Wisconsin Electric Power Company PFD 3.60% (WELPP) DEF 14C Information statement

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

SCHEDULE 14C

Information Statement Pursuant to Section 14(c)

of the Securities Exchange Act of 1934 (Amendment No.    )

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Last Update: 02/22/2000

231 W Michigan Street

Milwaukee, WI 53203

Richard A. Abdoo

Chairman of the Board

Gale E. Klappa

President and Chief Executive Officer

March 16, 2004

Dear Stockholder:

Wisconsin Electric Power Company, which is now doing business as We Energies, will hold its annual meeting of stockholders on Friday, April 30, 2004, at 11:00 a.m. in Conference Room P140A at the Public Service Building, 231 West Michigan Street, Milwaukee, Wisconsin. We are not soliciting proxies for this meeting, as over 99% of the voting stock is owned, and will be voted, by Wisconsin Electric Power Company’s parent company, Wisconsin Energy Corporation. If you wish, you may attend the meeting and vote your shares of preferred stock; however, it will be a very short business meeting.

On behalf of the directors and officers of Wisconsin Energy Corporation, I invite you to attend Wisconsin Energy Corporation’s annual meeting to be held Wednesday, May 5, 2004, at 10:00 a.m. at the Wisconsin Exposition Center at State Fair Park, 8200 West Greenfield Avenue, West Allis, Wisconsin. By attending this meeting, you will have the opportunity to meet many of the Wisconsin Electric Power Company officers and directors. Although you cannot vote your shares of Wisconsin Electric Power Company preferred stock at the Wisconsin Energy Corporation meeting, you may find the activities to be worthwhile. You will be asked to register before entering the meeting.

The annual report to stockholders accompanies this information statement. If you have any questions about the material presented or would like a copy of the Wisconsin Energy Corporation summary annual report, please call our toll-free stockholder hotline at

1-800-881-5882.

Sincerely,

NOTICE

OF

ANNUAL MEETING OF STOCKHOLDERS

March 16, 2004

To the Stockholders of Wisconsin Electric Power Company:

The 2004 Annual Meeting of Stockholders of Wisconsin Electric Power Company will be held on Friday, April 30, 2004, at 11:00 a.m. in Conference Room P140A at the Public Service Building, 231 West Michigan Street, Milwaukee, Wisconsin, for the following purposes:

1. To elect a Board of Directors to hold office until the 2005 Annual Meeting of Stockholders; and

2. To consider any other matters which may properly come before the meeting.

Stockholders of record at the close of business on February 25, 2004, are entitled to vote.

The following pages provide additional details about the meeting as well as other useful information.

By Order of the Board of Directors

Kristine Rappé

Vice President and Corporate Secretary

231 West Michigan Street

Milwaukee, Wisconsin 53203

INFORMATION STATEMENT

This information statement is being furnished to stockholders beginning on or about March 16, 2004, in connection with the annual meeting of stockholders of Wisconsin Electric Power Company (“WE” or the “Company”) to be held on Friday, April 30, 2004, at 11:00 a.m. in Conference Room P140A at the Public Service Building, 231 West Michigan Street, Milwaukee, Wisconsin, and all adjournments or postponements of the meeting, for the purposes listed in the preceding Notice of Annual Meeting of Stockholders. The WE annual report to stockholders accompanies this information statement.

We are not asking you for a proxy and you are requested not to send us a proxy. However, you may vote your shares of preferred stock at the meeting.

VOTING SECURITIES

As of February 25, 2004, WE had outstanding 44,498 shares of Six Per Cent. Preferred Stock; 260,000 shares of $100 par value 3.60% Serial Preferred Stock; and 33,289,327 shares of common stock. Each outstanding share of each class is entitled to one vote. Stockholders of record at the close of business on February 25, 2004, will be entitled to vote at the meeting. A majority of the shares entitled to vote represented at the meeting shall constitute a quorum.

All of WE’s outstanding common stock, representing over 99% of its voting securities, is owned by its parent company, Wisconsin Energy Corporation (“WEC”), whose principal business address is 231 West Michigan Street, Milwaukee, Wisconsin. A list of stockholders of record entitled to vote at the meeting will be available for inspection by stockholders at WE’s principal business office at 231 West Michigan Street, Milwaukee, Wisconsin, prior to and at the meeting.

ELECTION OF DIRECTORS

New Director Elected.Pursuant to authority granted to the Board under the Bylaws, the Board of Directors elected Gale E. Klappa, President and Chief Executive Officer of Wisconsin Electric Power Company, as a director effective December 9, 2003. Mr. Klappa was elected to complete the term expiring at the meeting previously held by Richard R. Grigg.

Director Retirement.Richard A. Abdoo, Chairman of the Board of Wisconsin Electric Power Company, has indicated his intention to retire from all officer and director positions with WEC and its subsidiaries, including Wisconsin Electric Power Company, and to retire as an employee, effective as of April 30, 2004. With much appreciation for his many years of leadership and service, the Board of Directors has accepted Mr. Abdoo’s retirement and has appointed Mr. Klappa to the additional position of Chairman of the Board, effective as of May 1, 2004. On the effectiveness of Mr. Abdoo’s retirement as a director on April 30, 2004, the Board of Directors has determined to reduce the number of directors constituting the whole Board from ten to nine, thereby eliminating the vacancy that otherwise would be created by Mr. Abdoo’s retirement.

Director Nominees. At the 2004 annual meeting, there will be an election of nine directors. The individuals named below have been nominated by the Board to serve one-year terms and until they are reelected or until their respective successors are duly elected and qualified.

Directors will be elected by a plurality of the votes cast by the shares entitled to vote, as long as a quorum is present. “Plurality” means that the individuals who receive the largest number of votes are elected as directors up to the maximum number of directors to be chosen. Therefore, shares not voted, whether by withheld authority or otherwise, have no effect in the election of directors.

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Each nominee has consented to being nominated and to serve if elected. In the unlikely event that any nominee becomes unable to serve for any reason, the proxies will be voted for a substitute nominee selected by the WE Board upon the recommendation of the Corporate Governance Committee of WEC’s Board of Directors.

Biographical information regarding each nominee is shown below. Ages are shown as of March 16, 2004. Wisconsin Electric Power Company and Wisconsin Gas Company are now doing business as We Energies and are subsidiaries of Wisconsin Energy Corporation.

Information Concerning Nominees For Terms Expiring in 2005

John F. Ahearne. Age 69.

• Sigma Xi Center for Sigma Xi, The Scientific Research Society – Director of the Ethics Program since 1999. Director of the Sigma Xi Center from 1997 to 1999 and Executive Director from 1989 to 1997. The Sigma Xi Center is an organization that publishesAmerican Scientist, provides grants to graduate students and conducts national meetings on major scientific issues.

• Resources for the Future – Adjunct Professor since 1993. Resources for the Future is an economic research, non-profit institute.

• Duke University – Lecturer and Adjunct Scholar from 1995 to 2003.

• United States Nuclear Regulatory Commission – Commissioner from 1978 to 1983, serving as Chairman from 1979 to 1981.

• Director of Wisconsin Energy Corporation and Wisconsin Electric Power Company since 1994. Director of Wisconsin Gas Company since 2000.

John F. Bergstrom. Age 57.

• Bergstrom Corporation – Chairman and Chief Executive Officer since 1997. President from 1974 through 1996. Bergstrom Corporation owns and operates numerous automobile sales and leasing companies.

• Director of Banta Corporation, Kimberly-Clark Corporation, Midwest Air Group, Inc. and Sensient Technologies Corporation.

• Director of Wisconsin Energy Corporation since 1987. Director of Wisconsin Electric Power Company since 1985. Director of Wisconsin Gas Company since 2000.

Barbara L. Bowles. Age 56.

• The Kenwood Group, Inc. – Founder and Chief Executive Officer since 1989. Chairman since 2000. President from 1989 to 2000. The Kenwood Group is an investment advisory firm that manages pension funds for corporations, public institutions and endowments.

• Director of Black & Decker Corporation, Dollar General Corporation and Georgia-Pacific Corporation.

• Director of Wisconsin Energy Corporation and Wisconsin Electric Power Company since 1998. Director of Wisconsin Gas Company since 2000.

Robert A. Cornog. Age 63.

• Snap-on Incorporated – Retired Chairman of the Board, President and Chief Executive Officer. Served from 1991 and retired as President and Chief Executive Officer in 2001. Retired as Chairman in 2002. Snap-on Incorporated is a developer, manufacturer and distributor of professional hand and power tools, diagnostic and shop equipment, and tool storage products.

• Director of Johnson Controls, Inc.

• Director of Wisconsin Energy Corporation since 1993. Director of Wisconsin Electric Power Company and Wisconsin Gas Company since 1994 and 2000, respectively.

Willie D. Davis. Age 69.

• All Pro Broadcasting, Inc. – President and Chief Executive Officer since 1977. All Pro Broadcasting owns and operates radio stations in Los Angeles and Milwaukee.

• Director of Alliance Bank, Bassett Furniture Industries Inc., Checkers Drive-In Restaurants, Inc., Dow Chemical Company, Fidelity National Information Solutions, Inc., Johnson Controls, Inc., MGM Mirage, Inc., Manpower, Inc., Metro-Goldwyn-Mayer, Inc., Sara Lee Corporation and Strong Capital Management, Inc.

• Director of Wisconsin Energy Corporation and Wisconsin Electric Power Company since 2000. Director of Wisconsin Gas Company since 1990.

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Gale E. Klappa. Age 53.

• Wisconsin Energy Corporation – President since April 2003.

• Wisconsin Electric Power Company – President and Chief Executive Officer since August 2003.

• Wisconsin Gas Company – President and Chief Executive Officer since August 2003.

• Southern Company – Executive Vice President, Chief Financial Officer and Treasurer from March 2001 to April 2003. Chief Strategic Officer from October 1999 to March 2001. Southern Company is a public utility holding company serving the southeastern United States.

• Southern Energy, Inc. (now Mirant) – President of the North American Group and Senior Vice President from December 1998 to October 1999. Mirant is a multi-national energy company that produces and sells electricity.

• Director of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas Company since December 2003.

Ulice Payne, Jr. Age 48.

• Milwaukee Brewers Baseball Club, Inc. – President and Chief Executive Officer from September 2002 to November 2003.

• Foley & Lardner – Managing Partner of the law firm’s Milwaukee office from May 2002 to September 2002. A partner from February 1998 to October 2002.

• Director of Badger Meter, Inc., Midwest Air Group, Inc. and State Financial Services Corporation.

• Director of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas Company since January 2003.

Frederick P. Stratton, Jr. Age 64.

• Briggs & Stratton Corporation – Chairman Emeritus since 2003. Chairman of the Board from 2001 to 2003. Chairman and Chief Executive Officer until 2001. Briggs & Stratton Corporation is a manufacturer of small gasoline engines.

• Director of Bank One Corporation, Midwest Air Group, Inc. and Weyco Group, Inc.

• Director of Wisconsin Energy Corporation since 1987. Director of Wisconsin Electric Power Company since 1986 and Director of Wisconsin Gas Company since 2000.

George E. Wardeberg. Age 68.

• Wisconsin Energy Corporation – Retired Vice Chairman of the Board of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas Company.

• WICOR, Inc. –Various positions including Chairman of the Board from 1997 to 2000, Chief Executive Officer from 1994 to 2000, and President from 1994 to 1997.

• Director of Marshall & Ilsley Corporation and Twin Disc, Inc.

• Director of Wisconsin Energy Corporation and Wisconsin Electric Power Company since 2000 and Wisconsin Gas Company since 1992.

OTHER MATTERS

The Board of Directors is not aware of any other matters that may properly come before the meeting. The WE Bylaws set forth the requirements that must be followed should a stockholder wish to propose any floor nominations for director or floor proposals at annual or special meetings of stockholders. In the case of annual meetings, the Bylaws state, among other things, that notice and certain other documentation must be provided to WE at least 70 days and not more than 100 days before the scheduled date of the annual meeting. No such notices have been received by WE.

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CORPORATE GOVERNANCE – FREQUENTLY ASKED QUESTIONS

Does WE have Corporate Governance Guidelines?	Yes, the WE Board of Directors follows WEC’s Corporate Governance Guidelines that WEC has maintained since 1996. These Guidelines provide a framework from which the Board conducts its business. WEC’s Corporate Governance Committee reviews the Guidelines annually to promote continuous improvement of the Board’s processes to provide effective governance over the affairs of the Company. To view the Guidelines, please refer to the “Governance” section of WEC’s website at www.WisconsinEnergy.com.
How are directors determined to be independent?	No director qualifies as independent unless the Board affirmatively determines that the director has no material relationship with the Company. WEC’s Corporate Governance Guidelines provide that the Board should consist of at least a two-thirds majority of independent directors.
What are the Board’s standards of independence?	The guidelines the Board uses in determining director independence are located in Appendix A of WEC’s Corporate Governance Guidelines. These standards of independence, which are more comprehensive than the standards established by the New York Stock Exchange, are summarized below. •      Has not been an employee of the Company for the last five years; •      Has not received, in the past three years, more than $100,000 per year in direct compensation from the Company, other than director fees or deferred compensation for prior service; •      Has not been affiliated with or employed by a present or former internal or external auditor of the Company in the past three years; •      Has not been an executive officer, in the past three years, of another company where any of the Company’s present executives serve on that other company’s compensation committee; •      In the past three years, has not been an employee of a company that makes payments to, or receives payments from, the Company for property or services in an amount which in any single fiscal year is the greater of $1 million or 2% of such other company’s consolidated gross revenues; •      Has not received, in the past three years, remuneration, other than de minimus remuneration, as a result of services as, or being affiliated with an entity that serves as an advisor, consultant, legal counsel, or significant supplier to the Company or to a member of the Company’s senior management; •      Has no personal service contract(s) with the Company or any member of the Company’s senior management; •      Is not an employee or officer with a not-for-profit entity that receives more than 5% of its total annual charitable awards from the Company; •      Has not had any business relationship with the Company, in the past three years, for which the Company has been required to make disclosure under certain rules of the Securities and Exchange Commission; •      Is not employed by a public company at which an executive officer of the Company serves as a director; and •      Does not have any beneficial ownership interest of 5% or more in an entity that has received remuneration, other than de minimus remuneration, from the Company, its subsidiaries or affiliates. The Board also considers whether a director’s immediate family members meet the above criteria, as appropriate, when determining the director’s independence.

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Who are the independent directors?	The Board has affirmatively determined that Directors Ahearne, Bergstrom, Bowles, Cornog, Davis, Payne, and Stratton have no material relationships with WE or WEC and are independent under the Board’s standards of independence. This represents more than a two-thirds majority of the Board. Directors Abdoo, Klappa and Wardeberg are not independent due to their present and/or previous employment with WE and/or WEC.
What are the committees of the Board?	The Board of Directors of WE has the following committees: Audit and Oversight, Compensation, Finance, and Executive. All committees, except the Executive Committee, operate under a charter approved by the Board. A copy of each committee charter is posted in the “Governance” section of WEC’s website at www.WisconsinEnergy.com. The members and the responsibilities of each committee are listed later in this information statement.
Are the Audit and Oversight and Compensation Committees comprised solely of independent directors?	Yes, these committees are comprised solely of independent directors, as determined under New York Stock Exchange rules and WEC’s Corporate Governance Guidelines. In addition, each member of the Audit and Oversight Committee is independent as determined under the rules of the New York Stock Exchange applicable to audit committee members. The Audit and Oversight Committee is a separately designated committee established in accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934, as amended.
Do the independent directors meet separately from management?	Yes, at every regularly scheduled Board meeting, an executive session of independent directors is held without any management present. The chair of WEC’s Corporate Governance Committee, currently Willie D. Davis, presides at these sessions.
How can I contact the members of the Board?	Correspondence may be sent to the directors, including the independent directors, in care of the Corporate Secretary, Kristine Rappé, at the Company’s principal business office, 231 West Michigan Street, P.O. Box 2046, Milwaukee, Wisconsin 53201. All communication received as set forth above will be opened by the Corporate Secretary for the sole purpose of determining whether the contents represent a message to the Company’s directors. Communications other than advertising, promotions of a product or service, or patently offensive material will be forwarded promptly to the addressee.
Does the Company have a written code of ethics?	Yes, all WE and WEC directors and employees, including the principal executive, financial and accounting officers, have a responsibility to comply with WEC’s Code of Business Conduct, seek advice in doubtful situations and report suspected violations. WEC’s Code of Business Conduct addresses, among other things: conflicts of interest; corporate opportunities; confidentiality; fair dealing; protection and proper use of company assets; and compliance with laws, rules and regulations (including insider trading laws). The Company has not provided any waivers to the Code for directors, executive officers or any other employee. The Code of Business Conduct is posted in the “Governance” section of the WEC’s website at www.WisconsinEnergy.com. It is also available in print to any stockholder upon request. The Company maintains a toll-free confidential helpline for employees to report suspected violations of the Code or other concerns regarding accounting, internal accounting controls or auditing matters.

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Does the Board evaluate its own performance?	Yes, the Board annually evaluates its own collective performance. Each director is asked to rate the performance of the Board on such things as: the establishment of appropriate corporate governance practices; providing appropriate oversight for key affairs of the Company (including its strategic plans, long-range goals, financial and operating performance and customer satisfaction initiatives); providing necessary and timely advice and counsel to the CEO; communicating the Board’s expectations and concerns to the CEO; identifying threats and opportunities critical to the Company; and operating in a manner that ensures open communication, objective and constructive participation and timely resolution of issues. WEC’s Corporate Governance Committee uses the results of this process as part of its annual review of WEC’s Corporate Governance Guidelines and to foster continuous improvement of the Board’s activities.
Is Board committee performance evaluated?	Yes, each committee conducts an annual performance evaluation of its activities and reports the results to the Board. The evaluation is designed to measure the effectiveness of the committee’s actions and compare the performance of each committee with the requirements of its charter. The committee may adjust its charter, with Board approval, based on the results of this evaluation.
Are all the members of the audit committee financially literate and does the committee have an “audit committee financial expert”?	Yes, the Board has determined that all of the members of the WE Audit and Oversight Committee are financially literate as required by New York Stock Exchange rules. The Board has also determined that Directors Barbara L. Bowles (Chair), John F. Bergstrom, Robert A. Cornog, Ulice Payne, Jr. and Frederick P. Stratton, Jr., all independent directors, qualify as audit committee financial experts within the meaning of Securities and Exchange Commission rules. In addition, no member of the Audit and Oversight Committee serves as an audit committee member of more than three public companies.
Does the Board have a nominating committee?	WE does not have a nominating committee. Directors of WEC are also directors of WE and, as such, WE relies on WEC’s Corporate Governance Committee for identifying and evaluating director nominees. The chair of the Committee coordinates this effort. All members of WEC’s Corporate Governance Committee are independent under the New York Stock Exchange rules applicable to nominating committee members and WEC’s Corporate Governance Guidelines. The WEC Corporate Governance Committee operates under a charter approved by the WEC Board, a copy of which is posted in the “Governance” section of WEC’s website at www.WisconsinEnergy.com. The members and responsibilities of the WEC Corporate Governance Committee are listed later in this information statement.
What is the process used to identify director nominees and how do I recommend a nominee to WEC’s Corporate Governance Committee?	Candidates for director nomination may be proposed by stockholders, WEC’s Corporate Governance Committee and other members of the Board. The Committee may pay a third party to identify qualified candidates; however, such a firm was not engaged with respect to the nominees listed in this information statement. The Committee identified and recommended all director nominees presented for election at the meeting. No stockholder nominations or recommendations were received. Stockholders wishing to propose director candidates for consideration and recommendation by WEC’s Corporate Governance Committee for election at the 2005 annual meeting of stockholders must submit the name(s) and qualifications of any proposed candidate(s) to WEC’s Corporate Governance Committee no later than November 1, 2004 via the Corporate Secretary, Kristine Rappé, at the Company’s principal business office, 231 West Michigan Street, P.O. Box 2046, Milwaukee, Wisconsin 53201.

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What are the criteria and process used to evaluate director nominees?	WEC’s Corporate Governance Committee has not established minimum qualifications for director nominees; however, the criteria for evaluating all candidates, which are reviewed annually, include characteristics such as: proven integrity, mature and independent judgment, vision and imagination, ability to objectively appraise problems, ability to evaluate strategic options and risks, sound business experience and acumen, relevant technological, political, economic or social/cultural expertise, social consciousness, achievement of prominence in career, familiarity with national and international issues affecting WEC and the Company’s businesses and contribution to the Board’s desired diversity and balance. In evaluating director candidates, WEC’s Corporate Governance Committee reviews potential conflicts of interest, including interlocking directorships and substantial business, civic and/or social relationships with other members of the Board that could impair the prospective Board member’s ability to act independently from the other Board members and management. WEC’s Bylaws state that directors shall be stockholders of WEC. Once a person has been identified by WEC’s Corporate Governance Committee as a potential candidate, the Committee may collect and review publicly available information regarding the person to assess whether the person should be considered further. If the Committee determines that the candidate warrants further consideration, the chair or another member of the Committee contacts the person. Generally, if the person expresses a willingness to be considered and to serve on the Board, the Committee requests information from the candidate, reviews the person’s accomplishments and qualifications, and conducts one or more interviews with the candidate. In certain instances, Committee members may contact one or more references provided by the candidate or may contact other members of the business community or other persons that may have greater firsthand knowledge of the candidate’s accomplishments. The Committee evaluates all candidates, including those proposed by stockholders, using the criteria and process described above. The process is designed to provide the Board with a diversity of experience to allow it to effectively meet the many challenges WE faces in today’s changing business environment.
What is WE’s policy regarding director attendance at annual meetings?	Directors are not expected to attend WE’s annual meetings of stockholders, as they are only short business meetings, but are expected to attend WEC’s annual meetings of stockholders. All directors attended WEC’s 2003 Annual Meeting.
Where can I find more information about WE and WEC’s corporate governance?	WEC’s website, www.WisconsinEnergy.com, contains information on the governance activities of WE and WEC. Here, you will find the Code of Business Conduct, Corporate Governance Guidelines, Board committee charters and other useful information. As policies are continually evolving, the Company encourages you to visit the website periodically. Copies of these documents may also be requested from the Corporate Secretary.

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COMMITTEES OF THE BOARD OF DIRECTORS

Members	Principal Responsibilities; Meetings
Audit and Oversight Barbara L. Bowles, Chair John F. Bergstrom Robert A. Cornog Ulice Payne, Jr. Frederick P. Stratton, Jr.	•      Oversee integrity of financial statements. •      Oversee management compliance with legal and regulatory requirements. •      Review, approve, and evaluate the independent auditors’ services. •      Oversee the performance of the internal audit function and independent auditors. •      Prepare the report required by the SEC. •      The Committee conducted seven meetings in 2003.
Compensation John F. Bergstrom, Chair John F. Ahearne Willie D. Davis	•      Identify through succession planning potential executive officers. •      Provide a competitive, performance-based executive and director compensation program. •      Set goals for the CEO and annually evaluate the CEO’s performance against such goals. •      Prepare the annual report on executive compensation required by the SEC. •      The Committee conducted six meetings in 2003.
Finance Frederick P. Stratton, Jr., Chair Barbara L. Bowles John F. Bergstrom Robert A. Cornog Ulice Payne, Jr.	•      Review and monitor the Company’s current and long-range financial policies and strategies, including its capital structure and dividend policy. •      Authorize issuance of corporate debt within limits set by the Board. •      Discuss policies with respect to risk assessment and risk management. •      Review, approve and monitor the Company’s capital and operating budgets. •      The Committee conducted three meetings in 2003.

Directors of WEC are also directors of WE and, as such, WE relies on WEC’s Corporate Governance Committee for identifying and evaluating director nominees. WEC’s Corporate Governance Committee is also responsible for establishing and reviewing the Corporate Governance Guidelines to ensure the Board is effectively performing its fiduciary responsibilities to stockholders. The members of the Corporate Governance Committee are Willie D. Davis (Chair), Barbara L. Bowles, and Robert A. Cornog. WEC’s Corporate Governance Committee conducted three meetings in 2003.

The Board also has an Executive Committee which may exercise all powers vested in the Board except action regarding dividends or other distributions to stockholders, filling Board vacancies and other powers which by law may not be delegated to a committee or actions reserved for a committee comprised of independent directors. The Executive Committee did not meet in 2003. The members of the Executive Committee are Richard A. Abdoo (Chair), John F. Bergstrom, Barbara L. Bowles, Robert A. Cornog and Frederick P. Stratton, Jr. Gale E. Klappa will become the Chair of the Executive Committee upon Mr. Abdoo’s retirement.

In addition to the number of committee meetings listed in the preceding table, the Board met seven times in 2003. The average meeting attendance during the year was 94%. No director attended fewer than 85% of the total number of meetings of the Board and Board committees on which he or she served.

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INDEPENDENT AUDITORS

Deloitte & Touche LLP served as independent auditors for the Company for the fiscal years ended December 31, 2003 and 2002, and was selected by the Audit and Oversight Committee as the independent auditors for the Company for the fiscal year ending December 31, 2004.

Representatives of Deloitte & Touche LLP are not expected to be present at the meeting, but are expected to attend WEC’s annual meeting of stockholders on May 5, 2004. They will have an opportunity to make a statement at WEC’s annual meeting, if they so desire, and are expected to respond to appropriate questions that may be directed to them.

The Company engaged Deloitte & Touche LLP as independent auditors for the fiscal year ended December 31, 2002 on July 3, 2002 following the dismissal of Arthur Andersen LLP as independent auditors for the Company on July 3, 2002. Both the dismissal of Arthur Andersen LLP and the engagement of Deloitte & Touche LLP were based on the recommendation of WEC’s Audit and Oversight Committee. Arthur Andersen LLP was engaged on March 8, 2001 as independent public accountants for the Company for the fiscal year ended December 31, 2001 based on the recommendation of WEC’s Audit and Oversight Committee.

The report of Arthur Andersen LLP on the financial statements for the fiscal year ended December 31, 2001 contained no adverse opinion or disclaimer of opinion and was not qualified or modified as to uncertainty, audit scope or accounting principles. Between March 8, 2001 (the date of Arthur Andersen LLP’s appointment as the Company’s auditors) and the termination of Arthur Andersen LLP’s appointment, there were no disagreements with Arthur Andersen LLP on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of Arthur Andersen LLP, would have caused that firm to make reference to the subject matter of the disagreement in connection with its report on the Company’s financial statements, and there were no “reportable events” (as defined in SEC Regulation S-K Item 304(a)(1)(v)). Between January 1, 2000 and the engagement of Deloitte & Touche LLP on July 3, 2002, neither the Company nor anyone acting on behalf of the Company consulted with Deloitte & Touche LLP regarding either (i) the application of accounting principles to a specified transaction or the type of audit opinion that might be rendered on the Company’s financial statements or (ii) any matter that was either the subject of a disagreement with Arthur Andersen LLP or a “reportable event” (as defined in SEC Regulation S-K Item 304(a)(1)(v)).

Pre-Approval Policy for 2003.As stated in its charter, the Audit and Oversight Committee is responsible for reviewing and approving, in advance, all audit and non-audit services of the independent auditor. The Committee, which worked in conjunction with WEC’s Audit and Oversight Committee, approved the engagement of Deloitte & Touche LLP to audit the financial statements of WE for fiscal 2003, and to provide certain non-audit services to WEC and its subsidiaries, including WE, in an amount not to exceed $500,000. The non-audit services pre-approved by the Committee included the annual audit of the various employee benefit plans as required by ERISA, preparation and filing of Form 5500s in connection with the various employee benefit plans, expatriate tax compliance, consultation on international and domestic tax issues, and assistance in international tax compliance. No fees were paid to Deloitte & Touche LLP pursuant to the “de minimus” exception to the pre-approval policy permitted under the Securities and Exchange Act of 1934, as amended.

Fee Table.The following table shows the fees for professional audit services provided by Deloitte & Touche LLP for the audit of WE’s annual financial statements for fiscal years 2002 and 2003 and fees billed for other services rendered during those periods. Certain amounts for 2002 have been reclassified to conform to the 2003 presentation.

		2002		2003
Audit Fees(1)		$	225,575	$	349,563
Audit-Related Fees(2)			21,500		31,925
Tax Fees(3)			21,350		49,554
All Other Fees(4)			—		—
Total		$	268,425	$	431,042
	��

(1) Audit Fees: Fees for the professional services rendered for the audit of WE’s annual financial statements, review of financial statements included in the Company’s 10-Q filings, and services normally provided in connection with statutory and regulatory filings or engagements.

(2) Audit-Related Fees:Fees for assurance and related services that are reasonably related to the performance of the audit or review of WE’s financial statements. This included benefit plan audits and other related services.

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(3) Tax Fees: Fees for professional services rendered with respect to tax compliance, tax advice and tax planning. This includes preparation of tax returns, claims for refunds, payment planning and tax law interpretation. Deloitte & Touche LLP did not provide any tax strategy consulting in 2003.

(4) All Other Fees:Deloitte & Touche LLP did not provide any services in 2002 or 2003 that should be reported in this category.

AUDIT AND OVERSIGHT COMMITTEE REPORT

The Audit and Oversight Committee, which is comprised solely of independent directors, oversees the integrity of the financial reporting process on behalf of the Board of Directors of Wisconsin Electric Power Company. In addition, the Committee ensures compliance with legal and regulatory requirements. The Committee is also responsible for the appointment, compensation, retention and oversight of the Company’s independent auditor, as well as the oversight of the Company’s internal audit function. The Committee operates under a written charter approved by the Board of Directors, which can be found in the “Governance” section of WEC’s website at www.WisconsinEnergy.com.

Management is responsible for the Company’s financial reporting process, the preparation of consolidated financial statements in accordance with generally accepted accounting principles and the system of internal controls and procedures designed to ensure compliance with accounting standards and applicable laws and regulations. WE’s independent auditors are responsible for performing an independent audit of the Company’s consolidated financial statements in accordance with generally accepted auditing standards and to issue a report thereon.

The Committee held seven meetings during fiscal 2003. Meetings are designed to facilitate and encourage open communication among the members of the Committee, management, the internal auditors and the Company’s independent auditor, Deloitte & Touche LLP. During these meetings, we reviewed and discussed with management, among other items, the Company’s quarterly and annual financial statements and the system of internal controls designed to ensure compliance with accounting standards and applicable laws. We reviewed the financial statements and the system of internal controls with the Company’s independent auditor, both with and without management present. The Committee discussed with Deloitte & Touche LLP matters relating to communications with audit committees as required by Statement on Auditing Standards No. 61, as amended.

