	6,809		$	1,706		$	17,015
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Income taxes	$	52,121		$	24,868		$	51,540
Interest on borrowed money	18,144			23,829			25,673
Interest to affiliated companies on borrowed money	11,323			4,162			1,850

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

41

Louisville Gas and Electric Company and Subsidiary

Consolidated Statements of Capitalization

(Thousands of $)

	December 31
	2004		2003
LONG-TERM DEBT (Note 9):
Pollution control series:
S due September 1, 2017, variable%	$	31,000	$	31,000
T due September 1, 2017, variable%	60,000		60,000
U due August 15, 2013, variable%	35,200		35,200
X due April 15, 2023, 5.90%	40,000		40,000
Y due May 1, 2027, variable%	25,000		25,000
Z due August 1, 2030, variable%	83,335		83,335
AA due September 1, 2027, variable%	10,104		10,104
BB due September 1, 2026, variable%	22,500		22,500
CC due September 1, 2026, variable%	27,500		27,500
DD due November 1, 2027, variable%	35,000		35,000
EE due November 1, 2027, variable%	35,000		35,000
FF due October 1, 2032, variable%	41,665		41,665
GG due October 1, 2033, variable%	128,000		128,000
Notes payable to Fidelia:
Due April 30, 2013, 4.55%, unsecured	100,000		100,000
Due August 15, 2013, 5.31%, secured	100,000		100,000
Due January 6, 2005, 1.53%, secured	50,000		—
Due January 16, 2012, 4.33%, secured	25,000		—
Mandatorily redeemable preferred stock:
$ 5.875 series, outstanding shares of 225,000 in 2004 and 237,500 in 2003	22,500		23,750
Total long-term debt outstanding	871,804		798,054
Less current portion of long-term debt	297,450		247,450
Long-term debt	574,354		550,604

CUMULATIVE PREFERRED STOCK:

	Shares Outstanding	Current Redemption Price
$ 25 par value, 1,720,000 shares authorized - 5% series	860,287	$	28.00	21,507			21,507
Without par value, 6,750,000 shares authorized - Auction rate	500,000	$	100.00	50,000			50,000
Preferred stock expense, net				(1,082		)	(1,082		)
				70,425			70,425
COMMON EQUITY:
Common stock, without par value -
Authorized 75,000,000 shares, outstanding 21,294,223 shares				425,170			425,170
Common stock expense				(836		)	(836		)
Additional paid-in capital				40,000			40,000
Accumulated other comprehensive income (Note 15)				(45,610		)	(38,111		)
Retained earnings				534,022			497,441
				952,746			923,664
Total capitalization				$	1,597,525		$	1,544,693

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

42

Louisville Gas and Electric Company and Subsidiary

Notes to Consolidated Financial Statements

Note 1 - Summary of Significant Accounting Policies

LG&E, a subsidiary of 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.  LG&E Energy is an exempt public utility holding company with wholly owned subsidiaries including LG&E, KU, Capital Corp., LEM, and LG&E Services.  All of LG&E’s common stock is held by LG&E Energy.  In May 2004, LG&E dissolved its accounts receivable securitization-related subsidiary, LG&E R.  Prior to May 2004, the consolidated financial statements include the accounts of LG&E and LG&E R with the elimination of intercompany accounts and transactions.

On December 11, 2000, LG&E Energy was acquired by Powergen.  On July 1, 2002, E.ON, a German company, completed its acquisition of Powergen plc (now Powergen Limited).  E.ON is a registered public utility holding company under PUHCA.

No costs associated with the E.ON purchase of Powergen or the Powergen purchase of LG&E Energy nor any effects of purchase accounting have been reflected in the financial statements of LG&E.

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.

Certain reclassification entries have been made to the previous years’ financial statements to conform to the 2004 presentation with no impact on the balance sheet net assets or previously reported income.  Effective December 31, 2004, operating and non-operating income taxes are presented as “Federal and State Income Taxes” on LG&E’s Consolidated Statements of Income.  Prior to December 31, 2004, the component of income taxes associated with operating income was included in net operating income and the component of income taxes associated with non-operating income taxes was included in other income (expense) – net.  LG&E has applied this change in presentation to all prior periods.

Regulatory Accounting.  Accounting for the regulated utility business conforms with generally accepted accounting principles as applied to regulated public utilities and as prescribed by FERC and the Kentucky Commission.  LG&E is subject to SFAS No. 71 under which certain costs that would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates.  Likewise, certain 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.  See Note 3 for additional detail regarding regulatory assets and liabilities.

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.

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.

43

Depreciation and Amortization.  Depreciation is provided on the straight-line method over the estimated service lives of depreciable plant.  The amounts provided were approximately 3.1% in 2004 (2.9% electric, 2.8% gas, and 7.6% common); 3.3% in 2003 (2.9% electric, 2.8% gas and 9.4% common); and 3.1% for 2002 (2.9% electric, 2.8% gas and 6.6% common), of average depreciable plant.  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.  Of the amount provided for depreciation, at December 31, 2003, approximately 0.4% electric, 0.8% gas and 0.1% common were related to the retirement, removal and disposal costs of long lived assets.

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

Restricted Cash.  A deposit in the amount of $10.9 million, used as collateral for a $83.3 million interest rate swap, is classified as restricted cash on LG&E’s balance sheet.

Fuel Inventory.  Fuel inventories of $21.8 million and $25.3 million at December 31, 2004, and 2003, respectively, are included in Fuel in the balance sheet.  The inventory is accounted for using the average-cost method.

Gas Stored Underground.  Gas inventories of $77.5 million and $69.9 million at December 31, 2004, and 2003, respectively, are included in gas stored underground in the balance sheet.  The inventory is accounted for using the average-cost method.

Other Materials and Supplies.  Non-fuel materials and supplies of $26.2 million and $25.0 million at December 31, 2004 and 2003, respectively, are accounted for using the average-cost method.

Financial Instruments.  LG&E uses over-the-counter interest-rate swap agreements to hedge its exposure to fluctuations in the interest rates it pays on variable-rate debt.  Gains and losses on interest-rate swaps used to hedge interest rate risk are reflected in other comprehensive income.  LG&E uses sales of market-traded electric forward contracts for periods less than one year to hedge the price volatility of its forecasted peak electric off-system sales.  Gains and losses resulting from ineffectiveness are shown in other income (expense) and to the extent that the hedging relationship has been effective, gains and losses are reflected in other comprehensive income.  Wholesale sales of excess asset capacity and wholesale purchases to be used to serve native load are treated as normal sales and purchases under SFAS No. 133, SFAS No. 138 and SFAS No. 149 and are not marked-to-market.  See Note 4, Financial Instruments and Note 15, Accumulated Other Comprehensive Income.

Unamortized Debt Expense.  Debt expense is capitalized in deferred debits and amortized over the lives of the related bond issues, consistent with regulatory practices.

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 basis 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 certain 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.

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,

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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 many transactions for which the ultimate tax outcome is uncertain.  To provide for these uncertainties or exposures, an allowance is maintained for tax contingencies, the balance of which management believes is adequate.  Tax contingencies are analyzed periodically and adjustments are made when events occur to warrant a change.  The company is currently in the examination phase of IRS audits for the years 1999 to 2003 and expects some or all of these audits to be completed within the next 12 months.  The results of audit assessments by taxing authorities are not anticipated to have a material adverse effect on cash flows or results of operations.

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 $63.0 million and $50.8 million at December 31, 2004 and 2003, respectively.

Allowance for Doubtful Accounts. At December 31, 2004 and 2003, the LG&E allowance for doubtful accounts was $0.8 million and $3.5 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.

Fuel and Gas Costs.  The cost of fuel for electric generation is charged to expense as used, and the cost of 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 gas procurement and off-system gas sales activity.  See Note 3, Rates and Regulatory Matters.

Other Property and Investments.  Other property and investments on the Balance Sheet consists of LG&E’s investment in OVEC and non-utility plant.  As of December 31, 2004 and 2003, LG&E’s investment in OVEC totaled $0.5 million.  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 an increase in LG&E ownership in OVEC from 4.9% to 5.63%.  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.

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. See Note 11, Commitments and Contingencies, for a further discussion.

New Accounting Pronouncements. The following accounting pronouncements were issued that affected LG&E in 2004 and 2003:

SFAS No. 143

SFAS No. 143 was issued in 2001.  SFAS No. 143 establishes accounting and reporting standards for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.

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The effective implementation date for SFAS No. 143 was January 1, 2003.  Management has calculated the impact of SFAS No. 143 and FERC Final Order No. 631 issued in Docket No. RM02-7.  As of January 1, 2003, LG&E recorded ARO assets in the amount of $4.6 million and liabilities in the amount of $9.3 million.  LG&E also recorded a cumulative effect adjustment in the amount of $5.3 million to reflect the accumulated depreciation and accretion of ARO assets at the transition date less amounts previously accrued under regulatory depreciation.  LG&E recorded offsetting regulatory assets of $5.3 million, pursuant to regulatory treatment prescribed under SFAS No. 71.  Also pursuant to SFAS No. 71, LG&E recorded regulatory liabilities in the amount of $0.1 million offsetting removal costs previously accrued under regulatory accounting in excess of amounts allowed under SFAS No. 143.

