Edgar Filing: WISCONSIN ENERGY CORP

Definitive Proxy Statement

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

SCHEDULE 14A

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SEC 1913 (3-99)

LOGO

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Notice of 2004 Annual Meeting of Stockholders

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Proxy Statement

•

Annual Financial Statements and Review of Operations

NOTICE OF ANNUAL MEETING OF STOCKHOLDERS

March 16, 2004

To the Stockholders of Wisconsin Energy Corporation:

You are cordially invited to attend the 2004 Annual Meeting of Stockholders. Regardless of whether you plan to attend, please take a moment to vote your proxy. It is especially important to vote this year, as the proposed amendment to the Bylaws requires an 80% affirmative vote of the outstanding shares to be adopted. The Meeting will be held as follows:


WHEN:		Wednesday, May 5, 2004 10:00 a.m., Central Time

WHERE:		Wisconsin Exposition Center State Fair Park 8200 West Greenfield Avenue West Allis, WI 53214

ITEMS OF BUSINESS:		• Elect three directors for terms expiring in 2007. • Approve an amendment to the Bylaws eliminating the classification of the Board of Directors. • Consider any other matters that may properly come before the Meeting.

RECORD DATE:		February 25, 2004

VOTING BY PROXY:		Your vote is important. You may vote:
		• using the Internet, • by telephone, or • by returning the proxy card in the envelope provided.

On the following pages, we list several Frequently Asked Questions about the Meeting and our corporate governance initiatives. Should you have additional questions, do not hesitate to contact the stockholder hotline at 1-800-881-5882.

By Order of the Board of Directors

Kristine Rappé

Vice President and Corporate Secretary

TABLE OF CONTENTS


		Page
Notice of Annual Meeting of Stockholders

Proxy Statement

General Information – Frequently Asked Questions		1

Proposals to be Voted Upon		3

Proposal 1: Election of Directors – Terms Expiring in 2007		3

Directors’ Biographical Information		4

Proposal 2: Amendment to the Bylaws Eliminating the Classification of the Board of Directors		6

Corporate Governance – Frequently Asked Questions		7

Committees of the Board of Directors		12

Independent Auditors		13

Audit and Oversight Committee Report		15

Compensation of the Board of Directors		16

Compensation Committee Report on Executive Compensation		17

Executive Officers’ Compensation		20

Employment and Severance Arrangements		23

Retirement Plans		25

Wisconsin Energy Corporation Common Stock Ownership		28

Section 16(a) Beneficial Ownership Reporting Compliance		29

Certain Relationships and Related Transactions		29

Performance Graph		30

Availability of Form 10-K		31

Appendices

Appendix A: Proposed Amendment to Wisconsin Energy Corporation’s Bylaws		A-1

Appendix B: Annual Financial Statements and Review of Operations		B-1

PROXY STATEMENT

This proxy statement is being furnished to stockholders beginning on or about March 16, 2004, in connection with the solicitation of proxies by the Wisconsin Energy Corporation (“WEC” or the “Company”) Board of Directors (the “Board”) to be used at the Annual Meeting of Stockholders on May 5, 2004 (the “Meeting”), at the Wisconsin Exposition Center at State Fair Park, located at 8200 West Greenfield Avenue, West Allis, Wisconsin 53214, and at all adjournments or postponements of the Meeting, for the purposes listed in the preceding Notice of Annual Meeting of Stockholders.

GENERAL INFORMATION – FREQUENTLY ASKED QUESTIONS



What am I voting on?		Proposal 1: To elect three directors for terms expiring in 2007.

		Proposal 2: To amend the Bylaws to eliminate the classification of the Board and allow the annual election of all directors in future years.

		The Company is not aware of any other matters that will be voted on. If a matter does properly come before the Meeting, the persons named as the proxies in the accompanying form of proxy will vote the proxy at their discretion.


What are the Board’s voting recommendations?		The Board of Directors recommends a vote: • FOR each of the three nominated directors, and
		• FOR the amendment to the Bylaws eliminating the classification of the Board of Directors.


What is the vote required for each proposal?		Proposal 1: The three individuals receiving the largest number of votes will be elected as directors.

		Proposal 2: The amendment to the Bylaws requires the affirmative vote of the holders of at least 80% of the outstanding shares of WEC common stock.


Who can vote?		Common stockholders as of the close of business on the record date, February 25, 2004, can vote. Each outstanding share of WEC common stock is entitled to one vote upon each matter presented. A list of stockholders entitled to vote will be available for inspection by stockholders at WEC’s principal business office at 231 West Michigan Street, P. O. Box 2949, Milwaukee, Wisconsin 53201, prior to the Meeting. The list will also be available at the Meeting.


How do I vote?		There are several ways to vote:

		• By Internet. To save costs, the Company encourages you to vote this way.
		• By toll-free touch-tone telephone.
		• By completing and mailing the enclosed proxy card.
		• By written ballot at the Meeting.

		Instructions to vote through the Internet or by telephone are listed on your proxy card or the information forwarded to you by your bank or broker. The Internet and telephone voting facilities will close at 10:00 a.m., Central Time, on May 5, 2004.

		If you are a participant in WEC’s Stock Plus Investment Plan (“Stock Plus”) or own shares through investments in the WEC Common Stock Fund in one of WEC’s 401(k) plans, your proxy will serve as voting instructions for your shares held in those plans. The administrator for Stock Plus and the trustee for the 401(k) plans will vote your shares as you direct. If a proxy is not returned for shares held in Stock Plus, the administrator will not vote those shares. If a proxy is not returned for shares held in a 401(k) plan, the trustee will vote those shares in the same proportion that all shares in the WEC Common Stock Fund for which voting instructions have been received are voted.



		If you are a beneficial owner and your broker holds your shares in its name, the broker is permitted to vote your shares on the election of directors and the proposal to eliminate the classification of the Board of Directors and related amendment to the Bylaws even if the broker does not receive voting instructions from you.

		If your shares are held in the name of a broker, bank or other holder of record you are invited to attend the Meeting, but may not vote at the Meeting unless you have first obtained a proxy, executed in the stockholder’s favor, from the holder of record.


What does it mean if I get more than one proxy?		It means your shares are held in more than one account. Please vote all proxies to ensure all your shares are counted.


What constitutes a quorum?		As of the record date, there were 118,604,529 shares of WEC common stock outstanding. In order to conduct the Meeting, a majority of the outstanding shares entitled to vote must be represented in person or by proxy. This is known as a “quorum.” Abstentions and shares which are the subject of broker non-votes will count toward establishing a quorum.


Can I change my vote?		You can change your vote or revoke your proxy at any time prior to the closing of the polls, by:
		• entering a new vote by Internet or phone,
		• returning a later-dated proxy card,
		• voting in person at the Meeting, or
		• notifying WEC’s Corporate Secretary by written revocation letter.

		The Corporate Secretary is Kristine Rappé. Any revocation should be filed with her at WEC’s principal business office, 231 West Michigan Street, P. O. Box 2949, Milwaukee, Wisconsin 53201.

		Attendance at the Meeting will not in itself constitute revocation of a proxy. All shares entitled to vote and represented by properly completed proxies timely received and not revoked will be voted as you direct. If no direction is given, the proxies will be voted as the Board recommends.


Who conducts the proxy solicitation?		The WEC Board is soliciting these proxies. WEC will bear the cost of the solicitation of proxies. WEC has retained Georgeson Shareholder Communications Inc. to assist in soliciting proxies from stockholders, including brokers’ accounts, at a fee of $15,000 plus expenses. Also, employees of WEC or its subsidiaries may solicit proxies by mail, by telephone, personally or by other communications, without compensation apart from their normal salaries.


Who will count the votes?		The Bank of New York, which will also serve as Inspector of Election, will tabulate the voted proxies.



What steps has WEC taken to reduce the cost of proxy solicitation?		WEC has implemented several practices that reduce the printing and postage costs and are friendly to the environment. The Company has: • encouraged Internet and telephone voting of your proxies,
		• encouraged stockholders to view the proxy statement and annual report on the Internet instead of receiving them via mail, and
		• implemented “householding” whereby stockholders sharing a single address receive a single annual report and proxy statement, unless the Company received instructions to the contrary.

		If you received multiple copies of the annual report and proxy statement, you may wish to contact the Company’s transfer agent, The Bank of New York, at 1-800-558-9663 to request householding, or you may provide written instructions to The Bank of New York at Church Street Station, P.O. Box 11258, New York, NY, 10286-1258. If you wish to receive separate copies of the annual report and proxy



		statement now or in the future, or to discontinue householding entirely, you may contact the Company’s transfer agent using the contact information provided above. Upon request, the Company will promptly send a separate copy of either document. Whether or not a stockholder is householding, each stockholder will continue to receive a proxy card. If your shares are held through a bank, broker or other holder of record, you may request householding by contacting the holder of record.

PROPOSALS TO BE VOTED UPON

PROPOSAL 1: ELECTION OF DIRECTORS – TERMS EXPIRING IN 2007

Directors elected at this Meeting will hold office for three-year terms expiring at the 2007 Annual Meeting of Stockholders. However, if the proposal to eliminate the classification of the Board of Directors, as more fully described in Proposal 2 of this proxy statement, is approved, then the terms of all directors, including those elected at the Meeting, will end at the 2005 Annual Meeting of Stockholders and all directors will thereafter be elected for one- year terms.

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.

The Board’s nominees for election are Robert A. Cornog, Gale E. Klappa and Frederick P. Stratton, Jr.

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 WEC Board upon the recommendation of the Corporate Governance Committee of the Board.

Pursuant to authority granted to the Board under the Bylaws, the Board of Directors elected Gale E. Klappa, President of Wisconsin Energy Corporation and President and Chief Executive Officer of Wisconsin Electric Power Company and Wisconsin Gas 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.

The Board of Directors recommends that you vote “FOR” all the director nominees.

Richard A. Abdoo, Chairman of the Board and Chief Executive Officer of Wisconsin Energy Corporation, and Chairman of the Board of Wisconsin Electric Power Company and Wisconsin Gas Company, has indicated his intention to retire from all officer and director positions with Wisconsin Energy Corporation and its subsidiaries, 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 officer positions held by Mr. Abdoo. Accordingly, effective as of May 1, 2004, Mr. Klappa, who is currently President of Wisconsin Energy Corporation and the President and Chief Executive Officer of Wisconsin Electric Power Company and Wisconsin Gas Company, will hold the titles of Chairman of the Board, President and Chief Executive Officer of all three companies. Mr. Abdoo is currently a member of the class of directors of the Company whose terms expire in 2005. On the effectiveness of Mr. Abdoo’s retirement as a director effective 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. The same action has been taken with respect to Mr. Abdoo’s position as a director of Wisconsin Electric Power Company and Wisconsin Gas Company.

Biographical information regarding each nominee and each director whose term will continue after the Meeting is shown below. Ages are as of March 16, 2004. Wisconsin Electric Power Company (WE) and Wisconsin Gas Company (WG) are now doing business as We Energies and are subsidiaries of Wisconsin Energy Corporation.



Nominees for Terms Expiring in 2007

		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.


		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.


		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.

Directors Continuing in Office – 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 publishes American 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.



	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.


	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.


Directors Continuing in Office – Terms Expiring in 2006

	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.


	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.

PROPOSAL 2: AMENDMENT TO THE BYLAWS ELIMINATING THE

CLASSIFICATION OF THE BOARD OF DIRECTORS

Directors’ Statement of Support. As permitted by its Restated Articles of Incorporation, the Company’s Bylaws provide for the classification of the Board of Directors into three classes, as nearly equal in number as possible. Each director currently serves a three-year term. Directors for one of the three classes are elected each year. The Board has determined that the Bylaws should be amended to eliminate classification of the Board and has unanimously adopted a resolution approving the amendment, declaring its advisability and recommending that stockholders vote to approve the amendment for the reasons stated below. It is also recommended that an outdated reference fixing the size of the Board at nine be eliminated from the Bylaws; the Bylaw provision granting the Board the authority to fix the size of the Board would remain unchanged. If the amendment to the Bylaws is approved, the Board will adopt certain conforming changes to the Bylaws, as appropriate.

A classified board has the effect of making it more difficult (i) for a substantial stockholder to gain control of a board of directors without the approval or cooperation of incumbent directors and therefore may deter unfriendly and unsolicited takeover proposals and proxy contests, and (ii) for stockholders to change a majority of directors even where a majority of stockholders are dissatisfied with the performance of incumbent directors.

The Board has carefully examined the arguments for and against continuation of the classified Board, considered stockholder opinions and corporate governance best practices and determined that the classified Board should be eliminated. The election of directors is the primary means for stockholders to influence corporate governance policies and to hold management accountable for implementing these policies, and the proposed amendment will allow stockholders to review and express their opinions on the performance of all directors each year, rather than over a three-year period. Because there is no limit to the number of terms an individual may serve, the continuity and stability of the Board’s membership and the Company’s policies and long-term strategic planning should not be affected.

The text of the proposed amendment is attached as Appendix A to this proxy statement.

If the amendment is adopted, how will the declassified Board be implemented?

If the proposed amendment is approved by the Company’s stockholders, it will become effective at the time of the Annual Meeting of Stockholders in 2005, and the classified Board will be eliminated, the current term of each director will end at the 2005 Annual Meeting of Stockholders, and directors will be elected for one-year terms at the 2005 Annual Meeting of Stockholders and at each Annual Meeting thereafter. In addition, any director elected to fill a vacancy on the Board of Directors, including a vacancy created by an increase in the number of directors, will hold office until the next Annual Meeting of Stockholders.

What is the vote required for approval?

The Company’s Bylaws require the affirmative vote of the holders of at least 80% of the outstanding shares of WEC common stock entitled to vote to approve the proposal to amend the Bylaws to eliminate the classification of the Board of Directors. Abstentions, broker non-votes and shares that are not represented at the Meeting will have the effect of votes cast against the proposal.

The Board of Directors unanimously recommends that you vote “FOR” the amendment to

the Bylaws eliminating the classification of the Board of Directors.

CORPORATE GOVERNANCE – FREQUENTLY ASKED QUESTIONS



Does WEC have Corporate Governance Guidelines?		Yes, the Board has maintained Corporate Governance Guidelines since 1996, which provide a framework from which it conducts its business. The 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 the Company’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. The 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 the 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.

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 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 WEC.



What are the committees of the Board?		The Board of Directors has the following committees: Audit and Oversight, Compensation, Corporate Governance, Finance, Nuclear Oversight, 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 the Company’s website at www.WisconsinEnergy.com. The members and the responsibilities of each committee are listed later in this proxy statement.

Are the Audit and Oversight, Corporate Governance 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 the Company’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 the 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 2949, 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 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 Company’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.



Does the Board evaluate CEO performance?		Yes, the Compensation Committee, on behalf of the Board, annually evaluates the performance of the CEO and reports the results to the Board. As part of this practice, the Compensation Committee requests that all independent directors provide their opinions to the Compensation Committee chair on the CEO’s performance. The CEO is evaluated in a number of areas including leadership, vision, financial stewardship, strategy development, management development, effective communication to constituencies, demonstration of integrity and effective representation of the Company in community and industry affairs. The chair of the Compensation Committee shares the responses with the CEO. The process is also used by the Committee to determine appropriate compensation for the CEO. This procedure allows the Board to evaluate the CEO and to communicate the Board’s expectations.

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. The Corporate Governance Committee uses the results of this process as part of its annual review of the 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 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?		Yes, the Corporate Governance Committee is responsible for identifying and evaluating director nominees. The chair of the Committee coordinates this effort. All members of the Corporate Governance Committee are independent under the New York Stock Exchange rules applicable to nominating committee members.



What is the process used to identify director nominees and how do I recommend a nominee to the Corporate Governance Committee?		Candidates for director nomination may be proposed by stockholders, the 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 proxy 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 the 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 the 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 2949, Milwaukee, Wisconsin 53201.

What are the criteria and process used to evaluate director nominees?		The 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 the Company’s businesses and contribution to the Board’s desired diversity and balance.
		In evaluating director candidates, the 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. The Bylaws state that directors shall be stockholders of WEC. Once a person has been identified by the 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 WEC faces in today’s changing business environment.



What is the deadline for stockholders to submit proposals for the 2005 Annual Meeting of Stockholders?		Stockholders who intend to have a proposal considered for inclusion in the Company’s proxy materials for presentation at the 2005 Annual Meeting of Stockholders must submit the proposal to the Company no later than November 16, 2004. Stockholders who intend to present a proposal at the 2005 Annual Meeting of Stockholders without inclusion of such proposal in the Company’s proxy materials, or who propose to nominate a person for election as a director at the Meeting, are required to provide notice of such proposal or nomination, containing the information required by the Company’s Bylaws, to the Company at least 70 days and not more than 100 days prior to the scheduled date of the 2005 Annual Meeting of Stockholders. Correspondence in this regard should be directed to the Corporate Secretary, Kristine Rappé, at the Company’s principal business office, 231 West Michigan Street, P.O. Box 2949, Milwaukee, Wisconsin 53201.

What is WEC’s policy regarding director attendance at annual meetings?		All directors are expected to attend the Company’s Annual Meetings of Stockholders. All directors attended the 2003 Annual Meeting.

Where can I find more information about WEC corporate governance?		The Company’s website, www.WisconsinEnergy.com, contains information on the Company’s governance activities. 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.

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 for inclusion in the proxy statement.
		• 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 for inclusion in the proxy statement.
		• The Committee conducted seven meetings in 2003.


Corporate Governance Willie D. Davis, Chair Barbara L. Bowles Robert A. Cornog		• Establish and review the Corporate Governance Guidelines to ensure the Board is effectively performing its fiduciary responsibilities to stockholders.
		• Identify and recommend candidates to be named as nominees of the Board for election as directors.
		• Lead the Board in its annual review of the Board’s performance.
		• The Committee conducted three 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 four meetings in 2003.


Nuclear Oversight John F. Ahearne, Chair Frederick P. Stratton, Jr.		• Advise and assist the Board in the proper and complete discharge of its responsibilities relating to the Company’s nuclear operations.
		• The Committee conducted two meetings in 2003.

The Nuclear Oversight Committee also includes one employee member and three non-directors who serve as ad hoc members due to their considerable expertise in nuclear matters. The employee member of the Committee is Frederick D. Kuester, Chief Operating Officer of Wisconsin Electric Power Company. The ad hoc members are Mr. Leon R. Eliason, former President—Generation at Northern States Power Company and former President—Nuclear Business Unit and Chief Nuclear Officer at Public Service Enterprise Group Incorporated, Dr. Thomas E. Murley, former director of the Nuclear Regulatory Commission’s Office of Nuclear Reactor Regulation, and Dr. C. Frederick Sears, formerly responsible for overseeing Northeast Utilities’ nuclear and environmental functions.

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 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 eight times in 2003. The average meeting attendance during the year was 95%. No director attended fewer than 86% of the total number of meetings of the Board and Board committees on which he or she served.

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 expected to be present at the Meeting. They will have an opportunity to make a statement, 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 the 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 the 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 approved the engagement of Deloitte & Touche LLP to audit the financial statements of the Company and its subsidiaries for fiscal 2003, and to provide certain non-audit services to the Company and its subsidiaries 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 WEC’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⁾	$	668,950	$	1,032,885
Audit-Related Fees ⁽²⁾		99,452		138,133
Tax Fees⁽³⁾		163,398		323,093
All Other Fees ⁽⁴⁾		—		—

Total	$	931,800	$	1,494,111

⁽¹⁾

Audit Fees: Fees for the professional services rendered for the audit of WEC’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 WEC’s financial statements. For 2003, this included benefit plan audits and other related services. For 2002, this included benefit plan audits, an investigation at an overseas manufacturing plant, and other related services.

⁽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 Energy Corporation. 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 the Company’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. Wisconsin Energy Corporation’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 Wisconsin Energy Corporation’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 Energy Corporation 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.

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 WEC director compensation with director compensation at WEC’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 restricted stock equal to a value of $65,000, vesting in three years.

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. 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 WEC directors also serve on the Wisconsin Electric Power Company 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 proxy statement.

The Company has established a Directors’ Charitable Awards Program to help further its policy of charitable giving. Under the program, the Company 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. 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 the 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.

COMPENSATION COMMITTEE REPORT

ON EXECUTIVE COMPENSATION

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

We believe that a substantial portion of executive compensation should be at risk. As a result, WEC’s 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 WEC’s executive compensation program are base salary, annual incentive compensation, and long-term incentive compensation. For WEC executives, 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.

In order to determine competitive compensation practices, we rely upon compensation surveys provided to us by Towers Perrin, an independent compensation consultant. We believe that the labor market for WEC executives is that of general industry in the United States. As a result, we principally rely upon a survey of compensation practices of similarly sized companies in general industry. However, we also recognize that a significant portion of WEC’s business is in the energy industry. Therefore, for executives whose positions principally relate to utility operations, we place a greater emphasis upon compensation practices in the energy industry.

Specific values of 2003 compensation for the Chief Executive Officer and the four other most highly compensated executive officers, 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 earnings per share, return on equity and cash flow. For Mr. Donnelly, the measures were EBITDA and sales growth related to WICOR Industries, Inc. (now WICOR Industries, LLC). 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 WEC 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%.

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 WEC executives to achieve the corporation’s 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 stock ownership by participants. Accordingly, as a condition of participating in the long-term incentive plan, we have implemented stock ownership guidelines for officers of the Company 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. Donnelly, 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 proxy 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 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 will be measured against the Custom Peer Group identified in the “Performance Graph” section of this proxy statement.

Chief Executive Officer Compensation. The assessment of the Chief Executive Officer’s performance and determination of the CEO’s compensation are among our principal responsibilities.

In reviewing the performance of WEC’s Chief Executive Officer, we requested that all non-employee directors evaluate the CEO’s performance. The Compensation Committee chair reviewed the evaluations, met with Mr. Abdoo to discuss them, and the Committee factored the results into our compensation determinations.

We set Mr. Abdoo’s base salary at $794,004 for 2003. This base salary is at the low end of the competitive range for CEO’s 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.

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

•

Milestones achieved with respect to implementation of WEC’s Power 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;

•

His 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 his compensation to the enhancement of long-term stockholder value, Mr. Abdoo was 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.

As described earlier in this proxy statement, Mr. Abdoo will retire from all positions with the Company and its subsidiaries 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 proxy 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 WEC and its stockholders despite the fact that such arrangements might not, in whole or in part, qualify for tax deductibility.

Respectfully submitted to Wisconsin Energy Corporation’s stockholders by the Compensation Committee of the Board of Directors.

John F. Bergstrom, Committee Chair

John F. Ahearne

Willie D. Davis

EXECUTIVE OFFICERS’ COMPENSATION

This table summarizes, for the last three fiscal years, compensation awarded to, earned by or paid to WEC’s Chief Executive Officer, each of WEC’s other four most highly compensated executive officers, 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 year 2003.

