ML051090201

in Accordance with 10 C.F.R. Section 50.71, Enclosed Is the 2004 Annual Report to Stockholders of Wisconsin Electric Power Company, Which Includes Certified Financial Statements

ML051090201
Person / Time
Site:	Point Beach
Issue date:	03/21/2005
From:	Ecke K We Energies
To:	Document Control Desk, Office of Nuclear Reactor Regulation
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Download: ML051090201 (88)

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weenergies 231 W.Michigan St.

Milwaukee, WI 53290-0001 www.we-energies.com March 21, 2005 Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Document Control Desk:

In accordance with 10 C.F.R. Section 50.71, enclosed is the 2004 annual report to stockholders of Wisconsin Electric Power Company, which includes certified financial statements. Such annual report accompanies Wisconsin Electric's definitive information statement, which is being mailed to stockholders today.

Wisconsin Electric Power Company is the holder of Facility Operating License Nos.

DPR-24 and DPR-27 issued by your Commission under Dockets 50-266 and 50-301, respectively.

Sincerely,

&ith H. Ecke Assistant Corporate Secretary Enclosure cc: U.S. Nuclear Regulatory Commission John O'Neill, Jr.

Region III Shaw Pittman LLP 2443 Warrenville Road 2300 N. Street, N.W.

Lisle, IL 60532-4352 Washington, DC 20037 Michael Morris, NRC Resident Inspector Ryan Moran A. William Finke Michael B. Sellman j:\data\ca\compl iance\proxy\2005\2005nrcItr.ddc

we energies Gale E. Klappa Chairman, President and Chief Executive Officer 231 W Michigan Street Milwaukee, WI 53203 March 21, 2005

Dear Stockholder:

Wisconsin Electric Power Company, which does business under the trade name of We Energies, will hold its Annual Meeting of Stockholders on Friday, April 29, 2005, at 10:00 a.m. in Conference Room P 140A of the Public Service Building, 231 West Michigan Street, Milwaukee, Wisconsin. We are not soliciting proxies for this meeting, as over 99% of the voting stock is owned, and will be voted, by Wisconsin Electric Power Company's parent firm, Wisconsin Energy Corporation. If you wish, you may vote your shares of preferred stock in person at the meeting; however, the business session will be very brief.

As an alternative, you might consider attending Wisconsin Energy Corporation's Annual Meeting of Stockholders to be held Thursday, May 5, 2005, at 10:00 a.m. at Concordia University Wisconsin in the R. John Buuck Field House, 12800 North Lake Shore Drive, Mequon, Wisconsin. By attending this meeting, you would have the opportunity to meet many of the Wisconsin Electric Power Company officers and directors. Although you cannot vote your shares of Wisconsin Electric Power Company preferred stock at the Wisconsin Energy Corporation meeting, you may find the activities worthwhile. Of course, you would be asked to register before entering the meeting.

The annual report to stockholders accompanies this information statement. If you have any questions or would like a copy of the Wisconsin Energy Corporation summary annual report, please call our toll-free stockholder hotline at 1-800-881-5882.

Thank you for your support.

Sincerely,

NOTICE OF ANNUAL MEETING OF STOCKHOLDERS March 21, 2005 To the Stockholders of Wisconsin Electric Power Company:

The 2005 Annual Meeting of Stockholders of Wisconsin Electric Power Company will be held on Friday, April 29, 2005, at 10:00 a.m. in Conference Room P140A at the Public Service Building, 231 West Michigan Street, Milwaukee, Wisconsin, for the following purposes:

1. To elect the Board of Directors to hold office until the 2006 Annual Meeting of Stockholders; and

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

Stockholders of record at the close of business on February 25, 2005 are entitled to vote. The following pages provide additional details about the meeting as well as other useful information.

By Order of the Board of Directors Anne K. Klisurich Vice President and Corporate Secretary

wCenergies 231 West Michigan Street Milwaukee, Wisconsin 53203 INFORMATION STATEMENT This information statement is being furnished to stockholders beginning on or about March 21, 2005, in connection with the annual meeting of stockholders of Wisconsin Electric Power Company ("WE" or the "Company") to be held on Friday, April 29, 2005 ("the Meeting"), at 10:00 a.m. in Conference Room P140A at the Public Service Building, 231 West Michigan Street, Milwaukee, Wisconsin 53203, and all adjournments or postponements of the Meeting, for the purposes listed in the preceding Notice of Annual Meeting of Stockholders. The WE annual report to stockholders accompanies this information statement.

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

VOTING SECURITIES As of February 25, 2005, WE had outstanding 44,498 shares of $100 par value Six Per Cent. Preferred Stock; 260,000 shares of $100 par value 3.60% Serial Preferred Stock; and 33,289,327 shares of common stock. Each outstanding share of each class is entitled to one vote. Stockholders of record at the close of business on February 25, 2005 will be entitled to vote at the Meeting. In order to conduct the Meeting, a majority of the outstanding shares entitled to vote must be represented at the Meeting. This is known as a "quorum." All of WE's outstanding common stock owned by Wisconsin Energy Corporation ("WEC") will be represented at the Meeting.

All of WE's outstanding common stock, representing over 99% of its voting securities, is owned by its parent company, WEC, whose principal business address is 231 West Michigan Street, Milwaukee, Wisconsin 53203. A list of stockholders of record entitled to vote at the Meeting will be available for inspection by stockholders at WE's principal business office at 231 West Michigan Street, Milwaukee, Wisconsin 53203, prior to and at the Meeting.

ELECTION OF DIRECTORS At the Meeting, there will be an election of nine directors. The individuals named below have been nominated by the WE Board of Directors (the "Board") to serve a one-year term expiring at the 2006 Annual Meeting of Stockholders and until they are re-elected or until their respective successors are duly elected and qualified. Directors of WEC also serve as the directors of WE.

Although John F. Ahearne's age exceeds the Company's age guideline for non-employee directors, the guideline permits the Board to request a director to remain on the Board. WEC's Corporate Governance Committee, who identifies and evaluates candidates for both WEC and WE, determined that Director Ahearne's expertise in the nuclear field is unique among Board members, and the Board is nominating him on that basis.

Pursuant to authority granted to the Board under the Bylaws, Curt S. Culver was elected as a director by the Board effective June 28, 2004. Willie D. Davis is not standing for re-election at the Meeting, and the Board has determined to reduce the number of directors constituting the whole Board from ten to nine.

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.

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

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Information About Nominees for Election to the Board of Directors for Terms Expiring in 2006.

Biographical information regarding each nominee is shown below. WE and Wisconsin Gas LLC are now doing business as We Energies and are wholly-owned subsidiaries of Wisconsin Energy Corporation. Effective July 28, 2004, Wisconsin Gas Company converted to a Wisconsin single member limited liability company and changed its name to Wisconsin Gas LLC. References to service as a director of Wisconsin Gas LLC below include the time each director sat as a director of its predecessor, Wisconsin Gas Company. Ages are shown as of March 21, 2005.

John F. Ahearne. Age 70.

• 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 graduaie students rand 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 since 1995. Adjunct Professor from 1996 to 2002. ' ' .I

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

Director of Wisconsin Energy Corpoirtation and Wisconsin Electric Power Company since 1994. Director of Wisconsin Gas LLC since 2000.

John F. Bergstrom. Age 58.

• Bergstrom Corporation - Chairman afid'Chief Executive Officer since 1997. President from 1974 through 1996.' Bergstro6m' '

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 LLC since 2000.

Barbara L; Bowles. Age 57.

• 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 LLC since 2000.

Robert A. Cornog. Age 64. ' ' ' '

• 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 Corpjoration'since 1993. Director of Wisconsin Electric Power Company since 1994. Director of Wisconsin Gas LLC since 2000.

Curt S. Culver. Age 52.

'MGIC investment Corporation - President and Chief Executive Officer since 2000. MGIC Investment Corporation' is the parent of Mortgage Guaranty Insurance Co'rporati6n. ' ' ' ' ' '

Mortgage Guaranty Insurance Corporation - President and Chief Executive Officer since 1999. Mortgage Guaranty Insurance Corporation is a private mortgage insurance company.

Director of MGIC Investment Corporation.

Director of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas LLC since June 2004.

Gale E. Klappa. Age 54. '

• Wisconsin Energy Corporation - Chairman of the Board and Chief Executive Officer since May 2004. President since April 2003.' ' ' ' ' ' ' ' "

• Wisconsin Electric Power Company - Chairman of the Board since May 2004. President and Chief Executive Officer since August 2003. ' ' ' ' ' ' ' ' "'

• Wisconsin Gas LLC - Chairman of the Board since May.2004. President and Chief Executive Officer since August 2003.

• Southern Company - Executive Vice President, Chief Financial Off icer and Treasurer from March 2001 to Apil 2003. Chief:

Strategic Offlicer from October 1999 to March 2001. Southern Company is a'public utility holding company serving the" southeastern United States. ' "' ' i

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

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Ulice Payne, Jr. Age 49.

Managing Member of Addison-Clifton, LLC since February 2004. Addison-Clifton, LLC provides advisory services on global trade compliance.

Milwaukee Brewers Baseball Club, Inc. - President and Chief Executive Officer from 2002 to 2003.

Foley & Lardner - Managing Partner of the law firm's Milwaukee office from May 2002 to September 2002. A partner from 1998 to 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 LLC since 2003.

Frederick P. Stratton, Jr. Age 65.

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 Baird Funds, Inc., Midwest Air Group, Inc. and Weyco Group, Inc.

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

George E. WVardeberg. Age 69.

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

• 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. Director of Wisconsin Gas LLC since 1992.

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

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CORPORATE GOVERNANCE - FREQUENTLY ASKED QUESTIONS Does WE have Yes, the WE Board of Directors follows WEC's Corporate Governance Guidelines that WEC has Corporate Governance maintained since. 1996.. These Guidelines provide a framework from which the Boaid coiiducts its Guidelines? business. WEC's Corporate Governance Committee reviews the Guidelines annually to promote continuous improvement of the Board's processes that provide effective governance over the affairs of the Company. To view the Guidelines, please refer to the "Governance" section of WEC's website at www.wisconsinenergy.com.

How are directors determined to No director qualifies as independent unless the Board affirmatively determines that the director has be independent? no mateiial relationship with the Comnpany. WEC's Corporate Governance Guidelines pro'ide that the Board should consist of at least a two-thirds majority of independent directors.

What are the Board's standards The guidelines the Board uses in determining director independence are located in Appendix A of of independence? WEC's Corporate Governance Guidelines. These' siandards of independence, which are summarized below, include those established by the New York Stock Exchange as well as a series of standards that are more comprehensive than New York Stock Exchange requirements.

To be considered by the Board as independent, the director:

• 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`vhere 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 5% or more 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. For purposes of the above discussion, "Company" refers to WEC and its subsidiaries, including WE.

Who are the independent The Board has affirmatively determined that Directors Ahearne, Bergstrom, Bowles, Cornog, directors? Culver, Davis, Payne and Stratton have no material relationships with WE or WEC and are independent under the Board's standards of independence. This represents more than a two-thirds majority of the Board. Directors Klappa and Wardeberg are not independent due to their present or previous employment with WE and/or WEC.

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What are the committees of the The Board of Directors of WE has the following committees: Audit and Oversight, Compensation, Board? Finance and Executive.

All committees, except the Executive Committee, operate under a charter approved by the Board. A copy of each committee charter is posted in the "Governance" section of WEC's website at www.wisconsinenergy.com. The members and the responsibilities of each committee are listed later in this information statement.

Are the Audit and Oversight Yes, these committees are comprised solely of independent directors, as determined under New and Compensation Committees York Stock Exchange rules and WEC's Corporate Governance Guidelines.

comprised solely of independent directors? In addition, the Board has determined that each member of the Audit and Oversight Committee is independent 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 non-management Yes, at every regularly scheduled Board meeting an executive session of non-management (non-directors meet separately from employee) directors is held without any management present. Annually, an executive session of management? independent directors is held without any management or non-independent directors present. The chair of WEC's Corporate Governance Committee, currently Director Davis, presides at these sessions.

How can I contact the members Correspondence may be sent to the directors, including the non-employee directors, in care of the of the Board? Corporate Secretary, Anne K. Klisurich, at the Company's principal business off-ice, 231 West Michigan Street, P.O. Box 2046, Milwaukee, Wisconsin 53201.

All communications 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.

All 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 Yes, all WE and WEC directors, executive officers and employees, including the principal written code of ethics? executive, financial and accounting officers, have a responsibility to comply with WEC's Code of Business Conduct, to seek advice in doubtful situations and to 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 waiver to the Code for any director, executive officer or other employee.

The Code of Business Conduct is posted in the "Governance" section of WEC's website at www.wisconsinenergy.com. It is also available in print to any stockholder upon request.

The Company maintains a toll-free confidential helpline for employees to report suspected violations of the Code or other concerns regarding accounting, internal accounting controls or auditing matters.

Does the Board evaluate CEO Yes, the Compensation Committee, on behalf of the Board, annually evaluates the performance of performance? the CEO and reports the results to the Board. As part of this practice, the Compensation Committee requests that all non-employee 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.

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Does the Board evaluate its Yes, the Board annually evaluates its own collective performance. Each director is asked to rate the own performance? 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);

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, candid and constructive dialogue as well as critical questioning. WEC's 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 Yes, each committee, except the Executive Committee, conducts an annual performance evaluation performance evaluated? of its own 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 Yes, the Board has determined that all of the members of WE's Audit and Oversight Committee are committee financially literate financially literate as required by New York Stock Exchange rules. The Board has also determined and does the committee have an that Directors Barbara L. Bowles (Chair), John F. Bergstrom, Robert A. Cornog, Curt S. Culver, "audit committee financial Ulice Payne, Jr. and Frederick P. Stratton, Jr. qualify as audit committee financial experts within the expert"? 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.

For this purpose, the Company considers service on the audit committees of Wisconsin Electric Power Company, Wisconsin Energy.Corporation and Wisconsini Gas LLC to be service on the audit committee of one public company because of the commonality of the issues considered by those committees.

Does the Board have a WE does not have a nominating committee.. Directors of WVEC are also directors of WE and, as nominating committee? such, WE relies on WEC's Corporate Governance Committee for identifying and evaluating director nominees. The chair of the Committee coordinates this effort. The WEC Board has determined that all members of WEC's Corporate Governance Committee are independent under the New York Stock Exchange rules applicable to nominating committee members.

The WEC Corporate Governance Committee operates under a charter approved by the WEC Board, a copy of which is posted in the "Governance" section of WEC's website at www.w isconsinenergy.com.

What is the process used to Candidates for director nomination may be proposed by stockholders, WEC's Corporate identify director nominees and Governance Committee and other members of the Board. The Committee may pay a third party to how do I recommend a nominee identify qualified candidates; however, such a firm was not engaged with respect to the nominees to WEC's Corporate listed in this information statement. The Committee identified and recommended all director Governance Committee? nominees presented for election at the Meeting. No nominations or recommendations were received from holders of either series of the Company's preferred stock.

Stockholders wishing to propose director candidates for consideration and recommendation by WEC's Corporate Governance Committee for election at the Company's 2006 Annual Meeting of Stockholders must submit the name(s) and qualifications of any proposed candidate(s) to WEC's Corporate Governance Committee no later than November 1, 2005 via the Corporate Secretary, Anne K. Klisurich, at the Company's principal business office, 231 West Michigan Street, P.O. Box 2046, Milwaukee, Wisconsin 53201.

What are the criteria and WE relies on WEC's Corporate Governance Committee for identifying and evaluating director process used to evaluate nominees. WEC's Corporate Governance Committee has not established minimum qualifications director nominees? for director nominees; however, the criteria for evaluating all candidates, which are reviewed annually, include characteristics such as: proven integrity, mature and independent judgment, vision and imagination, ability to objectively appraise problems, ability to evaluate strategic options and risks, sound business experience and acumen, relevant technological, political, economic or social/cultural expertise, social consciousness, achievement of prominence in career, familiarity with national 'and international issues affecting WEC and the Company's businesses and contribution to the Board's desired diversity and balance.

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In evaluating director candidates, WEC's Corporate Governance Committee reviews potential conflicts of interest, including interlocking directorships and substantial business, civic and/or social relationships with other members of the Board that could impair the prospective Board member's ability to act independently from the other Board members and management. WEC's Bylaws state that directors shall be stockholders of WEC.

Once a person has been identified by WEC's Corporate Governance Committee as a potential candidate, the Committee may collect and review publicly available information regarding the person to assess whether the person should be considered further. If the Committee determines that the candidate warrants further consideration, the chair or another member of the Committee contacts the person. Generally, if the person expresses a willingness to be considered and to serve on the Board, the Committee requests information from the candidate, reviews the person's accomplishments and qualifications and conducts one or more interviews with the candidate. In certain instances, Committee members may contact one or more references provided by the candidate or may contact other members of the business community or other persons that may have greater firsthand knowledge of the candidate's accomplishments.

The Committee evaluates all candidates, including those proposed by stockholders, using the criteria and process described above. The process is designed to provide the Board with a diversity of experience to allow it to effectively meet the many challenges WE and WEC face in today's changing business environment.

What is WE's policy regarding Directors are not expected to attend WE's annual meetings of stockholders, as they are only short director attendance at annual business meetings. All directors are expected to attend WEC's annual meetings of stockholders.

meetings? All directors attended WEC's 2004 Annual Meeting.

Where can I find more WEC's website, wwvw.wisconsinenergy.com, contains information on WE's and WEC's governance information about WE's and activities. There you will find the Code of Business Conduct, Corporate Governance Guidelines, WEC's corporate governance? Board committee charters and other useful information. As policies are continually evolving, the Company encourages you to visit the website periodically. Copies of these documents may also be requested from the Corporate Secretary.

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COMMITTEES OF TIHE BOARD OF DIRECTORS Members Principal Responsibilities; Meetings Audit and Oversight

• Oversee the integrity of the financial statements.

Barbara L. Bowles, Chair

• Oversee management compliance with legal and regulatory requirements.

John F. Bergstrom

• Review, approve and evaluate the independent auditors' services.

Robert A. Cornog

• Oversee the performance of the internal audit function and independent auditors.

Curt S. Culver

• Prepare the report required by the SEC for inclusion in the information statement.

Ulice Payne, Jr.

• Establish procedures for the submission of complaints and concerns regarding WE's Frederick P. Stratton, Jr. accounting or auditing matters.

• The Committee conducted six meetings in 2004.

Compensation

• Identify through succession planning potential executive officers.