Had SFAS No. 143 been in effect for the 2002 reporting period, LG&E would have established asset retirement obligations as described in the following table:

(in thousands)
Provision at January 1, 2002	$	8,752
Accretion expense	578
Provision at December 31, 2002	$	9,330

As of December 31, 2004, LG&E had ARO assets, net of accumulated depreciation, of $3.3 million and liabilities of $10.3 million.  As of December 31, 2003, LG&E had ARO assets, net of accumulated depreciation, of $3.5 million and liabilities of $9.7 million.  LG&E recorded regulatory assets of $6.9 million and $6.0 million and regulatory liabilities of $0.1 million as of both December 31, 2004 and 2003, respectively.

For the year ended December 31, 2004, LG&E recorded ARO accretion expense of approximately $0.7 million, ARO depreciation expense of $0.2 million and an offsetting regulatory credit in the income statement of $0.9 million, pursuant to regulatory treatment prescribed under SFAS No. 71.  For the year ended December 31, 2003, LG&E recorded ARO accretion expense of approximately $0.6 million, ARO depreciation expense of $0.1 million and an offsetting regulatory credit in the income statement of $0.7 million.  Removal costs incurred and charged against the ARO liability during 2004 and 2003, were $0.1 million and $0.2 million, respectively.  SFAS No. 143 has no impact on the results of operations of LG&E.

LG&E AROs are primarily related to final retirement of assets associated with generating units.  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, 2004 and 2003, LG&E recorded immaterial amounts (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 also continues to include a cost of removal component in depreciation for assets that do not have a legal ARO.  As of December 31, 2004 and 2003, LG&E has segregated this cost of removal, embedded in accumulated depreciation, of $220.2 million and $216.5 million, respectively, in accordance with FERC Order No. 631. For reporting purposes in its Consolidated Balance Sheets, LG&E has presented this cost of removal as a regulatory liability pursuant to 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.

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EITF No. 02-03

LG&E adopted EITF No. 98-10effective January 1, 1999.  This pronouncement required that energy trading contracts be marked to market on the balance sheet, with the gains and losses shown net in the income statement.  Effective January 1, 2003, LG&E adopted EITF No. 02-03.  EITF No. 02-03 established the following:

•     Rescinded EITF No. 98-10,

•     Contracts that do not meet the definition of a derivative under SFAS No. 133 should not be marked to fair market value, and

•     Revenues should be shown in the income statement net of costs associated with trading activities, whether or not the trades are physically settled.

With the rescission of EITF No. 98-10, energy trading contracts that do not also meet the definition of a derivative under SFAS No. 133 must be accounted for as executory contracts.  Contracts previously recorded at fair value under EITF No. 98-10 that are not also derivatives under SFAS No. 133 must be restated to historical cost through a cumulative effect adjustment.  The rescission of this standard had no impact on financial position or results of operations of LG&E since all forward and option contracts marked to market under EITF No. 98-10 were also within the scope of SFAS No. 133.

As a result of EITF No. 02-03, LG&E has netted the power purchased expense for trading activities against electric operating revenue to reflect this accounting change.  LG&E applied this guidance to previously reported 2002 balances as shown below.  The reclassifications had no impact on previously reported net income or common equity.

(in thousands)
Gross electric operating revenues as previously reported	$	1,026,184
Less costs reclassified from power purchased	22,449
Net electric operating revenues	$	1,003,735
Gross power purchased as previously reported	$	84,330
Less costs reclassified to revenues	22,449
Net power purchased	$	61,881

SFAS No. 150

In May 2003, the Financial Accounting Standards Board issued SFAS No. 150, which was effective immediately for financial instruments entered into or modified after May 31, 2003, and otherwise was effective for interim reporting periods beginning after June 15, 2003, except for certain instruments and certain entities which have been deferred by the FASB.  Such deferrals do not affect LG&E.

LG&E has $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, 2004 and 2003, leaving 225,000 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.  Dividends accrued beginning July 1, 2003 are charged as interest expense.

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FIN 46

In January 2003, the Financial Accounting Standards Board issued FIN 46.  FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties.  FIN 46 was effective immediately for all new variable interest entities created or acquired after January 31, 2003.  For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must have been applied for the first interim or annual period beginning after June 15, 2003.

In December 2003, FIN 46 was revised, delaying the effective dates for certain entities created before February 1, 2003, and making other amendments to clarify application of the guidance.  For potential variable interest entities other than special purpose entities, FIN 46R was required to be applied no later than the end of the first fiscal year or interim reporting period ending after March 15, 2004.  The original guidance under FIN 46 was applicable, however, for all special purpose entities created prior to February 1, 2003, at the end of the first interim or annual reporting period ending after December 15, 2003.  FIN 46R may be applied prospectively with a cumulative-effect adjustment as of the date it is first applied, or by restating previously issued financial statements with a cumulative-effect adjustment as of the beginning of the first year restated.  FIN 46R also requires certain disclosures of an entity’s relationship with variable interest entities. The adoption of FIN 46 and FIN 46R has no impact on the financial position or results of operations of LG&E.

Although LG&E holds an investment interest in OVEC, it is not the primary beneficiary of OVEC and, therefore, OVEC is not consolidated into the financial statements of LG&E.

LG&E and 11 other electric utilities are participating owners of 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’s share is 7%, representing approximately 155 Mw of generation capacity, and 5.63% thereafter.

LG&E’s original investment in OVEC was made in 1952.  As of December 31, 2004, LG&E’s investment in OVEC totaled $0.5 million.  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 an increase in LG&E ownership in OVEC from 4.9% to 5.63%.  LG&E’s investment in OVEC 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 the 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 11 for further discussion of developments regarding LG&E’s ownership interest and power purchase rights.

FSP 106-2

In May 2004, the FASB finalized FSP 106-2 with guidance on accounting for subsidies provided under the Medicare Act which became law in December 2003.  FSP 106-2 is effective for the first interim or annual period beginning after June 15, 2004.  FSP 106-2 does not have a material impact on LG&E.

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FSP 109-1

In December 2004, the FASB finalized FSP 109-1, whichrequires the tax deduction on qualified production activities to be treated as a special deduction in accordance with FAS 109.  FSP 109-1 became effective December 21, 2004, and does not have a material impact on LG&E.

Note 2 – Mergers and Acquisitions

On July 1, 2002, E.ON completed its acquisition of Powergen, including LG&E Energy, for approximately £5.1 billion ($7.3 billion).  As a result of the acquisition, LG&E Energy 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 utilities continue to file SEC reports.  Following the acquisition, E.ON became a registered holding company under PUHCA. LG&E, as a subsidiary of a registered holding company, is subject to additional regulations under PUHCA.  In March 2003, E.ON, Powergen and LG&E Energy completed an administrative reorganization to move the LG&E Energy group from an indirect Powergen subsidiary to an indirect E.ON subsidiary.  In early 2004, LG&E Energy commenced direct reporting arrangements to E.ON.

LG&E Energy and KU Energy merged on May 4, 1998, with LG&E Energy as the surviving corporation.  Management accounted for the merger as a pooling of interests and as a tax-free reorganization under the Internal Revenue Code.  Following the acquisition, LG&E has continued to maintain its separate corporate identity and serve customers under its present name.

Note 3 - Rates and Regulatory Matters

Electric and Gas Rate Cases

In December 2003, LG&E filed applications with the Kentucky Commission requesting adjustments in LG&E’s electric and gas rates.  LG&E asked for general adjustments in electric and gas rates based on the twelve month test year ended September 30, 2003.  The revenue increases requested were $63.8 million for electric and $19.1 million for gas.

On June 30, 2004, the Kentucky Commission issued an order approving increases in the base electric and gas rates of LG&E.  The Kentucky Commission’s order largely accepted proposed settlement agreements filed in May 2004 by LG&E and a majority of the parties to the rate case proceedings.  The rate increases took effect on July 1, 2004.

In the Kentucky Commission’s order, LG&E was granted increases in annual base electric rates of approximately $43.4 million (7.7%) and in annual base gas rates of approximately $11.9 million (3.4%).  Other provisions of the order include decisions on certain depreciation, gas supply clause, ECR and VDT amounts or mechanisms and a termination of the ESM with respect to all periods after 2003.  The order also provided for a recovery before March 31, 2005, by LG&E of previously requested amounts relating to the ESM during 2003.

During July 2004, the AG served subpoenas on LG&E, as well as on 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. The Kentucky Commission has procedurally reopened the rate cases for the limited purpose of taking evidence, if any, as to the communication issues. Subsequently, the AG filed pleadings with the Kentucky Commission requesting rehearing of the rate cases on certain computational components of the increased rates, including income tax, cost of removal and

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depreciation amounts. In August 2004, the Kentucky Commission denied the AG’s rehearing request on the cost of removal and depreciation issues, with the effect that the rate increase order is final as to these matters, subject to the parties’ rights to judicial appeals. The Kentucky Commission further agreed to hold in abeyance further proceedings in the rate cases, including the AG’s concerns about alleged improper communications, until the AG could file with the Kentucky Commission an investigative report regarding the latter issue. In addition, the Kentucky Commission granted a rehearing on the income tax component once the abeyance discussed above is lifted.