Summary Compensation Table


		Annual Compensation					Long-Term Compensation Awards
Name and Principal Position	Year	Salary ($)	Bonus ($)		Other Annual Compensation ($)		Restricted Stock Awards⁽¹⁾ ($)	Securities Underlying Options (#)	All Other Compensation⁽²⁾ ($)

Richard A. Abdoo Chairman of the Board and Chief Executive Officer of WEC; Chairman of the Board of WE and WG⁽⁵⁾	2003 2002 2001	794,004 756,300 707,500	1,500,000 859,308 563,948		11,749 11,868 11,811		0 0 163,120	300,000 300,000 300,000	49,099 66,959 66,875

Gale E. Klappa President of WEC since April 2003; President and Chief Executive Officer of WE and WG since August 2003	2003	458,179	1,075,000	⁽³⁾	131,740	⁽⁴⁾	1,006,320	250,000	12,952

Allen L. Leverett Chief Financial Officer of WEC, WE, and WG since July 2003	2003	230,004	690,000	⁽³⁾	66,025	⁽⁴⁾	846,748	200,000	6,900

James C. Donnelly President and Chief Executive Officer of WICOR Industries, LLC⁽⁶⁾	2003 2002 2001	440,004 420,000 400,000	329,446 251,790 80,000		0 0 0		0 0 61,170	113,730 113,130 113,130	20,254 40,068 51,085

Larry Salustro Senior Vice President and General Counsel of WEC, WE, and WG	2003 2002 2001	360,000 336,000 311,668	375,000 323,331 165,797		2,550 2,297 2,339		306,600 0 122,340	125,000 75,000 75,000	14,370 34,075 33,956

Richard R. Grigg President of WE and President and Chief Operating Officer of WG 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 2002 2001	579,600 518,668 440,000	463,680 507,879 350,719	⁽³⁾	7,456 4,015 4,128		0 0 122,340	200,000 200,000 131,535	3,458,102 52,874 98,545

Paul Donovan Executive Vice President and Chief Financial Officer of WEC, WE and WG until June 2003; Special Advisor to the Chairman and CEO of WEC after June 2003	2003 2002 2001	579,600 518,668 440,000	463,680 471,448 282,333	⁽³⁾	4,064 206,057 28,760	⁽⁴⁾	0 0 122,340	200,000 200,000 131,535	31,031 53,643 65,463

⁽¹⁾

In 2003, restricted stock awards were granted to Messrs. Klappa, Leverett and Salustro in the amounts of 39,510 shares, 28,850 shares, and 12,000 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 and $25.55 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. 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 the Company 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. Abdoo—37,764 shares ($1,263,206), Mr. Klappa—40,308 shares ($1,348,303), Mr. Leverett—29,223 shares ($977,509), Mr. Donnelly—3,302 shares ($110,452), Mr. Salustro—28,308 shares ($946,903), 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. Abdoo, Klappa, Leverett, Donnelly, Salustro, Grigg and Donovan, includes:

•

employer matching of contributions into the 401(k) plan in the amount of $5,500, $3,352, $0, $5,500, $5,430, $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 $43,599, $9,600, $6,900, $14,754, $8,940, $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 and Leverett received one-time signing bonuses of $350,000 and $250,000, respectively, and minimum guaranteed annual bonuses for 2003 of $576,000 and $368,000 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⁾

As discussed elsewhere in this proxy statement, effective as of April 30, 2004, Mr. Abdoo will retire from all officer and director positions with WEC and its subsidiaries, and will retire as an employee.

⁽⁶⁾

As described elsewhere in this proxy statement, effective as of May 1, 2004, Mr. Donnelly will retire from all officer and director positions with WEC and its subsidiaries, and will retire as an employee. In connection with his retirement, in addition to the retirement benefits to which he is entitled, Mr. Donnelly will receive the severance benefits described under “Employment and Severance Arrangements” in this proxy statement.

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 ($/Share)	Expiration Date	Grant Date Present Value⁽²⁾ ($)

Richard A. Abdoo	300,000	10.30	25.41	01/02/2013	2,049,900
Gale E. Klappa	250,000	8.58	25.31	04/14/2013	1,623,500
Allen L. Leverett	200,000	6.87	29.13	07/01/2013	1,520,600
James C. Donnelly	113,730	3.90	25.41	01/02/2013	777,117
Larry Salustro	125,000	4.29	25.41	01/02/2013	854,125
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, and July 1, 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%. 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.

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

Richard A. Abdoo	22,500	105,525	480,999		700,001	4,597,502	7,002,913
Gale E. Klappa	--	--	--		250,000	--	2,035,000
Allen L. Leverett	--	--	--		200,000	--	864,000
James C. Donnelly	52,572	816,367	358,339		255,142	6,253,932	2,510,003
Larry Salustro	--	--	153,749		231,251	1,531,992	2,270,495
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. Donnelly is a Tier 1 participant and Mr. Salustro is a Tier 2 participant. Messrs. Abdoo, Klappa, Leverett, 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 1 and 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.

The Company has entered into agreements with each of Messrs. Abdoo, Klappa, Leverett, 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 the Company, 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 the Company 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 the Company prior to termination or the change 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 the Company 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 the Company. 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 the Company, Mr. Klappa was granted a non-qualified stock option for 250,000 shares of the Company’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 the Company.

•

Mr. Leverett commenced employment with the Company 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 the Company 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 the Company’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 the Company.

•

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 the Company except those of Executive Vice President of WEC and Chief Operating Officer of Wisconsin Electric Power Company 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 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 the Company 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.

Mr. Donnelly has agreed to retire from all officer and director positions with the Company and its subsidiaries, and to retire as an employee of WICOR Industries, effective as of May 1, 2004. In connection with his retirement, the Company has agreed to pay Mr. Donnelly, in lieu of any other severance benefits to which he might have been entitled, a lump sum severance payment equal to three times the sum of his current base salary and highest bonus in the last three years (or current target bonus, if higher), plus a pension lump sum for the equivalent of three years worth of additional service. This payment, in the total amount of $3,908,304 is equal to the amount to which Mr. Donnelly would have been entitled upon a qualifying termination of employment under the Company’s severance policies described above in the event of or in anticipation of a change in control (including, in his case, a change in control of WICOR Industries, as will result from the pending sale of WICOR Industries to Pentair, Inc.). The Company has also agreed to provide Mr. Donnelly and his family with three years continuation of medical, dental and death benefits after May 1, 2004 on the same basis as if his employment had not terminated, subject to all of the terms applicable to active employees from time to time, including the making of any required contributions. His beneficiary will be entitled to a death benefit under the Company’s Death Benefit Only Plan described below in an amount equal to three times his final base salary in the event of his death within three years after May 1, 2004, and one times such salary upon death thereafter. The Company will also cause the restricted stock award granted to Mr. Donnelly on February 7, 2001 to become fully vested as of May 1, 2004.

RETIREMENT PLANS

WEC maintains a defined benefit pension plan of the cash balance type (the “WEC Plan”) for most employees, including Messrs. Abdoo, Klappa, Leverett, Donnelly, Salustro, 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.

Wisconsin Gas Company also maintained a defined benefit pension plan of the cash balance type (the “Wisconsin Gas Plan”) for most of its employees, including Mr. Donnelly. The Wisconsin Gas Plan was merged into the WEC Plan, effective as of January 1, 2002. The cash balance formula, effective in 1997, provided an annual accrual of 6% of salary and bonus, with a guaranteed earnings rate of 4%. Further, the Wisconsin Gas Plan provided that the Company could amend it from year to year to grant a higher earnings rate for the applicable year. In order to recognize the pre-1997 service and compensation of participants as of January 1, 1997, the Wisconsin Gas Plan granted each such participant a special transition credit. Additionally, the Wisconsin Gas Plan “grandfathered” individuals who were participants as of January 1, 1998 so that they will not receive any lower retirement benefit than would have been provided under the pre-1997 final average earnings formula, had it continued, if their employment terminated before December 31, 2007. The WEC Plan continues this “grandfathered” benefit approach for all former Wisconsin Gas Plan participants (including Mr. Donnelly) who became participants in the WEC Plan as a result of the January 1, 2002 merger of the plans and continued in employment as of that date.

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 tables 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 and Wisconsin Gas (including supplemental amounts providing additional benefits described below in the “Other Retirement Benefits” section):

Pension Plan Table – WEC Plan (Prior Plan Formula)


		Years of Service
Remuneration		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

Pension Plan Table – WEC Plan (Prior Wisconsin Gas Company Plan Formula)


		Years of Service
Remuneration		15	20	25	30	35	40

$	300,000	87,500	116,700	133,500	138,000	142,500	147,000
	500,000	146,900	195,900	224,100	231,600	239,100	246,600
	700,000	206,300	275,100	314,700	325,200	335,700	346,200
	900,000	265,700	354,300	405,300	418,800	432,300	445,800
	1,100,000	325,100	433,500	495,900	512,400	528,900	545,400
	1,300,000	384,500	512,700	586,500	606,000	625,500	645,000
	1,500,000	443,900	591,900	677,100	699,600	722,100	744,600
	1,700,000	503,300	671,100	767,700	793,200	818,700	844,200
	1,900,000	562,700	750,300	858,300	886,800	915,300	943,800
	2,100,000	622,100	829,500	948,900	980,400	1,011,900	1,043,400
	2,300,000	681,500	908,700	1,039,500	1,074,000	1,108,500	1,143,000
	2,500,000	740,900	987,900	1,130,100	1,167,600	1,205,100	1,242,600
	2,700,000	800,300	1,067,100	1,220,700	1,261,200	1,301,700	1,342,200
	2,900,000	859,700	1,146,300	1,311,300	1,354,800	1,398,300	1,441,800

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. Abdoo, Klappa, Leverett, Donnelly, Salustro, Grigg and Donovan, currently have or are considered to have 35, 35, 14, 16, 31, 33 and 31 credited years of service, respectively.

Other Retirement Benefits. Designated officers of WEC and Wisconsin Electric Power Company, including Messrs. Abdoo, Klappa, Leverett, Salustro, 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.

Designated officers of Wisconsin Gas Company and Mr. Donnelly participate in the Wisconsin Gas Company Supplemental Retirement Income Program. This plan provides supplemental retirement benefits to take into account certain compensation that is excluded under the applicable retirement plan and to provide benefits that otherwise would have been accrued or payable, except for the limitations of the Internal Revenue Code.

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.

WEC has entered into agreements with Messrs. Klappa and Leverett 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 and on January 1, 1989 for Mr. Leverett.

Due to certain restrictions contained in the Sarbanes-Oxley Act of 2002, effective June 2003, the Company 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 the Company 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.

WEC COMMON STOCK OWNERSHIP

Directors, Nominees and Executive Officers. The following table lists the beneficial ownership of WEC common stock of each 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 common stock.


	Shares Beneficially Owned⁽¹⁾
Name	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
James C. Donnelly	36,445		421,304	⁽⁵⁾	457,749
Paul Donovan	24,225		632,427		656,652
Richard R. Grigg	30,250		556,154		586,404
Gale E. Klappa	40,479		—		40,479

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 (16 persons)	316,878	⁽⁴⁾	2,194,994	⁽⁵⁾	2,511,872	⁽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 WEC 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. Donnelly (1,091), 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 (107,306). 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. Donnelly (27,349), Mr. Stratton (4,600), Mr. Wardeberg (22,759) and all directors and executive officers as a group (70,710).

⁽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. Donnelly (3,302), Mr. Donovan (20,337),

Mr. Grigg (22,817), Mr. Klappa (40,308), 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 (144,300). Shares listed for Mr. Donnelly include restricted stock granted by WICOR, Inc. which were converted to outstanding WEC restricted stock on the effective date of the acquisition of WICOR, Inc.

⁽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 2.1% of total WEC common stock outstanding on January 30, 2004.

Owners of More than 5%. The following table shows stockholders who reported beneficial ownership of more than 5% of WEC common stock, based on the information they have reported.


	Voting Authority		Dispositive Authority		Total Shares Beneficially Owned	Percent of WEC Common Stock
Name and Address	Sole	Shared	Sole	Shared	Total Shares Beneficially Owned	Percent of WEC Common Stock

AXA Financial, Inc.⁽¹⁾ 1290 Avenue of the Americas New York, NY 10104	5,266,321	1,325,676	10,710,721	0	10,710,721	9.1	%

FMR Corp. ⁽²⁾ 82 Devonshire Street Boston, MA 02109	656,866	0	8,372,916	0	8,372,916	7.1	%

⁽¹⁾

AXA Financial is a parent holding company.

⁽²⁾

FMR Corp. is a parent holding company. Edward C. Johnson 3d as Chairman of FMR Corp. and Abigail P. Johnson as a director of FMR Corp., and both as members of a controlling group of FMR Corp., may be deemed to beneficially own the shares of common stock of WEC beneficially owned by FMR Corp.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

Section 16(a) of the Securities Exchange Act of 1934, as amended, requires the Company’s executive officers, directors, and persons owning more than ten percent of WEC’s common stock to file reports of ownership and changes in ownership of equity and derivative securities of WEC with the Securities and Exchange Commission and the New York Stock Exchange. Specific due dates for those reports have been established, and the Company is required to disclose in this proxy statement any failure to file by those dates during the 2003 fiscal year. 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, except that one discretionary transaction in the Company’s Employee Retirement Savings Plan by Charles Cole, Senior Vice President of Wisconsin Electric Power Company, was reported late.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Pursuant to an agreement with WEC, Fidelity Management Trust Company (“Fidelity”), a wholly owned subsidiary of FMR Corp., holds and invests the assets of the Wisconsin Energy Corporation Employee Retirement Savings Plan and the retirement plans of several of the Company’s subsidiaries (collectively, the “Plan”). Fidelity has managed the Plan’s assets since 1992. FMR Corp. became a beneficial holder of more than five percent of WEC common stock, exclusive of shares held in the Plan, in 2003. Pursuant to the terms of its agreement with Fidelity, the Company may be required to make payments to Fidelity and/or its affiliates directly; however, it is not currently required to do so. Fidelity and its affiliates are currently compensated through the customary management fees collected by Fidelity’s affiliated mutual funds in which some of the Plan’s assets are invested.

PERFORMANCE GRAPH

The performance graph below shows a comparison of the cumulative total return, assuming reinvestment of dividends, over the last five years had $100 been invested at the close of business on December 31, 1998, in each of:

•

WEC common stock,

•

the Standard & Poor’s 500 Index (“S&P” 500),

•

a Custom Peer Group Index, and

•

the Edison Electric Institute Index of Investor-Owned Utilities (“EEI Index”).

In 2003, WEC began to use the Custom Peer Group Index rather than the EEI Index for peer comparison purposes. The Company believes the Custom Peer Group Index reflects a more accurate representation of WEC’s peers. In addition, the Board’s Compensation Committee will begin using total shareholder return thresholds for the Custom Peer Group Index to determine a portion of the long-term executive compensation awards.

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.

FIVE-YEAR CUMULATIVE RETURN CHART

LOGO

Value of Investment at Year-End


	12/31/1998		12/31/1999		12/31/2000		12/31/2001		12/31/2002		12/31/2003

Wisconsin Energy Corporation	$	100	$	65	$	82	$	85	$	98	$	134
S&P 500	$	100	$	121	$	110	$	97	$	76	$	97
Custom Peer Group Index	$	100	$	79	$	119	$	114	$	109	$	132
EEI Index	$	100	$	81	$	120	$	110	$	94	$	116

AVAILABILITY OF FORM 10-K

A copy (without exhibits) of WEC’s 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 WEC common stock by writing to the Corporate Secretary, Kristine Rappé, at the Company’s principal business offices, 231 West Michigan Street, P. O. Box 2949, Milwaukee, Wisconsin 53201. In lieu of providing all stockholders with an Annual Report, the WEC consolidated financial statements and certain other information found in the Form 10-K are provided in Appendix B to this proxy statement.

The Form 10-K, along with this proxy statement and all of WEC’s other filings with the Securities and Exchange Commission, is also available in the “Investor Info” section of the Company’s website at www.WisconsinEnergy.com.

APPENDIX A

PROPOSED AMENDMENT TO WISCONSIN ENERGY CORPORATION’S BYLAWS

Sections 2.01 and 2.02 of Wisconsin Energy Corporation’s Bylaws are hereby amended, effective at the time of the Annual Meeting of Stockholders in 2005, as follows (material that would be deleted at the time of the 2005 Annual Meeting of Stockholders is struck through; material that would be added at that time is underscored):

2.01. Number. The number of directors constituting the whole Board of Directors shall be such number as shall be fixed from time to time by the affirmative vote of the whole Board but in no event shall the number be less than three. ~~Until so fixed at a different number, the number shall be nine.~~ The number of directors at any time constituting the whole Board shall not be reduced so as to shorten the term of any director then in office. Directors shall be stockholders of the corporation.

The directors shall hold office until the next annual meeting of stockholders at which their respective terms of office shall expire and until their respective successors are duly elected and qualified.

2.02. Classification. The directors shall be divided into three classes as nearly equal in number as possible, the term of one class expiring each year. Except for any director elected pursuant to Section 2.05 of these Bylaws and any director elected by the stockholders to fill a vacancy for the remainder of a three year term, whose terms of office may be less than three years, directors shall be elected for three year terms. However, at any time when there shall be a complete vacancy of the Board, the directors of Class I shall be elected to hold office until the next succeeding annual meeting of stockholders; the directors of Class II until the second succeeding annual meeting of stockholders; and the directors of Class III until the third succeeding annual meeting of stockholders, and in each foregoing case, until their respective successors are duly elected and qualified. If, at any meeting of stockholders, directors of more than one class are to be elected, whether due to a vacancy or vacancies on the Board of Directors, or otherwise, each class of directors to be elected at the meeting shall be nominated and voted for in a separate election.

2.02. Term of Office. Commencing with the 2005 annual meeting of the stockholders of the corporation, the pre-existing division of the Board of Directors into three classes shall be eliminated and all directors shall be elected at the 2005 annual meeting of stockholders and at each annual meeting of stockholders thereafter. The directors shall hold office until the next annual meeting of stockholders and until their respective successors are duly elected and qualified.

A- 1

APPENDIX B

WISCONSIN ENERGY CORPORATION

2003 ANNUAL FINANCIAL STATEMENTS

and

REVIEW of OPERATIONS

SELECTED FINANCIAL AND OPERATING DATA

WISCONSIN ENERGY CORPORATION

CONSOLIDATED SELECTED FINANCIAL AND STATISTICAL DATA


Financial	2003 (a)		2002 (b)		2001		2000 (c)		1999
Year Ended December 31
Net income (Millions)	$	244.3	$	167.0	$	219.0	$	154.2	$	209.0
Earnings per share of common stock
Basic	$	2.09	$	1.45	$	1.87	$	1.28	$	1.79
Diluted	$	2.06	$	1.44	$	1.86	$	1.27	$	1.79
Dividends per share of common stock	$	0.80	$	0.80	$	0.80	$	1.37	$	1.56
Operating revenues (Millions)
Utility energy	$	3,263.9	$	2,852.1	$	2,964.8	$	2,556.7	$	2,050.2
Non-utility energy		14.4		167.2		337.3		372.8		193.2
Manufacturing		746.1		685.2		585.1		382.2		—
Other		29.9		31.7		41.3		51.0		29.2

Total operating revenues	$	4,054.3	$	3,736.2	$	3,928.5	$	3,362.7	$	2,272.6

Manufacturing operating revenues (Millions)
Domestic	$	533.2	$	507.6	$	444.9	$	294.1		—
International		212.9		177.6		140.2		88.1		—

Total manufacturing operating revenues	$	746.1	$	685.2	$	585.1	$	382.2		—

At December 31 (Millions)
Total assets	$	10,025.7	$	9,477.6	$	9,454.2	$	9,564.7	$	7,204.5
Total debt (includes long-term debt, current maturities of long-term debt, short-term debt, and trust preferred securities)	$	4,351.4	$	4,223.9	$	4,472.0	$	4,374.2	$	2,911.2

Utility Energy Statistics
Electric
Megawatt-hours sold (Thousands)		31,183.4		30,862.6		31,062.6		32,042.4		31,257.1
Customers (End of year)		1,090,513		1,078,710		1,066,275		1,048,711		1,027,785
Gas
Therms delivered (Millions)		2,171.2		2,121.3		1,997.2		1,621.5		944.1
Customers (End of year)		998,201		982,066		966,817		952,177		398,508

Non-Utility Energy Statistics
Independent Power Production
Electric megawatt-hour sales (Thousands)		12.2		2,998.3		4,428.2		3,213.2		2,417.2
Energy Marketing, Trading & Services
Electric megawatt-hour sales (Thousands)		—		—		457.6		2,091.2		1,598.1
Gas therm sales (Millions)		—		—		100.3		187.6		—

CONSOLIDATED SELECTED QUARTERLY FINANCIAL DATA (Unaudited)


	(Millions of Dollars, Except Per Share Amounts) (d)
	March					June
Three Months Ended	2003		2002 (b)			2003		2002
Total operating revenues	$	1,229.2	$	986.0		$	914.3	$	870.9
Operating income	$	188.1	$	34.3		$	116.3	$	112.3
Net income	$	92.0	$	(4.2	)	$	49.3	$	45.4
Earnings per share of common stock
Basic	$	0.79	$	(0.04	)	$	0.42	$	0.39
Diluted	$	0.79	$	(0.04	)	$	0.42	$	0.39

	September					December
Three Months Ended	2003 (a)		2002			2003 (a)		2002
Total operating revenues	$	878.5	$	869.8		$	1,032.3	$	1,009.5
Operating income	$	95.0	$	137.0		$	151.4	$	174.4
Net income	$	30.9	$	52.1		$	72.1	$	73.7
Earnings per share of common stock
Basic	$	0.26	$	0.45		$	0.61	$	0.64
Diluted	$	0.26	$	0.45		$	0.60	$	0.63

(a)	In 2003, Wisconsin Energy recorded non-cash charges of $45.6 million related primarily to non-utility investments which were held for sale (see Note D of the Notes to Consolidated Financial Statements for more detail).

(b)	In the first quarter of 2002, Wisconsin Energy recorded a non-cash charge of $141.5 million related primarily to non-utility investments which were held for sale (see Note D of the Notes to Consolidated Financial Statements for more detail).

(c)	Includes WICOR, Inc. and its subsidiaries subsequent to their acquisition on April 26, 2000.

(d)	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.

B-2

WISCONSIN ENERGY CORPORATION

CONSOLIDATED SELECTED UTILITY OPERATING DATA


Year Ended December 31	2003		2002			2001		2000 (a)		1999

Electric Utility
Operating Revenues (Millions)
Residential	$	715.5	$	703.0		$	654.5	$	606.7	$	584.3
Small Commercial/Industrial		642.0		606.3			592.9		550.0		524.9
Large Commercial/Industrial		519.3		483.1			479.7		472.8		459.4
Other - Retail/Municipal		84.9		77.7			70.6		64.7		56.7
Resale - Utilities		24.0		18.1			56.8		79.1		74.7
Other Operating Revenues		27.9		22.6			12.9		24.5		22.1

Total Operating Revenues	$	2,013.6	$	1,910.8		$	1,867.4	$	1,797.8	$	1,722.1

Megawatt-hour Sales (Thousands)
Residential		8,099.3		8,310.9			7,773.4		7,633.2		7,503.1
Small Commercial/Industrial		8,740.6		8,719.5			8,595.4		8,524.7		8,257.7
Large Commercial/Industrial		11,401.8		11,129.6			11,177.6		11,824.0		11,542.8
Other - Retail/Municipal		2,225.9		2,051.9			1,828.6		1,755.8		1,531.4
Resale - Utilities		715.8		650.7			1,687.6		2,304.7		2,422.1

Total Sales		31,183.4		30,862.6			31,062.6		32,042.4		31,257.1

Number of Customers (Average)
Residential		973,575		963,988			950,271		934,494		915,713
Small Commercial/Industrial		106,469		105,551			103,908		101,665		99,209
Large Commercial/Industrial		707		709			710		716		720
Other		2,392		2,389			2,363		2,327		1,978

Total Customers		1,083,143		1,072,637			1,057,252		1,039,202		1,017,620


Gas Utility
Operating Revenues (Millions)
Residential	$	769.3	$	591.0		$	645.9	$	450.2	$	193.8
Commercial/Industrial		386.0		279.7			313.4		225.2		95.1
Interruptible		16.9		12.6			17.0		13.7		5.3

Total Retail Gas Sales		1,172.2		883.3			976.3		689.1		294.2
Transported Gas		36.6		39.4			37.9		32.8		16.4
Other Operating Revenues		17.3		(4.6	)		60.3		14.4		(3.8	)

Total Operating Revenues	$	1,226.1	$	918.1		$	1,074.5	$	736.3	$	306.8

Therms Delivered (Millions)
Residential		853.7		817.1			756.3		569.0		329.0
Commercial/Industrial		492.5		463.1			427.7		336.5		195.3
Interruptible		27.5		29.4			25.8		24.9		16.3

Total Retail Gas Sales		1,373.7		1,309.6			1,209.8		930.4		540.6
Transported Gas		797.5		811.7			787.4		691.1		403.5

Total Therms Delivered		2,171.2		2,121.3			1,997.2		1,621.5		944.1

Number of Customers (Average)
Residential		901,322		888,626			875,339		697,570		360,084
Commercial/Industrial		83,915		82,973			79,503		62,626		32,594
Interruptible		67		79			82		72		89
Transported Gas		1,440		1,508			4,468		3,253		334

Total Customers		986,744		973,186			959,392		763,521		393,101


Degree Days (b)
Heating (6,721 Normal)		7,063		6,551			6,338		6,716		6,318
Cooling (728 Normal)		606		897			711		566		753

(a)	Includes Wisconsin Gas subsequent to the acquisition of WICOR, Inc. on April 26, 2000. Average gas customers are weighted for the eight months when Wisconsin Gas was a part of Wisconsin Energy.

