Louisville Gas & Electric DEF 14A Definitive proxy

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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 25, 2004

Dear Louisville Gas and Electric Company Shareholder:

You are cordially invited to attend the Annual Meeting of Shareholders of Louisville Gas and Electric Company ("LG&E") to be held on Thursday, July 8, 2004 at 3:00 p.m., local time in the Twelfth Floor Assembly 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 three directors, (ii) the approval of PricewaterhouseCoopers LLP as independent auditors of the Company for 2004 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 Assembly Room at the LG&E Building, Third and Main Streets, Louisville, Kentucky, on Thursday July 8, 2004, at 3:00 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 three directors for terms expiring in 2005;
2.: A proposal to approve and ratify the appointment of PricewaterhouseCoopers LLP as independent auditors of LG&E for 2004; and
3.: Such other business as may properly come before the meeting.

The close of business on May 3, 2004 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 25, 2004

PROXY STATEMENT

ANNUAL MEETING OF SHAREHOLDERS TO BE HELD JULY 8, 2004

The Board of Directors of Louisville Gas and Electric Company ("LG&E" or the "Company") hereby solicits your proxy, and asks that you vote, sign, date and promptly mail the enclosed proxy card for use at the Annual Meeting of Shareholders to be held July 8, 2004, and at any adjournment of such meeting. The meeting will be held in the Twelfth Floor Assembly 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 25, 2004.

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 May 3, 2004, the record date for the Annual Meeting, the following shares of four series 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		237,500 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 May 3, 2004, 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 E.ON AG shares, the ultimate parent company 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"), for cash of approximately$3.2 billion, or$24.85 per share of LG&E Energy Corp. common stock. 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.

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 May 3, 2004 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 shareholder 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 auditors 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.

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 auditors for LG&E. Nonetheless, the Board encourages you to vote on each of these matters, and appreciates your interest.

The Louisville Gas and Electric Company 2003 Financial Report, containing audited financial statements of LG&E and management's discussion of such financial statements, is included with this proxy statement (the "Financial Report"), and is incorporated by reference herein. All shareholders are urged to read the accompanying Financial Report.

PROPOSAL NO. 1

ELECTION OF DIRECTORS

The number of members of the Board of Directors of LG&E is currently fixed at three, 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.

Effective July 1, 2002, in connection with the completion of the E.ON-Powergen acquisition, Sir Frederick Crawford, Dr. David K-P Li and Messrs. Nicholas P. Baldwin, Sydney Gillibrand and David J. Jackson resigned as directors of LG&E. Messrs. Victor A. Staffieri and Edmund A. Wallis continued as directors and Mr. Michael Söhlke was appointed to fill a vacancy. Effective June 18, 2003, Edmund A. Wallis tendered his resignation, resulting in a Board of two persons. On November 3, 2003, Dr. Hans Michael Gaul was appointed to fill this vacancy and Messrs. John R. McCall and S. Bradford Rives were also appointed directors. Messrs. McCall and Rives tendered their resignations in November 2003. At the 2003 Annual Meeting held on December 16, 2003, LG&E's shareholders approved amendments previously recommended by the Board which reduced the required number of directors from nine to three and eliminated staggered terms for directors.

Effective January 31, 2004, Dr. Gaul and Mr. Söhlke resigned from the Board of LG&E and Messrs. McCall and Rives were appointed to fill the vacancies created thereby.

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

For one-year terms expiring at the 2005 Annual Meeting: Victor A. Staffieri, John R. McCall and S. Bradford Rives.

Messrs. Staffieri, McCall and Rives are presently also directors 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 THREE NOMINEES FOR DIRECTOR.

INFORMATION ABOUT DIRECTORS AND NOMINEES

The following contains certain information concerning the nominees for director:

Nominees for Directors with Terms Expiring at the 2005 Annual Meeting of Shareholders

Victor A. Staffieri(Age 49): 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, May 1997 to February 2000; Chief Financial Officer of KU, May 1998 to February 2000. President, Distribution Services Division of LG&E Energy, December 1995 to May 1997; 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 of Powergen from April 2001 until January 2004.

John R. McCall(Age 60): 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 and KU since January 2004.

S. Bradford Rives(Age 45): 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 and KU since January 2004.

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 2003, there were a total of 18 meetings or consents of the LG&E and KU Boards. All directors attended 75% or more of the total number of meetings or consents of the Board of Directors and committees of the Board on which they served.

Compensation of Directors

Directors who are also officers or employees of E.ON, Powergen, LG&E Energy or their subsidiaries receive no compensation in their capacities as directors of LG&E or KU.

Committees

There are currently no committees of the Board of Directors of LG&E. Due to the small Board size of three members, the Board as a whole performs the functions related to 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, currently Dr. Stefan Vogg.

Audit and Auditor Matters

Due to the small size of the LG&E Board, the Board as a whole performs the functions 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 2003, the Board maintained direct and indirect contact with the independent auditors and LG&E's internal Audit Services to review the following matters pertaining to LG&E: 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 auditors deemed necessary. A report of the Board acting as Audit Committee is included in the "Report of 2003 Audit Committee" section of this document. A copy of the charter applicable to the Board acting as Audit Committee is attached as Appendix A hereto.

The Board is responsible for approving all audit and permissible non-audit services to be provided by the independent auditors 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 auditor. 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 AG 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 its voting stock, the Board has determined that it is appropriate not to have a standing nominating committee, nominating committee charter or policy regarding consideration of candidates for director, including shareholder nominees. The full Board, with input from E.ON officers, selects director nominees. All members of the Board 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.

PROPOSAL NO. 2

APPROVAL OF INDEPENDENT AUDITORS FOR 2004

The Board of Directors, subject to ratification by shareholders, has selected PricewaterhouseCoopers LLP as independent auditors to audit the accounts of LG&E for the fiscal year ending December 31, 2004. 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 has audited the accounts of E.ON and Powergen for many years. PricewaterhouseCoopers 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 independent auditors, 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 auditors is assured.

THE BOARD OF DIRECTORS RECOMMENDS THAT YOU VOTE "FOR" THE APPROVAL OF THE APPOINTMENT OF THE INDEPENDENT AUDITORS.

REPORT REGARDING REMUNERATION

Following the July 1, 2002 completion of E.ON's acquisition of Powergen, the Remuneration Committee of the Boards of Directors of LG&E and KU 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, currently Dr. Stefan Vogg. This report describes the compensation policies applicable to LG&E's executive officers for the last completed fiscal year.

Prior to 2003, Dr. Vogg, in consultation with certain officers of E.ON, Powergen, 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 2003, 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 continued 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 2003 for its officers, including the executive officers named in the following tables. In many cases, the executive officers also serve in similar capacities for affiliates of LG&E, including 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, KU and their affiliates, during the relevant period.

Compensation Philosophy

During 2003, LG&E's executive compensation program had three major components: (1) base salary; (2) short-term or annual incentives; and (3) long-term incentives. This executive compensation program was developed 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 2003, 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 2003 to generally approach the 50th percentile of the competitive range from the Survey Group. Salaries, short-term incentives and long-term incentives for 2003 are described below. (The utilities and utility holding companies that

were in the Survey Group were not necessarily the same as those in the Dow Jones Utility Average used in the Company Performance Graph in this proxy statement.)

The 2003 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 2003 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 2003 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 2003 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 internal operating profit targets and LG&E/KU internal operating profit 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 2003, the Company Performance Award targets for named executive officers ranged from 29% to 42% of base salary, and the Individual Performance Award targets ranged from 20% to 28% 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, Powergen, LG&E Energy, LG&E/KU and other subsidiaries' performance against goals in 2003 and making adjustments for certain foreign currency rate effects, the Compensation Group determined relative annual performance against targets for Company Performance Awards. Based upon this determination, Company Performance Awards for 2003 to the named executive officers were paid ranging from 119% to 159% of target and 36% to 67% of base salary. Based on determinations of management effectiveness, payouts for Individual Performance Awards to the named executive officers ranged from 150% to 165% of target and 30% to 48% 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 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 2003, 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. 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 2003 grants of SAR's was substantially dependent upon the changing value of E.ON shares in the marketplace.

No SAR's were exercisable during 2003 as the two year vesting requirements had not been completed. No regular payouts of performance units under the Long-Term Plan occurred during 2003 as the three-year performance periods had not been completed.

Other

In connection with the E.ON-Powergen merger, Messrs. Staffieri and McCall entered into amendments to their employment and severance agreements and the other named officers entered into new retention and severance agreements.

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 the Companies or Mr. Staffieri give notice of non-renewal.

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. In the first quarter of 2003, the Compensation Group established Mr. Staffieri's compensation 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 2003 compensation are set forth below.

Base Salary. Mr. Staffieri was paid a total base salary of$648,902 during 2003, pursuant to the 2000 Agreement, as amended. The Compensation Group, in determining Mr. Staffieri's 2003 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 2003 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 2003 short-term incentive payouts were based 60% on

achievement of Company Performance Award targets and 40% on achievement of Individual Performance Award targets.

For 2003, the Company Performance Award payout for Mr. Staffieri was 158% of target and 67% of his 2003 base salary and the Individual Performance Award payout was 170% of target and 48% of his 2003 base salary. Mr. Staffieri's Company Performance Award was based on LG&E Energy internal operating profit. His 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 2003, Mr. Staffieri received 851,681 performance units for the 2003-2005 performance period under the Long-Term Plan and 25,282 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. As with other executive officers, no SAR's were exercisable by Mr. Staffieri during 2003 as the two year vesting requirements had not been completed. As with other executive officers, no regular payouts of performance units under the Long-Term Plan occurred during 2003 as the three-year performance periods had not been completed.

Other. In 2003, Mr. Staffieri also received a bonus in connection with a 2002 amendment to his employment and severance agreement in the amount of $837,375, including interest.

Members of LG&E's Board of Directors

Victor A. Staffieri
John R. McCall
S. Bradford Rives

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 2003, 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 from December 31, 1998, through December 31, 2003, 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, 1998, with reinvestment of dividends.

¹: While 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.

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, 2003, as required, in all capacities in which they served LG&E, KU, LG&E Energy or its subsidiaries during 2001, 2002 and 2003:

SUMMARY COMPENSATION TABLE

						Long-Term Compensation
	Annual Compensation					Awards
	Annual Compensation					Awards	Payouts
				Other Annual Comp. ($)		Restricted Stock Awards ($)	Payouts		All Other Compen- sation ($)
Name and Principal Position	Year	Salary ($)	Bonus ($)	Other Annual Comp. ($)		Restricted Stock Awards ($)	Securities Underlying Options/SAR (#)(1)	LTIP Payouts ($)(2)	All Other Compen- sation ($)
Victor A. Staffieri Chairman of the Board, President and Chief Executive Officer	2003 2002 2001	648,902 630,001 555,769	741,340 650,101 529,330	39,461 24,282 45,704		— — —	25,282 6,250 51,011	0 1,483,377 0	902,945 2,433,735 1,811,703	(3) (4) (5)
John R. McCall Executive Vice President, General Counsel and Corporate Secretary	2003 2002 2001	389,475 363,975 383,365	313,933 251,543 242,104	198,681 144,756 8,732	(6) (6)	— — —	8,671 3,611 14,786	0 401,580 0	47,529 1,390,557 463,793	(3) (4) (5)
S. Bradford Rives Chief Financial Officer	2003 2002 2001	305,495 280,019 235,000	243,607 180,145 131,342	6,880 6,616 6,595		— — —	5,345 2,877 7,554	0 204,450 0	423,923 486,491 390,335	(3) (4) (5)
Paul W. Thompson Senior Vice President— Energy Services	2003 2002 2001	269,071 262,497 245,193	187,526 147,944 142,650	7,232 8,106 9,970		— — —	4,792 2,604 10,714	0 290,000 0	10,151 440,486 436,152	(3) (4) (5)
Chris Hermann Senior Vice President Energy Delivery	2003 2002 2001	252,928 246,748 234,999	166,267 129,505 131,342	4,905 7,892 12,122		— — —	3,378 2,448 7,554	0 204,450 0	22,463 228,722 13,996	(3) (4) (5)

(1): Amounts for years 2003 and 2002 reflect E.ON SAR Plan grants. Amounts for year 2001 reflect options for Powergen ADS's.
(2): No payouts were made under the Long-Term Plan during years 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 2003 as follows: Mr. Staffieri $6,000, $32,970, $26,600, $0 and $837,375, respectively; Mr. McCall $5,775, $13,680, $20,583, $7,491 and $0, respectively; Mr. Rives $3,229, $11,478, $1,042, $4,618 and $403,556, respectively; Mr. Thompson, $2,688, $5,384, $2,078, $0 and $0, respectively; and Mr. Hermann, $5,732, $5,886, 5,981, $4,864 and $0, respectively. The retention payments above are discussed in the "Report Regarding Remuneration" and "Employment Contracts and Termination of Employment Arrangements and Change in Control Provisions".

(4): 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.
(5): Includes retention payments in 2001 as follows: Mr. Staffieri, $1,719,884; Mr. McCall, $423,524; Mr. Rives, $382,393; Mr. Thompson, $405,860; and Mr. Hermann, $0, 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 2003 Fiscal Year

The following table contains information at December 31, 2003, 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/SARs Granted (#)(1)	Percent of Total Options/SARs Granted to Employees in Fiscal Year(2)			Potential Realizable Value At Assumed Annual Rates of Stock Price Appreciation For Option Term
				Exercise Or Base Price ($/Share)
Name				Exercise Or Base Price ($/Share)	Expiration Date	0%($)	5%($)	10%($)
Victor A. Staffieri	25,282	36.1	%	43.99	12/31/2009	0	452,759	1,055,121
John R. McCall	8,671	12.4	%	43.99	12/31/2009	0	155,283	361,876
S. Bradford Rives	5,345	7.6	%	43.99	12/31/2009	0	95,720	223,069
Paul W. Thompson	4,792	6.9	%	43.99	12/31/2009	0	85,817	199,990
Chris Hermann	3,378	4.8	%	43.99	12/31/2009	0	60,494	140,978

(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 employees only.