In September and October 2004, various proceedings were held in circuit courts in Franklin and Jefferson Counties, Kentucky regarding the scope and timing of document production or other information required or agreed to be produced under the AG’s subpoenas and matters were consolidated into the Franklin County court.  In October 2004, the AG filed a motion with the Kentucky Commission requesting that the previously granted rate increases be set aside, that LG&E resubmit any applications for rate increases and that relevant Kentucky Commission personnel be recused from participation in rate case proceedings.  In November 2004, the Franklin County, Kentucky court denied an AG request for sanctions on LG&E relating to production matters and narrowed the AG’s permitted scope of discovery.  In January 2005, the AG conducted interviews of certain Company individuals.

In January 2005, the AG submitted its report to the Franklin County, Kentucky Circuit Court in confidence.  Concurrently the AG filed a motion summarizing the 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 requesting release of the report to such agencies.  During February 2005 the court ruled that the report be forwarded 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 cases, including ending the current abeyance.  To date, LG&E has neither seen nor requested copies of the report or its contents.

LG&E believes no improprieties have occurred in its communications with the Kentucky Commission and is cooperating 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 base rates.

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Regulatory Assets and Liabilities

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

(in thousands)	2004		2003
VDT Costs	$	37,676	$	67,810
Unamortized loss on bonds	20,272		21,333
ARO	6,870		6,015
Merger surcredit	4,838		6,220
ESM	2,118		12,359
Rate case expenses	1,111		854
FAC	842		—
DSM	—		24
Gas supply adjustments due from customers	13,320		22,077
Gas performance base ratemaking	3,673		5,480
Manufactured gas sites	1,146		1,454
Total regulatory assets	$	91,866	$	143,626
Accumulated cost of removal of utility plant	$	220,214	$	216,491
Deferred income taxes - net	37,184		41,180
ECR	4,039		17
DSM	2,439		1,706
ARO	136		85
FAC	8		1,950
ESM	—		79
Gas supply adjustments due to customers	8,344		6,805
Total regulatory liabilities	$	272,364	$	268,313

LG&E currently earns a return on all regulatory assets except for gas supply adjustments, ESM, 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 Costs - Kentucky Commission Settlement Order.  During the first quarter of 2001, LG&E recorded a $144 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 June 2001, LG&E filed an application (VDT case) with the Kentucky Commission to create a regulatory asset relating to these first quarter 2001 charges.  The application requested permission to amortize these costs over a four-year period.  The Kentucky Commission also opened a case to review a new depreciation study and resulting depreciation rates implemented in 2001.

In December 2001, the Kentucky Commission approved a settlement in the VDT case as well as other cases involving the depreciation rates and ESM. The order approving the settlement allowed LG&E to set up a regulatory asset of $141 million for the workforce reduction costs and begin amortizing these costs over a five-year period starting in April 2001. The first quarter 2001 charge of $144 million represented all employees who had accepted a voluntary enhanced severance program.  Some employees rescinded their participation in the voluntary enhanced severance program, thereby decreasing the original charge to the regulatory asset from $144 million to $141 million. The settlement reduces revenues approximately $26 million through a surcredit on bills to ratepayers over the same five-year period.  The surcredit represents net savings stipulated by LG&E.

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As mentioned, the current five-year VDT amortization period is scheduled to expire in March 2006.  As part of the settlement agreements in the electric and gas rate cases, LG&E shall file with the Kentucky Commission a plan for the future ratemaking treatment of the VDT surcredits and costs six months prior to the March 2006 expiration.  The surcredit shall remain in effect following the expiration of the fifth year until the Commission enters an order on the future disposition of VDT-related issues.

ARO.  At December 31, 2004 and 2003, LG&E had recorded $6.9 million and $6.0 million in regulatory assets and $0.1 million and $0.1 million in regulatory liabilities, respectively, related to SFAS No. 143.

Merger Surcredit.  As part of the LG&E Energy merger with KU Energy in 1998, LG&E Energy estimated non-fuel savings over a ten-year period following the merger.  Costs to achieve these savings for LG&E of $50.2 million were recorded in the second quarter of 1998, $18.1 million of which was deferred and amortized over a five-year period pursuant to regulatory orders.  Primary components of the merger costs were separation benefits, relocation costs, and transaction fees, the majority of which were paid by December 31, 1998.  LG&E expensed the remaining costs associated with the merger ($32.1 million) in the second quarter of 1998.

In approving the merger, the Kentucky 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 and lower point for rate of return on equity, whereby if LG&E’s rate of return for the calendar year fell within the range of 10.5% to 12.5%, no action was necessary.  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 and interested parties had the opportunity to provide recommendations for modification and continuance of the ESM or other forms of alternative or incentive regulation.

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.

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On June 30, 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 will continue 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.

As a result of the settlement, LG&E accrued an additional $4.1 million in June 2004, related to 2003 ESM revenue.

FAC.  LG&E’s retail electric rates contain a FAC, whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to retail 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 is due in May 2005.

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 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 is expected in April 2005.  LG&E is seeking to increase the fuel component of base rates.  LG&E does not anticipate any issues will arise during the regulatory proceeding.

DSM.  LG&E’s rates contain a DSM provision.  The provision includes a rate mechanism that provides concurrent recovery of DSM costs and provides an incentive for implementing DSM programs.  This provision allowed LG&E to recover revenues from lost sales associated with the DSM programs.  In May 2001, the Kentucky Commission approved LG&E’s plan to continue DSM programs.  This plan called for the expansion of the LG&E DSM programs into the service territory served by KU and proposed a mechanism to recover revenues from lost sales associated with DSM programs based on program plan engineering estimates and post-implementation evaluations.

Gas Supply Cost PBR Mechanism.  Since November 1, 1997, LG&E has operated under a PBR mechanism related to its gas procurement activities.  LG&E’s rates are adjusted annually to recover its portion of the savings (or expenses) incurred during each PBR year (12 months ending October 31). Since its implementation on November 1, 1997, through October 31, 2004, LG&E has achieved $60.7 million in savings. Of that total savings amount, LG&E’s portion has been $22.7 million and the ratepayers’ portion has been $38.0 million.  Pursuant to the extension of LG&E’s gas supply cost PBR mechanism effective November 1, 2001, the sharing mechanism under PBR requires savings (and expenses) to be shared 25% with shareholders and 75% with ratepayers up to 4.5% of the benchmarked gas costs.  Savings (and expenses) in excess of 4.5% of the benchmarked gas costs are shared 50% with shareholders and 50% with ratepayers.  LG&E filed a report and assessment with the Kentucky Commission on December 30, 2004, seeking modification and extension of the mechanism.

Accumulated Cost of Removal.  As of December 31, 2004 and 2003, LG&E has segregated the cost of removal, embedded in accumulated depreciation, of $220.2 million and $216.5 million, respectively, in

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accordance with FERC Order No. 631.  For reporting purposes in the Consolidated Balance Sheets, LG&E has presented this cost of removal as a regulatory liability pursuant to SFAS No. 71.

ECR.  In May 2002, the Kentucky Commission initiated a periodic two-year review of LG&E’s environmental surcharge.  The review included the operation of the surcharge mechanism, determination of the appropriateness of costs included in the surcharge mechanism, recalculation of the cost of debt to reflect actual costs for the period under review, final determination of the amount of environmental revenues over-collected from customers, and a final determination of the amount of environmental costs and revenues to be “rolled-in” to base rates.  A final order was issued in October 2002, in which LG&E was ordered to refund $0.3 million to customers over the four month period beginning November 2002 and ending February 2003.  Additionally, LG&E was ordered to roll $4.1 million into base rates and make corresponding adjustments to the monthly environmental surcharge filings to reflect that portion of environmental rate base now included in base rates.

In August 2002, LG&E filed an application with the Kentucky Commission to amend its compliance plan to allow recovery of the cost of new and additional environmental compliance facilities.  The estimated capital cost of the additional facilities is $71.1 million.  A final order was issued in February 2003, approving recovery of four new environmental compliance facilities totaling $43.1 million.  A fifth project, expansion of the landfill facility at the Mill Creek Station, was denied without prejudice with an invitation to reapply for recovery when required construction permits are approved.  Cost recovery through the environmental surcharge of the four approved projects commenced with bills rendered in April 2003.

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 of environmental rate base now included in base rates on a going-forward basis.  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 the cost of 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 is $40.2 million.  LG&E requested an overall rate of return of 10.72%, including an 11% return on common equity.  A final order in the case is anticipated in June 2005.

Other Regulatory Matters

MISO.  LG&E is a founding member of the MISO.  Membership was obtained in 1998 in response to and consistent with federal policy initiatives.  In February 2002, LG&E turned over operational control of their high voltage transmission facilities (100kV and above) to the MISO.  The MISO currently controls over 100,000 miles of transmission lines over 1.1 million square miles located in the northern Midwest between Manitoba, Canada and Kentucky.  In September 2002, FERC granted a 12.88% ROE on transmission facilities for LG&E and the rest of the MISO owners.  On February 18, 2005, the United States Court of Appeals for the District of

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Columbia Circuit ruled that FERC did not provide proper notice that it would consider an incentive adder of 50 basis points, but affirmed the September 2002 FERC order in all other respects.  Effective ROE, retroactive to February 1, 2002, is 12.38% for LG&E and the original MISO owners.