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

B-3

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

INTRODUCTION

Wisconsin Energy Corporation is a diversified holding company with subsidiaries primarily in a utility energy segment, a non-utility energy segment and a manufacturing segment. Unless qualified by their context, when used in this document the terms Wisconsin Energy, the Company, Our, Us or We refer to the holding company and all of our subsidiaries.

Our utility energy segment, consisting of Wisconsin Electric Power Company (Wisconsin Electric) and Wisconsin Gas Company (Wisconsin Gas), both doing business under the trade name of “We Energies”, and Edison Sault Electric Company (Edison Sault), is engaged primarily in the business of generating electricity and distributing electricity and natural gas in Wisconsin and the Upper Peninsula of Michigan. Our non-utility energy segment primarily consists of W.E. Power, LLC (We Power) and Wisvest Corporation (Wisvest). We Power is principally engaged in the engineering, construction and development of electric power generating facilities for long term lease to Wisconsin Electric and other utilities. Our manufacturing segment, which we have agreed to sell, consists of companies which manufacture pumps as well as fluid processing and water filtration equipment.

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

We seek to increase shareholder value by leveraging on the core competencies within our business segments. Our key corporate strategy is Power 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 we are committed to improved environmental performance. Our Power the Future strategy, which is discussed further below, is expected to have a significant impact on our utility and non-utility energy segments.

Utility Energy Segment: We are realizing operating efficiencies in this segment through the integration of the operations of Wisconsin Electric and Wisconsin Gas. These operating efficiencies should increase customer satisfaction and reduce operating costs. In connection with our Power the Future strategy, we plan to improve the existing energy distribution systems and upgrade existing electric generating assets.

Manufacturing Segment: In February 2004, we announced that we had reached an agreement to sell this segment to Pentair, Inc., for $850 million and the assumption of approximately $25 million of debt. We expect to realize a gain on the sale of approximately $0.15 - $0.20 per share, after taxes, debt redemption costs and transaction costs. We expect the sale to close during the second or third quarter of 2004 subject to regulatory approvals. For further information about the sale see “Capital Resources”.

B-4

Non-Utility Energy Segment: We will primarily focus this segment on improving the supply of electric generation in Wisconsin. We Power has been formed to design, construct, own, finance and lease new generation assets and make improvements in Wisconsin Electric’s existing generation assets under the Power the Future strategy. The majority of Wisvest’s assets have been divested in order to direct the capital and management attention to Power the Future.

Power the Future Strategy: In February 2001, we 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. Our Power 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 generating capacity to the state’s power portfolio and will allow Wisconsin Electric to maintain approximately the same fuel mix as exists today. As part of our Power the Future strategy, we plan to: (1) invest approximately $2.5 billion in 2,120 megawatts of new natural gas-based and coal-based generating capacity at existing sites; (2) upgrade Wisconsin Electric’s existing electric generating facilities and (3) invest in upgrades of our existing energy distribution system.

As of December 31, 2003, we have:

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 in July 2005 and the second unit in 2008 subject to resolution of legal challenges;

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

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, we created We Power to design, construct, own, finance and lease the new generating capacity. Under our Power the Future strategy Wisconsin Electric 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, Wisconsin Electric 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 Wisconsin Electric as a result of the additional electric generating capacity included in the proposal. Wisconsin Electric expects that all lease payments and operating costs of the plants will be recoverable in rates.

In February 2001, we made preliminary filings for our Power the Future proposal with the PSCW. Subsequently, the state legislature amended several laws, making changes which are critical to the implementation of Power the Future. On October 16, 2001, the PSCW issued a declaratory ruling finding, among other things, that it was prudent to proceed with Power 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 our Power 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”.

We anticipate obtaining the capital necessary to finance and execute Power the Future from a combination of internal and external sources. For further information concerning the Power the Future strategy, see “Liquidity and Capital Resources” as well as “Factors Affecting Results, Liquidity and Capital Resources” below.

B-5

Divestiture of Non-Core Assets

The Power the Future strategy led to a decision to divest non-core businesses. These non-core businesses primarily included non-utility generation assets located outside of the Midwest and a substantial amount of Wispark’s real estate portfolio. Since 2000, we have received total proceeds of approximately $1.1 billion from the divestiture of non-core assets as follows:


Proceeds from:	(Millions of Dollars)
Non-Utility Energy	$	579.3
Transmission		119.8
Real Estate		349.0
Other		20.6

Total Assets Divested	$	1,068.7

In February 2004, we announced that we had reached an agreement to sell our manufacturing segment. The sale, which is expected to close in the second or third quarter of 2004, is expected to result in net proceeds of approximately $740 million after taxes and transaction costs. For further information about the sale, see “Capital Resources” below.

RESULTS OF OPERATIONS

CONSOLIDATED EARNINGS

The following table compares our operating income by business segment for 2003, 2002 and 2001.


Wisconsin Energy Corporation	2003			2002			2001
	(Millions of Dollars)
Utility Energy	$	544.1		$	562.1		$	534.9
Manufacturing		66.9			56.2			41.1
Non-Utility Energy		(61.5	)		(132.0	)		36.2
Corporate and Other		1.3			(28.3	)		(7.3	)

Operating Income		550.8			458.0			604.9
Other Income, net		43.5			43.9			0.6
Financing Costs		214.9			229.2			246.6

Income Before Income Taxes		379.4			272.7			358.9
Income Taxes		135.1			105.7			150.4
Cumulative Effect of Change in Accounting Principle, Net of Tax		—			—			10.5

Net Income	$	244.3		$	167.0		$	219.0

2003 vs 2002: We had net income of $244.3 million during 2003 compared with net income of $167.0 million during 2002. Utility energy operating income decreased when compared with the prior year primarily due to cooler weather during the summer of 2003 as compared to 2002, higher fuel and purchased power costs, and increases in benefit costs, nuclear costs and costs associated with our Power the Future growth strategy. These items were partially offset by higher gas margins, growth in our base electric business and insurance recoveries in 2003 compared to associated settlement costs in 2002, both primarily related to the Giddings & Lewis/City of West Allis litigation. Our manufacturing segment contributed operating income of $66.9 million during 2003 compared with $56.2 million during 2002 reflecting strong water systems retail sales, costs in 2002 for plant closings and restructuring and cost reduction efforts. The decrease in the operating loss for our non-utility energy segment primarily relates to less asset valuation charges recorded in 2003 as compared to 2002. Corporate and other affiliates operating income increased $29.6 million in 2003 compared to 2002 primarily due to a non-cash asset valuation charge recorded in 2002, a gain from the liquidation of an investment in 2003, and improved operating results in 2003. In addition, net income increased in 2003 due to lower financing costs compared with 2002.

B-6

2002 vs 2001: Our net income was $167.0 million during 2002 compared with net income of $219.0 million during 2001. Operating income for our utility energy segment increased by $27.2 million in 2002 compared to 2001. The increase was primarily attributable to improved electric and gas margins and the adoption of SFAS 142 in 2002, which eliminated the amortization of goodwill, offset in part by litigation settlements and additional expenses related to nuclear operations. Manufacturing operating income was up $15.1 million primarily due to acquisitions, cost savings achieved through consolidation of operations, the continuation of cost improvement programs, and the adoption of SFAS 142, offset by one-time costs associated with consolidation of facilities in the first quarter of 2002. The decrease in operating income for our non-utility energy segment is due to a non-cash asset valuation charge recorded in 2002 and a decline in wholesale market prices partially offset by SFAS 133 gains. Corporate and other affiliates operating income decreased $21.0 million in 2002 compared to 2001 primarily due to an asset valuation charge offset in part by gains on asset sales and elimination of goodwill amortization. In addition, the decline in net income was offset in part due to higher other income, a reduction in financing costs and a lower effective income tax rate in 2002 compared with 2001.

An analysis of contributions to operating income by segment follows.

UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

2003 vs 2002: Utility energy segment operating income during 2003 decreased by $18.0 million to $544.1 million compared to 2002 operating income. The decline in utility operating income is primarily due to cooler summer weather, higher fuel and purchased power costs, increases in pension, medical and other benefit costs, higher nuclear costs and costs associated with our Power the Future growth strategy. This decline was somewhat mitigated by a March 2003 rate increase associated with fuel and purchased power expenses, higher gas margins, growth in our base electric business and litigation settlements in 2002 compared with the receipt of insurance recoveries in 2003 primarily related to the Giddings & Lewis/City of West Allis litigation.

2002 vs 2001: Operating income for our utility energy segment increased by $27.2 million or 5.1% in 2002 compared to 2001. The increase is primarily attributable to improved electric and gas margins and adoption of SFAS 142 which eliminated amortization of goodwill. Offsetting these items were 2002 litigation settlements related to the Giddings & Lewis/City of West Allis litigation and additional expenses related to nuclear operations.

The following table summarizes our utility energy segment’s operating income during 2003 and 2002 with similar information for 2001.


Utility Energy Segment	2003		2002		2001
	(Millions of Dollars)
Operating Revenues
Electric	$	2,013.6	$	1,910.8	$	1,867.4
Gas		1,226.1		918.1		1,074.5
Other		24.2		23.2		22.9

Total Operating Revenues		3,263.9		2,852.1		2,964.8
Fuel and Purchased Power		569.5		496.7		517.3
Cost of Gas Sold		863.3		574.9		751.6

Gross Margin		1,831.1		1,780.5		1,695.9
Other Operating Expenses
Other Operation and Maintenance		891.0		830.2		765.5
Depreciation, Decommissioning and Amortization		316.2		308.3		320.1
Property and Revenue Taxes		79.8		79.9		75.4

Operating Income	$	544.1	$	562.1	$	534.9

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Electric Utility Revenues, Gross Margins and Sales

The following table compares our electric utility operating revenues and its gross margin during 2003 with similar information for 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	$	715.5	$	703.0	$	654.5	8,099.3	8,310.9	7,773.4
Small Commercial/Industrial		642.0		606.3		592.9	8,740.6	8,719.5	8,595.4
Large Commercial/Industrial		519.3		483.1		479.7	11,401.8	11,129.6	11,177.6
Other-Retail/Municipal		84.9		77.7		70.6	2,225.9	2,051.9	1,828.6
Resale-Utilities		24.0		18.1		56.8	715.8	650.7	1,687.6
Other Operating Revenues		27.9		22.6		12.9	—	—	—

Total Operating Revenues		2,013.6		1,910.8		1,867.4	31,183.4	30,862.6	31,062.6

Fuel and Purchased Power
Fuel		298.5		278.9		308.8
Purchased Power		264.3		211.1		202.3

Total Fuel and Purchased Power		562.8		490.0		511.1

Gross Margin	$	1,450.8	$	1,420.8	$	1,356.3

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 $102.8 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, Wisconsin Electric 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 1.0% during 2003. Residential sales fell 2.5% 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 Wisconsin Electric’s 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. 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 0.4% between the comparative periods. Sales to municipal utilities, the other retail/municipal customer class, increased 8.5% 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 14% 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 increase was caused by the flood that temporarily shut down our Presque Isle Power Plant during the second quarter of 2003.

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Electric gross margin increased 2.1% to $1,450.8 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 American Transmission Company LLC (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 $9.4 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 $43.4 million or 2.3% 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, Wisconsin Electric 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 0.6% 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 Wisconsin Electric’s 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 commercial/industrial electric sales increased by 0.8% 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 $21.1 million or 4.1% 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 $64.5 million or 4.8% during 2002 compared with the same period in 2001.

Our electric gross margin was $1,420.8 million or 4.8% 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 gas cost recovery mechanisms. The following table compares our gas utility operating revenues and gross margins (total gas utility operating revenues less cost of gas sold) during 2003 and 2002 with similar information for 2001.


Gas Utility Operations	2003		2002		2001
	(Millions of Dollars)
Gas Operating Revenues	$	1,226.1	$	918.1	$	1,074.5
Cost of Gas Sold		863.3		574.9		751.6

Gross Margin	$	362.8	$	343.2	$	322.9

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2003 vs 2002: During 2003 gas operating revenues increased by $308.0 million or 33.5%. This increase in revenues is due primarily to a $288.4 million increase in the delivered cost of natural gas, recognition of $7.4 million of increased gas cost incentive revenues under our gas cost recovery mechanisms 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 gas cost recovery mechanisms.

2002 vs 2001: During 2002, total gas utility operating revenues decreased by $156.4 million or 14.6% 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 gas cost recovery mechanisms.

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	$	233.0	$	224.6	$	209.0	853.7	817.1	756.3
Commercial/Industrial		71.0		67.4		62.3	492.5	463.1	427.7
Interruptible		2.0		2.1		2.0	27.5	29.4	25.8

Total Gas Sold		306.0		294.1		273.3	1,373.7	1,309.6	1,209.8
Transported Gas		41.8		41.9		41.4	797.5	811.7	787.4
Other Operating		15.0		7.2		8.2	—	—	—

Total	$	362.8	$	343.2	$	322.9	2,171.2	2,121.3	1,997.2

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 $362.8 million in 2003, or a $19.6 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 $7.4 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 increased by 2.4% during 2003 but varied within customer classes. Volume deliveries for the residential and commercial/industrial customer classes increased by 4.5% and 6.3%, respectively, reflecting colder weather.

2002 vs 2001: Gas gross margin for 2002 totaled $343.2 million, or an increase of $20.3 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 $60.8 million or 7.3% 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 $30 million during 2003. Overall, nuclear costs were $8.7 million higher during 2003 compared with 2002 due to an extended outage and costs associated with the U.S. Nuclear Regulatory Commission (NRC) supplemental inspections at Point Beach. Insurance recoveries of approximately $11.1 million in 2003 compared to associated

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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 our Power the Future strategy.

2002 vs 2001: Other operation and maintenance expenses increased by $64.7 million or 8.5% 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 $17.4 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.

Depreciation, Decommissioning and Amortization Expenses

2003 vs 2002: Depreciation, Decommissioning and Amortization expenses increased by $7.9 million or 2.6% during 2003 primarily due to a higher base of depreciable assets between the comparative periods.

2002 vs 2001: Depreciation, decommissioning and amortization expenses decreased by $11.8 million during 2002 compared with 2001. This decrease was primarily due to the impact of the retirement of several shorter-lived intangible assets and the adoption on January 1, 2002 of Statement of Financial Accounting Standard (SFAS) 142 which eliminated the amortization of goodwill.

MANUFACTURING SEGMENT CONTRIBUTION TO OPERATING INCOME

During 2003, our manufacturing segment contributed $66.9 million to operating income, which was $10.7 million higher than the prior year amount. Our manufacturing segment contributed $56.2 million to operating income during 2002 compared to $41.1 million during 2001. The following table summarizes our manufacturing segment’s operating income during 2003, 2002 and 2001.


Manufacturing Segment	2003		2002		2001
	(Millions of Dollars)
Operating Revenues
Domestic	$	533.2	$	507.6	$	444.9
International		212.9		177.6		140.2

Total Operating Revenues		746.1		685.2		585.1
Cost of Goods Sold		557.6		513.2		428.0

Gross Margin		188.5		172.0		157.1
Other Operating Expenses		121.6		115.8		116.0

Operating Income	$	66.9	$	56.2	$	41.1

2003 vs 2002: Manufacturing operating revenues for 2003 were $746.1 million, an increase of $60.9 million or 8.9% compared to the same period in 2002. Acquisitions completed in 2002 contributed $10.8 million of sales during 2003. We achieved a 7.3% base business growth level between the comparative periods. During 2003, international sales were 19.9% above the same period in 2002, with approximately half due to international base business growth, mainly in Italy and Mexico, and half relating to currency translation effects. Overall for 2003, sales in all markets of our manufacturing business were up with the exception of the beverage/food, filtration and foam pro markets. The largest growth was seen in the water systems market, which increased 17.0%, due to Hurricane Isabel and wet conditions in the northeastern and midwest sections of the United States coupled with the impact of a 2002 second quarter acquisition, market share growth and the impact from currency translation. The pool/spa, agriculture and industrial markets also experienced growth over the prior year sales levels. Our

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manufacturing gross profit margin increased to $188.5 million for 2003 from $172.0 million in 2002, flat year over year as a percentage of sales. For 2003, operating expenses as a percentage of sales decreased to 16.3% from 16.9% for 2002. During 2002, our manufacturing segment recorded charges related to relocation and closing/severance payments, which did not recur in 2003. Excluding these charges, operating expenses as a percentage of sales were flat year over year.

2002 vs 2001: Manufacturing operating revenues increased by $100.1 million or 17.1% between 2002 and 2001. Acquisitions contributed incremental sales of $56.8 million in 2002. Excluding the impact of acquisitions, we experienced an 8.0% growth in our manufacturing business. Sales in almost all markets were up with the largest increases in water systems, pool/spa, R/V, and beverage and food markets. Domestic sales were up $62.7 million, and international sales increased $37.4 million for the twelve months ended December 31, 2002, or 14.1% and 26.7%, respectively, compared to the same period in 2001. The increases were due to acquisitions in 2002 and 2001, market share/customer growth, drought conditions in the United States and Australia, and new product introductions. Gross profit margin decreased to 25.1% in 2002 from 26.9% in 2001 due primarily to changes in the customer/product mix as a result of acquisitions and increased customer rebates due to sales growth. Operating income was up 36.7% primarily due to acquisitions, cost savings achieved through consolidation of operations, the continuation of cost improvement programs, and the adoption of SFAS 142 which eliminated the amortization of goodwill and certain intangible assets, offset by one-time costs associated with consolidation of facilities in the first quarter of 2002.

NON-UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

As part of our ongoing efforts to divest non-core assets, we have significantly reduced Wisvest’s operations over the past three years. The following table compares our non-utility energy segment’s operating income (loss) during 2003, 2002 and 2001.


Non-Utility Energy Segment	2003			2002			2001
	(Millions of Dollars)
Operating Revenues	$	14.4		$	167.2		$	337.3
Fuel and Purchased Power		1.3			97.3			142.8
Cost of Gas Sold		—			—			72.3
Cost of Goods Sold		—			—			6.7

Gross Margin		13.1			69.9			115.5
Other Operating Expenses
Other Operation and Maintenance		16.6			64.9			70.4
Depreciation, Decommissioning and Amortization		7.4			5.1			1.7
Property and Revenue Taxes		1.6			6.8			7.2
Asset Valuation Charges, Net		49.0			125.1			—

Operating Income (Loss)	$	(61.5	)	$	(132.0	)	$	36.2

2003 vs 2002: The significant decline in operating revenues, fuel and purchased power and other operation and maintenance is directly related to our sale of Wisvest-Connecticut in December 2002, which had operating earnings of $16.8 million and $38.4 million in 2002 and 2001, respectively.

The operating loss incurred in 2003 included total asset valuation charges of $59.5 million offset in part by gains on the sale of assets of $10.5 million. In 2002 we recorded a non-cash asset valuation charge of which $125.1 million ($81.3 million after-tax) related to the non-utility energy segment. (See further discussion below and in “Note D — Asset Sales and Divestitures” in the Notes to Consolidated Financial Statements of this report). The asset valuation charges recorded in 2003 relate to our investment in an entity that owns a co-generation power plant in Maine (Androscoggin) and costs associated with a 500 megawatt natural gas power island. We determined in the third quarter of 2003 based on information obtained from our efforts to market the power island, that the carrying value of these assets exceeded market values, and the power island was sold at the reduced carrying value in the fourth quarter of 2003. During our 2003 fourth quarter review of updated cash flow projections for our investment in Androscoggin, management determined a loss in the value of our investment had occurred. We wrote down our investment to its estimated fair value. These charges were offset in part by the sale of our interests in Kaztex Energy Management, Inc. and Blackhawk Energy Services, LLC in which we realized gains of approximately $10.5 million during the fourth quarter of 2003.

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2002 vs 2001: Our decrease in non-utility energy operating income between 2002 and 2001 can be broken down between operation of the assets and a 2002 asset valuation charge. During 2002, Wisvest-Connecticut had operating income of $16.8 million compared to operating income of $38.4 million in 2001. This decline is directly related to lower wholesale market prices for electricity in the northeast United States and an extended unscheduled outage at one of its major generating units from the last half of August through November 2002. In addition, on December 6, 2002, Wisvest completed the sale of Wisvest-Connecticut to Public Service Enterprise Group. We Power operations had an operating loss in 2002 primarily related to increased start-up costs as it continued to develop power plants for our Power the Future initiative. Wisvest’s Calumet natural gas-based peaking power plant in Chicago, which was placed in service in June of 2002, and the equity method investment in Androscoggin also recorded operating losses during 2002. The Calumet plant experienced start-up costs and limited power production due to lower wholesale market prices for electricity in the Midwest during the last six months of 2002. The Androscoggin plant was also negatively impacted by lower than expected wholesale electric prices.

During the first quarter of 2002, we recorded a non-cash asset valuation charge of $125.1 million primarily related to two non-utility energy assets classified as “Assets Held for Sale” as of December 31, 2001: the Wisvest-Connecticut power plants and costs associated with a 500 megawatt natural gas power island. For more information on the asset valuation charge, see “Note D — Asset Sales and Divestitures” in the Notes to Consolidated Financial Statements of this report.

CORPORATE AND OTHER CONTRIBUTION TO OPERATING INCOME

The following table identifies the components of operating income (loss) of our corporate and other affiliates between 2003, 2002 and 2001.


Corporate and Other Affiliates	2003			2002			2001
	(Millions of Dollars)
Operating Revenues	$	29.9		$	31.7		$	41.3
Other Operating Expenses
Other Operation and Maintenance		24.9			37.3			39.3
Depreciation, Decommissioning and Amortization		6.1			5.2			7.3
Property and Revenue Taxes		1.0			1.1			2.0
Asset (Gain)/Valuation Charge		(3.4	)		16.4			—

Operating Income (Loss)	$	1.3		$	(28.3	)	$	(7.3	)

2003 vs 2002: Our corporate and other affiliates recorded operating income of $1.3 million in 2003 compared to an operating loss of $28.3 million in 2002. This is primarily due to a non-cash asset valuation charge recorded in 2002 of $16.4 million ($10.7 million after-tax) related to the decline in value of a venture capital investment (see further discussion in “Note D — Asset Sales and Divestitures” in the Notes to Consolidated Condensed Financial Statements in this report), and a $2.7 million gain from the sale of investment assets in the third quarter of 2003.

2002 vs 2001: Our operating loss for corporate and other affiliates for 2002 was $21.0 million higher compared to 2001. This increase is primarily related to a non-cash asset valuation charge recorded in 2002 of which $16.4 million related to the decline in value of a venture capital investment.

CONSOLIDATED OTHER INCOME AND DEDUCTIONS

2003 vs 2002: Net consolidated other income and deductions decreased by $0.4 million in 2003 compared to 2002. This decrease is primarily due to $21.1 million ($12.7 million after tax) in SFAS 133 gains recognized in 2002 on fuel oil contracts at Wisvest-Connecticut’s two power plants, which were sold in December 2002, 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), and higher returns associated with investments in rabbi trusts. Also in 2002, we recorded $5.3 million of costs associated with bond redemptions and losses on asset sales of $3.6 million.

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2002 vs 2001: Other income and deductions increased by $43.3 million in 2002 compared to 2001. This increase is primarily due to $12.6 million in SFAS 133 gains for 2002 compared with charges of $12.7 million in 2001. Under SFAS 133, Wisvest-Connecticut recorded the changes in fair market value related to fuel oil contracts associated with its plants in the northeast United States. During 2002, we recorded an after-tax gain of $12.6 million on these contracts due to settlement of contract transactions and increases in fuel oil prices. During 2001, we recorded an after-tax gain of $10.5 million related to the cumulative effect of a change in accounting principle upon the adoption of SFAS 133 offset by after-tax charges of $23.1 million related to settlement of contract transactions and decreases in fuel oil prices. In addition, the 2002 increase included $22.9 million due to a reduction in the level of write-downs in the Witech Corporation venture capital portfolio offset in part by a decline in interest income during 2002 of $12.4 million primarily due to an interest accrual recorded in 2001 related to litigation. In addition, during the second quarter of 2001, we sold FieldTech, Inc. and Wisvest’s interest in Blythe Energy, LLC, an independent power production project in the state of California, in separate transactions. We realized after-tax gains of approximately $16.5 million or $0.14 per share as a result of the sales of FieldTech and Blythe.