In addition, we received the written disclosures and the letter relative to auditor independence from Deloitte & Touche LLP, as required by Independence Standards Board Standard No. 1. The Committee discussed this information with Deloitte & Touche LLP and also considered the compatibility of non-audit services provided by Deloitte & Touche LLP with maintaining its independence.

Based on these reviews and discussions, the Audit and Oversight Committee recommended to the Board of Directors that the audited financial statements be included in WE’s Annual Report on Form 10-K for the fiscal year ended December 31, 2003 for filing with the Securities and Exchange Commission.

Respectfully submitted to Wisconsin Electric Power Company stockholders by the Audit and Oversight Committee of the Board of Directors.

Barbara L. Bowles, Committee Chair

John F. Bergstrom

Robert A. Cornog

Ulice Payne, Jr.

Frederick P. Stratton, Jr.

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COMPENSATION OF THE BOARD OF DIRECTORS

In December 2003, based upon data provided by an independent compensation consultant, the Board approved a change in director compensation practice. The change, effective January 1, 2004, was approved to align WE director compensation with director compensation at WE’s peer companies and to reflect emerging governance and compensation trends with regard to equity compensation. Employee directors do not receive any directors’ fees.

In addition, to more closely link directors’ pay to the Company’s performance and to further align the Board’s interests with stockholders, in December 2003, the Board adopted a stock ownership guideline for directors. Under this guideline, directors are generally expected to hold WEC common stock in an amount equal to five times the director’s annual retainer acquirable within five years of the commencement of board service.

For 2004, each non-employee director will receive an annual retainer fee of $36,000 paid in cash. Non-employee chairs of Board committees will receive a quarterly retainer of $1,250. Non-employee directors will receive a fee of $1,500 for each Board or committee meeting attended. In addition, a per diem fee of $1,250 for travel on Company business will be paid for each day on which a Board or committee meeting is not also held. The Company will reimburse non-employee directors for all out-of-pocket travel expenses. Non-employee directors will be paid $300 for each signed, written unanimous consent in lieu of a meeting. Each non-employee director also received on January 2, 2004, annual stock compensation in the form of WEC restricted stock equal to a value of $65,000, vesting in three years, for serving as a director of WE and WEC.

During 2003, each non-employee director received an annual retainer fee of $24,000. This fee was paid half in WEC common stock and half in cash. For 2003, compensation for chairs of committees, attendance at Board or committee meetings, written consents, and per diem for travel were the same as listed above for 2004. Non-employee directors did not receive restricted stock in 2003, but instead received an option to purchase 5,000 shares of WEC common stock under WEC’s 1993 Omnibus Stock Incentive Plan, as amended, for serving as a director of WE and WEC. Each option had an exercise price equal to the fair market value of the shares on the date the option was granted and is exercisable for 10 years after the date of grant. The options vest over a three-year period on the anniversary of the grant date. Upon a change in control of WEC, disability or death, or if the director leaves the Board after completing a full three-year term, these options become immediately exercisable. The exercise price of an option may, at the non-employee director’s election, be paid in cash or with previously owned shares of common stock or a combination thereof.

Although WE directors also serve on the Wisconsin Energy Corporation and Wisconsin Gas Company boards, a single annual retainer is paid and only single fees are paid for meetings held on the same day. In these cases, fees are allocated between WEC, Wisconsin Electric Power Company and Wisconsin Gas Company based on services rendered.

Non-employee directors may defer fees pursuant to the Directors’ Deferred Compensation Plan. Deferred amounts are credited to one of ten measurement funds, including a WEC phantom stock account. The value of these accounts will appreciate or depreciate based on market performance, as well as through the accumulation of reinvested dividends. Deferral amounts are credited to accounts in the name of each participating director on the books of WEC, are unsecured and are payable only in cash following termination of the director’s service to WEC and its subsidiaries. The deferred amounts will be paid out of the general corporate assets or the trust described under “Retirement Plans” in this information statement.

A Directors’ Charitable Awards Program has been established to help further WEC’s policy of charitable giving. Under the program, WEC intends to contribute up to $100,000 per year for 10 years to a charitable organization(s) chosen by each director, upon the director’s death. All directors are provided with one charitable award benefit for serving on the boards of WEC and its subsidiaries, including WE. There is a vesting period of three years of service on the Board required for participation in this program. Beneficiary organizations under the program must be approved by WEC’s Corporate Governance Committee. The program is funded by life insurance on the lives of the Board members. Directors derive no financial benefit from the program since all insurance proceeds and charitable deductions accrue solely to the Company. Because of the tax deductibility of these charitable donations and the use of insurance as a funding vehicle, the long-term cost to the Company is expected to be modest.

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COMPENSATION COMMITTEE REPORT ON EXECUTIVE COMPENSATION

Compensation Philosophy and Objectives.The Compensation Committee, which works in conjunction with WEC’s Compensation Committee, is responsible for making decisions regarding compensation for the executives of Wisconsin Energy Corporation and its principal subsidiaries, including Wisconsin Electric Power Company. All Committee members are independent directors. We seek to provide a competitive, performance-based executive compensation program that enables WE to attract and retain key individuals and to motivate them to achieve short- and long-term goals.

We believe that a substantial portion of executive compensation should be at risk. As a result, the compensation plans have been structured so that the level of total compensation is strongly dependent upon achievement of business results that are aligned with the interests of WEC’s stockholders and customers.

The primary elements of the executive compensation program are base salary, annual incentive compensation, and long-term incentive compensation. For WE executives who also hold WEC positions, all elements of compensation are targeted at the 50th percentile of general industry practices — that is, we target compensation at the median levels paid for similar positions at similarly sized companies. For WE executives whose positions principally relate to utility operations, we place a greater emphasis upon compensation practices in the energy industry. In order to determine competitive compensation practices, we rely upon compensation surveys provided to us by Towers Perrin, an independent compensation consultant.

Specific values of 2003 compensation for the Chief Executive Officer, the four other most highly compensated executive officers, including former Chief Executive Officer and current Chairman of the Board Abdoo, and Messrs. Grigg and Donovan, who would have been among the four most highly compensated officers but for the fact that they were not serving as executive officers at the end of fiscal 2003, are shown in the Summary Compensation Table. Our basis for determining each element of compensation is described below.

Base Salary.For 2003, we adjusted base salaries to reflect updated survey results of executive compensation practices for similar positions at comparable companies. In making these adjustments, we also considered factors such as the relative levels of individual experience, performance, responsibility, and contribution to the results of Company operations.

Annual Incentive Compensation.The annual incentive plan provides for annual awards to executives based on achievement of pre-established stockholder, customer, and employee-focused objectives. All payments under the plan are at risk; payments are only made if performance goals are achieved, and awards may be less or greater than targeted amounts based on actual performance. Based upon a review of competitive practices for comparable positions at similarly sized companies, awards for 2003 were targeted at 35% to 100% of base salary and actual awards may range from 0% to 200% based on performance. The plan also provides the Committee with the discretion to recognize individual performance.

At the Committee’s direction, the annual performance incentive program for 2003 principally focused on the attainment of key financial measures including WEC’s earnings per share, return on equity and cash flow. Performance met or exceeded the target levels in each of these areas for 2003, resulting in bonuses that exceeded the target levels.

Based upon these results and any discretion to recognize individual performance, awards for 2003 were granted to the named executive officers as shown in the Summary Compensation Table. Awards were also granted to other executives based on comparable results.

For 2004, the Committee set goals for key officers of WE differently than those set for 2003. The Committee recognized the effect non-financial measures have on overall performance of the Company. In addition to financial performance, executives’ final awards will also be impacted by performance in three key operational areas: customer satisfaction, safety and diversity. In general, the annual incentive is dependent upon the financial achievement determined by performance against recurring budget targets for earnings per share and cash flow. Performance against the three operational areas will either increase or decrease final awards by up to 10%.

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Long-Term Incentive Compensation.The Committee administers WEC’s 1993 Omnibus Stock Incentive Plan, as amended. This is a stockholder approved, long-term incentive plan designed to link the interests of executives and other key employees to long-term stockholder value. It allows for various types of awards keyed to the performance of WEC’s common stock, including stock options.

In 2003, we reviewed the long-term incentive program to ensure its effectiveness in focusing executives to achieve long-term objectives. Awards to named executive officers were granted as indicated in the Summary Compensation Table.

Our Committee believes that an important adjunct to the long-term incentive program is significant WEC stock ownership by participants. Accordingly, as a condition of participating in the long-term incentive plan, we have implemented WEC stock ownership guidelines for officers of WE that must be attained within a five-year period. Guidelines for executive officers range from 100% to 300% of base salary.

As a result of their retirements as executive officers, Messrs. Grigg and Donovan will receive the benefits to which they are entitled under their employment, severance and retirement arrangements described under “Employment and Severance Arrangements” and “Retirement Plans” in this information statement.

For 2004, in order to model best practices in the industry, the Committee modified the long-term incentive program to include a performance share component. With the use of performance shares, the amount of shares of WEC stock ultimately vested is dependent upon performance against a pre-established target, instead of vesting due to the passage of time. This better aligns executive financial interests with those of stockholders and long-term interests of customers.

Performance of WEC stock will be measured against the Custom Peer Group. The Custom Peer Group Index is a market-capitalization-weighted index consisting of 30 companies, including WEC. These companies compare to WEC in terms of business model and size. All of the companies in the Custom Peer Group Index receive at least 80% of their revenue from gas and/or electric utility operations.

The companies in the Custom Peer Group Index are Allegheny Energy Inc., Alliant Energy Corporation, Ameren Corporation, American Electric Power Inc., Avista Corporation, Cinergy Corporation, Consolidated Edison Inc., DTE Energy Company, Energy East Corporation, Entergy Corporation, Exelon Corporation, FirstEnergy Corporation, FPL Group Inc., NiSource Inc., Northeast Utilities, Nstar, OGE Energy Corporation, Pinnacle West Capital Corporation, Pepco Holdings Inc., Progress Energy Inc., Public Service Enterprise Group Inc., Puget Energy Corporation, Scana Corporation, Sempra Energy, Sierra Pacific Resources Inc., Southern Company Inc., Westar Energy Inc., Wisconsin Energy Corporation, WPS Resources Corporation, and Xcel Energy Inc.

Chief Executive Officer Compensation.The assessment of the chief executive officer’s performance for determination of the CEO’s compensation is among our principal responsibilities. During 2003, Mr. Gale E. Klappa succeeded Mr. Richard A. Abdoo as WE’s CEO.

In reviewing the performance of Mr. Abdoo, we requested that all non-employee directors evaluate his performance. The Compensation Committee chair reviewed the evaluations and factored the results into our compensation determinations. The Committee met with Mr. Abdoo to discuss the results. The Committee will use a similar process with respect to Mr. Klappa when he completes his first full year as CEO.

Base salaries for Messrs. Abdoo and Klappa were set as shown in the Summary Compensation Table. These base salaries are at the low end of the competitive range for CEOs at comparably sized companies as reflected in the survey of general industry compensation practices. Mr. Abdoo’s annual incentive compensation for 2003 was based upon achievement of the measures described above under Annual Incentive Compensation. Mr. Klappa’s annual incentive compensation was principally based on the terms of his employment agreement, which awarded him a one-time signing bonus of $350,000 and guaranteed a minimum annual bonus of $576,000 in 2003.

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In view of the discretionary component of the annual incentive plan, the Committee also noted the significant accomplishments of Messrs. Abdoo and Klappa during 2003, including, among other things:

• Milestones achieved with respect to implementation of WEC’sPower the Future strategic plan, including:

— Commencement of demolition of the existing coal-based generating units at Port Washington Power Plant to make room for two new 545-megawatt natural gas-fired generating facilities, and the start of construction of one facility; and

— Receipt of approval to construct two 615-megawatt coal-fueled super-critical pulverized coal units at Oak Creek for operation in 2009 and 2010;

• Their role in the management succession initiative, which culminated in hiring individuals for key executive positions with proven leadership skills and extensive experience in the energy industry to guide the Company’s strategic future; and

• Receipt of the Reliability One Award for superior electric system reliability in the Midwest region for the second consecutive year.

To specifically link a portion of compensation to the enhancement of long-term stockholder value, Messrs. Abdoo and Klappa were awarded long-term incentive compensation in 2003 in the form of stock options, as set forth in the “Long-Term Compensation Awards” column of the Summary Compensation Table.

Mr. Abdoo will retire from all positions with WEC and its subsidiaries, including WE, effective April 30, 2004. Mr. Abdoo’s retirement will not invoke the provisions of his employment agreement providing for severance payments. As a result of his retirement, Mr. Abdoo will be entitled to receive the retirement benefits described under “Retirement Plans” in this information statement.

Compliance With Tax Regulations Regarding Executive Compensation.Section 162(m) of the Internal Revenue Code limits tax deductions for executive compensation to $1 million, unless certain requirements are met. It is our policy to take reasonable steps to obtain the corporate tax deduction by qualifying for the exemptions from limitation on such deductibility under Section 162(m) to the extent practicable. Nevertheless, maintaining tax deductibility is but one consideration among many in the design of the executive compensation program. The Committee may, from time to time, conclude that compensation arrangements are in the best interest of WE and WEC’s stockholders despite the fact that such arrangements might not, in whole or in part, qualify for tax deductibility.

Respectfully submitted to Wisconsin Electric Power Company’s stockholders by the Compensation Committee of the Board of Directors.

John F. Bergstrom, Committee Chair

John F. Ahearne

Willie D. Davis

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EXECUTIVE OFFICERS’ COMPENSATION

The following table summarizes, for the last three fiscal years, compensation awarded to, earned by, or paid to the Company’s Chief Executive Officer, each of the Company’s other four most highly-compensated executive officers who were serving as executive officers at the end of fiscal 2003, and Messrs. Grigg and Donovan, who would have been among the four most highly compensated officers but for the fact that they were not serving as executive officers at the end of fiscal 2003. The amounts shown in this and all subsequent tables in this information statement are WEC consolidated compensation data.

Summary Compensation Table

Name and Principal Position	Year	Annual Compensation					Long-Term Compensation Awards		All Other Compensation(2) ($)
		Salary ($)	Bonus ($)		Other Annual Compensation ($)		Restricted Stock Awards(1) ($)	Securities Underlying Options (#)
Gale E. Klappa
President and Chief Executive Officer of WE since August 2003; President of WEC since April 2003	2003	458,179	1,075,000	(3)	131,740	(4)	1,006,320	250,000	12,952
Richard A. Abdoo
Chairman of the Board and former Chief Executive Officer of WE; Chairman of the Board and Chief Executive Officer of WEC(5)	2003	794,004	1,500,000		11,749		0	300,000	49,099
	2002	756,300	859,308		11,868		0	300,000	66,959
	2001	707,500	563,948		11,811		163,120	300,000	66,875
Allen L. Leverett
Chief Financial Officer of WE and WEC since July 2003	2003	230,004	690,000	(3)	66,025	(4)	846,748	200,000	6,900
Larry Salustro
Senior Vice President and General Counsel of WE and WEC	2003	360,000	375,000		2,550		306,600	125,000	14,370
	2002	336,000	323,331		2,297		0	75,000	34,075
	2001	311,668	165,797		2,339		122,340	75,000	33,956
Frederick D. Kuester
Chief Operating Officer of WE since October 2003	2003	110,508	400,000	(3)	1,976		749,547	200,000	2,500
Richard R. Grigg
President of WE until July 2003; Executive Vice President of WEC and Chief Operating Officer of WE until October 2003; Special Advisor to the President of WEC after October 2003	2003	579,600	463,680	(3)	7,456		0	200,000	3,458,102
	2002	518,668	507,879		4,015		0	200,000	52,874
	2001	440,000	350,719		4,128		122,340	131,535	98,545
Paul Donovan
Executive Vice President and Chief Financial Officer of WE and WEC until June 2003; Special Advisor to the Chairman and CEO of WEC after June 2003	2003	579,600	463,680	(3)	4,064		0	200,000	31,031
	2002	518,668	471,448		206,057	(4)	0	200,000	53,643
	2001	440,000	282,333		28,760		122,340	131,535	65,463

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⁽¹⁾ In 2003, restricted stock awards were granted to Messrs. Klappa, Leverett, Salustro and Kuester in the amounts of 39,510 shares, 28,850 shares, 12,000 shares, and 24,140 shares respectively, which are subject to forfeiture until vested. The dollar values shown for these shares are based on the closing market prices of WEC common stock of $25.47, $29.35, $25.55 and $31.05 per share, respectively, on the grant dates. Mr. Klappa’s restricted stock award, granted pursuant to his employment agreement, will vest at the rate of 10% per year of service with WEC. Under Mr. Leverett’s restricted stock award, granted pursuant to his employment agreement, two-thirds of his restricted stock will vest on July 1, 2005, the second anniversary of his employment starting date, and the remainder will vest at the rate of 20% for each year of service thereafter. The shares awarded to Mr. Salustro vest upon his retirement at or after attainment of age 60. Mr. Kuester’s restricted stock award, granted pursuant to his employment agreement, vests at a rate of 10% per year of service with WEC for the next ten years. Pursuant to their terms, the shares of restricted stock previously granted to Mr. Abdoo will vest upon his retirement on April 30, 2004. However, in each case, earlier vesting may occur due to termination of employment by death, disability, a change in control of WEC or action by the Compensation Committee. Dividends are paid on shares of restricted stock at the same rate as on unrestricted shares and are used to acquire additional restricted shares. As of December 31, 2003, the named executive officers held the following number of shares of restricted stock, including restricted dividends, with the following values (based on a closing price of $33.45 on December 31, 2003): Mr. Klappa—40,308 shares ($1,348,303), Mr. Abdoo—37,764 shares ($1,263,206), Mr. Leverett—29,223 shares ($977,509), Mr. Salustro—28,308 shares ($946,903), Mr. Kuester— 24,287 shares ($812,400) Mr. Grigg—22,817 shares ($763,229) and Mr. Donovan—20,337 shares ($680,273).

⁽²⁾ All Other Compensation for 2003 for each of Messrs. Klappa, Abdoo, Leverett, Salustro, Kuester, Grigg and Donovan, includes:

• employer matching of contributions into the 401(k) plan in the amount of $3,352, $5,500, $0, $5,430, $200, $5,935 and $5,500, respectively,

• “make whole” payments under the Executive Deferred Compensation Plan with respect to matching in the 401(k) plan on deferred salary or salary received but not otherwise eligible for matching in the amounts of $9,600, $43,599, $6,900, $8,940, $2,300, $14,577 and $25,531, respectively, and

• a lump-sum severance payment in the amount of $3,437,590 to Mr. Grigg, which was accrued in fiscal 2003, but was paid out in March 2004.

⁽³⁾ Under their employment agreements, Messrs. Klappa, Leverett, and Kuester received one-time signing bonuses of $350,000, $250,000, and $200,000 respectively, and minimum guaranteed annual bonuses for 2003 of $576,000, $368,000, and $150,000 respectively. Annual bonus amounts for 2003 for Messrs. Grigg and Donovan are guaranteed based on their employment and severance agreements.

⁽⁴⁾ Other Annual Compensation for 2003 for Mr. Klappa and Mr. Leverett includes payments of relocation expenses in the amounts of $95,174 and $52,164, respectively. Other Annual Compensation for 2002 for Mr. Donovan includes $50,474 associated with payment of legal expenses and $53,989 primarily associated with temporary housing expenses, as well as income tax payments related to those items.

⁽⁵⁾ Mr. Abdoo retired as Chief Executive Officer of WE in August 2003. In addition, as discussed elsewhere in this information statement, effective as of April 30, 2004, Mr. Abdoo will retire from all officer and director positions with WEC and its subsidiaries, including WE, and will retire as an employee.

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Option Grants in Last Fiscal Year

This table shows additional data regarding the options granted in 2003 to the named executive officers.

	Individual Grants(1)				Grant Date Value
Name	Number of Securities Underlying Options Granted (#)	Percent of Total Options Granted to Employees in Fiscal Year (%)	Exercise or Base Price ($/Share)	Expiration Date	Grant Date Present Value(2) ($)
Gale E. Klappa	250,000	8.58	25.31	04/14/2013	1,623,500
Richard A. Abdoo	300,000	10.30	25.41	01/02/2013	2,049,900
Allen L. Leverett	200,000	6.87	29.13	07/01/2013	1,520,600
Larry Salustro	125,000	4.29	25.41	01/02/2013	854,125
Frederick D. Kuester	200,000	6.87	31.07	10/13/2013	1,781,800
Richard R. Grigg	200,000	6.87	25.41	01/02/2013	1,366,600
Paul Donovan	200,000	6.87	25.41	01/02/2013	1,366,600

⁽¹⁾ Consists of incentive and non-qualified stock options to purchase shares of WEC common stock granted on January 2, April 14, July 1, and October 13, 2003 pursuant to the 1993 Omnibus Stock Incentive Plan, as amended. These options have exercise prices equal to the fair market value of the WEC shares on the date of grant and vest pro rata over a four-year period beginning on the first anniversary of the grant date with full vesting on the fourth anniversary date. Upon a “change in control” of WEC, as defined in the plan, or upon retirement, permanent total disability or death of the option holder, options granted under the plan become immediately exercisable. These options were granted for a term of ten years, subject to earlier termination in certain events related to termination of employment. In the discretion of the Compensation Committee, the exercise price may be paid by delivery or attestation of already-owned shares. Tax withholding obligations related to exercise may be satisfied by withholding shares otherwise deliverable upon exercise, subject to certain conditions. Subject to the limitations of the 1993 Omnibus Stock Incentive Plan, as amended, the Compensation Committee has the power with the participant’s consent to modify or waive the restrictions on vesting of these options, to amend these options and to grant extensions or to accelerate the vesting of these options.

⁽²⁾ An option-pricing model (developed by Black-Scholes) was used to determine the options’ present value as of the date of the grant. The assumptions used in the Black-Scholes equation for options expiring January 2, 2013 are: market price of stock: $25.41; exercise price of option: $25.41; stock volatility: 26.12%; annualized risk-free interest rate: 4.54%; exercise at the end of the 10-year option term; and dividend yield: 3.15%. The assumptions for options expiring April 14, 2013 are: market price of stock: $25.31; exercise price of option: $25.31; stock volatility: 25.14%; annualized risk-free interest rate: 4.38%; exercise at the end of the 10-year option term; and dividend yield: 3.16%. The assumptions for options expiring July 1, 2013 are: market price of stock: $29.13; exercise price of option: $29.13; stock volatility: 24.51%; annualized risk-free interest rate: 3.93%; exercise at the end of the 10-year option term; and dividend yield: 2.75%. The assumptions for options expiring October 13, 2013 are: market price of stock: $31.07; exercise price of option: $31.07; stock volatility: 23.47%; annualized risk-free interest rate: 4.78%; exercise at the end of the 10-year option term; and dividend yield: 2.57%. WEC’s use of this model should not be construed as an endorsement of its accuracy. The ultimate value of the options, if any, will depend upon the future value of the WEC common stock, which cannot be forecast with reasonable accuracy, and on the optionee’s investment decisions.

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Aggregated Option Exercises in Last Fiscal Year and Fiscal Year-End Option Values

The following table reflects options exercised in 2003 and the number and value of exercisable and unexercisable in the money options held by the named executive officers at fiscal year-end.

Name	Shares Acquired on Exercise (#)	Value Realized ($)(1)	Number of Securities Underlying Unexercised Options at Fiscal Year-End (#)			Value of Unexercised In the Money Options at Fiscal Year-End ($)(2)
			Exercisable		Unexercisable	Exercisable	Unexercisable
Gale E. Klappa	—	—	—		250,000	—	2,035,000
Richard A. Abdoo	22,500	105,525	480,999		700,001	4,597,502	7,002,913
Allen L. Leverett	—	—	—		200,000	—	864,000
Larry Salustro	—	—	153,749		231,251	1,531,992	2,270,495
Frederick D. Kuester	—	—	—		200,000	—	476,000
Richard R. Grigg	263,015	2,341,269	—		434,520	—	4,139,088
Paul Donovan	131,136	1,113,330	42,137	(3)	434,519	389,789	4,139,074

⁽¹⁾ Value realized is determined by subtracting the exercise price from the fair market value on the date of exercise. Fair market value is the average of the high and low prices reported in the New York Stock Exchange Composite Transaction report on the exercise date.

⁽²⁾ Value is determined by subtracting the exercise price from the year-end market price multiplied by the number of shares underlying the option.

⁽³⁾ Excludes options for 28,743 shares, with an in the money value of $309,199 that were transferred to and are held by trusts for the benefit of Mr. Donovan’s family.

EMPLOYMENT AND SEVERANCE ARRANGEMENTS

Pursuant to the merger agreement relating to WEC’s acquisition of WICOR, Inc., on June 27, 1999, WEC adopted severance policies that became effective on April 26, 2000, when the merger occurred, replacing WEC’s previous severance policy. The policies provide for severance benefits to designated executives and other key employees if within two years after the merger they were discharged without cause or resign with good reason. WEC has approved changes to the severance policies (i) to continue the policies after the end of the two-year period following the WICOR merger to provide for severance benefits in the event of employment termination either in anticipation of or within a two-year period following a change in control by reason of discharge without cause or resignation with good reason, and (ii) to allow for a deferral opportunity for participants who may become entitled to benefits.

Under the current severance policies, participants have been designated into one of four benefit levels. Of the individuals named in the Summary Compensation Table, Mr. Salustro is a Tier 2 participant. Messrs. Klappa, Abdoo, Leverett, Kuester, Grigg and Donovan do not participate in the severance policy, but each has a separate change in control and severance agreement as described below.

Tier 2 benefits provide generally for lump sum severance payments equal to three times the sum of the current base salary and the highest bonus in the last three years (or the then current target bonus, if higher), a pension lump sum for the equivalent of three years’ worth of additional service and three years’ continuation of health and life insurance coverage. An overall limit is placed on benefits to avoid federal excise taxes under the “parachute payment” provisions of the tax law.

WEC has entered into agreements with each of Messrs. Abdoo, Klappa, Leverett, Kuester, Grigg and Donovan providing for certain employment and severance benefits as described below.

• Under the agreement with Mr. Abdoo, severance benefits are provided if his employment is terminated (i) by WEC, other than for cause, death or disability, in anticipation of or following a change in control, (ii) by the executive for good reason following such a change in control, (iii) by the executive within six months after completing one year of service following a change in control, or (iv) in the absence of a change in control, by WEC for any reason other than cause, death or disability or by the executive for good reason. The agreement provides for a lump sum severance payment equal to three times the sum of the executive’s highest annual base salary in effect in the last three years and highest bonus amount. The highest bonus amount would be calculated as the largest of (i) the current target bonus for the fiscal year in which employment termination occurs, (ii) the highest bonus paid in any of the last three fiscal years of WEC prior to termination or the change

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in control, or (iii) an amount calculated by multiplying the highest bonus percentage earned during either of such three fiscal year periods times the highest yearly base salary rate in effect during the three-year period ending prior to termination. The agreement also provides for three years’ continuation of health and certain other welfare benefit coverage, eligibility for retiree health coverage thereafter, a payment equal to the value of three additional years’ of participation in the applicable qualified and non-qualified retirement plans, full vesting in all outstanding stock options and restricted stock awards, certain financial planning services and other benefits and a “gross-up” payment should any payments or benefits under the agreements trigger federal excise taxes under the “parachute payment” provisions of the tax law. The agreement also contains a one-year non-compete provision applicable on termination of employment.

• Mr. Klappa commenced employment with WEC on April 14, 2003. Mr. Klappa’s employment agreement is substantially similar to Mr. Abdoo’s, except that if an event triggering severance benefits occurs, Mr. Klappa will receive an additional benefit based upon the difference between the retirement benefits that he would have received from his prior employer and the retirement benefits received from WEC. Mr. Klappa’s agreement provides that, for 2003, he will receive an annual base salary of $640,000 and a special lump sum signing bonus of $350,000 (with $250,000 paid on his employment starting date and the balance six months later). Mr. Klappa’s target bonus opportunity is fixed at 90% of his base salary, with a minimum guaranteed bonus of $576,000 for 2003. Upon his employment with WEC, Mr. Klappa was granted a non-qualified stock option for 250,000 shares of WEC’s common stock. He was also granted a restricted stock award for 39,510 shares which vests at the rate of 10% for each year of service until 100% vesting occurs on the tenth anniversary of his employment starting date, provided that the restricted stock will become 100% vested due to a termination of employment by death, disability or a change in control of WEC.

• Mr. Leverett commenced employment with WEC on July 1, 2003. Mr. Leverett’s employment agreement is substantially similar to Mr. Klappa’s, except that (i) if Mr. Leverett’s employment is terminated by WEC for any reason other than cause, death or disability or by the executive for good reason in the absence of a change in control, the special lump sum severance benefit is two times the sum of his highest annual base salary and highest bonus amount, (ii) the welfare benefits are provided for a two-year period and (iii) the special retirement plan lump sum is calculated as if his employment continued for a two-year period following termination of employment. The agreement provides that, for 2003, Mr. Leverett will receive an annual base salary of $460,000 and a special lump sum signing bonus of $250,000 (with $150,000 paid on his employment starting date and the balance paid six months later). Mr. Leverett’s target bonus opportunity is fixed at 80% of base salary, with a minimum guaranteed bonus of $368,000 for 2003. Upon his employment with the Company, Mr. Leverett was granted a non-qualified stock option for 200,000 shares of WEC’s common stock. Mr. Leverett was also granted a restricted stock award for 28,850 shares on his employment starting date. Two-thirds of the shares vest on July 1, 2005, the second anniversary of his employment starting date and the remaining one-third vest at the rate of 20% for each year of service thereafter until 100% vesting occurs on the seventh anniversary of the employment starting date, provided that the restricted stock will become 100% vested due to a termination of employment by death, disability or a change in control of WEC.