In October 2001, the FERC issued an order requiring that the bundled retail load and grandfathered wholesale load of each member transmission owner be included in the current calculation of the MISO’s “cost-adder,” the Schedule 10 charges designed to recover the MISO’s costs of operation, including start-up capital (debt) costs.  LG&E, along with several other transmission owners, opposed the FERC’s ruling on this matter. The opposition was rejected by the FERC in 2002.  Later that year, the MISO’s transmission owners, appealed the FERC’s decision to the United States Court of Appeals for the District of Columbia Circuit.  In response, in November 2002, the FERC requested that the Court issue a partial remand of its challenged orders to allow the FERC to revisit certain issues, and requested that the case be held in abeyance pending the agency’s resolution of such issues.  The Court granted the FERC’s petition in December 2002.  In February 2003, FERC issued an order reaffirming its position concerning the calculation of the Schedule 10 charges and in July 2003 denied a rehearing.  LG&E, along with several other transmission owners, again petitioned the District Court of Columbia Circuit for review. In July 2004 the court affirmed the FERC ruling.

In August 2004, the MISO filed its FERC-required proposed TEMT.  In September and October 2004, many MISO-related parties (including LG&E) filed proposals with the FERC regarding pending MISO-filed changes to transmission pricing principles, including the TEMT and elimination of RTORs. Additional filings of the companies before FERC in September 2004 sought to address issues relating to the treatment of certain GFA’s should TEMT become effective. The utility proposals generally seek to appropriately delay the RTORs and TEMT effective dates based upon errors in administrative or procedural processes used by FERC or to appropriately limit potential reductions in transmission revenues received by the utilities should the RTORs, TEMT or GFA structures be implemented.  At present, existing FERC orders conditionally approve elimination of RTORs and implementation of general TEMT rates in the MISO by spring 2005.  At this time, LG&E cannot predict the outcome or effects of the various FERC proceedings described above, including whether such will have a material impact on the financial condition or results of operations of the companies. Financial consequences (changes in transmission revenues and costs) associated with the upcoming transmission market tariff changes are subject to varying assumptions and calculations and are therefore difficult to estimate. Changes in revenues and costs related to broader shifts in energy market practices and economics are not currently estimable.  Should LG&E be ordered to exit MISO, current MISO rules may also impose an exit fee.  LG&E is not able to predict the estimated outcome or economic impact of any of the MISO-related matters.  While LG&E believes legal and regulatory precedent should permit most or many of the MISO-related costs to be recovered in their rates charged to customers, they can give no assurance that state or federal regulators will ultimately agree with such position with respect to all costs, components or timing of recovery.

The MISO plans to implement a Day-ahead and Real-time market, including a congestion management system in April 2005. This system will be similar to the LMP system currently used by the PJM RTO and contemplated in FERC’s SMD NOPR, currently being discussed.  The MISO filed with FERC a mechanism for recovery of costs for the congestion management system.  They proposed the addition of two new Schedules, 16 and 17.  Schedule 16 is the MISO’s cost recovery mechanism for the Financial Transmission Rights Administrative Service it will provide.  Schedule 17 is the MISO’s mechanism for recovering costs it will incur for providing Energy Marketing Support Administrative Service.  The MISO transmission owners, including LG&E, have objected to the allocation of costs among market participants and retail native load. FERC ruled in 2004 in favor of the MISO.

The Kentucky Commission opened an investigation into LG&E’s membership in the MISO in July 2003. The Kentucky Commission directed LG&E to file testimony addressing the costs and benefits of the MISO membership both currently and over the next five years and other legal issues surrounding continued

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membership.  LG&E engaged an independent third-party to conduct a cost benefit analysis on this issue.  The information was filed with the Kentucky Commission in September 2003.  The analysis and testimony supported the exit from the MISO, under certain conditions.  The MISO filed its own testimony and cost benefit analysis in December 2003.  A final Kentucky Commission order was expected in the second quarter of 2004; that ruling has since been delayed until summer 2005 due to the Kentucky Commission’s request for additional testimony on the MISO’s Market Tariff filing at FERC.

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 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 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.

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 will be 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.  The Kentucky Commission must provide its Strategic Blueprint to the Governor in early August 2005.  LG&E must respond to the Kentucky Commission’s first set of data requests by the end of March 2005.

FERC SMD NOPR.  In July 2002, the FERC issued a NOPR in Docket No. RM01-12-000 which would substantially alter the regulations governing the nation’s wholesale electricity markets by establishing a common set of rules, defined as SMD. The SMD NOPR would require each public utility that owns, operates, or controls interstate transmission facilities to become an ITP, belong to an RTO that is an ITP, or contract with an ITP for operation of its transmission assets. It would also establish a standardized congestion management system, real-time and day-ahead energy markets, and a single transmission service for network and point-to-point transmission customers. Review of the proposed rulemaking is underway and no timeframe has been established by the FERC for adoption of a final rule.  While it is expected that the SMD final rule will affect LG&E revenues and expenses, the specific impact of the rulemaking is not known at this time.

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Kentucky Commission Administrative Case for Affiliate Transactions.  In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates.  The Kentucky Commission intended to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility.  In early 2000, the Kentucky General Assembly enacted legislation, House Bill 897, which authorized the Kentucky Commission to require utilities that provide nonregulated activities to keep separate accounts and allocate costs in accordance with procedures established by the Kentucky Commission.  In the same bill, the General Assembly set forth provisions to govern a utility’s activities related to the sharing of information, databases, and resources between its employees or an affiliate involved in the marketing or the provision of nonregulated activities and its employees or an affiliate involved in the provision of regulated services. The legislation became law in July 2000 and LG&E has been operating pursuant thereto since that time.  In February 2001, the Kentucky Commission published notice of its intent to promulgate new administrative regulations under the auspices of this new law.  This effort is still on-going.

Wholesale Natural Gas Prices.  On September 12, 2000, the Kentucky Commission issued an order establishing Administrative Case No. 384 – “An Investigation of Increasing Wholesale Natural Gas Prices and the Impacts of such Increase on the Retail Customers Served by Kentucky’s Jurisdictional Natural Gas Distribution Companies”.

Subsequent to this investigation, the Kentucky Commission issued an order on July 17, 2001, encouraging the natural gas distribution companies in Kentucky to take various actions, among them to propose a natural gas hedge plan, consider performance-based ratemaking mechanisms, and to increase the use of storage.

In May 2004, in Case No. 2004-148, LG&E proposed a hedge plan for the 2004/2005 winter heating season relying upon LG&E’s storage to mitigate customer exposure to price volatility. In August 2004, the Kentucky Commission approved LG&E’s proposed hedge plan, validating the effectiveness of storage to mitigate potential volatility associated with high winter gas prices by approving this natural gas hedge plan.  The Kentucky Commission also ordered that LG&E need not file hedge plans in the future unless it intended to utilize financial hedging instruments.

Note 4 - Financial Instruments

The cost and estimated fair values of LG&E’s non-trading financial instruments as of December 31, 2004, and 2003 follow:

	2004					2003
			Fair					Fair
(in thousands)	Cost		Value			Cost		Value
Preferred stock subject to mandatory redemption	$	22,500	$	22,781		$	23,750	$	23,893
Long-term debt (including current portion)	$	574,304	$	575,419		$	574,304	$	576,174
Long-term debt from affiliate	$	275,000	$	280,684		$	200,000	$	206,333
Interest-rate swaps - liability	—		$	(18,542	)	—		$	(15,966	)

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.

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Interest Rate Swaps. LG&E uses interest rate swaps to hedge exposure to market fluctuations in certain of its debt instruments.  Pursuant to 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.  To the extent a financial instrument designated as a cash flow hedge or the underlying item being hedged is prematurely terminated or the hedge becomes ineffective, the resulting gains or losses are reclassified from other comprehensive income to net income. See Note 15, 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 $228.3 million as of December 31, 2004 and 2003.  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 1.74% and 1.11% at December 31, 2004 and 2003, respectively. The swap agreements in effect at December 31, 2004 have been designated as cash flow hedges and mature on dates ranging from 2005 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 gain of $2.3 million for 2004, recorded in other comprehensive income.  Upon expiration of these hedges, the amount recorded in other comprehensive income will be reclassified into earnings.  The amounts expected to be reclassified from other comprehensive income to earnings in the next twelve months is immaterial (less than $0.1 million). A deposit in the amount of $10.9 million, used as collateral for the $83.3 million interest rate swap, 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 Trading & Risk Management Activities.  LG&E conducts energy trading and risk management activities to maximize the value of power sales from physical assets it owns, in addition to the wholesale sale of excess asset capacity.  Certain energy trading activities are accounted for on a mark-to-market basis in accordance with SFAS No. 133, SFAS No. 138and SFAS No. 149.  Wholesale sales of excess asset capacity are treated as normal sales under these pronouncements and are not marked to market.  To be eligible for the normal sales exclusion under SFAS No. 133, sales are limited to the forecasted excess capacity of LG&E’s generation assets over what is needed to serve native load.  To be eligible for the normal purchases exclusion under SFAS No. 133 purchases must be used to serve the LG&E’s native load.  Without the normal sales and purchases exclusion these transactions would be considered derivatives and marked to market under SFAS No. 133.

The rescission of EITF No. 98-10 for fiscal periods ending after December 15, 2002, had no impact on LG&E’s energy trading and risk management reporting as all forward and option contracts marked to market under EITF No. 98-10 are also within the scope of SFAS No. 133.