CONSOLIDATED FINANCING COSTS

Total financing costs decreased by $14.3 million in 2003 compared to 2002. This decline was primarily due to a combination of reduced average debt levels, increased capitalized interest and lower interest rates. Total financing costs decreased by $17.4 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.

CONSOLIDATED INCOME TAXES

Our consolidated effective income tax rate was 35.6%, 38.8%, and 41.9% for each of the three years ended December 31, 2003, 2002, and 2001, respectively. The reduction in the 2003 effective income tax rate reflects recognition of $3.0 million of state net operating loss carryforwards, tax credits associated with rehabilitation projects and a lower state effective income tax rate due to an improving outlook by subsidiaries with the ability to utilize state losses. The lower rate in 2002 reflects the elimination of goodwill amortization and the recognition of historical rehabilitation tax credits. The 2001 effective income tax rate reflects the amortization of the WICOR goodwill, which is not deductible for income tax purposes. The effective income tax rate is negatively impacted by the inability to obtain a state tax benefit for state taxable losses of some of the separate legal entities within the Company. Those state taxable losses result primarily from interest expense. If the prospects for future taxable income for these legal entities should improve, the effective tax rate in years subsequent to 2003 may be favorably impacted.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

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


Wisconsin Energy Corporation	2003			2002			2001
	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$	623.9		$	711.3		$	570.6
Investing Activities	$	(667.2	)	$	(365.8	)	$	(479.1	)
Financing Activities	$	53.2		$	(348.9	)	$	(85.0	)

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Operating Activities

Cash provided by operating activities decreased to $623.9 million during 2003 compared with $711.3 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 and an increase in the use of working capital in 2003.

During 2002, cash flow from operations increased to $711.3 million, or a $140.7 million improvement over 2001. This increase was primarily attributable to the return of a $100 million deposit plus accrued interest as a result of a favorable court ruling discussed above.

Investing Activities

During 2003, we had capital expenditures totaling $659.4 million, an increase of $102.6 million over the prior year. (see table below for further information). This increase is primarily related to the increased expenditures at We Power associated with the new natural gas power plant.


Capital Expenditures	2003		2002		2001
	(Millions of Dollars)
Regulated Energy	$	455.6	$	405.4	$	428.7
We Power		162.9		52.9		—
Other Non-Utility Energy		0.7		39.8		127.7
Manufacturing		10.4		15.0		27.1
Other		29.8		43.7		89.0

Total Capital Expenditures	$	659.4	$	556.8	$	672.5

During 2003, we received net cash proceeds from asset sales of approximately $56 million from the sales of our investment in two energy marketing companies, the sale of gas turbines held by Wisvest and from real estate sales. In addition to these proceeds, we received approximately $15 million in dividends from companies that were sold and we expect to receive approximately $32 million in tax benefits from the sale of the Power Island.

During 2002 and 2001, we received proceeds from asset divestitures of $310.0 million and $294.4 million, respectively, related to the sale of the Wisvest-Connecticut power plants, real estate sales and other small miscellaneous sales in 2002, and the transfer in 2001 of electric transmission assets to ATC, and the successful sale in 2001 of the Wisvest Blythe project, FieldTech, and various real estate sales.

Financing Activities

During 2003, we provided $53.2 million from financing activities compared with using $348.9 million for financing activities during 2002. We reduced short-term debt by $343.2 million and retired $546.7 million of long-term debt during 2003.

In March 2003, we sold $200 million of unsecured 6.20% Senior Notes due April 1, 2033. These securities were issued under an existing shelf registration statement filed with the SEC. The proceeds of the offering were used to repay a portion of our outstanding commercial paper as it matured.

In May 2003, Wisconsin Electric 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. Wisconsin Electric 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 Wisconsin Electric’s debt securities in June 2003 and 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 revenue neutral method of accounting pursuant to PSCW authorization, whereby 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, Wisconsin Electric redeemed $9 million of 6.85% First Mortgage Bonds.

B-15

In December 2003, Wisconsin Gas sold $125 million of unsecured 5.20% Debentures due 2015. These securities were issued under an existing $200 million shelf registration statement filed with the SEC. The proceeds from the Debentures were used to repay short-term debt.

In September 2000, we initiated a share repurchase program. Since the inception of the program, we have repurchased and retired 13.4 million shares through December 31, 2003 at a cost of $293.6 million. In December 2002 the Board of Directors extended the program through December 31, 2004. As part of this program we expect to repurchase up to $50 million of our common stock in the open market with proceeds from the sale of our manufacturing segment.

During 2003, 2002 and 2001 we issued a total of approximately 2.7 million new shares of common stock in each of the three years in connection with our dividend reinvestment plan and other benefit plans and received payments aggregating $62.9 million, $52.6 million and $51.6 million, respectively. In February 2004, we instructed the plan agents to begin purchasing shares of Wisconsin Energy common stock for our stock plans in the open market in lieu of issuing new shares, and based upon market conditions and other factors the plan agents will continue to do so.

During 2001, we refinanced approximately $1.3 billion of commercial paper through the issuance of intermediate-term senior notes. In January 2002, Wisconsin Electric redeemed $100 million of 8³/8% long-term debt and $3.4 million of 9¹/8% long-term debt. In December 2002, Wisconsin Electric retired $150 million of 6⁵/8% debentures at maturity. These redemptions and retirements were financed with short-term commercial paper. In 2002, following the sale of Wisvest-Connecticut $180.5 million of nonrecourse variable rate notes were paid down.

CAPITAL RESOURCES AND REQUIREMENTS

As we continue to implement our strategy of leveraging on the core competencies of our business segments and building financial strength, we expect to continue to divest of non-core assets, invest in core assets and pay down debt.

Capital Resources

We anticipate meeting our capital requirements during 2004 primarily through internally generated funds, short-term borrowings, existing lines of credit and the sale of assets, 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 and construction financing.

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.

On February 4, 2004, we announced that we had reached an agreement to sell our manufacturing business to Pentair, Inc. for $850 million in cash. In addition, Pentair, Inc. will also assume approximately $25 million of third party debt. This sale is subject to customary regulatory approvals and is expected to close in the second or third quarter of 2004. When the sale is completed, we expect to realize net cash proceeds of approximately $740 million after the payment of taxes and transaction costs. We expect to use the cash proceeds to pay down long and short-term debt. In addition, we expect to repurchase up to $50 million of our common stock in the open market.

Wisconsin Electric has $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 its 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. Wisconsin Energy and Wisconsin Electric credit agreements provide liquidity support of Wisconsin Electric’s obligations with respect to variable rate tax-exempt bonds and commercial paper.

B-16

As of December 31, 2003, we had approximately $1.2 billion of available unused lines of bank back-up credit facilities on a consolidated basis. We had approximately $610 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:


Company	Total Facility		Drawn		Credit Available		Facility Maturity	Facility Term
	(Millions of Dollars)
Wisconsin Energy	$	300.0	$	—	$	300.0	Apr-2004	364 day
Wisconsin Energy	$	300.0	$	—	$	300.0	Apr-2006	3 year
Wisconsin Electric	$	250.0	$	—	$	250.0	Jun-2004	364 day
Wisconsin Electric	$	100.0	$	—	$	100.0	Aug-2004	9 month
Wisconsin Gas	$	200.0	$	—	$	200.0	Jun-2004	364 day

On April 8, 2003, we entered into an unsecured 364 day $300 million bank back-up credit facility to replace a $300 million credit facility that was expiring. The credit facility may be extended for an additional 364 days, subject to lender agreement. On April 8, 2003, we also entered into an unsecured three year $300 million bank back-up credit facility to replace a $500 million credit facility that was expiring. This facility will expire in April 2006.

On June 25, 2003, Wisconsin Electric 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, Wisconsin Electric entered into an unsecured 9 month $100 million bank back-up credit facility.

On June 25, 2003, Wisconsin Gas entered into an unsecured 364 day $200 million bank back-up credit facility to replace a $185 million credit facility that was scheduled to expire on December 10, 2003. The credit facility may be extended for an additional 364 days, subject to lender agreement.

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


Capitalization Structure	2003				2002
	(Millions of Dollars)
Common Equity	$	2,358.6	35.0	%	$	2,139.4	33.5	%
Preferred Stock of Subsidiaries		30.4	0.5	%		30.4	0.5	%
Trust Preferred Securities		—	—	%		200.0	3.1	%
Long-Term Debt (including current maturities)		3,741.5	55.5	%		3,070.8	48.0	%
Short-Term Debt		609.9	9.0	%		953.1	14.9	%

Total	$	6,740.4	100.0	%	$	6,393.7	100.0	%

Effective with the adoption of SFAS 150 on July 1, 2003, we began reclassifying our Trust Preferred Securities as long-term debt. Upon adoption of Interpretation 46 on December 31, 2003, we began deconsolidating WEC Capital Trust I, the issuer of our Trust Preferred Securities, and therefore at December 31, 2003 our debt included $206.2 million payable to the trust that issued the Trust Preferred Securities. Our debt, including Trust Preferred Securities, to total capital as of December 31, 2003 was 64.5% as compared to 66.0% as of December 31, 2002. For further information, see “Note B — Recent Accounting Pronouncements” in the Notes to Consolidated Financial Statements in this report.

B-17

Our Trust Preferred Securities are redeemable after March 25, 2004. In February we called all of the $200.0 million of Trust Preferred Securities in 2004. “See Note J — Trust Preferred Securities” in the Notes to Consolidated Financial Statements in this report.

As described in “Note A — Summary of Significant Accounting Policies” in the Notes to Consolidated Financial Statements, certain restrictions exist on the ability of our subsidiaries to transfer funds to us. We do not expect these restrictions to have any material effect on our operations or ability to meet our cash obligations.

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


	S&P	Moody’s	Fitch
Wisconsin Energy
Commercial Paper	A-2	P-2	F2
Unsecured Senior Debt	BBB+	A3	A-

Wisconsin Electric
Commercial Paper	A-2	P-1	F1
Secured Senior Debt	A-	Aa3	AA-
Unsecured Debt	A-	A1	A+
Preferred Stock	BBB	A3	A

Wisconsin Gas
Commercial Paper	A-2	P-1	F1
Unsecured Senior Debt	A-	A1	A+

Wisconsin Energy Capital Corporation
Unsecured Debt	BBB+	A3	A-

WEC Capital Trust I
Trust Preferred Securities	BBB-	Baa1	BBB+

In March 2003, S&P lowered its corporate credit ratings on us from A- to BBB+ and on Wisconsin Electric and Wisconsin Gas, both from A to A-. S&P lowered its ratings on our senior unsecured debt from A- to BBB+; on Wisconsin Electric’s senior secured debt from A to A- and on Wisconsin Gas’ senior unsecured debt from A to A-. S&P affirmed Wisconsin Electric’s A- senior unsecured debt rating. S&P lowered the rating on our preferred stock from BBB to BBB- and on Wisconsin Electric’s preferred stock from BBB+ to BBB. S&P affirmed the A-2 short-term rating of us and lowered the short-term ratings of both Wisconsin Electric and Wisconsin Gas from A-1 to A-2. Wisconsin Electric’s senior secured and senior unsecured debt are both rated A- by S&P. S&P assigned a stable outlook.

In October 2003, Moody’s downgraded certain of our security ratings and the security ratings of our subsidiaries. Moody’s lowered the senior unsecured debt ratings of Wisconsin Energy and Wisconsin Energy Capital Corporation from A2 to A3 and our commercial paper rating from P-1 to P-2. Moody’s lowered the WEC Capital Trust I Trust Preferred Securities rating from A3 to Baa1. Moody’s lowered Wisconsin Electric’s senior secured debt rating from Aa2 to Aa3, senior unsecured debt rating from Aa3 to A1 and preferred stock rating from A2 to A3. Moody’s lowered Wisconsin Gas’ senior unsecured debt rating from Aa2 to A1. Moody’s confirmed the P-1 commercial paper ratings of Wisconsin Electric and Wisconsin Gas. In February 2004, Moody’s changed the rating outlook for Wisconsin Energy and Wisconsin Energy Capital Corporation to stable from negative. The rating outlook for Wisconsin Electric and Wisconsin Gas is stable.

In October 2003, Fitch downgraded certain of our security ratings and the security ratings of our subsidiaries. Fitch lowered the senior unsecured debt ratings of Wisconsin Energy and Wisconsin Energy Capital Corporation from A to A- and the commercial paper rating of Wisconsin Energy from F1 to F2. Fitch lowered the WEC Capital Trust I Trust Preferred Securities rating from A- to BBB+. Fitch lowered Wisconsin Electric’s senior secured debt rating from AA to AA-, senior unsecured rating from AA- to A+ and preferred stock rating from AA- to A. Fitch lowered

B-18

Wisconsin Gas’ senior unsecured debt rating from AA- to A+. Fitch lowered the commercial paper ratings of Wisconsin Electric and Wisconsin Gas from F1+ to F1. The rating outlook for Wisconsin Energy, Wisconsin Electric, Wisconsin Gas and Wisconsin Energy Capital Corporation 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 $699.2 million during 2004 attributable to the following operating segments:


	Estimated		Actual
Capital Expenditures	2004		2003
	(Millions of Dollars)
Utility Energy	$	480.1	$	455.6
Non-Utility Energy
We Power		177.8		162.9
Other		2.9		0.7
Manufacturing		22.5		10.4
Other		15.9		29.8

Total	$	699.2	$	659.4

Due to changing environmental and other regulations such as air quality standards and electric reliability initiatives that impact our utility energy segments, future long-term capital requirements may vary from recent capital requirements. Our utility energy segment currently expects capital expenditures, excluding the purchase of nuclear fuel and expenditures for new generating capacity contained in our Power the Future strategy described below, to be between $400 million and $500 million per year during the next five years.

Our capital requirements through 2010 for Power the Future include approximately $2.5 billion to construct 2,120 megawatts of new natural gas-based and coal-based generating capacity of which we have expended approximately $210.8 million through the end of 2003. We expect that two unaffiliated entities will collectively invest approximately $350 million in the Power the Future coal units and receive an ownership interest of approximately 17% in the units or 204-megawatts. Total cost of all four units including the two unaffiliated entities’ portion is estimated to be $2.8 billion with total output at 2,320 megawatts.

We expect capital requirements to support our $2.5 billion of investment in new generation under Power the Future to come from a combination of internal and external sources. With the dividend reduction that began in 2001, we expect to retain almost $90 million per year of additional cash flows, which will provide substantial funding for new generation. We are also divesting non-utility assets, which will provide additional cash. The new generating plants will be constructed by We Power, a non-utility subsidiary, and leased to Wisconsin Electric under 25-30 year lease agreements. We expect that Wisconsin Electric will recover the lease payments in its utility rates. We anticipate that we will need external debt financing as the plants are constructed. However we believe that the construction debt, cash flows from the lease payments, cash resulting from additional asset divestitures and cash retained from earnings will be sufficient to fund our Power the Future capital expenditures.

Investments in Outside Trusts: We have funded our pension obligations, certain other post-retirement obligations and future nuclear obligations in outside trusts. Collectively, these trusts had investments that exceeded $1.8 billion as of December 31, 2003. These trusts hold investments that are subject to the volatility of the stock market and 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.

B-19

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 construction projects, commodity contracts and other payment obligations. Our estimated maximum exposure under these agreements is approximately $77 million as of December 31, 2003. However, we believe that these agreements do not have, and are not reasonably 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 P — 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)	$	3,560.2	$	144.9	$	844.1	$	349.0	$	2,222.2
Capital Lease Obligations (c)		619.3		52.6		89.8		73.1		403.8
Operating Lease Obligations (d)		302.0		48.4		91.2		73.4		89.0
Purchase Obligations (e)		187.9		115.8		59.6		3.0		9.5
Other Long-Term Liabilities (f)		983.2		267.2		377.2		150.0		188.8

Total Contractual Obligations	$	5,652.6	$	628.9	$	1,461.9	$	648.5	$	2,913.3

(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 Energy and affiliates.

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

(f)	Other Long-Term Liabilities under various contracts of Wisconsin Energy and affiliates for the procurement of fuel, power, gas supply and associated transportation, and post-retirement contributions primarily related to utility operations.

Obligations for utility operations by our utility affiliates 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 subsidiaries. The guarantees issued by us guarantee payment or performance by our subsidiaries under specified agreements or transactions. As a result, our exposure under the guarantees is based upon the net liability of the relevant subsidiary 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 P — Guarantees” in the Notes to Consolidated Financial Statements in this report for more information.

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:

B-20

Commodity Price Risk: In the normal course of business, our utility and non-utility power generation subsidiaries utilize contracts of various duration for the forward sale and purchase of electricity. This is done to effectively manage utilization of their available generating capacity and energy during periods when available power resources are expected to exceed the requirements of their 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 Wisconsin Electric’s 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 electrical utility gas costs. During 2003, a gas hedging program was approved by the PSCW and implemented by Wisconsin Electric. For 2003, Wisconsin Electric’s 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 the gas utility operations of Wisconsin Electric and Wisconsin Gas through gas cost recovery mechanisms, which mitigates most of the risk of gas cost variations. For additional information concerning the electric utility fuel cost adjustment procedure and the natural gas utilities’ gas cost recovery mechanisms, 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: The electric operations of Wisconsin Electric burn natural gas in several of its 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. Wisconsin Electric bears regulatory risk for the recovery of these fuel and purchased power costs when they are higher than the base rate established in its rate structure.

As noted above, the electric operations of Wisconsin Electric 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 Wisconsin Electric assumes the risks and benefits of fuel cost variances that are within 3% of the base rate. Wisconsin Electric is 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 Wisconsin Electric until January 2006, the end of a five year rate freeze associated with the WICOR Merger Order. Until this time, Wisconsin Electric will operate under an approved transaction mechanism similar to the old fuel cost adjustment procedure. For 2003, 2002 and 2001, actual fuel and purchased power costs at Wisconsin Electric exceeded base fuel rates by $7.6 million, $2.3 million and $0.1 million, respectively. In 2003, 2002 and 2001, 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. Because federal and state energy assistance dollars have decreased our risks related to bad debt expenses associated with non-paying customers has increased.

As a result of gas cost recovery mechanisms, our gas distribution subsidiaries 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.

B-21

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

Temperature can also impact demand for electricity in regions where we have invested in non-utility energy assets or projects. In addition, to the extent weather conditions incurred in various regions are extreme rather than normal or mild our manufacturing segment demand for products can be impacted.

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 $609.9 million short-term debt with a weighted average interest rate of 1.24% and $192.9 million of variable-rate long-term debt with a weighted average interest rate of 1.51%. A one-percentage point change in interest rates would cause our annual interest expense to increase or decrease by approximately $6.1 million before taxes from short-term borrowings and $1.9 million before taxes from variable rate long-term debt outstanding.

We entered into treasury rate lock agreements with a major financial institution in order to minimize interest rate risk. Near the end of the first quarter of 2003, we settled several treasury lock agreements entered into earlier in the quarter and during the third quarter of 2002 associated with the issuance of $200 million of long-term unsecured senior notes in March 2003. Under a treasury lock agreement, we agree to pay or receive an amount equal to the difference between the net present value of the cash flows for the notional amount of the instrument based on: a) the yield of a U.S. treasury bond at the date when the agreement is established, and b) the yield of a U.S. treasury bond at the date when the agreement is settled, which typically coincides with the debt issuance.

As these agreements qualified for cash flow hedging accounting treatment under SFAS 133, the payment made upon settlement of these agreements is deferred in Accumulated Other Comprehensive Income and will be amortized as an increase to interest expense over the same period in which the interest cost is recognized in income.

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 Energy Corporation	Millions of Dollars
Pension trust funds	$	996.4
Nuclear decommissioning trust fund	$	674.4
Other post-retirement benefits trust funds	$	166.8

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%.

B-22

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.

Wisconsin Electric insures 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 Wisconsin Electric.

Construction Risk: In December 2002, the PSCW issued a written order granting a CPCN to commence construction of the Port Washington Generating Station consisting of two 545 megawatt natural gas-based combined cycle generating units on the site of Wisconsin Electric’s existing Port Washington Power Plant. The order approves key financial terms of the leased generation contracts including fixed construction cost of the two Port Washington units at $309.6 million and $280.3 million (2001 dollars), respectively, subject to escalation at the GDP inflation rate and force majeure and excused events provisions. Project management is subject to a number of risks over which we will have limited or no control and which might adversely affect project costs and completion time. These risks include but are not limited to shortages of, or the inability to obtain, labor or materials, the inability of the general contractor or subcontractors to perform under their contracts, strikes, adverse weather conditions and changes in applicable laws or regulations. If final costs for the construction of the Port Washington Generating Station exceed the fixed costs allowed in the PSCW order this excess cannot be recovered from Wisconsin Electric or its customers unless specifically allowed by the PSCW.

In November 2003, the PSCW issued a written order granting a CPCN to commence construction of two 615 megawatt super critical pulverized coal generating units on the site of Wisconsin Electric’s existing Oak Creek Power Plant. The order approves key financial terms of the leased generation contracts including fixed construction cost of the two Elm Road units at $2.15 billion (year of occurence dollars) subject to a general one year inflation adjustment, force majeure, excused events and event of loss provisions. Project management is subject to a number of risks over which we will have limited or no control and which might adversely affect project costs and completion time. These risks include but are not limited to shortages of, or the inability to obtain, labor or materials, the inability of the general contractor or subcontractors to perform under their contracts, strikes, adverse weather conditions and changes in applicable laws or regulations. If final costs for the construction of the Elm Road units exceed the PSCW fixed amounts by more than 5%, this excess cannot be recovered from Wisconsin Electric or its customers unless specifically allowed by the PSCW.

Independent Power Project (IPP) Market Risk: Prior to the September 2000 Power the Future strategic announcement, we made significant commitments to develop, build and own non-utility power plants. Since September 2000, we have made significant progress in exiting many of these projects. As of December 31, 2003, we had approximately $171.3 million of investments in non-utility energy assets excluding We Power. Management believes that the projected cash flows from these investments over the life of these assets will exceed the recorded carrying value. However, the market value of some of these investments is currently believed not to exceed cost. In the fourth quarter of 2001 and continuing into 2003, the IPP market experienced a significant decline driven by several factors, including the softening economy, the financial viability of energy companies with large IPP investments, lower forward electric price curves and a significant tightening of credit to this market. These factors may adversely impact the timing, proceeds and the gain or loss on future sales of non-utility energy assets.

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 $99 million.

Economic Risk. We are exposed to market risks in the regional midwest economy for our utility energy segment and worldwide economic trends for our manufacturing segment. We use diversification in our portfolio of businesses to reduce our exposure to economic fluctuations. Additionally, our manufacturing segment is exposed to various competition risks in the markets in which we operate. These include foreign sourcing, comparable quality among various competitors, price cutting and aggressive warranties. To help mitigate these risks we have programs in place to implement continuous improvements in our processes, and continued cost reduction efforts.

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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, steam and water 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 Wisconsin Electric 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:

Governmental mandates;

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

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 the gas operations of Wisconsin Electric and 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 our Power the Future strategy, (2) increased costs linked to changes in Wisconsin’s public benefits legislation, (3) costs for construction of the Ixonia Lateral, and (4) 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 the electric operations of Wisconsin Electric, $26.2 million (3.9%) for the gas operations of Wisconsin Gas, and $0.6 million (3.9%) for Wisconsin Electric’s steam operations. The filing also included an additional anticipated 2005 Wisconsin revenue deficiency in the amount of $0.4 million (2.6%) for Wisconsin Electric’s 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. In February 2004, the PSCW approved an increase in gas rates of $25.9 million. We anticipate an order implementing this increase in March 2004. We anticipate an order from the PSCW on our request related to electric and steam rates in early 2004.

Wisconsin Electric Power Company: The table below summarizes the anticipated annualized revenue impact of recent rate changes, primarily in the Wisconsin jurisdiction, authorized by regulatory commissions for Wisconsin Electric’s electric, natural gas and steam utilities. Wisconsin Electric’s 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.