OPTION/SAR EXERCISES AND YEAR-END VALUE TABLE
Aggregated Option/SAR Exercises in 2003 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, 2003:

Name	Number of Securities Underlying Unexercised Options/SARs at FY-End (#)(2) Exercisable/Unexercisable	Value of Unexercised In-The-Money Options/SARs at FY-End ($) Exercisable/Unexercisable
Victor A. Staffieri	0/31,532	0/$	640,924
John R. McCall	0/12,282	0/$	242,975
S. Bradford Rives	0/8,222	0/$	160,049
Paul W. Thompson	0/7,396	0/$	143,880
Chris Hermann	0/5,826	0/$	111,088

(1): Amounts shown are E.ON SAR's. At December 31, 2003, no E.ON SAR's were exercisable due to the two year vesting period from their 2002 or 2003 grant dates.

LONG-TERM INCENTIVE PLAN AWARDS TABLE
Long-Term Incentive Plan Awards in 2003 Fiscal Year

The following table provides information concerning awards of performance units made in 2003 to the named executive officers under the Powergen Long-Term Plan.

	Number of Shares, Units or Other Rights(1)	Performance or Other Period Until Maturation Or Payout	Estimated Future Payouts Under Non-Stock Price Based Plans (number of shares)(1)
Name	Number of Shares, Units or Other Rights(1)	Performance or Other Period Until Maturation Or Payout	Threshold(#)	Target(#)	Maximum(#)
Victor A. Staffieri	851,681	12/31/2005	425,841	851,681	1,277,522
John R. McCall	292,106	12/31/2005	146,053	292,106	438,159
S. Bradford Rives	180,090	12/31/2005	90,045	180,090	270,135
Paul W. Thompson	161,445	12/31/2005	80,723	161,445	242,168
Chris Hermann	113,816	12/31/2005	56,908	113,816	170,724

(1): Amounts shown are awards of performance units under the Long-Term Plan during 2003.

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 the company performance over a three year cycle. For awards made in 2003, 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.

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:

2003 PENSION PLAN TABLE

		Years of Service
Remuneration		15		20		25		30 or more
$	100,000	$	43,348	$	43,348	$	43,348	$	43,348
$	200,000	$	107,348	$	107,348	$	107,348	$	107,348
$	300,000	$	171,348	$	171,348	$	171,348	$	171,348
$	400,000	$	235,348	$	235,348	$	235,348	$	235,348
$	500,000	$	299,348	$	299,348	$	299,348	$	299,348
$	600,000	$	363,348	$	363,348	$	363,348	$	363,348
$	700,000	$	427,348	$	427,348	$	427,348	$	427,348
$	800,000	$	491,348	$	491,348	$	491,348	$	491,348
$	900,000	$	555,348	$	555,348	$	555,348	$	555,348
$	1,000,000	$	619,348	$	619,348	$	619,348	$	619,348
$	1,100,000	$	683,348	$	683,348	$	683,348	$	683,348
$	1,200,000	$	747,348	$	747,348	$	747,348	$	747,348
$	1,300,000	$	811,348	$	811,348	$	811,348	$	811,348
$	1,400,000	$	875,348	$	875,348	$	875,348	$	875,348
$	1,500,000	$	939,348	$	939,348	$	939,348	$	939,348
$	1,600,000	$	1,003,348	$	1,003,348	$	1,003,348	$	1,003,348
$	1,700,000	$	1,067,348	$	1,067,348	$	1,067,348	$	1,067,348
$	1,800,000	$	1,131,348	$	1,131,348	$	1,131,348	$	1,131,348
$	1,900,000	$	1,195,348	$	1,195,348	$	1,195,348	$	1,195,348

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, 2003 was as follows: 11 years for Mr. Staffieri; 9 years for Mr. McCall; 20 years for Mr. Rives; 12 years for Mr. Thompson; and 33 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$160,000 per year. Officers of LG&E Energy, LG&E and KU with at least one year of service with an affiliated 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$160,000 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.

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 $702,523 for Mr. Staffieri; $344,984 for Mr. McCall; $251,425 for Mr. Rives; $241,419 for Mr. Thompson; and $208,324 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. 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 in 2003, as described in the Report Regarding Remuneration and the Summary Compensation Table.

Under the terms of his revised employment and severance agreement, Mr. Staffieri is entitled to additional retention payments 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 will initially be credited into a deferred compensation account and which will then be payable in a lump sum in cash, if Mr. Staffieri elects, upon (i) a termination of employment (other than by Mr. Staffieri without good reason), (ii) a change in control within 30 months of the E.ON-Powergen merger, or (iii) the respective first year, second year and thirty month anniversaries of the E.ON-Powergen merger, if Mr. Staffieri is still employed. 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, if Mr. McCall is (a) employed by LG&E Energy or LG&E or any of their affiliates on July 1, 2004 or (b) terminated prior to July 1, 2004 for any reason other than by the employer for cause or by Mr. McCall without good reason; then in each case Mr. McCall is entitled to receive 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, or, if within 48 months of the date of the E.ON-Powergen merger, 2.99 times the sum of (1) and (2).

In 2003, Mr. Rives became entitled to receive a scheduled retention payment of $355,078, plus interest, pursuant to the terms his retention agreement entered into at the time of the Powergen-LG&E Energy merger. During 2002, in connection with the E.ON-Powergen merger, Messrs. Thompson, Rives and Hermann entered into new retention agreements under which these officers will be 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. Messrs. Thompson, Rives and Hermann have also entered into change of control agreements with terms of 24 months, 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 other agreements described above, 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 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.

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 2003 AUDIT COMMITTEE MATTERS

The Board of Directors, consisting of three 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 one meeting during 2003.

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, 2003, the Audit Committee reviewed and discussed the audited financial statements and the quality of the financial reporting with management and the independent accountants. It also discussed with the independent accountants 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 accountants 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, 2003, 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, 2002 and December 31, 2003 are as follows: (Certain amounts for 2002 have been reclassified to conform to 2003 presentation.)

		LG&E
		2003		2002
• Audit Fees
	• Audit Fees	$	128,862	$	47,500
	• Regulatory Work	$	4,665		—

	• Total Audit Fees	$	131,527	$	47,500
• Audit Related Fees
	• Pension Plan Audits	$	17,200	$	17,000
	• Comfort Letter Procedures	$	51,154	$	69,270

	• Total Audit Related Fees	$	68,354	$	86,270
• Tax Fees			—		—
• All Other Fees			—		—

2. The Audit Committee considered whether the independent accountant's provision of non-audit services is compatible with maintaining the accountant'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

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. However, due to administrative errors arising from the transition from overseas directors to US-based directors, two reports were filed late or omitted regarding personnel changes in November 2003 and January 2004. All such errors related solely to entry or exit filings for individuals who had no holdings of or transactions in LG&E securities. Except as set forth above, based upon information provided to LG&E and KU by individual directors and officers, LG&E believes that during the year ended December 31, 2003, all filing requirements have otherwise been complied with.

SHAREHOLDER PROPOSALS AND NOMINATIONS

Any shareholder may submit a proposal for consideration at the 2005 Annual Meeting. Any shareholder desiring to submit a proposal for inclusion in the proxy statement for consideration at the 2005 Annual Meeting should forward the proposal so that it will be received at LG&E's principal executive offices no later than February 26, 2005. 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 2005 proxy statement.

Under LG&E's By-laws, shareholders intending to nominate a director for election or submit a proposal in person at the annual meeting must provide advance written notice along with other prescribed information. 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 for a director nominee 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. Proposals not properly submitted will be considered untimely.

SHAREHOLDER COMMUNICATIONS

Shareholders can communicate with our 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 32102, 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 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 three directors were in attendance at the annual meeting in 2003.

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 2003 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.

APPENDIX A

LOUISVILLE GAS AND ELECTRIC COMPANY
AND
KENTUCKY UTILITIES COMPANY

AUDIT COMMITTEE CHARTER

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 financial information provided to shareholders and others, the systems of internal controls which management and the Board of Directors have established and the audit process. 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. 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 and will call special meetings as circumstances require. It will meet privately 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 believes 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.
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.

A-1

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.

7.

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

8.

Approve the annual audit plan 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.

9.

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.

10.

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

11.

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

12.

Review with management and the independent accountant at the completion of the annual audit:

a.: The Company's annual financial statements and related footnotes;
b.: The independent accountant's audit of the financial statements and the report thereon;
c.: The independent accountant's judgment about the quality and appropriateness of the Company's accounting principals as applied to its financial reporting;
d.: Any significant changes required in the independent accountant's audit plan and scope;
e.: Any serious difficulties or disputes with management encountered during the course of the audit; and
f.: Other matters related to the conduct of the audit which are to be communicated to the Committee under generally accepted auditing standards.

13.

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.

14.

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;

A-2

d.: The Audit Services Department staffing and staff qualifications; and
e.: The Audit Services Department charter.

15.: Review with the Director of Audit Services the results of the annual Code of Business Conduct questionnaire.
16.: 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.
17.: Report Committee actions to the Board of Directors with such recommendations as the Committee may deem appropriate.
18.: 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.
19.: 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.

A-3

LOUISVILLE GAS AND ELECTRIC COMPANY

2003 FINANCIAL REPORT

LOUISVILLE GAS AND ELECTRIC COMPANY

2003 FINANCIAL REPORT

TABLE OF CONTENTS

Index of Abbreviations		2
Selected Financial Data		4
Management's Discussion and Analysis		5
Market for the Registrant's Common Equity and Related Stockholder Matters		25
Consolidated Statements of Income		26
Consolidated Statements of Retained Earnings		26
Consolidated Statements of Comprehensive Income		27
Consolidated Balance Sheets		28
Consolidated Statements of Cash Flows		29
Consolidated Statements of Capitalization		30
Notes to Consolidated Financial Statements		31
Report of Management		62
Report of Independent Auditors		63

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
CT		Combustion Turbines
CWIP		Construction Work in Progress
DSM		Demand Side Management
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.
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
S&P		Standard & Poor's Rating Services
SCR		Selective Catalytic Reduction
SEC		Securities and Exchange Commission
SERP		Supplemental Employee 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
TRA		Tennessee Regulatory Authority
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

Louisville Gas and Electric Company and Subsidiary
Selected Financial Data

The 1999 and 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. Arthur Andersen LLP has ceased operations. The amounts shown below for such periods, reclassified pursuant to the adoption of EITF 02-03, are unaudited.

		Years Ended December 31
		2003			2002		2001		2000			1999
		(in thousands)
LG&E:
Operating revenues:
Revenues		$	1,093,933		$	992,079	$	962,959	$	934,204		$	847,879
Provision for rate collections (refunds)			(412	)		11,656		1,588		(2,500	)		(1,735	)

	Total operating revenues	$	1,093,521		$	1,003,735	$	964,547	$	931,704		$	846,144

Net operating income		$	122,685		$	117,914	$	141,773	$	148,870		$	140,091

Net income		$	90,839		$	88,929	$	106,781	$	110,573		$	106,270

Total assets		$	2,888,928		$	2,768,930	$	2,448,354	$	2,226,084		$	2,171,452

Long-term obligations (including amounts due within one year)		$	798,054		$	616,904	$	616,904	$	606,800		$	626,800

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.

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 2003, 2002, and 2001 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

Overview

LG&E continues profitable operations despite national and regional economic weakness and turmoil in the U.S. energy industry. LG&E enjoys a competitive cost advantage relative to the U.S. industry average and high customer satisfaction ratings. During 2003, LG&E and KU (the "Companies") were awarded first place in the region by J.D. Power in the 2003 Residential Customer Satisfaction Survey and a national first place in the Midsize Business Survey.

As a regulated utility, LG&E's financial performance is greatly impacted by regulatory proceedings. In December 2003, LG&E filed an application with the Kentucky Commission requesting an adjustment in LG&E's electric and gas rates. LG&E applied for revenue increases of $63.8 million for electric and $19.1 million for gas. The Kentucky Commission has suspended the effective date of the proposed new tariffs for five months, so that the rates may go into effect subject to refund by July 1, 2004. The Kentucky Commission has established a procedural schedule for the cases pertaining to discovery and hearings. Hearings are scheduled in May 2004. LG&E expects the Kentucky Commission to issue orders in the cases before new rates go into effect July 1, 2004.

In addition, continuance of LG&E's ESM mechanism, which sets an upper and lower point for rate of return on equity and sharing guidelines for returns above or below these thresholds, is being deliberated by the Kentucky Commission. A final order is not expected until the second quarter of 2004. Although the ESM tariff remains in effect pending the resolution of the case, the future operation of the ESM cannot be determined by LG&E.

Major Strategic Goals

LG&E's major strategic goals are to continue to be leading electric and gas utilities by meeting their utility native load and reliability requirements while managing business, environmental and regulatory risks; by maintaining excellent customer service and reputation with all stakeholders; by engaging in continuous improvement to foster efficiency; by securing a foundation for future regulatory support; and, by developing transferable utility best practices business models.

To continue to meet the regulated load growth in Kentucky, LG&E and KU are jointly installing four combustion turbines at Trimble County in time for 2004 peak demand. The installations were authorized by the Kentucky Commission as the least cost alternative to meet Kentucky's needs. Although cost pressures resulted in LG&E filing a rate case in December 2003, prices will remain competitive in the region.

LG&E and KU continue to aggressively move to best practices and capture cost savings. The Companies have reduced headcount by 35% since 1998. They continue to pursue best practice improvements and additional savings initiatives, including limited staffing and management changes.

Current Trends

Although the stock market has rebounded somewhat, industrial energy demand and the employment market remain dampened. Short-term interest rates have fallen to forty-year lows and consensus forecasts continue to

predict gradual economic recovery over time. Natural gas prices have been volatile and have increased significantly, further aggravating the U.S. economy's recovery. Peak wholesale electric prices have risen as a result of gas price increases, even with continued overcapacity in many regions, favoring coal-fired generators like LG&E.