No changes to valuation techniques for energy trading and risk management activities occurred during 2004.  Changes in market pricing, interest rate and volatility assumptions were made during both years.  All contracts outstanding at December 31, 2004, 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, 2004, 100% of the trading and risk management commitments were with counterparties rated BBB-/Baa3 equivalent or better.

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LG&E hedges the price volatility of its forecasted peak electric off-system sales with the sales of market-traded electric forward contracts for periods 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 Consolidated Statements of Income in other income (expense) – net.  Upon expiration of these instruments, 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 2004, 2003 and 2002.  See Note 15, Accumulated Other Comprehensive Income.

Accounts Receivable Securitization.  On February 6, 2001, LG&E implemented an accounts receivable securitization program. LG&E terminated the accounts receivable securitization program in January 2004, and in May 2004, LG&E dissolved its inactive accounts receivable securitization-related subsidiary, LG&E R.  The purpose of this program was to enable LG&E to accelerate the receipt of cash from the collection of retail accounts receivable, thereby reducing dependence upon more costly sources of working capital.  The securitization program allowed for a percentage of eligible receivables to be sold.  Eligible receivables were generally all receivables associated with retail sales that had standard terms and were not past due.  LG&E was able to terminate the program at any time without penalty. 

As part of the program, LG&E sold retail accounts receivable to LG&E R.  Simultaneously, LG&E R entered into two separate three-year accounts receivable securitization facilities with two financial institutions and their affiliates whereby LG&E R could sell, on a revolving basis, an undivided interest in certain of its receivables and receive up to $75 million from unrelated third-party purchasers.  The effective cost of the receivables program was comparable to LG&E’s lowest cost source of capital, and was based on prime rated commercial paper. LG&E retained servicing rights of the sold receivables through two separate servicing agreements with the third-party purchasers.  LG&E obtained an opinion from independent legal counsel indicating these transactions qualified as a true sale of receivables. 

To determine LG&E’s retained interest, the proceeds on the sale of receivables to the financial institutions were netted against the amount of eligible receivables sold by LG&E to LG&E R.  Interest expense, program fees, and facility fees paid to the financial institutions and an allowance for doubtful accounts were deducted to arrive at the future value of retained interest.  The future value was discounted using the prime rate plus 25 basis points, assuming a 45-day receivable life.  No material pre-tax gains and losses from the sale of the receivables occurred in 2004, 2003 and 2002.  LG&E’s net cash flows from LG&E R were $(58.1) million, $(6.2) million and $20.2 million for 2004, 2003 and 2002, respectively.

The allowance for doubtful accounts associated with the eligible securitized receivables at December 31 was $1.4 million and $1.9 million in 2003 and 2002, respectively.  This allowance was based on historical experience of LG&E. Each securitization facility contained a fully funded reserve for uncollectible receivables.

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 318,000 customers and electricity to approximately 390,000 customers in Louisville and adjacent areas in Kentucky.  For the year ended December 31, 2004, 70% of total revenue was derived from electric operations and 30% from gas operations.

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In November 2001, LG&E and IBEW Local 2100 employees, that represent approximately 72% of LG&E’s workforce, entered into a four-year collective bargaining agreement and completed wage and benefit re-opener negotiations in October 2003.

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.

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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, 2004, and a statement of the funded status as of December 31, 2004, for LG&E’s sponsored defined benefit plan:

(in thousands)	2004			2003			2002
Pension Plans:
Change in benefit obligation
Benefit obligation at beginning of year	$	378,691		$	364,794		$	356,293
Service cost	2,777			1,757			1,484
Interest cost	22,742			23,190			24,512
Plan amendments	3,301			3,978			576
Change due to transfers	(1,144		)	(2,759		)	—
Benefits paid	(30,520		)	(33,539		)	(34,823		)
Actuarial (gain) or loss and other	26,529			21,270			16,752
Benefit obligation at end of year	$	402,376		$	378,691		$	364,794
Change in plan assets
Fair value of plan assets at beginning of year	$	297,778		$	196,314		$	233,944
Actual return on plan assets	39,240			47,152			(15,648		)
Employer contributions	34,492			89,125			336
Change due to transfers	(1,071		)	238			13,814
Benefits paid	(30,520		)	(33,539		)	(34,824		)
Administrative expenses	(1,764		)	(1,512		)	(1,308		)
Fair value of plan assets at end of year	$	338,155		$	297,778		$	196,314
Reconciliation of funded status
Funded status	$	(64,221	)	$	(80,913	)	$	(168,480	)
Unrecognized actuarial (gain) or loss	70,304			56,219			60,313
Unrecognized transition (asset) or obligation	(1,455		)	(2,183		)	(3,199		)
Unrecognized prior service cost	31,505			32,275			32,265
Net amount recognized at end of year	$	36,133		$	5,398		$	(79,101	)
Other Benefits:
Change in benefit obligation
Benefit obligation at beginning of year	$	108,030		$	93,233		$	89,946
Service cost	895			604			444
Interest cost	6,524			6,872			5,956
Plan amendments	355			7,380			—
Benefits paid	(7,119		)	(9,313		)	(4,988		)
Actuarial (gain) or loss	4,265			9,254			1,875
Benefit obligation at end of year	$	112,950		$	108,030		$	93,233
Change in plan assets
Fair value of plan assets at beginning of year	$	674		$	1,478		$	2,802
Actual return on plan assets	(2,007		)	2,076			(533		)
Employer contributions	9,339			6,401			4,213
Change due to transfers	(105		)	—			—
Benefits paid	(7,126		)	(9,281		)	(5,004		)
Fair value of plan assets at end of year	$	775		$	674		$	1,478
Reconciliation of funded status
Funded status	$	(112,175	)	$	(107,356	)	$	(91,755	)
Unrecognized actuarial (gain) or loss	29,414			23,724			16,971
Unrecognized transition (asset) or obligation	5,357			6,027			6,697
Unrecognized prior service cost	10,036			11,482			5,995
Net amount recognized at end of year	$	(67,368	)	$	(66,123	)	$	(62,092	)

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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, 2004, 2003 and 2002:

(in thousands)	2004			2003			2002
Pension Plans:
Amounts recognized in the balance sheet consisted of:
Accrued benefit liability	$	(53,197	)	$	(74,474	)	$	(162,611	)
Intangible asset	31,505			32,275			32,799
Accumulated other comprehensive income	57,825			47,597			50,711
Net amount recognized at year-end	$	36,133		$	5,398		$	(79,101	)
Increase (decrease) in minimum liability included in other comprehensive income	$	10,228		$	(3,114	)	$	25,999
Additional year-end information for plans with accumulated benefit obligations in excess of plan assets:
Projected benefit obligation	$	402,376		$	378,691		$	364,794
Accumulated benefit obligation	391,353			372,252			358,956
Fair value of plan assets	338,155			297,778			196,314
Other Benefits:
Amounts recognized in the balance sheet consisted of:
Accrued benefit liability	$	(67,368	)	$	(66,123	)	$	(62,092	)
Additional year-end information for plans with benefit obligations in excess of plan assets:
Benefit obligation	$	112,950		$	108,030		$	93,233
Fair value of plan assets	775			674			1,478

Components of Net Periodic Benefit Cost.  The following table provides the components of net periodic benefit cost for the plans for 2004, 2003 and 2002:

(in thousands)	2004			2003			2002
Pension Plans:
Components of net periodic benefit cost
Service cost	$	2,777		$	1,756		$	1,484
Interest cost	22,742			23,190			24,512
Expected return on plan assets	(26,975		)	(22,785		)	(21,639		)
Amortization of prior service cost	4,071			3,792			3,777
Amortization of transition (asset) or obligation	(728		)	(1,016		)	(1,016		)
Amortization of actuarial (gain) or loss	1,870			2,219			21
Net periodic benefit cost	$	3,757		$	7,156		$	7,139
Other Benefits:
Components of net periodic benefit cost
Service cost	$	895		$	604		$	444
Interest cost	6,524			6,872			5,956
Expected return on plan assets	—			(51		)	(204		)
Amortization of prior service cost	1,800			1,768			920
Amortization of transition (asset) or obligation	670			670			650
Amortization of actuarial (gain) or loss	695			505			116
Net periodic benefit cost	$	10,584		$	10,368		$	7,882

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

	2004		2003		2002
Weighted-average assumptions as of December 31:
Discount rate	5.75	%	6.25	%	6.75	%
Rate of compensation increase	4.50	%	3.00	%	3.75	%

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

	2004		2003		2002
Discount rate	6.25	%	6.75	%	7.25	%
Expected long-term return on plan assets	8.50	%	9.00	%	9.50	%
Rate of compensation increase	3.50	%	3.75	%	4.25	%

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, a 12.0% annual increase in the per capita cost of covered healthcare benefits was assumed for 2004.  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:

(in thousands)	1% Decrease			1% Increase
Effect on total of service and interest cost components for 2004	$	(283	)	$	322
Effect on year-end 2004 postretirement benefit obligations	$	(3,603	)	$	4,016

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

(in thousands)	Pension Plans		Other Benefits
2005	$	29,783	$	8,207
2006	$	28,878	$	8,095
2007	$	28,118	$	8,367
2008	$	27,353	$	8,520
2009	$	26,466	$	8,716
2010-2014	$	122,939	$	46,850

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

	Target Range		2004		2003		2002
Pension Plans:
Equity securities	55% - 85%		66	%	66	%	64	%
Debt securities	20%- 40%		33	%	33	%	34	%
Other	0% - 10%		1	%	1	%	2	%
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 with a targeted real rate of return (adjusted for inflation) objective of 6.0 percent.