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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 Wisconsin Electric to establish escrow accounting for the revenue requirement components associated with NO_xexpenditures. Wisconsin Electric’s 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.

Wisconsin Gas Company: Wisconsin Gas rates were set within the framework of the Productivity-based Alternative Ratemaking Mechanism, which was established by the PSCW in 1994 and expired on October 31, 2001. Under this mechanism, Wisconsin Gas had the ability to raise or lower margin rates within a specified range on a quarterly basis. Currently, Wisconsin Gas rates recover $1.5 million per year less than the maximum amount allowed by the PSCW’s rate order. Pursuant to that PSCW directive, Wisconsin Gas rates remain at the same levels as were set prior to the expiration of the Productivity-based Alternative Ratemaking Mechanism.

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Electric Transmission Cost Recovery: In September 2001, Wisconsin Electric 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. Wisconsin Electric was also seeking to recover associated incremental transmission costs of the Midwest Independent Transmission System Operator Inc., 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 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 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: Wisconsin Electric operates 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, Wisconsin Electric 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. Wisconsin Electric revised its 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, Wisconsin Electric 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 Wisconsin Electric until January 2006, the end of a five-year rate freeze associated with the WICOR Merger Order. Until such time, Wisconsin Electric will operate under an approved transaction mechanism similar to the old fuel cost adjustment procedure.

In addition, as previously reported, on June 4, 2001, two consumer advocacy groups petitioned the Dane County Circuit Court for review of decisions related to authorization by the PSCW for Wisconsin Electric to add a surcharge to its electric rates to recover its expected 2001 power supply costs. The petitioners alleged that the PSCW made various material errors of law and procedure as a result of which the Court should set aside both interim and final orders and remand the case to the PSCW. The case was settled and, in May 2002, the Dane County Circuit Court issued a final order dismissing the petition.

In February 2003, Wisconsin Electric 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. Wisconsin Electric 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 Wisconsin Electric 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 our acquisition of WICOR, the PSCW required similar gas cost recovery mechanisms (GCRM) for the gas operations of Wisconsin Electric and for Wisconsin Gas. Prior to the acquisition, Wisconsin Electric had operated under a modified dollar-for-dollar GCRM, which included after the fact prudence reviews by the PSCW, while the Wisconsin Gas GCRM included an incentive mechanism that

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provides an opportunity for Wisconsin Gas to increase or decrease earnings within certain limited ranges as a result of gas acquisition activities and transportation costs. For both companies, the majority of gas costs are passed through to customers under their existing gas cost recovery mechanisms.

In February 2001, the PSCW issued an order to Wisconsin Electric and to Wisconsin Gas authorizing a similar GCRM for each company. These new GCRMs, which were effective in April 2001, are similar to the existing GCRM at Wisconsin Gas. Under the new GCRMs, gas costs are passed directly to customers through a purchased gas adjustment clause. However, both companies have the opportunity to increase or decrease earnings by up to approximately 2.5% of their 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: The gas operations of Wisconsin Electric and Wisconsin Gas 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 utilities to utilize option contracts to reduce market risk associated with fluctuations in the price of natural gas purchases and gas in storage. Under these programs, Wisconsin Gas and Wisconsin Electric have the ability to hedge up to 50% of their 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 Wisconsin Gas and Wisconsin Electric gas cost recovery mechanisms. In addition, under the Gas Cost Incentive Mechanism, Wisconsin Gas and Wisconsin Electric 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: Under escrow accounting Wisconsin Gas expensed amounts included in rates for bad debt expense. If actual bad debt costs exceeded amounts allowed in rates, these amounts were deferred as a regulatory asset. In October 2002, the PSCW issued an order which eliminated escrow accounting for bad debts effective October 1, 2002. The escrow amount accumulated at September 30, 2002 of approximately $6.9 million is expected to be collected in future rates, but future bad debt expense at Wisconsin Gas will no longer be subject to this separate true-up mechanism.

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 $15.6 million in uncollectible accounts receivable as of December 31, 2003. Our annual residential bad debt expense in base rates is approximately $22.9 million.

Ixonia Lateral: On January 15, 2003, Wisconsin Gas received from the WDNR a Chapter 30 permit to construct the Ixonia Lateral after lengthy negotiations with the WDNR and interested parties. In February 2003, Wisconsin Gas filed updated cost estimates reflecting additional costs of approximately $14.0 million required by the WDNR permit conditions. In March 2003, the PSCW approved the updated construction cost estimate of $97.5 million. Wisconsin Gas started construction on the 35-mile Ixonia Lateral in April 2003. Wisconsin Gas completed construction and placed the Ixonia Lateral in service during December 2003. The Ixonia Lateral provides substantial gas cost savings as well as critical additional pipeline capacity.

Power the Future - Port Washington: The PSCW issued a written order on December 20, 2002 (the Port Order) granting Wisconsin Energy, Wisconsin Electric, and We Power 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 Wisconsin Electric’s 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 Wisconsin Electric 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;

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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, Wisconsin Electric commenced demolition of two of its 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 Wisconsin Electric in the third quarter of 2003 as provided for in lease generation contracts that were signed in May 2003. In January 2003, Wisconsin Electric filed a request with the PSCW to defer costs for recovery in future rates. 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 Port 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 Wisconsin Electric.

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 decisions. The PSCW has not made a decision on whether to appeal the Dane County Circuit Court decision.

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. We 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. We have 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. We have 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, Wisconsin Electric, and We Power a CPCN to commence construction of two 615-megawatt coal-based units (the Elm Road units) to be located on the site of Wisconsin Electric’s 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;

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Ø	The return on equity on the lease agreement with Wisconsin Electric 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, we submitted lease generation contracts for the Elm Road units to the PSCW for approval. We continue to work with the PSCW, the WDNR and other agencies to obtain all required permits and project approvals.

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.

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 Wisconsin Electric 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

Wisconsin Electric Power Company: In mid-November 2000, Wisconsin Electric submitted an application with 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 Wisconsin Electric 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 Michigan Public Service Commission’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 Wisconsin Electric and four other utilities operating in Michigan as defendants. MEC claims that Wisconsin Electric improperly collects 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. Wisconsin Electric filed a notice of intent to file claim with the Michigan Court of Claims and a motion to dismiss the complaint with the

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MPSC in May 2003. MEC filed its answer to Wisconsin Electric’s motion to dismiss in July 2003. Wisconsin Electric’s management believes 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 or the financial condition or results of operations of Wisconsin Electric.

Edison Sault Electric Company: In September 1995, the MPSC approved Edison Sault’s application to implement price cap regulation for its electric customers in the state of Michigan, capping base rates at existing levels, rolling its existing fuel cost adjustment procedure or Power Supply Cost Recovery (PSCR) factor into base rates and suspending its existing PSCR clause. Edison Sault was required to give thirty days notice for rate decreases. The order authorizing Edison Sault’s price cap represented a temporary experimental regulatory mechanism and allows Edison Sault to file an application seeking an increase in rates under extraordinary circumstances. In October 2000, Edison Sault filed a report with the MPSC addressing its experience under the price-cap mechanism. In September 2001, Edison Sault submitted an application to reinstate its PSCR clause in January 2002 and to incorporate therein 2002 incremental ATC charges and certain miscellaneous costs in the amount of $0.6 million. In October 2001, Edison Sault filed an application with the MPSC to establish its PSCR factor for the year 2002. In April 2002, the MPSC issued orders authorizing Edison Sault to reimplement its PSCR clause, beginning May 1, 2002. PSCR revenues and costs are subject to true-up hearings. In March 2003, the MPSC approved a PSCR factor of -0.00032 per kwh for calendar year 2003.

Electric Transmission Cost Recovery: Consistent with the requests in Wisconsin noted above, Wisconsin Electric 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 Wisconsin Electric to recover transmission costs in its 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 our Power 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 our Power the Future strategy is subject to a number of state and federal regulatory approvals. For additional information, see “Corporate Developments” above.

Wisconsin Electric had adequate capacity to meet all of its firm electric load obligations during 2003. All of Wisconsin Electric’s 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 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 the 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 connecting Wisconsin to the Upper Peninsula of Michigan. This incident also resulted in short outages to some firm customers.

Wisconsin Electric expects to have adequate capacity to meet all of its firm load obligations during 2004. However, extremely hot weather, unexpected equipment failure or unavailability could require Wisconsin Electric to call upon load management procedures during 2004 as it has in past years.

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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 and non-utility energy segments 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 our Power 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 by more than 65% and mercury by 50% within 10 years from Wisconsin Electric’s coal-based power plants in Wisconsin and Michigan, (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 consent decree, see “Note S — 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 F — 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, Wisconsin Electric believes that the revised standards will likely require significant reductions in SO₂ and NO_x emissions from coal-based generating facilities. Wisconsin Electric expects 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, Wisconsin Electric is currently unable to estimate the impact of the revised air quality standards on its 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.

Wisconsin Electric currently expects 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. Wisconsin Electric believes 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 Wisconsin Electric’s comprehensive plan to meet the Wisconsin regulations, permitting recovery in rates of NO_x emission reduction costs over an accelerated 10-year recovery period.

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 anticipated coal-based generating facilities.

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

Ash Landfill Sites: Wisconsin Electric aggressively seeks environmentally acceptable, beneficial uses for its combustion byproducts. For further information, see “Note S — Commitments and Contingencies” in the Notes to Consolidated Financial Statements.

Manufacturing Segment: WICOR Industries has provided reserves which it believes are sufficient to cover its estimated costs related to known contamination associated with its manufacturing facilities.

EPA Information Requests: Wisconsin Electric and Wisvest-Connecticut LLC., formerly a wholly owned subsidiary of Wisvest, each received requests for information from the EPA regional offices pursuant to Section 114(a) of the Clean Air Act. For further information related to Wisconsin Electric, see “Note S — Commitments and Contingencies” in the Notes to Consolidated Financial Statements.

Wisvest-Connecticut received requests for information from the EPA regional office pursuant to Section 114(a) of the Clean Air Act in May 2000 and February 2001. All membership interests in Wisvest-Connecticut were sold in December 2002 to PSEG Fossil, LLC, which is now the new owner and operator of the electric generating facilities that were the subject of the EPA information requests. Additionally, any liabilities relating to the information requests which were covered under our guaranty to United Illuminating, the prior owner of the facilities, have been covered by a guaranty by PSEG Power, LLC.

LEGAL MATTERS

Giddings & Lewis Inc./City of West Allis Lawsuit: In July 1999, a jury issued a verdict against Wisconsin Electric awarding the plaintiffs $4.5 million in compensatory damages and $100 million in punitive damages in an action alleging that Wisconsin Electric 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 reached 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 S — 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 $8 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.

Other: Wisvest has a 49.5% ownership interest in Androscoggin LLC (Androscoggin), which owns a co-generation power plant in Maine. Androscoggin has an energy services agreement with a company that receives steam from the co-generation plant. The steam customer filed a lawsuit against Androscoggin alleging breach of contract under the energy services agreement. The lawsuit is tentatively scheduled to go to a jury trial in 2004. For further information, see “Note D — Assets Sales and Divestitures” in the Notes to Consolidated Financial Statements in this report.

NUCLEAR OPERATIONS

Point Beach Nuclear Plant: Wisconsin Electric owns 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 joint venture of the Company and affiliates of other unaffiliated utilities. During 2003, 2002, and 2001, Point Beach provided 25% of Wisconsin Electric’s 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.

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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. In February 2003, Point Beach completed an equipment upgrade, which resulted in a capacity increase of 7 megawatts per generating unit. We are currently evaluating the timing for implementation of the power uprate project.

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 with the NRC in February 2004 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 is 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. Point Beach has responded to NRC’s February 2002 Order for interim safeguards and security compensatory measures. Point Beach has also responded to NRC orders regarding security of independent spent fuel storage installations, design basis threat, and security officer training and work hours. We are currently unable to estimate the further impact, if any, that may result.

Used Nuclear Fuel Storage and Disposal: Wisconsin Electric is 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 Wisconsin Electric has 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.

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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, Wisconsin Electric 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, Wisconsin Electric has incurred damages in excess of $70 million, which it seeks to recover from the United States Department of Energy. Damages continue to accrue, and, accordingly, Wisconsin Electric expects to seek recovery of its damages in this lawsuit.

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 United States 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 our Power 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:

Addition of new generating capacity in the state;

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

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

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 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.”

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As of January 1, 2002, Michigan retail customers of Wisconsin Electric and Edison Sault 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 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 the companies’ service territories in Michigan has been limited. With the exception of one general inquiry, no alternate supplier activity has occurred in our service territories 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 Wisconsin Electric’s business. Wisconsin Electric has one wholesale customer in Illinois, the City of Geneva, whose contract is scheduled to expire on December 31, 2005. However, Wisvest’s wholly-owned subsidiary, Calumet Energy Team, LLC, does compete in the Illinois electric generation market with power produced from its 308-megawatt gas based peaking plant that entered commercial operation in 2002. We believe that the Illinois choice legislation will not materially affect Calumet Energy’s operating results.

Electric Transmission

American Transmission Company: Effective January 1, 2001, we transferred all of the electric utility transmission assets of Wisconsin Electric and Edison Sault to American Transmission Company LLC (ATC) in exchange for ownership interests in this new company. Joining ATC is consistent with the FERC’s Order No. 2000, designed 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 Independent Transmission System Operator, Inc. (Midwest ISO). As of February 1, 2002, operational control of ATC’s transmission system was transferred to the Midwest ISO, and Wisconsin Electric 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 this 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, the financial impact of the LMP congestion pricing system might have on Wisconsin Electric and Edison Sault. The Midwest ISO is currently deferring the costs to start-up its 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 Wisconsin Electric and Edison Sault.

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.

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In December 2003, Wisconsin Electric and Edison Sault, 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 Wisconsin Electric, to place their transmission facilities under the control of PJM.

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, Wisconsin Electric and Wisconsin Gas 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 anticipate we may have to consolidate some immateral equity method investments upon adoption of the final phase of Interpretation 46.

The FASB issued FASB Staff Position (FSP) No. FAS 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 O — Benefits” in the Notes to Consolidated Financial Statements in this report for additional 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 utility subsidiaries 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

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regulatory asset and liability amounts on the utilities’ 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 $612.3 million in regulatory assets and $887.7 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.

Valuation of Long-Lived Assets and Investments: We evaluate the carrying value of our long-lived assets and our investments, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. The review of assets for impairment requires significant assumptions regarding operating strategies and estimates of future cash flows. An estimate of future cash flows contains many significant assumptions including, but not limited to future price curves, future operating costs and the expected growth of the economy. A variation in an assumption could result in a different conclusion regarding the realizability of the asset.

In 2003 and 2002 we recorded impairment charges primarily related to long-lived assets and investments associated with our non-utility energy assets. See “Note D — Asset Sales and Divestitures” in the Notes to Consolidated Financial Statements for further information. In determining the amount of impairment charges related to our non-utility energy assets, we considered the estimated length of time we expected to hold the assets and we estimated the current market value which would be realized upon sale of the assets based upon similar asset sales.

Pension and Other Post-retirement Benefits: Our reported costs of providing non-contributory defined pension benefits (described in “Note O — 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 $27 million overfunded status as of December 31, 2001 to a $218 million underfunded status as of December 31, 2002. As a result, we recorded a minimum pension liability of $113 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 $288 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 still remain $182 million underfunded. As a result, we recorded a minimum pension liability of $34 million in December 2003. We recorded a corresponding $189 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.

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Pension Plan Actuarial Assumption (a)	Impact on Reported Annual Cost
	(Millions of Dollars)
0.5% decrease in discount rate	$	3.7
0.5% decrease in rate of return on plan assets	$	5.2

(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 O — 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 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 segment 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.


Other Post-retirement Benefit Plan Actuarial Assumption (a)	Impact on Reported Annual Cost
	(Millions of Dollars)
0.5% decrease in discount rate	$	2.4
0.5% decrease in health care cost trend rate	$	(1.6	)
0.5% decrease in rate of return on plan assets	$	0.6

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

Goodwill and Other Intangible Assets: As a result of the adoption of Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (SFAS 142), effective January 1, 2002, we are required to perform annual assessments of our goodwill for impairment by applying fair-value-based tests. As of December 31, 2003, we had $835.9 million of goodwill on our balance sheet primarily attributable to our April 2000 acquisition of the gas utility and manufacturing businesses of Wicor, Inc. To perform our annual test of goodwill, we are required to make various assumptions including assumptions about the future profitability of our utility and manufacturing operations as compared to published projections for other similar businesses. A significant change in these markets or in our projections could result in the recognition of a goodwill impairment loss related to a decrease in the goodwill asset.

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We reviewed our goodwill for impairment during the third quarter of 2003 as part of our annual test as required by SFAS 142. We determined that there were no impairments to the recorded goodwill balance for any of our reporting units.

In addition, SFAS 142 required the elimination of goodwill and indefinite-lived intangible asset amortization on January 1, 2002 which resulted in an increase in net income of $21.3 million for 2002. At this time, we are unable to predict whether any adjustments to goodwill and other intangible assets will occur in the future. For further information, see “Note B — Recent Accounting Pronouncements” in the Notes to Consolidated Financial Statements.

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 $3.3 billion included accrued utility revenues of $212 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 our utility energy segment’s 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, 2004, 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 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 F — Nuclear Operations” in the Notes to Consolidated Financial Statements.

Deferred Tax Assets Valuation Allowance: At December 31, 2003, we had a valuation allowance of approximately $22 million related to state net operating loss carryforwards (state NOLs), of which $11 million relates to state NOLs of the parent company that begin to expire in 2006. The remainder of the allowance relates to state NOLs of various other non-utility subsidiaries. The state NOLs have been generated over a period of many years due to taxable losses in the separate state income tax returns. The losses at the Parent were primarily due to interest expense. We had established the valuation allowance against the state NOLs each year as the taxable losses occurred because management concluded that it was more likely than not that the state NOLs would not be realized prior to expiration.

B-39

The Power the Future generating units will be owned by our subsidiaries organized as LLCs. Once the plants become operational, taxable income or loss of the LLCs will flow through to and be reported in the separate state income tax return of the Parent. As a result, the Parent no longer expects to generate large state losses if all plants are in service. The determination of future state taxable income of the Parent is a significant estimate. Factors affecting the estimate include the ultimate resolution of legal challenges to the construction of the plants, amounts spent and timing for construction of the Power the Future generating units, the amount of debt and interest expense at the Parent and the consideration of available tax planning strategies. We concluded at December 31, 2003 it was more likely than not that all of the deferred tax assets related to state NOLs would expire before being realized.

If we would conclude in a future period that it was more likely than not that some or all of the state NOLs would be realized before expiration, generally accepted accounting principles would require that we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported as an increase or decrease in income.

B-40

CAUTIONARY FACTORS

This report and other documents or oral presentations contain or may contain forward-looking statements made by or on behalf of Wisconsin Energy. 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:

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.

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	Restrictions imposed by various financing arrangements and regulatory requirements on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans or advances.

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.

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 Wisconsin Electric.

B-41

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.

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.

Possible risks associated with non-utility diversification, such as: general economic conditions; competition; operating risks; dependence upon certain suppliers and customers; the cyclical nature of property values that could affect real estate investments; unanticipated changes in environmental or energy regulations; timely regulatory approval without onerous conditions of potential acquisitions or divestitures; risks associated with minority investments, where there is a limited ability to control the development, management or operation of the project; and the risk of higher interest costs associated with potentially reduced securities ratings by independent rating agencies as a result of these and other factors.

Ø	Legislative or regulatory restrictions or caps on non-utility acquisitions, investments or projects, including the state of Wisconsin’s amended public utility holding company law.

Ø	Factors affecting foreign non-utility operations and investments, including: foreign governmental actions; foreign economic and currency risks; political instability; and unanticipated changes in foreign environmental or energy regulations.

Factors which impede execution of our Power 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	Factors which impede execution of the sale of our Manufacturing Segment announced in February 2004, including receipt of necessary regulatory approvals.

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.

B-42

WISCONSIN ENERGY CORPORATION

CONSOLIDATED INCOME STATEMENTS

Year Ended December 31


	2003			2002			2001
	(Millions of Dollars, Except Per Share Amounts)
Operating Revenues
Utility energy	$	3,263.9		$	2,852.1		$	2,964.8
Non-utility energy		14.4			167.2			337.3
Manufacturing		746.1			685.2			585.1
Other		29.9			31.7			41.3

Total Operating Revenues		4,054.3			3,736.2			3,928.5

Operating Expenses
Fuel and purchased power		570.8			594.1			660.1
Cost of gas sold		863.3			574.9			823.8
Cost of goods sold		557.6			513.2			434.7
Other operation and maintenance		1,051.5			1,046.1			978.3
Depreciation, decommissioning and amortization		332.3			320.6			342.1
Property and revenue taxes		82.4			87.8			84.6
Asset valuation charges, net		45.6			141.5			—

Total Operating Expenses		3,503.5			3,278.2			3,323.6

Operating Income		550.8			458.0			604.9

Other Income and Deductions
Interest income		2.9			5.8			18.2
Equity in earnings of unconsolidated affiliates		22.2			22.9			26.0
AFUDC-equity		5.1			4.3			1.9
Gain (loss) on asset sales		—			(3.6	)		27.5
Other, net		13.3			14.5			(73.0	)

Total Other Income and Deductions		43.5			43.9			0.6

Financing Costs
Interest expense		220.3			221.2			245.0
AFUDC-debt		(13.5	)		(6.9	)		(13.3	)
Distributions on preferred securities of subsidiary trust		6.9			13.7			13.7
Preferred dividend requirement of subsidiary		1.2			1.2			1.2

Total Financing Costs		214.9			229.2			246.6

Income Before Income Taxes and the Cumulative Effect of Change in Accounting Principle		379.4			272.7			358.9

Income Taxes		135.1			105.7			150.4

Income Before the Cumulative Effect of Change in Accounting Principle		244.3			167.0			208.5
Cumulative Effect of Change in Accounting Principle, Net of Tax		—			—			10.5

Net Income	$	244.3		$	167.0		$	219.0

Earnings Per Share Before Change in Accounting Principle
Basic	$	2.09		$	1.45		$	1.78
Diluted	$	2.06		$	1.44		$	1.77

Earnings Per Share
Basic	$	2.09		$	1.45		$	1.87
Diluted	$	2.06		$	1.44		$	1.86

Weighted Average Common Shares Outstanding (Millions)
Basic		117.1			115.4			117.1
Diluted		118.4			116.3			117.9

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

B-43

WISCONSIN ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

December 31

ASSETS


	2003			2002
	(Millions of Dollars)
Property, Plant and Equipment
Utility energy	$	7,890.4		$	7,368.7
Non-utility energy		179.8			182.5
Manufacturing		188.9			164.5
Other		272.2			243.0
Accumulated depreciation		(3,090.4	)		(2,891.8	)

		5,440.9			5,066.9
Construction work in progress		302.2			274.0
Leased facilities, net		104.6			110.3
Nuclear fuel, net		78.4			63.2

Net Property, Plant and Equipment		5,926.1			5,514.4

Investments
Nuclear decommissioning trust fund		674.4			550.0
Investment in ATC		154.4			148.6
Other		122.8			158.0

Total Investments		951.6			856.6

Current Assets
Cash and cash equivalents		53.5			43.6
Accounts receivable, net of allowance for doubtful accounts of $56.6 and $56.4		473.5			479.2
Accrued revenues		212.2			209.1
Materials, supplies and inventories		514.8			455.1
Prepayments		109.3			85.1
Deferred income taxes - current		62.8			59.1
Other		9.9			8.5

Total Current Assets		1,436.0			1,339.7

Deferred Charges and Other Assets
Regulatory assets		612.3			649.5
Goodwill, net		835.9			833.1
Other		263.8			284.3

Total Deferred Charges and Other Assets		1,712.0			1,766.9

Total Assets	$	10,025.7		$	9,477.6

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

B-44

WISCONSIN ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

December 31

CAPITALIZATION AND LIABILITIES


	2003		2002
	(Millions of Dollars)
Capitalization
Common equity	$	2,358.6	$	2,139.4
Preferred stock of subsidiary		30.4		30.4
Company-obligated mandatorily redeemable preferred securities of subsidiary trust holding solely debentures of the Company		—		200.0
Long-term debt		3,574.3		3,030.5