The U.S. energy industry is still in the grips of national regulatory uncertainty and financial turmoil, highlighting the strength of companies with integrated utility operations. Deregulation momentum is stalled or abandoned in most states, with national attention on the economy and international issues. The Kentucky legislature did not take any action in either 2002 or 2003 to move Kentucky towards electric deregulation. 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.

Another area of regulatory uncertainty relates to the MISO. LG&E obtained membership in the MISO in 1998 in response to federal policy initiatives. The Kentucky Commission has formally questioned LG&E's participation in the MISO and initiated a formal case to evaluate the justification of MISO membership. Due to LG&E's membership in MISO, costs have been incurred related to transmission fees and the MISO organization's administrative fees. Additional fees which may be incurred by the MISO members, related to recovery of costs for the congestion management system, are currently being debated by FERC and the members of the MISO. LG&E is attempting to mitigate costs, maintain system reliability, and operate within all applicable laws and regulation. Litigation on federal and state jurisdictional issues appears likely.

Also, the FERC issued a NOPR in July 2002 which would substantially alter the regulations governing the nation's wholesale electricity markets by establishing a common set of rules, defined as SMD. The FERC NOPR has met opposition, even after revision, and implementation is uncertain. Prolonged litigation is likely over any contentious provisions. Low cost states are wary of grid reforms and increased cost burdens. There are still fundamental differences over federal and state jurisdictional issues and prerogatives. Kentucky regulators and political leaders are in the forefront of opposition to broad federal mandates on utility related issues.

National energy legislation and policy continues to be a very divisive area. The U.S. House of Representatives passed the Energy Policy Act in April 2003. The legislation, as passed in the House, included the repeal of PUHCA as well as tax incentives for various energy initiatives. The U.S. Senate Energy and Natural Resources Committee passed its version of energy legislation in April 2003. A conference agreement merging both versions passed in the House in October 2003, but failed to pass in the Senate. Many disputed issues remain and it is unclear whether legislation will pass this year. The impact of legislation on LG&E, which may be significant, cannot be predicted.

The August 14, 2003 transmission grid failures in the Northeast have spurred demands for transmission investment and national oversight through the National Electricity Reliability Council (NERC) enforcement powers. In the past, compliance with NERC reliability standards and guidelines has largely been voluntary. Potential impacts could include increased NERC power to impose transmission standards, resulting in further transmission regulation and increased capital requirements for LG&E.

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, among other things, LG&E Energy became a wholly owned subsidiary of Powergen and, as a result, LG&E became an indirect subsidiary of Powergen. Following the acquisition, Powergen became a registered holding company under PUHCA, and LG&E, as a subsidiary of a registered holding company, became subject to additional regulation under PUHCA.

As a result of the Powergen acquisition and in order to comply with PUHCA, LG&E Services was formed as a subsidiary of LG&E Energy effective on January 1, 2001. LG&E Services provides certain services to affiliated entities, including LG&E, at cost as required under PUHCA. On January 1, 2001, approximately 1,000 employees, mainly from LG&E Energy, LG&E and KU, were moved to LG&E Services.

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.

Following the purchase of Powergen by E.ON, E.ON became a registered holding company under PUHCA. As a result, E.ON, its utility subsidiaries, including LG&E, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services. In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company. LG&E believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct their business. LG&E will seek additional authorization when necessary.

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 (LG&E and KU) of LG&E Energy have continued their separate identities and continue to serve customers in Kentucky, Virginia and Tennessee under their existing names. The preferred stock and debt securities of LG&E were not affected by these transactions resulting in LG&E's obligation to continue to file SEC reports.

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.

RESULTS OF OPERATIONS

LG&E

Net Income

LG&E's net income in 2003 increased $1.9 million (2.1%) compared to 2002. The increase resulted primarily from increased electric wholesale sales partially offset by increased transmission expense and increased depreciation expense due to plant additions.

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%).

LG&E's net income in 2002 decreased $17.9 million (16.7%) ($15.8 million related to electric business and $2.1 million related to gas business) as compared to 2001. The decrease resulted primarily from higher transmission expenses, increased amortization of the VDT regulatory asset, and increased property insurance and pension expense, partially offset by an increase in electric sales to retail customers and lower interest expenses.

Revenues

A comparison of operating revenues for the years 2003 and 2002, excluding the provisions recorded for rate collections (refunds), with the immediately preceding year reflects both increases and decreases, which have been segregated by the following principal causes:

			Increase (Decrease) From Prior Period
			Electric Revenues						Gas Revenues
			2003			2002			2003			2002
			(in thousands)
Cause
Retail sales:
	Fuel and gas supply adjustments		$	6,620		$	19,449		$	50,972		$	(58,003	)
	LG&E/KU Merger surcredit			(2,288	)		(2,825	)		—			—
	Environmental cost recovery surcharge			(269	)		9,694			—			—
	Earnings sharing mechanism			9,768			622			—			—
	Demand side management			1,362			1,381			267			938
	VDT surcredit			(3,394	)		(1,177	)		(1,283	)		(285	)
	Weather normalization			—			—			(506	)		2,234
	Variation in sales volumes and other			(18,450	)		27,118			12,070			21,658

		Total retail sales		(6,651	)		54,262			61,520			(33,458	)
Wholesale sales				49,230			(6,701	)		(4,106	)		10,682
Gas transportation-net				—			—			(186	)		190
Other				1,635			4,641			412			(496	)

		Total	$	44,214		$	52,202		$	57,640		$	(23,082	)

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. Electric revenues increased in 2002 primarily due to an increase in retail sales due to warmer summer weather, an increase in the recovery of fuel costs passed through the FAC, partially offset by a decrease in wholesale sales due to lower market prices as compared to 2001. Cooling degree days increased 20% compared to 2001 and were 29% above the 20-year average.

Gas revenues in 2003 increased 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 wholesale sales. Heating degree days increased 5% as compared to 2002 and were the same as the 20-year average. Gas revenues in 2002 decreased due to a lower gas supply cost billed to customers through the gas supply clause offset partially by increased gas retail sales due to cooler winter weather and an increase in wholesale sales volume. Heating degree days increased 17% as compared to 2001 and were 5% below the 20-year average.

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 2003 fuel accruals ($2.6 million), partially offset by an increase in 2003 ECR accruals ($2.9 million). The increase in the provision for rate collections (refunds) in 2002 over 2001 ($10.1 million) is due primarily to the increase in the ESM accruals ($10.2 million) and an increase in fuel accruals ($1.4 million), partially offset by a 2002 ECR over-recovery ($1.5 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 an 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 $2.1 million (1.1%) in 2003 due to increased generation ($5.8 million) offset by lower cost of coal burned ($3.7 million). Fuel for electric generation increased $35.7 million (22.4%) in 2002 due to increased generation ($5.4 million) and higher cost of coal burned ($30.3 million). The average delivered cost per ton of coal purchased was $25.56 in 2003, $25.30 in 2002 and $21.27 in 2001.

Power purchased increased $17.7 million (28.7%) in 2003 due to an increase in purchases to meet requirements for off-system sales and a higher unit cost of purchases. Power purchased increased $12.6 million (25.5%) in 2002 due to an increase in purchases to meet requirements for native load and off-system sales and a higher unit cost of purchases.

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). Gas supply expenses decreased $24.1 million (11.7%) in 2002 due to a decrease in cost of net gas supply ($36.6 million), partially offset by an increase in the volume of gas delivered to the distribution system ($12.5 million).

Other operation expenses increased $8.7 million (4.2%) in 2003 due primarily 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) and an increase in uncollectible customer accounts ($1.6 million), partially offset by decreases in expenses from the amortization of regulatory assets ($3.5 million) and lower expenses related to injury and damage liabilities ($2.1 million). Other operation expenses increased $40.5 million (24.1%) in 2002 primarily due to a full year amortization in 2002 of a regulatory asset created as a result of the workforce reduction costs associated with LG&E's VDT ($17.0 million), higher costs for electric transmission primarily resulting from increased MISO costs ($13.9 million), an increase in property and other insurance costs ($3.9 million), an increase in pension costs due to change in pension assumptions to reflect current market conditions and change in market value of plan assets at the measurement date ($3.7 million), and an increase in steam production costs ($3.4 million).

Maintenance expenses for 2003 decreased $3.0 million (5.0%) due primarily to a decrease in expenses for maintenance of electric distribution ($1.1 million) and gas distribution ($0.8 million) and a decrease in communications maintenance expenses ($0.9 million). Maintenance expenses for 2002 increased $1.5 million (2.6%) primarily due to gas distribution expenses for main remediation work ($2.2 million).

Depreciation and amortization increased $7.4 million (7.0%) in 2003 and $5.6 million (5.5%) in 2002 because of additional utility plant in service.

Variations in income tax expenses are largely attributable to changes in pre-tax income. LG&E's 2003 effective income tax rate decreased to 35.5% from the 37.2% rate in 2002. See Note 7 of LG&E's Notes to Financial Statements under Item 8.

Property and other taxes decreased $0.4 million (2.3%) in 2003 compared to a $0.3 million (1.6%) decrease in 2002. Property taxes decreased $1.1 million in 2003 due to a $1.2 million coal credit partially offset by payroll taxes which increased by $0.7 million. Payroll taxes decreased by $1.1 million in 2002 due to employee reductions and property taxes increased by $0.8 million.

Other income (expense)—net decreased $2.0 million (246.2%) 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). Other income (expense)—net decreased $2.1 million (72.0%) in 2002 primarily due to increased costs for non-regulated commercial activities ($1.3 million) and decreases in the gain on sale of property ($0.8 million).

Interest charges for 2003 increased $0.8 million (2.8%) due to new fixed-rate debt with an affiliated company ($5.0 million) offset by a decrease in average outstanding balances on short-term notes payable to an affiliated company ($0.4 million) and savings from lower average interest rates on variable-rate long-term bonds ($3.7 million). Interest charges for 2002 decreased $8.1 million (21.4%) primarily due to lower interest rates on variable-rate debt ($5.6 million), a decrease in debt to affiliated companies ($0.8 million) and a decrease in interest associated with LG&E's accounts receivable securitization program ($1.5 million).

The weighted average interest rate on variable-rate long-term bonds for 2003, 2002 and 2001 was 1.10%, 1.54% and 3.42%, respectively. At December 31, 2003, 2002 and 2001, LG&E's percentage of long-term debt having a variable-rate, including the impact of interest rate swaps, was 38.3% at $306.0 million, 46.8% at $289.0 million and 40.1% at $247.3 million, respectively. LG&E's weighted average cost of long-term debt, including amortization of debt expense and interest rate swaps, was 3.58% and 3.87% at December 31, 2003 and 2002, respectively. See Note 9 of LG&E's Notes to Financial Statements under Item 8.

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

CRITICAL ACCOUNTING POLICIES/ESTIMATES

Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment also may have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied has not changed. Specific risks for these critical accounting policies are described in the following paragraphs. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Events rarely develop exactly as 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. See Note 4—Financial Instruments.

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, 2003, a 10% change in these estimated quantities would cause revenue and accounts receivable to change by approximately $5.1 million, including $2.2 million for

electric usage and $2.9 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, 2003 and 2002, the LG&E allowance for doubtful accounts was $3.5 million and $2.1 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—Judgments and uncertainties in benefit plan accounting include future rate of returns on pension plan assets, interest rates used in valuing benefit obligation, healthcare cost trend rates, and other actuarial assumptions.

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, discount rate, and contributions made to the plan. At December 31, 2002, LG&E was required to recognize an additional minimum liability as prescribed by SFAS No. 87Employers' Accounting for Pensions. The liability was recorded as a reduction to other comprehensive income, and did not affect net income. The amount of the liability depended upon the asset returns experienced in 2002 and contributions made by LG&E to the plan during 2002. 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.

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. Market performance in 2003 reversed the negative trend. Should poor market conditions return, these conditions could result in an increase in LG&E's funded 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.

LG&E made contributions to the pension plan of $83.1 million in January 2003, $6.0 million in September 2003 and $34.5 million in January 2004.

A 1% increase or decrease in the assumed discount rate could have an approximate $41 million positive or negative impact to the accumulated benefit obligation of LG&E.

See also Note 6 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.

LG&E has accrued in the financial statements an estimate of $8.9 million for 2003 ESM, with collection from customers commencing in April 2004. The ESM is subject to Kentucky Commission approval.

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

NEW ACCOUNTING PRONOUNCEMENTS

The following accounting pronouncements were implemented by LG&E in 2003:

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.

industry, contracts, permits, certificates of need and right of way agreements, to determine if legal obligations existed. The fair value of future removal obligations was calculated based on the Company's engineering estimates, costs expended for similar retirements and third party estimates at current market prices inflated at a rate of 2.31% per year to the expected retirement date of the asset. The future removal obligations were then discounted to their net present value at the original asset in-service date based on a discount rate of 6.61%. ARO assets equal to the net present value were recorded on the Company's books at implementation. An amount equal to the net present value plus the accretion the Company would have accrued had the standard been in effect at the original in-service date was also recorded on the Company's books as an ARO liability at implementation. Additionally, the Company contracted with an independent consultant to quantify the cost of removal included in its accumulated depreciation under regulatory accounting practices.

As of January 1, 2003, LG&E recorded asset retirement obligation (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.

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, 2003, LG&E recorded ARO assets, net of accumulated depreciation, of $4.5 million and liabilities of $9.7 million. LG&E recorded regulatory assets of $6.0 million and regulatory liabilities of $0.1 million.

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, pursuant to regulatory treatment prescribed under SFAS No. 71. Approximately $0.2 million of removal costs were incurred and charged against the ARO liability during 2003. SFAS No. 143 has no impact on the results of the operation 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 year ended December 31, 2003, LG&E recorded approximately $25,000 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, 2003 and 2002, LG&E has segregated this cost of removal, included in accumulated depreciation, of $223.6 million and $207.9 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.

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,Accounting for Derivative Instruments and Hedging Activities, 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 all prior periods, which had no impact on previously reported net income or common equity.