The fund 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 have a maximum average weighted maturity of no more than fifteen (15) years, with the weighted average duration of the portfolio being no more than eight (8) years.  All securities must be rated “investment grade” or better and foreign bonds in the aggregate shall not exceed 10% of the total fund.  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 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 $34.5 million in January 2004 and $89.2 million during 2003.  No discretionary contributions are planned for 2005.

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FSP 106-2.  In May 2004, the FASB finalized FSP 106-2 with the guidance on accounting for subsidies provided under the Medicare Act which became law in December 2003.  FSP 106-2 was effective for the first interim or annual period beginning after June 15, 2004.  The following table reflects the impact of the subsidy:

(in thousands)
Reduction in accumulated postretirement benefit obligation (“APBO”)	$	3,166
Effect of the subsidy on the measurement of the net periodic postretirement benefit cost:
Amortization of the actuarial experience gain/(loss)	$	198
Reduction in service cost due to the subsidy	0
Resulting reduction in interest cost on the APBO	198
Total	$	396

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 $1.4 million for 2004, $1.8 million for 2003, and $1.7 million for 2002.

Note 7 - Income Taxes

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

(in thousands)		2004			2003			2002
Related to operating income:
Current	- federal	$	35,190		$	30,598		$	26,231
	- state	13,358			11,007			8,083
Deferred	- federal – net	11,363			16,922			20,464
	- state – net	(800		)	1,746			4,410
Amortization of investment tax credit		(4,153		)	(4,207		)	(4,153		)
Total		54,958			56,066			55,035
Related to other income - net:
Current	- federal	(1,340		)	(4,830		)	(1,667		)
	- state	(350		)	(1,004		)	(430		)
Deferred	- federal – net	21			(129		)	(206		)
	- state – net	5			(30		)	(53		)
Total		(1,664		)	(5,993		)	(2,356		)
Total income tax expense		$	53,294		$	50,073		$	52,679

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

(in thousands)	2004		2003
Deferred tax liabilities:
Depreciation and other plant-related items	$	397,806	$	365,460
Regulatory assets and other	33,335		52,976
	431,141		418,436
Deferred tax assets:
Investment tax credit	18,638		20,314
Income taxes due to customers	15,008		16,620
Pensions and related benefits	32,219		29,508
Liabilities and other	18,043		14,290
	83,908		80,732
Net deferred income tax liability	$	347,233	$	337,704
Thereof non-current	$	342,609	$	332,796
Thereof current	4,624		4,908
	$	347,233	$	337,704

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

	2004		2003		2002
Statutory federal income tax rate	35.0	%	35.0	%	35.0	%
State income taxes, net of federal benefit	5.3		5.4		5.6
Amortization of investment tax credit	(3.6	)	(3.0	)	(2.9	)
Other differences – net	(0.9	)	(1.9	)	(0.5	)
Effective income tax rate	35.8	%	35.5	%	37.2	%

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 generation taxable income in 2005. On a stand-alone basis, LG&E expects to generate a deduction in 2005 which will reduce LG&E’s effective tax rate by less than 1%.

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.  The impact of these reduced rates is expected to decrease LG&E’s income tax expense in future periods.  Furthermore, these reduced rates will result in the reversal of accumulated temporary differences at lower rates than originally provided.  LG&E is presently evaluating the impact of this and other changes to the Kentucky tax system, however, no material adverse impacts on cash flows or results of operations are expected.

LG&E is subject to periodic changes in state tax law, regulation or interpretation, as well as enforcement proceedings.  LG&E is currently undergoing a routine Kentucky sales tax audit for the period October 1997 through 2001.  The possible assessment or amount at issue is not known at this time, but is not expected to have a material adverse effect on cashflows or results of operations. 

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Note 8 - Other Income (Expense) - Net

Other income (expense) - net consisted of the following at December 31:

(in thousands)	2004				2003			2002
Interest and dividend income (expense)	$		304		$	100		$	554
IMEA/IMPA fees	719				806			859
Gain on disposition of property	166				2			421
Terminated projects	0				(2,997		)	0
Benefits expense	0				0			(1,655		)
Other	(4,521			)	(5,104		)	(1,715		)
	$	(3,332		)	$	(7,193	)	$	(1,536	)

Note 9 - Long-Term Debt

Refer to the Consolidated Statements of Capitalization for detailed information for LG&E’s long-term debt.

As of December 31, 2004, long-term debt and the current portion of long-term debt consists primarily of pollution control bonds and long-term loans from affiliated companies as summarized below.  Interest rates and maturities in the table below reflect the impact of interest rate swaps.

		Weighted
		Average
	Stated	Interest			Principal
(in thousands)	Interest Rates	Rate		Maturities	Amounts
Outstanding at December 31, 2004:
Noncurrent portion	Variable - 5.90%	4.39	%	2008-2033	$	574,354
Current portion	Variable	1.96	%	2005-2027	297,450
Outstanding at December 31, 2003:
Noncurrent portion	Variable - 5.90%	4.23	%	2027-2033	$	550,604
Current portion	Variable	1.46	%	2017-2027	247,450

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 Consolidated Balance Sheets.  The average annualized interest rate for these bonds during 2004 was 1.29%.

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 December 31, 2004 or 2003.

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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, 2004 and 2003, LG&E had swaps with a combined notional value of $228.3 million.  See Note 4. 

In January 2004, LG&E entered into one long-term loan from Fidelia totaling $25 million with an interest rate of 4.33% that matures in January 2012.  The loan is collateralized by a pledge of substantially all assets of LG&E that is subordinated to the first mortgage bond lien. The proceeds were used to repay amounts due under the accounts receivable securitization program. 

In November 2003, LG&E issued $128 million variable-rate pollution control bonds due October 1, 2033, and exercised its call option on the $102 million, 5.625% pollution control bonds due August 15, 2019 and on the $26 million, 5.45% pollution control bonds due October 15, 2020.

LG&E’s first mortgage bond, 6% Series of $42.6 million, matured in August 2003 and was retired. 

During 2003, LG&E entered into two long-term loans from Fidelia totaling $200 million (see Note 14).  Of this total, $100 million is unsecured with an interest rate of 4.55% and matures in April 2013.  The remaining $100 million is collateralized by a pledge of substantially all assets of LG&E that is subordinated to the first mortgage bond lien, has an interest rate of 5.31% and matures in August 2013.  The second lien applies to substantially all assets of LG&E. 

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, 2004 and 2003, leaving 225,000 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. 

See Note 11, Commitments and Contingencies for all long-term debt maturities.

Note 10 - Notes Payable and Other Short-Term Obligations

LG&E participates in an intercompany money pool agreement wherein LG&E Energy and/or KU make funds available to LG&E at market-based rates (based on an index of highly rated commercial paper issues as of the prior month end) up to $400 million.  The balance of the money pool loan from LG&E Energy (shown as “Notes payable to affiliated company”) was $58.2 million at an average rate of 2.22% and $80.3 million at an average rate of 1.00%, at December 31, 2004 and 2003, respectively.  The amount available to LG&E under the money pool agreement at December 31, 2004 was $341.8 million.  LG&E Energy maintains a revolving credit facility totaling $150 million with an affiliate to ensure funding availability for the money pool.  The outstanding balance under LG&E Energy’s facility as of December 31, 2004 was $65.4 million, and availability of $84.6 million remained.  LG&E Energy increased the size of its revolving credit facility to $200 million effective January 24, 2005.

During June 2004, LG&E renewed five revolving lines of credit with banks totaling $185 million.  These credit facilities expire in June 2005, and there was no outstanding balance under any of these facilities at December 31, 2004. 

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The covenants under these revolving lines of credit include:

1.The debt/total capitalization ratio must be less than 70%,

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

3.The corporate credit rating of the company must be at or above BBB- and Baa3, and

4.A limitation on disposing of assets aggregating more than 15% of total assets as of December 31, 2003.

In January 2004, LG&E entered into a one year loan totaling $100 million with Fidelia.  The interest rate on the loan is 1.53%, and the proceeds were used to repay notes payable to LG&E Energy under the money pool arrangement.  The loan is collateralized by a pledge of substantially all assets of LG&E that is subordinated to the first mortgage bond lien.  A prepayment of $50 million was made in 2004 and the remaining $50 million was paid at maturity in January 2005.

Note 11 - Commitments and Contingencies

The following is provided to summarize LG&E’s contractual cash obligations for periods after December 31, 2004.  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 Consolidated Statements of Capitalization).

(in thousands)	Payments Due by Period
Contractual Cash Obligations	2005		2006		2007		2008		2009		Thereafter			Total
Short-term debt (a)	$	58,220	$	—	$	—	$	—	$	—	$	—		$	58,220
Long-term debt	297,450		1,250		1,250		18,750		—		553,104		(b)	871,804
Operating lease (c)	3,469		3,538		3,609		3,681		3,754		22,375			40,426
Unconditional power purchase obligations (d)	11,230		10,098		9,726		9,932		10,145		181,089			232,220
Coal and gas purchase obligations (e)	202,450		95,478		52,656		49,396		6,037		6,037			412,054
Retirement obligations (f)	9,250		10,106		13,305		10,992		15,839		—			59,492
Other long-term obligations (g)	14,767		—		—		—		—		—			14,767
Total contractual cash obligations	$	596,836	$	120,470	$	80,546	$	92,751	$	35,775	$	762,605		$	1,688,983

(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 2005.