Total Capitalization		5,963.3		5,400.3

Current Liabilities
Long-term debt due currently		167.2		40.3
Short-term debt		609.9		953.1
Accounts payable		300.8		317.6
Payroll and vacation accrued		88.4		89.0
Taxes accrued - income and other		37.0		63.7
Interest accrued		35.8		36.7
Other		149.0		125.5

Total Current Liabilities		1,388.1		1,625.9

Deferred Credits and Other Liabilities
Regulatory liabilities		887.7		326.0
Asset retirement obligations		732.0		—
Cost of removal obligations		—		1,115.6
Deferred income taxes - long term		647.5		568.0
Accumulated deferred investment tax credits		66.0		70.9
Minimum pension liability		34.7		113.5
Other		306.4		257.4

Total Deferred Credits and Other Liabilities		2,674.3		2,451.4

Commitments and Contingencies (Note S)		—		—

Total Capitalization and Liabilities	$	10,025.7	$	9,477.6

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

B-45

WISCONSIN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31


	2003			2002			2001
	(Millions of Dollars)
Operating Activities
Net income	$	244.3		$	167.0		$	219.0
Reconciliation to cash
Depreciation, decommissioning and amortization		383.4			361.8			377.5
Nuclear fuel expense amortization		25.3			27.3			32.3
Equity in (earnings) losses of unconsolidated affiliates		(22.2	)		(22.9	)		(26.0	)
Asset valuation charges		59.4			141.5			—
Deferred income taxes and investment tax credits, net		70.9			(25.0	)		(12.8	)
Losses (gains) on asset sales		(13.8	)		3.6			(27.5	)
Accrued income taxes, net		(25.9	)		30.7			(20.3	)
Change in - Accounts receivable and accrued revenues		2.6			(66.8	)		187.5
Other accounts receivable		—			116.4			—
Inventories		(59.7	)		10.2			(38.7	)
Other current assets		(25.6	)		7.6			62.4
Accounts payable		(16.8	)		4.0			(119.2	)
Other current liabilities		21.1			(1.9	)		(108.6	)
Other		(19.1	)		(42.2	)		45.0

Cash Provided by Operating Activities		623.9			711.3			570.6

Investing Activities
Capital expenditures		(659.4	)		(556.8	)		(672.5	)
Acquisitions and investments		(7.6	)		(39.7	)		(35.7	)
Proceeds from asset sales, net		55.9			310.0			294.4
Nuclear fuel		(38.3	)		(20.7	)		(9.9	)
Nuclear decommissioning funding		(17.6	)		(17.6	)		(17.6	)
Other		(0.2	)		(41.0	)		(37.8	)

Cash Used in Investing Activities		(667.2	)		(365.8	)		(479.1	)

Financing Activities
Issuance of common stock		62.9			52.6			51.6
Repurchase of common stock		(6.8	)		(52.3	)		(133.6	)
Dividends paid on common stock		(93.7	)		(92.4	)		(93.8	)
Issuance of long-term debt		1,004.4			46.8			1,325.5
Retirement of long-term debt		(546.7	)		(485.6	)		(98.2	)
Change in short-term debt		(343.2	)		182.0			(1,124.7	)
Other		(23.7	)		—			(11.8	)

Cash (Used in) Provided by Financing Activities		53.2			(348.9	)		(85.0	)

Change in Cash and Cash Equivalents		9.9			(3.4	)		6.5

Cash and Cash Equivalents at Beginning of Year		43.6			47.0			40.5

Cash and Cash Equivalents at End of Year	$	53.5		$	43.6		$	47.0

Supplemental Information - Cash Paid For
Interest (net of amount capitalized)	$	205.7		$	235.6		$	228.3
Income taxes (net of refunds)	$	100.0		$	90.9		$	166.8

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

B-46

WISCONSIN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMMON EQUITY


	Common Stock		Other Paid In Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Unearned Compensation			Stock Options Exercisable			Total
	(Millions of Dollars)
Balance - December 31, 2000	$	1.2	$	833.3		$	1,159.7		$	(2.9	)	$	(3.9	)	$	29.4		$	2,016.8
Net Income							219.0												219.0
Other comprehensive income
Foreign currency translation										(1.4	)								(1.4	)
Unrealized hedging losses										(6.5	)								(6.5	)

Comprehensive income (loss)		—		—			219.0			(7.9	)		—			—			211.1
Common stock cash dividends $0.80 per share							(93.8	)											(93.8	)
Common stock issued				51.6															51.6
Repurchase of common stock				(133.6	)														(133.6	)
Restricted stock awards													(1.6	)					(1.6	)
Amortization and forfeiture of restricted stock													1.3						1.3
Stock options exercised				8.2												(8.2	)		—
Tax benefit of stock options exercised				4.9															4.9
Other				(0.6	)														(0.6	)

Balance - December 31, 2001	$	1.2	$	763.8		$	1,284.9		$	(10.8	)	$	(4.2	)	$	21.2		$	2,056.1
Net Income							167.0												167.0
Other comprehensive income
Foreign currency translation										3.0									3.0
Minimum pension liability										(0.8	)								(0.8	)
Unrealized hedging gains										1.1									1.1

Comprehensive income		—		—			167.0			3.3			—			—			170.3
Common stock cash dividends $0.80 per share							(92.4	)											(92.4	)
Common stock issued				52.6															52.6
Repurchase of common stock				(52.3	)														(52.3	)
Amortization and forfeiture of restricted stock				(0.2	)								0.9						0.7
Stock options exercised				10.2												(10.2	)		—
Tax benefit of stock options exercised				4.5															4.5
Other				(0.1	)														(0.1	)

Balance - December 31, 2002	$	1.2	$	778.5		$	1,359.5		$	(7.5	)	$	(3.3	)	$	11.0		$	2,139.4
Net Income							244.3												244.3
Other comprehensive income
Foreign currency translation										7.8									7.8
Minimum pension liability										1.3									1.3
Unrealized hedging gains										1.5									1.5

Comprehensive income		—		—			244.3			10.6			—			—			254.9
Common stock cash dividends $0.80 per share							(93.7	)											(93.7	)
Common stock issued				62.9															62.9
Repurchase of common stock				(6.8	)														(6.8	)
Restricted stock awards													(2.8	)					(2.8	)
Amortization and forfeiture of restricted stock				(0.3	)								1.4						1.1
Stock options exercised				3.8												(3.8	)		—
Tax benefit of stock options exercised				5.0															5.0
Other				(1.4	)														(1.4	)

Balance - December 31, 2003	$	1.2	$	841.7		$	1,510.1		$	3.1		$	(4.7	)	$	7.2		$	2,358.6

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

B-47

WISCONSIN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CAPITALIZATION

December 31


	2003			2002
	(Millions of Dollars)
Common Equity (See Consolidated Statements of Common Equity)
Common stock - $.01 par value; authorized 325,000,000 shares; outstanding - 118,425,546 and 116,027,724 shares	$	1.2		$	1.2
Other paid in capital		841.7			778.5
Retained earnings		1,510.1			1,359.5
Accumulated other comprehensive income (loss)		3.1			(7.5	)
Unearned compensation - restricted stock awards		(4.7	)		(3.3	)
Stock options exercisable		7.2			11.0

Total Common Equity		2,358.6			2,139.4

Preferred Stock
Wisconsin Energy $.01 par value; authorized 15,000,000 shares; none outstanding		—			—
Wisconsin Electric 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		—			—
Wisconsin Gas $.01 par value; authorized 3,000,000 shares; none outstanding		—			—

Total Preferred Stock		30.4			30.4
Company-obligated mandatorily redeemable preferred securities of subsidiary trust holding solely debentures of the Company, 6.85% due 2039 (See Note B)		—			200.0

Long-Term Debt
First mortgage bonds
7¹/4% due 2004		140.0			140.0
7¹/8% due 2016		—			100.0
6.85% due 2021		—			9.0
7³/4% due 2023		—			100.0
7.05% due 2024		—			60.0
7.70% due 2027		—			200.0

Debentures (unsecured)
6⁵/8% due 2006		200.0			200.0
9.47% due 2006		2.1			2.8
8¹/4% due 2022		—			25.0
6¹/2% due 2028		150.0			150.0
6⁷/8% due 2095		100.0			100.0
6.60% due 2013		45.0			45.0
4.50% due 2013		300.0			—
5.625% due 2033		335.0			—
5.20% due 2015		125.0			—

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

B-48

WISCONSIN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CAPITALIZATION - (Cont’d)

December 31


	2003			2002
	(Millions of Dollars)
Long-Term Debt - (Cont’d)
Notes (secured, nonrecourse)
2.915% variable rate due 2005 (a)	$	6.8		$	7.0
6.36% effective rate due 2006		3.3			4.4
6.90% due 2006		1.1			1.1
7.125% due 2007		—			4.3
3.12% variable rate due 2003-2009 (a)		4.7			4.2
2% stated rate due 2011		1.3			1.3
4.81% effective rate due 2030		2.0			—
1.41% variable rate due 2023 (a)		16.0			—

Notes (unsecured)
6.66% due 2003		—			10.6
6³/8% due 2005		65.0			65.0
6.85% due 2005		10.0			10.0
1.52% variable rate due 2006 (a)		1.0			1.0
5.875% due 2006		550.0			550.0
6.36% effective rate due 2006		3.6			4.8
7.00% to 8.00% due 2001-2008		2.3			2.9
5.50% due 2008		300.0			300.0
6.21% due 2008		20.0			20.0
6.48% due 2008		25.4			25.4
5¹/2% due 2009		50.0			50.0
6.50% due 2011		450.0			450.0
6.51% due 2013		30.0			30.0
1.52% variable rate due 2015 (a)		17.4			17.4
1.25% variable rate due 2016 (a)		67.0			67.0
6.94% due 2028		50.0			50.0
1.52% variable rate due 2030 (a)		80.0			80.0
6.20% due 2033		200.0			—

Junior subordinated debentures (unsecured)
6.85% due 2039 (see Note B)		206.2			—

Obligations under capital leases		213.2			218.2
Unamortized discount, net and other		(31.9	)		(35.6	)
Long-term debt due currently		(167.2	)		(40.3	)

Total Long-Term Debt		3,574.3			3,030.5

Total Capitalization	$	5,963.3		$	5,400.3

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

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

B-49

WISCONSIN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General: Our consolidated financial statements include the accounts of Wisconsin Energy Corporation (Wisconsin Energy, the Company, Our, We or Us), a diversified holding company, as well as our principal subsidiaries in the following operating segments:

Ø	*Utility Energy Segment* — Consisting of Wisconsin Electric Power Company (Wisconsin Electric), Wisconsin Gas Company (Wisconsin Gas) and Edison Sault Electric Company (Edison Sault); engaged primarily in the generation of electricity and the distribution of electricity and natural gas;

Ø	*Manufacturing Segment* — Consisting of WICOR Industries, LLC, an intermediate holding company, and its primary subsidiaries, Sta-Rite Industries, LLC, SHURflo, LLC and Hypro LLC; engaged in the manufacture of pumps as well as fluid processing and water filtration equipment; and

Ø	*Non-Utility Energy Segment* — Consisting primarily of W.E. Power, LLC (We Power); engaged principally in the design, development, construction and ownership of electric power generating facilities for long term lease to Wisconsin Electric, and Wisvest Corporation (Wisvest).

Our other non-utility subsidiaries include primarily Minergy Corp., which develops and markets renewable energy and recycling technologies, and Wispark LLC (Wispark), which develops and invests in real estate. We have eliminated all significant intercompany transactions and balances 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.

Revenues: We recognize energy revenues on the accrual basis and include estimated amounts for service rendered but not billed. Manufacturing revenues from product sales are recognized upon shipment. Our manufacturing segment estimates and records provisions for sales returns, allowances and original warranties in the period the sale is reported based upon experience.

Wisconsin Electric’s rates include base amounts for estimated fuel and purchased power costs. It can request recovery of fuel and purchased power costs prospectively from retail electric customers in the Wisconsin jurisdiction through its 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.

Wisconsin Electric’s and Wisconsin Gas’ 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.

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Our regulated utilities collect in their 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 $571.1 million as of December 31, 2003 and is classified as a regulatory liability. The December 31, 2002 liability was $565.6 million and was classified in Cost of Removal Obligations.

We include capitalized software costs associated with our regulated operations in the subcaption “Utility Energy” under the caption “Property, Plant and Equipment” on the Consolidated Balance Sheets. As of December 31, 2003 and 2002, regulated capitalized software costs totaled $64.6 million and $68.9 million, respectively, of which approximately $0.1 million and $0.2 million is associated with non-utility companies as of December 31, 2003 and 2002, respectively.

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 F).

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—Gain (loss) on asset sales” in the Consolidated Income Statements.

Estimated useful lives for non-regulated assets are 3 to 10 years for manufacturing equipment, 3 to 28 years for other non-utility equipment, 2 to 5 years for software and 30 to 40 years for non-utility buildings.

For assets other than our regulated assets we accrue depreciation expense at straight-line rates over the estimated useful lives of the assets. For manufacturing property, we primarily include depreciation expense in cost of goods sold.

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, Wisconsin Electric capitalized AFUDC-debt and equity at 10.18% during the periods reported.

In a rate order dated August 30, 2000, the PSCW authorized Wisconsin Electric to accrue AFUDC on all electric utility nitrogen oxide (NO_x) 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 these 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.

As approved by the PSCW, Wisconsin Gas is allowed to accrue AFUDC on specific large construction projects at a rate of 10.32%.

Earnings Per Common Share: We compute basic earnings per common share by dividing net earnings by the weighted average number of common shares outstanding. Diluted earnings per share is less than basic earnings per share due to the potentially dilutive effects of stock options.

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


Materials, Supplies and Inventories	2003		2002
	(Millions of Dollars)
Fossil Fuel	$	108.0	$	124.4
Natural Gas in Storage		184.4		91.9
Materials and Supplies		93.2		97.2
Manufacturing		129.2		141.6

Total	$	514.8	$	455.1

We price substantially all fossil fuel, materials and supplies and natural gas in storage inventories using the weighted-average method of accounting. Approximately 75% and 82% of the manufacturing inventories in 2003 and 2002 were priced using the last-in, first-out method (not in excess of the market), with the remaining inventories priced using the first-in, first-out method. If we had used the first-in, first-out method of accounting exclusively, manufacturing inventories would have been $0.3 million higher at December 31, 2003 and $0.3 million lower at December 31, 2002.

Goodwill and Long-Lived Assets: Goodwill represents the excess of acquisition costs over the fair value of the net assets of acquired businesses and has been amortized through 2001 on a straight-line basis over its estimated life, which was generally 40 years. Effective January 1, 2002, we adopted Statement of Financial Accounting Standards (SFAS) No. 142, Goodwill and Other Intangible Assets (SFAS 142) which eliminated the annual amortization of goodwill. For further information, see Note I.

Regulatory Accounting: Our utility energy segment accounts for its 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 $25.7 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).

Our regulatory assets and liabilities at December 31 consist of:


Regulatory Assets	2003		2002
	(Millions of Dollars)
Unrecognized pension costs (See Note O)	$	189.4	$	288.5
Deferred Income tax related (See Note E)		133.0		139.6
Deferred electric transmission costs		73.3		62.5
Environmental costs		55.6		46.9
Plant related — capital lease (See Note K)		54.5		47.2
Post-retirement benefit costs		22.8		25.6
Bad debt costs		21.5		7.0
Debt redemption costs		18.3		—
Department of Energy assessments (See Note F)		10.7		13.3
Other, net		33.2		18.9

Total Regulatory Assets	$	612.3	$	649.5

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Regulatory Liabilities	2003		2002
	(Millions of Dollars)
Cost of removal obligations	$	571.1	$	—
Deferred pension - income		128.3		139.6
Income tax related (See Note E)		126.8		134.5
Conservation escrow		12.4		14.2
Derivatives		11.7		4.5
SO₂ allowances		10.0		1.0
Other, net		27.4		32.2

Total Deferred Regulatory Liabilities	$	887.7	$	326.0

We recorded a minimum pension liability in 2003 and in 2002 to reflect the funded status of our pension plans (see Note O). We concluded that substantially all of the unrecognized pension costs resulting from the recognition of our minimum pension liability that relate to our utility energy segment qualify as a regulatory asset. As a result, we recorded a pre-tax regulatory asset in the amount of $189.4 million and $288.5 million associated with our minimum pension liability as of December 31, 2003 and 2002, respectively.

In October 2002, the PSCW issued an order authorizing Wisconsin Electric 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. Wisconsin Electric is currently recovering incremental transmission costs from its 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 $55.6 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 $29.9 million accrual for estimated future site remediation (See Note S). 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 of December 31, 2003, we have deferred a regulatory asset of approximately $21.5 million in total uncollectible accounts receivable representing unamortized 2002 escrowed amounts and 2003 incremental bad debt costs in excess of amounts in existing rates. During 2002, Wisconsin Gas expensed bad debt costs included in rates. If actual bad debt costs exceeded amounts allowed in rates, we escrowed these costs as a deferred regulatory asset for recovery in a future rate case. In October 2002, the PSCW issued an order which prospectively eliminated escrow accounting for the bad debts of Wisconsin Gas effective October 1, 2002. We expect to collect the escrowed balance of bad debts accumulated as of September 30, 2002 in future rates. However, future bad debt expense at Wisconsin Gas will no longer be subject to this separate true-up mechanism. 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, the PSCW approved our request effective in October 2003 for deferral of 2003 uncollectible accounts receivable in excess of amounts included in existing annual utility rates.

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.

In connection with the WICOR acquisition, we recorded the funded status of the Wisconsin Gas pension and post-retirement medical plans at fair value at the acquisition date. Due to the expected regulatory treatment of these items, we recorded a regulatory asset (Post-retirement benefit costs) and a regulatory liability (Deferred pension - income) that is being amortized over an average remaining service life of 15 years ending 2015.

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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, use of financial instruments is limited. For further information, see Notes N and M.

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 the ability of our principal utility subsidiaries to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. Under Wisconsin law, Wisconsin Electric and Wisconsin Gas 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 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.

Impairment or Disposal of Long Lived Assets: We carry property, equipment and goodwill related to businesses held for sale at the lower of cost or estimated fair value less costs to sell. As of December 31, 2003, we had no assets classified as Held for Sale. In August 2001, the Financial Accounting Standards Board (FASB) issued SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which we adopted January 1, 2002. SFAS 144 addresses the financial accounting and reporting for the impairment of long-lived assets and for long-lived assets to be disposed of. This statement supersedes SFAS 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of. Under SFAS 144, long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that their carrying value may not be recoverable from the use and eventual disposition of the asset based on the remaining useful life. For further information, see Notes D and T.

Investments: We account for investments in other affiliated companies in which we do not maintain control using the equity method.

Income Taxes: We file a consolidated Federal income tax return. Accordingly, we allocate Federal current tax expense benefits and credits to our subsidiaries based on their separate tax computations.

Stock Options: We account for stock options under Accounting Principles Board Opinion 25, Accounting for Stock Issued to Employees (APB 25) and adopted the disclosure provisions of SFAS 123, Accounting for Stock-Based Compensation, as amended by SFAS 148, Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of SFAS 123 (See Note G).

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

Financial Instruments with Characteristics of both Liabilities and Equity: We adopted SFAS 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity, on July 1, 2003. SFAS 150, which was issued by the FASB in May 2003, requires an issuer to classify outstanding freestanding financial instruments within its scope as a liability on its balance sheets even though the instruments have characteristics of equity. Our Trust Preferred Securities (see Note J), previously separately classified in the capitalization section of our balance sheet, fell within the scope of SFAS 150. Effective for the quarterly period ending September 30, 2003, we began classifying our $200 million of outstanding Trust Preferred Securities as long-term debt on our balance

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sheet. In addition, we began prospectively classifying our associated dividends ($13.7 million on an annualized basis) as interest expense on our income statements. As required by SFAS 150, we did not reclassify our Trust Preferred Securities as long-term debt on the December 31, 2002 balance sheet.

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 after March 15, 2004. While we are continuing to evaluate the impact of the application of these new rules, we anticipate that we may have to consolidate some immateral equity method investments upon adoption of the final phase of FIN 46 in the first quarter of 2004.

Our Trust Preferred Securities, classified as long-term debt on our September 30, 2003 balance sheet, fall within the scope of Interpretation 46. The Trust that issued our Trust Preferred Securities is a variable interest entity under FIN 46, but we are not the primary beneficiary. As a result, when we adopted FIN 46 for special purpose entities effective for the quarterly period ending December 31, 2003 we deconsolidated the Trust. With this change in financial statement presentation, we began prospectively reporting on our balance sheet our investment in the trust of $6.2 million and long-term debt of $206.2 million of junior subordinated debentures payable to the trust instead of the trust’s $200 million of outstanding Trust Preferred Securities. In addition, we prospectively began reporting $14.1 million of annual interest expense on the junior subordinated debentures and $0.4 million of equity in the unconsolidated earnings of the trust on our 2004 income statements and statements of cash flows instead of $13.7 million of distributions on the Trust Preferred Securities.

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. See Note M for further information.

Pension and Other Post-retirement Benefit Plans: We adopted SFAS 132, Employers’ Disclosures about Pensions and Other Post-retirement Benefits, in December 2003. SFAS 132, 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 O).

C — MERGERS AND ACQUISITIONS

Manufacturing Segment

During 2003 and 2002, we completed acquisitions of several relatively small manufacturing companies. The aggregate purchase price for these transactions was approximately $4 million and $17 million, respectively. We financed these purchases using corporate working capital and short-term borrowings. We accounted for these acquisitions as purchases, and the acquired companies’ results of operations are included in our consolidated financial statements from the acquisition date. The excess of the purchase price over the estimated fair value of the net assets of the acquired companies was approximately $0.3 million which we recorded as other intangibles in 2003 and $2 million which we recorded as goodwill and other intangibles in 2002. Due to the immaterial nature of the transactions, we have not presented pro forma financial information.

D — ASSET SALES AND DIVESTITURES

We have been pursuing a corporate strategy since September 2000, which, among other things, identified the divestiture of non-core investments. These assets primarily related to non-utility energy investments and real estate. As discussed in Note T, in February 2004, we announced that we reached an agreement to sell our manufacturing segment.

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During 2003, we sold our investment in two energy marketing companies, a small investment in assets of a Minergy Corp. project, a 500 megawatt natural gas power island and miscellaneous small real estate and other sales. These sales resulted in net cash proceeds of approximately $56 million. In addition, we received $15 million in dividends from certain of these companies at closing, and we expect to receive $32 million in tax benefits. In addition, during 2003 we wrote-off our remaining investment in Androscoggin LLC, an independent power project. The combination of our asset sales and asset write-down resulted in a pre-tax charge of $45.6 million during 2003.

During 2002, we completed the sale of Wisvest - Connecticut LLC, which resulted in net cash proceeds of approximately $220 million. In addition, during 2002 we also recorded pre-tax impairment charges of $125.1 million related to the decline in value in non-utility energy assets and $16.4 million related to a decline in a venture capital investment.

During 2001, we completed the sale of a meter services company, and an investment in Blythe Energy LLC, an independent power project. These sales resulted in after-tax gains of approximately $16.5 million. In addition, during 2001, we recorded a non-cash charge of $0.21 per share, related to the decline in the value of a venture capital investment.

Effective January 1, 2001, Wisconsin Electric and Edison Sault transferred electric utility transmission system assets with a net book value of approximately $254.9 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 $119.8 million of cash back to Wisconsin Electric and Edison Sault as a partial return of the original equity contribution. As of December 31, 2003 and 2002, we had a total ownership interest of approximately 39.4% and 42.5%, 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.

As of December 31, 2003, we had approximately $171.0 million of non-utility energy assets, excluding We Power. Based upon projections of the expected undiscounted cash flows from these assets, we have concluded that we will recover our non-utility energy asset investments. However, the values that could be realized if we immediately disposed of certain of these assets are believed to be less than their carrying amounts.