John F. Bergstrom, Chair

• Provide a competitive, performance-based executive and director compensation program.

John F. Aheame

• Set goals for the CEO, annually evaluate the CEO's performance against such goals and Willie D. Davis determine compensation adjustments based on whether these goals have been achieved.

• Prepare the annual report on executive compensation required by the SEC for inclusion in the information statement.

• The Committee conducted six meetings in 2004.

Finance

• Review and monitor the Company's current and long-range financial policies and strategies, Frederick P. Stratton, Jr., Chair including its capital structure and dividend policy.

John F. Bergstrom

• Authorize the issuance of corporate debt within limits set by the Board.

Barbara L. Bowles

• Discuss policies with respect to risk assessment and risk management.

Robert A. Cornog

• Review, approve and monitor the Company's capital and operating budgets.

Curt S. Culver

• The Committee conducted three meetings in 2004.

Ulice Payne, Jr.

Directors of WEC are also directors of WE and, as such, WE relies on WEC's Corporate Governance Committee for identifying and evaluating director nominees. WEC's Corporate Governance Committee is also responsible for establishing and reviewing the Corporate Governance Guidelines to ensure the Board is effectively performing its fiduciary responsibilities to stockholders. The members of the Corporate Governance Committee are Willie D. Davis (Chair), Barbara L. Bowles and Robert A. Cornog. WEC's Corporate Governance Committee conducted one meeting in 2004.

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 Gale E. Klappa (Chair), John F. Bergstrom, Barbara L. Bowles, Robert A. Cornog and Frederick P. Stratton, Jr. The Executive Committee did not meet in 2004.

In addition to the number of committee meetings listed in the preceding table, the Board met six times in 2004. 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.

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INDEPENDENT AUDITORS' FEES AND SERVICES Deloitte & Touche LLP served as the independent auditors for the Company for the fiscal years ended December 31, 2004, 2003 and 2002. They have been selected by the Audit and Oversight Committee as the independent auditors for the Company for the fiscal year ending December 31, 2005, subject to ratification by the stockholders of Wisconsin Energy Corporation at WEC's Annual Meeting of Stockholders on May 5, 2005.

Representatives of Deloitte & Touche LLP are not expected to be present at the Meeting, but are expected to attend WEC's Annual Meeting of Stockholders on May 5, 2005. They will have an opportunity to make a statement at WEC's Annual Meeting, if they so desire, and are expected to respond to appropriate questions that may be directed to them.

Pre-Approval Policy. During 2004, the Audit and Oversight Committee approved a formal policy delineating its responsibilities for reviewing and approving, in advance, all audit, audit-related, tax and other services of the independent auditors. The Committee is committed to ensuring the independence of the auditors, both in appearance as well as in fact.

Under the pre-approval policy, before engagement of the independent auditors for the next year's audit, the independent auditors will submit a detailed description of services anticipated to be rendered for the Committee to approve. Annual pre-approval will be deemed effective for a period of twelve months from the date of pre-approval, unless the Committee specifically provides for a different period. A fee level will be established for all permissible non-audit services. Any proposed non-audit services exceeding this level will require additional approval by the Committee.

The Audit and Oversight Committee delegated pre-approval authority to the Committee's chair. The Committee Chair shall report any pre-approval decisions at the next scheduled Committee meeting. Under the pre-approval policy, the Committee shall not delegate to management its responsibilities to pre-approve services performed by the independent auditors.

Under the pre-approval policy, prohibited non-audit services are services prohibited by the Securities and Exchange Commission to be performed by the Company's independent auditors. These services include bookkeeping or other services related to the accounting records of the Company, financial information systems design and implementation, appraisal or valuation services, fairness opinions or contribution-in-kind reports, actuarial services, internal audit outsourcing services, management functions, human resources, broker-dealer, investment advisor or investment banking services, legal services and expert services unrelated to the audit. In addition, the Committee has determined that tax services performed by the independent auditors should not involve tax strategy consulting.

Fee Table. The following table shows the fees for professional audit services provided by Deloitte & Touche LLP for the audit of WE's annual financial statements for fiscal years 2004 and 2003 and fees for other services rendered during those periods. 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.

2004 2003 Audit Fees (') ........................ ........ $671,577 $349,563 Audit-Related Fees (2)......................,,,,,, 98,724 31,925 Tax Fees (3)................- ........... 49,554 All Other Fees (4).................................. -

Total................................................... $431,042 (I) A udit Fees consist of fees for professional services rendered in connection with the audit of WE's annual financial statements, review of financial statements included in Form I0-Q filings of the Company and services normally provided in connection with statutory and regulatory filings or engagements.

(2) Audit-Related Fees consist of fees for professional services that are reasonably related to the performance of the audit or review of the Company's financial statements and are not reported under "Audit Fees." These services primarily include benefit plan audits and consultations regarding implementation of accounting standards.

(3) Tax Fees consist of fees for professional services rendered with respect to federal and state 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 2004 or 2003.

(4) All Other Fees: Deloitte & Touche LLP did not provide any services in 2004 or 2003 that should be reported in this category.

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AUDIT AND OVERSIGHT CO;MMITTEE REPORT The Audit and Oversight Committee, which is comprised solely of independent directors, oversees the integrity of the financial  ;

reporting process on behalf of the Board of Directors of Wisconsin Electric Power Company. In addition, the Committee oversees compliance with legal and regulatory requirements. The Committee operates under a written charter approved by the Board of Directors, which can be found in the "Governance" section of WEC's website at wwwv.wisconsinenergy.com.

The Committee is also responsible for the appointment, compensation, retention and oversight of the Company's independent auditors, as well as the oversight of the Company's internal audit function. The Committee selected Deloitte & Touche LLP to remain as the Company's independent auditors for 2005, subject to ratification by WEC's stockholders.

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. The Company's independent auditors are responsible for performing an independent audit of the Company's consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States) and issuing a report thereon.

The Committee held six meetings during 2004. Meetings are designed to facilitate and encourage open communication among the. -

members of the Committee, management, the internal auditors and the Company's independent auditors, 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 auditors, 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, including the quality of the Company's accounting principles, the reasonableness of significant judgments and the clarity of disclosures in the financial statements.

In addition, we received the written disclosures and the letter relative to auditors' 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 Electric Power Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2004 and filed with the Securities and Exchange Commission.

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

Barbara L. Bowles, Committee Chair John F. Bergstrom Robert A. Cornog Curt S. Culver Ulice Payne, Jr.

Frederick P. Stratton, Jr.

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COMPENSATION OF THE BOARD OF DIRECTORS Effective January 1, 2004, WE's and WEC's Board of Directors approved a change in director compensation practices in order to align director compensation with director compensation practices at their peer companies and to reflect emerging governance and compensation trends with regard to equity compensation. In addition, the WEC Board adopted stock ownership guidelines for directors to further align the Board's interests with WEC's stockholders. Under these guidelines, directors are generally expected, over time (generally within five years of commencement of Board service), to acquire and hold WEC common stock with a fair market value equal to five times the director's annual retainer.

During 2004, each non-employee director received an annual retainer fee of $36,000 paid in cash. Non-employee chairs of Board committees received a quarterly retainer of $1,250. Non-employee directors received a fee of $1,500 for each Board or committee meeting attended. In addition, each non-employee director received a per diem fee of $1,250 for travel on Company business for each day on which a Board or committee meeting was not also held, and the Company reimbursed non-employee directors for all out-of-pocket travel expenses (including the travel expenses of spouses if they were specifically invited to attend the event and approved in advance by the Chairman of the Board). Non-employee directors were paid S300 for each signed, written unanimous consent in lieu of a meeting. Each non-employee director also received on January 2, 2004, the 2004 annual stock compensation award in the form of restricted stock equal to a value of $65,000, with vesting to occur three years from the grant date. Insurance is also provided by the Company for director liability coverage, fiduciary and employee benefit liability coverage and travel accident coverage for director travel on Company business. Employee directors did not receive any directors' fees.

For 2005, the fees paid to non-employee directors will be the same as in 2004. In addition, each non-employee director received on January 3, 2005, the 2005 annual stock compensation award in the form of restricted stock equal to a value of $65,000, with vesting to occur three years from the grant date.

Non-employee directors may defer all or a portion of director fees pursuant to WEC's Directors' Deferred Compensation Plan.

Deferred amounts can be credited to any 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, including WE. The deferred amounts will be paid out of the general corporate assets or the trust described under "Retirement Plans" in this information statement.

Although WE directors also serve on the Wisconsin Energy Corporation and Wisconsin Gas LLC boards and their committees, a single annual retainer is paid and only a single fee is paid for meetings held on the same day. Fees are allocated among Wisconsin Electric Power Company, Wisconsin Energy Corporation and Wisconsin Gas LLC based on services rendered.

A Directors' Charitable Awards Program has been established to help further WEC's philosophy of charitable giving. Under the program, WEC intends to contribute up to $100,000 per year for 10 years to one or more charitable organizations chosen by each director, upon the director's death. Directors are provided with one charitable award benefit for serving on the boards of WEC and its subsidiaries, including WE. There is a vesting period of three years of service on the Board required for participation in this program.

Beneficiary organizations under the program must be approved by WEC's Corporate Governance Committee. Charitable donations under the program will be paid out of general corporate assets. Directors derive no financial benefit from the program, and all income tax deductions accrue solely to WEC. The tax deductibility of these charitable donations mitigates the net cost.

I1I

COMPENSATION COMMITTEE REPORT ON EXECUTIVE COMPENSATION Compensation Philosophy and Objectives. The Compensation Committee, which works in conjunction with WEC's Compensation Committee (collectively, the "Committee"), is responsible for making decisions regarding compensation for the executives of Wisconsin Electric Power Company. The Board of Directors has determined that all Committee members are independent. We seek to provide a competitive, performance-based executive compensation program that enables WE to attract and retain key individuals and to motivate them to achieve short- and long-term goals.

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

The primary elements of the executive compensation program are base salary, annual incentive compensation and long-term incentive compensation. We believe that the labor market for WEC executives is that of general industry in the United States. As a result, for WE executives who also hold WEC positions, all elements of compensation are targeted at the 50 "'percentile of general industry practices - that is, we target compensation at the median levels paid for similar positions at similarly sized companies. Recognizing that a significant portion of WEC's business is in the energy services industry, we place a greater emphasis upon compensation practices in the energy industry for WE executives whose positions principally relate to utility operations.

In order to determine appropriate compensation levels, we rely upon a variety of sources for guidance, including compensation data compiled by Towers Perrin, an independent compensation consultant. We also consider the executive's responsibilities and experience.

Specific values of 2004 compensation for the current Chief Executive Officer, and the four other most highly compensated executive officers, and for Mr. Abdoo who would have been among the four most highly compensated executive officers but for the fact that he was not serving as an executive officer at the end of fiscal year 2004, are shown in the Summary Compensation Table. Our basis for determining each element of compensation is described below.

Base Salary. We adjusted base salaries for 2004 to target the 50th percentile of general industry practices for WEC officers and the 50th percentile of energy services industry practices for Wisconsin Electric officers. In making these adjustments, the Committee also considered factors such as the relative levels of individual experience, performance, responsibility and contribution to the results of WE's and WEC's operations. With respect to salary adjustments for the named executive officers other than Mr. Klappa, the Committee considered the recommendations of Mr. Klappa. Base salaries for each of the named executive officers are shown in the Summary Compensation Table under the heading of "Salary."

Annual Incentive Compensation. The annual incentive plan provides for annual awards to executives based upon achievement of pre-established stockholder, customer and employee focused objectives. All payments under the plan are at risk. Payments are made only 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 2004 were targeted at 35%

to 100% of base salary; however, actual awards may range from 0% to 200% of base salary based on performance. The plan also provides the Committee with the discretion to recognize individual performance.

At the direction of the Committee, the annual performance incentive program for 2004 was designed with a principal focus on financial results. In general, the annual incentive was dependent upon financial achievement determined by performance against targets for WEC's earnings from ongoing operations and cash flow. For 2004, the target for WEC's earnings from ongoing operations excluded the effects of asset sales, impairment charges, debt redemption costs and certain severance costs. In addition to targets for WEC's earnings from ongoing operations and cash flow, executives whose positions principally relate to utility operations are also measured against targets for the aggregate net income of WE and Wisconsin Gas LLC (WG). WE and WEC's financial performance exceeded the targets for 2004. Performance incentive awards could be increased or decreased by up to 10% based upon WEC's performance in the operational areas of customer satisfaction (5%), supplier and workforce diversity (2.5%) and safety (2.5%).

WEC's performance in these operational areas, in the aggregate, decreased awards by 1.25%. Based upon these results and any discretion to recognize individual performance, awards granted to executives for 2004 exceeded the target levels. Awards to the named executive officers are shown in the Summary Compensation Table under the heading of "Bonus."

In addition to the financial and operational factors described above, the Committee also considered the performance and achievement of each executive in determining the total annual incentive compensation for each executive for 2004.

The annual performance incentive program for 2005 will again depend upon financial achievement determined by performance against WEC's earnings from ongoing operations and cash flow targets. For executives whose positions principally relate to utility operations, executives will also be measured against targets for the aggregate net income of WE and WG. As was the case in 2004, 12

WEC's performance in the operational areas of customer satisfaction, supplier and workforce diversity and safety will either increase or decrease final awards by up to 10%. In addition, the Committee retains discretion to consider individual performance when awarding incentive compensation.

Long-Term Incentive Compensation. WEC's Compensation Committee administers WEC's 1993 Omnibus Stock Incentive Plan, as amended, which is a WEC stockholder approved, long-term incentive plan designed to link the interests of executives and other key employees to long-term WEC stockholder value. It allows for various types of awards keyed to the performance of WEC's common stock, including stock options, stock appreciation rights, restricted stock and performance shares. Historically, WEC's Compensation Committee has primarily used stock options to deliver competitive long-term incentive opportunities.

For 2004, in order to model best practices, WEC's Compensation Committee modified the long-term incentive program to include a WEC performance share component to complement stock option awards made in 2004. With the use of performance shares, the amount of shares ultimately vested is dependent upon WEC's Total Shareholder Return over a three-year period, as compared to the Total Shareholder Return of the Custom Peer Group identified below. "Total Shareholder Return" is defined as the calculation of total return (stock price appreciation plus reinvestment of dividends) based upon an initial investment of $ 100 and subsequent $100 investments at the end of each quarter during the three-year performance period. WEC's Compensation Committee believes this measure better aligns executive financial interests with those of WEC's stockholders and long-term interests of customers. Executives receive a cash dividend when WEC declares a dividend on its common stock in an amount equal to the number of performance shares granted to the executive at the target 100% rate, as more fully described in "Long-Term Incentive Plans - Awards in Last Fiscal Year" in this information statement, multiplied by the amount of the dividend paid on a share of common stock. The dividends paid to the named executive officers in 2004 are included in the Summary Compensation Table under the heading "Other Annual Compensation."

Performance of WEC stock will be measured against the Custom Peer Group. The Customer 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, as well as long-term strategies. All of the companies in the Customer Peer Group Index receive at least 80% of their revenue from gas andlor 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 Sound Energy Corporation, SCANA Corporation, Sempra Energy, Sierra Pacific Resources Inc.,

The Southern Company, Westar Energy Inc., Wisconsin Energy Corporation, WPS Resources Corporation and Xcel Energy Inc.

For 2005, WEC's Compensation Committee adopted a similar plan, except that upon vesting, the WEC performance units granted under the plan will be settled in cash while the performance shares granted in 2004 will be settled in WEC common stock.

In December 2004, WEC's Compensation Committee approved the acceleration of vesting of all unvested WEC options awarded to executive officers and other key employees in 2002, 2003 and 2004 in anticipation of the impact of the Financial Accounting Standards Board's recent adoption of its statement, "Share-Based Payment" (FAS 123(R)), which requires the expensing of unvested options over the remaining vesting period of the options beginning July 1,2005. In connection with the acceleration of vesting, WEC's Compensation Committee approved new terms and conditions governing the future award of options to purchase shares of WEC common stock. The terms and conditions are substantially similar to those of options that have been awarded since 2000, except that each new option will be a non-qualified stock option and will not vest at all until three years from the date of grant at which time the new options will become 100% exercisable. In addition, the new options will become immediately exercisable upon (i) a termination of employment with WEC or its subsidiaries, including WE, by reason of retirement, disability or death or (ii) a change in control of WEC. It is anticipated that incentive stock options will no longer be awarded. These new terms govern the options granted on January 18, 2005.

The Committee believes that an important adjunct to the long-term incentive program is significant stock ownership by officers who participate in the program. Accordingly, we have implemented WEC stock ownership guidelines for officers. The guidelines provide that each executive officer should, over time (generally within five years of appointment as an executive officer), acquire and hold WEC common stock having a minimum fair market value ranging from 150% to 300% of base salary.

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

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Mr. Klappa's consolidated salary was S856,668 for 2004. This amount reflects his salary as President and Chief Executive Officer of Wisconsin Electric Power Company and Wisconsin Gas LLC and as President of Wisconsin Energy Corporation. This amount also reflects the upward adjustment made when he was appointed to the additional positions of Chairman of the Board of Wisconsin Electric Power Company and Wisconsin Gas LLC and Chairman of the Board and Chief Executive Officer of Wisconsin Energy Corporation effective May 1, 2004. Mr. Klappa's base salary as Chairman, President and Chief Executive Officer is at the mid-point of the competitive range for CEOs at comparably sized companies to WEC as reflected in the survey of general industry compensation practices.

Mr. Klappa's annual incentive compensation award as President and Chief Executive Officer of Wisconsin Electric Power Company and Wisconsin Gas LLC and as President of Wisconsin Energy Corporation was targeted at 90% of base pay. When he was appointed to the additional positions of Chairman of the Board of Wisconsin Electric Power Company and Wisconsin Gas LLC and Chairman of the Board and Chief Executive Officer of Wisconsin Energy Corporation, his award was targeted at 100% of a full year of base pay in such positions. The consolidated award for 2004 was SI,791,202 and was based upon achievement of the financial and operational objectives described above under Annual Incentive Compensation and the accomplishments described below.

In view of the discretionary component of the annual incentive plan, the Committee also noted the significant accomplishments of Mr. Klappa during 2004, including, among other things:

Completed the successful sale of WEC's pump and water systems business for approximately $850 million plus the buyer's assumption of S25 million of third party debt, all of which assisted in the significant reduction of WEC's consolidated debt.