	2002		2001
	(in thousands)
Gross operating revenues	$	1,026,184	$	996,700
Less costs reclassified from power purchased		22,449		32,153

Net operating revenues reported	$	1,003,735	$	964,547

Gross power purchased	$	84,330	$	81,475
Less costs reclassified to revenues		22,449		32,153

Net power purchased reported	$	61,881	$	49,322

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 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, 2003, leaving 237,500 shares currently outstanding. Beginning with the three months ended September 30, 2003, LG&E reclassified its $5.875 series preferred stock as long-term debt with the minimum shares mandatorily redeemable within one year classified as current portion of long-term debt. Dividends accrued beginning July 1, 2003, are charged as interest expense.

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) is now 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.

LG&E has no special purpose entities that fall within the scope of FIN 46R. LG&E continues to evaluate the impact that FIN 46R may have on its financial position and results of operations.

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.

Operating Activities

Cash provided by operations was $163.3 million, $212.4 million and $287.1 million in 2003, 2002, and 2001, respectively. The 2003 decrease compared to 2002 of $49.1 million resulted primarily from pension funding in 2003 of $89.1 million and the change 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 taxes of $35.0 million and $36.0 million, respectively. The 2002 decrease of $74.7 million resulted primarily from the change in accounts receivable balances of $68.0 million. See Note 1 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 $213.0 million, $220.4 million and $253.0 million in 2003, 2002, and 2001, respectively. LG&E expects its capital expenditures for 2004 and 2005 to total approximately $270.0 million, which consists primarily of construction estimates associated with installation of NOx equipment as described in the section titled "Environmental Matters," construction of jointly owned CTs with KU and on-going construction for the generation and distribution systems.

Net cash used for investment activities decreased $7.2 million in 2003 compared to 2002 primarily due to the level of construction expenditures. NOx equipment expenditures were approximately $29.6 million in 2003 and $71.8 million in 2002, while CT expenditures were approximately $71.4 million in 2003 and $35.9 million in 2002. The $28.7 million decrease in net cash used in 2002 as compared to 2001 was primarily due to the purchase of CTs.

Financing Activities

Net cash inflows for financing activities were $34.2 million in 2003, $22.5 million in 2002 and outflows of $38.7 million in 2001. In 2003, long-term borrowings from affiliated company increased $200.0 million which were used in part for repayment of short-term borrowings from LG&E Energy and to retire a maturing first mortgage bond. During 2002, short-term borrowings increased $78.5 million from 2001 for payment of $73.3 million in dividends.

During 2001, LG&E issued $10.1 million of pollution control bonds resulting in net proceeds of $9.7 million after issuance costs.

On March 6, 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.

On March 22, 2002, LG&E refinanced its two $35 million unsecured pollution control bonds due November 1, 2027. The replacement variable-rate bonds are secured by 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.

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 an affiliated company totaling $200 million. $100 million of this total is unsecured and the remaining $100 million is secured by a lien subordinated to the first mortgage bond lien. The second lien applies to substantially all utility assets of LG&E.

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

Under the provisions for LG&E's variable-rate pollution control bonds totaling $246.2 million, 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.

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. Likewise, LG&E Energy and LG&E make funds available to KU at market-based rates up to $400 million. Fidelia Corporation, an affiliated company, also provides long-term intercompany funding to LG&E.

Certain regulatory approvals are required for the Company to incur additional debt. FERC and the SEC authorize the issuance of short-term debt while the Kentucky Commission authorizes issuance of long-term debt. As of December 31, 2003 the Company has received approvals from FERC and the SEC to borrow up to $400 million in short-term funds, and approvals from the Kentucky Commission for $150 million in additional long-term loans. New long-term loans totaling $125 million were completed in January 2004.

LG&E's debt ratings as of December 31, 2003, 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. Fitch withdrew its ratings on LG&E securities effective October 14, 2003.

Contractual Obligations

The following is provided to summarize LG&E's contractual cash obligations for periods after December 31, 2003:

	Payments Due by Period
Contractual Cash Obligations	2004		2005- 2006		2007- 2008		After 2008		Total
	(in thousands)
Short-term debt (a)	$	80,332	$	—	$	—	$	—	$	80,332
Long-term debt (b)		247,450		2,500		20,000		528,104		798,054
Operating lease (c)		3,401		7,006		7,290		26,130		43,827
Unconditional
purchase obligations (d)		10,614		25,182		27,195		254,235		317,226
Other long-term
obligations (e)		20,700		3,000		—		—		23,700

Total contractual cash obligations (f)	$	362,497	$	37,688	$	54,485	$	808,469	$	1,263,139

(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.

(c): Operating lease represents the lease of LG&E's administrative office building.
(d): Represents future minimum payments under purchased power agreements through 2023.
(e): Represents construction commitments.
(f): LG&E does not expect to pay the $246.2 million of long-term debt classified as a current liability in the Consolidated Balance Sheets in 2004 as explained in (b) above. LG&E anticipates cash from operations and external financing will be sufficient to fund future obligations. LG&E anticipates refinancing a portion of its short-term debt with long-term debt in 2004.

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 transaction produced a pre-tax gain of approximately $1.2 million which was recorded in other income on the income statement in 2000, pursuant to a Kentucky Commission order. 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, 2003, the maximum aggregate amount of default fees or amounts, which decrease over the term of the lease, was $8.9 million, of which LG&E would be responsible for 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. LG&E paid LG&E Energy a one-time fee of $114,000 to provide the guarantee.

MARKET RISKS

LG&E is exposed to market risks from changes in interest rates and commodity prices. To mitigate changes in cash flows attributable to these exposures, LG&E uses various financial instruments including derivatives. Derivative positions are monitored using techniques that include market value and sensitivity analysis. See Note 1 and 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, 2003, the potential change in interest expense associated with a 1% change in base interest rates of LG&E's unhedged debt is estimated at $4.4 million after the impact of interest rate swaps.

As of December 31, 2003, 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 $10 million as of December 31, 2003. 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, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities. Wholesale sales of excess asset capacity and wholesale purchases are treated as normal sales and purchases under SFAS No. 133 and SFAS No. 138 and are not marked to market.

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 2003 and 2002.

		2003			2002
		(in thousands)
Fair value of contracts at beginning of period, net liability		$	(156	)	$	(186	)
	Fair value of contracts when entered into during the period		2,654			(65	)
	Contracts realized or otherwise settled during the period		(569	)		448
	Changes in fair values due to changes in assumptions		(1,357	)		(353	)

Fair value of contracts at end of period, net liability		$	572		$	(156	)

No changes to valuation techniques for energy trading and risk management activities occurred during 2003. Changes in market pricing, interest rate and volatility assumptions were made during both years. All contracts outstanding at December 31, 2003, 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, 2003, 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. 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 are generally all receivables associated with retail sales that have standard terms and are not past due. LG&E was able to terminate the program at any time without penalty.

LG&E terminated the accounts receivable securitization program in January 2004 and replaced it with intercompany loans from an E.ON affiliate. The accounts receivable program required LG&E R to maintain minimum levels of net worth. The program also contained a cross-default provision if LG&E defaulted on debt obligations in excess of $25 million. If there was a significant deterioration in the payment record of the receivables by the retail customers or if LG&E failed to meet certain covenants regarding the program, the program could terminate at the election of the financial institutions. In this case, payments from retail customers would first be used to repay the financial institutions participating in the program, and would then be available for use by LG&E. LG&E did not violate any covenants with regard to the accounts receivable securitization program.

As part of the program, LG&E sold retail accounts receivables to a wholly owned subsidiary, 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 an unrelated third-party purchaser. 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. As of December 31, 2003, the outstanding program balance was $58.0 million.

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. Pre-tax gains and losses from the sale of the receivables in 2003, 2002 and 2001 were gains of $20,648, $46,727 and a loss of $206,578, respectively. LG&E's net cash flows from LG&E R were $(6.2) million, $20.2 million and $39.7 million for 2003, 2002 and 2001, respectively.

The allowance for doubtful accounts associated with the eligible securitized receivables at December 31 was $1.4 million, $1.9 million and $1.3 million in 2003, 2002 and 2001, 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,Accounting for the Effects of Certain Types of Regulation. 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.

Kentucky Commission Settlement Order—VDT Costs, ESM and Depreciation. 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.

LG&E reached a settlement in the VDT case as well as other cases involving the depreciation rates and ESM with all intervening parties. The settlement agreement was approved by a Kentucky Commission order in December 2001. The order 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 stipulated net savings LG&E is expected to realize from implementation of best practices through the VDT. The agreement also established new depreciation rates in effect December 2001, retroactive to January 2001. The new depreciation rates decreased depreciation expense by $5.6 million in 2001.

ECR. In June 2000, the Kentucky Commission approved LG&E's application for a CCN to construct up to three SCR NOx reduction facilities. The construction and subsequent operation of the SCRs is intended to reduce NOx emission levels to meet the EPA's mandated NOx emission level of 0.15 lbs./ Mmbtu by May 2004. In its order, the Kentucky Commission ruled that LG&E's proposed plan for construction was "reasonable, cost-effective and will not result in the wasteful duplication of facilities." In October 2000, LG&E filed an application with the Kentucky Commission to amend its Environmental Compliance Plan to reflect the addition of the proposed NOx reduction technology projects and to amend its Environmental Cost Recovery Tariff to include an overall rate of return on capital investments. Approval of LG&E's application in April 2001 allowed LG&E to begin to recover the costs associated with these new projects, subject to Kentucky Commission oversight during normal six-month and two-year reviews.

��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 going forward.

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. The final order approved 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 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.

ESM. LG&E's electric rates are subject to an ESM. The ESM, initially in place for three years beginning in 2000, sets an upper and lower point for rate of return on equity, whereby if LG&E's rate of return for the calendar year falls within the range of 10.5% to 12.5%, no action is necessary. If earnings are above the upper limit, the excess earnings are shared 40% with ratepayers and 60% with shareholders; if earnings are below the lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders. By order of the Kentucky Commission, rate changes prompted by the ESM filing go 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, and recently concluded discovery in the case. 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. Continuance of the ESM is still being deliberated by the Kentucky Commission and a final order is not expected until the second quarter of 2004. The ESM tariff remains in effect pending the resolution of the case.

LG&E made its third ESM filing in February 2003, for the calendar year 2002 reporting period. LG&E is in the process of recovering $13.6 million from customers for the 2002 reporting period. LG&E estimated that the rate of return will fall below the lower limit, subject to Kentucky Commission approval, for the year ended December 31, 2003. The 2003 financial statements include an accrual to reflect the earnings deficiency of $8.9 million to be recovered from customers commencing in April 2004.

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 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 evaluation.

Gas Supply Cost PBR Mechanism. Since November 1, 1997, LG&E has operated under an experimental PBR mechanism related to its gas procurement activities. For each of the last five years, LG&E's rates have been adjusted to recover its portion of the savings (or expenses) incurred during each of the five 12-month periods beginning November 1 and ending October 31. Since its implementation on November 1, 1997, through October 31, 2003, LG&E has achieved $51.7 million in savings. Of that total savings amount, LG&E's portion has been $20.5 million and the ratepayers' portion has been $31.2 million. Pursuant to the extension of LG&E gas supply cost PBR mechanism effective November 1, 2001, the sharing mechanism under the PBR requires savings (and expenses) to be shared 25% with shareholders and 75% with ratepayers up to 4.5% of the benchmarked 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 is obligated to file a report and assessment with the Kentucky Commission by December 31, 2004, seeking an extension or modification of the mechanism.

FAC. LG&E employs an FAC mechanism, which under Kentucky law allows LG&E to recover from customers the actual fuel costs associated with retail electric sales. In February 1999, LG&E received orders from the Kentucky Commission requiring a refund to retail electric customers of approximately $3.9 million resulting from reviews of the FAC from November 1994 through April 1998. While legal challenges to the Kentucky Commission order were pending, a comprehensive settlement was reached by all parties and approved by the Kentucky Commission in May 2002. Thereunder, LG&E agreed to credit its fuel clause in the amount of $0.7 million (such credit provided over the course of June and July 2002), and the parties agreed on a prospective

interpretation of the state's fuel adjustment clause regulation to ensure consistent and mutually acceptable application going forward.

In January 2003, the Kentucky Commission reviewed KU's FAC for the six-month period ending October 2002 and, as part of the Order in that case, required that an independent audit be conducted to examine operational and management aspects of both KU's and LG&E's fuel procurement functions. The final report was issued in February 2004. The report's recommendations related to documentation and process improvements will be addressed with the Kentucky Commission staff as Management Audit Action Plans are developed in the second quarter of 2004.

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.

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. The Kentucky Commission has suspended the effective date of the proposed new tariffs for five months, so that the rates may go into effect subject to refund by July 1, 2004. The Kentucky Commission established a procedural schedule for the cases pertaining to discovery and hearings. Hearings are scheduled in May 2004. LG&E expects the Kentucky Commission to issue orders in the cases before new rates go into effect July 1, 2004.

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 in July 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 April 2003, LG&E proposed a hedge plan for the 2003/2004 winter heating season with two alternatives, the first relying upon LG&E's storage and the second relying upon a combination of LG&E's storage and financial hedge instruments. In July 2003, the Kentucky Commission approved LG&E's first alternative which relies upon storage to mitigate the price volatility to which customers might otherwise be exposed. The Kentucky Commission validated the effectiveness of storage to mitigate potential volatility associated with high winter gas prices by approving this natural gas hedge plan.

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.

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.

FERC SMD NOPR. On July 31, 2002, 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 revenues and expenses, the specific impact of the rulemaking is not known at this time.

MISO. LG&E and KU are founding members of the MISO. Membership was obtained in 1998 in response to and consistent with federal policy initiatives. In February 2002, LG&E and KU 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 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, KU and the rest of the 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 and KU, 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 and KU, along with several other transmission owners, have again petitioned the District Court of Columbia Circuit for review. This case is currently pending.