E — 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	$	112.3		$	153.0		$	163.2
Deferred income taxes, net		27.7			(42.4	)		(7.8	)
Investment tax credit, net		(4.9	)		(4.9	)		(5.0	)

Total Income Tax Expense	$	135.1		$	105.7		$	150.4

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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:


	2003					2002					2001
Income Tax Expense	Amount			Effective Tax Rate		Amount			Effective Tax Rate		Amount			Effective Tax Rate
	(Millions of Dollars)
Expected tax at statutory federal tax rates	$	132.8		35.0	%	$	96.5		35.0	%	$	125.6		35.0	%
State income taxes net of federal tax benefit		23.6		6.2	%		22.4		8.1	%		26.3		7.3	%
Investment tax credit restored		(4.9	)	(1.3	)%		(4.9	)	(1.8	)%		(5.0	)	(1.4	)%
Amortization of goodwill		—		—			—		—			6.6		1.8	%
Historical rehabilitation credits		(3.3	)	(0.9	)%		(6.0	)	(2.2	)%		—		—
Other, net		(13.1	)	(3.4	)%		(2.3	)	(0.3	)%		(3.1	)	(0.8	)%

Total Income Tax Expense	$	135.1		35.6	%	$	105.7		38.8	%	$	150.4		41.9	%

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	$	—	$	—		$	774.5		$	691.9
Construction advances		—		—			(82.9	)		(75.7	)
Decommissioning trust		—		—			(65.5	)		(59.0	)
Contested liability payment		—		(2.4	)		—			—
Recoverable gas costs		1.5		3.7			—			—
Uncollectible account expense		17.9		17.7			—			—
Employee benefits and compensation		14.0		16.6			9.0			(0.2	)
Asset impairment charge		10.7		10.8			—			—
State NOL’s		—		—			(22.5	)		(24.0	)
Valuation allowance		—		—			22.5			24.0
Other		18.7		12.7			12.4			11.0

Total Deferred Income Taxes	$	62.8	$	59.1		$	647.5		$	568.0

Our regulated subsidiaries have also recorded deferred regulatory assets and liabilities representing the future expected impact of deferred taxes on utility revenues (see Note A). We had not recorded $22.5 and $24.0 million of tax benefits as of December 31, 2003 and 2002 primarily related to state loss carryforwards due to the uncertainty of the ability to benefit from these losses in the future. These loss carryforwards begin to expire in 2006 and have been reduced by a valuation allowance.

F — NUCLEAR OPERATIONS

Point Beach Nuclear Plant: Wisconsin Electric owns two 518-megawatt electric generating units at Point Beach Nuclear Plant in Two Rivers, Wisconsin. Point Beach is operated by Nuclear Management Company (NMC), a company that, as of December 31, 2003, provides services to eight nuclear generating units in the Midwest. NMC is owned by our wholly owned subsidiary WEC Nuclear Corporation 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 Wisconsin Electric’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

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$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 (Wisconsin Electric owns two) with a limit of $10 million per reactor within one calendar year. As the owner of Point Beach, Wisconsin Electric would be obligated to pay its proportionate share of any such assessment.

Wisconsin Electric, through its membership in Nuclear Electric Insurance Limited (NEIL), carries 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. Wisconsin Electric’s maximum retrospective liability under its policies is $14.9 million.

Wisconsin Electric also maintains 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. Wisconsin Electric’s 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 Wisconsin Electric 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, Wisconsin Electric’s 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 sheet 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 plants 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 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 H.

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. The SFAS 143 liability as of December 31, 2003 is approximately $732 million.

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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, Wisconsin Electric recorded its 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.

G — COMMON EQUITY

Common Stock Repurchase Plan: The Board of Directors approved a common stock repurchase plan which as amended, authorized us to purchase up to $400 million of our shares of common stock in the open market through December 31, 2004. Through December 31, 2003 we purchased and retired approximately 13.4 million shares of common stock for $293.6 million.

We issued approximately 2.7 million new shares of common stock each year during 2003, 2002 and 2001. These shares were primarily issued through employee benefit plans and the dividend reinvestment plan. Proceeds totaled approximately $62.9 million, $52.6 million, and $51.6 million during 2003, 2002, and 2001, respectively. In February 2004, we announced that we did not expect to issue new shares under these programs; rather we instructed the plan agents to begin purchasing the shares in the open market in lieu of issuing new shares.

Stock Option Plans and Restricted Stock: Our 1993 Omnibus Stock Incentive Plan (OSIP), as approved by stockholders, enables us to provide a long-term incentive, through equity interests in Wisconsin Energy, to outside directors, selected officers and key employees of the Company and its subsidiaries. In May 2001, the OSIP was amended to increase the number of shares reserved for issuance from 4.0 million to 20.0 million and to extend the expiration date to 2011.

The OSIP provides for the granting of stock options, stock appreciation rights, stock awards and performance units during the ten-year extension of the plan. Awards may be paid in common stock, cash or a combination thereof. No stock appreciation rights have been granted to date.

The exercise price of a stock option under the OSIP is to be no less than 100% of the common stock’s fair market value on the grant date and options may not be exercised within six months of the grant date except in the event of a change in control. The stock options generally vest on a straight line basis over a four year period and expire no later than eleven years from the date of grant.

The following is a summary of our stock options issued through December 31, 2003. In addition to the OSIP, the table below reflects our assumption of former WICOR options in 2000, which were converted into options to purchase shares of Wisconsin Energy common stock on the same terms and conditions as were applicable under these WICOR options.

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	2003				2002				2001
Stock Options	Number of Options		Weighted- Average Exercise Price		Number of Options		Weighted- Average Exercise Price		Number of Options		Weighted- Average Exercise Price
Outstanding at January 1	8,307,190		$	21.21	7,135,463		$	19.16	6,216,835		$	17.81
Granted	2,913,289		$	26.05	2,465,815		$	22.88	2,168,825		$	20.94
Exercised	(1,357,197	)	$	19.55	(1,284,500	)	$	13.47	(990,136	)	$	13.36
Forfeited	(39,347	)	$	21.97	(9,588	)	$	24.38	(260,061	)	$	23.81

Outstanding at December 31	9,823,935		$	22.87	8,307,190		$	21.21	7,135,463		$	19.16

Exercisable at December 31	4,303,482		$	21.25	4,267,604		$	20.56	3,724,398		$	17.45

Following its normal schedule of awarding options on January 2, 2004, the Board of Directors awarded 1,847,585 additional stock options to our officers and key employees with an exercise price of $33.45 per option.

The following table summarizes information about stock options outstanding at December 31, 2003:


	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number	Average Exercise Price		Life (years)	Number	Average Exercise Price
$ 8.99 to $19.97	1,770,499	$	17.09	3.0	1,565,477	$	16.71
$20.39 to $21.98	1,901,505	$	20.95	7.2	1,054,419	$	21.02
$22.66 to $24.58	2,215,383	$	22.66	7.9	772,776	$	22.67
$25.19 to $27.65	3,155,198	$	25.69	8.3	529,460	$	26.98
$29.13 to $31.07	781,350	$	29.87	6.7	381,350	$	29.64

	9,823,935	$	22.87	6.9	4,303,482	$	21.25

We apply APB 25 and related interpretations when accounting for our stock option plans and have adopted the disclosure-only provisions of SFAS 123, as amended by SFAS 148. The fair value of options at date of grant was estimated using the Black-Scholes option-pricing model with the following weighted average assumptions:


	2003			2002			2001
Risk free interest rate		4.5	%		5.6	%		5.5	%
Dividend yield		3.1	%		3.5	%		3.8	%
Expected volatility		25.73	%		25.5	%		23.5	%
Expected life (years)		10			10			10
Pro forma weighted average fair value of our stock options granted	$	7.04		$	6.25		$	5.04

As described more fully in the following table, our diluted earnings would have been reduced by $0.06, $0.05 and $0.03 per share, respectively had we expensed the 2003, 2002 and 2001 grants for stock-based compensation plans under SFAS 123.

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	2003		2002		2001
	(Millions of Dollars, Except Per Share Amounts)
Net Income
As reported	$	244.3	$	167.0	$	219.0
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects	$	0.7	$	0.3	$	0.3
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	$	8.5	$	5.3	$	3.1

Pro forma	$	236.5	$	162.0	$	216.2

Basic Earnings Per Common Share
As reported	$	2.09	$	1.45	$	1.87
Pro forma	$	2.02	$	1.40	$	1.85

Diluted Earnings Per Common Share
As reported	$	2.06	$	1.44	$	1.86
Pro forma	$	2.00	$	1.39	$	1.83

We have granted restricted shares of common stock to certain key employees. The following restricted stock activity occurred during 2003, 2002 and 2001:


	2003				2002				2001
Restricted Shares	Number of Shares		Weighted- Average Market Price		Number of Shares		Weighted- Average Market Price		Number of Shares		Weighted- Average Market Price
Outstanding at January 1	219,052				243,941				204,941
Granted	104,500		$	27.72	—			—	77,650		$	20.39
Released / Forfeited	(28,632	)	$	22.84	(24,889	)	$	20.64	(38,650	)	$	22.54

Outstanding at December 31	294,920				219,052				243,941

Recipients of the restricted shares, who have the right to vote the shares and to receive dividends, are not required to provide consideration to us other than rendering service. Forfeiture provisions on the restricted stock expire 10 years after award grant subject to an accelerated expiration schedule based on the achievement of certain financial performance goals.

Under the provisions of APB 25, we record the market value of the restricted stock awards on the date of grant as a separate unearned compensation component of common stock equity and then we charge their value to expense over the vesting period of the awards. We also adjust expense for acceleration of vesting due to achievement of performance goals.

On January 2, 2004, the Board also granted 159,159 deferred stock units identified as performance shares to executive officers and other key employees. These awards provide for the issuance of Common Stock based on certain management objectives achieved by the performance period ending December 31, 2006. Prospective compensation cost relating to the performance shares will be recorded based on the quoted market price of our common stock at the end of the reporting period.

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H — ASSET RETIREMENT OBLIGATIONS

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

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, Wisconsin Electric signed an agreement to lease the site of its existing coal-based Port Washington Power Plant to We Power, which is constructing and will own a new gas-fired generating station at the site as part of our Power the Future program. The terms of the lease call for Wisconsin Electric 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.

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)
Wisconsin Energy	$	—	$	675.4	$	14.9	$	0.8	$	35.2	$	7.3	$	732.0

I — GOODWILL AND INTANGIBLE ASSETS

We adopted SFAS 142, Goodwill and Other Intangible Assets, effective January 1, 2002. Under SFAS 142, goodwill and other intangibles with indefinite lives are no longer subject to amortization. However, goodwill along with other intangibles are subject to new fair value-based rules for measuring impairment, and resulting write-downs, if any, are reflected as a change in accounting principle upon adoption and in operating expense in subsequent periods.

We assess the fair value of our SFAS 142 reporting units by considering future discounted cash flows. This analysis is supplemented with a comparison of fair value based on public company trading multiples and merger and acquisition transaction multiples for similar companies. We perform our annual impairment test as of August 31. There was no impairment to the recorded goodwill balance as of our annual 2003 impairment test date for any of our reporting units.

The following table presents pro forma net income, basic earnings per share and diluted earnings per share as if SFAS 142 had been adopted at the beginning of fiscal 2001.

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2001	Net Income		Basic EPS		Diluted EPS
	(Millions of Dollars)
Reported	$	219.0	$	1.87	$	1.86
Pro forma	$	240.2	$	2.05	$	2.04

The following table presents the details of our identifiable intangible assets which are included on the consolidated balance sheets in “Other Assets”.


	Gross Value		Accumulated Amortization		Net Book Value
	(Millions of Dollars)
December 31, 2003
Total amortizable intangible assets	$	21.6	$	7.8	$	13.8
Total non-amortizable intangible assets		54.8		2.1		52.7

Total intangible assets	$	76.4	$	9.9	$	66.5

December 31, 2002
Total amortizable intangible assets	$	21.3	$	6.2	$	15.1
Total non-amortizable intangible assets		54.7		2.1		52.6

Total intangible assets	$	76.0	$	8.3	$	67.7

The amount of amortization expense included in operating income for identifiable intangibles was $1.6 million for 2003 and 2002 and $2.9 million in 2001. We estimated that our future annual intangible amortization expense will be $1.6 million per year for the years 2004 through 2006 and $1.2 million for the years 2007 through 2008.

The following table presents the changes in our goodwill during fiscal 2003:


Reporting Unit	Balance at Dec 31, 2002		Acquired		Adjustments (a)		Balance at Dec 31, 2003
	(Millions of Dollars)
Utility Energy	$	442.9	$	—	$	—	$	442.9
Manufacturing		390.2		—		2.8		393.0

	$	833.1	$	—	$	2.8	$	835.9

(a)	The adjustment for our manufacturing reporting unit includes $1.7 million of purchase accounting adjustments and $1.1 million of currency translation adjustments.

J — TRUST PREFERRED SECURITIES

In March 1999, WEC Capital Trust I, a Delaware business trust of which we own all of the outstanding common securities, issued $200 million of 6.85% trust preferred securities to the public. The sole asset of WEC Capital Trust I is $206.2 million of 6.85% junior subordinated debentures issued by us and due March 31, 2039. The terms and interest payments on these debentures correspond to the terms and distributions on the trust preferred securities. WEC Capital Trust I had been consolidated into our financial statements prior to adoption of Interpretation 46. For further information on adoption of Interpretation 46 see Note B above.

Prior to December 31, 2003, we treated WEC Capital Trust I as a subsidiary of ours and consolidated its accounts into our financial statements. The Trust Preferred Securities were presented as a separate line item in our balance sheets and we reported distributions on the Trust Preferred Securities as an expense.

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In December 2003, the FASB issued a revised version of Interpretation 46, Consolidation of Variable Interest Entities. This standard requires an enterprise that is the primary beneficiary of a variable interest entity to consolidate that entity. Interpretation 46 became effective in the first reporting period ending after December 15, 2003 for entities commonly referred to as special-purpose entities.

We determined that WEC Capital Trust I is a special-purpose entity that falls under the scope of Interpretation 46 but that we are not the primary beneficiary of the trust. As a result, we discontinued consolidating WEC Capital Trust I’s financial statements effective December 31, 2003. See Note B for information on the impacts to our financial statements.

For tax purposes, we are allowed to deduct an amount equal to the distributions on the trust preferred securities. We may elect to defer interest payments on the debentures for up to 20 consecutive quarters, causing corresponding distributions on the trust preferred securities to also be deferred. In case of a deferral, interest and distributions will continue to accrue, along with quarterly compounding interest on the deferred amounts.

We called all of the $200 million of trust preferred securities in February 2004. We have entered into a limited guarantee of payment of distributions, redemption payments and payments in liquidation with respect to the trust preferred securities. This guarantee, when considered together with our obligations under the related debentures and indenture and the applicable declaration of trust, provide a full and unconditional guarantee by us of amounts due on the outstanding trust preferred securities.

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K — 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	$	144.9
2005		87.3
2006		756.8
2007		2.0
2008		347.0
Thereafter		2,222.2

Total	$	3,560.2

Sinking fund requirements for the years 2004 through 2008, included in the preceding table, are $9.0 million. Substantially all of Wisconsin Electric’s 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 March 2003, we sold $200 million of unsecured 6.20% Senior Notes due April 1, 2033. These securities were issued under a shelf registration statement filed with the SEC. The proceeds of the offering were used to repay a portion of our outstanding commercial paper as it matured.

In May 2003, Wisconsin Electric 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. Wisconsin Electric 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 Wisconsin Electric’s debt securities in June 2003 and to fund the early redemption in August 2003 of another $60 million debt issue.

In October 2003, Wisconsin Electric funded the early redemption of $9 million of 6.85% First Mortgage Bonds.

In December 2003, Wisconsin Gas sold $125 million of unsecured 5.20% debentures due 2015. These securities were issued under an existing $200 million shelf registration statement filed with the SEC. The proceeds of the offering were used to repay short-term debt.

In January 2002, we redeemed $100 million of 8-3/8% first mortgage bonds due 2026 and $3.4 million of 9¹/8% first mortgage bonds due 2024. Early redemption of this long-term debt was financed through the issuance of short-term commercial paper.

Obligations Under Capital Leases: In 1997, Wisconsin Electric 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, Wisconsin Electric may, at its 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 - other property related - capital lease in Note A). Due to the timing of

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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 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.

Wisconsin Electric also has 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 Wisconsin Electric or the Trust terminates the lease, the Trust would recover its unamortized cost of nuclear fuel from Wisconsin Electric. Under the lease terms, Wisconsin Electric is 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 Wisconsin Electric’s 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

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

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L — 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
Domestic subsidiaries	$	—	—	%	$	50.0	1.29	%
Foreign subsidiaries		19.1	3.05	%		24.5	3.71	%
Commercial paper		590.8	1.18	%		878.6	1.46	%

	$	609.9	1.24	%	$	953.1	1.51	%

On December 31, 2003, we had approximately $1.2 billion of available unused lines of bank back-up credit facilities on a consolidated basis. We had approximately $610 million of total consolidated short-term debt outstanding on such date. Our bank back-up credit facilities mature beginning April 2004 through April 2006.

Wisconsin Energy, Wisconsin Electric and Wisconsin Gas have entered into various bank back-up credit agreements to maintain short-term credit liquidity which, among other terms, require the companies to maintain a minimum total funded debt to capitalization ratio of less than 70%, 65% and 65%, respectively.

Wisconsin Energy’s bank back-up credit facilities require us to maintain a minimum ratio of consolidated EBITDA to consolidated interest expense. For the twelve months ended December 31, 2003 we were in compliance.

M— DERIVATIVE INSTRUMENTS

We follow SFAS 133, 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.

Wisvest-Connecticut LLC, a wholly-owned subsidiary of Wisvest, which was sold December 6, 2002, had fuel oil contracts utilized to mitigate the commodity risk associated with generation costs. These contracts were defined as derivatives under SFAS 133 and did not qualify or were not designated for hedge accounting treatment. For the year ended December 31, 2002, we recorded non-cash, after tax income of $12.7 million or $0.11 per share to reflect the changes in fuel oil prices during the year and the settlement of transactions. For the year ended December 31, 2001, our adoption of SFAS 133 resulted in an increase in net income of $10.5 million or $0.09 per share reported as a cumulative effect of a change in accounting principle and a subsequent recording of a non-cash, after tax charge of $22.4 million or $0.20 per share to reflect the change in oil prices and the settlement of transactions during 2001.

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 the underlying transaction occurs, the amounts in Accumulated Other Comprehensive Income are reported in 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 as of December 31, 2003 was four months, and as of December 31, 2002 was seven months.

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We adopted SFAS 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, effective July 1, 2003. SFAS 149, which was issued by the FASB in April 2003, amends Statement 133 for certain decisions made by FASB dealing with financial instruments. This Statement also amends Statement 133 to incorporate clarifications of the definition of a derivative. Upon adoption of SFAS 149 prospectively any forward commodity contracts, other than electric power contracts that meet the qualification of a capacity contract, that are subject to unplanned netting, qualify as derivatives and any changes in fair value of the derivative is 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.

During March 2003, we settled several treasury lock agreements entered into earlier in the quarter and during the third-quarter of 2002 to mitigate interest risk associated with the issuance of $200 million of long-term unsecured senior notes in March 2003. As these agreements qualified for cash flow hedging accounting treatment under FAS 133, the payment made upon settlement of these agreements is deferred in Accumulated Other Comprehensive Income and will be amortized as an increase to Interest expense over the same period in which the interest cost is recognized in income.

We reclassified $0.8 million in treasury lock agreement settlement payments deferred in Accumulated Other Comprehensive Income, as an increase to Interest expense for the year ended December 31, 2003. We estimate that during the next twelve months, $0.9 million will be reclassified from Accumulated Other Comprehensive Income as a reduction in earnings. We reclassified $0.7 million to interest expense for the year ended December 31, 2002.

N — 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
Trust preferred securities	$	—	$	—	$	200.0	$	201.0
Long-term debt including current portion	$	3,560.2	$	3,703.7	$	2,888.2	$	3,042.3

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 F). The fair value of our preferred stock is estimated based upon the quoted market value for the same or similar issues. Our Trust Preferred Securities had been consolidated into our financial statements prior to adoption of Interpretation 46 (see Note B and Note J). 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.

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O — 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.


	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	$	1,079.4		$	1,035.8		$	998.5		$	348.3		$	279.9		$	244.7
Service cost		32.4			23.6			23.9			11.0			8.2			6.8
Interest cost		72.2			73.0			73.7			23.6			21.1			18.7
Plan participants’ contributions		—			—			—			1.4			7.4			6.0
Plan amendments		20.1			(1.2	)		0.2			5.1			2.3			—
Actuarial loss		38.5			38.4			20.5			15.5			54.6			25.5
Acquisitions / divestitures		—			(20.3	)		—			—			(1.9	)		—
Benefits paid		(63.8	)		(69.9	)		(81.0	)		(17.5	)		(23.3	)		(21.8	)

Benefit Obligation at December 31	$	1,178.8		$	1,079.4		$	1,035.8		$	387.4		$	348.3		$	279.9

Change in Plan Assets
Fair Value at January 1	$	861.2		$	1,062.7		$	1,224.8		$	137.8		$	148.8		$	149.8
Actual earnings (loss) on plan assets		196.7			(127.5	)		(83.4	)		24.7			(11.1	)		(0.9	)
Employer contributions		2.3			7.9			2.3			20.4			17.2			15.7
Plan participants’ contributions		—			—			—			1.4			7.4			6.0
Acquisitions / divestitures		—			(12.0	)		—			—			(1.2	)		—
Benefits paid		(63.8	)		(69.9	)		(81.0	)		(17.5	)		(23.3	)		(21.8	)

Fair Value at December 31	$	996.4		$	861.2		$	1,062.7		$	166.8		$	137.8		$	148.8

Funded Status of Plans
Funded status at December 31	$	(182.3	)	$	(218.1	)	$	26.9		$	(220.6	)	$	(210.4	)	$	(131.1	)
Unrecognized
Net actuarial loss		328.8			402.6			142.2			130.4			136.8			63.6
Prior service cost		38.2			22.9			27.3			6.9			2.4			0.3
Net transition (asset) obligation		(2.3	)		(4.6	)		(6.9	)		14.2			15.8			17.4

Net Asset (Accrued Benefit Cost)	$	182.4		$	202.8		$	189.5		$	(69.1	)	$	(55.4	)	$	(49.8	)

Amounts recognized in the Balance Sheet consist of:
Prepaid benefit cost	$	51.4		$	43.4		$	229.9		$	49.9		$	49.7		$	47.5
Accrued benefit cost		(60.9	)		(38.9	)		(40.4	)		(119.0	)		(105.1	)		(97.3	)
Minimum liability		(34.7	)		(113.5	)		—			—			—			—
Intangible asset		37.2			23.3			—			—			—			—
Regulatory asset (See Note A)		189.4			288.5			—			—			—			—

Net amount recognized at end of year	$	182.4		$	202.8		$	189.5		$	(69.1	)	$	(55.4	)	$	(49.8	)

The accumulated benefit obligation for all defined benefit plans was $1,080.5 million and $997.1 million at December 31, 2003 and 2002, respectively.

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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	$	1,083.7		$	995.4
Accumulated benefit obligation	$	997.1		$	939.7
Fair value of plan assets	$	926.9		$	802.1

Additional Information	2003			2002
	(Millions of Dollars)
Increase (decrease) in minimum liability included in a combination of other comprehensive income and regulatory assets	$	(78.8	)	$	113.5

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


	Pension Benefits									Other Post-retirement Benefits
Benefit Plan Cost Components	2003			2002			2001			2003			2002			2001
	(Millions of Dollars)
Net Periodic Benefit Cost (Income)
Service cost	$	32.4		$	23.6		$	23.9		$	11.0		$	8.2		$	6.8
Interest cost		72.2			73.0			73.7			23.6			21.1			18.7
Expected return on plan assets		(94.5	)		(101.1	)		(105.0	)		(11.6	)		(12.6	)		(13.0	)
Amortization of:
Transition (asset) obligation		(2.3	)		(2.3	)		(2.3	)		1.6			1.6			1.6
Prior service cost		4.9			3.4			3.5			0.7			0.2			0.1
Actuarial loss (gain)		4.6			3.5			1.1			8.8			4.7			1.5

Net Periodic Benefit Cost (Income)	$	17.3		$	0.1		$	(5.1	)	$	34.1		$	23.2		$	15.7

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		4.0 to 5.0			4.0 to 5.0			4.0 to 5.0			4.0 to 5.0			4.0 to 5.0			4.0 to 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 5.0			4.0 to 5.0			3.0 to 5.0			4.0 to 5.0			4.0 to 5.0			3.0 to 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.