Achievements with respect to WEC's Powerthe Future strategic plan, including:

- approval of Environmental Trust Financing legislation by the Wisconsin State Legislature and the Governor of Wisconsin, which is expected to save the Company's utility customers S155 million over traditional financing alternatives in connection with the Company's anticipated power plant improvements to cut plant emissions of sulfur dioxide, nitrogen oxide and mercury;

- continued construction of a new 545-megawatt natural gas-fired generating unit at the Port Washington Generating Station that was approximately 80% complete at the end of 2004 and has remained on schedule for commercial operation in July 2005; and

- receipt of certain essential environmental permits for construction of a new coal-fired generating facility at the existing Oak Creek site and successful negotiation and signing of the construction contract.

Improved utility operating effectiveness as evidenced by:

- the Company's receipt of the National ReliabilityOne Award for superior electric system reliability and its third consecutive Midwest regional award;

- the Company's receipt of the Edison Award from the Edison Electric Institute for recognition of innovation and leadership in expanding the markets for coal combustion products and finding productive uses for 98% of these materials;

- a 25% reduction in the average response time to power outages; and

- the largest increase in scores and the second largest improvement in regional rank in the United States of customer service ratings by JD Power and Associates for the Company's and WG's residential gas service.

Leadership of the Board of Directors through effective corporate governance as evidenced by WEC's rating of a "10," the highest possible score, from GovemanceMetrics Intemational (GMI) and WEC being rated one of the top 10 companies in the S&P 400 by Institutional Shareholder Services (ISS) for governance practices in 2004.

To specifically link a portion of his compensation to the enhancement of long-term stockholder value, Mr. Klappa was awarded long-temn incentive compensation in 2004 in the form of WEC stock options, as set forth in the "Long-Termn Compensation Awards" column of the Summary Compensation Table, and WEC performance shares, as set forth in "Long-Term Incentive Plans - Awards in Last Fiscal Year."

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Compliance with Tax Regulations Regarding Executive Compensation. Section 162(m) of the Internal Revenue Code limits the deductibility of certain executives' compensation that exceeds $1 million per year, 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 the limitations 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. With respect to incentive compensation, long-term incentive compensation payable under WEC's 1993 Omnibus Stock Incentive Plan, as amended, has been designed to comply with the requirements of Section 162(m), while annual incentive compensation awards have not been qualified under Section 162(m). The Committee may, from time to time, conclude that compensation arrangements are in the best interest of WE and 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 Electric Power Company's stockholders by the Compensation Committee of the Board of Directors.

John F. Bergstrom, Committee Chair John F. Aheame Willie D. Davis 15

EXECUTIVE OFFICERS' CONIPENSATION This table summarizes, for the last three fiscal years, compensation awarded to, earned by or paid to the Company's Chief Executive Officer, each of the Company's other four most highly compensated executive officers, and Mr. Abdoo who would have been among the four most highly compensated officers but for the fact that he was not serving as an executive officer at the end of fiscal year 2004 (the "named executive officers"). The amounts shown in this and all subsequent tables in this information statement are WEC consolidated compensation data.

Summary Compensation Table Long-Term Compensation Annual Compensation Awards Restricted Securities Other Annual Stock Underlying All Other Salary Bonus Compensation Awards.. Options Compensation(Zt Name and Principal Position Y'ear ID I# ID Cale E. Klappa Chairman of the Board, President 2004 856,668 1,791,202 212,573(3) 200,000 47,450 and Chief Executive Officer of 2003 458,179 1,075,000 131,740(3) 1,006,320 250,000 12,952 WEC, WE and WG (4 Richard A. Abdoo Retired Chairman of the Board 2004 283,332 400,000 5,748 300,000 53,500 and Chief Executive Officer o 2003 794,004 1,500,000 11,749 300,000 49,099 WEC; Retired Chairman of the 2002 756,300 859,308 11,868 300,000 66,959 Board of WE and WG (5)

Frederick D. Kuester Executive Vice President of WEC 2004 520,004 795,606 103,017 (3) - 150,000 24,600 and WG; Executive Vice 2003 110,508 400,000 1,976 749,547 200,000 2,500 President and Chief Operating Officer of WE (4)

Allen L. Levereit Executive Vice President and 2004 484,996 942,044 93,895 (3) 150,000 30,750 Chief Financial Officer of 2003 230,004 690,000 66,025 (3 846,748 200,000 6,900 WEC, WE and WG (4)

Larry Salustro Executive Vice President and 2004 385,000 589,050 17,612 150,000 24,241 General Counsel of WEC, WE 2003 360,000 375,000 2,550 306,600 125,000 14,370 and WG 2002 336,000 323,331 2,297 75,000 34,075 Kristine A. Rapp6 Senior Vice President and Chief 2004 273,332 285,599 16,354 20,925 20,503 Administrative Officer of WEC, WE and WG (4)

') There were no restricted stock awards made during fiscal 2004. In 2003, restricted stock awards of WEC common stock were granted to Messrs. Klappa, Kuester, Leverett and Salustro in the amounts of 39,510 shares, 24,140 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 upon the closing market prices of WEC common stock of S25.47, $31.05, $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. Mr. Kuester'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 will vest upon his retirement at or after attainment of age 60. However, in each case, earlier vesting may occur due to termination of employment by death, disability, a change in control of WEC or action by the Compensation Committee. In addition, early vesting may occur for Messrs. Klappa, Kuester and Leverett if they terminate employment for good reason or WEC terminates their employment other than because of death or disability and without cause. 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, 2004, the named executive officers held the following number of shares of restricted stock with the following values (based on a closing price of

$33.71 on December 31, 2004): Mr. Klappa-37,208 shares (S 1,254,282); Mr. Kuester-22,419 shares (S755,744); Mr.

Leverett-29,973 shares (S1,010,390); Mr. Salustro-29,034 shares (S978,736); and Ms. Rapp&-8,439 shares ($284,479).

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During 2004, performance shares were awarded to Messrs. Klappa, Kuester, Leverett and Salustro, and Ms. Rapp6. These performance shares are not reflected in the table or footnote discussion above. These performance share awards are reflected in the table under the heading "Long-Term Incentive Plans - Awards in Last Fiscal Year."

(2) All Other Compensation for 2004 for each of Messrs. KlappaAbdoo, Kuester, Leverett and Salustro, and Ms. Rapp6, consists of:

• employer matching of contributions into the 401 (k) plan in the amount of $6,150 for each named executive officer;

• "make whole" payments under the Wisconsin Energy Corporation Executive Deferred Compensation Plan with respect to matching in the 401(k) plan on deferred salary or salary received but not othervise eligible for matching in the amounts of $41,300, S47,350, $18,450, $24,600, $9,788 and S5,250, respectively; and

• gain in value of life insurance policies prior to the policies termination in the amounts of S8,303 for Mr. Salustro and

$9,103 for Ms. Rapp6.

(3) Other Annual Compensation for 2004 for Mr. Klappa includes payments for club dues in the amount of $92,847, which includes a one-time new member fee of $80,256. Other Annual Compensation for 2004 for Mr. Kuester and Mr. Leverett includes payments of relocation expenses in the amounts of $52,648 and $46,545, respectively, which are in addition to the expenses incurred by WEC that are described under the heading "Certain Relationships and Related Transactions" below. 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.

(4) Mr. Klappa commenced employment with WEC in April 2003 and with WE in August 2003. Mr. Kuester commenced employment with WEC and WE in October 2003. Mr. Leverett commenced employment with WEC and WE in July 2003.

Ms. Rapp6 became an executive officer of WEC and WE in May 2004.

(5) Effective as of April 30, 2004, Mr. Abdoo retired from all officer and director positions with WEC and its subsidiaries, including WE, and retired as an employee.

Option Grants in Last Fiscal Year This table shows additional data regarding the options granted in 2004 to the named executive officers.

Grant Date Individual Grants") Value Percent of Number of Total Securities Options Grant Underlying Granted to Employee Exercise Date Options in or Base Present Granted Fiscal Year Price Expiration Value(2 )

Name # (%) (5/Share) Date (

Gale E. Klappa 200,000 10.84 33.435 01/02/2014 $1,889,340 Richard A. Abdoo 300,000 16.26 33.435 01/02/2014 $2,834,010 Frederick D. Kuester 150,000 8.13 33.435 01/02/2014 $1,417,005 Allen L. Leverett 150,000 8.13 33.435 01/02/2014 $1,417,005 Larry Salustro 150,000 8.13 33.435 01/02/2014 $1,417,005 Kristine A. Rapp6 20,925 1.13 33.435 01/02/2014 $ 197,672

') Consists of incentive and non-qualified stock options to purchase shares of WEC common stock granted on January 2, 2004 pursuant to WEC's 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. By action of WEC's Compensation Committee on December 28, 2004, all of these options became fully vested and exercisable as of December 31, 2004, other than Mr. Abdoo's options which became vested and exercisable as of his retirement on April 30, 2004. Prior to this action, the options were scheduled to vest in 25%

increments beginning on the first anniversary of the grant date. These options were granted for a term often years, subject to earlier termination in certain events related to termination of employment. In the discretion of WEC's 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 WEC's 1993 Omnibus Stock Incentive Plan, as amended, WEC's Compensation Committee has the power with the participant's consent to amend these options and to grant extensions.

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(2) An option-pricing model (developed by Black-Scholes) was used to determine the options' hypothetical present value as of the date of the grant. The assumptions used in the Black-Scholes equation are: market price of WEC common stock: S33.435; exercise price of option: $33.435; stock volatility: 23.10%; annualized risk-free interest rate: 4.62%; exercise at the end of the 10-year option term; and dividend yield: 2.51%. The 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 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 2004 and the number and value of exercisable and unexercisable "in-the-money" options held by the named executive officers at fiscal year-end.

Number of Securities Shares Underlying Unexercised Value of Unexercised In the Acquired on Options at Fiscal Year-End Money Options at Fiscal Year-End Exercise Value Realized (#) _ __)___

2 Name ExerciahbleW) Unexercisahle' - ExereisahieW2 Unexercsable Gale E. Klappa 450,000 2,155,000 Richard A. Abdoo 739,771 7,434,866 741,229 3,325,956 Frederick D. Kuester 350,000 569,250 Allen L. Leverett . 350,000 957,250 Larry Salustro 516,250 18,750 3,694,087 249,750 Kristine A. Rapp6 3,000 15,561 105,477 4,294 686,274 56,127

(') 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 of WEC common stock reported in the New York Stock Exchange Composite Transaction report on the exercise date.

(2) By action of WEC's Compensation Committee on December 28, 2004, all options that were granted in 2002, 2003 and 2004, and not othervise exercisable, became exercisable as of December 31, 2004, including those granted to Messrs. Klappa, Kuester, Leverett and Salustro, and Ms. Rapp6. All of Mr. Abdoo's unvested options became vested and exercisable as of his retirement on April 30, 2004.

(3) Value is determined by subtracting the exercise price from the year-end closing price of WEC common stock multiplied by the number of shares underlying the option.

Long-Term Incentive Plans - Awards in Last Fiscal Year The following table provides information on long-term incentive plan awards in 2004 to the named executive officers.

Estimated future pay-outs under Number of shares, Performance or other period non-stock price based plans Name units or other riphts (y until maturation or Pa5ment Threshold (# Tariet (# Mavimum (#)

Gale E. Klappa 19,500 3 years from date of grant 4,875 19,500 34,125 Richard A. Abdoo Frederick D. Kuester 16,500 3 years from date of grant 4,125 16,500 28,875 Allen L. Leverett 16,500 3 years from date of grant 4,125 16,500 28,875 Larry Salustro 16,500 3 years from date of grant 4,125 16,500 28,875 Kristine A. Rapp6 2,115 3 years from date of grant 529 2,115 3,701 The table set forth above reflects the award of WEC performance shares to the named executive officers in 2004 under WEC's 1993 Ominbus Stock Incentive Plan, as amended. The number of performance shares ultimately vested is dependent upon WEC's Total Shareholder Return over a three-year period as compared to the Total Shareholder Return of the Custom Peer Group previously identified in this information statement. "Total Shareholder Return" is defined as the calculation of total return (stock price appreciation plus reinvested dividends) based upon an initial investment of $100 and subsequent $100 investments at the end of each quarter during the three-year performance period. The regular vesting schedule for the performance shares is as follows:

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Percentile Vesting Rank Percent

< 25th Percentile 0%

25 th Percentile 25%

Target (50th Percentile) 100%

75 th Percentile 125%

90 'h Percentile 175%

If WEC's rank is between the benchmarks identified above, the vesting percentage will be determined by interpolating the appropriate vesting percentage. Except as discussed herein, unvested performance shares are immediately forfeited upon a named executive officer's cessation of employment with WEC or its subsidiaries prior to completion of the three-year performance period.

The performance shares will vest immediately at the target 100% rate upon (i) the termination of the named executive officer's employment by reason of disability or death or (ii) a change in control of WEC while the named executive officer is employed by WEC or one of its subsidiaries. In addition, a prorated number of performance shares will vest upon the termination of employment of the named executive officer by reason of retirement prior to the end of the three-year performance period. Named executive officers will receive a cash dividend when WEC declares a dividend on its common stock in an amount equal to the number of performance shares granted to the named executive officer at the target 100% rate multiplied by the amount of the dividend paid on a share of common stock.

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

Under the current severance policies, participants have been designated into one of four benefit levels. Of the individuals named in the Summary Compensation Table, Mr. Salustro and Ms. Rapp6 are Tier 2 participants. Messrs. Klappa, Abdoo, Kuester and Leverett do not participate in the severance policy, but each has a separate change in control and severance agreement as described below.

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

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

Mr. Klappa commenced employment with WEC on April 14, 2003 and with WE on August 1, 2003. Under the agreement with Mr. Klappa, severance benefits are provided if his employment is terminated (i) by WEC, other than for cause, death or disability, in anticipation of or following a change in control, (ii) by Mr. Klappa for good reason following such a change in control, (iii) by Mr. Klappa within six months after completing one year of service following a change in control, or (iv) in the absence of a change in control, by WEC for any reason other than cause, death or disability or by Mr. Klappa for good reason.

The agreement provides for a lump sum severance payment equal to three times the sum of Mr. Klappa's highest annual base salary in effect in the last three years and highest bonus amount. The highest bonus amount would be calculated as the largest of (i) the current target bonus for the fiscal year in which employment termination occurs, (ii) the highest bonus paid in any of the last three fiscal years of WEC prior to termination or the change 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, restricted stock and other equity awards, certain financial planning services and other benefits and a "gross-up" 19

payment should any payments or benefits under the agreements trigger federal excise taxes under the "parachute payment" provisions of the tax law. Mr. Klappa is eligible to receive a supplemental retirement benefit from WEC which is further described under the "Retirement Plans" section of this information statement. Mr. Klappa will receive an additional benefit based upon the difference between the retirement benefits that he would have received from his prior employer and the retirement benefits received from WEC. Mr. Klappa's agreement provides that, for 2003, he receive an annual base salary of

$640,000 and a special lump sum signing bonus of S350,000 (with $250,000 paid on his employment starting date and the balance six months later). Pursuant to the terms of his employment agreement, Mr. Klappa's target bonus opportunity was fixed at 90% of his base salary, with a minimum guaranteed bonus of $576,000 for 2003. However, upon being appointed to the additional positions of Chairman of the Board of Wisconsin Electric Power Company and Chairman of the Board and Chief Executive Officer of Wisconsin Energy Corporation Mr. Klappa's target bonus opportunity increased to 100% of his base salary.

Upon his employment with WEC, Mr. Klappa was granted a non-qualified stock option for 250,000 shares of WEC's common stock. He was 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 with WEC. The agreement provides that the restricted stock will become 100% vested due to a termination of employment by death or disability. The agreement contains a one-year non-compete provision applicable on termination of employment.

Mr. Abdoo retired effective April 30, 2004. Prior to his retirement, Mr. Abdoo's employment agreement provided severance benefits substantially similar to Mr. Klappa, with the exception of the additional benefit based upon the difference between the retirement benefits received from a former employer and from WEC. Mr. Abdoo did not receive any severance benefits under his employment agreement. Upon his retirement, Mr. Abdoo became entitled to the benefits provided to other senior officers who retired after attaining the age of 60; however, pursuant to his employment agreement, Mr. Abdoo will receive supplemental retirement benefits which will make his total retirement benefits substantially the same as those employees who were in the same compensation bracket and became participants in WEC's supplemental retirement plan at age 25. Mr. Abdoo's outstanding stock options and restricted stock awards vested upon his retirement.

WEC entered into an employment agreement with Mr. Kuester, which became effective on October 13, 2003. The agreement provides severance benefits to Mr. Kuester if his employment is terminated by WEC for any reason other than cause, death or disability or by Mr. Kuester for good reason in the absence of a change in control. This severance benefit includes a lump sum payment equal to two times the sum of Mr. Kuester's highest annual base salary in effect for the three fiscal years preceding his termination and his highest bonus amount. The highest bonus amount is the larger of (i) the current target bonus for the fiscal year in which his employment termination occurs, or (ii) the highest bonus paid in any of the three fiscal years preceding the termination. This severance benefit also includes two years' continuation of health and certain other welfare benefit coverage, eligibility for retiree health coverage thereafter, a payment equal to the value of two additional years of participation in the applicable qualified and non-qualified retirement plans, an additional benefit based upon the difference between the retirement benefits that he would have received from his prior employer and the retirement benefits received from WEC, full vesting in all outstanding stock options, restricted stock and other equity awards, certain financial planning services and other benefits. If Mr.

Kuester has a covered termination in connection with a change in control, (i) the lump sum severance benefit is three times the sum of his highest base salary and highest bonus amount, (ii) the welfare benefits are provided for a three-year period, (iii) the special retirement plan lump sum is calculated as if his employment continued for a three-year period following termination of employment and (iv) there is a "gross-up" payment should any payments or benefits under the agreement trigger federal excise taxes under the "parachute payment" provisions of the tax law. Mr. Kuester is eligible to receive a supplemental retirement benefit from WEC which is further described under the "Retirement Plans" section of this information statement. The agreement also contains a one-year non-compete provision applicable on termination of employment. The agreement provides that, for 2003, Mr. Kuester receive an annual base salary of $500,000 and a special lump sum signing bonus of $200,000 (with S 100,000 paid on his employment starting date and the balance paid six months later). Mr. Kuester's target bonus opportunity is fixed at 80% of base salary, with a minimum guaranteed bonus of S150,000 for 2003. Upon his employment with WEC, Mr.