As a separate matter, MISO, its transmission owners and other interested industry segments reached a settlement in mid-2002 regarding the level of cost responsibility properly borne by bundled and grandfathered load under these FERC rulings (such settlement expressly not prejudicing the transmission owners' and LG&E's right to challenge the FERC's ruling imposing cost responsibility on bundled loads in the first instance). In February 2003, FERC accepted a partial settlement between MISO and the transmission owners. FERC did not accept the only contested section of the settlement, which would have allowed the transmission owners to immediately treat unrecoverable Schedule 10 charges as regulatory assets. FERC will consider allowing regulatory asset treatment of unrecoverable Schedule 10 charges on a case-by-case basis.

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 and KU, have objected to the allocation of costs among market participants and retail native load. A hearing at FERC has been completed, but a ruling has not been issued.

The Kentucky Commission opened an investigation into LG&E's and KU's membership in MISO in July 2003. The Kentucky Commission directed LG&E and KU to file testimony addressing the costs and benefits of MISO membership both currently and over the next five years and other legal issues surrounding continued membership. LG&E and KU 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 MISO, under certain conditions. The MISO filed its own testimony and cost benefit analysis in December 2003. A final Kentucky Commission order is expected in the second quarter of 2004.

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 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.

Any fuel cost savings are passed to Kentucky customers through the fuel adjustment clause. See FAC above.

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 not subject to Phase I SO₂ emissions reduction requirements. 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 EPA 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, 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 2004. All LG&E generating units are subject to the May 2004 compliance date under these NOx emissions reduction rules.

reduction of its NOx emissions. 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 had 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, and EPA's December 2003 proposals to regulate mercury emissions from steam electric generating units and to further reduce emissions of sulfur dioxide and nitrogen oxides under the Interstate Air Quality Rule. In addition, LG&E is currently working 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 is in the process of converting 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 will incur additional costs of $0.4 million. Accordingly, an accrual of $0.4 million has been recorded in the accompanying financial statements at December 31, 2003 and 2002.

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

Deferred Income Taxes. LG&E expects to have adequate levels of taxable income to realize its recorded deferred tax assets. At December 31, 2003, deferred tax assets totaled $80.7 million and were principally related to expenses attributable to LG&E's pension plans and post retirement benefit obligations.

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.

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.

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.

LG&E had no cash distributions on common stock paid to LG&E Energy in 2003. The following table sets forth LG&E's cash distributions on common stock paid to LG&E Energy during 2002:

(in thousands)
First quarter	$	—
Second quarter		23,000
Third quarter		23,000
Fourth quarter		23,000

Louisville Gas and Electric Company and Subsidiary
Consolidated Statements of Income
(Thousands of $)

			Years Ended December 31
			2003			2002		2001
OPERATING REVENUES:
	Electric (Note 14)		$	768,600		$	724,386	$	672,184
	Gas			325,333			267,693		290,775
	Provision for rate collections (refunds) (Note 3)			(412	)		11,656		1,588

		Total operating revenues (Note 1)		1,093,521			1,003,735		964,547

OPERATING EXPENSES:
	Fuel for electric generation			196,965			194,900		159,231
	Power purchased (Note 14)			79,621			61,881		49,322
	Gas supply expenses			233,601			182,108		206,165
	Other operation expenses			217,060			208,322		167,818
	Maintenance			57,170			60,210		58,687
	Depreciation and amortization (Note 1)			113,288			105,906		100,356
	Federal and state income taxes (Note 7)			56,066			55,035		63,452
	Property and other taxes			17,065			17,459		17,743

		Total operating expenses		970,836			885,821		822,774

Net operating income				122,685			117,914		141,773
Other income (expense)—net (Note 8)				(1,205	)		815		2,930
Other income from affiliated company (Note 14)				6			5		—
Interest expense				23,863			27,630		34,907
Interest expense to affiliated companies (Note 14)				6,784			2,175		3,015

Net income			$	90,839		$	88,929	$	106,781

Consolidated Statements of Retained Earnings
(Thousands of $)

		Years Ended December 31
		2003		2002		2001
Balance January 1		$	409,319	$	393,636	$	314,594
Add net income			90,839		88,929		106,781

			500,158		482,565		421,375

Deduct:	Cash dividends declared on stock:
	5% cumulative preferred		1,075		1,075		1,075
	Auction rate cumulative preferred		908		1,702		2,195
	$5.875 cumulative preferred (Note 1)		734		1,469		1,469
	Common		—		69,000		23,000

			2,717		73,246		27,739

Balance December 31		$	497,441	$	409,319	$	393,636

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

Louisville Gas and Electric Company and Subsidiary
Consolidated Statements of Comprehensive Income
(Thousands of $)

	Years Ended December 31
	2003		2002			2001
Net income	$	90,839	$	88,929		$	106,781
Cumulative effect of change in accounting principle—Accounting for derivative instruments and hedging activities, net of tax benefit/(expense) of $2,399 for 2001		—		—			(3,599	)
Gain/(losses) on derivative instruments and hedging activities, net of tax benefit/(expense) of $(358), $3,404 and $1,043 for 2003, 2002 and 2001, respectively (Note 1)		544		(5,107	)		(1,563	)
Additional minimum pension liability adjustment, net of tax benefit/(expense) of $(1,257), $10,494 and $9,974 for 2003, 2002 and 2001, respectively (Note 6)		1,857		(15,505	)		(14,738	)

Other comprehensive income (loss), net of tax		2,401		(20,612	)		(19,900	)

Comprehensive income	$	93,240	$	68,317		$	86,881

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

Louisville Gas and Electric Company and Subsidiary
Consolidated Balance Sheets
(Thousands of $)

			December 31
			2003		2002
ASSETS:
Utility plant, at original cost (Note 1):
	Electric		$	2,809,957	$	2,717,187
	Gas			468,504		435,235
	Common			186,556		169,577

				3,465,017		3,321,999
	Less: reserve for depreciation			1,319,768		1,255,822

				2,145,249		2,066,177
	Construction work in progress			339,166		300,986

				2,484,415		2,367,163

Other property and investments—less reserve of $63 in 2003 and 2002				611		764

Current assets:
	Cash (Note 1)			1,706		17,015
	Accounts receivable—less reserve of $3,515 in 2003 and $2,125 in 2002			84,585		68,440
	Materials and supplies—at average cost:
		Fuel (predominantly coal) (Note 1)		25,260		36,600
		Gas stored underground (Note 1)		69,884		50,266
		Other (Note 1)		24,971		25,651
	Prepayments and other			5,281		5,298

				211,687		203,270

Deferred debits and other assets:
	Unamortized debt expense (Note 1)			8,468		6,532
	Regulatory assets (Note 3)			142,772		153,446
	Other			40,975		37,755

				192,215		197,733

			$	2,888,928	$	2,768,930

CAPITAL AND LIABILITIES:
Capitalization (see statements of capitalization):
	Common equity		$	923,664	$	833,141
	Cumulative preferred stock			70,140		95,140

				993,804		928,281

	Long-term debt:
		Long-term bonds (Note 9)		328,104		328,104
		Long-term notes to affiliated company (Note 9)		200,000		—
		Mandatorily redeemable preferred stock (Note 9)		22,500		—

				550,604		328,104

				1,544,408		1,256,385

Current liabilities:
	Current portion of long-term debt:
		Long-term bonds (Note 9)		246,200		288,800
		Mandatorily redeemable preferred stock (Note 9)		1,250		—

				247,450		288,800

	Notes payable to affiliated company (Notes 10 and 14)			80,332		193,053
	Accounts payable			93,118		96,410
	Accounts payable to affiliated companies (Note 14)			38,343		26,361
	Accrued taxes			18,615		1,450
	Customer deposits			10,493		9,735
	Other			9,308		9,801

				250,209		336,810

				497,659		625,610

Deferred credits and other liabilities:
	Accumulated deferred income taxes (Notes 1 and 7)			337,704		313,225
	Investment tax credit, in process of amortization			50,329		54,536
	Accumulated provision for pensions and related benefits (Note 6)			140,598		224,703
	Asset retirement obligations			9,747		—
	Regulatory liabilities (Note 3):
		Accumulated cost of removal of utility plant		223,622		207,852
		Other		51,822		52,424
	Other			33,039		34,195

				846,861		886,935

Commitments and contingencies (Note 11)			$	2,888,928	$	2,768,930

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

Louisville Gas and Electric Company and Subsidiary
Consolidated Statements of Cash Flows
(Thousands of $)

			Years Ended December 31
			2003			2002			2001
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income		$	90,839		$	88,929		$	106,781
	Items not requiring cash currently:
		Depreciation and amortization		113,288			105,906			100,356
		Deferred income taxes—net		20,123			11,915			3,021
		Investment tax credit—net		(4,207	)		(4,153	)		(4,290	)
		LG&E/KU merger amortization		1,815			3,629			3,629
		VDT amortization		30,400			30,000			13,000
		Mark-to-market financial instruments		(1,149	)		8,512			8,604
		One utility amortization		954			2,688			2,689
		Other		8,042			4,909			1,239
	Change in certain net current assets:
		Accounts receivable		(10,945	)		(3,973	)		43,185
		Materials and supplies		(7,598	)		(15,048	)		(2,018	)
		Accounts payable		8,690			(26,299	)		14,678
		Accrued taxes		17,165			(18,807	)		12,184
		Prepayments and other		906			321			(10,500	)
	Sale of accounts receivable (Note 1)			(5,200	)		21,200			42,000
	Pension funding			(89,125	)		336			374
	VDT expenses			(166	)		(514	)		(140,529	)
	Pension liability			3,908			11,904			66,865
	Provision for post-retirement benefits			4,031			1,775			38,459
	Gas supply clause			(4,712	)		3,873			(4,138	)
	Other			(13,809	)		(14,722	)		(8,526	)

		Net cash flows from operating activities		163,250			212,381			287,063

CASH FLOWS FROM INVESTING ACTIVITIES:
	Proceeds from sales of securities			153			412			4,237
	Construction expenditures			(212,957	)		(220,416	)		(252,958	)

		Net cash flows from investing activities		(212,804	)		(220,004	)		(248,721	)

CASH FLOWS FROM FINANCING ACTIVITIES:
	Long-term borrowings from affiliated company			200,000			—			—
	Short-term borrowings			—			—			29,944
	Repayment of short-term borrowings			—			(29,944	)		—
	Short-term borrowings from affiliated company			602,700			652,300			656,282
	Repayment of short-term borrowings from affiliated company			(715,421	)		(523,500	)		(706,618	)
	Retirement of first mortgage bonds			(42,600	)		—			—
	Issuance of pollution control bonds			128,000			161,665			10,104
	Issuance expense on pollution control bonds			(5,843	)		(3,030	)		(442	)
	Retirement of pollution control bonds			(128,000	)		(161,665	)		—
	Retirement of manditorily redeemable preferred stock			(1,250	)		—			—
	Payment of dividends			(3,341	)		(73,300	)		(27,995	)

		Net cash flows from financing activities		34,245			22,526			(38,725	)

Change in cash and temporary cash investments				(15,309	)		14,903			(383	)
Cash and temporary cash investments at beginning of year				17,015			2,112			2,495

Cash and temporary cash investments at end of year			$	1,706		$	17,015		$	2,112

Supplemental disclosures of cash flow information:
	Cash paid during the year for:
		Income taxes	$	24,868		$	51,540		$	35,546
		Interest on borrowed money		23,829			25,673			30,989
		Interest to affiliated companies on borrowed money		4,162			1,850			2,966

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

Louisville Gas and Electric Company and Subsidiary
Consolidated Statements of Capitalization
(Thousands of $)

						December 31
						2003			2002
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						(38,111	)		(40,512	)
	Retained earnings						497,441			409,319

							923,664			833,141

			Shares Outstanding	Current Redemption Price
CUMULATIVE PREFERRED STOCK:
	$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
		$5.875 series	237,500		100.00		—			25,000
	Preferred stock expense						(1,367	)		(1,367	)

							70,140			95,140

LONG-TERM DEBT (Note 9):
	First mortgage bonds—
		Series due August 15, 2003, 6%					—			42,600
	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
		V due August 15, 2019, 5.625%					—			102,000
		W due October 15, 2020, 5.45%					—			26,000
		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			—
	Notes payable to Fidelia:
		Due April 30, 2013, 4.55%, unsecured					100,000			—
		Due August 15, 2013, 5.31%, secured					100,000			—
	Mandatorily redeemable preferred stock:
		$5.875 series, outstanding shares of 237,500 in 2003 and 250,000 in 2002					23,750			—

		Total long-term debt outstanding					798,054			616,904
		Less current portion of long-term debt					247,450			288,800

		Long-term debt					550,604			328,104

		Total capitalization				$	1,544,408		$	1,256,385

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

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 a registered 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. LG&E has one wholly owned consolidated subsidiary, LG&E R. 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 had announced its pre-conditional cash offer of £5.1 billion ($7.3 billion) for Powergen on April 9, 2001. E.ON and Powergen are registered public utility holding companies 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 2003 presentation with no impact on the balance sheet net assets or previously reported income.

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,Accounting for the Effects of Certain Types of Regulation, 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 generally 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.

Depreciation and Amortization. Depreciation is provided on the straight-line method over the estimated service lives of depreciable plant. The amounts provided were approximately 3.3% in 2003 (2.9% electric, 2.8% gas, and 9.4% common); 3.1% in 2002 (2.9% electric, 2.8% gas and 6.6% common); and 3.0% for 2001 (2.9% electric, 2.9% gas and 5.7% common), of average depreciable plant. 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 Temporary Cash Investments. LG&E considers all debt instruments purchased with a maturity of three months or less to be cash equivalents. Temporary cash investments are carried at cost, which approximates fair value.

Fuel Inventory. Fuel inventories of $25.3 million and $36.6 million at December 31, 2003, and 2002, 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 $69.9 million and $50.3 million at December 31, 2003, and 2002, 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 $25.0 million and $25.7 million at December 31, 2003 and 2002, 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. See Note 4—Financial Instruments.

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.

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 $50.8 million and $40.7 million at December 31, 2003 and 2002, respectively.