(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 contributions to pension plans and other post-employment benefit obligations as calculated by the actuary.

(g)Represents construction commitments.

Operating Leases.  LG&E leases office space, office equipment and vehicles.  LG&E accounts for its leases as operating leases.  Total lease expense for 2004, 2003 and 2002, less amounts contributed by affiliated companies occupying a portion of the office space leased by LG&E, was $2.8 million, $2.2 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, 2004, are in the Contractual Cash Obligations table above.

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

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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, 2004, the maximum aggregate amount of default fees or amounts, which decrease over the term of the lease, was $9.5 million, of which LG&E would be responsible for $3.6 million (38%).  LG&E has made arrangements with LG&E Energy, via guarantee and regulatory commitment, for LG&E Energy to pay its 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.  Through March 2006, LG&E’s entitlement is 7% of OVEC’s generation capacity or approximately 155 Mw, and 5.63% thereafter.

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%. 

Construction Program.  LG&E had approximately $14.8 million of commitments in connection with its construction program at December 31, 2004.  Construction expenditures for the years 2005 and 2006 are estimated to total approximately $268 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 NOx emission requirements of the 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,

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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 controls project commenced in late 2000 with the controls being placed into operation prior to the 2004 Summer Ozone Season. As of December 31, 2004, LG&E incurred total capital costs of approximately $186 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.

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, measures to implement EPA’s regional haze rule, EPA’s Clean Air Mercury Rule which regulates mercury emissions from steam electric generating units and reductions in emissions of SO₂ and NOx required under the Clean Air Interstate Rule.  In addition, LG&E has worked with local regulatory authorities to review the effectiveness of remedial measures aimed at controlling particulate matter emissions from its Mill Creek Station.  LG&E previously settled a number of property damage claims from adjacent residents and completed significant remedial measures as part of its ongoing capital construction program. LG&E has converted the Mill Creek Station to a wet stack operation in an effort to resolve all outstanding issues related to particulate matter emissions.

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 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, 2004 and 2003.

Note 12 - 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.

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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 thousands)
Cost	$	597,433
Accumulated depreciation	207,022
Net book value	$	390,411
Construction work in progress (included above)	$	4,378

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

(in thousands)		LG&E			KU			Total
Paddy’s Run 13	Ownership %	53		%	47		%	100		%
	Mw capacity	84			74			158
	Cost	$	34,033		$	30,038		$	64,071
	Depreciation	4,042			3,555			7,597
	Net book value	$	29,991		$	26,483		$	56,474
E.W. Brown 5	Ownership %	53		%	47		%	100		%
	Mw capacity	62			55			117
	Cost	$	23,978		$	20,221		$	44,199
	Depreciation	2,712			2,269			4,981
	Net book value	$	21,266		$	17,952		$	39,218
E.W. Brown 6	Ownership %	38		%	62		%	100		%
	Mw capacity	59			95			154
	Cost	$	25,353		$	38,935		$	64,288
	Depreciation	3,426			6,644			10,070
	Net book value	$	21,927		$	32,291		$	54,218
E.W. Brown 7	Ownership %	38		%	62		%	100		%
	Mw capacity	59			95			154
	Cost	$	22,718		$	36,137		$	58,855
	Depreciation	5,679			7,012			12,691
	Net book value	$	17,039		$	29,125		$	46,164
Trimble 5	Ownership %	29		%	71		%	100		%
	Mw capacity	46			114			160
	Cost	$	16,241		$	39,665		$	55,906
	Depreciation	1,363			3,327			4,690
	Net book value	$	14,878		$	36,338		$	51,216
Trimble 6	Ownership %	29		%	71		%	100		%
	Mw capacity	46			114			160
	Cost	$	16,205		$	39,703		$	55,908
	Depreciation	1,361			3,332			4,693
	Net book value	$	14,844		$	36,371		$	51,215

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Trimble 7	Ownership %	37		%	63		%	100		%
	Mw capacity	59			101			160
	Cost	$	19,274		$	32,913		$	52,187
	Depreciation	355			606			961
	Net book value	$	18,919		$	32,307		$	51,226
Trimble 8	Ownership %	37		%	63		%	100		%
	Mw capacity	59			101			160
	Cost	$	19,161		$	32,762		$	51,923
	Depreciation	353			604			957
	Net book value	$	18,808		$	32,158		$	50,966
Trimble 9	Ownership %	37		%	63		%	100		%
	Mw capacity	59			101			160
	Cost	$	19,195		$	32,835		$	52,030
	Depreciation	299			512			811
	Net book value	$	18,896		$	32,323		$	51,219
Trimble 10	Ownership %	37		%	63		%	100		%
	Mw capacity	59			101			160
	Cost	$	19,141		$	32,802		$	51,943
	Depreciation	298			511			809
	Net book value	$	18,843		$	32,291		$	51,134
Trimble CT Pipeline	Ownership %	29		%	71		%	100		%
	Cost	$	1,978		$	4,813		$	6,791
	Depreciation	165			403			568
	Net book value	$	1,813		$	4,410		$	6,223
Trimble CT Substation	Ownership %	29		%	71		%	100		%
5 & 6	Cost	$	1,474		$	3,598		$	5,072
	Depreciation	76			196			272
	Net book value	$	1,398		$	3,402		$	4,800
Trimble CT Substation	Ownership %	37		%	63		%	100		%
7 - 10	Cost	$	2,856		$	4,711		$	7,567
	Depreciation	30			53			83
	Net book value	$	2,826		$	4,658		$	7,484

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.

Note 13 - 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 gas financial information separately with the Kentucky Commission.  The Kentucky Commission establishes rates specifically for the electric and gas businesses.  Therefore, management reports and analyzes financial

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performance based on the electric and gas segments of the business.  Financial data for business segments follow:

(in thousands)	Electric		Gas		Total
2004
Operating revenues	$	815,697	$	357,071	$	1,172,768
Depreciation and amortization	99,971		16,606		116,577
Income taxes	48,296		4,998		53,294
Interest income	223		31		254
Interest expense	27,320		5,467		32,787
Net income	87,249		8,369		95,618
Total assets	2,416,500		550,052		2,966,552
Construction expenditures	113,382		34,924		148,306
2003
Operating revenues	$	768,188	$	325,333	$	1,093,521
Depreciation and amortization	96,486		16,801		113,287
Income taxes	44,692		5,381		50,073
Interest income	27		4		31
Interest expense	25,694		4,953		30,647
Net income	80,612		10,227		90,839
Total assets	2,338,938		543,144		2,882,082
Construction expenditures	177,961		34,996		212,957
2002
Operating revenues	$	736,042	$	267,693	$	1,003,735
Depreciation and amortization	90,248		15,658		105,906
Income taxes	47,419		5,260		52,679
Interest income	381		76		457
Interest expense	24,837		4,968		29,805
Net income	79,246		9,683		88,929
Total assets	2,276,712		492,218		2,768,930
Construction expenditures	195,662		24,754		220,416

Note 14 - Related Party Transactions

LG&E, subsidiaries of LG&E Energy 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 LG&E Energy subsidiaries are eliminated upon consolidation of LG&E Energy. 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 SEC regulations under the PUHCA and the applicable 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 LG&E Energy and Fidelia are presented as separate line items on the balance sheet, as appropriate. The significant related party transactions are disclosed below.

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 and LEM, a subsidiary of LG&E Energy, purchase energy from each other. These sales and purchases are included in the Consolidated Statements of Income as Electric Operating

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Revenues and Purchased Power Operating Expense.  LG&E intercompany electric revenues and purchased power expense for the years ended December 31, 2004, 2003 and 2002 were as follows:

(in thousands)	2004		2003		2002
Electric operating revenues from KU	$	58,687	$	53,747	$	41,480
Electric operating revenues from LEM	374		9,372		9,939
Purchased power from KU	61,743		46,690		33,249
Purchased power from LEM	—		—		913

Interest Charges

LG&E participates in an intercompany money pool agreement wherein LG&E Energy and/or KU make funds available to LG&E at market-based rates (based on an index of highly rated commercial paper issues as of the prior month end) up to $400 million.  The balance of the money pool loan from LG&E Energy (shown as “Notes payable to affiliated company”) was $58.2 million at an average rate of 2.22% and $80.3 million at an average rate of 1.00%, at December 31, 2004 and 2003, respectively.  The amount available to LG&E under the money pool agreement at December 31, 2004 was $341.8 million.  LG&E Energy maintains a revolving credit facility totaling $150 million with an affiliate to ensure funding availability for the money pool.  The outstanding balance under LG&E Energy’s facility as of December 31, 2004 was $65.4 million, and availability of $84.6 million remained.  LG&E Energy increased the size of its revolving credit facility to $200 million effective January 24, 2005.

In addition, in 2003 LG&E began borrowing long-term funds from Fidelia (see Note 9). 