• WEC entered into an employment agreement with Mr. Kuester, which is effective as of October 13, 2003. The agreement provides severance benefits to Mr. Kuester if his employment is terminated by WEC for any reason other than cause, death or disability or by Mr. Kuester for good reason in the absence of a change in control. This severance benefit includes a lump sum payment equal to two times the sum of Mr. Kuester’s highest annual base salary in effect for the three fiscal years preceding his termination and his highest bonus amount. The highest bonus amount is the larger of (i) the current target bonus for the fiscal year in which his employment termination occurs, or (ii) the highest bonus paid in any of the three fiscal years preceding the termination. This severance benefit also includes two years’ continuation of health and certain other welfare benefit coverage, eligibility for retiree health coverage thereafter, a payment equal to the value of two additional years’ of participation in the applicable qualified and non-qualified retirement plans, an additional benefit based upon the difference between the retirement benefits that he would have received from his prior employer and the retirement benefits received from WEC, full vesting in all outstanding stock options and restricted stock awards, certain financial planning services and other benefits. If Mr. Kuester has a covered termination in connection with a change in control, (i) the lump sum severance benefit is three times the sum of his highest annual base salary and highest bonus amount, (ii) the welfare benefits are provided for a three-year period, (iii) the special retirement plan lump sum is calculated as if his employment continued for a three-year period following termination of employment and (iv) there is a “gross-up” payment should any payments or benefits under the agreement trigger federal excise taxes under the “parachute payment” provisions of the tax law. The agreement also contains a one-year non-compete provision applicable on termination of employment. The agreement provides that, for 2003, Mr. Kuester will receive an annual base salary of $500,000 and a special lump sum signing bonus of $200,000 (with $100,000 paid on his employment starting date and the balance paid six months later). Mr. Kuester’s target bonus opportunity is fixed at 80% of base salary, with a minimum guaranteed bonus of $150,000 for 2003. Upon his employment with WEC, Mr. Kuester was granted a non-qualified stock option for 200,000 shares of WEC’s common stock. Mr. Kuester was also granted a restricted stock award for 24,140 shares, which vest at the rate of

19

10% for each year of service until 100% vesting occurs on the 10^th anniversary of his employment starting date, provided that the restricted stock will become 100% vested due to a termination of employment by death, disability or change in control of WEC.

• The agreement with Mr. Grigg was substantially similar to Mr. Abdoo’s. Pursuant to the terms of the agreement, on January 2, 2003, WEC granted to Mr. Grigg an option to purchase 200,000 shares of its common stock. Mr. Grigg retired from all officer titles with WEC and its subsidiaries, except those of Executive Vice President of WEC and Chief Operating Officer of WE effective July 31, 2003; subsequently he retired from those titles effective October 13, 2003, but he continued to be employed as a special advisor to Mr. Klappa until his retirement on March 1, 2004. Mr. Grigg’s retirement invoked certain provisions of his employment agreement that resulted in the severance payment in the Summary Compensation Table. Mr. Grigg’s 2003 bonus was fixed at 80% of his $579,600 base salary. Mr. Grigg continued to receive salary and a bonus equal to 80% of his salary through his March 1, 2004 retirement date. Pursuant to the terms of his employment agreement, all of Mr. Grigg’s outstanding options and restricted stock awards vested upon his retirement.

• The agreement with Mr. Donovan was similar to Mr. Abdoo’s. The agreement provided that as of January 1, 2003, Mr. Donovan’s annual base salary increased to $579,600 and his target bonus compensation was fixed at 80% of such increased salary. Pursuant to the terms of the agreement, on January 2, 2003, WEC granted to Mr. Donovan an option to purchase 200,000 shares of its common stock. Mr. Donovan retired from his officer positions with WEC and its subsidiaries as of June 30, 2003. He continued to be employed as a special advisor to Mr. Abdoo until his retirement on February 29, 2004. Under the terms of his employment agreement, all of Mr. Donovan’s outstanding stock options and restricted stock awards vested upon his retirement on February 29, 2004. In connection with Mr. Donovan joining WEC, he was encouraged to purchase a house in Wisconsin. In this regard, the agreement obligates WEC to repurchase, at Mr. Donovan’s request within seven years of his leaving WEC, his Wisconsin house at a price that would assure the after-tax recovery of his investment in that house or its then fair market value, whichever is greater.

RETIREMENT PLANS

WEC maintains a defined benefit pension plan of the cash balance type (the “WEC Plan”) for most employees, including Messrs. Klappa, Abdoo, Leverett, Salustro, Kuester, Grigg and Donovan. The WEC Plan bases a participant’s defined benefit pension on the value of a hypothetical account balance. For individuals participating in the WEC Plan as of December 31, 1995, a starting account balance was created equal to the present value of the benefit accrued as of December 31, 1994, under the plan benefit formula prior to the change to a cash balance approach. That formula provided a retirement income based on years of credited service and final average compensation for the 36 highest consecutive months, with an adjustment to reflect the Social Security integrated benefit. In addition, individuals participating in the WEC Plan as of December 31, 1995 received a special one-time transition credit amount equal to a specified percentage varying with age multiplied by credited service and 1994 base pay.

The present value of the accrued benefit as of December 31, 1994, plus the transition credit, was also credited with interest at a stated rate. For 1996 and thereafter, a participant receives annual credits to the account equal to 5% of base pay (including certain incentive payments, pre-tax deferrals and other items), plus an interest credit on all prior accruals equal to 4% plus 75% of the annual time-weighted trust investment return for the year in excess of 4%. Additionally, the WEC Plan provides that up to an additional 2% of base pay may be earned based upon achievement of earnings targets.

The life annuity payable under the WEC Plan is determined by converting the hypothetical account balance credits into annuity form.

Individuals who were participants in the WEC Plan on December 31, 1995 were “grandfathered” so that they will not receive any lower retirement benefit than would have been provided under the prior formula, had it continued, if their employment terminates on or before January 1, 2011.

For the individuals listed in the Summary Compensation Table, estimated benefits under both “grandfathered” formulas are higher than under the cash balance plan formula. As a result, their benefits would currently be determined by the prior plan benefit formula. The following table set forth estimated annual benefits payable in life annuity form on normal retirement for persons in various compensation and years of service classifications during 2003, based on the continuation of the “grandfathered” prior plan formulas for WEC (including supplemental amounts providing additional benefits described below in the “Other Retirement Benefits” section):

20

Pension Plan Table—WEC Plan (Prior Plan Formula)

	Remuneration	Years of Service
		15	20	25	30	35	40
$	300,000	74,501	99,334	124,168	149,002	163,106	177,210
	500,000	126,251	168,334	210,418	252,502	276,356	300,210
	700,000	178,001	237,334	296,668	356,002	389,606	423,210
	900,000	229,751	306,334	382,918	459,502	502,856	546,210
	1,100,000	281,501	375,334	469,168	563,002	616,106	669,210
	1,300,000	333,251	444,334	555,418	666,502	729,356	792,210
	1,500,000	385,001	513,334	641,668	770,002	842,606	915,210
	1,700,000	436,751	582,334	727,918	873,502	955,856	1,038,210
	1,900,000	488,501	651,334	814,168	977,002	1,069,106	1,161,210
	2,100,000	540,251	720,334	900,418	1,080,502	1,182,356	1,284,210
	2,300,000	592,001	789,334	986,668	1,184,002	1,295,606	1,407,201
	2,500,000	643,751	858,334	1,072,918	1,287,502	1,408,856	1,530,210
	2,700,000	695,501	927,334	1,159,168	1,391,002	1,522,106	1,653,210
	2,900,000	747,251	996,334	1,245,418	1,494,502	1,635,356	1,776,210

The compensation for the individuals listed in the Summary Compensation Table in the columns labeled “Salary” and “Bonus” is virtually equivalent to the compensation considered for purposes of the retirement plans and the various supplemental plans. Messrs. Klappa, Abdoo, Leverett, Salustro, Kuester, Grigg and Donovan, currently have or are considered to have 35, 35, 14, 31, 31, 33 and 31 credited years of service, respectively.

Other Retirement Benefits.Designated officers of Wisconsin Electric Power Company and WEC, including Messrs. Klappa, Abdoo, Leverett, Salustro, Kuester, Grigg, and Donovan participate in the Supplemental Executive Retirement Plan (“SERP”). The SERP provides monthly supplemental pension benefits to participants, which will be paid out of unsecured corporate assets, or the grantor trust described below, in an amount equal to the difference between the actual pension benefit payable under the pension plan and what such pension benefit would be if calculated without regard to any limitation imposed by the Internal Revenue Code on pension benefits or covered compensation. In addition, Messrs. Abdoo and Salustro are also entitled to an amount calculated so as to provide participants with a supplemental lifetime annuity, estimated to be between 8% and 10% of final average compensation depending on which pension payment option is selected. Except for a “change in control” of WEC, as defined in the SERP, no payments are made until after the participant’s retirement or death.

WEC has entered into agreements with Messrs. Abdoo, Salustro and Donovan who cannot accumulate by normal retirement age the maximum number of years of credited service under the pension plan formula in effect immediately before the change to the cash balance formula, as described below:

• According to Mr. Abdoo’s agreement, Mr. Abdoo at retirement will receive supplemental retirement payments which will make his total retirement benefits at age 58 or older substantially the same as those payable to employees who are age 60 or older, who are in the same compensation bracket and who became plan participants at the age of 25, offset by the value of any qualified or non-qualified defined benefit pension plans of prior employers.

• According to Mr. Salustro’s agreement, Mr. Salustro at retirement will receive supplemental retirement payments which will make his total retirement benefits at age 60 or older substantially the same as those payable to employees who are age 60 or older, who are in the same compensation bracket, and who became plan participants at the age of 25, offset by the value of any qualified or non-qualified defined benefit pension plans of prior employers.

• According to Mr. Donovan’s agreement, at retirement Mr. Donovan received supplemental retirement payments which made his total retirement benefits at age 55 or older substantially the same as those payable to employees who are in the same compensation bracket and who became plan participants at the age of 25, offset by the value of social security benefits and modified by early retirement reduction factors applicable to Mr. Donovan between ages 55 and 58.

WEC has agreed to provide Mr. Donovan certain life insurance benefits in consideration for his surrendering certain post-retirement benefits under the SERP. An independent review has verified that based on certain assumptions, the exchange is cost neutral to the Company.

21

WEC has entered into agreements with Messrs. Klappa, Leverett, and Kuester to provide them with supplemental retirement benefits upon retirement at or after age 60. The supplemental retirement payments are intended to make the total retirement benefits payable to the executive comparable to that which would have been received under the WEC Plan as in effect on December 31, 1995 had the defined benefit formula then in effect continued until the executive’s retirement, calculated without regard to Internal Revenue Code limits, and as if the executive had started participation in the WEC Plan at age 27 for Mr. Klappa, on January 1, 1989 for Mr. Leverett, and at age 22 for Mr. Kuester.

Due to certain restrictions contained in the Sarbanes-Oxley Act of 2002, effective June 2003, WEC converted its split dollar life insurance program to a Death Benefit Only Plan (“DBO”). Pursuant to the terms of the DBO, upon an officer’s death a benefit is paid to his or her designated beneficiary in an amount equal to three times the officer’s base salary if the officer is employed by WEC at the time of death or one times final base salary if death occurs post-retirement. All of the named executive officers other than Mr. Donovan participate in the DBO.

The WEC Amended Non-Qualified Trust, a grantor trust, has been established to fund certain non-qualified benefits, including the SERP, the Executive Deferred Compensation Plan and the agreements with the named executive officers. The plans and agreements provide for optional lump sum payments and, in the instance of a change in control, and absent a deferral election, mandatory lump sum payments without regard to whether the executive’s employment has terminated.

22

STOCK OWNERSHIP OF DIRECTORS, NOMINEES AND EXECUTIVE OFFICERS

None of the WE directors, nominees or executive officers own any of WE’s stock, but do beneficially own shares of stock of its parent company, Wisconsin Energy Corporation. The following table lists the beneficial ownership of WEC common stock of each WE director, nominee, named executive officer, and all of the directors and executive officers as a group as of January 30, 2004. In general, “beneficial ownership” includes those shares as to which the indicated persons have voting power or investment power and stock options that are exercisable currently or within 60 days of January 30, 2004. Included are shares owned by each individual’s spouse, minor children or any other relative sharing the same residence, as well as shares held in a fiduciary capacity or held in WEC’s Stock Plus and 401(k) plans. None of these persons beneficially owns more than 1% of the outstanding WEC common stock.

Name	Shares Beneficially Owned(1)
	Shares Owned(2) (3)(4)		Option Shares Exercisable Within 60 Days		Total
Richard A. Abdoo	58,083		693,534		751,617
John F. Ahearne	6,236		16,000		22,236
John F. Bergstrom	4,945		16,000		20,945
Barbara L. Bowles	5,025		16,000		21,025
Robert A. Cornog	9,487		16,000		25,487
Willie D. Davis	11,086		23,234	(5)	34,320
Paul Donovan	24,225		632,427		656,652
Richard R. Grigg	30,250		556,154		586,404
Gale E. Klappa	40,479		—		40,479
Frederick D. Kuester	24,412		—		24,412
Allen L. Leverett	29,842		—		29,842
Ulice Payne, Jr.	2,992		1,667		4,659
Larry Salustro	36,996		222,499		259,495
Frederick P. Stratton, Jr.	10,545		16,000		26,545
George E. Wardeberg	25,214		641,667	(5)	666,881
All directors and executive officers as a group (15 persons)	280,433	(4)	1,773,690	(5)	2,054,123	(6)

⁽¹⁾ Information on beneficially owned shares is based on data furnished by the specified persons and is determined in accordance with Rule 13d-3 under the Securities Exchange Act of 1934, as amended, as required for purposes of this proxy statement. It is not necessarily to be construed as an admission of beneficial ownership for other purposes.

⁽²⁾ Certain WE directors and executive officers also hold share units in the WEC phantom common stock account under WEC’s deferred compensation plans as indicated: Mr. Abdoo (63,729), Mr. Bergstrom (6,965), Mr. Cornog (12,340), Mr. Davis (8,772), Mr. Donovan (10,032), Mr. Grigg (4,066), Mr. Salustro (2,975), Mr. Stratton (8,702), Mr. Wardeberg (1,764), and all directors and executive officers as a group (106,215). Share units are intended to reflect the performance of WEC common stock and are payable in cash. While these units do not represent a right to acquire WEC common stock, have no voting rights and are not included in the number of shares reflected in the “Shares Owned” column in the table above, the Company listed them in this footnote because they represent an additional economic interest of the directors and executive officers tied to the performance of WEC common stock.

⁽³⁾ Each individual has sole voting and investment power as to all shares listed for such individual, except the following individuals have shared voting and/or investment power as indicated: Mr. Abdoo (11,120), Mr. Cornog (4,882), Mr. Stratton (4,600), Mr. Wardeberg (22,759) and all directors and executive officers as a group (43,361).

⁽⁴⁾ Certain WEC directors and executive officers hold shares of restricted stock (included in table above) over which the holders have sole voting but no investment power: Dr. Ahearne (1,945), Mr. Bergstrom (1,945), Ms. Bowles (1,945), Mr. Cornog (1,945), Mr. Davis (1,945), Mr. Donovan (20,337), Mr. Grigg (22,817), Mr. Klappa (40,308), Mr. Kuester (24,287), Mr. Leverett (29,223), Mr. Payne (1,945), Mr. Salustro (28,308), Mr. Stratton (1,945), Mr. Wardeberg (1,945) and all directors and executive officers as a group (140,998).

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⁽⁵⁾ Option shares listed include options granted by WICOR, Inc. which were converted to WEC stock options on the effective date of the acquisition of WICOR, Inc.

⁽⁶⁾ Represents 1.7% of total WEC common stock outstanding on January 30, 2004.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

Section 16(a) of the Securities Exchange Act of 1934, as amended, requires the corporation’s officers, directors, and persons owning more than ten percent of a registered class of the corporation’s equity securities to file reports of ownership and changes in ownership of equity and derivative securities of WE with the Securities and Exchange Commission. To the Company’s knowledge, based on information provided by the reporting persons, all applicable reporting requirements for fiscal year 2003 were complied with in a timely manner.

CERTAIN RELATED TRANSACTIONS

The Company provides to and receives from Wisconsin Energy Corporation, and other subsidiaries of WEC, services, property and other things of value (the “Items”). These transactions are made pursuant to either a master affiliated interest agreement or a service agreement, both of which have been approved by the Public Service Commission of Wisconsin. The master affiliated interest agreement provides that the Company receive payment equal to the higher of its cost or fair market value for the Items provided to Wisconsin Energy Corporation or its nonutility subsidiaries, and that the Company make payment equal to the lower of the provider’s cost or fair market value for the Items which Wisconsin Energy Corporation or its nonutility subsidiaries provide to the Company. The service agreement provides that any Items provided by the Company or Wisconsin Gas Company to each other shall be provided at cost. Modification or amendment to the master affiliated interest agreement or the service agreement requires the approval of the Public Service Commission of Wisconsin.

AVAILABILITY OF FORM 10-K

A copy (without exhibits) of the Annual Report on Form 10-K for the fiscal year ended December 31, 2003, as filed with the Securities and Exchange Commission, is available without charge to any stockholder of record or beneficial owner of WE preferred stock by writing to the Corporate Secretary, Kristine Rappé, at the Company’s principal business offices, 231 West Michigan Street, P. O. Box 2046, Milwaukee, Wisconsin 53201. The WE consolidated financial statements and certain other information found in the Form 10-K are included in the accompanying WE 2003 Annual Report to Stockholders.

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WISCONSIN ELECTRIC POWER COMPANY

2003 ANNUAL REPORT TO STOCKHOLDERS

2003 ANNUAL FINANCIAL STATEMENTS

and

REVIEW of OPERATIONS

A-1

SELECTED FINANCIAL DATA

WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED SELECTED FINANCIAL AND STATISTICAL DATA

	2003		2002		2001		2000		1999
Financial
Year Ended December 31
Earnings available for common stockholder (Millions)	$	255.5	$	258.0	$	245.3	$	163.5	$	211.9
Operating revenues (Millions)
Electric	$	1,986.4	$	1,884.6	$	1,839.8	$	1,763.4	$	1,688.3
Gas		513.0		389.8		457.1		399.7		306.8
Steam		22.5		21.5		21.8		21.9		21.3
Total operating revenues	$	2,521.9	$	2,295.9	$	2,318.7	$	2,185.0	$	2,016.4
At December 31 (Millions)
Total assets	$	6,644.6	$	6,285.1	$	6,040.6	$	6,038.7	$	5,907.9
Total debt (includes long-term debt, current maturities of long-term debt, and short term debt)	$	1,915.4	$	1,814.2	$	1,875.6	$	1,964.7	$	1,973.1
Utility Energy Statistics
Electric
Megawatt-hours sold (Thousands)		30,713.8		30,378.2		30,539.7		31,398.8		30,619.9
Customers (End of year)		1,068,034		1,056,370		1,044,129		1,026,691		1,006,013
Gas
Therms delivered (Millions)		888.3		890.0		852.4		944.9		944.1
Customers (End of year)		428,719		420,494		412,674		407,761		398,508
Steam
Pounds sold (Millions)		3,072.8		3,001.1		2,929.2		3,085.2		2,913.9
Customers (End of year)		459		467		449		451		450

CONSOLIDATED SELECTED QUARTERLY FINANCIAL DATA (Unaudited)

	(Millions of Dollars) (a)
	March				June
	2003		2002		2003		2002
Three Months Ended
Total operating revenues	$	718.8	$	586.7	$	564.9	$	533.6
Operating income	$	132.5	$	129.5	$	93.2	$	91.3
Earnings available for common stockholder	$	75.1	$	66.1	$	49.5	$	47.0
	September				December
	2003		2002		2003		2002
Three Months Ended
Total operating revenues	$	599.6	$	566.7	$	638.6	$	608.9
Operating income	$	124.5	$	127.1	$	121.1	$	137.4
Earnings available for common stockholder	$	67.7	$	69.0	$	63.2	$	75.9

(a) Quarterly results of operations are not directly comparable because of seasonal and other factors. See Management’s Discussion and Analysis of Financial Condition and Results of Operations.

A-2

WISCONSIN ELECTRIC POWER COMPANY

SELECTED OPERATING DATA

Year Ended December 31	2003		2002			2001		2000			1999
Electric Utility
Operating Revenues (Millions)
Residential	$	705.0	$	693.4		$	644.8	$	597.2		$	574.8
Small Commercial/Industrial		626.0		591.0			577.3		534.7			510.1
Large Commercial/Industrial		511.4		475.6			472.0		464.9			451.2
Other—Retail/Municipal		77.1		71.0			63.2		58.3			51.2
Resale—Utilities		39.1		31.3			69.6		84.0			79.1
Other Operating Revenues		27.8		22.3			12.9		24.3			21.9
Total Operating Revenues	$	1,986.4	$	1,884.6		$	1,839.8	$	1,763.4		$	1,688.3
Megawatt-hour Sales (Thousands)
Residential		7,928.8		8,147.8			7,615.7		7,477.6			7,346.8
Small Commercial/Industrial		8,493.1		8,473.2			8,354.2		8,287.5			8,028.2
Large Commercial/Industrial		11,201.8		10,933.0			10,983.0		11,626.2			11,333.6
Other—Retail/Municipal		1,980.4		1,810.4			1,599.4		1,527.3			1,314.0
Resale—Utilities		1,109.7		1,013.8			1,987.4		2,480.2			2,597.3
Total Sales		30,713.8		30,378.2			30,539.7		31,398.8			30,619.9
Number of Customers (Average)
Residential		954,757		945,298			931,714		916,028			897,333
Small Commercial/Industrial		102,928		102,058			100,456		98,277			95,964
Large Commercial/Industrial		703		705			706		712			716
Other		2,348		2,345			2,319		2,283			1,938
Total Customers		1,060,736		1,050,406			1,035,195		1,017,300			995,951
Gas Utility
Operating Revenues (Millions)
Residential	$	317.5	$	250.9		$	275.8	$	244.3		$	193.8
Commercial/Industrial		166.9		125.8			150.0		132.0			95.1
Interruptible		3.8		3.2			5.1		5.3			5.3
Total Retail Gas Sales		488.2		379.9			430.9		381.6			294.2
Transported Gas		16.2		16.0			15.4		18.9			16.4
Other Operating Revenues		8.6		(6.1	)		10.8		(0.8	)		(3.8	)
Total Operating Revenues	$	513.0	$	389.8		$	457.1	$	399.7		$	306.8
Therms Delivered (Millions)
Residential		361.0		345.4			318.4		335.7			329.0
Commercial/Industrial		210.8		199.2			194.5		206.2			195.3
Interruptible		6.8		7.4			8.9		12.0			16.3
Total Retail Gas Sales		578.6		552.0			521.8		553.9			540.6
Transported Gas		309.7		338.0			330.6		391.0			403.5
Total Therms Delivered		888.3		890.0			852.4		944.9			944.1
Number of Customers (Average)
Residential		388,896		381,846			376,510		369,210			360,084
Commercial/Industrial		34,646		34,180			33,839		33,275			32,594
Interruptible		23		24			30		33			89
Transported Gas		362		366			427		389			334
Total Customers		423,927		416,416			410,806		402,907			393,101
Degree Days (a)
Heating (6,721 Normal)		7,063		6,551			6,338		6,716			6,318
Cooling (728 Normal)		606		897			711		566			753

(a) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a twenty-year moving average.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

INTRODUCTION

Wisconsin Electric Power Company (Wisconsin Electric), a wholly-owned subsidiary of Wisconsin Energy Corporation (Wisconsin Energy), is engaged principally in the business of generating electricity and distributing electricity and natural gas with operations in Wisconsin and Michigan. Unless qualified by their context, when used in this document the terms the Company, Our, Us or We refer to Wisconsin Electric and its subsidiaries.

Wisconsin Energy is also the parent company of Wisconsin Gas Company (Wisconsin Gas) a natural gas distribution utility, which serves customers throughout Wisconsin, and Edison Sault Electric Company (Edison Sault) an electric utility, which serves customers in the Upper Peninsula of Michigan. Wisconsin Electric and Wisconsin Gas have combined common functions and operate under the trade name of “We Energies”.

Cautionary Factors:Certain statements contained herein are “Forward-Looking Statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-Looking Statements may be identified by reference to a future period or periods or by the use of forward looking terminology such as “may,” “intends,” “anticipates,” “believes,” “estimates,” “expects,” “forecasts,” “objectives,” “plans,” “possible,” “potential,” “project” or similar terms or variations of these terms. Actual results may differ materially from those set forth in Forward-Looking Statements as a result of certain risks and uncertainties, including but not limited to, changes in political and economic conditions, equity and bond market fluctuations, varying weather conditions, governmental regulation and supervision, as well as other risks and uncertainties detailed from time to time in our filings with the Securities and Exchange Commission (SEC), including factors described throughout this document and below in “Factors Affecting Results, Liquidity and Capital Resources”.

CORPORATE STRATEGY

Business Opportunities

Wisconsin Energy’s key corporate strategy isPower the Future, which was announced in September 2000. This strategy is designed to increase the electric generating capacity in the state of Wisconsin while maintaining a fuel diverse, reasonably priced electric supply. It also is designed to improve the delivery of energy within our distribution systems to meet increasing customer demands, and it is committed to improved environmental performance. ThePower the Future strategy, which is discussed further below, is expected to have a significant impact on us.

Power the Future Strategy:In February 2001, Wisconsin Energy filed a petition with the Public Service Commission of Wisconsin (PSCW) starting the regulatory review process for a proposed 10-year strategy to improve the supply and reliability of electricity in Wisconsin. ThisPower the Future strategy is intended to meet the growing demand for electricity and ensure a diverse fuel mix while keeping electricity prices reasonable.Power the Future will add new coal-based and natural gas-based capacity to the state’s power portfolio and will allow us to maintain approximately the same fuel mix as exists today. The new generation will be built by an affiliated company, W.E. Power LLC (We Power), and leased to us through long-term leases. As part of Wisconsin Energy’sPower the Future strategy, Wisconsin Energy plans to: (1) invest in 2,120 megawatts of new natural gas-based and coal-based generating capacity; (2) upgrade our existing electric generating facilities and (3) upgrade our existing energy distribution system.

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As of December 31, 2003, Wisconsin Energy has:

Ø Received a Certificate of Public Convenience and Necessity (CPCN) from the PSCW to build two 545-megawatt natural gas-based intermediate load units in Port Washington, Wisconsin, with the first unit expected to be in service July 2005 and the second unit in 2008, subject to resolution of legal challenges;

Ø Begun construction on the first 545-megawatt generating unit in Port Washington (approximately 14% complete as of January 31, 2004), which is currently on schedule and within budget; and

Ø Received a CPCN from the PSCW to build two 615-megawatt coal-based base load units at Elm Road in Oak Creek, Wisconsin, with the first unit expected to be in service in 2009 and the second unit in 2010 subject to resolution of legal challenges and receipt of environmental permits.

In November 2001, Wisconsin Energy created We Power, to design, construct, own, finance and lease the new generating capacity. UnderPower the Future, we will lease each new facility from We Power as well as operate and maintain the new plants under 25 to 30-year lease agreements approved by the PSCW. At the end of the leases, we will have the right to acquire the plants outright at market value or renew the lease. Smaller investor-owned or municipal utilities, cooperatives and power marketing associations have the opportunity to own a portion of the coal units, including expanding or extending wholesale power purchases from us as a result of the additional electric generating capacity included in the proposal. We expect that all lease payments and operating costs of the plants will be recoverable in rates.

In February 2001, Wisconsin Energy made preliminary filings for itsPower the Future proposal with the PSCW. Subsequently, the state legislature amended several laws, making changes that are critical to the implementation ofPower the Future. On October 16, 2001, the PSCW issued a declaratory ruling finding, among other things, that it was prudent to proceed withPower the Future and for us to incur the associated pre-certification expenses. However, individual expenses are subject to review by the PSCW in order to be recovered.

Several phases of thePower the Future strategy remain subject to a number of regulatory approvals and legal challenges by third parties. Additional information regarding the regulatory process, specific regulatory approvals and associated legal challenges may be found below under “Rates and Regulatory Matters”.

For further information concerning thePower the Future strategy, see “Liquidity and Capital Resources” as well as “Factors Affecting Results, Liquidity and Capital Resources” below.

Divestiture of Assets

During 2000, we agreed to join American Transmission Company LLC (ATC) by transferring our electric utility transmission system assets to ATC in exchange for an ownership interest in this new company. Transfer of these electric transmission assets, with a net book value of approximately $224.1 million, became effective on January 1, 2001. During 2001, ATC issued debt and distributed $105.2 million of cash back to us as a partial return of the original equity contribution. As of December 31, 2003, we had an ownership interest of approximately 34.6% in ATC. Joining ATC is consistent with the Federal Energy Regulatory Commission’s Order No. 2000, intended to foster competition, efficiency and reliability in the electric industry.

RESULTS OF OPERATIONS

EARNINGS

2003 vs 2002: Earnings during 2003 decreased by $2.5 million to $255.5 million compared to 2002 earnings. This decline is primarily due to cooler summer weather, higher fuel and purchased power costs, and increases in pension, medical and other benefit costs, nuclear costs and costs associated with Wisconsin Energy’sPower the Future growth strategy. The decline was somewhat mitigated by a March 2003 rate increase associated with fuel and

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purchased power expenses, as well as by higher gas margins, growth in our base electric business, litigation settlements in 2002 compared with the receipt of insurance recoveries in 2003 primarily related to the Giddings & Lewis/City of West Allis litigation, higher other income and deductions and lower interest expense.

2002 vs 2001: Earnings during 2002 increased by $12.7 million to $258.0 million compared to 2001 earnings. The increase is primarily attributable to improved electric and gas margins, a strong focus on managing financial resources and reduced financing costs. Offsetting these items were $17.3 million for litigation settlements related to the Giddings & Lewis/City of West Allis litigation, $10.5 million in reduced interest income, $5.3 million in costs in 2002 for the early repayment of $103.4 million of long-term debt and additional expenses related to nuclear operations.

The following table summarizes our consolidated earnings during 2003, 2002, and 2001.