Allowance for Doubtful Accounts. At December 31, 2003 and 2002, the LG&E allowance for doubtful accounts was $3.5 million and $2.1 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.

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 reasonable 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 implemented by LG&E in 2003:

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. The Company evaluated the impact of SFAS 143 from both a legal and operations perspective, reviewing applicable laws and regulations affecting the industry, contracts, permits, certificates of need and right of way agreements, to determine if legal obligations existed. The fair value of future removal obligations was calculated based on the Company's engineering estimates, costs expended for similar retirements and third party estimates at current market prices inflated at a rate of 2.31% per year to the expected retirement date of the asset. The future removal obligations were then discounted to their net present value at the original asset in-service date based on a discount rate of 6.61%. ARO assets equal to the net present value were recorded on the Company's books at implementation. An amount equal to the net present value plus the accretion the Company would have accrued had the standard been in effect at the original in-service date was also recorded on the Company's books as an ARO liability at implementation. Additionally, the Company contracted with an independent consultant to quantify the cost of removal included in its accumulated depreciation under regulatory accounting practices.

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

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 year ended December 31, 2003, LG&E recorded approximately $25,000 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.

accumulated depreciation, of $223.6 million and $207.9 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.

—: 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.

	2002		2001
	(in thousands)
Gross operating revenues	$	1,026,184	$	996,700
Less costs reclassified from power purchased		22,449		32,153

Net operating revenues reported	$	1,003,735	$	964,547

Gross power purchased	$	84,330	$	81,475
Less costs reclassified to revenues		22,449		32,153

Net power purchased reported	$	61,881	$	49,322

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, 2003, leaving 237,500 shares currently outstanding. Beginning with the three months ended September 30, 2003, LG&E reclassified its $5.875 series preferred stock as long-term debt with the minimum shares mandatorily redeemable within one year classified as current. Dividends accrued beginning July 1, 2003 are charged as interest expense.

LG&E has no special purpose entities that fall within the scope of FIN 46R. LG&E continues to evaluate the impact that FIN 46R may have on its financial position and results of operations.

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 (through Powergen) 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, and Powergen remained, a registered holding company under PUHCA. LG&E, as a subsidiary of a registered holding company, is subject to additional regulations under PUHCA. 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 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

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

	2003			2002
	(in thousands)
VDT Costs	$	67,810		$	98,044
Gas supply adjustments due from customers		22,077			13,714
Unamortized loss on bonds		21,333			18,843
ESM provision		12,359			12,500
LG&E/KU merger costs		—			1,815
Merger surcredit		6,220			—
Manufactured gas sites		1,454			1,757
One utility costs		—			954
ARO		6,015			—
Gas performance base ratemaking		5,480			4,243
DSM		24			1,576

Total regulatory assets	$	142,772		$	153,446

Accumulated cost of removal of utility plant	$	(223,622	)	$	(207,852	)
Deferred income taxes—net		(41,180	)		(45,536	)
Gas supply adjustments due to customers		(6,805	)		(3,154	)
ARO		(85	)		—
Gas purchase refund		—			(328	)
ESM		(79	)		(1,479	)
ECR		(17	)		(243	)
FAC		(1,950	)		—
DSM		(1,706	)		(1,684	)

Total regulatory liabilities	$	(275,444	)	$	(260,276	)

LG&E currently earns a return on all regulatory assets except for gas supply adjustments, ESM, 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.

LG&E reached a settlement in the VDT case as well as other cases involving the depreciation rates and ESM with all intervening parties. The settlement agreement was approved by a Kentucky Commission order in December 2001. The order 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. The agreement also established LG&E's new depreciation rates in

effect December 2001, retroactive to January 2001. The new depreciation rates decreased depreciation expense by $5.6 million in 2001.

PUHCA. Following the purchases of LG&E Energy by Powergen and Powergen by E.ON, Powergen and E.ON became registered holding companies under PUHCA. As a result, E.ON, its utility subsidiaries, including LG&E, and certain of its non-utility subsidiaries are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties, and intra-system sales of certain goods and services. In addition, PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company. LG&E believes that it has adequate authority (including financing authority) under existing SEC orders and regulations to conduct its business. LG&E will seek additional authorization when necessary.

ECR. In June 2000, the Kentucky Commission approved LG&E's application for a CCN to construct up to three SCR NOx reduction facilities. The construction and subsequent operation of the SCRs is intended to reduce NOx emission levels to meet the EPA's mandated NOx emission level of 0.15 lbs./ Mmbtu by May 2004. In its order, the Kentucky Commission ruled that LG&E's proposed plan for construction was "reasonable, cost-effective and will not result in the wasteful duplication of facilities." In October 2000, LG&E filed an application with the Kentucky Commission to amend its Environmental Compliance Plan to reflect the addition of the proposed NOx reduction technology projects and to amend its ECR Tariff to include an overall rate of return on capital investments. Approval of LG&E's application in April 2001 allowed LG&E to begin to recover the costs associated with these new projects, subject to Kentucky Commission oversight during normal six-month and two-year reviews.

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 going forward.

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.

lower limit, the earnings deficiency is recovered 40% from ratepayers and 60% from shareholders. By order of the Kentucky Commission, rate changes prompted by the ESM filing go 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, and recently concluded discovery in the case. 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. Continuance of the ESM is still being deliberated by the Kentucky Commission and a final order is not expected until the second quarter. The ESM tariff remains in effect pending the resolution of the case.

LG&E made its third ESM filing in February 2003 for the calendar year 2002 reporting period. LG&E is in the process of recovering $13.6 million from customers for the 2002 reporting period. LG&E estimated that the rate of return will fall below the lower limit, subject to Kentucky Commission approval, for the year ended December 31, 2003. The 2003 financial statements include an accrual to reflect the earnings deficiency of $8.9 million to be recovered from customers commencing in April 2004.

Gas Supply Cost PBR Mechanism. Since November 1, 1997, LG&E has operated under an experimental PBR mechanism related to its gas procurement activities. For each of the last five years, LG&E's rates have been adjusted to recover its portion of the savings (or expenses) incurred during each of the five 12-month periods beginning November 1 and ending October 31. Since its implementation on November 1, 1997, through October 31, 2003, LG&E has achieved $51.7 million in savings. Of that total savings amount, LG&E's portion has been $20.5 million and the ratepayers' portion has been $31.2 million. Pursuant to the extension of LG&E 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 is obligated to file a report and assessment with the Kentucky Commission by December 31, 2004, seeking an extension or modification of the mechanism.

adjustment charge or credit to the base charges. No significant issues have been identified as a result of these reviews.

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. The Kentucky Commission has suspended the effective date of the proposed new tariffs for five months, so that the rates may go into effect subject to refund by July 1, 2004. The Kentucky Commission established a procedural schedule for the cases pertaining to discovery and hearings. Hearings will be held in May 2004. LG&E expects the Kentucky Commission to issue orders in the cases before new rates go into effect July 1, 2004.

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 April 2003, in Case No. 2003-00149, LG&E proposed a hedge plan for the 2003/2004 winter heating season with two alternatives, the first relying upon LG&E's storage and the second relying upon a combination of LG&E's storage and financial hedge instruments. In July 2003, the Kentucky Commission approved LG&E's first alternative which relies upon storage to mitigate the price volatility to which customers might otherwise be exposed. The Kentucky Commission validated the effectiveness of storage to mitigate potential volatility associated with high winter gas prices by approving this natural gas hedge plan.

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.

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, 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.

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

FERC SMD NOPR. On July 31, 2002, 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 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.

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 and KU, 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 and KU, along with several other transmission owners, have again petitioned the District Court of Columbia Circuit for review. This case is currently pending.

The MISO plans to implement a congestion management system in December 2004, in compliance with FERC Order 2000. 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 and KU, have objected to the allocation of costs among market participants and retail native load. A hearing at FERC has been completed, but a ruling has not been issued.

ARO. In 2003, LG&E recorded $6.0 million in regulatory assets and $0.1 million in regulatory liabilities related to SFAS No. 143,Accounting for Asset Retirement Obligations.

Accumulated Cost of Removal. As of December 31, 2003 and 2002, LG&E has segregated the cost of removal, embedded in accumulated depreciation, of $223.6 million and $207.9 million, respectively, in 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.

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.

Any fuel cost savings are passed to Kentucky customers through the fuel adjustment clause. See FAC above.

Note 4—Financial Instruments

The cost and estimated fair values of LG&E's non-trading financial instruments as of December 31, 2003, and 2002 follow:

	2003					2002
	Cost		Fair Value			Cost		Fair Value
	(in thousands)
Preferred stock subject to mandatory redemption	$	23,750	$	23,893		$	25,000	$	25,188
Long-term debt (including current portion)		574,304		576,174			616,904		623,325
Long-term debt from Fidelia		200,000		206,333			—		—
Interest-rate swaps		—		(15,966	)		—		(17,115	)

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.

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 and earnings 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 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.

As of December 31, 2003 and 2002, LG&E was party to various interest rate swap agreements with aggregate notional amounts of $228.3 million and $117.3 million, respectively. Under these swap agreements, LG&E paid fixed rates averaging 4.38% and 5.13% and received variable rates based on LIBOR or the Bond Market Association's municipal swap index averaging 1.11% and 1.52% at December 31, 2003 and 2002, respectively. The swap agreements in effect at December 31, 2003 have been designated as cash flow hedges and mature on dates ranging from 2005 to 2033. The hedges have been deemed to be fully effective resulting in a pretax gain of $1.1 million for 2003, 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.

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, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities. Wholesale sales of excess asset capacity and wholesale purchases are treated as normal sales and purchases under SFAS No. 133 and SFAS No. 138 and are not marked to market.

The table below summarizes LG&E's energy trading and risk management activities for 2003 and 2002:

		2003			2002
		(in thousands)
Fair value of contracts at beginning of period, net liability		$	(156	)	$	(186	)
	Fair value of contracts when entered into during the period		2,654			(65	)
	Contracts realized or otherwise settled during the period		(569	)		448
	Changes in fair values due to changes in assumptions		(1,357	)		(353	)

Fair value of contracts at end of period, net liability		$	572		$	(156	)

outstanding at December 31, 2003, 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 hedges the price volatility of its forecasted peak electric off-system sales with the sale 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. In 2003, LG&E recognized a pre-tax loss of approximately $18,000, and a loss, net of tax, deferred in other comprehensive income of approximately $147,000.

Accounts Receivable Securitization. On February 6, 2001, LG&E implemented an accounts receivable securitization program. 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 have standard terms and are not past due. LG&E was able to terminate the program at any time without penalty.

LG&E terminated the accounts receivable securitization program in January 2004 and replaced it with long-term intercompany loans from an E.ON affiliate. The accounts receivable program required LG&E R to maintain minimum levels of net worth. The program also contained a cross-default provision if LG&E defaulted on debt obligations in excess of $25 million. If there was a significant deterioration in the payment record of the receivables by the retail customers or if LG&E failed to meet certain covenants regarding the program, the program could terminate at the election of the financial institutions. In this case, payments from retail customers would first be used to repay the financial institutions participating in the program, and would then be available for use by LG&E. LG&E did not violate any covenants with regard to the accounts receivable securitization program.

As part of the program, LG&E sold retail accounts receivables to a wholly owned subsidiary, 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 an unrelated third-party purchaser. 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 purchaser. LG&E obtained an opinion from independent legal counsel indicating these transactions qualified as a true sale of receivables. As of December 31, 2003, the outstanding program balance was $58.0 million.

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 312,000 customers and electricity to approximately 384,000 customers in Louisville and adjacent areas in Kentucky. For the year ended December 31, 2003, 70% of total revenue was derived from electric operations and 30% from gas operations.

In November 2001, LG&E and IBEW Local 2100 employees, which represent approximately 70% 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.

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, 2003, and a statement of the funded status as of December 31, 2003, for LG&E's sponsored defined benefit plan:

		2003			2002			2001
		(in thousands)
Pension Plans:
Change in benefit obligation
	Benefit obligation at beginning of year	$	364,794		$	356,293		$	310,822
	Service cost		1,757			1,484			1,311
	Interest cost		23,190			24,512			25,361
	Plan amendments		3,978			576			1,550
	Change due to transfers		(2,759	)		—			—
	Curtailment loss		—			—			24,563
	Special termination benefits		—			—			53,610
	Benefits and lump sums paid		(33,539	)		(34,823	)		(53,292	)
	Actuarial (gain) or loss and other		21,270			16,752			(7,632	)

	Benefit obligation at end of year	$	378,691		$	364,794		$	356,293

Change in plan assets
	Fair value of plan assets at beginning of year	$	196,314		$	233,944		$	333,378
	Actual return on plan assets		47,152			(15,648	)		(27,589	)
	Employer contributions		89,125			336			374
	Changes due to transfers		238			13,814			(17,508	)
	Benefits and lump sums paid		(33,539	)		(34,824	)		(53,292	)
	Administrative expenses		(1,512	)		(1,308	)		(1,419	)

	Fair value of plan assets at end of year	$	297,778		$	196,314		$	233,944

Reconciliation of funded status
	Funded status	$	(80,913	)	$	(168,480	)	$	(122,349	)
	Unrecognized actuarial (gain) or loss		56,219			60,313			18,800
	Unrecognized transition (asset) or obligation		(2,183	)		(3,199	)		(4,215	)
	Unrecognized prior service cost		32,275			32,265			35,435

	Net amount recognized at end of year	$	5,398		$	(79,101	)	$	(72,329	)

Other Benefits:
Change in benefit obligation
	Benefit obligation at beginning of year	$	93,233		$	89,946		$	56,981
	Service cost		604			444			358
	Interest cost		6,872			5,956			5,865
	Plan amendments		7,380			—			1,487
	Curtailment loss		—			—			8,645
	Special termination benefits		—			—			18,089
	Benefits and lump sums paid		(9,313	)		(4,988	)		(4,877	)
	Actuarial (gain) or loss		9,254			1,875			3,398