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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.

Effective 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 the utility customers of Wisconsin Electric, Wisconsin Gas and Edison Sault. Wisconsin Gas and Edison Sault have recorded deferred regulatory assets, which are being amortized over a twenty-year period effective January 1, 1992, for the cumulative difference between the amounts funded and SFAS 106 post-retirement expenses through January 1, 1992.

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. 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	$	29.1	$	(25.9	)
Total of service and interest cost components	$	3.6	$	(3.1	)

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.

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 plans. 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 Allocation 2004		Percentage of Pension Plans Assets at December 31
Asset Category	Target Allocation 2004		2003		2002
Equity Securities	72	%	76	%	72	%
Debt Securities	28	%	24	%	28	%

Total	100	%	100	%	100	%

Our 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.

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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.

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 Allocation 2004		Percentage of Other Benefit Plans Assets at December 31
Asset Category	Target Allocation 2004		2003		2002
Equity Securities	47	%	48	%	44	%
Debt Securities	52	%	50	%	53	%
Other	1	%	2	%	3	%

Total	100	%	100	%	100	%

Our 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.

Cashflows:


Employer Contributions	Pension Benefits		Other Post- Retirement Benefits
	(Millions of Dollars)
2002	$	2.5	$	17.3
2003		—		20.5
2004 (Expected)		18.3		20.9

Of the $18.3 million expected to be contributed to fund pension benefits in 2004, $5.7 million is to our qualified plans and is the minimum required by law. There was no contribution made during 2003. The $2.5 million payment made in 2002 was discretionary.

The entire contribution to the other post-retirement benefit plans during 2004 is discretionary as the plans are not subject to any minimum regulatory funding requirements. The contribution is 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 $11.6 million of matching contributions during 2003, $11.3 million during 2002 and $11.5 million during 2001.

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P — GUARANTEES

Wisconsin Energy and certain subsidiaries enter into various guarantees to provide financial and performance assurance to third parties on behalf of our affiliates. As of December 31, 2003 Wisconsin Energy and subsidiaries had the following guarantees:


	Maximum Potential Future Payments		Outstanding at Dec 31, 2003		Liability Recorded at Dec 31, 2003
	(Millions of Dollars)
Wisconsin Energy
Joint venture (Energy Affiliates)	$	61.9	$	3.4	$	—
Other		2.0		2.0		—

Wisconsin Electric		223.3		—		—
Subsidiary		12.9		12.9		—

Total	$	300.1	$	18.3	$	—

Our guarantees issued in support of energy related affiliates are for obligations under commodity contracts and credit agreements between the affiliates and third parties. Failure of the affiliates to fulfill their obligations under the agreements would require our performance under the guarantees. All of the Wisconsin Energy joint venture guarantees are related to affiliates that were sold during the fourth quarter of 2003 and the guarantees are backstopped by the acquiring company until the anticipated terminations during the first quarter of 2004.

Other guarantees support obligations of our affiliates to third parties under loan agreements. In the event our affiliates fail to perform under the loan agreements, we would be responsible for the obligations.

Wisconsin Electric guarantees the potential retrospective premiums that could be assessed under Wisconsin Electric’s nuclear insurance program (See Note F).

Subsidiary guarantees support loan obligations between our affiliates and third parties. In the event the loan obligations are not performed, our subsidiary would be responsible for the obligations.

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 $6.7 million.

Q — SEGMENT REPORTING

Our reportable operating segments include a utility energy segment, a manufacturing segment, and a non-utility energy segment. We have organized our reportable operating segments based in part upon the regulatory environment in which our utility subsidiaries operate. In addition, the segments are managed separately because each business requires different technology and marketing strategies. The accounting policies of the reportable operating segments are the same as those described in Note A.

Our utility energy segment primarily includes our electric and natural gas utility operations. Our electric utility operation 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 operation is engaged in the purchase, distribution and sale of natural gas to retail customers and the transportation of customer-owned natural gas throughout Wisconsin. Our manufacturing segment is engaged in the manufacturing of pumps and processing equipment used to pump, control, transfer, hold and filter water and other fluids. Our non-utility energy segment derives its revenues primarily from economic interests in other energy-related entities as well as independent power production.

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. The 2003 and 2002 information is not comparable to 2001 due to the adoption of SFAS 142 (See Note I), which eliminated the amortization of goodwill. The segment information below also includes the elimination of $305 million of intercompany notes between the Utility Energy Segment and Corporate in December 2001, and non-cash impairment charges of $45.6 million ($29.7 million after tax or $0.25 per share) in 2003 and $141.5 million ($92.0 million after tax or $0.79 per share) in 2002, primarily related to the Non-Utility Energy Segment (See Note D). Substantially all of our long-lived assets and operations are domestic.

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	Reportable Operating Segments							Other (a), Corporate & Reconciling Eliminations (b)			Total Consolidated
	Energy
Year Ended	Utility		Non-Utility			Manufacturing
	(Millions of Dollars)
December 31, 2003

Operating Revenues (b)	$	3,263.9	$	14.4		$	746.1	$	29.9		$	4,054.3
Depreciation, Decommissioning and Amortization (c)	$	316.2	$	7.4		$	2.6	$	6.1		$	332.3
Operating Income (Loss)	$	544.1	$	(61.5	)	$	66.9	$	1.3		$	550.8
Equity in Earnings (Losses) of Unconsolidated Affiliates	$	25.9	$	(8.9	)		—	$	5.2		$	22.2
Net Income (Loss)	$	294.1	$	(52.7	)	$	30.8	$	(27.9	)	$	244.3
Capital Expenditures (d)	$	455.6	$	163.6		$	10.4	$	29.8		$	659.4
Total Assets	$	8,315.1	$	397.6		$	937.0	$	376.0		$	10,025.7

December 31, 2002

Operating Revenues (b)	$	2,852.1	$	167.2		$	685.2	$	31.7		$	3,736.2
Depreciation, Decommissioning and Amortization (c)	$	308.3	$	5.1		$	2.0	$	5.2		$	320.6
Operating Income (Loss)	$	562.1	$	(132.0	)	$	56.2	$	(28.3	)	$	458.0
Equity in Earnings (Losses) of Unconsolidated Affiliates	$	23.4	$	(8.5	)		—	$	8.0		$	22.9
Net Income (Loss)	$	295.2	$	(94.4	)	$	24.0	$	(57.8	)	$	167.0
Capital Expenditures (d)	$	405.4	$	92.7		$	15.0	$	43.7		$	556.8
Total Assets	$	7,832.2	$	348.7		$	924.5	$	372.2		$	9,477.6

December 31, 2001

Operating Revenues (b)	$	2,964.8	$	337.3		$	585.1	$	41.3		$	3,928.5
Depreciation, Decommissioning and Amortization (c)	$	320.1	$	1.7		$	13.0	$	7.3		$	342.1
Operating Income (Loss)	$	534.9	$	36.2		$	41.1	$	(7.3	)	$	604.9
Equity in Earnings (Losses) of Unconsolidated Affiliates	$	23.4	$	3.3			—	$	(0.7	)	$	26.0
Cumulative Effect of Change in Accounting Principle, Net		—	$	10.5			—		—		$	10.5
Net Income (Loss)	$	274.4	$	18.7		$	9.7	$	(83.8	)	$	219.0
Capital Expenditures (d)	$	428.7	$	127.7		$	27.1	$	89.0		$	672.5

(a)	Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark and non-utility investment in renewable energy and recycling technologies by Minergy as well as interest on corporate debt.

(b)	Intersegment revenues are not material. An elimination is included in Operating Revenues of $3.7 million, $3.1 million and $3.9 million for 2003, 2002 and 2001, respectively.

(c)	The total manufacturing depreciation expense for 2003, 2002 and 2001 was $21.6 million, $23.9 million and $32.6 million, respectively, the majority of which is recorded in cost of goods sold for reporting purposes.

(d)	Excludes acquisitions.

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R — RELATED PARTIES

American Transmission Company: We have a 39.4% interest in ATC, a regional transmission company established in 2000 under Wisconsin legislation. During 2003, 2002 and 2001, we paid ATC $94.4 million, $87.3 million and $72.9 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.

Guardian Pipeline: We have a one third ownership interest in Guardian Pipeline, L.L.C., which owns and operates an interstate natural gas pipeline. Wisconsin Gas has committed to purchase 650,000 dekatherms per day of capacity (approximately 88% of the pipeline’s total capacity) under the terms of a 10 year transportation agreement. Guardian began deliveries to Wisconsin Gas in December 2002.

S — 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 $699.2 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	$	48.4
2005		45.9
2006		45.3
2007		44.1
2008		29.3
Thereafter		89.0

Total	$	302.0

Giddings & Lewis, Inc./City of West Allis Lawsuit: During 2002, Wisconsin Electric 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, Wisconsin Electric paid $17.3 million as full and final settlement of all damage claims against Wisconsin Electric. These settlements resulted in a 2002 charge of approximately $0.09 per share 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 does not constitute an admission of liability or wrongdoing by Wisconsin Electric with respect to any released claims.

In September 2002, Wisconsin Electric filed a lawsuit against its insurance carriers to recover those costs and expenses associated with this matter. As of December 31, 2003, Wisconsin Electric had 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.

Product Liability: Our manufacturing business is a party to certain legal proceedings arising in the normal course of business. Management believes that the outcome of these proceedings, individually and in the aggregate, will not have a material effect on us or our consolidated financial position, results of operations or cash flows.

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.

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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 previously used by Wisconsin Electric or Wisconsin Gas, and coal ash disposal/landfill sites used by Wisconsin Electric, 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 identified fourteen sites at which Wisconsin Electric, Wisconsin Gas, or a predecessor company historically owned or operated a manufactured gas plant. We have completed planned remediation activities at four of those 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-$52 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 $29.9 million related to future remediation costs.

The PSCW has allowed Wisconsin utilities, including Wisconsin Electric and Wisconsin Gas, 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: Wisconsin Electric aggressively seeks environmentally acceptable, beneficial uses for its 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 Wisconsin Electric has 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 the fuel costs of Wisconsin Electric. During 2003, 2002 and 2001, Wisconsin Electric 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.

Manufacturing Segment: Our manufacturing subsidiaries are involved in various environmental matters, including matters in which the subsidiaries or alleged predecessors have been named as potentially responsible parties under the Comprehensive Environmental Response Compensation and Liability Act. We have established reserves for all of these environmental contingencies of which management is currently aware in “Other Current Liabilities” in the Consolidated Balance Sheets.

EPA Information Requests: Wisconsin Electric 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, Wisconsin Electric and EPA announced that a consent decree had been reached which resolved all issues related to this matter. Under the consent decree, Wisconsin Electric will significantly reduce its air emissions from its 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, Wisconsin Electric will spend between $20 million and $25 million to conduct a research project at its 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 Power the Future plan. Wisconsin Electric 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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T — SUBSEQUENT EVENT - AGREEMENT TO SELL THE MANUFACTURING SEGMENT

On February 4, 2004 we announced that we had reached an agreement to sell our manufacturing business to Pentair, Inc. for $850 million in cash. In addition, Pentair will assume approximately $25 million of third party debt. This sale is subject to standard regulatory approvals and is expected to close in the second or third quarter of 2004. When the sale is completed, we expect to realize net cash proceeds of approximately $740 million after the payment of taxes and transaction costs. Additionally, beginning with the first quarter 2004 financial statements, we will begin reporting our manufacturing business as discontinued operations.

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LOGO

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Stockholders of Wisconsin Energy Corporation:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Wisconsin Energy Corporation and its subsidiaries (the “Company”) 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 consolidated financial statements of the Company for the year ended December 31, 2001, prior to the addition of the transitional disclosures discussed in Note I, were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statements, and included an explanatory paragraph relating to the change in accounting for derivatives effective January 1, 2001, 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 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 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 the Company at December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.

As described in Note I, on January 1, 2002, the Company adopted Statement of Financial Accounting Standards (Statement) No. 142, “Goodwill and Other Intangible Assets.” As described in Note H, on January 1, 2003, the Company adopted Statement No. 143, “Accounting for Asset Retirement Obligations.”

As discussed above, the consolidated financial statements of the Company for the year ended December 31, 2001, were audited by other auditors who have ceased operations. As described in Note I, these financial statements have been revised to include the transitional disclosures required by Statement No. 142, which was adopted by the Company as of January 1, 2002. Our audit procedures with respect to the disclosure in Note I, included (a) agreeing the previously reported net income to the previously issued financial statements and the adjustments to reported net income representing amortization expense (including any related tax effects) recognized in those periods related to goodwill, intangible assets that are no longer being amortized and changes in amortization periods for intangible assets that will continue to be amortized as a result of initially applying Statement No. 142 (including any related tax effects) to the Company’s underlying records obtained from management, and (b) testing the mathematical accuracy of the reconciliation of adjusted net income to reported net income, and the related earnings per share amounts. In our opinion, the disclosures for 2001 in Note I are appropriate. However, we were not engaged to audit, review, or apply any procedures to the 2001 consolidated financial statements of the Company other than with respect to such disclosures and, accordingly, we do not express an opinion or any other form of assurance on the 2001 consolidated financial statements taken as a whole.

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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. In fiscal 2002, we adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). As discussed in Note I of the Notes to Consolidated Financial Statements, we have presented the transitional disclosures for fiscal 2001 required by SFAS 142. The Arthur Andersen LLP report does not extend to these transitional disclosures. These disclosures are reported on by Deloitte & Touche LLP as stated in their report appearing herein.

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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors and Stockholders of Wisconsin Energy Corporation:

We have audited the accompanying consolidated balance sheet and consolidated statement of capitalization of Wisconsin Energy Corporation and its subsidiaries as of December 31, 2001, and the related consolidated 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Wisconsin Energy Corporation and its subsidiaries as of December 31, 2001, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States.

As described in Note K, on January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.”

LOGO

Arthur Andersen LLP

Milwaukee, Wisconsin

February 5, 2002

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MARKET FOR REGISTRANT’S COMMON

EQUITY AND RELATED STOCKHOLDER MATTERS

NUMBER OF COMMON STOCKHOLDERS

As of December 31, 2003, based upon the number of Wisconsin Energy Corporation stockholder accounts (including accounts in our dividend reinvestment and stock purchase plan), we had 61,400 registered stockholders.

COMMON STOCK LISTING AND TRADING

Our common stock is listed on the New York Stock Exchange. The ticker symbol is “WEC”. Daily trading prices and volume can be found in the “NYSE Composite” section of most major newspapers, usually abbreviated as WI Engy.

DIVIDENDS AND COMMON STOCK PRICES

Common Stock Dividends of Wisconsin Energy: Cash dividends on our common stock, as declared by the board of directors, are normally paid on or about the first day of March, June, September and December. We review our dividend policy on a regular basis. Subject to any regulatory restrictions 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.

On February 4, 2004, our Board of Directors announced that it increased our common stock quarterly dividend rate by 5%, to $0.21 per share. With the increase, the new annual dividend rate will be $0.84 per share. In addition, the Board announced that it has established a goal of increasing the annual dividend at a rate of approximately half of the expected rate of growth in earnings, subject to the factors referred to above.

Range of Wisconsin Energy Common Stock Prices and Dividends:


	2003						2002
Quarter	High		Low		Dividend		High		Low		Dividend
First	$	26.60	$	22.56	$	0.20	$	25.49	$	22.07	$	0.20
Second	$	29.75	$	25.00		0.20	$	26.48	$	24.60		0.20
Third	$	30.75	$	26.54		0.20	$	26.16	$	20.17		0.20
Fourth	$	33.68	$	30.63		0.20	$	25.30	$	21.20		0.20

Year	$	33.68	$	22.56	$	0.80	$	26.48	$	20.17	$	0.80

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BUSINESS OF THE COMPANY

Wisconsin Energy Corporation was incorporated in the state of Wisconsin in 1981 and became a diversified holding company in 1986. We maintain our principal executive offices in Milwaukee, Wisconsin. We conduct our operations primarily in three operating segments: a utility energy segment, a non-utility energy segment and a manufacturing segment. Our primary subsidiaries are Wisconsin Electric Power Company (Wisconsin Electric), Wisconsin Gas Company (Wisconsin Gas) and WICOR Industries, LLC, formerly WICOR Industries, Inc., (WICOR Industries).

Utility Energy Segment: Our utility energy segment consists of: Wisconsin Electric, which serves approximately 1,068,000 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 428,700 gas customers in Wisconsin and approximately 460 steam customers in metro Milwaukee, Wisconsin; Wisconsin Gas, which serves approximately 569,500 gas customers in Wisconsin and about 2,600 water customers in suburban Milwaukee, Wisconsin; and Edison Sault Electric Company (Edison Sault), which serves approximately 22,000 electric customers in the Upper Peninsula of Michigan. In April 2002, Wisconsin Electric and Wisconsin Gas began doing business under the trade name of “We Energies”.

Non-Utility Energy Segment: Our non-utility energy segment consists of W.E. Power, LLC (We Power) and Wisvest Corporation (Wisvest). We Power was formed in 2001 to design, construct, own, finance and lease the new generating capacity included in our Power the Future strategy. See Management’s Discussion and Analysis of Financial Condition and Results of Operations for more information on Power the Future. Wisvest owns and has investments in electric generating facilities and other energy-related entities and assets. We are in the process of reducing the operations of Wisvest.

Manufacturing Segment: Our manufacturing segment consists of WICOR Industries, an intermediary holding company, and its three primary subsidiaries: Sta-Rite Industries, LLC (Sta-Rite), SHURflo, LLC (SHURflo) and Hypro, LLC (Hypro), which are manufacturers of pumps, water treatment products and fluid handling equipment with manufacturing, sales and distribution facilities in the United States and several other countries. In February 2004, we announced that we reached an agreement to sell this segment to Pentair, Inc. for $850 million and the assumption of approximately $25 million of debt. Subject to regulatory approvals, we expect the sale to close during the second or third quarter of 2004. For further information about the sale see “Capital Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

For additional financial information about Wisconsin Energy’s operating segments, see “Note Q —Segment Reporting” in the Notes to Consolidated Financial Statements.

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DIRECTORS AND EXECUTIVE OFFICERS

DIRECTORS

The information under “Proposal 1: Election of Directors - Terms Expiring in 2007” in Wisconsin Energy Corporation’s definitive proxy statement dated March 16, 2004, attached hereto, is incorporated herein by reference.

EXECUTIVE OFFICERS

Richard A. Abdoo, Chairman of the Board and Chief Executive Officer of Wisconsin Energy and Chairman of the Board of Wisconsin Electric and Wisconsin Gas, has indicated his intention to retire from all officer and director positions with Wisconsin Energy and its subsidiaries, and to retire as an employee, effective as of April 30, 2004. Gale E. Klappa, currently President of Wisconsin Energy and President and Chief Executive Officer of Wisconsin Electric and Wisconsin Gas, has been appointed to the officer positions held by Mr. Abdoo. Accordingly, effective as of May 1, 2004, Mr. Klappa will hold the titles of Chairman of the Board, President and Chief Executive Officer of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas.

In addition, James C. Donnelly has indicated his intention to retire from all officer and director positions with Wisconsin Energy and its subsidiaries, and to retire as an employee of WICOR Industries, effective as of May 1, 2004.

Richard A. Abdoo

•	Chairman of the Board and Chief Executive Officer of Wisconsin Energy Corporation; Chairman of the Board of Wisconsin Electric Power Company and Wisconsin Gas Company

Charles R. Cole

•	Senior Vice President of Wisconsin Electric Power Company

Stephen P. Dickson

•	Controller of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas Company

James C. Donnelly

•	Vice President of WICOR, Inc.

•	President and Chief Executive Officer of WICOR Industries, LLC

Gale E. Klappa

•	President of Wisconsin Energy Corporation, President and Chief Executive Officer of Wisconsin Electric Power Company and Wisconsin Gas Company

Frederick D. Kuester

•	Chief Operating Officer of Wisconsin Electric Power Company

Allen L. Leverett

•	Chief Financial Officer of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas Company

Larry Salustro

•	Senior Vice President and General Counsel of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas Company

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Printed on recycled paper


		9341-PS-04
231 W. Michigan Street, P.O. Box 2949, Milwaukee, WI 53201 1-800-558-9663 www. WisconsinEnergy.com		2K4PS-RRD-120

LOGO

YOUR VOTE IS IMPORTANT

VOTE BY INTERNET / TELEPHONE

24 HOURS A DAY, 7 DAYS A WEEK

INTERNET

TELEPHONE

MAIL

https://www.proxyvotenow.com/wec

• Go to the website address listed
above.

• Have your proxy card ready.

• Follow the simple instructions that

appear on your computer screen.

1-866-756-9925

• Use any touch-tone telephone.
• Have your proxy card ready.
• Follow the simple recorded
instructions.

• Mark, sign and date your proxy card.
• Detach your proxy card.
• Return your proxy card in the
postage-paid envelope provided.

Your vote is important.

Please vote immediately.

Ú DETACH PROXY CARD HERE IF YOU ARE NOT VOTING BY TELEPHONE OR INTERNET Ú

Please Sign, Date and Return

the Proxy Card Promptly

Using the Enclosed Envelope.

Votes must be indicated

(x) in Black or Blue ink.

The Board of Directors recommends a vote “FOR” Items 1 and 2.

1. Election of Directors

Where no voting instructions are given, the shares represented by your proxy will be voted “FOR” Items 1 and 2.

FOR

ALL

WITHHOLD

FOR ALL

EXCEPTIONS

Check here if you plan to attend the annual meeting.

Nominees: 01 - Robert A. Cornog, 02 - Gale E. Klappa, 03 - Frederick P. Stratton, Jr.

To change your address, please mark this box.

(INSTRUCTIONS: To withhold authority to vote for any individual nominee, strike

a line through that nominee’s name and check the “Exceptions” box above.)

To include any comments, please mark this box.

FOR

AGAINST

ABSTAIN

2. Approve amending the Bylaws to declassify the

Board and allow for annual election of all Directors.

Please sign exactly as name(s) appear hereon. Joint owners should each sign personally. When signing as executor, administrator, corporation officer, attorney, agent, trustee, guardian or in other representative capacity, please state your full title as such.

Date Shareholder sign here Co-owner sign here


Wisconsin Energy Corporation Annual Meeting of Stockholders Wednesday, May 5, 2004 10:00 a.m. Central Time Wisconsin Exposition Center State Fair Park 8200 W. Greenfield Avenue West Allis, WI 53214
If you plan to attend in person, please check the box on the reverse side and bring this card with you to the meeting.

Name


Address

Wisconsin Energy Corporation

Proxy / Voting Instructions for the Annual Meeting of Stockholders

May 5, 2004

This PROXY is solicited by the Board of Directors for use at the Annual Meeting of Stockholders on May 5, 2004. Your shares of stock will be voted as you specify on the reverse side of this card. If no choice is specified, your PROXY will be voted “For” Items 1 and 2, and in the discretion of the proxy holder, on any other matter which may properly come before the Annual Meeting of Stockholders and all adjournments or postponements of the meeting.

By signing this PROXY, you revoke all prior proxies and appoint Larry Salustro and Kristine A. Rappe, or either of them, as proxies, with the power to appoint substitutes, to vote your shares on the matters shown below and on any other matters which may properly come before the Annual Meeting of Stockholders and all adjournments or postponements of the meeting.

1. Elect Robert A. Cornog, Gale E. Klappa and Frederick P. Stratton, Jr. as Directors.

2. Approve amending the Bylaws to eliminate the classification of the Board and allow for annual election of all Directors.

If you hold Wisconsin Energy Corporation common shares in Wisconsin Energy Corporation’s Stock Plus Investment Plan or a 401(k) plan under the Wisconsin Energy Corporation Master Trust, this proxy constitutes voting instructions for any shares so held by the undersigned.

WISCONSIN ENERGY CORPORATION

P.O. BOX 11468

NEW YORK, N.Y. 10203-0468

SEE REVERSE SIDE. We encourage you to vote by telephone or the Internet. However, if you wish to vote by mail, just complete, sign and date the reverse side of this card. If you wish to vote in accordance with the Board of Directors’ recommendations, you need not mark any voting boxes.