	2003		2002		2001
	(Millions of Dollars)
Gross Margin
Electric (See below)	$	1,430.7	$	1,397.5	$	1,336.3
Gas (See below)		157.6		149.0		138.1
Steam		15.8		14.7		15.6
Total Gross Margin		1,604.1		1,561.2		1,490.0
Other Operating Expenses
Other Operation and Maintenance		784.0		736.3		681.9
Depreciation, Decommissioning and Amortization		276.2		267.9		264.3
Property and Revenue Taxes		72.6		71.7		67.8
Operating Income		471.3		485.3		476.0
Other Income (Deductions)		31.5		24.3		36.0
Financing Costs		91.2		92.7		108.9
Income Before Income Taxes		411.6		416.9		403.1
Income Taxes		154.9		157.7		156.6
Preferred Stock Dividend Requirement		1.2		1.2		1.2
Earnings Available for Common Stockholder	$	255.5	$	258.0	$	245.3

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Electric Utility Revenues, Gross Margins and Sales

The following table compares our electric utility operating revenues and gross margin during 2003, 2002 and 2001.

	Electric Revenues and Gross Margin						Megawatt-Hour Sales
Electric Utility Operations	2003		2002		2001		2003	2002	2001
	(Millions of Dollars)						(Thousands)
Operating Revenues
Residential	$	705.0	$	693.4	$	644.8	7,928.8	8,147.8	7,615.7
Small Commercial/Industrial		626.0		591.0		577.3	8,493.1	8,473.2	8,354.2
Large Commercial/Industrial		511.4		475.6		472.0	11,201.8	10,933.0	10,983.0
Other-Retail/Municipal		77.1		71.0		63.2	1,980.4	1,810.4	1,599.4
Resale-Utilities		39.1		31.3		69.6	1,109.7	1,013.8	1,987.4
Other Operating Revenues		27.8		22.3		12.9	—	—	—
Total Operating Revenues		1,986.4		1,884.6		1,839.8	30,713.8	30,378.2	30,539.7
Fuel and Purchased Power
Fuel		298.3		278.9		308.8
Purchased Power		257.4		208.2		194.7
Total Fuel and Purchased Power		555.7		487.1		503.5
Gross Margin	$	1,430.7	$	1,397.5	$	1,336.3
Weather — Degree Days (a)
Heating (6,721 Normal)							7,063	6,551	6,338
Cooling (728 Normal)							606	897	711

(a) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a twenty-year moving average.

2003 vs 2002: During 2003, total electric utility operating revenues increased by $101.8 million or 5.4% when compared with 2002 primarily due to the impact of rate increases related to fuel and purchased power costs and to a surcharge related to transmission costs. The total rate impact was approximately $83.3 million in 2003. In March 2003, we received an interim increase in rates of $55.1 million annually to recover increases in fuel and purchased power costs. In October 2003, we received the final rate order which authorized an additional $6.1 million of annual revenues (see “Factors Affecting Results, Liquidity and Capital Resources” below). In spite of the interim fuel order, we under recovered fuel costs by approximately $7.6 million during 2003, which is approximately $5.3 million worse than our under recovery during 2002. Much of our under recovery of fuel costs during 2003 can be attributed to the need to purchase replacement power due to a flood at Presque Isle Power Plant in May and June of 2003 and to high natural gas prices. The impact of unfavorable summer weather in 2003 reduced electric operating revenues by approximately $19.0 million between the comparative periods.

Total electric megawatt-hour sales increased by 1.1% during 2003. Residential sales fell 2.7% due to the impact of unfavorable weather conditions on cooling load during the second and third quarters of 2003. Residential customers contribute higher margins than other customer classes and are particularly sensitive to fluctuations in weather. Sales to our largest customers, two iron ore mines, increased by 238.4 thousand megawatt-hours or 12.1% between the comparative periods despite temporary curtailments of electric sales in the second and fourth quarters of 2003 resulting from a flood-related outage at our Presque Isle Power Plant and a transmission outage, respectively. During the first and third quarters of 2002, the mines had extended outages. Excluding these two mines, our total electric energy sales increased by 0.3% and sales volumes to the remaining large commercial/industrial customers improved by 0.3% between the comparative periods. Sales to municipal utilities, the other retail/municipal customer class, increased 9.4% between the periods due to a higher off-peak demand from municipal wholesale power customers.

Total fuel and purchased power expenses increased due in large part to increases in fuel prices, especially for natural gas, the primary fuel source for our purchased power, resulting in a 13% increase in the cost per megawatt hour of purchased power. Average commodity gas market prices were $5.39 for 2003 compared to $3.22 for 2002 on a per dekatherm basis. Fuel and purchased power costs also increased due to higher purchased capacity costs and a higher need for purchased energy in 2003 compared with the same period in 2002. Approximately $9 million of this

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increase was caused by the flood that temporarily shut down our Presque Isle Power Plant during the second quarter of 2003.

Electric gross margin increased 2.4% to $1,430.7 million between the comparative periods. The increase is primarily related to implementing a PSCW approved surcharge in October 2002 for recovery of increased annual transmission costs associated with ATC, which increased year-to-date 2003 gross margin by approximately $39.4 million. Non-fuel operation and maintenance costs increased by a similar amount, so there was little impact to Operating Income as a result of the transmission surcharge. Excluding the surcharge, electric gross margin fell by $6.2 million primarily due to the impact of cooler summer weather and higher fuel and purchased power costs compared to the prior year.

2002 vs 2001: During 2002, our total electric utility operating revenues increased by $44.8 million or 2.4% compared with 2001 due to favorable weather, the full year impact of price increases related to fuel and purchased power and a surcharge related to transmission costs. As measured by cooling degree days, 2002 was 26.2% warmer than 2001 and 27.6% warmer than normal. In February and May 2001, we received increases in rates to cover increased fuel and purchased power costs. On a year to year basis, the fuel surcharge resulted in $10.0 million of additional revenue. For additional information concerning the rate increases, see “Factors Affecting Results, Liquidity and Capital Resources” below. Even with the increased fuel revenues, we estimate that we under-recovered fuel and purchased power costs by $2.3 million and $0.1 million for 2002 and 2001, respectively.

During 2002, total electric energy sales decreased by 0.5% compared with 2001, primarily reflecting a decline in sales for resale to other utilities due to a reduced demand for wholesale power. Most of the remaining customer classes had increased sales in 2002 reflecting favorable weather and the growth in the average number of customers. Sales to our largest commercial/industrial customers, two iron ore mines, declined by 2.8% between the comparative periods due to the shutdown of a mine in the first quarter of 2002. Excluding these mines, total electric sales decreased by 0.4% and sales to the remaining large commercial/industrial customers increased by 0.1% between the comparative periods.

Between the comparative periods, fuel and purchased power expenses decreased by $16.4 million or 3.3% primarily due to lower natural gas prices, lower wholesale power prices, and lower megawatt sales. These reductions were partially offset by higher costs due to a larger number of planned outages including a second refueling outage at the Point Beach Nuclear Plant during 2002. The lower fuel and purchased power expenses and increased sales to higher margin customers offset the impact on electric revenues of the decline in electric megawatt-hours such that the total gross margin on electric operating revenues increased by $61.2 million or 4.6% during 2002 compared with the same period in 2001.

Our electric gross margin was $1,397.5 million or 4.6% higher than 2001. The increase is primarily related to the favorable impact of weather and higher fuel cost recovery compared to the prior year. In addition, we implemented a PSCW-approved surcharge in October 2002 for recovery of increased annual transmission costs associated with ATC, which increased year-to-date 2002 gross margin by approximately $8.7 million. Non-fuel operation and maintenance costs increased by a similar amount, so there was little impact to Operating Income as a result of the transmission surcharge.

Gas Utility Revenues and Gross Margins

Gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under a gas cost recovery mechanism. The following table compares our gas utility operating revenues and gross margins (total gas utility operating revenues less cost of gas sold) during 2003, 2002 and 2001.

Gas Utility Operations	2003		2002		2001
	(Millions of Dollars)
Gas Operating Revenues	$	513.0	$	389.8	$	457.1
Cost of Gas Sold		355.4		240.8		319.0
Gross Margin	$	157.6	$	149.0	$	138.1

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2003 vs 2002: During 2003 gas operating revenues increased by $123.2 million or 31.6%. This increase in revenues is due primarily to a $114.6 million increase in the delivered cost of natural gas, recognition of $4.5 million of increased gas cost incentive revenues under our gas cost recovery mechanism and increased deliveries resulting from colder weather during 2003 compared with 2002. The increase in purchased gas costs is passed on to customers because changes in the cost of gas sold flow through to revenue under the gas cost recovery mechanism.

2002 vs 2001: During 2002, total gas utility operating revenues decreased by $67.3 million or 14.7% compared to 2001 due to lower gas costs offset in part by increased deliveries resulting from colder winter weather. This decline primarily reflects a decrease in natural gas costs in 2002, which are passed on to customers under the gas cost recovery mechanism.

Gas Utility Gross Margins and Therm Deliveries

The following table compares gas utility gross margin and therm deliveries during 2003, 2002 and 2001.

	Gross Margin						Therm Deliveries
Gas Utility Operations	2003		2002		2001		2003	2002	2001
	(Millions of Dollars)						(Millions)
Customer Class
Residential	$	98.8	$	95.3	$	87.4	361.0	345.4	318.4
Commercial/Industrial		34.2		32.7		31.2	210.8	199.2	194.5
Interruptible		0.5		0.5		0.7	6.8	7.4	8.9
Total Gas Sold		133.5		128.5		119.3	578.6	552.0	521.8
Transported Gas		16.2		16.7		15.7	309.7	338.0	330.6
Other Operating		7.9		3.8		3.1	—	—	—
Total	$	157.6	$	149.0	$	138.1	888.3	890.0	852.4
Weather—Degree Days (a)
Heating (6,721 Normal)							7,063	6,551	6,338

(a) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a twenty-year moving average.

2003 vs 2002: Gas gross margin totaled $157.6 million in 2003, an $8.6 million improvement from 2002. This was directly related to a favorable weather-related increase in therm deliveries, especially to residential customers who are more weather sensitive and contribute higher margins per therm than other customer classes. As measured by heating degree days, 2003 was 7.8% colder than 2002 and 5.1% colder than normal. A $4.5 million increase in gas cost incentive revenues during 2003 under our gas cost recovery mechanism also contributed to the increased gross margin between the comparative periods. Total therm deliveries of natural gas decreased by 0.2% during 2003, but varied within customer classes. Volume deliveries for the residential and commercial/industrial customer classes increased by 4.5% and 5.8%, respectively, reflecting colder weather.

2002 vs 2001: Gas gross margin for 2002 totaled $149.0 million, an increase of $10.9 million from 2001. This increase was primarily due to a return to colder winter weather in 2002, which increased the heating degree days compared to 2001. In addition, we had a rate increase which became effective December 20, 2001, which contributed $3.2 million in 2002. The average number of customers also increased in 2002, which favorably impacted the fixed component of operating revenues that is not affected by volume fluctuations.

Other Operation and Maintenance Expenses

2003 vs 2002:Other operation and maintenance expenses increased by $47.7 million or 6.5% during 2003 when compared with 2002. The increase was primarily attributable to approximately $39.4 million of higher electric transmission expenses. A surcharge for transmission costs that was approved by the PSCW in October 2002 offset the impact of higher transmission expenses. Pension, medical and other benefit costs increased by approximately $25.0 million during 2003. Overall, nuclear costs were $8.7 million higher during 2003 compared with 2002 due to

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an extended outage and costs associated with supplemental inspections at Point Beach by the U.S. Nuclear Regulatory Commission (NRC). Insurance recoveries of approximately $11.1 million in 2003 compared to associated settlement costs of $17.3 million in 2002, both primarily related to the Giddings & Lewis/City of West Allis litigation, offset some of the increase in other operation and maintenance expenses. We spent approximately $7.2 million more in 2003 than 2002 on the implementation of Wisconsin Energy’sPower the Future strategy.

2002 vs 2001: Other operation and maintenance expenses increased by $54.4 million or 8.0% during 2002 compared with 2001. The most significant change in other operation and maintenance expenses between 2002 and 2001 resulted from $17.3 million for the settlements of litigation with the City of West Allis in the second quarter of 2002 and Giddings & Lewis Inc. and Kearney & Trecker Corporation (now part of Giddings & Lewis) in the third quarter of 2002. Increased other operation and maintenance expenses during 2002 were also attributable to $9.8 million of higher electric transmission expenses associated with ATC which were offset by increased revenues recorded due to the surcharge that became effective in October of 2002, $9.2 million of increased scheduled maintenance at several steam generation plants and $15.4 million associated with the second scheduled outage and incremental costs associated with reactor vessel head inspections at Point Beach Nuclear Plant in 2002. In 2002, both Point Beach nuclear units had scheduled outages. In 2001, only one nuclear unit had a scheduled outage. We also experienced an increase of $13.7 million for employee benefit and pension costs and $4.8 million in property insurance costs which were partially offset by cost reduction efforts during 2002. These increased expenses were offset in part by lower intercompany costs related to information systems. Prior to August 2001, Wisconsin Gas utilized its own customer service system. Following the April 2000 merger of Wisconsin Energy with WICOR, Inc., in August of 2001, we combined our customer service function with Wisconsin Gas’ customer service function which resulted in decreased operating and maintenance costs of $7.8 million for us for 2002 compared to 2001.

Depreciation, Decommissioning and Amortization Expenses

2003 vs 2002:Depreciation, decommissioning and amortization expenses increased by $8.3 million or 3.1% during 2003 primarily due to a higher base of depreciable assets between the comparative periods.

2002 vs 2001: Depreciation, decommissioning and amortization expenses increased by $3.6 million during 2002 compared with 2001. This increase was primarily due to capital asset additions of longer-lived assets offset by the impact of the retirement of several shorter-lived intangible assets.

Other Income and Deductions

2003 vs 2002:Other income and deductions increased by $7.2 million in 2003 compared to 2002. This increase is primarily due to increased equity in earnings of ATC, our unconsolidated affiliate offset in part by $5.3 million of costs associated with bond redemptions we recorded in 2002 and a $3.2 million civil penalty we agreed to pay in 2003 pursuant to the terms of a consent decree with the U.S. Environmental Protection Agency (EPA).

2002 vs 2001:Other income and deductions decreased by $11.7 million in 2002 compared to 2001. This decrease is primarily due to $10.5 million in interest income accrued in 2001 related to litigation.

Financing Costs

Total financing costs decreased by $1.5 million in 2003 compared to 2002. This decline was primarily due to lower interest rates. Total financing costs decreased by $16.2 million in 2002 compared to 2001. This decline was primarily due to lower interest rates and the early repayment of $103.4 million of long-term debt.

Income Taxes

Our effective income tax rate was 37.6%, 37.8%, and 38.8% for each of the three years ending December 31, 2003, 2002, and 2001, respectively. The 2003 and 2002 effective income tax rates reflect tax credits associated with rehabilitation projects.

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LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

The following table summarizes our cash flows during 2003, 2002 and 2001:

Wisconsin Electric	2003			2002			2001
	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$	514.2		$	656.3		$	537.1
Investing Activities	($	402.8	)	($	416.1	)	($	301.8	)
Financing Activities	($	104.7	)	($	248.2	)	($	224.6	)

Operating Activities

Cash provided by operating activities decreased to $514.2 million during 2003 compared with $656.3 million during the same period in 2002. This decrease was primarily due to a $116 million refund received in the first quarter of 2002 from a favorable court ruling in the Giddings & Lewis/City of West Allis litigation, increased use of working capital in 2003 due to higher natural gas prices and higher volumes of natural gas in storage and increased tax payments.

During 2002, cash flow from operations increased to $656.3 million, a $119.2 million improvement over 2001. This increase was primarily attributable to the return of a $100 million deposit plus accrued interest as a result of the favorable court ruling discussed above.

Investing Activities

During 2003, we made net investments totaling $402.8 million, a decrease of $13.3 million over the prior year. For 2003 and 2002, capital expenditures totaled $343.7 million and $365.7 million, respectively. In addition, due to the timing of refueling outage schedules at Point Beach Nuclear Plant, we spent $17.6 million more on the acquisition of nuclear fuel in 2003 than in 2002.

During 2002, we had net cash outflows for investing activities of $416.1 million as compared to $301.8 million in 2001. For 2002 and 2001, capital expenditures totaled $365.7 million and $377.0 million, respectively. The primary reason for the decline is the receipt during 2001 of $105.2 million from ATC as a partial return of our investment. In addition, due to the timing of refueling outage schedules at Point Beach Nuclear Plant, we spent $10.8 million more on the acquisition of nuclear fuel in 2002 than in 2001.

Financing Activities

During 2003, we used $104.7 million of net cash in our financing activities consisting primarily of the payment of $179.6 million of dividends to Wisconsin Energy. In May 2003, we sold $635 million of unsecured Debentures ($300 million of ten-year 4.50% Debentures due 2013 and $335 million of thirty-year 5.625% Debentures due 2033) under an existing $800 million shelf registration statement filed with the SEC. We used a portion of the proceeds from the Debentures to repay short-term debt, which was originally incurred to retire debt that matured in December 2002. The balance of the proceeds were used to redeem $425 million of our debt securities in June 2003 and to fund the early redemption in August 2003 of another $60 million debt issue.

The debt refinancings in June and August 2003 are being accounted for using the PSCW-authorized revenue neutral method of accounting, under which net debt extinguishment costs in the amount of approximately $18.3 million were deferred and are being amortized over an approximately two year period based upon the level of interest savings achieved.

In October 2003, we redeemed $9 million of 6.85% First Mortgage Bonds.

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During 2002, we used $248.2 million of net cash in our financing activities consisting primarily of the payment of $179.6 million of dividends to Wisconsin Energy. In January 2002, we redeemed $103.4 million of debt with a weighted average interest rate of 8.4%. In December 2002, we retired $150 million of 6 5/8% debentures at maturity. These redemptions and retirements were originally financed with short-term commercial paper bearing rates of approximately 2%.

CAPITAL RESOURCES AND REQUIREMENTS

Capital Resources

We anticipate meeting our capital requirements during 2004 primarily through internally generated funds, short-term borrowings and existing lines of credit, supplemented through the issuance of debt securities depending on market conditions and other factors. Beyond 2004, we anticipate meeting our capital requirements through internally generated funds supplemented, when required, through the issuance of debt securities.

We have access to the capital markets and have been able to generate funds internally and externally to meet our capital requirements. Our ability to attract the necessary financial capital at reasonable terms is critical to our overall strategic plan. We believe that we have adequate capacity to fund our operations for the foreseeable future through our borrowing arrangements and internally generated cash.

We have $165 million of unsecured notes outstanding at December 31, 2003 that were issued as support for a similar amount of variable rate tax-exempt bonds issued on our behalf. The terms of the variable rate tax-exempt bonds require resetting of the interest rate on a weekly basis and allow holders to put the bonds at par value to the issuer with seven days notice. Our credit agreements, as well as those of Wisconsin Energy, provide liquidity support of our obligations with respect to variable rate tax-exempt bonds and commercial paper.

As of December 31, 2003, we had approximately $350.0 million of available unused lines of bank back-up credit facilities on a consolidated basis. We had approximately $315.9 million of total consolidated short-term debt outstanding on such date.

We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. The following table summarizes such facilities at December 31, 2003:

Total Facility	Drawn	Credit Available	Facility Maturity	Facility Term
(Millions of Dollars)
$250.0	$—	$250.0	Jun-2004	364 day
$100.0	$—	$100.0	Aug-2004	9 month

On June 25, 2003, we entered into an unsecured 364 day $250 million bank back-up credit facility to replace a $230 million credit facility that was expiring. The credit facility may be extended for an additional 364 days, subject to lender agreement.

On December 12, 2003, we entered into an unsecured nine month $100 million bank back-up credit facility.

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The following table shows our consolidated capitalization structure at December 31:

Capitalization Structure	2003				2002
	(Millions of Dollars)
Common Equity	$	2,131.9	52.3%		$	2,049.9	52.6%
Preferred Stock		30.4	0.7%			30.4	0.8%
Long-Term Debt (including current maturities)		1,599.5	39.2%			1,459.4	37.5%
Short-Term Debt		315.9	7.8%			354.8	9.1%
Total	$	4,077.7	100.0	%	$	3,894.5	100.0	%

Access to capital markets at a reasonable cost is determined in large part by credit quality. The following table summarizes the ratings of our securities by Standard & Poors Corporation (S&P), Moody’s Investors Service (Moody’s) and Fitch as of December 31, 2003.

	S&P	Moody’s	Fitch
Commercial Paper	A-2	P-1	F1
Secured Senior Debt	A-	Aa3	AA-
Senior Unsecured Debt	A-	A1	A+
Preferred Stock	BBB	A3	A

In March 2003, S&P lowered its corporate credit rating on us from A to A-. S&P lowered its rating on our senior secured debt from A to A-. S&P affirmed our A- senior unsecured debt rating. S&P lowered the rating on our preferred stock from BBB+ to BBB. S&P lowered our short-term rating from A-1 to A-2. S&P’s ratings outlook for us is stable.

In October 2003, Moody’s downgraded certain of our security ratings. Moody’s lowered our senior secured debt rating from Aa2 to Aa3, our senior unsecured debt rating from Aa3 to A1 and our preferred stock debt rating from A2 to A3. Moody’s confirmed our P-1 commercial paper rating. Moody’s ratings outlook for us is stable.

In October 2003, Fitch downgraded certain of our security ratings. Fitch lowered our senior secured debt rating from AA to AA-, our senior unsecured debt rating from AA- to A+ and our preferred stock rating from AA- to A. Fitch lowered our commercial paper rating from F1+ to F1. Fitch’s ratings outlook for us is stable.

We believe these security ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agencies only. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell or hold securities, but rather an indication of creditworthiness. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating should be evaluated independently of any other rating.

Capital Requirements

Total capital expenditures, excluding the purchase of nuclear fuel, are currently estimated to be $406 million during 2004. Due to changing environmental and other regulations such as air quality standards and electric reliability initiatives that impact us, future long-term capital requirements may vary from recent capital requirements. We currently expect capital expenditures, excluding the purchase of nuclear fuel and expenditures for new generating capacity contained in Wisconsin Energy’sPower the Future strategy, to be between $350 million and $425 million per year during the next five years.

Investments in Outside Trusts: We fund our pension obligations, certain other post-retirement obligations and future nuclear obligations in outside trusts. Collectively, these trusts had investments that exceeded $1.4 billion as of December 31, 2003. These trusts hold investments that are subject to the volatility of the stock market and

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interest rates. During 2003, our pension investments had returns of 24%, and during 2002, we had losses of 13%. Our other trusts had similar returns during these periods.

Off-Balance Sheet Arrangements: We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support commodity contracts and other payment obligations. Our estimated maximum exposure under these agreements is approximately $2.1 million as of December 31, 2003. We believe that such agreements do not have, and are not reasonable likely to have, a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors See “Note L—Guarantees” in the Notes to Consolidated Financial Statements in this report for more information.

Contractual Obligations/Commercial Commitments:We have the following contractual obligations and other commercial commitments as of December 31, 2003:

	Payments Due by Period
Contractual Obligations(a)	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
	(Millions of Dollars)
Long-Term Debt Obligations (b)	$	1,399.4	$	141.9	$	204.9	$	0.4	$	1,052.2
Capital Lease Obligations (c)		619.3		52.6		89.8		73.1		403.8
Operating Lease Obligations (d)		272.2		42.5		82.6		67.2		79.9
Purchase Obligations (e)		176.6		42.1		63.9		60.9		9.7
Other Long-Term Liabilities (f)		494.2		174.3		246.6		61.3		12.0
Total Contractual Obligations	$	2,961.7	$	453.4	$	687.8	$	262.9	$	1,557.6

(a) The amounts included in the table are calculated using current market prices, forward curves and other estimates. Contracts with multiple unknown variables have been omitted from the analysis.

(b) Principal payments on our Long-Term Debt and the Long-Term Debt of our affiliates (excluding capital lease obligations).

(c) Capital Lease Obligations of Wisconsin Electric for nuclear fuel lease and purchase power commitments.

(d) Operating Lease Obligations for purchased power and rail car leases for Wisconsin Electric.

(e) Purchase Obligations for information technology and other services for utility operations.

(f) Other Long-Term Liabilities under various contracts of Wisconsin Electric for the procurement of fuel, power, gas supply and associated transportation, and post-retirement contributions.

Our obligations for utility operations have historically been included as part of the rate making process and therefore are generally recoverable from customers.

Guarantees:We provide various guarantees supporting certain of our operations. We guarantee payment or performance under specified agreements or transactions. As a result, our exposure under the guarantees is based upon the net liability under the specified agreements or transactions. The majority of the guarantees issued by us limit our exposure to a maximum amount stated in the guarantees. See “Note L—Guarantees” in the Notes to Consolidated Financial Statements in this report for more information.

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FACTORS AFFECTING RESULTS, LIQUIDITY AND CAPITAL RESOURCES

MARKET RISKS AND OTHER SIGNIFICANT RISKS

We are exposed to market and other significant risks as a result of the nature of our businesses and the environment in which those businesses operate. These risks, described in further detail below, include but are not limited to:

Commodity Price Risk:In the normal course of business, our utility operations utilize contracts of various duration for the forward sale and purchase of electricity. This is done to effectively manage utilization of available generating capacity and energy during periods when available power resources are expected to exceed the requirements of our obligations. This practice may also include forward contracts for the purchase of power during periods when the anticipated market price of electric energy is below expected incremental power production costs. We manage our fuel and gas supply costs through a portfolio of short and long-term procurement contracts with various suppliers for the purchase of coal, uranium, natural gas and fuel oil.

Wisconsin’s retail electric fuel cost adjustment procedure mitigates some of our risk of electric fuel cost fluctuation. If cumulative fuel and purchased power costs for electric utility operations deviate from a prescribed range when compared to the costs projected in the most recent retail rate proceeding, retail electric rates may be adjusted, subject to risks associated with the regulatory approval process including regulatory lag. Regulatory lag risk occurs between the time we submit rate proceedings and we receive final approval or denial. Regulatory risk can increase or decrease due to many factors which may also change during this approval period including commodity price fluctuations, unscheduled operating outages or unscheduled maintenance. In 2002, the PSCW authorized the inclusion of price risk management financial instruments for the management of our electric utility gas costs. During 2003, a gas hedging program was approved by the PSCW and implemented by us. For 2003, our electric fuel cost exceeded fuel recovery by approximately $7.6 million. The PSCW has authorized dollar for dollar recovery for the majority of natural gas costs for our gas utility operations through a gas cost recovery mechanism, which mitigates most of the risk of gas cost variations. For additional information concerning the electric utility fuel cost adjustment procedure and our gas cost recovery mechanism, see “Rates and Regulatory Matters” below. For information concerning commodity price risk as it applies to gas operations see “Commodity Price Risk Programs” below.

Regulatory Recovery Risk:Our electric operations burn natural gas in several of our peaking power plants or as a supplemental fuel at several coal-based plants and the cost of purchased power is tied to the cost of natural gas in many instances. We bear regulatory risk for the recovery of these fuel and purchased power costs when they are higher than the base rate established in our rate structure.

As noted above, our electric operations operate under a fuel cost adjustment clause in the Wisconsin retail jurisdiction for fuel and purchased power costs associated with the generation and delivery of electricity. This clause establishes a base rate for fuel and purchased power and we assume the risks and benefits of fuel cost variances that are within 3% of the base rate. We are subject to risks associated with the regulatory approval process including regulatory lag once the costs fall outside the 3% variances of the base rate. During the second quarter of 2002, the PSCW issued an order authorizing new fuel cost adjustment rules to be implemented in the Wisconsin retail jurisdiction. The new rules will not be effective for us until January 2006, the end of a five year rate freeze associated with the WICOR Merger Order. Until that time, we will operate under an approved transaction mechanism similar to the old fuel cost adjustment procedure. For 2003, 2002 and 2001, our actual fuel and purchased power costs exceeded base fuel rates by $7.6 million, $2.3 million and $0.1 million, respectively. In all three years, the electric rates included a fuel surcharge.

Gas Costs:Significant increases in the cost of natural gas affect our electric and gas utility operations. Gas costs have increased significantly because the supply of gas in recent years has not kept pace with the demand for natural gas, which has grown throughout the United States as a result of increased reliance on natural gas-based electric generating facilities. We expect that demand for natural gas will remain high into the foreseeable future and that significant price relief will not occur until additional natural gas is added to the nation’s energy supply mix.

Higher gas costs increase our working capital requirements resulting in higher gross receipts taxes in the state of Wisconsin. Higher gas costs combined with poor economic conditions also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills. Our risks related to bad debt expenses

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associated with non-paying customers have increased because federal and state energy assistance dollars have decreased.

As a result of a gas cost recovery mechanism, our gas distribution operations receive dollar for dollar pass through on most of the cost of natural gas. However, increased natural gas costs increase the risk that customers will switch to alternative fuel sources, which could reduce future gas margins.

Weather: Our rates are set by the PSCW based upon estimated temperatures which approximate 20-year averages. Our electric revenues are sensitive to the summer cooling season, and to some extent, to the winter heating season. Our gas revenues are sensitive to the winter heating season. A summary of actual weather information in our service territory during 2003, 2002 and 2001, as measured by degree-days, may be found above in “Results of Operations”.

Interest Rate Risk:We have various short-term borrowing arrangements to provide working capital and general corporate funds. We also have variable rate long-term debt outstanding at December 31, 2003. Borrowing levels under these arrangements vary from period to period depending upon capital investments and other factors. Future short-term interest expense and payments will reflect both future short-term interest rates and borrowing levels.

We performed an interest rate sensitivity analysis at December 31, 2003 of our outstanding portfolio of $315.9 million of short-term debt with a weighted average interest rate of 1.7% and $165.4 million of variable-rate long-term debt with a weighted average interest rate of 1.4%. A one-percentage point change in interest rates would cause our annual interest expense to increase or decrease by approximately $3.2 million before taxes from short-term borrowings and by $1.7 million before taxes from variable rate long-term debt outstanding.

Marketable Securities Return Risk:We fund our pension, other post-retirement benefit and nuclear decommissioning obligations through various trust funds, which in turn invest in debt and equity securities. Changes in the market price of the assets in these trust funds can affect future pension, other post-retirement benefit and nuclear decommissioning expenses. Future contributions to these trust funds can also be affected by changes in the market price of trust fund assets. We expect that the risk of expense and contribution variations as a result of changes in the market price of trust fund assets would be mitigated in part through future rate actions by our various utility regulators. However, we are currently operating under a PSCW-ordered, qualified five-year rate restriction period through 2005. For further information about the rate restriction, see “Rates and Regulatory Matters” below.