	Benefit obligation at end of year	$	108,030		$	93,233		$	89,946

Change in plan assets
	Fair value of plan assets at beginning of year	$	1,478		$	2,802		$	7,166
	Actual return on plan assets		2,076			(533	)		(765	)
	Employer contributions		6,401			4,213			1,470
	Changes due to transfers		—			—			(188	)
	Benefits and lump sums paid		(9,281	)		(5,004	)		(4,881	)

	Fair value of plan assets at end of year	$	674		$	1,478		$	2,802

Reconciliation of funded status
	Funded status	$	(107,356	)	$	(91,755	)	$	(87,144	)
	Unrecognized actuarial (gain) or loss		23,724			16,971			15,947
	Unrecognized transition (asset) or obligation		6,027			6,697			7,346
	Unrecognized prior service cost		11,482			5,995			5,302

	Net amount recognized at end of year	$	(66,123	)	$	(62,092	)	$	(58,549	)

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, 2003, 2002 and 2001:

		2003			2002			2001
		(in thousands)
Pension Plans:
Amounts recognized in the balance sheet consisted of:
	Prepaid benefits cost	$	—		$	—		$	—
	Accrued benefit liability		(74,474	)		(162,611	)		(108,977	)
	Intangible asset		32,275			32,799			11,936
	Accumulated other comprehensive income		47,597			50,711			24,712

	Net amount recognized at year-end	$	5,398		$	(79,101	)	$	(72,329	)

Additional year-end information for plans with accumulated benefit obligations in excess of plan assets:
	Projected benefit obligation	$	378,691		$	364,794		$	356,293
	Accumulated benefit obligation		372,252			358,956			352,477
	Fair value of plan assets		297,778			196,314			233,944
Other Benefits:
Amounts recognized in the balance sheet consisted of:
	Accrued benefit liability	$	(66,123	)	$	(62,092	)	$	(58,549	)

Additional year-end information for plans with benefit obligations in excess of plan assets:
	Projected benefit obligation	$	108,030		$	93,233		$	89,946
	Fair value of plan assets		674			1,478			2,802
Increase (decrease) in minimum liability included in other comprehensive income		$	(3,114	)	$	25,999		$	24,712

Components of Net Periodic Benefit Cost. The following table provides the components of net periodic benefit cost for the plans for 2003, 2002 and 2001:

		2003			2002			2001
		(in thousands)
Pension Plans:
Components of net periodic benefit cost
	Service cost	$	1,756		$	1,484		$	1,311
	Interest cost		23,190			24,512			25,361
	Expected return on plan assets		(22,785	)		(21,639	)		(26,360	)
	Amortization of prior service cost		3,792			3,777			3,861
	Amortization of transition (asset) or obligation		(1,016	)		(1,016	)		(1,000	)
	Recognized actuarial (gain) or loss		2,219			21			(777	)

	Net periodic benefit cost	$	7,156		$	7,139		$	2,396

Special charges
	Prior service cost recognized	$	—		$	—		$	10,237
	Special termination benefits		—			—			53,610
	Settlement loss		—			—			(2,244	)

	Total charges	$	—		$	—		$	61,603

Other Benefits:
Components of net periodic benefit cost
	Service cost	$	604		$	444		$	358
	Interest cost		6,872			5,956			5,865
	Expected return on plan assets		(51	)		(204	)		(420	)
	Amortization of prior service cost		1,768			920			951
	Amortization of transition (asset) or obligation		670			650			719
	Recognized actuarial (gain) or loss		505			116			(32	)

	Net periodic benefit cost	$	10,368		$	7,882		$	7,441

Special charges
	Curtailment loss	$	—		$	—		$	6,671
	Transition obligation recognized		—			—			4,743
	Prior service cost recognized		—			—			2,391
	Special termination benefits		—			—			18,089

	Total charges	$	—		$	—		$	31,894

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

	2003		2002		2001
Weighted-average assumptions as of December 31:
Discount rate	6.25	%	6.75	%	7.25	%
Rate of compensation increase	3.00	%	3.75	%	4.25	%

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

	2003		2002		2001
Discount rate	6.75	%	7.25	%	7.75	%
Expected long-term return on plan assets	9.00	%	9.50	%	9.50	%
Rate of compensation increase	3.75	%	4.25	%	4.75	%

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

each asset class. The expected return for each asset class was then weighted based on the target asset allocation to develop the expected long-term rate of return on assets assumption for the portfolio.

Assumed Healthcare Cost Trend Rates. For measurement purposes, 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:

	1% Decrease			1% Increase
	(in thousands)
Effect on total of service and interest cost components for 2003	$	(276	)	$	313
Effect on year-end 2003 postretirement benefit obligations	$	(3,482	)	$	3,875

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

		2003		2002		2001
Pension Plans:
	Equity securities	66	%	64	%	70	%
	Debt securities	33		34		28
	Other	1		2		2

	Totals	100	%	100	%	100	%

Other Benefits:
	Equity securities	0	%	0	%	97	%
	Debt securities	100		100		3

	Totals	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 a discretionary contribution to the pension plan of $34.5 million in January 2004. No further discretionary contributions are planned and no contributions are required for 2004.

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 $1.8 million for 2003, $1.7 million for 2002 and $1.2 million for 2001.

Note 7—Income Taxes

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

				2003			2002			2001
				(in thousands)
Included in operating expenses:
	Current		-federal	$	30,598		$	26,231		$	42,997
			-state		11,007			8,083			8,668
	Deferred		-federal—net		16,922			20,464			12,310
			-state—net		1,746			4,410			3,767
Amortization of investment tax credit					(4,207	)		(4,153	)		(4,290	)

		Total			56,066			55,035			63,452

Included in other income—net:
	Current		-federal		(4,830	)		(1,667	)		(1,870	)
			-state		(1,004	)		(430	)		(483	)
	Deferred		-federal—net		(129	)		(206	)		285
			-state—net		(30	)		(53	)		73

		Total			(5,993	)		(2,356	)		(1,995	)

Total income tax expense				$	50,073		$	52,679		$	61,457

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

		2003		2002
		(in thousands)
Deferred tax liabilities:
	Depreciation and other plant-related items	$	365,460	$	346,737
	Other liabilities		52,976		64,734

			418,436		411,471

Deferred tax assets:
	Investment tax credit		20,314		22,012
	Income taxes due to customers		16,620		18,431
	Pensions		5,345		21,056
	Accrued liabilities not currently deductible and other		38,453		36,747

			80,732		98,246

Net deferred income tax liability		$	337,704	$	313,225

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

	2003		2002		2001
Statutory federal income tax rate	35.0	%	35.0	%	35.0	%
State income taxes, net of federal benefit	5.4		5.6		4.7
Amortization of investment tax credit	(3.0	)	(2.9	)	(2.6	)
Other differences—net	(1.9	)	(0.5	)	(0.6	)

Effective income tax rate	35.5	%	37.2	%	36.5	%

The decrease in the effective rate in 2003 compared to 2002 relates to the recognition of tax benefits for prior year audit settlements and excess deferred tax adjustments.

Note 8—Other Income (Expense)—Net

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

	2003			2002			2001
	(in thousands)
Interest and dividend income (expense)	$	(1,254	)	$	554		$	856
Income and other taxes		5,943			2,305			1,945
Other		(5,894	)		(2,044	)		129

	$	(1,205	)	$	815		$	2,930

Note 9—Long-Term Debt

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

Long-term debt and the current portion of long-term debt consists primarily of first mortgage bonds, pollution control bonds, and long-term loans from affiliated companies as summarized below (in thousands of $). Interest rates and maturities in the table below are for the amounts outstanding at December 31, 2003 and reflect the impact of interest rate swaps.

		Stated Interest Rates		Weighted Average Interest Rate		Maturities		Principal Amounts
Noncurrent portion		Variable—5.90%		4.23	%	2027-2033		$	528,104
Current portion		Variable		1.46	%	2017-2027			246,200

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 2003 was 1.10%.

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. As of December 31, 2003, 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. See Note 4.

LG&E's first mortgage bond, 6% Series of $42.6 million, matured in 2003.

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

In March 2002, LG&E refinanced four unsecured pollution control bonds with an aggregate principal balance of $120 million and replaced them with secured pollution control bonds. The new bonds and the previous bonds were all variable-rate bonds, and the maturity dates remained unchanged.

Annual requirements for the sinking funds of LG&E's first mortgage bonds (other than the first mortgage bonds issued in connection with certain pollution control bonds) are the amounts necessary to redeem 1% of the highest principal amount of each series of bonds at any time outstanding. Property additions (166²/3% of principal amounts of bonds otherwise required to be so redeemed) have been applied in lieu of cash, such that the sinking fund requirements are fully met.

Substantially all of LG&E's utility plant is 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. LG&E has not violated any of these conditions that could cause any portion of retained earnings to be restricted by this provision.

During 2003, LG&E entered into two long-term loans from an affiliated company totaling $200 million. Of this total, $100 million is unsecured with an interest rate of 4.55% and matures in April 2013. The remaining $100 million is secured by a lien 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 utility assets of LG&E.

The following table reflects the long-term debt maturities:

	2004			2005		2006		2007		2008		Thereafter		Total
	(in thousands)
Pollution control bonds	$	246,200 (1	)	$	—	$	—	$	—	$	—	$	328,104	$	574,304
Notes payable to Fidelia		—			—		—		—		—		200,000		200,000
Mandatorily redeemable preferred stock		1,250			1,250		1,250		1,250		18,750		—		23,750

	$	247,450		$	1,250	$	1,250	$	1,250	$	18,750	$	528,104	$	798,054

(1): Includes $246,200 of bonds with put provisions that allow the holders to sell bonds back to LG&E at a specific price before maturity.

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

Note 10—Notes Payable and Other Short-Term Obligations

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 (based on an index of highly rated commercial paper issues as of the prior month end) up to $400 million. Likewise, LG&E Energy and LG&E make funds available to KU at market-based rates up to $400 million. The balance of the money pool loan from LG&E Energy (shown as "Notes payable to affiliate") was $80.3 million at an average rate of 1.00% and $193.1 million at an average rate of 1.61%, at December 31, 2003 and 2002, respectively. The amount available to LG&E under the money pool agreement at December 31, 2003 was $319.7 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, 2003 was $111.1 million, and availability of $38.9 million remained.

During July 2003, LG&E entered into five revolving lines of credit with banks totaling $185 million. These credit facilities expire in June 2004, and there was no outstanding balance under any of these facilities at December 31, 2003. 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.: limitation on disposing assets aggregating more than 15% of total assets as of December 31, 2002.

LG&E has not violated any of the above covenants.

In January 2004, LG&E entered into a one year loan totaling $100 million with an affiliated company. The interest rate on the loan is 1.53%, and the proceeds were used to repay notes payable to an affiliated under the money pool arrangement. The loan is secured by a second lien on substantially all utility assets of LG&E.

Note 11—Commitments and Contingencies

The following is provided to summarize LG&E's contractual cash obligations for periods after December 31, 2003:

	Payments Due by Period
	2004		2005- 2006		2007- 2008		After 2008		Total
	(in thousands)
Contractual Cash Obligations
Short-term debt (a)	$	80,332	$	—	$	—	$	—	$	80,332
Long-term debt (b)		247,450		2,500		20,000		528,104		798,054
Operating lease (c)		3,401		7,006		7,290		26,130		43,827
Unconditional purchase obligations (d)		10,614		25,182		27,195		254,235		317,226
Other long-term obligations (e)		20,700		3,000		—		—		23,700

Total contractual cash obligations (f)	$	362,497	$	37,688	$	54,485	$	808,469	$	1,263,139

(a): Represents borrowings from affiliate 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.
(c): Operating lease represents the lease of LG&E's administrative office building.
(d): Represents future minimum payments under purchased power agreements through 2023.
(e): Represents construction commitments.
(f): LG&E does not expect to pay the $246.2 million of long-term debt classified as a current liability in the Consolidated Balance Sheets in 2004 as explained in (b) above. LG&E anticipates cash from operations and external financing will be sufficient to fund future obligations. LG&E anticipates refinancing a portion of its short-term debt with long-term debt in 2004.

Operating Lease. LG&E leases office space, office equipment and vehicles. LG&E accounts for its leases as operating leases. Total lease expense for 2003, 2002, and 2001, less amounts contributed by affiliated companies occupying a portion of the office space leased by LG&E, was $2.2 million, $2.2 million, and $2.5 million, respectively. The future minimum annual lease payments under LG&E's office space lease agreement for years subsequent to December 31, 2003, are as follows:

	(in thousands)
2004	$	3,401
2005		3,468
2006		3,538
2007		3,609
2008		3,681
Thereafter		26,130

Total	$	43,827

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.

Letters of Credit. LG&E has provided letters of credit totaling $14.3 million as collateral for derivative transactions and 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 4.9% ownership in OVEC's common stock, which is accounted for under the cost method of accounting. LG&E's entitlement is 7% of OVEC's generation capacity or approximately 155 Mw.

The estimated future minimum annual demand payment under the OVEC purchased power agreement for the years subsequent to December 31, 2003, are as follows:

	(in thousands)
2004	$	10,614
2005		10,900
2006		14,282
2007		13,426
2008		13,769
Thereafter		254,235

Total	$	317,226

Construction Program. LG&E had approximately $20.7 million of commitments in connection with its construction program at December 31, 2003. Construction expenditures for the years 2004 and 2005 are estimated to total approximately $270.0 million, although all of this amount is not currently committed, including the construction of four jointly owned CTs, $13.6 million, and construction of NOx equipment, $5.1 million.

LG&E is currently implementing a plan for adding significant additional NOx controls to its generating units. Installation of additional NOx controls will proceed on a phased basis, with installation of controls commencing in late 2000 and continuing through the final compliance date. LG&E estimates that it will incur total capital costs of approximately $185 million to reduce its NOx emissions to the 0.15 lb./Mmbtu level on a company-wide basis. As of December 31, 2003, LG&E has incurred approximately $177 million of these capital costs related to the reduction of its NOx emissions. In addition, LG&E will incur additional operation 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 had 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 December 2003 proposals to regulate mercury emissions from steam electric generating units and to further reduce emissions of sulfur dioxide and nitrogen oxides under the Interstate Air Quality Rule. In addition, LG&E is currently working 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 is in the process of converting the Mill Creek Station to wet stack operation in an effort to resolve all outstanding issues related to particulate matter emissions.