Kuester was granted a non-qualified stock option for 200,000 shares of WEC's common stock. Mr. Kuester was also granted a restricted stock award for 24,140 shares, which vest at the rate of 10% for each year of service until 100% vesting occurs on the I 0 th anniversary of his employment starting date, provided that the restricted stock will become 100% vested due to a termination of employment by death or disability.

Mr. Leverett commenced employment with WEC and WE on July 1, 2003. Mr. Leverett's employment agreement is substantially similar to Mr. Klappa's, except that if Mr. Leverett's employment is terminated by WEC for any reason other than cause, death or disability or by Mr. Leverett for good reason in the absence of a change in control, (i) 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. Mr. Leverett is eligible to receive a supplemental retirement benefit from WEC which is further described under the "Retirement Plans" section of this information statement. The agreement provides that, for 2003, Mr. Leverett receive an annual base salary of $460,000 and a special lump sum signing bonus of S250,000 (with $150,000 paid on his employment starting date and the balance paid six months later). Mr. Leverett's target 20

bonus opportunity is fixed at 80% of base salary, with a minimum guaranteed bonus of $368,000 for 2003. Upon his employment with WEC, Mr. Leverett was granted a non-qualified stock option for 200,000 shares of WEC's common stock.

Mr. Leverett was also granted a restricted stock award for 28,850 shares on his employment starting date. Two-thirds of the shares vest on July 1, 2005, the second anniversary of his employment starting date and the remaining one-third vest at the rate of 20% for each year of service thereafter until 100% vesting occurs on the seventh anniversary of the employment starting date, provided that the restricted stock will become 100% vested due to a termination of employment by death or disability.

Long-Term Incentive Compensation Plans Special Vesting Provisions. Under the terms of WEC's long-term incentive compensation plans, including WEC's 1993 Omnibus Stock Incentive Plan, as amended, and WEC Performance Unit Plan, awards are generally subject to special vesting provisions upon the occurrence of a defined change in control transaction, or the termination of employment by reason of retirement (as defined in the respective plan), disability (as defined in the respective plan) or death, unless the provision is superseded in an executive's employment agreement. Under the plans, any outstanding stock options and restricted stock awards will generally become fully vested in all cases. Performance shares and performance units will generally become fully vested upon a change in control or the termination of employment by reason of death or disability; but generally vest on a prorated basis upon the termination of employment by reason of retirement.

Benefits and Perquisites. WEC provides its executive officers with employee benefits and perquisites. Except as specifically noted elsewhere in this information statement, the employee benefits programs in which executive officers participate (which provide benefits such as medical benefits coverage, life insurance protection, retirement benefits and annual contributions to a qualified savings plan) are generally the same programs offered to substantially all of the Company's salaried employees. The perquisites available to executive officers are generally made available to all officers at or above the level of vice president. These perquisites include the availability of financial planning and payment of the cost of an annual physical exam. WEC also pays the periodic dues and fees for certain club memberships for the named executive officers and other designated officers.

Death Benefit Only Plan. WEC maintains 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 the after-tax value of three times the officer's base salary if the officer is employed at the time of death or the after-tax value of one times final base salary if death occurs post-retirement. All of the named executive officers participate in the DBO.

RETIREMENT PLANS WEC maintains a defined benefit pension plan of the cash balance type (the "WEC Plan") for most employees, including the named executive officers. The WEC Plan bases a participant's defined benefit pension on the value of a hypothetical account balance. For individuals participating in the WEC Plan as of December 31, 1995, a starting account balance was created equal to the present value of the benefit accrued as of December 31, 1994 under the plan benefit formula prior to the change to a cash balance approach.

That formula provided a retirement income based on years of credited service and final average compensation for the 36 highest consecutive months, with an adjustment to reflect the Social Security integrated benefit. In addition, individuals participating in the WEC Plan as of December 31, 1995 received a special one-time transition credit amount equal to a specified percentage varying with age multiplied by credited service and 1994 base pay.

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

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

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

For the individuals listed in the SummaryCompensation Table, estimated benefits under the "grandfathered" formula are higher than under the cash balance plan formula. Pursuant to the agreements discussed below, their benefits would currently be determined by the prior plan benefit formula. The following table sets forth estimated annual benefits payable in life annuity form on normal retirement for persons in various compensation and years of service classifications during 2004, based on the continuation of the "grandfathered" prior plan formula for WEC (including supplemental amounts providing additional benefits, which include elimination of any caps on compensation that can be recognized under the WEC Plan, described below in the "Other Retirement Benefits" section):

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Pension Plan Table - WEC Plan (Prior Plan Formula)

Yean onfServie Remuneration 15 20 25 30 35 40 S 300,000 74,338 99,117 123,897 148,676 162,753 176,830 500,000 126,088 168,117 210,147 252,176 276,003 299,830 700,000 177,838 237,117 296,397 355,676 389,253 422,830 900,000 229,588 306,117 382,647 459,176 502,503 545,830 1,100,000 281,338 375,117 468,897 562,676 615,753 668,830 1,300,000 333,088 444,117 555,147 666,176 729,003 791,830 1,500,000 384,838 513,117 641,397 769,676 842,253 914,830 1,700,000 436,588 582,117 727,647 873,176 955,503 1,037,830 1,900,000 488,338 651,117 813,897 976,676 1,068,753 1,160,830 2,100,000 540,088 720,117 900,147 1,080,176 1,182,003 1,283,830 2,300,000 591,838 789,117 986,397 1,183,676 1,295,253 1,406,830 2,500,000 643,588 858,117 1,072,647 1,287,176 1,408,503 1,529,830 The compensation considered for purposes of the retirement plans and the various supplemental plans for Messrs. Klappa, Abdoo, Kuester, Leverett and Salustro, and Ms. Rapp6, is $1,191,219, S1,856,185, $682,073, $770,000, S615,043, and $322,649, respectively.

Messrs. Klappa, Abdoo, Kuester, Leverett and Salustro, and Ms. Rapp6, currently have or are considered to have 27, 35, 32, 16, 33 and 22 credited years of service, respectively, under the various supplemental plans described below. Messrs. Klappa, Kuester, Leverett and Salustro, and Ms. Rapp6, are not entitled to these supplemental benefits until they attain the age of 60.

Other Retirement Benefits. Designated officers of WE and WEC, including the named executive officers, participate in the Supplemental Executive Retirement Plan ("SERP"). The SERP provides monthly supplemental pension benefits to participants, which will be paid out of unsecured corporate assets, or the grantor trust described below, in an amount equal to the difference between the actual pension benefit payable under the pension plan and what such pension benefit would be if calculated without regard to any limitation imposed by the Internal Revenue Code on pension benefits or covered compensation. In addition, Messrs. Abdoo and Salustro are also entitled to an amount calculated so as to provide participants with a supplemental lifetime annuity, estimated to be between 8% and 10% of final average compensation depending on which pension payment option is selected.

Except for a "change in control" of WEC, as defined in the SERP, no payments are made until after the participant's retirement or death.

WEC has entered into agreements with Messrs. Abdoo and Salustro 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, effective with his retirement on April 30, 2004, began receiving supplemental retirement payments which will make his total retirement benefits 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.

WEC has entered into agreements with Messrs. Klappa, Kuester 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, at the age of 22 for Mr. Kuester, and' on January 1, 1989 for Mr. Leverett.

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, the Directors' 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.

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STOCK OWNERSHIP OF DIRECTORS, NOM1INEES AND EXECUTIVE OFFICERS None of the WE directors, nominees or executive officers own any of WE's stock, but do beneficially own shares of its parent company, Wisconsin Energy Corporation. The following table lists the beneficial ownership of WEC common stock of each WE director, nominee, named executive officer and all of the directors and executive officers as a group as of February 15, 2005. 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 February 15, 2005. 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 Investment Plan and 401(k) plan. None of these persons beneficially owns more than 1% of the outstanding WEC common stock.

Shares Beneficially Owned l Option Shares Exercisable Within Name Shares Owned (2) (31(4) 60 Davs Total Richard A. Abdoo 40,763 741,229 781,992 John F. Aheame 8,844 21,000 29,844 John F. Bergstrom 6,919 21,000 27,919 Barbara L. Bowles 7,066 21,000 28,066 Robert A. Cornog 11,655 21,000 32,655 Curt S. Culver 2,948 0 2,948 Willie D. Davis 13,060 28,234 (5) 41,294 Gale E. Klappa 40,298 450,000 490,298 Frederick D. Kuester 22,658 350,000 372,658 Allen L. Leverett 30,700 350,000 380,700 Ulice Payne, Jr. 4,994 5,000 9,994 Kristine A. Rapp6 14,603 108,973 123,576 Larry Salustro 37,951 535,000 572,951 Frederick P. Stratton, Jr. 12,519 18,000 30,519 George E. Wardeberg 27,786 375,000(5) 402,786 All directors and executive officers as a group (16 persons) 260,958 2,546,697 (5) 2,807,655 (6)

') 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 WEC's proxy statement. It is not necessarily to be construed as an admission of beneficial ownership for other purposes.

(2) Certain directors, named executive officers and executive officers also hold share units in the WEC phantom common stock account under WEC's deferred compensation plans as indicated: Mr. Abdoo (34,862), Mr. Bergstrom (7,143), Mr. Cornog (12,657), Mr. Culver (1,615), Mr. Davis (8,998), Mr. Kuester (2,490), Ms. Rapp6 (6,595), Mr. Salustro (3,051), Mr. Stratton (8,926), Mr. Wardeberg (1,407) and all directors and executive officers as a group (53,879). 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, named executive officers 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 (included in table above) as indicated: Mr. Bergstrom (3,000), Mr. Cornog (5,007),

Mr. Stratton (4,600), Mr. Wardeberg (23,344) and all directors and executive officers as a group (35,951).

(4) Certain directors and executive officers hold shares of WEC restricted stock (included in table above) over which the holders have sole voting but no investment power: Dr. Aheame (3,919), Mr. Bergstrom (3,919), Ms. Bowles (3,919), Mr. Cornog (3,919), Mr. Culver (2,948), Mr. Davis (3,919), Mr. Klappa (37,208), Mr. Kuester (22,419), Mr. Leverett (29,973), Mr. Payne (3,919), Ms. Rapp6 (8,439), Mr. Salustro (29,034), Mr. Stratton (3,919), Mr. Wardeberg (3,919) and all directors and executive officers as a group (170,447).

(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 2.4% of total WEC common stock outstanding on February 15, 2005.

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SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COM1PLIANCE Section 16(a) of the Securities Exchange Act of 1934, as amended, requires the Company's officers, directors and persons owning more than ten percent of a registered class of the Company's equity securities to file reports of ownership and changes in ownership of equity and derivative securities of WE with the Securities and Exchange Commission. To the Company's knowledge, based on information provided by the reporting persons, all applicable reporting requirements for fiscal year 2004 were complied with in a timely manner.

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

As reported in the Summary Compensation Table, Mr. Kuester received benefits in 2004 under WEC's relocation program. In addition, in 2004 Mr. Kuester sold his home in the city of his former employment for S770,000 to a third-party relocation company hired by WEC to assist in Mr. Kuester's relocation. The amount of S770,000 was the appraised fair market value of the home as determined in an appraisal performed by an appraiser hired by the relocation company. The relocation company subsequently sold Mr. Kuester's home for $617,250, and WEC paid a total of $211,762 to the relocation company for the loss of S 152,750 on the resale of Mr. Kuester's home and S59,012 of closing costs and real estate commissions related thereto.

As reported in the Summary Compensation Table, Mr. Leverett also received benefits under WEC's relocation program. In addition, in 2004 Mr. Leverett sold his home in the city of his former employment to the same third-party relocation company for $400,000.

The amount of $400,000 was the appraised fair market value of the home as determined in an appraisal performed by an appraiser hired by the relocation company. The relocation company subsequently sold Mr. Leverett's home for $414,125, and WEC paid a net total of S28,542 to the relocation company for the gain of $14,125 on the resale of Mr. Leverett's home and S42,667 of closing costs and real estate commissions related thereto.

AVAILABILITY OF FORM 10-K A copy (without exhibits) of Wisconsin Electric Power Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2004, as filed with the Securities and Exchange Commission, is available without charge to any stockholder of record or beneficial owner of WE preferred stock by writing to the Corporate Secretary, Anne K. Klisurich, at the Company's principal business office, 231 WVest Michigan Street, P. 0. Box 2046, Mlilvaukee, Wisconsin 53201. The WVE consolidated financial statements and certain other information found in the Form 10-K are included in the accompanying Wisconsin Electric Power Company 2004 Annual Report to Stockholders.

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APPENDIX A WISCONSIN ELECTRIC POWER COMPANY 2004 ANNUAL REPORT TO STOCKHOLDERS 2004 ANNUAL FINANCIAL STATEMENTS And REVIEW of OPERATIONS

SELECTED FINANCIAL DATA WISCONSIN ELECTRIC POWER COMPANY CONSOLIDATED SELECTED FINANCIAL AND STATISTICAL DATA Financial 2004 2003 2002 20CI1 2000 Year Ended December 31 Earnings available for common stockholder (Millions) S248.7 $255.5 S258.0 S: ;45.3 $163.5 Operating revenues (Millions)

Electric $2,070.8 S 1,986.4 $1,884.6 S1,839.8 S1,763.4 Gas 523.8 513.0 389.8 457.1 399.7 Steam 22.0 22.5 21.5 21.8 21.9 Total operating revenues S2,616.6 $2,521.9 52,295.9 $2,318.7 $2,185.0 At December31 (Millions)

Total assets S7,050.3 $6,644.6 $6,285.1 $6,040.6 $6,038.7 Total debt $1,896.3 S1,915.4 $1,814.2 $1,875.6 S1,964.7 Utility Energy Statistics Electric Megawatt-hours sold (Thousands) 31,162.4 30,713.8 30,378.2 30,539.7 31,398.8 Customers (End of year) 1,081,400 1,068,034 1,056,370 1,044,129 1,026,691 Gas Therms delivered (Millions) 835.1 888.3 890.0 852.4 944.9 Customers (End of year) 437,800 428,719 420,494 412,674 407,761 Steam Pounds sold (Millions) 2,869.0 3,072.8 3,001.1 2,929.2 3,085.2 Customers (End of year) 460 459 467 449 451 CONSOLIDATED SELECTED QUARTERLY FINANCIAL DATA (Unnudited)

(Millions of Dollars) (a)

March June Three Months Ended 2004 2003 2004 2003 Total operating revenues S741.7 $718.8 S583.8 $564.9 Operating income $144.4 S132.5 S71.8 $93.2 Earnings available for common stockholder $79.7 S75.1 $36.4 $49.5 September December Three Months Ended 2004 2003 2004 2003 Total operating revenues S600.6 $599.6 S690.5 S638.6 Operating income $106.4 S124.5 S136.6 $121.1 Earnings available for common stockholder $58.8 S67.7 S73.8 $63.2 (a) Quarterly results of operations are not directly comparable because of seasonal and other factors. See Management's Discussion and Analysis of Financial Condition and Results of Operations.

WISCONSIN ELECTRIC POWER COMPANY SELECTED OPERATING DATA Year Ended December 31 2004 2003 2002 2001 2000 Electric Utility Operating Revenues (Millions)

Residential $720.7 $705.0 $693.4 $644.8 $597.2 Small Commercial/industrial 651.9 626.0 591.0 577.3 534.7 Large Commercial/Industrial 541.4 511.4 475.6 472.0 464.9 Other - Retail/Municipal 82.6 77.1 71.0 63.2 58.3 Resale - Utilities 39.9 39.1 31.3 69.6 84.0 Other Operating Revenues 34.3 27.8 22.3 12.9 24.3 Total Operating Revenues $2,070.8 $1,986.4 $1,884.6 $1,839.8 $1,763.4 Megawatt-hour Sales (Thousands)

Residential 7,885.3 7,928.8 8,147.8 7,615.7 7,477.6 Small Commercial/Industrial 8,597.0 8,493.1 8,473.2 8,354.2 8,287.5 Large Commercial/Industrial 11,477.4 11,201.8 10,933.0 10,983.0 11,626.2 Other - Retail/Municipal 2,157.6 1,980.4 1,810.4 1,599.4 1,527.3 Resale - Utilities 1,045.1 1,109.7 1,013.8 1,987.4 2,480.2 Total Sales 31,162.4 30,713.8 30,378.2 30,539.7 31,398.8 Number of Customers (Average)

Residential 966,840 954,757 945,298 931,714 916,028 Small Commercial/Industrial 104,261 102,928 102,058 100,456 98,277 Large Commercial/Industrial 705 703 705 706 712 Other 2,371 2,348 2,345 2,319 2,283 Total Customers - 1,074,177 1,060,736 1,050,406 1,035,195 1,017,300 Gas Utility Operating Revenues (Millions)

Residential $330.5 $317.5 $250.9 $275.8 $244.3 Commercial/Industrial 173.8 166.9 125.8 150.0 132.0 Interruptible 4.1 3.8 3.2 5.1 5.3 Total Retail Gas Sales 508.4 488.2 379.9 430.9 381.6 Transported Gas 15.3 15.6 16.0 15.4 18.9 Other Operating Revenues 0.1 9.2 (6.1) 10.8 (0.8)

Total Operating Revenues $523.8 $513.0 $389.8 $457.1 $399.7 Therms Delivered (Millions)

Residential 342.3 361.0 345.4 318.4 335.7 Commercial/Industrial 200.4 210.8 199.2 194.5 206.2 Interruptible 6.4 6.8 7.4 8.9 12.0 Total Retail Gas Sales 549.1 578.6 552.0 521.8 553.9 Transported Gas 286.0 309.7 338.0 330.6 391.0 Total Therms Delivered 835.1 888.3 890.0 852.4 944.9 Number of Customers (Average)

Residential 396,985 388,896 381,846 376,510 369,210 Commercial/Industrial 35,174 34,646 34,180 33,839 33,275 Interruptible 24 23 24 30 33 Transported Gas 369 362 366 427 389 Total Customers 432,552 423,927 416,416 410,806 402,907 Degree Days (a)

Heating (6,739 Normal) 6,663 7,063 6,551 6,338 6,716 Cooling (714 Normal) 442 606 897 711 566 (a) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a twenty-year moving average A-3

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS CORPORATE DEVELOPMENTS INTRODUCTION Wisconsin Electric Power Company, a wholly-owned subsidiary of Wisconsin Energy Corporation (Wisconsin Energy), is engaged primarily in the business of generating electricity and distributing electricity and natural gas in Wisconsin and the Upper Peninsula of Michigan. Unless qualified by their context, when used in this document the terms Wisconsin Electric, the Company, our, us or we refer to Wisconsin Electric Power Company and its subsidiary.