At December 31, 2003, we held the following total trust fund assets at fair value, primarily consisting of publicly traded debt and equity security investments.

Wisconsin Electric Power Company	Millions of Dollars
Pension trust funds	$695.2
Nuclear decommissioning trust fund	$674.4
Other post-retirement benefits trust funds	$95.7

We manage our fiduciary oversight of the pension and other post-retirement plan trust fund investments through a Board-appointed Investment Trust Policy Committee. Qualified external investment managers are engaged to manage the investments. We conduct asset/liability studies periodically through an outside investment advisor. The current study projects long-term, annualized returns of approximately 9%.

Fiduciary oversight for the nuclear decommissioning trust fund investments is also the responsibility of the Board-appointed Investment Trust Policy Committee. Qualified external investment managers are also engaged to manage these investments. An asset/liability study is periodically conducted by an outside investment advisor, subject to additional constraints established by the PSCW. The current study projects long-term, annualized returns of approximately 9%. Current PSCW constraints allow a maximum allocation of 65% in equities. The allocation to equities is expected to be reduced as the date for decommissioning Point Beach Nuclear Plant approaches in order to increase the probability of sufficient liquidity at the time the funds will be needed.

We insure various property and outage risks through Nuclear Electric Insurance Limited (NEIL). Annually, NEIL reviews its underwriting and investment results and determines the feasibility of granting a distribution to policyholders. Adverse loss experience, rising reinsurance costs, or impaired investment results at NEIL could result in increased costs or decreased distributions to us.

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Credit Rating Risk: We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. We do have certain agreements in the form of commodity and energy services contracts and employee benefit plans that could require collateral or termination payments in the event of a credit ratings change to below investment grade. At December 31, 2003, we estimate that the potential payments under these agreements that could result from credit rating downgrades totaled approximately $90 million.

Economic Risk.We are exposed to market risks in the regional midwest economy for our utility operations.

Inflationary Risk:We continue to monitor the impact of inflation, especially with respect to the rising costs of medical plans, in order to minimize its effects in future years through pricing strategies, productivity improvements and cost reductions. Except for continuance of an increasing trend in the inflation of medical costs and the impacts on our medical and post-retirement benefit plans, we have expectations of low-to-moderate inflation. We do not believe the impact of general inflation will have a material effect on our future results of operations.

For additional information concerning risk factors, including market risks, see “Cautionary Factors” below.

RATES AND REGULATORY MATTERS

The PSCW regulates retail electric, natural gas, and steam rates in the state of Wisconsin, while the Federal Energy Regulatory Commission (FERC) regulates wholesale power, electric transmission and interstate gas transportation service rates. The Michigan Public Service Commission (MPSC) regulates retail electric rates in the state of Michigan. Orders from the PSCW can be viewed at http://psc.wi.gov/ and orders from the MPSC can be viewed at www.michigan.gov/mpsc/.

Wisconsin Jurisdiction

WICOR Merger Order: As a condition of its March 2000 approval of the WICOR acquisition, the PSCW ordered a five-year rate restriction period in effect freezing electric and natural gas rates for us and Wisconsin Gas effective January 1, 2001. We may seek biennial rate reviews during the five-year rate restriction period limited to changes in revenue requirements as a result of:

Ø Governmental mandates;

Ø Abnormal levels of capital additions required to maintain or improve reliable electric service; and

Ø Major gas lateral projects associated with approved natural gas pipeline construction projects.

To the extent that natural gas rates and rules need to be modified during the integration of our gas operations and those of Wisconsin Gas, our total gas revenue requirements are to remain revenue neutral under the merger order. In its order, the PSCW found that electric fuel cost adjustment procedures as well as gas cost recovery mechanisms would not be subject to the five-year rate restriction period and that it was reasonable to allow us to retain efficiency gains associated with the merger. A full rate review will be required by the PSCW for rates beginning in January 1, 2006.

Limited Rate Adjustment Request: On July 2, 2003, we filed an application with the PSCW for an increase in electric, gas and steam rates for anticipated 2004 revenue deficiencies associated with (1) costs for the new Port Washington Generating Station being constructed as part of Wisconsin Energy’sPower the Future strategy, (2) increased costs linked to changes in Wisconsin’s public benefits legislation and (3) costs related to steam utility operations. The filing identified anticipated revenue deficiencies in 2004 attributable to Wisconsin in the amount of $63.5 million (3.5%) for our electric operations and $0.6 million (3.9%) for our steam operations. The filing also included an additional anticipated 2005 Wisconsin revenue deficiency in the amount of $0.4 million (2.6%) for our steam operations. In 2004, we expect to file with the PSCW for recovery of additional anticipated 2005 electric revenue deficiencies associated with costs for the Elm Road Generating Station. Hearings on our July 2003 request were completed in December 2003, and we anticipate an order from the PSCW on this request in early 2004.

Recent Rate Changes:The table below summarizes the anticipated annualized revenue impact of recent rate changes, primarily in the Wisconsin jurisdiction, authorized by regulatory commissions for our electric, natural gas

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and steam utilities. Our current Wisconsin rates are based on an authorized return on common equity of 12.2%. See “Rates and Regulatory Matters” above for the web site addresses where the related rate orders can be found.

Service—Wisconsin Electric	Incremental Annualized Revenue Increase		Percent Change in Rates		Effective Date
	(Millions)		(%)
Fuel electric, MI	$	3.3	7.6	%	January 1, 2004
Fuel electric, WI(a)	$	6.1	0.3	%	October 2, 2003
Fuel electric, WI(a)	$	55.1	3.3	%	March 14, 2003
Fuel electric, MI	$	0.9	2.0	%	January 1, 2003
Retail electric, WI(b)	$	48.1	3.2	%	October 22, 2002
Retail electric, MI(c)	$	3.2	7.8	%	September 16, 2002
Fuel electric, MI	$	1.6	3.8	%	January 1. 2002
Retail gas(d)	$	3.6	0.9	%	December 20, 2001
Fuel electric, WI(e)	$	20.9	1.4	%	May 3, 2001
Fuel electric, WI(e)	$	37.8	2.5	%	February 9, 2001
Fuel electric, MI	$	1.0	2.4	%	January 1, 2001
Retail electric, WI	$	27.5	1.8	%	January 1, 2001

(a) In October 2003, the PSCW issued a final order authorizing a fuel surcharge for $6.1 million of additional fuel costs. In March 2003, the PSCW issued an interim order authorizing a surcharge for $55.1 million of additional fuel costs on an annualized basis subject to true up.

(b) In October 2002, the PSCW issued its order authorizing a surcharge for recovery of $48.1 million of annual estimated incremental costs associated with the formation and operation of ATC. The additional revenues will be offset by additional transmission costs.

(c) In September 2002, the MPSC issued an order authorizing an annual electric retail rate increase of $3.2 million for Wisconsin Electric. In addition, the September 2002 order issued by the MPSC authorized us to include the transmission costs from ATC prospectively in its Power Supply Cost Recovery clause.

(d) In November 2001, the Milwaukee County Circuit Court overturned the PSCW’s August 2000 final order for natural gas rates and the PSCW reinstated a higher April 2000 interim gas rate order, effective December 2001.

(e) The February 2001 order was an interim order that was effective until the May 2001 final order was issued by the PSCW. The final May 2001 order superceded the February 2001 interim order.

In its final order related to the 2000/2001 biennial period, the PSCW authorized recovery of revenue requirements for, among other things, electric reliability and safety construction expenditures as well as for nitrogen oxide (NO_x) remediation expenditures. Revenue requirements for electric reliability and safety construction expenditures were subject to refund at the end of 2001 to the extent that actual expenditures were less than forecasted expenditures included in the final order. During 2002, we accrued a $1.1 million refund liability associated with the electric safety and reliability spending requirements subject to PSCW review and future resolution. In March 2000, the PSCW had previously authorized all Wisconsin utilities to depreciate NO_xemission reduction costs over an accelerated 10-year recovery period. Due to the uncertainty regarding the level and timing of these expenditures, the PSCW, in its final order, required us to establish escrow accounting for the revenue requirement components associated with NO_xexpenditures. Our actual NO_xremediation expenditures resulted in an under-spent balance of approximately $2.7 million in the escrow account, a component of deferred regulatory liabilities at the end of 2003. The NO_xescrow balance will be impacted by future NO_x expenditures and rate making activities.

We have the ability to request biennial rate reviews for certain changes in revenue requirement items. We are currently updating a request for regulatory relief for the year beginning January 1, 2005. See “Limited Rate Adjustment Request” above for more information.

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Electric Transmission Cost Recovery: In September 2001, we requested that the PSCW approve $58.8 million of annual rate relief to recover the estimated incremental costs associated with the formation and operation of ATC, which was designed to enhance transmission access and increase electric system reliability and market efficiency in the state of Wisconsin. We were also seeking to recover associated incremental transmission costs of the Midwest Independent Transmission System Operator Inc. (Midwest ISO), the multi-state organization that monitors and controls electric transmission throughout the Midwest. These increased costs are primarily due to the implementation of capital improvement projects for the period 2001-2005 and associated operation costs that are expected to increase transmission capacity and reliability. In October 2002, the PSCW issued its order authorizing a surcharge for recovery of $48.1 million of annual costs reflecting lower projected transmission costs through 2005 than we estimated. Recognizing the uncertainty of these transmission related costs, the PSCW order authorized a four year escrow accounting treatment such that rate recovery will ultimately be trued-up to actual costs plus a return on the unrecovered costs. The October 2002 order increased annual revenues and operating costs by approximately $48.1 million, with an insignificant impact to net earnings. We estimate that we are recovering approximately 96% of our incremental transmission related costs from our customers.

Fuel Cost Adjustment Procedure: We operate under a fuel cost adjustment clause for fuel and purchased power costs associated with the generation and delivery of electricity and purchase power contracts. In December 2000, we submitted an application to the PSCW seeking a $51.4 million increase in rates on an expedited basis to recover increased costs of fuel and purchased power in 2001. We revised our projected power supply cost shortfall in January 2001 to reflect updated natural gas cost projections for 2001. This update resulted in a request for an additional $11.1 million in 2001, bringing the total requested increase to $62.5 million. In February 2001, the PSCW issued an interim order authorizing a $37.8 million increase in rates for 2001 power supply costs. The PSCW issued a final order in May 2001, effective immediately, authorizing a total increase in rates of $58.7 million (or an additional $20.9 million over the interim order). Under the final order, we would have to refund to customers any over recoveries of fuel costs as a result of the surcharges authorized in 2001. During 2003, 2002 and 2001, we did not over recover fuel costs.

During the second quarter of 2002, the PSCW issued an order authorizing new fuel cost adjustment rules to be implemented in the Wisconsin retail jurisdiction. The order redefined fuel for fuel cost recovery. The new rules will not be effective for us until January 2006, the end of a five-year rate freeze associated with the WICOR Merger Order. Until such time, we will operate under an approved transaction mechanism similar to the old fuel cost adjustment procedure.

In February 2003, we completed a power supply cost analysis, which included updated natural gas cost projections for 2003. Based on this analysis, in February 2003 we determined that projected costs had deviated outside of a range prescribed by the PSCW when compared to fuel and purchased power costs authorized in current rates. As a result, we filed a request with the PSCW to increase Wisconsin retail electric rates by $55.1 million annually to recover the forecasted increases in fuel and purchased power costs. We received an interim order from the PSCW authorizing an increase of $55.1 million in electric rates in March 2003. In October 2003, the PSCW approved the fuel surcharge adjustment request authorizing an increase of $61.2 million for 2003, $6.1 million more than the interim order on an annualized basis. The final order reflects seven months of actual costs incurred plus changes in natural gas prices. The final order imposes an obligation on us to refund any fuel surcharge amounts that result in excess revenues as defined. We do not anticipate a refund will occur.

Gas Cost Recovery Mechanism: As a result of Wisconsin Energy’s acquisition of WICOR, the PSCW required similar gas cost recovery mechanisms (GCRM) for our gas operations and for those of Wisconsin Gas. Prior to the acquisition, we had operated under a modified dollar-for-dollar GCRM, which included after the fact prudence reviews by the PSCW. The majority of gas costs are passed through to customers under our existing gas cost recovery mechanism.

In February 2001, the PSCW issued an order to us authorizing a new GCRM. Under the new GCRM, gas costs are passed directly to customers through a purchased gas adjustment clause. However, we may increase or decrease earnings by up to approximately 2.5% of our total annual gas costs based upon how closely actual gas commodity and capacity costs compare to benchmarks established by the PSCW.

Commodity Price Risk Programs:Our gas operations have commodity risk management programs that have been approved by the PSCW. These programs hedge the cost of natural gas. As gas costs are recovered from customers, changes in the value of the financial instruments do not impact net income. These programs allow our gas operations to utilize option contracts to reduce market risk associated with fluctuations in the price of natural gas

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purchases and gas in storage. Under these programs, we have the ability to hedge up to 50% of our planned flowing gas and storage inventory volumes. The cost of applicable call and put option contracts, as well as gains or losses realized under the contracts, do not affect net income as they are fully recovered under the purchase gas adjustment clauses of our gas cost recovery mechanism. In addition, under these programs, we use derivative financial instruments to manage the cost of gas. The cost of these financial instruments, as well as any gains or losses on the contracts, are subject to sharing under the incentive mechanisms. For information concerning commodity price risk as it applies to electric operations see “Commodity Price Risk” above.

Bad Debt Expense:In 2003, due to a combination of unusually high natural gas prices, the soft economy within our utility service territories and limited governmental assistance available to low-income customers, we have seen a significant increase in uncollectible accounts receivable. Because of this, we sent a letter to the PSCW in July 2003 requesting authority to defer for future rate recovery all residential bad debt write-offs during 2003 in excess of amounts included in current annual utility rates. The PSCW approved our request for deferral of 2003 uncollectible accounts receivable effective October 2003. We have deferred approximately $10.9 million in uncollectible accounts receivable as of December 31, 2003. Our annual residential bad debt expense in base rates is approximately $11.6 million.

Power the Future—Port Washington:The PSCW issued a written order on December 20, 2002 (the Port Order) granting Wisconsin Energy, We Power and us a CPCN to commence construction of the Port Washington Generating Station consisting of two 545-megawatt natural gas-based combined cycle generating units (Port Units 1 and 2) on the site of our existing Port Washington Power Plant. The Port Order also authorized Wisconsin Gas to proceed with the construction of a connecting natural gas lateral and ATC to construct required transmission system upgrades to serve the Port Washington Generating Station. As part of the proceedings, the PSCW approved the lease agreements and related documents under which we will staff, operate and maintain Port Units 1 and 2. Key financial terms of the leased generation contracts include:

Ø Initial lease term of 25 years with the potential for subsequent renewals at reduced rates;

Ø Cost recovery over a 25 year period on a mortgage basis amortization schedule;

Ø Imputed capital structure of 53% equity, 47% debt for lease computation purposes;

Ø Authorized rate of return of 12.7% on equity for lease calculation purposes;

Ø Fixed construction cost of the two Port units at $309.6 million and $280.3 million (2001 dollars) subject to escalation at the GDP inflation rate; and

Ø Ongoing PSCW supervisory authority only over those lease terms and conditions specifically identified in the Port Order, which do not include the key financial terms.

After receiving approval for the Port Washington project, We Power entered into binding contracts with third parties to secure necessary engineering, design and construction services and major equipment components for Port Unit 1. In January 2003, we commenced demolition of two of our existing coal-based generating units on the Port Washington plant site to make room for the new facility. We Power began construction of the new facility in July 2003 and expects to complete construction by the end of the second quarter of 2005. We Power began collecting certain costs from us in the third quarter of 2003 as provided for in lease generation contracts that were signed in May 2003. In January 2003, we filed a request with the PSCW to defer costs for recovery in future rates. Wisconsin state law allows us to recover fully in our retail rates any portion of a lease generation contract that the PSCW has approved and allocated to retail electric service. The PSCW approved the request in an open meeting in April 2003. (See “Limited Rate Adjustment Request” above for further information.) Before beginning construction of Port Unit 2, the order requires that an updated demand and energy forecast be filed with the PSCW to document market demand for additional generating capacity. In October 2003, we received approval from the FERC to transfer by long-term lease certain associated FERC jurisdictional assets from We Power to us.

In March 2003, an individual who participated in the Port Washington CPCN proceedings before the PSCW filed a petition for review with the Dane County Circuit Court requesting the Court to reverse and remand in its entirety the PSCW’s December 2002 Port Order granting the CPCN. In January 2004, the Dane County Circuit Court issued a decision vacating the Port Order and remanding the matter to the PSCW to develop additional environmental analysis to justify its decision to perform only an Environmental Assessment, rather than a more comprehensive Environmental Impact Statement. The PSCW has begun a process to revise the Environmental Assessment consistent with the Court’s decision. The PSCW has not made a decision on whether to appeal the Dane County Circuit Court decision.

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Associated with construction of the Port Washington Generating Station, Wisconsin Gas received a Certificate of Authority from the PSCW in January 2003 authorizing construction of a 16.8 mile gas lateral that will connect the plant to the ANR Pipeline. It will also improve reliability for the natural gas distribution system in the area. Wisconsin Gas received a Chapter 30 wetland permit from the Wisconsin Department of Natural Resources (WDNR) in July 2003 approving construction of this lateral. The WDNR permitted construction of substantially the entire lateral consistent with the planned route previously approved by the PSCW, with certain exceptions. Wisconsin Gas has modified the planned route pursuant to the WDNR’s request and received the necessary approvals for the modified route. Including the requested changes, the PSCW approved an updated cost estimate for the project of $41.5 million in November 2003. Construction of the lateral is scheduled to begin in spring 2004 and to be completed by late 2004.

In July and August 2003, two landowners filed separate Petitions for Review in Ozaukee County Circuit Court challenging the Chapter 30 permit issued in July 2003 by the WDNR to Wisconsin Gas for the Port Washington Lateral natural gas pipeline. Further, in September 2003, one of the same landowners filed an additional Petition for Review in Ozaukee County Circuit Court challenging the WDNR’s denial of a request for a contested case hearing on the issuance of the Chapter 30 permit. Wisconsin Energy has reached a settlement with the landowners and the Petitions for Review have been dismissed.

Power the Future—Elm Road:In November 2003, the PSCW issued an order (the Elm Road Order) granting Wisconsin Energy, We Power and us a CPCN to commence construction of two 615-megawatt coal-based units (the Elm Road units) to be located on the site of our existing Oak Creek Power Plant. The Elm Road Order concluded:

Ø Additional electric generation was required for Southeast Wisconsin;

Ø A diversity of fuel sources best serves the state;

Ø Two coal-fired super-critical pulverized coal units should be constructed with the first plant going on line in 2009 and the second going on line in 2010;

Ø The cost to construct the two coal units will be $2.15 billion (subject to adjustment for one year of escalation costs), which is expected to result in an approved project cost of $2.19 billion;

Ø The return on equity on the lease agreement will be set at 12.7% with a capital structure that includes 55% equity;

Ø If the actual project cost is less than the approved project cost, the actual cost will be used in the lease. If the actual project cost exceeds the approved project cost, excess costs up to 5% of the approved project cost may be recoverable, subject to a prudence requirement;

Ø Cost recovery over a 30 year period on a mortgage basis amortization schedule with the potential for subsequent renewals at reduced rates;

Ø The CPCN will be granted contingent upon us obtaining the necessary air quality and water permits;

Ø Ongoing PSCW supervisory authority only over those lease terms and conditions specifically identified in the Elm Road Order, which do not include the key financial terms; and

Ø The third proposed integrated gasification combined cycle unit was not approved at this time as the technology is not currently considered cost-effective.

We expect that we will have co-owners for approximately 17% of the project. In December 2003, Wisconsin Energy submitted lease generation contracts for the Elm Road units to the PSCW for approval. We anticipate these lease generation contracts, when approved by the PSCW, will, under state law, be recovered fully in our retail rates for that portion which the PSCW allocates to retail electric service.

In March 2003, the City of Oak Creek reached a tentative environmental and economic agreement with us covering our expansion plans for new generation at the Oak Creek site. We have also agreed to follow the City of Oak Creek’s conditional use permit for construction on the Oak Creek site.

Four appeals challenging the PSCW’s Elm Road Order have been filed, which appeals have been consolidated in Dane County Circuit Court. We have filed a Notice of Appearance and Statement of Position in three of these proceedings requesting that the PSCW’s decision be upheld and the petitions be dismissed. Also, two cases were filed in January 2004 in Dane County Circuit Court against the WDNR contending that the WDNR did not comply with state laws when it participated with the PSCW in preparing the Environmental Impact Statement for the Elm Road units. We have filed a Notice of Appearance and Statement of Position in these two proceedings requesting that the WDNR’s decision be upheld and the petitions be dismissed.

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In September 2003, several parties filed a request with the WDNR for a contested case hearing in connection with our application to the WDNR for a water discharge permit for the Elm Road units. That request was granted. In January 2004, the WDNR issued the air pollution control construction permit to us for the Elm Road units. In February 2004, parties submitted to the WDNR and to the Dane County Circuit Court requests for a contested case hearing and for judicial review, respectively, on the Elm Road units air pollution control construction permit. No proceedings on these permit hearings have been scheduled. We continue to work with the PSCW and the WDNR, and other agencies, to obtain all required permits and project approvals.

Michigan Jurisdiction

In mid-November 2000, we submitted an application to the MPSC requesting an electric retail rate increase of $3.7 million or 9.4% on an annualized basis. Hearings on this rate relief request were completed in June of 2001. In December of 2001, the MPSC issued an order reopening the case on a limited basis to incorporate the rate effects of the transfer of our transmission assets to ATC. Hearings were completed in April 2002. In September 2002, the MPSC issued its order authorizing an annual electric retail rate increase of $3.2 million effective immediately. On February 20, 2003, International Paper Corporation filed a claim of appeal from the MPSC’s final order in Case No. U-12725, which awarded us a $3.2 million rate increase and changed the procedures by which we recover the cost of obtaining transmission services. We believe the MPSC will prevail in defense of its order.

Used Nuclear Fuel Rates:In March 2003, a group of consumer advocacy groups led by the Michigan Environmental Council (collectively, MEC) filed a Formal Complaint and Request to Open a Formal Proceeding (the Complaint) with the MPSC naming us and four other utilities operating in Michigan as defendants. MEC claims that we improperly collect revenues for used nuclear fuel storage and disposal. The amounts of these revenues claimed by MEC to be collected from Michigan customers is between $2.3 million and $11.4 million. MEC requested that the MPSC open a contested case and review the rate making mechanisms for these used nuclear fuel revenues, as well as prospective remedies including ratepayer reductions, long-term mechanisms to ensure that used nuclear fuel revenues do not become stranded and performance or surety bonds to protect Michigan ratepayers. In April 2003, the MPSC certified the Complaint. We filed a notice of intent to file claim with the Michigan Court of Claims and a motion to dismiss the Complaint with the MPSC in May 2003. MEC filed its answer to our motion to dismiss in July 2003. We believe that the revenues are properly collected as the collection of these revenues is authorized by the MPSC. The resolution of this matter is not expected to have a material impact on our financial condition or results of operations.

Electric Transmission Cost Recovery:Consistent with the requests in Wisconsin noted above, we filed a request with the MPSC in September 2001 for rate recovery of estimated 2002 transmission costs over 2001 levels in the amount of $0.3 million through the Michigan Power Supply Cost Recovery mechanism. In September 2002, the MPSC issued an order that authorized us to recover transmission costs in our Power Supply Cost Recovery clause prospectively. In April 2003, we received MPSC approval to defer costs associated with the start-up, formation of, and obtaining transmission service from ATC. As of December 31, 2003, we have deferred $1.2 million of start-up and network charges for the period January 2001 through September 2002 plus carrying costs.

ELECTRIC SYSTEM RELIABILITY

In response to customer demand for higher quality power required by modern digital equipment, we are evaluating and updating our electric distribution system as part of Wisconsin Energy’sPower the Future strategy. We are taking some immediate steps to reduce the likelihood of outages by upgrading substations and rebuilding lines to upgrade voltages and reliability. These improvements, along with better technology for analysis of our existing system, better resource management to speed restoration and improved customer communication, are near-term efforts to enhance our current electric distribution infrastructure. In the long-term, we are initiating a new distribution system design that is expected to consistently provide the level of reliability needed for a digital economy, using new technology, advanced communications and a two-way electricity flow. Implementation of Wisconsin Energy’sPower the Future strategy is subject to a number of state and federal regulatory approvals. For additional information, see “Corporate Developments” above.

We had adequate capacity to meet all of our firm electric load obligations during 2003. All of our generating plants performed well during the hottest periods of the summer and all power purchase commitments under firm contract were received. During this period, public appeals for conservation were not required, nor was there the need to

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interrupt or curtail service to non-firm customers who participate in load management programs in exchange for discounted rates. In mid-May a flood at a hydroelectric dam owned by another utility forced a complete shutdown of our 618-megawatt Presque Isle Power Plant in Marquette, Michigan, which resulted in the curtailment of non-firm service to some customers, as well as brief interruptions to firm service. Deliveries were also curtailed on several occasions to certain special contract customers in the Upper Peninsula of Michigan because of transmission constraints in the area including an incident in December 2003. During the December incident, flow was interrupted on the three main electric transmission lines owned by ATC and connecting Wisconsin to the Upper Peninsula of Michigan. This incident also resulted in short outages to some firm customers.

We expect to have adequate capacity to meet all of our firm load obligations during 2004. However, extremely hot weather, unexpected equipment failure or unavailability could require us to call upon load management procedures during 2004 as we have in past years.

ENVIRONMENTAL MATTERS

Consistent with other companies in the energy industry, we face potentially significant ongoing environmental compliance and remediation challenges related to current and past operations. Specific environmental issues affecting our utility operations include but are not limited to (1) air emissions such as carbon dioxide (CO₂), sulfur dioxide (SO₂), nitrogen oxide (NOx), small particulates and mercury, (2) disposal of combustion by-products such as fly ash, (3) remediation of former manufactured gas plant sites, (4) disposal of used nuclear fuel and (5) the eventual decommissioning of nuclear power plants.

We are currently pursuing a proactive strategy to manage our environmental issues including (1) substituting new and cleaner generating facilities for older facilities as part of Wisconsin Energy’sPower the Future strategy, (2) developing additional sources of renewable electric energy supply, (3) participating in regional initiatives to reduce the emissions of NO_x from our fossil fuel-based generating facilities, (4) entering into agreements with the WDNR and EPA to reduce emissions of SO₂ and NOx from our coal-based power plants in Wisconsin and Michigan by more than 65% and mercury by 50% within 10 years, (5) recycling of ash from coal-based generating units and (6) the clean-up of former manufactured gas plant sites. The capital cost of implementing the EPA agreement is estimated to be approximately $600 million over 10 years. For further information concerning the associated consent decree, see “Note O — Commitments and Contingencies” in the Notes to Consolidated Financial Statements in this report. For further information concerning disposal of used nuclear fuel and nuclear power plant decommissioning, see “Nuclear Operations” below and “Note E — Nuclear Operations” in the Notes to Consolidated Financial Statements in this report, respectively.

National Ambient Air Quality Standards:In July 1997, the EPA revised the National Ambient Air Quality Standards for ozone and fine particulate matter. Legal challenges to the new standards are complete and the EPA and the states are currently developing rules to implement them. Although specific emission control requirements are not yet defined, we believe that the revised standards will likely require significant reductions in SO₂ and NO_x emissions from coal-based generating facilities. We expect that reductions needed to achieve compliance with the 8-hour ozone attainment standard will be implemented in stages from 2007 through 2010, beginning with the 1-hour ozone reductions described below. Reductions associated with the new fine particulate matter standards are expected to be implemented in stages after the year 2010 and extending to the year 2017. Beyond the cost estimates identified below, we are currently unable to estimate the impact of the revised air quality standards on our future liquidity, financial condition or results of operation.

Ozone Non-Attainment Standards: The 1-hour ozone nonattainment rules currently being implemented by the state of Wisconsin and ozone transport rules implemented by the state of Michigan limit NOx emissions in phases over the next five years.

We currently expect to incur total annual operation and maintenance costs of $1-2 million during the period 2004 through 2005 to comply with the Michigan and Wisconsin rules. We believe that compliance with the NO_x emission reductions requirements will substantially mitigate costs to comply with the EPA’s 8-hour ozone National Ambient Air Quality Standards discussed above.

In January 2000, the PSCW approved our comprehensive plan to meet the Wisconsin regulations, permitting recovery in rates of NO_x emission reduction costs over an accelerated 10-year recovery period.

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Mercury Emission Control Rulemaking: As required by the 1990 amendments to the Federal Clean Air Act, the EPA issued a regulatory determination in December 2000 that utility mercury emissions should be regulated. The EPA issued draft rules in December 2003 and will issue final rules by December 2004. In June 2001, the WDNR independently developed draft mercury emission control rules that would affect electric utilities in Wisconsin. In May 2003, the WDNR released a final draft of the proposed rules, which include mercury emission reductions of 40% by 2010 and 80% by 2015. The rules provide for a multi-emission alternative approach for compliance, but it is not clear if this would apply to the second phase of reductions. In June 2003, the Natural Resources Board approved the rules and sent them to the Wisconsin Legislature. The Wisconsin Legislature rejected the rules during the third quarter of 2003. We are currently unable to predict the ultimate rules, if any, that will be developed and adopted by the EPA or the WDNR, nor are we able to predict the impacts, if any, that the EPA’s and WDNR’s mercury emission control rulemakings might have on the operations of our existing or Wisconsin Energy’s anticipated coal-based generating facilities.

Manufactured Gas Plant Sites:We are voluntarily reviewing and addressing environmental conditions at a number of former manufactured gas plant sites. For further information, see “Note O — Commitments and Contingencies” in the Notes to Consolidated Financial Statements.

Ash Landfill Sites:We aggressively seek environmentally acceptable, beneficial uses for our combustion byproducts. For further information, see “Note O—Commitments and Contingencies” in the Notes to Consolidated Financial Statements.

EPA Information Requests:We received requests for information from the EPA regional offices pursuant to Section 114(a) of the Clean Air Act. For further information, see “Note O—Commitments and Contingencies” in the Notes to Consolidated Financial Statements.