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.

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		386.2		66.4		62.4		515.0
LG&E's 75% ownership (in thousands):
Cost	$	595,313
Accumulated depreciation		194,343

Net book value	$	400,970

Construction work in progress (included above)	$	8,374

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

		LG&E			KU			Total
		($ in thousands)
Paddy's Run 13	Ownership %		53	%		47	%		100	%
	Mw capacity		84			74			158
	Cost	$	33,919		$	29,973		$	63,892
	Depreciation		2,875			2,527			5,402

	Net book value	$	31,044		$	27,446		$	58,490

E.W. Brown 5	Ownership %		53	%		47	%		100	%
	Mw capacity		62			55			117
	Cost	$	24,111		$	20,296		$	44,407
	Depreciation		2,033			1,700			3,733

	Net book value	$	22,078		$	18,596		$	40,674

E.W. Brown 6	Ownership %		38	%		62	%		100	%
	Mw capacity		59			95			154
	Cost	$	23,975		$	36,701		$	60,676
	Depreciation		2,629			5,447			8,076

	Net book value	$	21,346		$	31,254		$	52,600

E.W. Brown 7	Ownership %		38	%		62	%		100	%
	Mw capacity		59			95			154
	Cost	$	23,824		$	38,256		$	62,080
	Depreciation		3,571			4,039			7,610

	Net book value	$	20,253		$	34,217		$	54,470

Trimble 5	Ownership %		29	%		71	%		100	%
	Mw capacity		46			114			160
	Cost	$	15,970		$	39,045		$	55,015
	Depreciation		799			1,953			2,752

	Net book value	$	15,171		$	37,092		$	52,263

Trimble 6	Ownership %		29	%		71	%		100	%
	Mw capacity		46			114			160
	Cost	$	15,961		$	39,025		$	54,986
	Depreciation		798			1,952			2,750

	Net book value	$	15,163		$	37,073		$	52,236

Trimble 7	Ownership %		37	%		63	%		100	%
	Mw capacity		56			96			152
	Current CWIP	$	17,342		$	29,634		$	46,976
Trimble 8	Ownership %		37	%		63	%		100	%
	Mw capacity		56			96			152
	Current CWIP	$	17,307		$	29,601		$	46,908
Trimble 9	Ownership %		37	%		63	%		100	%
	Mw capacity		56			96			152
	Current CWIP	$	17,300		$	29,599		$	46,899
Trimble 10	Ownership %		37	%		63	%		100	%
	Mw capacity		56			96			152
	Current CWIP	$	17,300		$	29,597		$	46,897
Trimble CT Pipeline	Ownership %		29	%		71	%		100	%
	Cost	$	1,835		$	4,475		$	6,310
	Depreciation		102			249			351

	Net book value	$	1,733		$	4,226		$	5,959

Trimble CT Substation	Ownership %		29	%		71	%		100	%
	Cost	$	1,474		$	3,598		$	5,072
	Depreciation		45			116			161

	Net book value	$	1,429		$	3,482		$	4,911

See also Note 11, Construction Program, for LG&E's planned expenditures for construction of four jointly owned CTs in 2004.

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

	Electric			Gas		Total
	(in thousands)
2003
Operating revenues	$	768,188	(a)	$	325,333	$	1,093,521
Depreciation and amortization		96,487			16,801		113,288
Operating income taxes		49,409			6,657		56,066
Interest income		27			4		31
Interest expense		25,694			4,953		30,647
Net income		80,612			10,227		90,839
Total assets		2,345,784			543,144		2,888,928
Construction expenditures		177,961			34,996		212,957
2002
Operating revenues	$	736,042	(b)	$	267,693	$	1,003,735
Depreciation and amortization		90,248			15,658		105,906
Operating income taxes		49,010			6,025		55,035
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
2001
Operating revenues	$	673,772	(c)	$	290,775	$	964,547
Depreciation and amortization		85,572			14,784		100,356
Operating income taxes		55,527			7,925		63,452
Interest income		616			132		748
Interest expense		31,295			6,627		37,922
Net income		95,103			11,768		106,781
Total assets		1,985,252			463,102		2,448,354
Construction expenditures		227,107			25,851		252,958

(a): Net of provision for rate refunds of $0.4 million.
(b): Net of provision for rate collections of $11.7 million.
(c): Net of provision for rate collections of $1.6 million.

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, an E.ON subsidiary, 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 LG&E Energy Marketing Inc. ("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 Revenues and Purchased Power Operating Expense. LG&E intercompany electric revenues and purchased power expense for the years ended December 31, 2003, 2002, and 2001 were as follows:

	2003		2002		2001
	(in thousands)
Electric operating revenues from KU	$	53,747	$	41,480	$	28,521
Electric operating revenues from LEM		9,372		9,939		5,564
Purchased power from KU		46,690		33,249		31,133
Purchased power from LEM		—		913		—

Interest Charges

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 (based on an index of highly rated commercial paper issues as of the prior month end) up to $400 million. Likewise, LG&E Energy and LG&E make funds available to KU at market-based rates up to $400 million. The balance of the money pool loan from LG&E Energy (shown as "Notes payable to affiliated company") was $80.3 million at an average rate of 1.00% and $193.1 million at an average rate of 1.61%, at December 31, 2003 and 2002, respectively. The amount available to LG&E under the money pool agreement at December 31, 2003 was $319.7 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, 2003 was $111.1 million, and availability of $38.9 million remained.

In addition, in 2003 LG&E began borrowing long-term funds from Fidelia Corporation, an affiliate of E.ON (see Note 9). Fidelia Corporation has a second lien on the property subject to the first mortgage bond lien. The second lien secures $100 million of the loans provided by Fidelia.

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 the utilities relates to LG&E's receipt and payment of KU's portion of off-system sales and purchases.

LG&E intercompany interest income and expense for the years ended December 31, 2003, 2002, and 2001 were as follows:

	2003		2002		2001
	(in thousands)
Interest on money pool loans	$	1,751	$	2,114	2,719
Interest on Fidelia loans		5,025		—	—
Interest expense paid to KU		8		61	296
Interest income received from KU		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 L&GE 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 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, 2003, 2002, and 2001 were as follows:

	2003		2002		2001
	(in thousands)
LG&E Services billings to LG&E	$	185,756	$	183,124	$	193,426
LG&E billings to KU		23,436		29,659		31,314
KU billings to LG&E		31,850		36,404		87,992
LG&E billings to LG&E Services		19,951		15,079		26,060

Note 15—Selected Quarterly Data (Unaudited)

Selected financial data for the four quarters of 2003 and 2002 are shown below. Because of seasonal fluctuations in temperature and other factors, results for quarters may fluctuate throughout the year.

	Quarters Ended
	March		June		September		December
	(in thousands)
2003
Operating revenues	$	326,844	$	215,373	$	262,833	$	288,471
Net operating income		33,190		16,290		47,680		25,525
Net income		27,264		7,755		39,871		15,949
2002
Operating revenues	$	278,005	$	216,163	$	243,074	$	266,493
Net operating income		28,748		22,410		41,652		25,104
Net income		20,943		15,256		34,204		18,526

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 March
	(in thousands)
2003
Gross operating revenues	$	335,117
Less costs reclassified from power purchased		8,273

Net operating revenues reported	$	326,844
2002
Gross operating revenues	$	283,365
Less costs reclassified from power purchased		5,360

Net operating revenues reported	$	278,005

Note 16—Subsequent Events

LG&E made a contribution to the pension plan of $34.5 million in January 2004 (see Note 6).

LG&E terminated the accounts receivable securitization program in January 2004 (see Note 4).

In January 2004, LG&E entered into a one year loan with an affiliated company totaling $100 million with an interest rate of 1.53%. The proceeds were used to repay notes payable to the affiliated companies under the money pool arrangement. The loan is secured by a second lien on substantially all utility assets of LG&E (see Note 10).

In January 2004, LG&E entered into a long-term loan with an affiliated company totaling $25 million with an interest rate of 4.33% that matures in January 2012. The proceeds were used to repay amounts due under the accounts receivable securitization program. The loan is secured by a lien subordinated to the first mortgage bond lien (see Note 9).

Louisville Gas and Electric Company and Subsidiary
REPORT OF MANAGEMENT

The management of Louisville Gas and Electric Company and Subsidiary 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 2003, 2002 and 2001 financial statements have been audited by PricewaterhouseCoopers LLP, independent auditors. Management made available to PricewaterhouseCoopers 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, 2003, did not identify any material weaknesses in the design and operation of LG&E's internal control structure.

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 public auditors and the internal auditors have access to the Board of Directors at any time.

Louisville Gas and Electric Company 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 and Subsidiary
Louisville, Kentucky

Louisville Gas and Electric Company and Subsidiary
REPORT OF INDEPENDENT AUDITORS

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 (the "Company") at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 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 year ended December 31, 2003 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 consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which 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

PricewaterhouseCoopers LLP
Louisville, Kentucky
February 6, 2004

Louisville Gas and Electric Company

MR A SAMPLE		000000 0000000000 0 0000
DESIGNATION (IF ANY)		000000000.000 ext
ADD 1		000000000.000 ext
ADD 2		000000000.000 ext
ADD 3		000000000.000 ext
ADD 4		000000000.000 ext
ADD 5		000000000.000 ext
ADD 6		000000000.000 ext
		C 1234567890 J N T

/: / Mark this box with an X if you have made changes to your name or address details above.

Annual Meeting Proxy Card

A: Election of Directors for terms expiring in 2005
1.: The Board of Directors Recommends a Vote "FOR" the listed nominees.

	For	Withhold
01 — Victor A. Staffieri	/ /	/ /
02 — John R. McCall	/ /	/ /
03 — S. Bradford Rives	/ /	/ /

B: Issue

The Board of Directors Recommends a Vote "FOR" the following proposal.

	For	Against	Abstain
2. Approval of PricewaterhouseCoopers LLP as Independent Accountants.	/ /	/ /	/ /
I plan to attend the Annual Meeting.	/ /
I will bring the indicated number of guests to the annual meeting.	/ /

C: 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.

Signature 1 — Please keep signature within the box

Signature 2 — Please keep signature within the box

Date (mm/dd/yyyy)

1 U P X HHH P P P P 003452

00BXLC

Proxy—Louisville Gas and Electric Company

Annual Meeting of Shareholders
July 8, 2004

Victor A. Staffieri, John R. McCall and S. Bradford Rives are hereby appointed as proxies, with full power of substitution to vote the shares of the shareholder(s) named on the reverse side hereof at the Annual Meeting of Shareholders of Louisville Gas and Electric Company to be held on July 8, 2004 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.

00BXMB

Admission Ticket

Louisville Gas and Electric Company
Annual Meeting of Shareholders

Thursday, July 8, 2004
3:00 p.m., Louisville time
Twelfth Floor Assembly Room
LG&E Building
220 West Main Street
Louisville, Kentucky

If you plan to attend the meeting, please check the box on the proxy card indicating that you plan to attend. Please bring this Admission Ticket to the meeting with you.

Each proposal is fully explained in the enclosed Notice of Annual Meeting of Shareholders and Proxy Statement. To vote your proxy, pleaseMARK 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.

Complimentary parking will be available at the LG&E Building Garage off Market Street and The Actors Theatre Garage off Main Street. 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.

QuickLinks

NOTICE OF ANNUAL MEETING OF SHAREHOLDERS
ELECTION OF DIRECTORS
INFORMATION CONCERNING THE BOARD OF DIRECTORS
APPROVAL OF INDEPENDENT AUDITORS FOR 2004
REPORT REGARDING REMUNERATION
COMPANY PERFORMANCE
COMPARISON OF FIVE YEAR CUMULATIVE TOTAL SHAREHOLDER RETURN (1) DATA POINTS (IN $)
EXECUTIVE COMPENSATION AND OTHER INFORMATION
SUMMARY COMPENSATION TABLE
OPTION/SAR GRANTS TABLE Option/SAR Grants in 2003 Fiscal Year
OPTION/SAR EXERCISES AND YEAR-END VALUE TABLE Aggregated Option/SAR Exercises in 2003 Fiscal Year And FY-End Option/SAR Values
LONG-TERM INCENTIVE PLAN AWARDS TABLE Long-Term Incentive Plan Awards in 2003 Fiscal Year
EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT ARRANGEMENTS AND CHANGE IN CONTROL PROVISIONS
EQUITY COMPENSATION PLAN INFORMATION
REPORT ON 2003 AUDIT COMMITTEE MATTERS
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING
SHAREHOLDER PROPOSALS AND NOMINATIONS
SHAREHOLDER COMMUNICATIONS
OTHER MATTERS

APPENDIX A

LOUISVILLE GAS AND ELECTRIC COMPANY AND KENTUCKY UTILITIES COMPANY AUDIT COMMITTEE CHARTER
2003 FINANCIAL REPORT
TABLE OF CONTENTS
INDEX OF ABBREVIATIONS
Selected Financial Data
Louisville Gas and Electric Company and Subsidiary Management's Discussion and Analysis of Financial Condition and Results of Operations
Louisville Gas and Electric Company and Subsidiary Market for the Registrant's Common Equity and Related Stockholder Matters.
Louisville Gas and Electric Company and Subsidiary Consolidated Statements of Income (Thousands of $)
Consolidated Statements of Retained Earnings
Consolidated Statements of Comprehensive Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Louisville Gas and Electric Company and Subsidiary Consolidated Statements of Capitalization (Thousands of $)
Louisville Gas and Electric Company and Subsidiary Notes to Consolidated Financial Statements
Louisville Gas and Electric Company and Subsidiary REPORT OF MANAGEMENT
Louisville Gas and Electric Company and Subsidiary REPORT OF INDEPENDENT AUDITORS

Louisville Gas & Electric DEF 14ADefinitive proxy