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

Cautionary Factors: Certain statements contained herein are "Forward-Looking Statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-Looking Statements include, among other things, statements regarding management's expectations and projections regarding completion of construction projects, regulatory matters, fuel costs, sources of electric energy supply, gas deliveries, remediation costs, environmental and other capital expenditures, liquidity and capital resources and other matters. Also, Forvard-Looking Statements may be identified by reference to a future period or periods or by the use of forward looking terminology such as "anticipates," "believes," "estimates," "expects," "forecasts," "intends," "may," "objectives," "plans," "possible,"

"potential," "projects" 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, those risks and uncertainties described under the heading "Cautionary Factors" in this Management's Discussion and Analysis of Financial Condition and Results of Operations, as well as other matters described under the heading "Factors Affecting Results, Liquidity and Capital Resources" below, and other risks and uncertainties detailed from time to time in our filings with the Securities and Exchange Commission (SEC) or otherwise described throughout this document.

CORPORATE STRATEGY Business Opportunities Wisconsin Energy's key corporate strategy is Power the Future, which was announced in September 2000. This strategy is designed to address Wisconsin's growing electric supply needs by increasing the electric generating capacity in the state 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 to support our commitment to improved environmental performance. We expect that the Power the Future strategy will have a significant impact on us.

Powerthe Fet'ureStrategy: In February 2001, Wisconsin Energy filed a petition with the Public Service Commission of Wisconsin (PSCW) that would allow Wisconsin Energy to begin implementing its 10-year Power the Future strategy to improve the supply and reliability of electricity in Wisconsin. Powerthe Future is intended to meet a growing demand for electricity and ensure a diverse fuel mix while keeping electricity prices reasonable.

Under Posver the Future Wisconsin Energy plans to add new coal-fired and natural gas-fired generating capacity to Wisconsin's power portfolio which would allow us to maintain approximately the same fuel mix as exists today. As part of' its Power the Future strategy, Wisconsin Energy is (I) investing a net of approximately $2.5 billion in 2,120 megawatts of new natural gas-fired and coal-fired generating capacity at existing sites; (2) upgrading our existing electric generating facilities and (3) investing in upgrades of our existing energy distribution system. The new generating capacity will be built by an affiliated company, W.E. Power LLC (We Power).

Subsequent to Wisconsin Energy's February 2001 filing, the state legislature amended several laws, making changes which are critical to the implementation of Powerthe Future. In October 2001, the PSCW issued a declaratory ruling finding, among other things, that it was prudent to proceed with Power the Future and for Wisconsin Energy A-4

to incur the associated pre-certification expenses. However, individual expenses are subject to review by the PSCW in order to be recovered.

In November 2001, Wisconsin Energy created We Power to design, construct, own, finance and lease the new generating capacity. We will lease each new facility from We Power as well as operate and maintain the new plants under 25 to 30-year lease agreements approved by the PSCW. Based upon the structure of the leases, Wisconsin Energy expects to recover the initial investments in We Power's new facilities over the initial lease term. At the end of the leases, we will have the right to acquire the plants outright at market value or to renew the leases. We expect that all lease payments and operating costs of the plants will be recoverable in rates under the provisions of the Wisconsin Leased Generation Law.

Under the Powerthe Future strategy, Wisconsin Energy expects to meet a significant portion of our future generation needs through We Power's construction of the Port Washington and Elm Road generating stations.

As of December 31, 2004, Wisconsin Energy:

t> Received a Certificate of Public Convenience and Necessity (CPCN) from the PSCW to build two 545-megawatt natural gas-fired intermediate load units in Port Washington, Wisconsin, with the first unit expected to be operational early in the third quarter of 2005 and the second unit by the end of the second quarter of 2008:

> Began construction on the first 545-megawatt generating unit in Port Washington (approximately 87% complete as of January 31, 2005), which is currently on schedule and within budget.

> Began site preparation on the second 545-megawatt generating unit in Port Washington in May 2004.

~1- Received a CPCN from the PSCW to build two 615-megawatt coal-fired base load units at our existing Oak Creek Power Plant site 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 required permits and project approvals. In November 2004, the order granting the CPCN was vacated and remanded back to the PSCW by the Dane County Circuit Court. We appealed this decision along with Wisconsin Energy and We Power in December 2004, as has the PSCW and Wisconsin Department of Natural Resources (WDNR). In January 2005, the Supreme Court of Wisconsin agreed to hear the appeals filed by the PSCW, WDNR and us to reverse the Dane County Circuit Court ruling. The Supreme Court's order allows the case to bypass the state appeals court. The Supreme Court scheduled oral arguments in this matter for March 30, 2005. We expect a decision to be reached no later than June 30, 2005.

> Received approval from the PSCW for various leases between us and We Power.

Primary risks under Power the Future are associated with successful, timely resolution of court challenges related to the Elm Road facility, timely receipt of remaining permits for Elm Road, and construction risks associated with the schedule and costs for both Wisconsin Energy's Elm Road and Port Washington generating stations.

You can find additional information regarding risks associated with the Power the Future strategy, as well as the regulatory process, specific regulatory approvals and associated legal challenges in "Factors Affecting Results, Liquidity and Capital Resources" below.

Utility Operations: We are realizing operating efficiencies through the integration of our operations with those of Wisconsin Gas. These operating efficiencies are expected to increase customer satisfaction and reduce operating costs. In connection with Wisconsin Energy's Powerthe Futurestrategy, we are improving our existing energy distribution systems and upgrading existing electric generating assets.

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Divestiture of Assets During 2000, we agreed to join American Transmission Company LLC (ATC) by transferring our electric utility transmission system assets to ATC in exchange for an ownership interest in this new company. Transfer of these electric transmission assets became effective on January 1, 2001. As of December 31, 2004, we had an ownership interest of approximately 33.2% in ATC. For additional information, see "Note A-- Summary of Significant Accounting Policies" in the Notes to Consolidated Financial Statements.

RESULTS OF OPERATIONS EARNINGS 2004 vs. 2003: Earnings decreased to S248.7 million in 2004 compared with S255.5 million in 2003. Operating income was down $12.1 million between the comparative periods. During 2004, we experienced an increase in revenues due to base electric sales growth, and we benefited from lower bad debt expenses. However, these items were offset by higher pension and medical costs, severance costs recorded during the second half of 2004 and unfavorable weather.

2003 vs. 2002: Earnings decreased by $2.5 million to S255.5 million during 2003 when compared to 2002. The decline 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 Wisconsin Energy's Power the Future growth strategy. The decline was somewhat mitigated by a March 2003 rate increase associated with fuel and purchased power expenses as well as by higher gas margins; growth in our base electric business; litigation settlements in 2002 compared with the receipt of insurance recoveries in 2003, primarily related to the Giddings &

Lewis/City of West Allis litigation; and higher other income and deductions.

The following table summarizes our consolidated earnings during 2004, 2003 and 2002.

2004 2003 2002 (Millions of Dollars)

Utility Gross Margin Electric (See below) $1,492.2 $1,430.7 S1,397.5 Gas (See below) 146.9 157.6 149.0 Steam 15.2 15.8 14.7 Total Gross Margin 1,654.3 1,604.1 1,561.2 Other Operating Expenses Other Operation and Maintenance 844.7 784.0 736.3 Depreciation, Decommissioning and Amortization 274.1 276.2 267.9 Property and Revenue Taxes 76.3 72.6 71.7 Operating Income 459.2 471.3 485.3 Other Income and Deductions, Net 33.5 31.5 24.3 Interest Expense 89.6 91.2 92.7 Income Before Income Taxes 403.1 411.6 416.9 Income Taxes 153.2 154.9 157.7 Preferred Stock Dividend Requirement 1.2 1.2 1.2 Earnings Available for Common Stockholder $248.7 $255.5 S258.0 Electric Utility Gross Margin The following table compares our electric utility gross margin during 2004 with similar information for 2003 and 2002, including a summary of electric operating revenues and electric sales by customer class.

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Electric Revenues and Gross Margin Electric Megawatt-Hour Sales Electric Utility Operations 2004 2003 2002 2004 2003 2002 (Millions of Dollars) (Thousands, Except Degree Days)

Customer Class Residential $720.7 $705.0 $693.4 7,885.3 7,928.8 8,147.8 Small Commercial/Industrial 651.9 626.0 591.0 8,597.0 8,493.1 8,473.2 Large Commercial/Industrial 541.4 511.4 475.6 11,477.4 11,201.8 10,933.0 Other-Retail/Municipal 82.6 77.1 71.0 2,157.6 1,980.4 1,810.4 Resale-Utilities 39.9 39.1 31.3 1,045.1 1,109.7 1,013.8 Other Operating Revenues 34.3 27.8 22.3 - - -

Total Electric Operating Revenues 2,070.8 1,986.4 1,884.6 31,162.4 30,713.8 30,378.2 Fuel and Purchased Power Fuel 335.0 298.3 278.9 Purchased Power 243.6 257.4 208.2 Total Fuel and Purchased Power 578.6 555.7 487.1 Total Electric Gross Margin $1,492.2 $1,430.7 $1,397.5 Weather -- Degree Days (a)

Heating (6,739 Normal) 6,663 7,063 6,551 Cooling (714 Normal) 442 606 897 (a) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a tventy-year moving average.

Electric Utility Revenues and Sales 2004 vs. 2003: During 2004, our total electric utility operating revenues increased by $84.4 million or 4.2% when compared with 2003 due to pricing increases and to growth in our base businesses, partially offset by the effects of unfavorable weather during the summer of 2004.

During 2004, we received $54.5 million of higher operating revenues as a result of pricing increases which were not in effect during 2003. In May 2004, we received an order from the PSCW authorizing an annualized increase in electric rates of approximately $59.5 million to cover construction costs associated with Wisconsin Energy's Power the Futureprogram and to recover low income uncollectible expenses transferred to Wisconsin's public benefits fund. In addition, two rate increases related to a rise in fuel and purchased power costs were implemented in March and October 2003, which increased revenues by approximately $16.3 million during 2004.

Total electric sales increased by 448.6 thousand megawatt-hours or 1.5% between 2004 and 2003. Residential sales were down 0.5%, and small commercial/industrial sales were up just 1.2% due to the unfavorable weather during 2004. We estimate that the unfavorable weather reduced our electric revenues by approximately $28.6 million as compared to the prior year and by $20.7 million as compared to normal weather. As measured by cooling degree days, 2004 was 27.1% cooler than in 2003 and 38.1% cooler than normal.

However, we estimate that customer growth and higher weather-normalized use per customer during 2004 mitigated much of the impact of unfavorable weather. Sales volumes to large commercial/industrial customers improved by 2.5%. Excluding our largest customers, two iron ore mines, sales volumes to our remaining large commercial/industrial customers improved by 1.4%. Sales to municipal utilities, the other retail/municipal customer class, increased 8.9% between the periods due to higher off-peak demand from low-margin municipal wholesale power customers.

2003 vs. 2002: During 2003, total electric utility operating revenues increased by $101.8 million or 5.4% when compared with 2002, primarily due to the impact of rate increases related to fuel and purchased power costs and to a surcharge related to transmission costs. The total rate impact was approximately $83.3 million in 2003. In March 2003, we received an interim increase in rates of $55.1 million annually to recover increases in fuel and purchased power costs. In October 2003, we received the final rate order, which authorized an additional S6.1 million of annual revenues. In spite of the interim fuel order, we under recovered fuel costs by $7.6 million during 2003, which is $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 in May and June of 2003 due to a flood at our A-7

Presque Isle Power Plant and to high natural gas prices. The impact of unfavorable summer weather in 2003 reduced electric operating revenues by approximately $19.0 million between the comparative periods.

Total electric megawatt-hour sales increased by 1.1 % during 2003. Residential sales fell 2.7% due to the impact of unfavorable weather conditions on cooling load during the second and third quarters of 2003. Sales to our largest customers, two iron ore mines, increased by 238.4 thousand megawatt-hours or 12.1% between the comparative periods despite temporary curtailments of electric sales in the second and fourth quarters of 2003 resulting from a flood-related outage at our Presque Isle Power Plant and a transmission outage. 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%

between the comparative periods, and sales volumes to the remaining large commercial/industrial customers improved by 0.3%. Sales to municipal utilities, the other retail/municipal customer class, increased 9.4% between the periods due to higher off-peak demand from low-margin municipal wholesale power customers.

Electric Fuel and Purchased Power Expenses 2004 vs. 2003: Total fuel and purchased power expenses for our electric utility increased by $22.9 million or 4.1%

during 2004 when compared with 2003. This increase is primarily due to our 1.5% increase in total megawatt-hour sales and to higher coal and purchased capacity costs. Increased availability of several of our coal-fired generating units during 2004, which are less expensive to operate than our natural gas-fired generating units, mitigated the rise in fuel and purchased power costs. Very cool summer weather significantly reduced our need to use higher cost peak generating units and purchased power during 2004, also mitigating the rise in fuel and purchased power costs between the comparative periods.

2003 vs. 2002: During 2003, total fuel and purchased power expenses increased S68.6 million or 14.1% 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 S5.39 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 $8 million of this increase was caused by the flood that temporarily shut down our Presque Isle Power Plant during the second quarter of 2003.

Gas Utility Revenues, Gross Margin and Therm Deliveries The following table compares our total gas utility operating revenues and gross margin (total gas utility operating revenues less cost of gas sold) during 2004, 2003 and 2002.

Gas Utility Operations 2004 2003 2002 (Millions of Dollars)

Operating Revenues $523.8 $513.0 $389.8 Cost of Gas Sold 376.9 355.4 240.8 Gross Margin $146.9 $157.6 S 149.0 We believe that 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 gross margin and therm deliveries by customer class during 2004, 2003 and 2002.

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Gas Gross Margin Gas Therm Deliveries Gas Utility Operations 2004 2003 2002 2004 2003 2002 (Millions of Dollars) (Millions, Except Degree Days)

Customer Class Residential $95.7 $98.8 $95.3 342.3 361.0 345.4 CommerciallIndustrial 32.9 34.2 32.7 200.4 210.8 199.2 Interruptible 0.5 0.5 0.5 6.4 6.8 7.4 Total Gas Sold 129.1 133.5 128.5 549.1 578.6 552.0 Transported Gas 15.9 16.2 16.7 286.0 309.7 338.0 Other Operating 1.9 7.9 3.8 - - -

Total $146.9 $157.6 $149.0 835.1 888.3 890.0 Weather -- Degree Days (a)

Heating (6,739 Normal) 6,663 7,063 6,551 (a) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a twenty-year moving average.

2004 vs. 2003: Our total gas utility gross margin fell from $157.6 million in 2003 to $146.9 million in 2004 largely due to a decrease in therm deliveries resulting from less favorable weather. Total therm deliveries were 6.0% lower during 2004 primarily due to weather. As measured by heating degree days, 2004 was 5.7% warmer than 2003 and 1.1% warmer than normal, which reduced heating load. We estimate that weather reduced gross margin by approximately $5.4 million between the comparative periods. We also recognized $5.8 million less in gas cost incentive revenues under our gas cost recovery mechanisms when compared with 2003.

2003 vs. 2002: During 2003, our total gas utility gross margin improved by S8.6 million compared with 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, increasing heating load. A

$4.4 million increase in gas cost incentive revenues during 2003 under our gas cost recovery mechanism also contributed to the increased gross margin and operating revenues between the comparative periods. Total therm deliveries of natural gas decreased by 0.2% during 2003 but varied within customer classes. Volume deliveries for the residential and commercial/industrial customer classes increased by 4.5% and 5.8%, respectively, reflecting the colder weather.

Other Operation and Maintenance Expenses 2004 vs. 2003: Other operation and maintenance expenses increased by $60.7 million or 7.7% during 2004 compared with 2003. The largest increase related to $36.3 million of costs that we recognized under a lease agreement in connection with the construction of the power plant in Port Washington, Wisconsin under Wisconsin Energy's Power the Futureplan. Under the lease agreement, we are billed for costs, and these costs are deferred on our balance sheet. The costs are amortized to expense as we recover revenues from our customers under specific pricing agreements which allow us to recover the lease costs. As noted in the electric revenue discussion, increased revenues resulting from the order we received from the PSCW in May 2004 basically offset these lease costs on a dollar for dollar basis. In addition to the lease costs, we also recognized $4.0 million of increased public benefits costs which were also included in the May 2004 price increase.

In addition, our employee benefit costs increased $13.7 million due to increased pension and medical costs. We also incurred $22.3 million of severance-related costs during 2004, primarily due to a Voluntary Separation Plan which was offered to certain management and represented employees in the second half of 2004. Partially offsetting these increases was a $5.7 million reduction in bad debt costs due to improved collections and the timing of a deferral order.

2003 vs. 2002: During 2003, our other operation and maintenance expenses increased by $47.7 million or 6.5%

when compared with 2002. The increase was primarily attributable to approximately $39.4 million of higher electric transmission expenses. A surcharge for transmission costs that was approved by the PSCW in October 2002 offset the impact of higher transmission expenses. Pension, medical and other benefit costs increased by approximately $25 million during 2003. Overall, nuclear costs were $8.7 million higher during 2003 compared with A-9

2002 due to an extended outage and costs associated with supplemental inspections at Point Beach by the U.S.

Nuclear Regulatory Commission (NRC). Insurance recoveries of approximately $11.1 million in 2003 compared to associated settlement costs of S17.3 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 S7.2 million more in 2003 than in 2002 on the implementation of Wisconsin Energy's Powver the Future strategy.

Other Income and Deductions, Net 2004 vy. 2003: Net consolidated other income and deductions were up $2.0 million in 2004 as compared to 2003, primarily due to a civil penalty that we agreed to pay in the second quarter of 2003 pursuant to the terms of a consent decree entered into with the United States Environmental Protection Agency (EPA), an increase in our interest in the earnings of ATC, our unconsolidated affiliate, and to the recognition of higher carrying costs on deferred electric transmission costs, partially offset by an increase in contributions to the WEC Foundation. For additional information, see "Note A -- Summary of Significant Accounting Policies" in the Notes to Consolidated Financial Statements.

2003 vs. 2002: During 2003, net consolidated other income and deductions were up by $7.2 million compared to 2002. This increase was primarily due to costs that we recorded in 2002 associated with early bond redemptions as well as higher equity in the earnings of ATC and the recognition of higher carrying costs on deferred electric transmission costs between the comparative periods partially offset by the civil penalty we agreed to pay in 2003 pursuant to the terms of a consent decree with the EPA. Also, we recorded S5.3 million of costs associated with bond redemptions in 2002.