LEGAL MATTERS

Giddings & Lewis Inc./City of West Allis Lawsuit:In July 1999, a jury issued a verdict against us awarding the plaintiffs $4.5 million in compensatory damages and $100 million in punitive damages in an action alleging that we had deposited contaminated wastes at two sites in West Allis, Wisconsin owned by the plaintiffs. In September 2001, the Wisconsin Court of Appeals overturned the $100 million punitive damage award and remanded the punitive damage claim to the lower court for retrial. In January 2002, the Wisconsin Supreme Court denied the plaintiffs’ petition for review. Plaintiffs’ claims were settled during 2002 for a total cost of $17.3 million. During 2003, we recovered settlements with various insurance carriers for approximately $11.2 million. We are continuing to pursue litigation against the remaining insurance carriers and other third parties. For further information, see “Note O — Commitments and Contingencies” in the Notes to Consolidated Financial Statements in this report.

Presque Isle Flood:During the second quarter of 2003, our Presque Isle Power Plant was temporarily shut down due to the failure of a hydroelectric reservoir dike which flooded Marquette, Michigan. We estimate that our fuel and purchased power costs increased by approximately $9 million due to the need for replacement power during the plant outage. These increased costs were included as part of the fuel surcharge request discussed above. In addition, we incurred approximately $13.5 million in damage to equipment and property. We are pursuing recovery from insurance carriers and other parties for the above costs. We are continuing to analyze and refine the costs associated with this matter.

NUCLEAR OPERATIONS

Point Beach Nuclear Plant:We own two 518-megawatt electric generating units at Point Beach Nuclear Plant in Two Rivers, Wisconsin which are operated by Nuclear Management Company, LLC (NMC), a company owned by one of our affiliates and affiliates of other unaffiliated utilities. During 2003, 2002 and 2001, Point Beach provided 25% of our net electric energy supply. The United States Nuclear Regulatory Commission (NRC) operating licenses for Point Beach expire in October 2010 for Unit 1 and in March 2013 for Unit 2.

In July 2000, our senior management authorized the commencement of initial design work for the power uprate of both units at Point Beach. Subject to approval by the PSCW, the project could add approximately 90 megawatts of electrical output to Point Beach. We are currently evaluating the timing for implementation of the power uprate

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project. In February 2003, Point Beach completed an equipment upgrade, which resulted in a capacity increase of 7 megawatts per generating unit.

In 2003, NMC formed an operating license renewal team which completed a technical and economic evaluation of license renewal. Based upon the results of this evaluation and following approval by executive management and our Board of Directors in December 2003, NMC filed an application in February 2004 with the NRC to renew the operating licenses for both of Point Beach’s nuclear reactors for an additional 20 years.

In February 2003, NRC issued an order establishing interim inspection requirements for reactor vessel heads at pressurized water reactors. The order formally establishes requirements for licensees to implement the provisions of NRC Bulletin 2002-02, “Reactor Pressure Vessel Head and Vessel Head Penetration Nozzle Inspection Programs,” issued in August 2002. We plan to replace both reactor vessel heads during the 2005 refueling outages as an alternative to incurring the additional time and costs of these examinations and filed such an application with the PSCW in June 2003. In October 2003, the PSCW approved reactor vessel head replacement for Units 1 and 2 at Point Beach. Total capital expenditure to replace the two reactor vessel heads are estimated at approximately $54 million.

During 2002 and 2003, the NRC issued Final Significance Determination letters for two red (high safety significance) inspection findings regarding problems identified by Point Beach with the performance of the auxiliary feedwater system recirculation lines. During 2003 the NRC conducted a three-phase supplemental inspection of Point Beach in accordance with NRC Inspection Procedure 95003 to review corrective actions for the findings as well as the effectiveness of the corrective action, emergency preparedness and engineering programs.

The inspection results were presented at a public meeting in December 2003 and documented in a February 2004 NRC letter to NMC. The NRC determined that the plant is being operated in a manner that ensures public safety but also identified several performance issues in the areas of problem identification and resolution, emergency preparedness, electrical design basis calculation control and engineering-operations communication.

NMC responded to the supplemental inspection in February 2004 with specific commitments to address the NRC concerns, including revision of the Point Beach Excellence Plan. NRC will review the adequacy of the revised Excellence Plan and its implementation and will continue to provide increased oversight at Point Beach.

As a result of the September 11, 2001 terrorist attacks, NRC and the industry have been strengthening security at nuclear power plants. Security at Point Beach remains at a high level, with limited access to the site continuing. NMC has responded to NRC’s February 2002 Order for interim safeguards and security compensatory measures. NMC has also responded to NRC orders regarding security of independent spent fuel storage installations, design basis threat, and security officer training and work hours. Federal legislation is also pending on the federalization of nuclear plant security. We are currently unable to estimate the impact, if any, that may result.

Used Nuclear Fuel Storage and Disposal: We are authorized to load and store sufficient dry fuel storage containers to allow Point Beach Units 1 and 2 to operate to the end of their current operating licenses but not to exceed the original 48-canister capacity of the dry fuel storage facility.

Temporary storage alternatives at Point Beach are necessary until the United States Department of Energy takes ownership of and permanently removes the used fuel as mandated by the Nuclear Waste Policy Act of 1982, as amended in 1987 (the Waste Act). Effective January 31, 1998, the Department of Energy failed to meet its contractual obligation to begin removing used fuel from Point Beach, a responsibility for which we have paid a total of $193.2 million over the life of the plant. The Department of Energy has indicated that it does not expect a permanent used fuel repository to be available any earlier than 2010. It is not possible, at this time, to predict with certainty when the Department of Energy will actually begin accepting used nuclear fuel.

On August 13, 2000, the United States Court of Appeals for the Federal Circuit ruled in a lawsuit brought by Maine Yankee and Northern States Power Company that the Department of Energy’s failure to begin performance by January 31, 1998 constituted a breach of the Standard Contract, providing clear grounds for filing complaints in the Court of Federal Claims. Consequently, we filed a complaint on November 16, 2000 against the Department of Energy in the Court of Federal Claims. The matter is pending. As of December 2003, we have incurred damages in excess of $70 million, which we seek to recover from the Department of Energy. Damages continue to accrue, and, accordingly, we expect to seek recovery of our damages in this lawsuit.

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In January 2002, as required by the Waste Act, the Secretary of Energy notified the Governor of Nevada and the Nevada Legislature that he intended to recommend to the President that the Yucca Mountain site is scientifically sound and suitable for development as the nation’s long-term geological repository for used nuclear fuel. In February 2002, the Secretary provided the formal recommendation to the President. In a February 2002 letter to Congress, the President expressed his support for the development of the Yucca Mountain site. The letter also affirmed the need for a permanent repository by supporting the need for nuclear power and its cost competitiveness, as well as acknowledging that successful completion of the repository program will redeem the clear Federal legal obligation set forth in the Waste Act. In April 2002, the Nevada Governor announced the state’s official disapproval of the President’s recommendation. In May 2002, the U.S. House of Representatives endorsed the President’s recommendation to develop the Yucca Mountain site as the nation’s long-term geological repository for used nuclear fuel overriding the state of Nevada’s objections. In July 2002, the U.S. Senate approved Yucca Mountain as such a repository. The President signed the resolution in July 2002 which cleared the way for the Department of Energy to begin preparation of the application to the NRC for a license to design and build the repository.

INDUSTRY RESTRUCTURING AND COMPETITION

Electric Utility Industry

Across the United States, electric industry restructuring progress has generally stalled subsequent to the California price and supply problems in early 2001. The wide-spread outage in the eastern United States in August of 2003 further slowed the pace of electric industry restructuring. FERC continues to strongly support large Regional Transmission Organizations (RTOs), which will affect the structure of the wholesale market. The timeline for restructuring and retail access continues to be stretched out and it is uncertain when retail access will happen in Wisconsin. Late in 2003 a federal energy bill containing changes that would impact the electric utility industry passed the U. S. House of Representatives, however it was not passed by the Senate. Major issues in industry restructuring like deregulating existing generation, unbundling transmission and generation from distribution costs, implementing RTOs, and market power mitigation received little attention in 2003. We continue to focus on infrastructure issues through Wisconsin Energy’sPower the Future growth strategy.

Restructuring in Wisconsin:Electric utility revenues in Wisconsin are regulated by the PSCW. Due to many factors, including relatively competitive electric rates charged by the state’s electric utilities, Wisconsin is proceeding with restructuring of the electric utility industry at a much slower pace than many other states in the United States. Instead, the PSCW has been focused in recent years on electric reliability infrastructure issues for the state of Wisconsin such as:

Ø Addition of new generating capacity in the state;

Ø Modifications to the regulatory process to facilitate development of merchant generating plants;

Ø Continued development of a regional independent electric transmission system operator; and

Ø Improvements to existing and addition of new electric transmission lines in the state.

The PSCW continues to maintain the position that the question of whether to implement electric retail competition in Wisconsin should ultimately be decided by the Wisconsin Legislature. No such legislation has been introduced in Wisconsin to date.

Restructuring in Michigan: Electric utility revenues in Michigan are regulated by the MPSC. In June 2000, the Governor of Michigan signed the “Customer Choice and Electric Reliability Act” into law empowering the MPSC to implement electric retail access in Michigan. The new law provides that as of January 1, 2002 all Michigan retail customers of investor-owned utilities have the ability to choose their electric power producer. The Michigan Retail Access law was characterized by the Michigan Governor as “Choice for those who want it and protection for those who need it.”

As of January 1, 2002, our Michigan retail customers were allowed to remain with their regulated utility at regulated rates or choose an alternative electric supplier to provide power supply service. We have maintained our generation

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capacity and distribution assets and provide regulated service as we have in the past. We continue providing distribution and customer service functions regardless of the customer’s power supplier.

Competition and customer switching to alternative suppliers in our service territory in Michigan has been limited. With the exception of one general inquiry, no alternate supplier activity has occurred in our service territory in Michigan, reflecting the small market area, our competitive regulated power supply prices and a lack of interest in general in the Upper Peninsula of Michigan as a market for alternative electric suppliers.

Restructuring in Illinois: In 1999, the state of Illinois passed legislation that introduced retail electric choice for large customers and introduced choice for all retail customers in May 2002. This legislation is not expected to have a material impact on our business. We have one wholesale customer in Illinois, the City of Geneva, whose contract is scheduled to expire on December 31, 2005.

Electric Transmission

American Transmission Company:Effective January 1, 2001, we transferred all of our electric utility transmission assets to ATC in exchange for an ownership interest in this new company. Joining ATC is consistent with the FERC’s Order No. 2000, intended to foster competition, efficiency and reliability in the electric industry.

ATC is regulated by the FERC for all rate terms and conditions of service and is a transmission-owning member of the Midwest ISO. As of February 1, 2002, operational control of ATC’s transmission system was transferred to the Midwest ISO and we became a non-transmission owning member and customer of the Midwest ISO.

Midwest ISO:In connection with its role as a FERC-approved RTO, the Midwest ISO is in the process of developing a bid-based energy market, which is currently proposed to be implemented on December 1, 2004. In connection with the development of the energy market, the Midwest ISO is developing a market-based platform for valuing transmission congestion premised upon the locational marginal pricing (LMP) system that has been implemented in certain northeastern and mid-atlantic states. It is expected that the LMP system will include the ability to mitigate or eliminate congestion costs through the use of Financial Transmission Rights (FTR) which will be initially allocated by the Midwest ISO and, it is anticipated, will be available through an auction-based system run by the Midwest ISO. It is unknown at this time how and in what quantity FTRs will be initially allocated by the Midwest ISO and, what, if any, financial impact the LMP congestion pricing system might have on us. Additionally, the Midwest ISO is currently deferring the costs to start-up their energy market (new software systems and personnel), but once the market is operational, these costs will be charged to customers.

In the Midwest ISO, base transmission costs are currently being paid by load serving entities (LSEs) located in the service territories of each Midwest ISO transmission owner in proportion to the load served by the LSE versus the total load of the service territory. This “license plate” rate design is scheduled to be replaced after a six-year phase-in of rates in Midwest ISO. It is unknown at this point what rate design will replace the license plate rate design or the impact that any new rate design will have on our results of operations or financial position.

Lost Revenue Charges:The FERC permits transmission owning utilities that have not joined an RTO to propose a charge to recover revenues that would be lost as a result of RTO membership. These lost revenues result from FERC’s requirement that, within an RTO and for transmission between the systems operated by the Midwest ISO and PJM Interconnection, LLC, entities that currently pay a transmission charge to move energy through or out of a neighboring transmission system will no longer pay this charge to the neighboring transmission system owner or operator upon the neighboring transmission system owner or operator joining an RTO.

In December 2003, we, along with other entities, reached an agreement with the Midwest ISO and a consortium of companies referred to as the Grid America Companies on a lost revenue payment resulting from the Grid America Companies’ decision to place their transmission facilities under the operational control of the Midwest ISO. Discussions as to appropriate lost revenue charges are currently ongoing with regard to several entities’ decisions, including that of Commonwealth Edison Company, a transmission provider to us, to place their transmission facilities under the control of PJM.

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Natural Gas Utility Industry

Restructuring in Wisconsin: The PSCW has instituted generic proceedings to consider how its regulation of gas distribution utilities should change to reflect the changing competitive environment in the natural gas industry. To date, the PSCW has made a policy decision to deregulate the sale of natural gas in customer segments with workably competitive market choices and has adopted standards for transactions between a utility and its gas marketing affiliates. However, work on deregulation of the gas distribution industry by the PSCW is presently on hold. Currently, we are unable to predict the impact of potential future deregulation on our results of operations or financial position.

ACCOUNTING DEVELOPMENTS

New Pronouncements: In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation 46, Consolidation of Variable Interest Entities (FIN 46). This standard requires an enterprise that is the primary beneficiary of a variable interest entity to consolidate that entity. The Interpretation was applied to any existing interests in variable interest entities beginning in the third quarter of 2003. In October 2003, the FASB deferred the adoption of FIN 46 for entities commonly referred to as special-purpose entities to the first reporting period ending after December 15, 2003. See “Note B — Recent Accounting Pronouncements” in the Notes to Consolidated Financial Statements for additional information. In December 2003, the FASB revised the effective date for all other types of entities to financial statements for periods after March 15, 2004. While we are continuing to evaluate the impact of the application of these new rules, we do not expect adoption of the final phase of Interpretation 46 to have a significant impact on our balance sheets or on our results of operations.

The FASB issued FASB Staff Position No. SFAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”, (FSP 106-1) that allows sponsors to elect to defer recognition of the effects of the Act. In accordance with FSP 106-1, we elected to defer recognition of the effects of the Act. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require us to change previously reported information. See “Note K — Benefits” in the Notes to Consolidated Financial Statements in this report for more information.

CRITICAL ACCOUNTING ESTIMATES

Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles (GAAP) 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 the likelihood of success of particular projects, 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. In addition, the financial and operating environment also may have a significant effect, not only on the operation of our business, but on our 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 have not changed.

The following is a list of accounting policies that are most significant to the portrayal of our financial condition and results of operations and that require management’s most difficult, subjective or complex judgments.

Regulatory Accounting:Our electric, gas and steam operations operate under rates established by state and federal regulatory commissions, which are designed to recover the cost of service and provide a reasonable return to investors. Developing competitive pressures in the utility industry may result in future utility prices which are based upon factors other than the traditional original cost of investment. In this situation, continued deferral of certain regulatory asset and liability amounts on our books, as allowed under Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71), may no longer be appropriate and the unamortized regulatory assets net of the regulatory liabilities would be recorded as an extraordinary after-tax non-cash charge to earnings. As of December 31, 2003, we had $443.4 million in regulatory assets and $561.7 million in regulatory liabilities. We continually review the applicability of SFAS 71 and have determined that it is currently appropriate to continue following SFAS 71. See “Note A — Summary of Significant Accounting Policies” in the Notes to Consolidated Financial Statements for additional information.

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Pension and Other Post-retirement Benefits:Our reported costs of providing non-contributory defined pension benefits (described in “Note K—Benefits” in the Notes to Consolidated Financial Statements) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. Pension costs are impacted by actual employee demographics (including age, compensation levels, and employment periods), the level of contributions made to plans and earnings on plan assets. Changes made to the provisions of the plans may also impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs.

In accordance with SFAS 87, Employers’ Accounting for Pensions (SFAS 87), changes in pension obligations associated with these factors may not be immediately recognized as pension costs on the income statement but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants.

As of December 31, 2002, approximately 72% of our pension plan assets were invested in equity securities. Remaining plan assets were invested primarily in corporate and government bonds. During 2002, the funded status of our plans fell significantly due to the decline in the value of plan investments and due to the increase in the benefit obligation resulting from a lower discount rate. Our pension plans went from a $50 million underfunded status as of December 31, 2001 to a $241 million underfunded status as of December 31, 2002. As a result, we recorded a minimum pension liability of $164 million in December 2002. The regulators of our utility segment have adopted SFAS 87 and 88 for rate making purposes. As such, during 2002 we recorded a corresponding $136 million regulatory asset under SFAS 71 (see “Note A—Summary of Significant Accounting Policies” in the Notes to Consolidated Financial Statements) representing future pension costs expected to be recoverable in future rates.

As of December 31, 2003, approximately 76% of our pension plan assets were invested in equity securities. Remaining plan assets were invested primarily in corporate and government bonds. During 2003, the funded status of our plans recovered from the 2002 levels but they still remain $237 million underfunded. As a result, we recorded a minimum pension liability of $113.8 million in December 2003. We recorded a corresponding $70.4 million regulatory asset under SFAS 71 during 2003 (see “Note A—Summary of Significant Accounting Policies” in the Notes to Consolidated Financial Statements) representing future pension costs expected to be recoverable in future rates.

The following chart reflects pension plan sensitivities associated with changes in certain actuarial assumptions by the indicated percentage. Each sensitivity reflects a change to the given assumption, holding all other assumptions constant for our pension plans.

Pension Plans Actuarial Assumption (a)	Impact on Reported Annual Cost
	(Millions of Dollars)
0.5% decrease in discount rate	$	2.8
0.5% decrease in rate of return on plan assets	$	3.6

(a) The inverse of the change in the actuarial assumption may be expected to have an approximately similar impact in the opposite direction.

In addition to pension plans, we maintain other post-retirement benefit plans, which provide health and life insurance benefits for retired employees (described in “Note K—Benefits” in the Notes to Consolidated Financial Statements). We account for these plans in accordance with Statement of Financial Accounting Standards No. 106, Employers’ Accounting for Post-retirement Benefits Other Than Pensions (SFAS 106). Our reported costs of providing these post-retirement benefits are dependent upon numerous factors resulting from actual plan experience including employee demographics (age and compensation levels), our contributions to the plans, earnings on plan assets and health care cost trends. Changes made to the provisions of the plans may also impact current and future post-retirement benefit costs. Other post-retirement benefit costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in

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determining the post-retirement benefit obligation and post-retirement costs. Our other post-retirement benefit plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased other post-retirement costs in future periods. Similar to accounting for pension plans, the regulators of our utility operations have adopted SFAS 106 for rate making purposes.

The following chart reflects other post-retirement benefit plan sensitivities associated with changes in certain actuarial assumptions by the indicated percentage. Each sensitivity reflects a change to the given assumption, holding all other assumptions constant for our other post-retirement plans.

Other Post-retirement Benefit Plans Actuarial Assumption(a)	Impact on Reported Annual Cost
	(Millions of Dollars)
0.5% decrease in discount rate	$2.2
0.5% decrease in health care cost trend rate	($1.4)
0.5% decrease in rate of return on plan assets	$0.3

(a) The inverse of the change in the actuarial assumption may be expected to have an approximately similar impact in the opposite direction.

Unbilled Revenues:We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated. This unbilled revenue is estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses and applicable customer rates. Significant fluctuations in energy demand for the unbilled period or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. Total utility operating revenues during 2003 of $2.5 billion included accrued utility revenues of $149.8 million at December 31, 2003.

Asset Retirement Obligations:Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (SFAS 143), which requires entities to recognize the estimated fair value of legal liabilities for asset retirements in the period in which they are incurred. SFAS 143 applies primarily to decommissioning costs for Point Beach Nuclear Plant. Using a discounted future cash flow methodology, we estimated that our nuclear asset retirement obligation was approximately $673 million at January 1, 2003. Calculation of this asset retirement obligation is based upon projected decommissioning costs calculated by an independent decommissioning consulting firm as well as several significant assumptions including the timing of future cash flows, future inflation rates, the discount rate applied to future cash flows and an 85% probability of plant relicensing. Assuming the following changes in key assumptions and holding all other assumptions constant, we estimate that our nuclear asset retirement obligation at January 1, 2003 would have changed by the following amounts:

Change in Assumption	Change in Liability
	(Millions of Dollars)
1% increase in inflation rate	$226
1% decrease in inflation rate	($167)
0% probability of license extension	$138
100% probability of license extension	($24)

At January 1, 2003, we were unable to identify a viable market for or third party who would be willing to assume this liability. Accordingly, we used a market-risk premium of zero when measuring our nuclear asset retirement

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obligation. We estimate that for each 1% increment that would be included as a market-risk premium, our nuclear asset retirement obligation would increase by approximately $7.1 million.

For additional information concerning adoption of SFAS 143 and our estimated nuclear asset retirement obligation, see “Note B—Recent Accounting Pronouncements” and “Note E—Nuclear Operations” in the Notes to Consolidated Financial Statements.

CAUTIONARY FACTORS

This report and other documents or oral presentations contain or may contain forward-looking statements made by us or on our behalf. These statements are based upon management’s current expectations and are subject to risks and uncertainties that could cause our actual results to differ materially from those contemplated in the statements. Readers are cautioned not to place undue reliance on the forward-looking statements. When used in written documents or oral presentations, the terms “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “objective,” “plan,” “possible,” “potential,” “project” and similar expressions are intended to identify forward-looking statements. In addition to the assumptions and other factors referred to specifically in connection with these statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statements or otherwise affect our future results of operations and financial condition include, among others, the following:

Ø Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related or terrorism-related damage; availability of electric generating facilities; unscheduled generation outages, or unplanned maintenance or repairs; unanticipated changes in fossil fuel, nuclear fuel, purchased power, gas supply or water supply costs or availability due to higher demand, shortages, transportation problems or other developments; nonperformance by electric energy or natural gas suppliers under existing power purchase or gas supply contracts; nuclear or environmental incidents; resolution of used nuclear fuel storage and disposal issues; electric transmission or gas pipeline system constraints; unanticipated organizational structure or key personnel changes; collective bargaining agreements with union employees or work stoppages; inflation rates; or demographic and economic factors affecting utility service territories or operating environment.

Ø Regulatory factors such as unanticipated changes in rate-setting policies or procedures; unanticipated changes in regulatory accounting policies and practices; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of costs of previous investments made under traditional regulation; recovery of costs associated with adoption of changed accounting standards; required changes in facilities or operations to reduce the risks or impacts of potential terrorist activities; required approvals for new construction; changes in the United States Nuclear Regulatory Commission’s regulations related to Point Beach Nuclear Plant or a permanent repository for used nuclear fuel; changes in the United States Environmental Protection Agency’s regulations as well as regulations from the Wisconsin or Michigan Departments of Natural Resources, including but not limited to regulations relating to the release of emissions from fossil-fueled power plants such as carbon dioxide, sulfur dioxide, nitrogen oxide, small particulates or mercury; or the siting approval process for new generation and transmission facilities; or changes in the regulations from the Wisconsin Department of Natural Resources related to the siting approval process for new pipeline construction.

Ø Unexpected difficulties or unanticipated effects of the qualified five-year electric and gas rate freeze ordered by the Public Service Commission of Wisconsin as a condition of approval of the WICOR merger.

Ø The changing electric and gas utility environment as market-based forces replace strict industry regulation and other competitors enter the electric and gas markets resulting in increased wholesale and retail competition.

Ø Consolidation of the industry as a result of the combination and acquisition of utilities in the Midwest, nationally and globally.

Ø Changes in social attitudes regarding the utility and power industries.

Ø Customer business conditions including demand for their products or services and supply of labor and material used in creating their products and services.

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Ø The cost and other effects of legal and administrative proceedings, settlements, investigations and claims, and changes in those matters, including the final outcome of litigation with insurance carriers to recover costs and expenses associated with the Giddings & Lewis Inc./City of West Allis lawsuit against us.

Ø Factors affecting the availability or cost of capital such as: changes in interest rates and other general capital market conditions; our capitalization structure; market perceptions of the utility industry, us or any of our subsidiaries; or security ratings.

Ø Federal, state or local legislative factors such as changes in tax laws or rates; changes in trade, monetary and fiscal policies, laws and regulations; electric and gas industry restructuring initiatives; changes in the Price-Anderson Act; changes in environmental laws and regulations; or changes in allocation of energy assistance, including state public benefits funds.

Ø Authoritative generally accepted accounting principle or policy changes from such standard setting bodies as the Financial Accounting Standards Board, the Securities and Exchange Commission and the Public Company Accounting Oversight Board.

Ø Unanticipated technological developments that result in competitive disadvantages and create the potential for impairment of existing assets.

Ø Factors which impede execution of Wisconsin Energy’sPower the Future strategy announced in September 2000 and revised in February 2001, including receipt of necessary state and federal regulatory approvals, local opposition to siting of new generating facilities and obtaining the investment capital from outside sources necessary to implement the strategy.

Ø Other business or investment considerations that may be disclosed from time to time in our Securities and Exchange Commission filings or in other publicly disseminated written documents.

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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FINANCIAL STATEMENTS AND SUPPLEMENTARY INFORMATION

WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED INCOME STATEMENT

Year Ended December 31

	2003			2002			2001
	(Millions of Dollars)
Operating Revenues
Electric	$	1,986.4		$	1,884.6		$	1,839.8
Gas		513.0			389.8			457.1
Steam		22.5			21.5			21.8
Total Operating Revenues		2,521.9			2,295.9			2,318.7
Operating Expenses
Fuel and purchased power		562.4			493.9			509.7
Cost of gas sold		355.4			240.8			319.0
Other operation and maintenance		784.0			736.3			681.9
Depreciation, decommissioning and amortization		276.2			267.9			264.3
Property and revenue taxes		72.6			71.7			67.8
Total Operating Expenses		2,050.6			1,810.6			1,842.7
Operating Income		471.3			485.3			476.0
Other Income and Deductions
Interest income		0.6			2.1			13.2
Equity in earnings of unconsolidated affiliates		22.8			20.4			20.6
AFUDC-equity		2.4			3.5			1.7
Other, net		5.7			(1.7	)		0.5
Total Other Income and Deductions		31.5			24.3			36.0
Financing Costs
Interest expense		92.6			94.9			109.7
AFUDC-debt		(1.4	)		(2.2	)		(0.8	)
Total Financing Costs		91.2			92.7			108.9
Income Before Income Taxes		411.6			416.9			403.1
Income Taxes		154.9			157.7			156.6
Net Income		256.7			259.2			246.5
Preferred Stock Dividend Requirement		1.2			1.2			1.2
Earnings Available for Common Stockholder	$	255.5		$	258.0		$	245.3

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

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WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED BALANCE SHEET — ASSETS

December 31

ASSETS

	2003			2002
	(Millions of Dollars)
Property, Plant and Equipment
Electric	$	5,726.6		$	5,297.2
Gas		671.0			623.5
Steam		69.7			68.5
Common		299.0			346.5
Other		52.8			31.0
		6,819.1			6,366.7
Accumulated depreciation		(2,571.4	)		(2,389.8	)
		4,247.7			3,976.9
Construction work in progress		68.3			188.8
Leased facilities, net		104.6			110.3
Nuclear fuel, net		78.4			63.2
Net Property, Plant and Equipment		4,499.0			4,339.2
Investments
Nuclear decommissioning trust fund		674.4			550.0
Investment in ATC		136.2			130.9
Other		0.7			6.3
Total Investments		811.3			687.2
Current Assets
Cash and cash equivalents		20.0			13.3
Accounts receivable, net of allowance for doubtful accounts of $26.6 and $30.2		239.3			246.6
Accrued revenues		149.8			147.8
Materials, supplies and inventories		276.2			244.5
Prepayments		95.6			72.4
Deferred income taxes—current		42.4			38.3
Other		3.6			3.6
Total Current Assets		826.9			766.5
Deferred Charges and Other Assets
Regulatory assets		443.4			457.9
Other		64.0			34.3
Total Deferred Charges and Other Assets		507.4			492.2
Total Assets	$	6,644.6		$	6,285.1

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

A-34

WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED BALANCE SHEET — CAPITALIZATION & LIABILITIES

December 31

CAPITALIZATION AND LIABILITIES

	2003		2002
	(Millions of Dollars)
Capitalization (See Statements of Capitalization)
Common equity	$	2,131.9	$	2,049.9
Preferred stock		30.4		30.4
Long-term debt		1,435.3		1,432.4
Total Capitalization		3,597.6		3,512.7
Current Liabilities
Long-term debt due currently		164.2		27.0
Short-term debt		315.9		354.8
Accounts payable		184.9		193.6
Payroll and vacation accrued		58.1		62.1
Taxes accrued—income and other		103.7		110.1
Interest accrued		12.2		16.5
Other		91.1		74.9
Total Current Liabilities		930.1		839.0
Deferred Credits and Other Liabilities
Asset retirement obligations		732.0		—
Regulatory liabilities		561.7		156.9
Cost of removal obligations		—		954.2
Deferred income taxes—long-term		456.4		430.5
Minimum pension liability		113.8		163.6
Accumulated deferred investment tax credits		61.4		65.8
Other		191.6		162.4
Total Deferred Credits and Other Liabilities		2,116.9		1,933.4
Commitments and Contingencies (Note O)		—		—
Total Capitalization and Liabilities	$	6,644.6	$	6,285.1

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

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WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

Year Ended December 31

	2003			2002			2001
	(Millions of Dollars)
Operating Activities
Net income	$	256.7		$	259.2		$	246.5
Reconciliation to cash
Depreciation, decommissioning and amortization		301.9			282.3			277.6
Nuclear fuel expense amortization		25.3			27.3			32.3
Equity in earnings of unconsolidated affiliates		(22.8	)		(20.4	)		(20.6	)
Deferred income taxes and investment tax credits, net		(1.7	)		(31.9	)		(32.9	)
Accrued income taxes, net		(6.0	)		37.2			46.5
Change in—Accounts receivable and accrued revenues		5.3			(26.1	)		17.0
Other accounts receivable		—			116.4			—
Inventories		(31.7	)		(17.4	)		(29.7	)
Other current assets		(23.2	)		2.0			27.0
Accounts payable		(8.7	)		(20.0	)		—
Other current liabilities		7.5			22.3			(48.2	)
Other		11.6			25.4			21.6
Cash Provided by Operating Activities		514.2			656.3			537.1
Investing Activities
Capital expenditures		(343.7	)		(365.7	)		(377.0	)
Return of investment from ATC		—			—			105.2
Nuclear fuel		(38.3	)		(20.7	)		(9.9	)
Nuclear decommissioning funding		(17.6	)		(17.6	)		(17.6	)
Other		(3.2	)		(12.1	)		(2.5	)
Cash Used in Investing Activities		(402.8	)		(416.1	)		(301.8	)
Financing Activities
Dividends paid on common stock		(179.6	)		(179.6	)		(130.0	)
Dividends paid on preferred stock		(1.2	)		(1.2	)		(1.2	)
Issuance of long-term debt		655.2			36.0			22.0
Retirement of long-term debt		(522.2	)		(285.8	)		(30.8	)
Change in short-term debt		(38.9	)		182.4			(84.6	)
Other, net		(18.0	)		—			—
Cash Used in Financing Activities		(104.7	)		(248.2	)		(224.6	)
Change in Cash and Cash Equivalents		6.7			(8.0	)		10.7
Cash and Cash Equivalents at Beginning of Year		13.3			21.3			10.6
Cash and Cash Equivalents at End of Year	$	20.0		$	13.3		$	21.3
Supplemental Information—Cash Paid For
Interest (net of amount capitalized)	$	112.1		$	114.8		$	131.7
Income taxes (net of refunds)	$	148.7		$	124.1		$	142.1

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

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WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED CAPITALIZATION STATEMENT

December 31

		2003			2002
		(Millions of Dollars)
Common Equity (See Consolidated Statements of Common Equity)
Common stock—$10 par value; authorized 65,000,000 shares; outstanding—33,289,327 shares		$	332.9		$	332.9
Other paid in capital			532.4			530.7
Retained earnings			1,270.8			1,194.9
Accumulated other comprehensive income (loss)			(4.2	)		(8.6	)
Total Common Equity			2,131.9			2,049.9
Preferred Stock
Six Per Cent. Preferred Stock—$100 par value; authorized 45,000 shares; outstanding—44,498 shares			4.4			4.4
Serial preferred stock— $100 par value; authorized 2,286,500 shares; 3.60% Series redeemable at $101 per share; outstanding—260,000 shares			26.0			26.0
$25 par value; authorized 5,000,000 shares; none outstanding			—			—
Total Preferred Stock			30.4			30.4
Long-Term Debt
First mortgage bonds	7-1/4% due 2004		140.0			140.0
	7-1/8% due 2016		—			100.0
	6.85% due 2021		—			9.0
	7-3/4% due 2023		—			100.0
	7.05% due 2024		—			60.0
	7.70% due 2027		—			200.0
Debentures (unsecured)	6-5/8% due 2006		200.0			200.0
	9.47% due 2006		2.1			2.8
	8-1/4% due 2022		—			25.0
	6-1/2% due 2028		150.0			150.0
	6-7/8% due 2095		100.0			100.0
	4.50% due 2013		300.0			—
	5.625% due 2033		335.0			—
Notes (secured, nonrecourse)	2% stated rate due 2011		1.3			1.3
	4.81% effective rate due 2030		2.0			—
Notes (unsecured)	6.36% effective rate due 2006		3.6			4.8
	1.52% variable rate due 2006 (a)		1.0			1.0
	1.52% variable rate due 2015 (a)		17.4			17.4
	1.25% variable rate due 2016 (a)		67.0			67.0
	1.52% variable rate due 2030 (a)		80.0			80.0
Obligations under capital leases			213.2			218.2
Unamortized discount			(13.1	)		(17.1	)
Long-term debt currently due			(164.2	)		(27.0	)
Total Long-Term Debt			1,435.3			1,432.4
Total Capitalization		$	3,597.6		$	3,512.7

(a) Variable interest rate as of December 31, 2003.