Intercompany agreements do not require interest payments for receivables related to services provided when settled within 30 days.  The only interest income or expense recorded by LG&E relates to its receipt and payment of KU’s portion of off-system sales and purchases.

LG&E’s intercompany interest income and expense for the years ended December 31, 2004, 2003 and 2002 were as follows:

(in thousands)	2004		2003		2002
Interest on money pool loans	$	303	$	1,751	$	2,114
Interest on Fidelia loans	11,895		5,025		—
Interest expense paid to KU	44		8		61
Interest income received from KU	2		6		5

Other Intercompany Billings

LG&E Services provides LG&E with a variety of centralized administrative, management, and support services in accordance with agreements approved by the SEC under PUHCA. These charges include taxes paid by LG&E Energy on behalf of LG&E, labor and burdens of LG&E Services employees performing services for LG&E, and vouchers paid by LG&E 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 certain services to each other and to LG&E Services, in accordance with exceptions granted under PUHCA. 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 LG&E Services relate to information technology-related services provided by LG&E employees, cash received by LG&E Services on behalf of

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LG&E, and services provided by LG&E to other non-regulated businesses which are paid through LG&E Services. 

Intercompany billings to and from LG&E for the years ended December 31, 2004, 2003 and 2002 were as follows:

(in thousands)	2004		2003		2002
LG&E Services billings to LG&E	$	190,351	$	194,394	$	183,100
LG&E billings to KU	59,513		77,166		71,127
KU billings to LG&E	7,188		16,636		11,921
LG&E billings to LG&E Services	12,470		23,743		15,079

Note 15 – Accumulated Other Comprehensive Income

Accumulated other comprehensive income consisted of the following:

	Minimum Pension			Accumulated Derivative						Income
(in thousands)	Liability Adjustment			Gain or Loss			Pre-Tax			Taxes			Net
Balance at December 31, 2001	$	(24,712	)	$	(8,655	)	$	(33,367	)	$	(13,467	)	$	(19,900	)
Minimum pension liability adjustment	(25,999		)	—			(25,999		)	(10,493		)	(15,506		)
Gains (losses) on derivative instruments designated and qualifying as cash flow hedging instruments	—			(8,563		)	(8,563		)	(3,457		)	(5,106		)
Balance at December 31, 2002	(50,711		)	(17,218		)	(67,929		)	(27,417		)	(40,512		)
Minimum pension liability adjustment	3,114			—			3,114			1,257			1,857
Gains (losses) on derivative instruments designated and qualifying as cash flow hedging instruments	—			912			912			368			544
Balance at December 31, 2003	(47,597		)	(16,306		)	(63,903		)	(25,792		)	(38,111		)
Minimum pension liability adjustment	(10,228		)	—			(10,228		)	(4,128		)	(6,100		)
Gains (losses) on derivative instruments designated and qualifying as cash flow hedging instruments	—			(2,346		)	(2,346		)	(947		)	(1,399		)
Balance at December 31, 2004	$	(57,825	)	$	(18,652	)	$	(76,477	)	$	(30,867	)	$	(45,610	)

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Note 16 - Selected Quarterly Data (Unaudited)

Selected financial data for the four quarters of 2004 and 2003 are shown below.  Because of seasonal fluctuations in temperature and other factors, results for quarters may fluctuate throughout the year.

	Quarters Ended
(in thousands)	March		June		September		December
2004
Operating revenues	$	361,963	$	236,211	$	261,842	$	312,752
Net operating income	47,623		34,592		62,830		39,986
Net income	24,219		17,139		32,538		21,722
2003
Operating revenues	$	326,844	$	215,373	$	262,833	$	288,471
Net operating income	49,831		21,004		71,387		36,530
Net income	27,264		7,755		39,871		15,949

Effective December 31, 2004, operating and non-operating income taxes are presented as “Federal and State Income Taxes” on LG&E’s Consolidated Statements of Income.  Prior to December 31, 2004, the component of income taxes associated with operating income was included in net operating income and the component of income taxes associated with non-operating income taxes was included in other income (expense) – net.  LG&E has applied this change in presentation to all prior periods.

	Quarters Ended
(in thousands)	March		June		September		December
2004
Net operating income as previously reported	$	32,598	$	25,219	$	41,741
Plus income taxes reclassified from total operating expenses	15,025		9,373		21,089
Net operating income	$	47,623	$	34,592	$	62,830
2003
Net operating income as previously reported	$	33,190	$	16,290	$	47,680	$	25,525
Plus income taxes reclassified from total operating expenses	16,641		4,714		23,707		11,005
Net operating income	$	49,831	$	21,004	$	71,387	$	36,530

As the result of EITF No. 02-03, LG&E has netted the power purchased expense for trading activities against electric operating revenue.  LG&E applied this guidance to all prior periods beginning with the June 2003 10-Q filing, which had no impact on previously reported net income or common equity (See Note 1).

	Quarter Ended
(in thousands)	March 31, 2003
Gross operating revenues as previously reported	$	335,117
Less costs reclassified from power purchased	8,273
Net operating revenues	$	326,844

Note 17 - Subsequent Events

In January 2005, LG&E paid at maturity the $50 million loan from Fidelia using proceeds from short-term loans from the money pool.

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 will be 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

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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.  The Kentucky Commission must provide its Strategic Blueprint to the Governor in early August 2005.  LG&E must respond to the Kentucky Commission’s first set of data requests by the end of March 2005.

LG&E purchased from AEP an additional 0.73% interest in OVEC for a purchase price of approximately $0.1 million, resulting in an increase in LG&E ownership in OVEC from 4.9% to 5.63%.  The parties completed the share purchase transaction during March 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.  The impact of these reduced rates is expected to decrease LG&E’s income tax expense in future periods.  Furthermore, these reduced rates will result in the reversal of accumulated temporary differences at lower rates than originally provided.  LG&E is presently evaluating the impact of this and other changes to the Kentucky tax system, however, no material adverse impacts on cash flows or results of operations are expected.

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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, 2004 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, 2004, 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 its first periodic report covering the fiscal year ended December 31, 2006 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 auditors, internal auditors and management.  The Board of Directors reviews the results of the independent auditors’ 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

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Louisville Gas and Electric Company and Subsidiary

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders of Louisville Gas and Electric Company and Subsidiary:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements 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 and Subsidiary at December 31, 2004 and December 31, 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America.  In addition, in our opinion, based on our audits, the financial statement schedule as of and for the three years in the period ended December 31, 2004, listed in the index appearing under Item 15(a)(2), presents fairly in all material respects, the information set forth therein when read in conjunction with the related consolidatedfinancial statements.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.  We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2003, Louisville Gas and Electric Company and Subsidiary adopted EITF No. 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. 

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2003, Louisville Gas and Electric Company and Subsidiary adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.

As discussed in Note 1 to the consolidated financial statements, effective July 1, 2003, Louisville Gas and Electric Company and Subsidiary adopted Statement of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.

/s/ PricewaterhouseCoopers LLP

Louisville, Kentucky

February 4, 2005

80

Admission Ticket

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Louisville Gas and Electric Company

Louisville Gas and Electric

MMMMMMMMMMMM

Annual Meeting of Shareholders

Company

000000000.000 ext

Tuesday, June 21, 2005

000000000.000 ext

2:00 p.m., Louisville time

MR A SAMPLE

000000000.000 ext

Twelfth Floor Assembly Room

DESIGNATION (IF ANY)

000000000.000 ext

LG&E Building

ADD 1

000000000.000 ext

220 West Main Street

ADD 2

000000000.000 ext

Louisville, Kentucky

ADD 3

000000000.000 ext

ADD 4

If you plan to attend the meeting, please check the box on the proxy card

ADD 5

indicating  that you plan to attend. Please bring this Admission Ticket to the

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C 1234567890

J N T

meeting with you.

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Each proposal is fully explained in the enclosed Notice of Annual Meeting of

Shareholders and Proxy Statement. To vote your proxy, please MARK by placing

an “X” in the appropriate box. SIGN and DATE this proxy. Then please DETACH

and RETURN the completed proxy promptly in the enclosed envelope.

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Mark this box with an X if you

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have made changes to your

Building Garage off Market Street and The Actors Theatre Garage off Main Street.

name or  address details above.

Please visit the registration table at the annual meeting for a parking voucher,

which you should submit with your parking ticket to the attendant upon leaving.

Annual Meeting Proxy Card

A

Election of Directors for terms expiring in 2006

1.

The Board of Directors recommends a vote “FOR” the listed nominees.

For

Withhold

01 - Victor A. Staffieri

o

o

02 - John R. McCall

o

o

03 - S. Bradford Rives

o

o

04 - Paul W. Thompson

o

o

05 - Chris Hermann

o

o

B

Issues

The Board of Directors recommends a vote “FOR” the following proposals.

For

Against

Abstain

2.

Approval of

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o

o

I plan to attend the

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PricewaterhouseCoopers

Annual Meeting.

LLP as Independent

Registered Public

I will bring the

Accounting Firm

indicated number of

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guests to the annual

meeting.

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Authorized Signatures - Sign Here - This section must be completed for your instructions to be executed.

Signature(s) should correspond to the name(s) appearing in this proxy. If executor, trustee, guardian, etc. please indicate.

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00FOMA

Proxy - Louisville Gas and Electric Company

Annual Meeting of Shareholders

June 21, 2005

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 June 21, 2005 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.