Interest Expense 2004 vs. 2003: Total interest expense decreased by S 1.6 million in 2004 compared with 2003. This decrease primarily reflects the replacement of higher cost long-term debt outstanding during 2003 with lower cost borrowings outstanding during 2004. In August 2004, we retired S140 million of 7-1/4% First Mortgage Bonds at their scheduled maturity through the issuance of lower-cost short-term debt.

2003 vs. 2002: Total interest expense decreased by $1.5 million in 2003 compared to 2002. This decline was primarily due to lower interest rates.

Income Taxes 2004 vs. 2003: Our effective income tax rate was 38.0% in 2004 compared with 37.6% in 2003. This increase in the effective income tax rate was due primarily to a reduction in tax credits associated with rehabilitation projects.

2003 v's. 2002: Our effective income tax rate was 37.6% in 2003 compared with 37.8% in 2002. The 2003 and 2002 effective income tax rates reflect tax credits associated with rehabilitation projects.

LIQUIDITY AND CAPITAL RESOURCES CASH FLOWS The following table summarizes our cash flows during 2004, 2003 and 2002:

Wisconsin Electric 2004 2003 2002 (Millions of Dollars)

Cash Provided by (Used in)

Operating Activities $630.8 S514.2 $656.3 Investing Activities (S423.9) ($402.8) ($416.1)

Financing Activities (S200.8) ($104.7) ($248.2)

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Operating Activities Cash provided by operating activities increased to $630.8 million during 2004 compared with $514.2 million during the same period in 2003. This increase was due in large part to higher deferred income taxes and to lower working capital requirements between the comparative periods.

Cash provided by operating activities decreased to $514.2 million during 2003 compared with $656.3 million during the same period in 2002. This decrease was primarily due to a $116.4 million refund received in the first quarter of 2002 from a favorable court ruling in the Giddings & Lewis/City of West Allis litigation, increased use of working capital in 2003 due to higher natural gas prices and higher volumes of natural gas in storage and increased tax payments.

Investing Activities During 2004, we invested a total of $423.9 million in our business compared to $402.8 million during 2003.

Between the comparative periods, capital expenditures were up $15.2 million, but we spent $8.3 million less on nuclear fuel due to the timing of scheduled outages at Point Beach. In 2004, we made a $23.2 million capital contribution to ATC.

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

Financing Activities During 2004, we used $200.8 million for financing activities compared with using $104.7 million during 2003 and using $248.2 million during 2002. The following table summarizes our cash flows from financing activities:

2004 2003 2002 (Millions of Dollars)

Dividends to Wisconsin Energy ($179.6) ($179.6) ($179.6)

Increase (Reduction) in Total Debt (19.5) 94.1 (67.4)

Other (1.7) (19.2) (1.2)

Cash Used in Financing ($200.8) ($104.7) ($248.2)

In November 2004, we issued $250 million of unsecured 3.50% debentures due December 1, 2007, the proceeds of which were used to pay down outstanding commercial paper.

In June and August 2003, we refinanced a total of $485 million of our debt securities. These debt refinancings are being accounted for using the PSCW-authorized revenue neutral method of accounting, under which net debt extinguishment costs in the amount of approximately $18.3 million were deferred and are being amortized over an approximately two year period based upon the level of interest savings achieved.

For additional information concerning changes in our long-term debt, see "Note G -- Long-Term Debt" in the Notes to Consolidated Financial Statements.

CAPITAL RESOURCES AND REQUIREMENTS Capital Resources We anticipate meeting our capital requirements during 2005 primarily through internally generated funds and short-term borrowings supplemented by the issuance of intermediate or long-term debt securities depending on market conditions and other factors. Beyond 2005, we anticipate meeting our capital requirements through internally generated funds supplemented, when required, by the issuance of debt securities.

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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.

Environmental Trust Financing: In March 2004, the Governor of Wisconsin signed into law a measure that gives utilities the ability to securitize the portion of customer bills that recovers the cost of certain investments intended to improve the environment. The measure would result in a lower cost to customers when compared to traditional financing and ratemaking. In June 2004, we filed an application with the PSCW that sought authority to issue up to

$500 million of environmental trust bonds pursuant to this legislation. In October 2004, the PSCW approved an order authorizing us to issue environmental trust bonds to finance the recovery of $425 million of environmental control costs plus up-front financing costs. The proposed terms of the bonds are subject to further PSCW approval prior to issuance. In January 2005, we notified the PSCW that we would not issue the environmental trust bonds until the satisfactory resolution of tax rulings associated with the proposed securitization and the resolution of the Elm Road proceedings before the Wisconsin State Supreme Court. The issuance would also be dependent upon market conditions.

We have credit agreements that provide liquidity support for our obligations with respect to commercial paper.

As of December 31, 2004, we had S372.0 million of available unused lines of bank back-up credit facilities on a consolidated basis and $189.5 million of total consolidated short-term debt outstanding.

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, 2004:

Letters Facility Facility Total Facility of Credit Credit Available Maturity Term (Millions of Dollars)

$250.0 $3.0 $247.0 Jun-2007 3 year

$125.0 $- S125.0 Nov-2007 3 year On June 23, 2004, we entered into an unsecured three year S250 million bank back-up credit facility to replace a

$250 million 364 day credit facility that was expiring. This facility will expire in June 2007 and may be extended for an additional 364 days, subject to lender agreement.

On November 1, 2004, we entered into an unsecured three year $125 million bank back-up credit facility to replace a $100 million Il-month letter agreement that was expiring. This facility will expire in November 2007 and 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 2004 2003 (Millions of Dollars)

Common Equity $2,204.2 53.4% $2,131.9 52.3%

Preferred Stock 30.4 0.7% 30.4 0.7%

Long-Tern Debt (including current maturities) 1,706.8 41.3% 1,599.5 39.2%

Short-Term Debt 189.5 4.6% 315.9 7.8%

Total S4.130.9 100.0% $4,077.7 100.0%

Access to capital markets at a reasonable cost is determined in large part by credit quality. The following table summarizes the ratings of our debt securities and preferred stock by Standard & Poors Corporation (S&P), Moody's Investors Service (Moody's) and Fitch Ratings (Fitch) as of December 31, 2004.

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S&P Moody's Fitch Commercial Paper A-2 P-I Fl Senior Secured Debt A- Aa3 AA-Unsecured Debt A- Al A+

Preferred Stock BBB A3 A The security rating outlooks assigned to us by S&P, Moody's and Fitch are all stable.

In March 2003, S&P lowered its corporate credit rating for us from A to A-. S&P lowered its rating for our senior secured debt from A to A-. S&P affirmed our A- senior unsecured debt rating. S&P lowered the rating for our preferred stock from BBB+ to BBB. S&P lowered our short-term rating from A-I to A-2.

In October 2003, Moody's downgraded certain of our security ratings. Moody's lowered our senior secured debt rating from Aa2 to Aa3, our senior unsecured debt rating from Aa3 to Al and our preferred stock debt rating from A2 to A3. Moody's confirmed our P- I commercial paper rating.

In October 2003, Fitch downgraded certain of our security ratings. Fitch lowered our senior secured debt rating from AA to AA-, our senior unsecured debt rating from AA- to A+ and our preferred stock rating from AA- to A.

Fitch lowered our commercial paper rating from Fl+ to Fl.

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 $460.0 million during 2005. Due to changing environmental and other regulations such as air quality standards and electric reliability initiatives that impact us, future long-term capital requirements may vary from recent capital requirements. We currently expect our capital expenditures, excluding the purchase of nuclear fuel and expenditures for new generating capacity contained in Wisconsin Energy's Power the Futurestrategy, to be between $350 million and $475 million per year during the next five years.

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 of approximately

$1.6 billion as of December 31, 2004. These trusts hold investments that are subject to the volatility of the stock market and interest rates. For further information, see ."Note L - Benefits" in the Notes to Consolidated Financial Statements.

Off-Balance Sheet Arrangements: We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support commodity contracts and other payment obligations. We believe that such 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.

For further information, see "Note M -- Guarantees" in the Notes to Consolidated Financial Statements.-

We have identified three tolling and purchased power agreements with third parties but have been unable to determine if we are the primary beneficiary of any of these three variable interest entities as defined by Financial Accounting Standard Board (FASB) Interpretation 46, Consolidation of Variable Interest Entities (FIN 46). As a result, we do not consolidate these entities. Instead, we account for one of these contracts as a capital lease and for the other two contracts as operating leases. We have included our contractual obligations under all three of these; contracts in our "Contractual Obligations/Commercial Commitments" disclosure that follows. For additional information, see "Note D -- Variable Interest Entities" in the Notes to Consolidated Financial Statements.

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Contractual Obligations/ComotiercialCotmntittnents: We have the following contractual obligations and other commercial commitments as of December 31, 2004:

Payments Due by Period Less than More than Contractual Obligations (a) Total I year 1-3 years 3-5 years 5 years (Millions of Dollars)

Long-Term Debt Obligations (b) $3,114.3 $40.0 $593.7 S 107.7 $2,372.9 Capital Lease Obligations (c) 1,797.4 78.3 187.4 173.7 989.0 Operating Lease Obligations (d) 270.4 50.4 99.3 54.6 66.1 Purchase Obligations (e) 501.7 192.4 169.6 56.3 83.4 Other Long-Tenn Liabilities 0.4 0.2 0.2 -

Total Contractual Obligations S5,684.2 $361.3 $1,050.2 $392.3 $3,880.4 (a) The amounts included in the table are calculated using current market prices, for vard curves and other estimates.

Contracts with multiple unknown variables have been omitted from the analysis.

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

(c) Capital Lease Obligations for nuclear fuel lease and purchase power commitments. Includes payments on a S330 million capital lease obligation that is expected to be recorded in the third quarter of 2005 when We Powers Port Washington Generating Station Unit I is scheduled to go into commercial operation.

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

(e) Purchase Obligations under various contracts for the procurement of fuel, power, gas supply and associated transportation and for information technology and other services for utility operations.

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

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:

Construction Risk: In December 2002, the PSCW issued a written order granting a CPCN to commence construction of We Power's Port Washington Generating Station (Port Washington units) consisting of two 545 megawatt natural gas-fired combined cycle generating units on the site of our 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.

In addition, in November 2003, the PSCW issued a written order granting a CPCN for We Power to commence construction of two 615-megawatt super critical pulverized coal generating units (Elm Road units) on the site of our 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. For additional information, see "Power the Future -

Elm Road" below.

Large construction projects of this type are subject to usual construction risks over which We Power 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, the inability to obtain or the cost of labor or materials, the inability of the general contractor or subcontractors to perform under their contracts, strikes, adverse weather conditions, the inability to obtain necessary permits in a timely manner and changes in applicable laws or regulations, governmental actions and events in the global economy. Iffinal costs for the construction of the Port Washington units or the Elm Road A-14

units exceed the fixed costs allowed in the PSCW order, We Power cannot recover this excess from us or our customers unless specifically allowed by the PSCW. Project costs above the authorized amount, but below a 5%

cap will be subject to a prudence determination by the PSCW.

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

As noted below in Commodity Price Risk, our electric operations operate under a fuel cost adjustment clause in the Wisconsin retail jurisdiction for fuel and purchased power costs associated with the generation and delivery of electricity. This clause establishes a fuel base for fuel and purchased power costs, and we assume the risks and benefits of fuel cost variances that are within 3% of the fuel base. We are subject to risks associated with the regulatory approval process including regulatory lag once the costs fall outside the 3% variance of the fuel base.

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 until January 2006, the end of a five year rate freeze associated with Wisconsin Energy's merger with WICOR, Inc. in 2000. Until this time, we will operate under an approved transaction mechanism similar to the old fuel cost adjustment procedure. For 2004, 2003 and 2002, our actual fuel and purchased power costs exceeded our fuel base rates by $0.8 million, $7.6 million and $2.3 million, respectively. In 2004, 2003 and 2002, our electric rates included a fuel surcharge.

Commodity Price Risk: In the normal course of business, we utilize contracts of various duration for the forvard sale and purchase of electricity. This is done to effectively manage utilization of available generating capacity and energy during periods when available power resources are expected to exceed the requirements of our obligations.

This practice may also include forward contracts for the purchase of power during periods when the anticipated market price of electric energy is below expected incremental power production costs. We manage our fuel and gas supply costs through a portfolio of short and long-term procurement contracts with various suppliers for the purchase of coal, uranium, natural gas and fuel oil.

Wisconsin's retail electric fuel cost adjustment procedure mitigates some of our risk of electric fuel cost fluctuation.

If cumulative fuel and purchased power costs for electric utility operations deviate from a prescribed range when compared to the costs projected in the most recent retail rate proceeding, retail electric rates may be adjusted, subject to risks associated with the regulatory approval process including regulatory lag. Regulatory lag risk occurs between the time we incur costs in excess of what we collect in rates and the time we receive approval for interim rates following a regulatory filing. Regulatory lag risk can increase or decrease due to many factors which may also change during this approval period including commodity price fluctuations, unscheduled operating outages or unscheduled maintenance. In 2002, the PSCW authorized the inclusion of price risk management financial instruments for the management of our electric utility gas costs. During 2003, we implemented a gas hedging program approved by the PSCW.

The PSCW has authorized dollar for dollar recovery for the majority of natural gas costs for our gas utility operations through a gas cost recovery mechanism, which mitigates most of the risk of gas cost variations. For additional information concerning the electric utility fuel cost adjustment procedure and our gas cost recovery mechanism, see "Rates and Regulatory Matters" below.

Natural Gas Costs: Significant increases in the cost of natural gas affect our electric and gas utility operations.

Natural gas costs have increased significantly because the supply of natural 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-fired 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 natural gas costs increase our working capital requirements resulting in higher gross receipts taxes in the state of Wisconsin. Higher natural gas costs combined with slower 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 not kept pace with rising natural gas costs, our risks related to bad debt expenses associated with non-paying customers have increased.

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

Weather: Our rates are set by the PSCW based upon estimated temperatures which approximate 20-year averages.

Our electric revenues are unfavorably sensitive to below normal temperatures during the summer cooling season, and to some extent, to above normal temperatures during the winter heating season. Our gas revenues are unfavorably sensitive to above normal temperatures during the winter heating season. A summary of actual weather information in our service territory during 2004, 2003 and 2002, as measured by degree-days, may be found above in "Results of Operations".

Interest Rate Risk: We have various short-term borrowing arrangements to provide working capital and general corporate funds. We also have variable rate long-term debt outstanding at December 31, 2004. 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, 2004 of our outstanding portfolio of S 189.5 million of short-term debt with a weighted average interest rate of 3.07% and S 165.4 million of variable-rate long-term debt with a weighted average interest rate of 1.72%. A one-percentage point change in interest rates would cause our annual interest expense to increase or decrease by approximately $1.9 million before taxes from short-term borrowings and by $1.7 million before taxes from variable rate long-term debt outstanding.

MarketableSecurities 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, 2004, we held, or Wisconsin Energy held on our behalf, the following total trust fund assets at fair value, primarily consisting of publicly traded debt and equity security investments.

Wisconsin Electric Power Company Millions of Dollars Pension trust funds $748.0 Nuclear decommissioning trust fund $737.8 Other post-retirement benefits trust funds $107.4 Fiduciary oversight of the pension and other post-retirement plan trust fund investments is the responsibility of a Chairman-appointed Investment Trust Policy Committee. Qualified external investment managers are engaged to manage the investments. Asset/liability studies are periodically conducted with the assistance of an outside investment advisor. The current study for the pension fund projects long-term, annualized returns of approximately 9%.

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

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

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Credit Rating Risk: We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. We do have certain agreements in the form of commodity and energy services contracts and employee benefit plans that could require collateral in the event of a credit ratings change to below investment grade, a termination payments if collateral is not provided, or an accelerated payment. At December 31, 2004, we estimate that the potential payments under these agreements that could result from credit rating downgrades totaled approximately $109.0 million.

Economic Risk. We are exposed to market risks in the regional Midwest economy.

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.

POWER THE FUTURE Under Wisconsin Energy's Power the Future strategy, we expect to meet a significant portion of our future generation needs through the construction of the Port Washington and Elm Road generating stations by We Power.

The new plants will be leased to us by We Power under long-term leases and we expect to recover the lease payments in our electric rates.

Power the Future - Port Washington

Background:

In December 2002, the PSCW issued a written order (the Port Order) granting us, as well as Wisconsin Energy and We Power, a CPCN to commence construction of the Port Washington Generating Station consisting of two 545-megawatt natural gas-fired combined cycle generating units (Port Units I and 2) on the site of our existing Port Washington Power Plant. The Port Order also authorized Wisconsin Gas to proceed with the construction of a connecting natural gas lateral and ATC to construct required transmission system upgrades to serve Port Units I and 2 as a result of their concurrent applications. In January 2003, we commenced demolition of two of our existing coal-fired units on the site to make room for the new units. In July 2003, We Power began construction of Unit I and expects the unit to be operational early in the third quarter of 2005. In October 2003, We Power received approval from the Federal Energy Regulatory Commission (FERC) to transfer by long-term lease certain associated FERC jurisdictional assets to us. In May 2004, Wisconsin Energy filed an updated demand and energy forecast with the PSCW to document market demand for additional generating capacity. We Power began site preparation of Unit 2 in May 2004. We expect Unit 2 to be operational in 2008.

Lease Terms: The PSCW approved the lease agreements and related documents under which we will staff, operate and maintain Port Units I and 2. Key terms of the leased generation contracts include:

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

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

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

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

> Fixed construction cost of the two Port units at $309.6 million and S280.3 million (2001 dollars) subject to escalation at the GDP inflation rate;

> Recovery of carrying costs during construction; and

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

In January 2003, we 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 Requests" below for further information.) We Power began collecting certain costs from us in the third quarter of 2003 as provided for in lease generation contracts that were signed in May 2003. We defer the lease costs on our balance sheet, and we amortize the costs to expense as we recover the costs in rates.

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Legal and Regulatory Matters: In March 2003, an individual who participated in the PSCW's Port Washington CPCN proceedings 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 Order granting the CPCN (Port Order). This case was remanded back to the PSCW which, after reviewing certain environmental matters, affirmed the original CPCN.

The same individual then filed additional appeals challenging the CPCN; however, in October 2004, the Court, at the request of the individual, dismissed all outstanding appeals related to the CPCN.