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

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WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED COMMON STOCK EQUITY STATEMENT

	Common Stock		Other Paid In Capital		Retained Earnings			Accumulated Other Comprehensive Income			Total
	(Millions of Dollars)
Balance—December 31, 2000	$	332.9	$	530.7	$	1,001.2		$	—		$	1,864.8
Net income						246.5						246.5
Other comprehensive income (loss)
Unrealized gain (loss) on derivatives qualified as hedges:
Unrealized losses due to cumulative effect of a change in accounting principle, net of tax									(5.1	)		(5.1	)
Reclassification adjustment for gains included in net income, net of tax									5.1			5.1
Comprehensive Income		—		—		246.5			—			246.5
Cash dividends
Common stock						(130.0	)					(130.0	)
Preferred stock						(1.2	)					(1.2	)
Balance—December 31, 2001	$	332.9	$	530.7	$	1,116.5		$	—		$	1,980.1
Net income						259.2						259.2
Other comprehensive income (loss)
Minimum pension liability									(8.1	)		(8.1	)
Unrealized hedging losses									(0.5	)		(0.5	)
Comprehensive Income (loss)		—		—		259.2			(8.6	)		250.6
Cash dividends
Common stock						(179.6	)					(179.6	)
Preferred stock						(1.2	)					(1.2	)
Balance—December 31, 2002	$	332.9	$	530.7	$	1,194.9		($	8.6	)	$	2,049.9
Net income						256.7						256.7
Other comprehensive income
Minimum pension liability									3.9			3.9
Unrealized hedging gains									0.5			0.5
Comprehensive Income		—		—		256.7			4.4			261.1
Cash dividends
Common stock						(179.6	)					(179.6	)
Preferred stock						(1.2	)					(1.2	)
Tax Benefit of exercised stock options allocated from Parent				1.7								1.7
Balance—December 31, 2003	$	332.9	$	532.4	$	1,270.8		($	4.2	)	$	2,131.9

The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

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WISCONSIN ELECTRIC POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General:Wisconsin Electric Power Company (Wisconsin Electric, the Company, Our, We or Us), a wholly-owned subsidiary of Wisconsin Energy Corporation (Wisconsin Energy), is an electric, gas and steam utility which services electric customers in Wisconsin and the Upper Peninsula of Michigan, gas customers in Wisconsin and steam customers in metro Milwaukee, Wisconsin. We consolidate our wholly owned subsidiary Bostco LLC (Bostco). Bostco owns real estate properties, with total assets of $45.1 million as of December 31, 2003 that are eligible for historical rehabilitation tax credits.

All significant intercompany transactions and balances have been eliminated from the consolidated financial statements.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Reclassifications:We have reclassified certain prior year financial statement amounts to conform to their current year presentation. These reclassifications had no effect on net income or earnings per share.

The most significant reclassifications relate to the reporting of accumulated costs of removal, which are non-legal retirement obligations and accumulated decommissioning costs accrued prior to January 1, 2003. Previously, these costs were included as components of accumulated depreciation on our balance sheets.

Revenues: We recognize energy revenues on the accrual basis and include estimated amounts for service rendered but not billed.

Our rates include base amounts for estimated fuel and purchased power costs. We can request recovery of fuel and purchased power costs prospectively from retail electric customers in the Wisconsin jurisdiction through the rate review process with the Public Service Commission of Wisconsin (PSCW) and in interim fuel cost hearings when such annualized costs are more than 3% higher than the forecasted costs used to establish rates.

Our retail gas rates include monthly adjustments, which permit the recovery or refund of actual purchased gas costs. We defer any difference between actual gas costs incurred (adjusted for a sharing mechanism) and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year and any residual balance at the annual October 31 reconciliation date is subsequently refunded to or recovered from customers.

Property and Depreciation:We record utility property, plant and equipment at cost. Cost includes material, labor, overheads and allowance for funds used during construction. Additions to and significant replacements of property are charged to property, plant and equipment at cost; minor items are charged to maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.

We collect future removal costs in our rates future removal costs for many assets that do not have an associated legal asset retirement obligation. We record a liability on our balance sheet for the estimated amounts we have collected in rates for future removal costs less amounts we have spent in removal activities. This liability was $400.6 million as of December 31, 2003 and is classified as a regulatory liability. The December 31, 2002 liability was $404.2 million and was classified in Cost of Removal Obligations.

We include capitalized software costs associated with our regulated operations under the caption “Property, Plant and Equipment” on the Consolidated Balance Sheets. We had capitalized software costs of $47.6 million and $50.5 million as of December 31, 2003 and 2002, respectively.

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Our utility depreciation rates are certified by the state regulatory commissions and include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 4.2% in 2003, 4.5% in 2002, and 4.6% in 2001. Nuclear plant decommissioning costs are accrued and included in depreciation expense (see Note E).

We record other property, plant and equipment at cost. Cost includes material, labor, overhead and capitalized interest. We charge additions to and significant replacements of property to property, plant and equipment at cost and we charge minor items to maintenance expense. Upon retirement or sale of other property and equipment we remove the cost and related accumulated depreciation from the accounts and include any gain or loss in “Other Income and Deductions” in the Consolidated Income Statements.

Estimated useful lives for non-regulated assets are 2 to 5 years for software.

For assets other than our regulated assets we accrue depreciation expense at straight-line rates over the estimated useful lives of the assets.

Allowance For Funds Used During Construction: Allowance for funds used during construction (AFUDC) is included in utility plant accounts and represents the cost of borrowed funds used during plant construction and a return on stockholders’ capital used for construction purposes. Allowance for borrowed funds also includes interest capitalized on qualifying assets of non-utility subsidiaries. In the Consolidated Income Statements, we show the cost of borrowed funds (AFUDC-debt) as an offset to interest expense and include the return on stockholders’ capital (AFUDC-equity) as an item of other income.

As approved by the PSCW, we capitalized AFUDC-debt and equity at 10.18% during the periods reported.

In a rate order dated August 30, 2000, the PSCW authorized us to accrue AFUDC on all electric utility nitrogen oxide (NOx) remediation construction work in progress at a rate of 10.18%, and provided a full current return on electric safety and reliability construction work in progress so that no AFUDC accrual is required on such projects. In addition, the August 2000 PSCW order provided a current return on half of other utility construction work in progress and authorized AFUDC accruals on the remaining 50% of these projects.

Materials, Supplies and Inventories:Our inventory at December 31 consists of:

Materials, Supplies and Inventories	2003		2002
	(Millions of Dollars)
Fossil Fuel	$	107.0	$	124.3
Natural Gas in Storage		83.8		37.4
Materials and Supplies		85.4		82.8
Total	$	276.2	$	244.5

We price substantially all fossil fuel, materials and supplies and natural gas in storage inventories using the weighted-average method of accounting.

Regulatory Accounting: We account for our regulated operations in accordance with Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71). This statement sets forth the application of generally accepted accounting principles to those companies whose rates are determined by an independent third-party regulator. The economic effects of regulation can result in regulated companies recording costs that have been or are expected to be allowed in the rate making process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses in the periods when those same amounts are reflected in rates. We defer all of our regulatory assets pursuant to specific rate orders or by a generic order issued by our primary regulator. We expect to recover our outstanding regulatory assets in rates over a period of no longer than 20 years. As of December 31, 2003, we had approximately $25.2 million of regulatory assets that were not earning a return. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities).

A-40

Our regulatory assets and liabilities at December 31 consist of:

Regulatory Assets	2003		2002
	(Millions of Dollars)
Deferred income tax related (See Note D)	$	132.3	$	138.4
Deferred electric transmission costs		73.3		62.5
Unrecognized pension costs (See Note K)		70.4		135.8
Plant related—capital lease (See Note G)		54.5		47.2
Environmental costs		48.7		44.0
Debt redemption costs		18.3		—
Bad debt costs		10.9		—
Department of Energy assessments (See Note E)		10.7		13.3
Lightweight aggregate plant		8.9		12.2
Other, net		15.4		4.5
Total Regulatory Assets	$	443.4	$	457.9

Regulatory Liabilities	2003		2002
	(Millions of Dollars)
Cost of removal obligations	$	400.6	$	—
Deferred income tax related (See Note D)		91.0		97.5
Tax and interest refunds		21.2		20.7
Derivatives		11.5		4.5
NOx escrow		2.7		11.9
Other, net		34.7		22.3
Total Regulatory Liabilities	$	561.7	$	156.9

We recorded a minimum pension liability in 2003 and in 2002 to reflect the funded status of our pension plans (See Note K). We concluded that substantially all of the unrecognized pension costs resulting from the recognition of our minimum pension liability that relate to our utility operations qualify as a regulatory asset. As a result, we recognized a pre-tax regulatory asset in the amount of $70.4 million and $135.8 million associated with our minimum pension liability as of December 31, 2003 and 2002, respectively.

In October 2002, the PSCW issued an order authorizing us to implement a surcharge for recovery of annual electric transmission costs projected through 2005. Recognizing the uncertainty of these transmission-related costs, the PSCW order authorized a four year escrow accounting treatment such that rate recovery will ultimately be trued-up to actual costs plus a return on the unrecovered costs. We are currently recovering incremental transmission costs from our customers. The difference between actual incremental transmission costs incurred and the amount being recovered goes to the escrow account We have deferred a total of $73.3 million of electric transmission costs as a regulatory asset through December 31, 2003.

Consistent with a generic order from and past rate-making practices of the PSCW, we defer as a regulatory asset costs associated with the remediation of former manufactured gas plant sites. As of December 31, 2003, we have recorded $48.7 million of environmental costs associated with manufactured gas plant sites as a regulatory asset, including $25.7 million of deferrals for actual remediation costs incurred and a $23.5 million accrual for estimated future site remediation (See Note O). We expect to include total actual remediation costs incurred in our next rate case at which time we would begin amortizing these costs over the following five years.

As permitted by our regulators, we account for certain debt redemption costs under the revenue neutral method of accounting. Under the revenue neutral method of accounting, we defer the costs associated with the redemption of utility debt to the extent that the redeemed debt is refinanced with other utility debt. The redemption costs are amortized based upon the difference between the interest expense of the new and redeemed debt. At December 31, 2003, we have deferred approximately $18.3 million of net debt redemption costs as a regulatory asset and expect to fully amortize these costs through 2005.

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As of December 31, 2003, we have deferred a regulatory asset of approximately $10.9 million in total uncollectible accounts receivable representing incremental bad debt costs in excess of amounts in existing rates. In 2003, due to a combination of unusually high natural gas prices, the soft economy within our utility service territories and limited governmental assistance available to low-income customers, we experienced a significant increase in uncollectible accounts receivable. As a result, in October 2003 the PSCW approved our request for deferral of 2003 uncollectible accounts receivable in excess of amounts included in existing annual utility rates.

Income Taxes:We are included in Wisconsin Energy’s consolidated Federal income tax return. As such, Wisconsin Energy allocates Federal current tax expense or credits to us based on our separate tax computation.

Investment tax credits related to regulated utility assets are recorded as a deferred credit on the balance sheet and amortized to income over the applicable service lives of related properties in accordance with regulatory treatment. Historical rehabilitation credits are reported in income in the year claimed.

Wisconsin Energy allocates the tax benefit of stock options exercised to us to the extent the option holders payroll cost was incurred by us. We record the allocated tax benefit as an addition to paid in capital.

Derivative Financial Instruments: We have derivative physical and financial instruments as defined by Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS 133). However, we limit the use of financial instruments. For further information, see Notes I and J.

Statement of Cash Flows:Cash and cash equivalents include marketable debt securities acquired three months or less from maturity.

Restrictions:Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. Under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy. We do not believe that these restrictions will materially affect our operations.

Asset Retirement Obligations:In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No 143, Accounting for Asset Retirement Obligations. We adopted SFAS 143 effective January 1, 2003. Consistent with SFAS 143, we record a liability at fair value for a legal asset retirement obligation in the period in which it is incurred. When a new legal obligation is recorded, we capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. We accrete the liability to its present value each period and depreciate the capitalized cost over the useful life of the related asset. At the end of the asset’s useful life, we settle the obligation for its recorded amount or incur a gain or loss. As it relates to our regulated operations, we apply SFAS 71 and recognize regulatory assets or liabilities for the timing differences between when we recover legal asset retirement obligations in rates and when we would recognize these costs under SFAS 143.

Investments:Investments in affiliated companies in which we have a controlling financial interest are consolidated. Investments in other affiliated companies in which we do not maintain control are accounted for using the equity method.

Nuclear Fuel Amortization:We lease our nuclear fuel and amortize the fuel inventory to fuel expense as the power is generated, generally over a period of 60 months.

B—RECENT ACCOUNTING PRONOUNCEMENTS

Variable Interest Entities:In January 2003, the FASB issued Interpretation 46, Consolidation of Variable Interest Entities (FIN 46). This standard requires an enterprise that is the primary beneficiary of a variable interest entity to consolidate that entity. We applied the Interpretation to any existing interests in variable interest entities beginning in the third quarter of 2003. In October 2003, the FASB deferred the adoption of FIN 46 for all entities commonly referred to as special-purpose entities to the first reporting period ending after December 15, 2003. In December 2003, the FASB revised the effective date for all other types of entities to financial statements for periods ending after March 15, 2004. While we are continuing to evaluate the impact of the application of these new rules, we do not expect adoption of the final phase of Interpretation 46 to have a significant impact on our balance sheets or on our results of operations.

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Derivative Instruments:We adopted SFAS 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, effective July 1, 2003. SFAS 149, which was issued by FASB in April 2003, amends Statement 133 for certain decisions made by the FASB as part of the Derivatives Implementation Group process and other FASB projects dealing with financial instruments. SFAS 149 also amends Statement 133 to incorporate clarifications of and to expand the definition of a derivative.

Pension and Other Post-retirement Benefit Plans:We adopted SFAS 132R, Employers’ Disclosures about Pensions and Other Post-retirement Benefits, in December 2003. SFAS 132R, which was issued by FASB in December 2003, replaces existing FASB disclosure requirements for defined benefit plans. In addition to expanded annual disclosures, the FASB is requiring companies to report the various elements of pension and other post-retirement benefit costs on a quarterly basis (See Note K).

C—AMERICAN TRANSMISSION COMPANY

Effective January 1, 2001, we transferred electric utility transmission system assets with a net book value of approximately $224.1 million to American Transmission Company LLC (ATC) in exchange for an ownership interest in this new company. No gain or loss was recorded in this transaction. During 2001, ATC issued debt and distributed $105.2 million of cash back to us as a partial return of the original equity contribution. As of December 31, 2003 and 2002, we had a total ownership interest of approximately 34.6% and 37%, respectively, in ATC. We are represented by one out of fourteen ATC board members, each of whom has one vote. Due to the voting requirements, no individual member has more than 8% of the voting control. We account for our investment in ATC under the equity method.

D—INCOME TAXES

We follow the liability method in accounting for income taxes as prescribed by Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109). SFAS 109 requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. Tax credits associated with regulated operations are deferred and amortized over the life of the assets.

The following table is a summary of income tax expense for each of the years ended December 31:

Income Tax Expense	2003			2002			2001
	(Millions of Dollars)
Current tax expense	$	156.6		$	189.7		$	189.5
Deferred income taxes, net		2.8			(27.5	)		(28.4	)
Investment tax credit, net		(4.5	)		(4.5	)		(4.5	)
Total Income Tax Expense	$	154.9		$	157.7		$	156.6

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The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable U.S. statutory federal income tax rate to income before income taxes and preferred dividend as a result of the following:

Income Tax Expense	2003					2002					2001
	Amount			Effective Tax Rate		Amount			Effective Tax Rate		Amount			Effective Tax Rate
	(Millions of Dollars)
Expected tax at statutory federal tax rates	$	144.1		35.0	%	$	145.9		35.0	%	$	141.0		35.0	%
State income taxes net of federal tax benefit		19.3		4.7	%		20.2		4.8	%		20.7		5.1	%
Investment tax credit restored		(4.5	)	(1.1	%)		(4.5	)	(1.0	%)		(4.5	)	(1.1	%)
Historical rehabilitation credits		(3.3	)	(1.0	%)		(2.5	)	(0.6	%)		—		—
Other, net		(0.7	)	(0.0	%)		(1.4	)	(0.4	%)		(0.6	)	(0.2	%)
Total Income Tax Expense	$	154.9		37.6	%	$	157.7		37.8	%	$	156.6		38.8	%

The components of SFAS 109 deferred income taxes classified as net current assets and net long-term liabilities at December 31 are as follows:

	Current Assets (Liabilities)						Long-Term Liabilities (Assets)
Deferred Income Taxes	2003			2002			2003			2002
	(Millions of Dollars)
Property-related	$	—		$	—		$	643.2		$	607.8
Construction advances		—			—			(82.9	)		(75.7	)
Decommissioning trust		—			—			(65.5	)		(59.0	)
Contested liability payment		—			(2.4	)		—			—
Recoverable gas costs		(0.5	)		2.3			—			—
Uncollectible account expense		9.8			9.1			—			—
Employee benefits and compensation		10.6			10.7			(44.3	)		(37.5	)
Asset impairment charge		10.7			10.8			—			—
Other		11.8			7.8			5.9			(5.1	)
Total Deferred Income Taxes	$	42.4		$	38.3		$	456.4		$	430.5

We have also recorded deferred regulatory assets and liabilities representing the future expected impact of deferred taxes on utility revenues (See Note A).

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E—NUCLEAR OPERATIONS

Point Beach Nuclear Plant: We own two 518-megawatt electric generating units at Point Beach Nuclear Plant (Point Beach) in Two Rivers, Wisconsin. Point Beach is operated by Nuclear Management Company, LLC (NMC), a company that, as of December 31, 2003, provides services to eight nuclear generating units in the Midwest. NMC is owned by Wisconsin Energy and the affiliates of four other unaffiliated investor-owned utilities in the region. We currently expect the two units at Point Beach to operate to the end of their operating licenses, which expire in October 2010 for Unit 1 and in March 2013 for Unit 2. NMC filed an application in February 2004 with the NRC to renew the operating licenses for both of our plant’s nuclear reactors for an additional 20 years.

Nuclear Insurance: The Price-Anderson Act, as it applies to Point Beach, currently limits the total public liability for damages arising from a nuclear incident at a nuclear power plant to approximately $10.7 billion, of which $300 million is covered by liability insurance purchased from private sources. The remaining $10.4 billion is covered by an industry retrospective loss sharing plan whereby in the event of a nuclear incident resulting in damages exceeding the private insurance coverage, each owner of a nuclear plant would be assessed a deferred premium of up to $99.2 million per reactor (we own two) with a limit of $10 million per reactor within one calendar year. As the owner of Point Beach, we would be obligated to pay our proportionate share of any such assessment.

We, through our membership in Nuclear Electric Insurance Limited (NEIL), carry decontamination, property damage and decommissioning shortfall insurance covering losses of up to $2.0 billion at Point Beach. Under policies issued by NEIL, the insured member is liable for a retrospective premium adjustment in the event of catastrophic losses exceeding the full financial resources of NEIL. Our maximum retrospective liability under these policies is $14.9 million.

We also maintain insurance with NEIL covering business interruption and extra expenses during any prolonged accidental outage at Point Beach, where such outage is caused by accidental property damage from radioactive contamination or other risks of direct physical loss. Our maximum retrospective liability under this policy is $10.0 million.

It should not be assumed that, in the event of a major nuclear incident, any insurance or statutory limitation of liability would protect us from material adverse impact.

Nuclear Decommissioning: We record decommissioning expense in amounts equal to the amounts collected in rates and funded to the external trusts. Nuclear decommissioning costs are accrued over the expected service lives of the nuclear generating units and are included in electric rates. Decommissioning expense was $17.6 million for each of the years ended 2003, 2002 and 2001. As of December 31, 2003, and 2002, we had the following investments in Nuclear Decommissioning Trusts, stated at fair value.

	2003		2002
	(Millions of Dollars)
Funding and Realized Earnings	$	485.2	$	458.6
Unrealized Gains		189.2		91.4
Total	$	674.4	$	550.0

In accordance with Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities, our debt and equity security investments in the Nuclear Decommissioning Trust Fund are classified as available for sale. Gains and losses on the fund are determined on the basis of specific identification; net unrealized holding gains on the fund are recorded as part of the fund. We record realized and unrealized fund earnings as a regulatory liability.

As of December 31, 2002, we had accrued decommissioning costs of $550.0 million. These amounts were included on the 2002 consolidated balance sheets as a long-term liability under Cost of Removal Obligations. Beginning January 1, 2003, we adopted SFAS 143 Accounting for Asset Retirement Obligations. Under SFAS 143, we recorded a liability on our balance sheet for the net present value of the expected cash flows associated with our legal obligation to decommission our nuclear plant and reclassified non-legal removal obligations from cost of removal obligation to regulatory liabilities. Under SFAS 71, Accounting for the Effects of Certain Types of

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Regulation, we recorded a regulatory asset for the amounts that the Asset Retirement Obligation liability exceeded amounts collected in rates and cumulative investment gains. In the future, if the SFAS 143 liability is less than the amounts funded, we would expect to record a regulatory liability for the difference based on the expected rate treatment from our primary regulator. For further information on our asset retirement obligations see Note F.

The asset retirement liability as calculated under SFAS 143 is based on several significant assumptions including the timing of future cash flows, future inflation rates, the extent of work that is performed and the discount rate applied to future cash flows. These assumptions differ significantly from the assumptions used by the PSCW to calculate the nuclear decommissioning liability for funding purposes. For the SFAS 143 calculation, we assumed an 85% probability of plant license renewal based strictly on industry averages. Our SFAS 143 liability is approximately $732 million as of December 31, 2003.

In 2002, we engaged a consultant to perform a site specific study for regulatory funding purposes. This study assumed that the plants would not run past their current operating licenses of 2010 and 2013, respectively, and the study made several assumptions as to the scope of work. The study also estimated the liability for fuel management costs and non-nuclear demolition costs. These costs are excluded from the calculation of the SFAS 143 liability. The 2002 site specific study estimated that the cost to decommission the plant in 2003 year dollars was approximately $1.1 billion. The differences between the regulatory funding liability and the SFAS 143 liability are primarily related to fuel management costs, non-nuclear demolition costs and the timing of future cash flows.

The ultimate timing and amount of future cash flows associated with nuclear decommissioning is dependent upon many significant variables including the scope of work involved, the ability to relicense the plants, future inflation rates and discount rates. However, based on the current plant licenses, we do not expect to make any nuclear decommissioning expenditures in excess of $1.0 million before the year 2009.

Decontamination and Decommissioning Fund:The Energy Policy Act of 1992 established a Uranium Enrichment Decontamination and Decommissioning Fund (D&D Fund) for the United States Department of Energy’s nuclear fuel enrichment facilities. Deposits to the D&D Fund are derived in part from special assessments on utilities using enrichment services. As of December 31, 2003, we recorded our remaining estimated liability equal to projected special assessments of$8.0 million. An associated deferred regulatory asset is detailed in Note A. The deferred regulatory asset will be amortized to nuclear fuel expense and included in utility rates over the next four years ending in 2007.

F—ASSET RETIREMENT OBLIGATIONS

SFAS 143, Accounting for Asset Retirement Obligations, primarily applies to the future decommissioning costs for Point Beach. Prior to January 2003, we recorded a long-term liability for accrued nuclear decommissioning costs. (See Note E).

SFAS 143 also applies to a smaller extent to several other utility assets including the dismantlement of certain hydro facilities and the removal of certain coal handling equipment and water intake facilities located on lakebeds. We have not recorded any asset retirement obligations for the removal of the coal handling equipment or for the water intake facilities located on lakebeds because the associated liability cannot be reasonably estimated.

During the second quarter of 2003, we signed an agreement to lease the site of our existing coal-based Port Washington Power Plant to our affiliate, W.E. Power LLC, which is constructing and will own a new gas-fired generating station at the site as part of Wisconsin Energy’sPower the Future program. The terms of the lease call for us to raze the existing facilities at the site by the spring of 2006. Accordingly, we recorded an asset retirement obligation and corresponding plant asset in the amount of $14.9 million.

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If we had adopted SFAS 143 at the beginning of fiscal 2002, we would have reported the following asset retirement obligations on our Consolidated Balance Sheets in “Deferred Credits and Other Liabilities” as of December 31:

	2003		2002
	(Millions of Dollars)
Asset Retirement Obligations
Reported	$	732.0	$	—
Pro forma	$	732.0	$	675.4

The following table presents the change in our asset retirement obligations during 2003.

Balance at 12/31/02	Initial Adoption	Liabilities Incurred	Liabilities Settled	Accretion	Cash Flow Revisions	Balance at 12/31/03
(Millions of Dollars)
$ —	$675.4	$14.9	$0.8	$35.2	$7.3	$732.0

G—LONG-TERM DEBT

First Mortgage Bonds, Debentures and Notes: At December 31, 2003, the maturities and sinking fund requirements through 2008 and thereafter for the aggregate amount of our long-term debt outstanding (excluding obligations under capital leases) were:

	(Millions of Dollars)
2004	$	141.9
2005		1.9
2006		203.0
2007		0.2
2008		0.2
Thereafter		1,052.2
Total	$	1,399.4

Sinking fund requirements for the years 2004 through 2008, included in the preceding table, are $9.0 million. Substantially all of our utility plant is subject to a first mortgage lien.

Long-term debt premium or discount and expense of issuance are amortized over the lives of the debt issues and included as interest expense.

In May 2003, we sold $635 million of unsecured Debentures ($300 million of ten-year 4.50% Debentures due 2013 and $335 million of thirty-year 5.625% Debentures due 2033) under an $800 million shelf registration statement filed with the SEC. We used a portion of the proceeds from the Debentures to repay short-term debt, which was originally incurred to retire debt that matured in December 2002. The balance of the proceeds were used to redeem $425 million of our debt securities in June 2003, and to fund the early redemption in August 2003 of another $60 million debt issue.

In October 2003, redeemed $9 million of 6.85% First Mortgage Bonds.

In January 2002, we redeemed $100 million of 8-3/8% first mortgage bonds due 2026 and $3.4 million of 9-1/8% First Mortgage Bonds due 2024. Early redemption of this long-term debt was financed through the issuance of short-term commercial paper.

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Obligations Under Capital Leases: In 1997, we entered into a 25 year power purchase contract with an unaffiliated independent power producer. The contract, for 236 megawatts of firm capacity from a gas-fired cogeneration facility, includes no minimum energy requirements. When the contract expires in 2022, we may, at our option and with proper notice, renew for another ten years or purchase the generating facility at fair value or allow the contract to expire. We account for this contract as a capital lease and recorded the leased facility and corresponding obligation under the capital lease at the estimated fair value of the plant’s electric generating facilities. We are amortizing the leased facility on a straight-line basis over the original 25-year term of the contract.

We treat the long-term power purchase contract as an operating lease for rate-making purposes and we record our minimum lease payments as purchased power expense on the Consolidated Income Statements. We paid a total of $23.4 million, $22.3 million and $21.5 million in minimum lease payments during 2003, 2002, and 2001, respectively. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on our Consolidated Balance Sheets (see deferred regulatory asset—plant related—capital lease in Note A). Due to the timing of the minimum lease payments, we expect the regulatory asset to increase to approximately $78.5 million by the year 2009 and the total obligation under the capital lease to increase to $160.2 million by the year 2005 before each is reduced to zero over the remaining life of the contract.

We also have a nuclear fuel leasing arrangement with Wisconsin Electric Fuel Trust (Trust), which is treated as a capital lease. We lease and amortize the nuclear fuel to fuel expense as power is generated, generally over a period of 60 months. Lease payments include charges for the cost of fuel burned, financing costs and management fees. In the event that we or the Trust terminates the lease, the Trust would recover its unamortized cost of nuclear fuel from us. Under the lease terms, we are in effect the ultimate guarantor of the Trust’s commercial paper and line of credit borrowings that finance the investment in nuclear fuel. We included $1.4 million of interest expense on the nuclear fuel lease in fuel expense during 2003, as well as $1.9 million during 2002 and $3.3 million during 2001.

Following is a summary of our capitalized leased facilities and nuclear fuel at December 31.

Capital Lease Assets	2003			2002
	(Millions of Dollars)
Leased Facilities
Long-term purchase power commitment	$	140.3		$	140.3
Accumulated amortization		(35.7	)		(30.0	)
Total Leased Facilities	$	104.6		$	110.3
Nuclear Fuel
Under capital lease	$	115.9		$	118.4
Accumulated amortization		(67.0	)		(63.7	)
In process/stock		29.5			8.5
Total Nuclear Fuel	$	78.4		$	63.2

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Future minimum lease payments under our capital leases and the present value of our net minimum lease payments as of December 31, 2003 are as follows:

Capital Lease Obligations	Purchase Power Commitment			Nuclear Fuel Lease			Total
	(Millions of Dollars)
2004	$	29.0		$	23.6		$	52.6
2005		30.1			18.3			48.4
2006		31.2			10.2			41.4
2007		32.4			4.2			36.6
2008		33.6			2.9			36.5
Thereafter		403.8			—			403.8
Total Minimum Lease Payments		560.1			59.2			619.3
Less: Estimated Executory Costs		(118.5	)		—			(118.5	)
Net Minimum Lease Payments		441.6			59.2			500.8
Less: Interest		(282.5	)		(5.1	)		(287.6	)
Present Value of Net
Minimum Lease Payments		159.1			54.1			213.2
Less: Due Currently		—			(22.3	)		(22.3	)
	$	159.1		$	31.8		$	190.9

H—SHORT-TERM DEBT

Short-term notes payable balances and their corresponding weighted-average interest rates at December 31 consist of:

	2003				2002
Short-Term Debt	Balance		Interest Rate		Balance		Interest Rate
	(Millions of Dollars)
Banks and other	$	35.2	6.13	%	$	73.1	2.59	%
Commercial paper		280.7	1.15	%		281.7	1.38	%
Total Short-Term Debt	$	315.9	1.70	%	$	354.8	1.63	%

As of December 31, 2003, we had approximately $350.0 million of available unused lines of bank back-up credit facilities on a consolidated basis. We had approximately $315.9 million of total consolidated short-term debt outstanding on such date. Our bank back-up credit facilities mature beginning June 2004 through August 2004.

We have entered into various bank back-up credit agreements to maintain short-term credit liquidity which, among other terms, require us to maintain a minimum total funded debt to capitalization ratio of less than 65%.

I—DERIVATIVE INSTRUMENTS

We follow SFAS 133 as amended by SFAS 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, effective July 1, 2003, which requires that derivative instruments be recorded on the balance sheet as an asset or liability measured at its fair value and that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Upon adoption of SFAS 149, prospectively any forward commodity contracts other than electric power contracts that meet the qualification of a capacity contract and are subject to unplanned netting, qualify as a derivative, and any changes in fair value of the derivative

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are to be recorded currently in earnings. However, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities for any energy-related contracts in the regulated electric operations that qualify as derivatives.

We have a limited number of other financial and physical commodity contracts that are defined as derivatives under SFAS 133 and that qualify for cash flow hedge accounting. These cash flow hedging instruments are comprised of gas futures and basis swap contracts utilized to manage the cost of gas.

Changes in the fair market values of these cash flow hedging instruments, to the extent that the hedges are effective at mitigating the underlying commodity risk, are recorded in Accumulated Other Comprehensive Income. At the date that the underlying transaction occurs, we report the amounts in Accumulated Other Comprehensive Income as earnings. The ineffective portion of the derivative’s change in fair value is recorded as a regulatory asset or liability immediately as these transactions are part of the purchased gas adjustment.

For the years ended December 31, 2003 and 2002, the amount of hedge ineffectiveness was immaterial. We did not exclude any components of derivative gains or losses from the assessment of hedge effectiveness. The maximum length of time over which we are hedging our exposure to the variability in future cash flows of forecasted transactions was two months as of December 31, 2003 and 2002.

J—FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amount and estimated fair value of certain of our recorded financial instruments at December 31 are as follows:

	2003				2002
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Millions of Dollars)
Nuclear decommissioning trust fund	$	674.4	$	674.4	$	550.0	$	550.0
Preferred stock, no redemption required	$	30.4	$	20.9	$	30.4	$	17.5
Long-term debt including current portion	$	1,399.4	$	1,417.9	$	1,258.3	$	1,302.1

The carrying value of cash and cash equivalents, net accounts receivable, accounts payable and short-term borrowings approximates fair value due to the short term nature of these instruments. The nuclear decommissioning trust fund is carried at fair value as reported by the trustee (see Note E). The fair value of our preferred stock is estimated based upon the quoted market value for the same or similar issues. The fair value of our long-term debt, including the current portion of long-term debt but excluding capitalized leases, is estimated based upon quoted market value for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the issuing company’s bond rating and the present value of future cash flows. The fair values of gas commodity instruments are equal to their carrying values as of December 31, 2003.

K—BENEFITS

Pensions and Other Post-retirement Benefits:    We have funded and unfunded noncontributory defined benefit pension plans that together cover substantially all of our employees. The plans provide defined benefits based upon years of service and final average salary.

We also have other post-retirement benefit plans covering substantially all of our employees. The health care plans are contributory with participants’ contributions adjusted annually; the life insurance plans are noncontributory. The accounting for the health care plans anticipates future cost-sharing changes to the written plans that are consistent with our expressed intent to maintain the current cost sharing levels. The post-retirement health care plans include a limit on our share of costs for recent and future retirees. We use a year end measurement date for all of our pension and other post-retirement benefit plans.

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	Pension Benefits									Other Post-retirement Benefits
Status of Benefit Plans	2003			2002			2001			2003			2002			2001
	(Millions of Dollars)
Change in Benefit Obligation
Benefit Obligation at January 1	$	851.2		$	806.2		$	773.5		$	257.6		$	205.3		$	173.4
Service cost		27.2			18.3			18.5			10.3			7.5			6.2
Interest cost		56.9			56.7			57.0			17.6			15.3			13.6
Plan participants’ contributions		—			—			—			0.7			6.9			5.8
Plan amendments		18.5			0.1			—			—			—			—
Actuarial loss		32.5			28.6			14.9			14.0			39.8			21.9
Benefits paid		(53.8	)		(58.7	)		(57.7	)		(10.9	)		(17.2	)		(15.6	)
Benefit Obligation at December 31	$	932.5		$	851.2		$	806.2		$	289.3		$	257.6		$	205.3
Change in Plan Assets
Fair Value at January 1	$	609.6		$	756.4		$	873.2		$	78.6		$	81.0		$	79.4
Actual earnings (loss) on plan assets		138.2			(91.2	)		(60.3	)		11.9			(5.1	)		(0.1	)
Employer contributions		1.2			3.1			1.2			15.4			13.0			11.5
Plan participants’ contributions		—			—			—			0.7			6.9			5.8
Benefits paid		(53.8	)		(58.7	)		(57.7	)		(10.9	)		(17.2	)		(15.6	)
Fair Value at December 31	$	695.2		$	609.6		$	756.4		$	95.7		$	78.6		$	81.0
Funded Status of Plans
Funded status at December 31	$	(237.3	)	$	(241.6	)	$	(49.8	)	$	(193.6	)	$	(179.0	)	$	(124.3	)
Unrecognized
Net actuarial loss		153.6			203.2			18.4			94.1			92.1			44.1
Prior service cost		36.6			22.9			26.2			0.2			0.2			0.3
Net transition (asset) obligation		(2.3	)		(4.5	)		(6.8	)		13.8			15.4			16.8
Net Asset (Accrued Benefit Cost)	$	(49.4	)	$	(20.0	)	$	(12.0	)	$	(85.5	)	$	(71.3	)	$	(63.1	)
Amounts recognized in the Balance Sheet consist of:
Prepaid benefit cost	$	6.9		$	13.5		$	12.3		$	0.1		$	0.1		$	0.1
Accrued benefit cost		(49.4	)		(28.5	)		(24.3	)		(85.6	)		(71.4	)		(63.2	)
Minimum liability		(113.8	)		(163.6	)		—			—			—			—
Intangible asset		36.5			22.8			—			—			—			—
Regulatory asset (See Note A)		70.4			135.8			—			—			—			—
Net amount recognized at end of year	$	(49.4	)	$	(20.0	)	$	(12.0	)	$	(85.5	)	$	(71.3	)	$	(63.1	)

The accumulated benefit obligation for all of our defined benefit plans was $858.5 million and $785.7 million at December 31, 2003 and 2002, respectively.

Information for pension plans with an accumulated benefit obligation in excess of the fair value of assets are as follows:

	2003		2002
	(Millions of Dollars)
Projected benefit obligation	$	913.1	$	834.6
Accumulated benefit obligation	$	839.9	$	785.7
Fair value of plan assets	$	695.2	$	609.6

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Additional Information	2003		2002
	(Millions of Dollars)
Increase (decrease) in minimum liability included in a combination of other
comprehensive income and regulatory assets	($49.8	)	$163.6

The components of net periodic pension and other post-retirement benefit costs are:

Benefit Plan Cost Components	Pension Benefits									Other Post-retirement Benefits
	2003			2002			2001			2003			2002			2001
Net Periodic Benefit Cost (Income)
Service cost	$	27.2		$	18.3		$	18.5		$	10.3		$	7.5		$	6.2
Interest cost		56.9			56.7			57.0			17.6			15.3			13.6
Expected return on plan assets		(64.0	)		(68.2	)		(71.3	)		(6.5	)		(6.8	)		(6.8	)
Amortization of:
Transition (asset) obligation		(2.2	)		(2.2	)		(2.2	)		1.5			1.5			1.5
Prior service cost		4.8			3.4			3.3			—			—			0.1
Actuarial loss (gain)		3.0			3.1			0.9			6.6			3.7			1.5
Net Periodic Benefit Cost (Income)	$	25.7		$	11.1		$	6.2		$	29.5		$	21.2		$	16.1
Weighted-Average assumptions used to determine benefit obligations at Dec 31
Discount rate		6.25	%		6.75	%		7.25	%		6.25	%		6.75	%		7.25	%
Rate of compensation increase		4.5 to			4.0 to			4.5 to			4.5 to			4.0 to			4.5 to
		5.0			5.0			5.0			5.0			5.0			5.0
Weighted-Average assumptions used to determine net cost for year ended Dec 31
Discount rate		6.75	%		7.25	%		7.50	%		6.75	%		7.25	%		7.50	%
Expected return on plan assets		9.0			9.0			9.0			9.0			9.0			9.0
Rate of compensation increase		4.0 to			4.5 to			4.5 to			4.0 to			4.5 to			4.5 to
		5.0			5.0			5.0			5.0			5.0			5.0
Assumed health care cost trend rates at Dec 31
Health care cost trend rate assumed for next year		N/A			N/A			N/A			10			10			9
Rate that the cost trend rate gradually declines to		N/A			N/A			N/A			5			5			5
Year that the rate reaches the rate it is assumed to remain at		N/A			N/A			N/A			2009			2008			2007

The expected long-term rate of return on plan assets was 9% in 2003 and 2002. This return expectation on plan assets was determined by reviewing actual pension historical returns as well as calculating expected total trust returns using the weighted average of long term market returns for each of the asset categories utilized in the pension fund.

Other Post-retirement Benefits Plans: We use various Employees’ Benefit Trusts to fund a major portion of other post-retirement benefits. The majority of the trusts’ assets are mutual funds or commingled indexed funds.

Since January 1, 1992, we have calculated our post-retirement benefit costs in accordance with SFAS 106, Employers’ Accounting for Post-retirement Benefits Other Than Pensions. These costs are recoverable from our utility customers.

The assumed health care cost trend rate for 2004 is at 10% for all plan participants decreasing gradually to 5% in 2008 and thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans.

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A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	1% Increase		1% Decrease
	(Millions of Dollars)
Effect on
Post-retirement benefit obligation	$	25.5	($	22.7	)
Total of service and interest cost components	$	3.3	($	2.9	)

On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was signed into law. The Act introduced a prescription drug benefit program under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.

In general, accounting rules require that changes in relevant laws and government benefit programs be considered in measuring post-retirement benefit costs and the Accumulated Post-retirement Benefit Obligation (APBO). However, certain accounting issues raised by the Act – in particular, how to account for the federal subsidy – are not explicitly addressed by FASB Statement 106. In addition, significant uncertainties exist for a plan sponsor both as to the direct effects of the Act and its ancillary effects on plan participant’s behavior and health care costs.

The FASB issued FASB Staff Position No. SFAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” (FSP 106-1) that allows sponsors to elect to defer recognition of the effects of the Act.

In accordance with FSP 106-1, we elected to defer recognition of the effects of the Act. Accordingly, any measures of the APBO or net periodic post-retirement benefit cost in the financial statements or the accompanying footnotes do not reflect the effects of the Act on the plan. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require us to change previously reported information.

Plan Assets: In our opinion, current pension trust assets and amounts which are expected to be contributed to the trusts in the future will be adequate to meet pension payment obligations to current and future retirees. Our pension plans asset allocation at December 31, 2003 and 2002, and our target allocation for 2004, by asset category, are as follows:

Asset Category	Target Alocation 2004	Percentage of Pension Plans Assets at December 31
		2003	2002
Equity Securities	72%	76%	72%
Debt Securities	28%	24%	28%
Total	100%	100%	100%

Wisconsin Energy Corporation’s common stock is not included in equity securities. Investment managers are specifically prohibited from investing in our securities or any affiliate of ours except if part of a commingled fund.

The target asset allocation was established by our Board of Directors appointed Investment Trust Policy Committee, which oversees investment matters related to all of our funded benefit plans. Asset allocation is monitored by the Investment Trust Policy Committee and support staff on a monthly basis.

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Our other post-retirement benefit plans asset allocation at December 31, 2003 and 2002, and our target allocation for 2004, by asset category, are as follows:

Asset Category	Target Alocation 2004		Percentage of Pension Plans Assets at December 31
			2003		2002
Equity Securities	35	%	35	%	36	%
Debt Securities	64	%	64	%	63	%
Other	1	%	1	%	1	%
Total	100	%	100	%	100	%

Wisconsin Energy Corporation’s common stock is not included in equity securities. Investment managers are specifically prohibited from investing in our securities or any affiliate of ours except if part of a commingled fund.

The target asset allocation was established by our Board of Directors appointed Investment Trust Policy Committee, which oversees investment matters related to all of our funded benefit plans. Asset allocation is monitored by the Investment Trust Policy Committee and support staff on a monthly basis.

Cashflows:

Employer Contributions	Pension Benefits		Other Post- retirement Benefits
	(Millions of Dollars)
2002	$	—	$	12.9
2003		—		15.3
2004 (Expected)		15.0		15.5

Of the $15.0 million expected to be contributed in 2004 for pension benefits, $3.5 million is the minimum required by law for our qualified plans.

All contributions to the other post-retirement benefit plans during 2004 are discretionary, as the plans are not subject to any minimum regulatory funding requirements. These contribution would be expected to be in the form of cash.

Savings Plans:We sponsor savings plans which allow employees to contribute a portion of their pretax and or after tax income in accordance with plan-specified guidelines. Under these plans, we expensed $8.8 million of matching contributions during 2003 and $8.3 million each during 2002 and 2001.

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L—GUARANTEES

We enter into various guarantees to provide financial and performance assurance to third parties. As of December 31, 2003, we had the following guarantees:

	Maximum Potential Future Payments		Outstanding at Dec 31, 2003	Liability Recorded at Dec 31, 2003
	(Millions of Dollars)
Guarantees	$	223.3	—	—
Letters of Credit		2.1	2.1	—

We guarantee the potential retrospective premiums that could be assessed under our nuclear insurance program (See Note E).

Postemployment benefits:Postemployment benefits provided to former or inactive employees are recognized when an event occurs. As of December 31, 2003, we have recorded an estimated liability, based on an accrual analysis, of $4 million.

M—SEGMENT REPORTING

We are a wholly-owned subsidiary of Wisconsin Energy and have organized our operating segments according to how we are currently regulated. Our reportable operating segments include electric, natural gas and steam utility segments. The accounting policies of the reportable operating segments are the same as those described in Note A.

Our electric utility engages in the generation, distribution and sale of electric energy in southeastern (including metropolitan Milwaukee), east central and northern Wisconsin and in the Upper Peninsula of Michigan. Our natural gas utility is engaged in the purchase, distribution and sale of natural gas to retail customers and the transportation of customer-owned natural gas in three service areas in southeastern, east central and northern Wisconsin. Our steam utility produces, distributes and sells steam to space heating and processing customers in the Milwaukee, Wisconsin area.

Summarized financial information concerning our reportable operating segments for each of the years ended December 31, 2003, 2002 and 2001, is shown in the following table.

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	Reportable Operating Segments
Year Ended	Electric		Gas		Steam			Other (a)		Total
	(Millions of Dollars)
December 31, 2003
Operating Revenues(b)	$	1,986.4	$	513.0	$	22.5		$	—	$	2,521.9
Depreciation, Decommissioning and Amortization	$	234.1	$	38.9	$	3.2		$	—	$	276.2
Operating Income(c)	$	422.3	$	49.0	$	—		$	—	$	471.3
Equity in Earnings of Unconsolidated Affiliates	$	22.8	$	—	$	—		$	—	$	22.8
Capital Expenditures	$	271.6	$	56.8	$	2.6		$	12.7	$	343.7
Total Assets(d)	$	5,784.9	$	628.7	$	54.5		$	176.5	$	6,644.6
December 31, 2002
Operating Revenues(b)	$	1,884.6	$	389.8	$	21.5		$	—	$	2,295.9
Depreciation, Decommissioning and Amortization	$	230.0	$	34.6	$	3.3		$	—	$	267.9
Operating Income (Loss)(c)	$	453.3	$	33.5	($	1.5	)	$	—	$	485.3
Equity in Earnings of Unconsolidated Affiliates	$	20.4	$	—	$	—		$	—	$	20.4
Capital Expenditures	$	312.3	$	34.7	$	1.6		$	17.1	$	365.7
Total Assets(d)	$	5,513.3	$	566.2	$	55.3		$	150.3	$	6,285.1
December 31, 2001
Operating Revenues(b)	$	1,839.8	$	457.1	$	21.8		$	—	$	2,318.7
Depreciation, Decommissioning and Amortization	$	231.7	$	29.3	$	3.3		$	—	$	264.3
Operating Income(c)	$	446.2	$	28.6	$	1.2		$	—	$	476.0
Equity in Earnings of Unconsolidated Affiliates	$	20.6	$	—	$	—		$	—	$	20.6
Capital Expenditures	$	324.4	$	34.5	$	3.1		$	15.0	$	377.0

(a) Other includes primarily other non-utility property and investments, materials and supplies and deferred charges.

(b) We account for intersegment revenues at a tariff rate established by the PSCW. Intersegment revenues are not material.

(c) Interest income and interest expense are not included in segment operating income.

(d) Common utility plant is allocated to electric, gas and steam to determine segment assets (see Note A).

N—RELATED PARTIES

American Transmission Company: We have approximately a 34.6% interest in ATC, a regional transmission company established in 2000 under Wisconsin legislation. During 2003, 2002 and 2001, we paid ATC $94.4 million, $85.1 million and $71.0 million, respectively, for transmission services. We also provide a variety of operational, maintenance and project management work for ATC, which are reimbursed to us by ATC.

Other:Managerial, financial, accounting, legal, data processing and other services may be rendered between associated companies and are billed in accordance with service agreements approved by the PSCW. We had a net receivable from associated companies of approximately $10.7 million as of December 31, 2003.

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O—COMMITMENTS AND CONTINGENCIES

Capital Expenditures: We have made certain commitments in connection with 2004 capital expenditures. During 2004, we estimate that total capital expenditures will be approximately $406 million.

Operating Leases:We enter into long-term purchase power contracts to meet a portion of our anticipated increase in future electric energy supply needs. These contracts expire at various times through 2013. Certain of these contracts were deemed to qualify as operating leases.

Future minimum payments for the next five years and thereafter for these contracts are as follows:

	(Millions of Dollars)
2004	$	42.5
2005		41.4
2006		41.2
2007		40.8
2008		26.4
Thereafter		79.9
Total	$	272.2

Giddings & Lewis, Inc./City of West Allis Lawsuit:During 2002, we entered into Settlement Agreements and Releases with Giddings & Lewis Inc. and Kearney & Trecker Corporation (now a part of Giddings & Lewis) and the City of West Allis, thereby ending all remaining litigation in this lawsuit. Under the Settlement Agreements and Releases, we paid $17.3 million as full and final settlement of all damage claims against us. These settlements resulted in a 2002 charge of approximately $10.6 million after tax for us. The Settlement Agreements were determined to be in the mutual best interests of the settling parties in order to avoid the burden, inconvenience and expense of continued litigation between the parties and do not constitute an admission of liability or wrongdoing by us with respect to any released claims.

In September 2002, we filed a lawsuit against our insurance carriers to recover those costs and expenses associated with this matter. As of December 31, 2003, we have recovered amounts totaling approximately $11.2 million from several insurance carriers, with $11.1 million recorded as a reduction of other operation and maintenance expenses. We are continuing to pursue litigation against the remaining insurance carriers and other third parties.

Environmental Matters: We periodically review our exposure for environmental remediation costs as evidence becomes available indicating that our liability has changed. Given current information, including the following, management believes that future costs in excess of the amounts accrued and/or disclosed on all presently known and quantifiable environmental contingencies will not be material to our financial position or results of operations.

We have a voluntary program of comprehensive environmental remediation planning for former manufactured gas plant sites and coal-ash disposal sites. We perform ongoing assessments of manufactured gas plant sites and related disposal sites and coal ash disposal/landfill sites used by us, as discussed below. We are working with the Wisconsin Department of Natural Resources in our investigation and remediation planning. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

Manufactured Gas Plant Sites: We have completed planned remediation activities at three former manufactured gas plant sites. Remediation at additional sites is currently being performed, and other sites are being investigated or monitored. We have identified additional sites that may have been impacted by historical manufactured gas plant activities. Based upon ongoing analysis, we estimate that the future costs for detailed site investigation and future remediation costs may range from $25-$40 million over the next ten years. This estimate is dependent upon several variables including, among other things, the extent of remediation, changes in technology and changes in regulation. As of December 31, 2003, we have established reserves of $23.5 million related to future remediation costs.

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The PSCW has allowed Wisconsin utilities, including us, to defer the costs spent on the remediation of manufactured gas plant sites, and has allowed for these costs to be recovered in rates over five years. Accordingly, we have recorded a regulatory asset for remediation costs.

Ash Landfill Sites:    We aggressively seek environmentally acceptable, beneficial uses for our coal combustion by-products. However, these coal-ash by-products have been, and to a small degree, continue to be disposed in company-owned, licensed landfills. Some early designed and constructed landfills may allow the release of low levels of constituents resulting in the need for various levels of monitoring or adjusting. Where we have become aware of these conditions, efforts have been expended to define the nature and extent of any release and work has been performed to address these conditions. The costs of these efforts are included in our fuel costs. During 2003, 2002 and 2001, we incurred $2.1 million, $2.1 million and $1.2 million, respectively, in coal-ash remediation expenses. As of December 31, 2003 we have no reserves established related to ash landfill sites.

EPA Information Requests:    We received a request for information in December 2000 from the United States Environmental Protection Agency (EPA) regional offices pursuant to Section 114(a) of the Clean Air Act and a supplemental request in December 2002. In April 2003, we announced that a consent decree had been reached with the EPA that resolved all issues related to this matter. Under the consent decree, we will significantly reduce our air emissions from our coal-fired generating facilities. The reductions will be achieved between now and 2013 through a combination of installing new pollution control equipment, upgrading existing equipment, and retiring certain older units. The capital cost of implementing this agreement is estimated to be approximately $600 million over 10 years. Under the agreement with EPA, we will spend between $20 million and $25 million to conduct a research project at our Presque Isle facility, in cooperation with the U.S. Department of Energy, to test new mercury reduction technologies. These steps and the associated costs are consistent with our cost projections for implementing our Wisconsin Multi-Emission Cooperative Agreement and Wisconsin Energy’sPower the Future plan. We also agreed to pay a civil penalty of $3.2 million, which was charged to earnings in the second quarter of 2003. On July 21, 2003, the court granted the state of Michigan’s and the EPA’s joint motion to amend the consent decree to allow Michigan to become a party. Under the terms of the amended consent decree, $0.1 million of the original $3.2 million civil penalty will be paid to the state of Michigan. The agreement has gone through the public comment period. In October 2003, three citizen groups filed a motion with the court to intervene in the proceeding to contest the consent decree; the court granted their motion. Also, in October 2003, the government filed its response to public comments and a motion asking the court to approve the amended consent decree The intervenor groups subsequently filed a motion requesting that the court stay the government’s motion for approval of the decree to allow the intervenors to conduct discovery. Briefing has been completed. Both the intervenors’ motion and the government’s motion for court approval of the decree are before the court for consideration.

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INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Stockholders of Wisconsin Electric Power Company:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Wisconsin Electric Power Company and subsidiary as of December 31, 2003 and 2002, and the related consolidated statements of income, common equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. The financial statements of Wisconsin Electric Power Company for the year ended December 31, 2001 were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statements in their report dated February 5, 2002.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Wisconsin Electric Power Company and subsidiary at December 31, 2003 and 2002, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

As described in Note F, on January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”.

Deloitte & Touche LLP

Milwaukee, Wisconsin

February 20, 2004

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The following report is a copy of a report previously issued by Arthur Andersen LLP in connection with our Annual Report on Form 10-K for the year ended December 31, 2001. This opinion has not been reissued by Arthur Andersen LLP. See Exhibit 23.2 for further discussion.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors and Stockholders of Wisconsin Electric Power Company:

We have audited the accompanying balance sheet and statement of capitalization of Wisconsin Electric Power Company as of December 31, 2001, and the related statements of income, common equity and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Wisconsin Electric Power Company as of December 31, 2001, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States.

Arthur Andersen LLP

Milwaukee, Wisconsin

February 5, 2002

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MARKET FOR REGISTRANT’S COMMON

EQUITY AND RELATED STOCKHOLDER MATTERS

Dividends declared on our common stock during the two most recent fiscal years are set forth below. Dividends were paid entirely in cash. Dividends were paid to our sole common stockholder, Wisconsin Energy Corporation. There is no established public trading market for our common stock.

Quarter	2003		2002
	(Millions of Dollars)
First	$	44.9	$	44.9
Second		44.9		44.9
Third		44.9		44.9
Fourth		44.9		44.9
Total	$	179.6	$	179.6

Subject to any regulatory restriction or other limitations on the payment of dividends, future dividends will be at the discretion of the board of directors and will depend upon, among other factors, earnings, financial condition and other requirements.

Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. Under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy.

BUSINESS OF THE COMPANY

We are an electric, gas and steam utility which was incorporated in the state of Wisconsin in 1896. Our operations are conducted in the following three segments.

Electric Operations:Our electric operations generate, distribute and sell electric energy to approximately 1,068,000 customers in Wisconsin and in the Upper Peninsula of Michigan. We transferred our electric transmission assets together with Edison Sault Electric Company, an affiliated electric utility, and with other unaffiliated Wisconsin utilities, to American Transmission Company LLC in return for a proportionate ownership interest in this new company on January 1, 2001.

Gas Operations:Our gas operations purchase, distribute and sell natural gas to retail customers and transports customer-owned gas to approximately 428,700 customers in three distinct service areas in Wisconsin. We began doing business with Wisconsin Gas Company, an affiliated gas utility, under the trade name “We Energies” in April 2002.

Steam Operations:Our steam operations generate, distribute and sell steam supplied by our Valley and Milwaukee County Power Plants. Steam is used by approximately 460 customers in the metropolitan Milwaukee area for space heating and processing, hot water and humidification.

For additional financial information about our operating segments, see “Note M – Segment Reporting” in the Notes to Consolidated Financial Statements.

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DIRECTORS AND EXECUTIVE OFFICERS

DIRECTORS

The information under “Election of Directors” in Wisconsin Electric’s definitive Information Statement dated March 16, 2004, attached hereto, is incorporated herein by reference.

EXECUTIVE OFFICERS

Richard A. Abdoo

Chairman of the Board

Charles R. Cole

Senior Vice President

Stephen P. Dickson

Controller

Gale E. Klappa

President and Chief Executive Officer

Frederick D. Kuester

Chief Operating Officer

Allen L. Leverett

Chief Financial Officer

Larry Salustro

Senior Vice President and General Counsel

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