The construction of Port Units I and 2 required the receipt of many permits including permits relating to air and water quality. All construction permits have been received. In addition, with the construction of Port Units I and 2, Wisconsin Gas needed the approval from the WDNR for the construction of a natural gas lateral which will deliver fuel to the Units. After several discussions with the WDNR, Wisconsin Gas agreed to modify the planned route and mitigate certain environmental impacts. In July 2003, Wisconsin Gas received approval for construction for the natural gas lateral and the lateral was completed in December 2004.

Power the Future- Elm Road Backgrounil: In November 2003, the PSCW issued an order (the Elm Road Order) granting us, as well as Wisconsin Energy and We Power, a CPCN to commence construction of two 615-megawatt coal-fired units (the Elm Road units) to be located near the site of our existing Oak Creek Power Plant. The first unit was scheduled to be operational in 2009 and the second unit was scheduled to be operational in 2010. The Elm Road Order concluded, among other things, that there was a need for additional electric generation for Southeastern Wisconsin and that a diversity of fuel sources best serves the interests of the state. The total cost for the two units was set at

$2.19 billion, adjusted for inflation, and the order provided for recovery of excess costs of up to 5% of the total project. subject to a prudence review by the PSCW. The CPCN was granted contingent upon us obtaining the necessary environmental penmits. In April 2004, We Power entered into a contract with Bechtel to secure necessary engineering, design and construction services and major equipment components for these units. We Power expects that it will have co-owners that will have an interest in the project of approximately 17%.

Lease Terms: In October 2004, the PSCW approved the lease generation contracts between us and We Power for the Elm Road units. Key terms of the leased generation contracts include:

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

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

> Recovery of carrying costs during construction; and

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

In April 2004, the PSCW approved the deferral of certain costs related to the Elm Road units for recovery in future rates. In May 2004, we filed a request with the PSCW for an increase in rates due to several factors including the Elm Road lease payment costs. We expect to receive an order from the PSCW on this request in April 2005.

Legal and Regulatory Matters: The construction of the Elm Road units is subject to a number of regulatory approvals and legal challenges by third parties. The most notable remaining legal challenges relate to the Elm Road CPCN.

In November 2004, a Dane County Circuit Court judge reviewing challenges to the PSCW's order authorizing We Power to build two coal-fired generating facilities on the site of our existing Oak Creek Power Plant vacated the CPCN and remanded it back to the PSCW for additional proceedings. The Court determined that the PSCW committed errors in determining the completeness of the application and in its decisions on several other points.

We, along with Wisconsin Energy, We Power, the PSCW and the WDNR filed motions for direct, expedited appeal in mid - December 2004 with the Supreme Court of Wisconsin. We believe that the appeal represents a clear need for prompt, ultimate judicial resolution of matters involving substantial public importance to Wisconsin. While the Dane County decision specifically addresses the Oak Creek expansion, we believe this order would make it very difficult for any new generation facilities to be built anywhere in the state. In addition to serious questions of reliability and availability of power, this decision also poses increased costs to customers. In January 2005, the A-18

Supreme Court of Wisconsin agreed to hear the appeal. The Supreme Court scheduled oral arguments in this matter for March 30,2005. We anticipate a decision to be issued no later than June 30, 2005.

We continue to work with the PSCW, the WDNR and other agencies to obtain all required permits and project approvals. The major permits and the status regarding these permits are discussed below.

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 permit for wetlands and waterways alterations and construction on the bed of Lake Michigan for the construction of the Elm Road units. That request was granted and assigned to an administrative law judge. The hearing took place in August 2004 and post hearing briefing concluded in September 2004. In November 2004, the administrative law judge approved the WDNR's issuance of the wetlands and waterways permit (Chapter 30 permit) for the Elm Road units. In December 2004, two opponents filed a petition for review of the decision in Dane County Circuit Court. In January 2005, we filed a motion to dismiss the opponents' petition. The WDNR has joined in this motion.

Wisconsin Energy has applied to the WDNR to modify the existing Wisconsin Pollution Discharge Elimination System (WPDES) permit at this location that is required for operation of the water intake and discharge system for the planned Elm Road and existing Oak Creek generating units. In January 2005, the WDNR published its notice of intent to issue a WPDES permit with a public comment period ending in February 2005. Additionally, Wisconsin Energy has applied to the Army Corps of Engineers for the federal permits necessary for the construction of the Elm Road units. We anticipate decisions on these permits in the first half of 2005. Decisions favorable to the project may be contested by project opponents.

In January 2004, the WDNR issued the Air Pollution Control and Construction Permit to us for the Elm Road units.

In February 2004, certain project opponents filed a petition for judicial review in the Dane County Circuit Court. At the same time, the project opponents submitted a request for a contested case hearing with the WDNR which was granted. Petitioners subsequently agreed to dismiss their petition for judicial review. The contested case hearing was held in October 2004. In February 2005, an administrative law judge issued a decision affirming the WDNR January 2004 issuance of the Air Pollution Control and Construction Permit. In February 2005, the project opponents filed a petition for judicial review of the decision with the Dane County Circuit Court.

The terms of We Power's construction contract with Bechtel for the Elm Road units presently provide that full notice to proceed must be given to Bechtel by July 1, 2005. In order for Bechtel to be able to proceed on July 1, it must begin site mobilization activities in May. Wisconsin Energy is unable to state whether the project could proceed if delayed beyond July 1, 2005.

In July 2004, we entered into an environmental and economic agreement with the Town of Caledonia (the community immediately adjacent to the Oak Creek plant site), covering Wisconsin Energy's plans for expansion of the Oak Creek plant site and the associated increase in train and vehicular traffic that would result in the community.

The agreement was approved by the Town Board in July 2004. The initial discussions were held at the suggestion of the PSCW in its decision approving the Elm Road Order. Under the agreement, we will take certain actions to mitigate the impact on the Town of construction of the Elm Road units, as well as pay the Town to mitigate certain community health and safety impacts. The Town will cooperate with us in the issuance of necessary local permits and dismiss its judicial appeal of the PSCW permits issued. The Town's appeal was dismissed at the Town's request in September 2004. Portions of the agreement concerning the impact payments are subject to review and approval by the PSCW. Our direct obligations under the agreement are not expected to have a material impact on our financial condition or results of operations.

RATES AND REGULATORY MATTERS The PSCW regulates our retail electric, natural gas, and steam rates in the state of Wisconsin, while the FERC regulates our 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. We estimate that approximately 88% of our electric utility revenues are regulated by the PSCW, 7% are regulated by the MPSC and the balance of our electric revenues are regulated by the FERC. All of our gas and steam utility revenues are regulated by the PSCW. Orders from the PSCW can be viewed at http://psc.wi.gov/ and orders from the MPSC can be viewed at wvww.michigan.gov/mpsc/.

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Overview: In the state of Wisconsin, our rates are governed by an order from the PSCW issued in March 2000 in connection with the approval of Wisconsin Energy's WICOR acquisition. Under this order, we are restricted from increasing Wisconsin rates for a five year period ending December 31, 2005, with certain exceptions. We may seek biennial rate reviews during the five-year rate restriction 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.

In addition, 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. As identified below, we have received rate increases during the five year restriction period for the exceptions listed above. Under the March 2000 order, a full rate review will be required by the PSCW for rates beginning in January 1, 2006. We expect to make a filing in 2005 in connection with this PSCW review.

The table below summarizes the anticipated annualized revenue impact of recent rate changes. Our current Wisconsin rates are based on an authorized return on common equity of 12.2%.

Incremental Annualized Percent Revenue Change Effective Service Increase in Rates Date (Millions) (%)

Fuel electric, Michigan $3.4 8.0% January 1, 2005 Fuel electric, Michigan S1.3 3.1% October 1, 2004 Retail steam, Wisconsin S0.5 3.4% May 5,2004 Retail electric, Wisconsin (a) S59.0 3.3% May 5, 2004 Fuel electric, Michigan $3.3 7.6% January 1,2004 Fuel electric, Wisconsin (b) $6.1 0.3% October 2, 2003 Fuel electric, Wisconsin (b) $55.1 3.3% March 14, 2003 Fuel electric, Michigan $0.9 2.0% January 1, 2003 Retail electric, Wisconsin (c) $48.1 3.2% October 22, 2002 Retail electric, Michigan (d) $3.2 7.8% September 16, 2002 Fuel electric, Michigan $1.6 3.8% January 1, 2002 (a) In May 2004, the PSCW issued a final order authorizing an increase in electric rates for costs associated with the Port Washington power plant under construction and increased costs associated with low-income energy assistance.

(b) 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 555.1 million of additional fuel costs on an annualized basis subject to true up.

(c) In October 2002, the PSCW issued its order authorizing a surcharge for recovery of 548.1 million of annual estimated incremental costs associated with the formation and operation of ATC.

(d) In September 2002, the MPSC issued an order authorizing an annual electric retail rate increase of S3.2 million. 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.

Limited Rate Adjustment Requests 2005 Revenue Deficiencies: In May 2004, we filed an application with the PSCW for an increase in electric and steam rates for anticipated 2005 revenue deficiencies associated with (1) costs for the new Port Washington Generating Station and the Elm Road Generating Station being constructed as part of the Power the Future strategy, (2) costs associated with our energy efficiency procurement plan, and (3) costs associated with making changes to our steam utility systems as part of the reconstruction of the Marquette Interchange highway project in downtown Milwaukee, Wisconsin. The filing identified anticipated revenue deficiencies in 2005 attributable to Wisconsin in the amount of S84.8 million (4.5%) for electric operations and $0.5 million (3.6%) for steam operations. In January A-20

2005, as a result of litigation involving the Elm Road units, we amended this filing to reduce the total revenue request to $52.4 million. We anticipate receiving an order from the PSCW before April 2005.

2005 Fuel Recovery Filing: In February 2005, we filed an application with the PSCW for an increase in electric rates in the amount of $114.9 million due to the increased costs of fuel and purchased power as a result of customer growth and the increase in the reliance upon natural gas as a fuel source. We expect to receive approval of the increase in fuel recoveries on an interim basis in March 2005. The revenues associated with this filing will be subject to refund and the costs associated with the filing will be audited by the PSCW. Under the fuel rules, we would have to refund to customers any over recoveries of fuel costs plus interest at a rate of 12.2%.

Other Utility Rate Matters Electric Transmission Cost Recovery: We transferred all of our transmission assets with the formation of ATC in January 2001. In connection with the formation of ATC, our transmission costs have escalated due to the socialization of costs within ATC and increased transmission requirements in the state. In 2002, in connection with the increased costs experienced by our customers, the PSCW issued an order which allowed the deferral of transmission costs in excess of amounts imbedded in rates. We are allowed to earn a return on the unrecovered transmission costs at our weighted average cost of capital. As of December 31, 2004, we have deferred

$109.6 million of unrecovered transmission costs. We expect to begin to recover these costs beginning in 2006.

Fiuel CostAdjustment Procedure: Within the state of Wisconsin, we operate under a fuel cost adjustment clause for fuel and purchased power costs associated with the generation and delivery of electricity and purchase power contracts. Imbedded within its base rates is an amount to recover fuel costs. Under the current fuel rules, no adjustments are made to rates as long as fuel and purchased power costs are expected to be within a 3% band of the costs imbedded in current rates for the twelve month period ending December 31. If however, annual fuel costs are expected to fall outside of the 3% band, and actual interim costs fall outside of established ranges, then we may file for a change in fuel recoveries on a prospective basis.

In Michigan, our electric utility operates under a Power Supply Cost Recovery (PSCR) mechanism which generally allows for the recovery of fuel and purchase power costs on a dollar for dollar basis.

Gas Cost Recovery'Mechanism: Our natural gas operations operate under a gas cost recovery mechanism (GCRM) as approved by the PSCW. Generally, the GCRM allows for a dollar for dollar recovery of gas costs. There is an incentive mechanism under the GCRM which allows for increased revenues if we acquire gas lower than benchmarks approved by the PSCW. We earned $0.2 million of additional revenues during 2004 under the incentive portion of the GCRM compared with $6.0 million during 2003 and $1.6 million during 2002.

BadDebt Costs: In 2003 and 2004, due to a combination of unusually high natural gas prices, a soft economy within our utility service territories, and limited governmental assistance available to low-income customers, we saw a significant increase in residential uncollectible accounts receivable. Because of this, we requested and received letters from the PSCW which allowed us to defer the costs of residential bad debts to the extent that the costs exceeded the amounts allowed in rates. As a result of these letters from the PSCW, we deferred approximately

$11.7 million in 2004 and $10.9 million in 2003 related to bad debt costs.

In December 2004, we filed with the PSCW a request to implement a pilot program, which, among other things, is designed to better match our collection efforts with the ability of low income customers to pay their bills. Included in this filing is a request to implement escrow accounting for all residential bad debt costs. In February 2005, the PSCW approved our pilot program and our request for escrow accounting.

Environmental Trust Financing: In March 2004, the Governor of Wisconsin signed into law a measure that gives utilities the ability to securitize the portion of customer bills that recovers the cost of certain investments intended to improve the environment. The measure would result in a lower cost to customers when compared to traditional financing and ratemaking. In June 2004, we filed an application with the PSCW that sought authority to issue up to

$500 million of environmental trust bonds pursuant to this legislation. In October 2004, the PSCW approved an order authorizing us to issue environmental trust bonds to finance the recovery of $425 million of environmental control costs plus up-front financing costs. The proposed terms of the bonds are subject to further PSCW approval prior to issuance. In January 2005, we notified the PSCW that we would not issue the environmental trust bonds A-21

until the satisfactory resolution of tax rulings associated with the proposed securitization and tile resolution of the Elm Road proceedings before the Wisconsin State Supreme Court. The issuance would also be dependent upon market conditions.

.1!lHwest Independent TrainsminssionSyswtem Operator, inc. (1Midwest ISO) Day 2: In January 2005, we requested deferral accounting treatment from the PSCW for incremental costs or benefits that may occur due to the implementation of the Midwest ISO Day 2 energy markets, except for locational marginal pricing (LMP) energy costs. We anticipate receiving a decision related to this request prior to the scheduled start of the Midwest ISO energy market on April 1, 2005.

Nuitclear Reftelinig Outages - 2005: In January 2005, we requested deferral accounting treatment for non-fuel operations and maintenance expenses related to the second nuclear refueling outage expected to occur in the fall of 2005. We estimate that the additional non-fuel operation and maintenance expense associated with the fall nuclear outage is approximately S15.0 million. The PSCW denied our request on March 10, 2005.

ELECTRIC SYSTEM RELIABILITY In response to customer demand for higher quality power required by modern digital equipment, we are evaluating and updating our electric distribution system as part of Wisconsin Energy's Powter 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-tenm, we are initiating a new asset management strategy that is expected to consistently provide the level of reliability needed for a digital economy, using nerv technology and advanced communications. In addition, we are participating in a world-wide consortium for electric infrastructure to support a digital society sponsored by the Electric Power Research Institute.

Implementation of Wisconsin Energy's Powver the Futurestrategy is subject to a number of state and federal regulatory approvals. For additional information, see "Pot'ertihe rutllre" above.

We had adequate capacity to meet all of our firm electric load obligations during 2004. All of our generating plants performed well during the hottest periods of the summer and all power purchase commitments under firm contract were received. During this period, public appeals for conservation were not required, nor was there the need to interrupt or curtail service to non-firm customers who participate in load management programs in exchange for discounted rates.

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

This incident also resulted in short outages to some firm customers.

We expect to have adequate capacity to meet all of our firm load obligations during 2005. 1lowever, extremely hot weather, unexpected equipment failure or unavailability could require us to call upon load management procedures during 2005 as we have in past years.

ENVIRONMENTAL MATTERS Consistent with other companies in the energy industry, we face potentially significant ongoing environmental compliance and remediation challenges related to current and past operations. Specific environmental issues affecting our utility operations include but are not limited to (I) air emissions such as carbon dioxide (CO2 ), sulfur dioxide (SO,), nitrogen oxide (NOJ), 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 (I) substituting new and cleaner generating facilities for older facilities as part of Wisconsin Energy's Pout'ertihe Future strategy, A-22

(2) developing additional sources of renewable electric energy supply, (3) participating in regional initiatives to reduce the emissions of NO. from our fossil fuel-based generating facilities, (4) entering into agreements with the WDNR and EPA to reduce emissions of SO 2 and NO. from our coal-fired power plants in Wisconsin and Michigan by more than 65% and mercury by 50% within 10 years, (5) recycling of ash from coal-fired 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 the ten years ending 2013. For further information concerning an associated consent decree, see "Note P -- 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.

NationalAmnbient Air Quality Standards: In 2004, EPA began implementing the National Ambient Air Quality Standards (NAAQS) for 8-hour ozone and fine particulate matter (PM2.5) by designating non-attainment areas in the country. The states are currently developing rules to implement the new standards. Although specific emission control requirements are not yet defined, we believe that the revised standards will likely require significant reductions in SO2 and NO, emissions from coal-fired generating facilities. We expect that reductions needed to achieve compliance with the 8-hour ozone attainment standard will be implemented in stages from 2007 through 2010, beginning with I-hour ozone reductions. 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. We are currently unable to predict the impact that the revised air quality standards might have on the operations of our existing coal-fired generating facilities.

Ozone Non-Attainmnent Standards: The 1-hour ozone non-attainment rules currently being implemented by the state of Wisconsin and ozone transport rules implemented by the state of Michigan limit NO. emissions in phases over the next five years.

We currently expect to incur total annual operation and maintenance costs of $1-2 million during the period 2004 through 2007 to comply with the Michigan and Wisconsin rules. In January 2000, the PSCW approved our comprehensive plan to meet the Wisconsin regulations, permitting recovery in rates of NO, emission reduction costs over an accelerated 10-year recovery period.

In April 2004, the EPA designated 10 counties in Southeastern Wisconsin as non-attainment areas for the 8-hour ozone NAAQS. States will be required to develop and submit State Implementation Plans to the EPA to demonstrate how they intend to comply with the 8-hour ozone NAAQS by June 2007. Reductions needed to achieve compliance with the 8-hour ozone attainment standard will be implemented in stages from 2007 through 2010. We believe that compliance with the NO, emission reductions requirements under the agreements with the WDNR and EPA will substantially mitigate costs to comply with the EPA's 8-hour ozone NAAQS.

In December 2004, the EPA designated PM2.5 non-attainment areas in the country. All counties in the state of Wisconsin were designated as attainment with the standard. EPA published proposed regulations called the Clean Air Interstate Rule (CAIR) in January 2004 to facilitate the states in meeting the 8-hour ozone and PM 2.5 standards by addressing the regional transport of SO 2 and NO,. The proposed rules would require NO, and SO 2 emission reductions in two phases from electric generating units located in a 28-state region within the eastern U.S.

Wisconsin and Michigan are affected states under CAIR. The EPA is planning to issue the final CAIR regulations by March 15, 2005. We believe that compliance with the NO, and S0 2 emission reductions requirements under the agreements with the WDNR and EPA will substantially mitigate costs to comply with the CAIR rule.

Aferciiry Emission ControlRulemzaking: 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 is expected to issue final rules by March 15, 2005. The compliance date for the final federal rules cannot be predicted at this time, but could be as early as 2008.

The WDNR independently developed mercury emission control rules that affect electric utilities in Wisconsin. The mercury control rules became effective in October 2004. The rules require emission reductions of 40% by 2010 and 75% by 2015. The rules explicitly recognize an underlying state statutory restriction that state regulations cannot be more stringent than those included in any federal program. The rules state that the WDNR must adopt state rule changes within 18 months of publication of any federal rules. State rules are to be changed to be consistent with, and no more restrictive than, any federal rules. Our compliance planning estimates show that no additional emission control investments are likely to be needed to meet the state mercury rules. This is because the federal rules are very likely to be in place prior to the compliance dates contained in the state rule. We are currently unable to predict the A-23

ultimate rules that will be developed and adopted by the EPA, and we are not able to predict the impact that the EPA's mercury emission control rulemakings might have on the operations of our existing or anticipated coal-fired generating facilities.

Mfanufactured Gas PlantSites: We are reviewing and addressing environmental conditions at a number of former manufactured gas plant sites. For further information, see "Note P -- Commitments and Contingencies" in the Notes to Consolidated Financial Statements.

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

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

LEGAL MATTERS PresqueIsle 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. During 2004, we reached settlements with an insurance carrier for approximately $9.1 million. We are continuing to pursue recovery against the remaining insurance carriers and other third parties. We are continuing to analyze and refine the costs associated with this matter.

Stray Voltage: On July 11, 1996, the PSCW issued a final order regarding the stray voltage policies of Wisconsin's investor-owned utilities. The order clarified the definition of stray voltage, affirmed the level at which utility action is required, and placed some of the responsibility for this issue in the hands of the customer. Additionally, the order established a uniform stray voltage tariff which delineates utility responsibility and provides for the recovery of costs associated with unnecessary customer demanded services.

In recent years, dairy farmers have commenced actions or made claims against us for loss of milk production and other damages to livestock allegedly caused by stray voltage, and more recently, ground currents resulting from the operation of our electrical system, even though that electrical system has been operated within the parameters of the PSCW's order. In 2003, the Wisconsin Supreme Court upheld a Court of Appeals' affirmance of ajury verdict against us in a stray voltage lawsuit and held that even though a utility company's measurement of stray voltage is below the PSCW "level of concern," that utility could still be found negligent in stray voltage cases. Additionally, the Court held that the PSCW regulations regarding stray voltage were only minimum standards to be considered by ajury in stray voltage litigation.

As a result of this case, claims by dairy farmers for livestock damage have been based upon ground currents with levels measuring less than the PSCW level of concern. Even though the claims which have been made against us with respect to stray voltage and ground currents are not expected to have a material adverse effect on our financial statements, we continue to evaluate various options and strategies to mitigate this risk.

NUCLEAR OPERATIONS Point Beach Nuclear Plant: We own two 518-megawatt electric generating units (Unit I and Unit 2) at Point Beach Nuclear Plant in Two Rivers, Wisconsin. The Plant is operated by Nuclear Management Company, LLC (NMC), a joint venture between us and affiliates of other unaffiliated utilities. Point Beach provided approximately 25% of our net electric energy supply during each of the three years ended December 31, 2004.

Each Unit at the Plant has a scheduled refueling outage approximately every 18 months. In 2004, Unit I had a scheduled refueling outage in the second quarter and in 2003, Unit 2 had a scheduled refueling outage over the third and fourth quarters. In 2005, Unit 2 is scheduled to have a refueling outage in the second quarter and Unit I is scheduled to have a refueling outage over the third and fourth quarters. During the 2005 scheduled refueling A-24

outages, wve will replace the reactor vessel heads at each Unit. This work, along with other planned maintenance, is expected to result in longer than normal outages. During scheduled refueling outages, we incur significant operations and maintenance costs for work performed during the outage and we incur costs associated with replacement power.

The United States Nuclear Regulatory Commission (NRC) operating licenses for Point Beach expire in October 2010 for Unit I and in March 2013 for Unit 2. In February 2004, we and NMC filed an application with the NRC to renew the operating license for both units for an additional 20 years. The NRC has indicated that they expect to act on the license renewal request before January 2006.

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 seven megawatts per generating Unit. We are currently evaluating the timing for implementation of the power uprate project.

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. We were assessed a fine of $60,000 related to issues identified with our emergency preparedness. NRC reviewed the adequacy of the revised Excellence Plan and its implementation, and NMC received a confirmatory action letter in April 2004. NRC 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.

Used Nuclear Fuel Storage and Disposal: We are authorized to load and store sufficient dry fuel storage containers to allow Point Beach Units I 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 Nuclear Waste Policy Act established the Nuclear Waste Fund which is composed of payments made by the generators and owners of such waste and fuel. Effective January 31, 1998, the Department of Energy failed to meet its contractual obligation to begin removing used fuel from Point Beach, a responsibility for which we have paid a total of $200.3 million into the Nuclear Waste Fund over the life of the plant.

On August 13, 2000, the United States Court of Appeals for the Federal Circuit ruled in a lawsuit brought by Maine Yankee and Northern States Power Company that the Department of Energy's failure to begin performance by January 31, 1998 constituted a breach of the Standard Contract, providing clear grounds for filing complaints in the Court of Federal Claims. Consequently, we filed a complaint on November 16, 2000 against the Department of Energy in the Court of Federal Claims. The matter is pending. We have incurred substantial damages to date and damages continue to accrue. We are seeking recovery of our damages in this lawsuit.

In July 2002, President Bush signed a resolution which allowed the United States Department of Energy to begin preparation of the application to the NRC for a license to design and build a spent fuel repository in Yucca Mountain in Nevada. The Department of Energy has indicated that it does not expect a permanent used fuel repository to be A-25

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.

INDUSTRY RESTRUCTURING AND COMPETITION Electric Utility Industry Across the United States, electric industry restructuring progress remains slow as it has been subsequent to the California price and supply problems in early 2001. The FERC continues to strongly support large Regional Transmission Organizations (RTOs), which will affect the structure of the wholesale market To this end, the Midwest ISO is expected to implement a bid-based market including the use of LMPs to value electric transmission congestion. The Midwest ISO energy markets are currently slated to commence operation on April 1, 2005. The timeline for restructuring and retail access continues to be stretched out and it is uncertain when retail access will happen in Wisconsin. However, Michigan has adopted retail choice which potentially affects our Michigan operations. Deliberations are expected to continue in Congress on a federal energy bill containing changes that would impact the electric utility industry. In the past few years, bills have passed the U. S. House of Representatives, but were not passed by the Senate. Major issues in industry restructuring, implementation of RTO markets and market power mitigation received substantial attention in 2004. We continue to focus on infrastructure issues through Wisconsin Energy's Power the Future growth strategy.

Restructuring in Wisconsitn: 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.

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

As of January 1, 2002, our Michigan retail customers were allowed to remain with their regulated utility at regulated rates or choose an alternative electric supplier to provide power supply service. We have maintained our generation capacity and distribution assets and provide regulated service as we have in the past. We continue providing distribution and customer service functions regardless of the customer's power supplier.

Competition and customer switching to alternative suppliers in our service territory in Michigan has been limited.

With the exception of two general inquiries, no alternate supplier activity has occurred in our service territory in Michigan, reflecting the small market area, our competitive regulated power supply prices and a lack of interest in general in the Upper Peninsula of Michigan as a market for alternative electric suppliers.

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

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

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

Midwest ISO: In connection with its status as a FERC approved RTO, the Midwest ISO is in the process of implementing a bid-based energy market which is currently scheduled to be implemented on April 1, 2005. As part of this energy market, the Midwest ISO is developing a market-based platform for valuing transmission congestion premised upon the LMP system that has been implemented in certain northeastern and mid-Atlantic states. As proposed to the FERC and preliminarily approved, the LMP system will include the ability to mitigate or eliminate congestion costs through the use of Financial Transmission Rights (FTRs), 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.

Currently, there are several different estimates, both positive and negative, of the impacts of the LMP pricing system on Wisconsin and the Upper Peninsula of Michigan's utilities (also known as WUMS utilities).

In August 2004, the FERC accepted the Midwest ISO Energy Markets Tariff (August 2004 Plan), subject to further development on certain issues and subsequent compliance filings by the Midwest ISO. Included in the plan were mitigation features, which were proposed by us and other WUMS utilities, to minimize the potential cost impacts of the start of the market on the WUMS utilities. Also included was an FTR mitigation plan for entities in highly congested areas such as WUMS. The August 2004 Plan is subject to numerous requests for rehearing which may result in further modifications to the Tariff.

It is unknown at this time what, if any, financial impact the LMP congestion pricing system might have on us. The Midwest ISO recently completed its first allocation of FTRs for the period starting April 1, 2005 and ending August 31, 2005. We received 94% of the FTRs that we requested in the allocation process. The FTR allocation process will be performed again for the period from September 1, 2005 to May 31, 2006, and it is unknown how many FTRs wve will be granted during that allocation process.

The Midwest ISO is currently deferring the costs to develop and start-up its energy market (new software systems and personnel). Once the market is operational, the development and start-up costs will be charged to the Midwest ISO's market participants, including us.

To mitigate the risks of this new bid-based energy market, we requested deferral accounting treatment from the PSCW in January 2005 for incremental costs or benefits that may occur due to the implementation of the Midwest ISO "Day 2" energy markets. Our request excluded LMP energy costs which will be recoverable under Wisconsin's Fuel Cost Adjustment Procedure. We anticipate receiving a decision related to this request prior to the scheduled start of the Midwest ISO market on April 1, 2005.

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 the Midwest ISO; but it also was the subject of a proceeding in which a new rate design governing service in the combined Midwest ISO and PJM Interconnection, L.L.C (PJM) service territories was to be developed. However, the FERC has ordered the elimination of through and out transmission charges for transactions between the Midwest ISO and the PJM.

In November 2004, FERC issued an order allowing the existing Midwest ISO license plate rate design to continue until at least February 1, 2008. In addition, FERC ordered a seams elimination charge to be paid by Midwest ISO LSE's from December 1, 2004 until March 31, 2006 to compensate transmission owners for the loss of revenues resulting from the joining of an RTO and/or FERC's elimination of through and out transmission charges between the Midwest ISO and PJM. The FERC ordered that certain existing transmission transactions continue to pay for through and out service from December 1, 2004 until March 31, 2006. The details of the seams elimination charge and the quantification of the existing transaction charge are the subject of a hearing process initiated by FERC in a February 2005 order. We are currently unable to determine the impact on us.

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Lost Rereniue 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, 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.

Discussions as to appropriate lost revenue charges with regard to several entities' decisions, including that of Commonwealth Edison Company, a non-affiliated Illinois utility that provides us with transmission service, to place their transmission facilities under the control of PJM were terminated in September 2004. In lieu of charging the previously ordered seam elimination cost adjustment, the FERC pennitted the Midwest ISO, PJM and the affected entities, including Commonwealth Edison Company, to continue to charge their existing rates for transmission to adjoining areas until December 1, 2004, after which the affected entities as directed by the FERC, were required to develop a new rate design that will eliminate the multiple charges between the service territories of the Midwest ISO and PJM. Proposals addressing the rate design issue were filed at the FERC on October 1,2004. These proposals were rejected by the FERC and the transmission owners. The Midwest ISO and PJM were directed to file Seams Elimination Charge Adjustment (SECA) proposals to be effective December 1, 2004. As previously noted, the reasonableness and magnitude of the proposed SECA charges has been set for a hearing. For further information see the above discussion related to Midwest ISO.

Contgyestioi C'harges on Oatter Systems: Effective May 1,2004, Commonwealth Edison transferred control of its transmission facilities to PJM, at which time PJM's LMP based congestion pricing system began to apply to transmission service on Commonwealth Edison's facilities. We were allocated FTRs for virtually all of our PJM transmission through May 31, 2005, and a new allocation will take place for the period June 1, 2005 through May 31, 2006. To date, we have experienced minimal net congestion costs associated with our FTRs in PJM.

Congestion costs are included under the definition of fuel for the Wisconsin Fuel Cost Adjustment Procedure.

Natural Gas Utility Industry Restructuring irt IWisconsin: 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. Ilowever, work on deregulation of the gas distribution industry by the PSCW is presently on hold.

Currently, we are unable to predict the impact of potential future deregulation on our results of operations or financial position.

ACCOUNTING DEVELOPMENTS Vew Pronounuceineits: In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 123 (revised 2004), Share-Based Payment (SFAS 123R), which amended SFAS 123, Accounting for Stock-Based Compensation. This statement requires that the compensation costs relating to such transactions be recognized in the consolidated income statement. We are currently evaluating the provisions of SFAS 123R and expect to adopt it on July 1,2005. We have not yet determined the method of transition. See "Note B -- Recent Accounting Pronouncements" 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 A-28

preparing the financial statements and related disclosures, even if the nature of the accounting policies applied have not changed.

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

Regulatory Accounting: Our electric, gas and steam operations operate under rates established by state and federal regulatory commissions, which are designed to recover the cost of service and provide a reasonable return to investors. Developing competitive pressures in the utility industry may result in future utility prices which are based upon factors other than the traditional original cost of investment. In this situation, continued deferral of certain regulatory asset and liability amounts on our books, as allowed under Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation, 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, 2004, we had $656.6 million in regulatory assets and $600.2 million in regulatory liabilities in comparison to $443.4 million of regulatory assets and $561.7 million of regulatory liabilities as of December 31, 2003. We continually review the applicability of SFAS 71 and have determined that it is currently appropriate to continue following SFAS 71. See "Note C -- Regulatory Assets and Liabilities" in the Notes to Consolidated Financial Statements for additional information.

Pension and Otlier Post-retirementBenefits: Our reported costs of providing non-contributory defined pension benefits (described in "Note L -- 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, 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.

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.

Pension Plans Impact on Actuarial Assumption (a) Annual Cost (Millions of Dollars) 0.5% decrease in discount rate $5.8 0.5% decrease in expected rate of return on plan assets $3.5 (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 L -- 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 A-29

well as changes in general interest rates may result in increased or decreased other post-retirement costs in future periods.

Similar to accounting for pension plans, the regulators of our utility operations have adopted SFAS 106 for rate making purposes.

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

Impact on Other Post-retirement Benefit Plans Reported Actuarial Assumption (a) Annual Cost (Millions of Dollars) 0.5% decrease in discount rate S2.2 0.5% decrease in health care cost trend rate ($1.4) 0.5% decrease in expected rate of return on plan assets $0.4 (a) The inverse of the change in the actuarial assumption may be expected to have an approximately similar impact in the opposite direction.

Unbilled Reveniues: We record utility operating revenues when energy is delivered to our customers. However, the detennination 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 2004 of $2.6 billion included accrued utility revenues of $164.5 million at December 31, 2004.

Asset Retiremrenit Obligations: We account for legal liabilities for asset retirements at fair value in the period in which they are incurred according to the provisions of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (SFAS 143). SFAS 143 applies primarily to decommissioning costs for Point Beach Nuclear Plant. Using a discounted future cash flow methodology, our estimated nuclear asset retirement obligation was approximately $745 million at December 31, 2004.

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 December 31, 2004 would have changed by the following amounts:

Change in Assumption Change in Liability (Millions of Dollars) 1% increase in inflation rate S250 1% decrease in inflation rate (S185) 0% probability of license extension $153 100% probability of license extension ($27)

We were unable to identify a viable market for or third party who would be willing to assume this liability.

Accordingly, we have used a market-risk premium of zero when measuring our nuclear asset retirement obligation.

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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 $7.5 million.

For additional information concerning SFAS 143 and our estimated nuclear asset retirement obligation, see "Note I -

- Asset Retirement Obligations" and "Note F -- Nuclear Operations" in the Notes to Consolidated Financial Statements, CAUTIONARY FACTORS This report and other documents or oral presentations contain or may contain forward-looking statements made by or on behalf of Wisconsin Electric. 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 forvard-looking statements. When used in written documents or oral presentations, the terms "anticipates," "believes," "estimates," "expects," "forecasts,"

"intends," "may," "objectives," "plans," "possible," "potential," "projects" and similar expressions are intended to identify forwvard-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 regulations of the United States Environmental Protection Agency as well as 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; the siting approval process for new generation and transmission facilities; recovery of costs associated with implementation of a bid-based energy market; or changes in the regulations from the Wisconsin Department of Natural Resources related to the siting approval process for new pipeline construction.

> 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 its approval of the merger of Wisconsin Energy Corporation and WICOR, Inc. in 2000.

> 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.

> Unanticipated operational and/or financial consequences related to implementation of the Midwest Independent Transmission System Operator, Inc's bid-based energy market scheduled to start up in 2005 and the associated outcome of our request of the Public Service Commission of Wisconsin to defer for potential future rate recovery the incremental costs or benefits resulting from this new energy market.

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

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> Factors which impede execution of Wisconsin Energy's Power the Future strategy announced in September 2000 and revised in February 2001, including receipt of necessary state and federal regulatory approvals, timely and successful resolution of legal challenges; local opposition to siting of new generating facilities; construction risks and obtaining the investment capital from outside sources necessary to implement the strategy.

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

> 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.

> 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.

> 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.

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

- 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.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK See "Factors Affecting Results, Liquidity and Capital Resources -- Market Risks and Other Significant Risks" in Management's Discussion and Analysis of Financial Condition and Results of Operations for information concerning potential market risks to which we are exposed.

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FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA WISCONSIN ELECTRIC POWER COMPANY CONSOLIDATED INCOME STATEMENTS Year Ended December 31 2004 2003 2002 (Millions of Dollars)

Total Operating Revenues $ 2,616.6 $ 2,521.9 $ 2,295.9 Operating Expenses Fuel and purchased power 585.4 562.4 493.9 Cost of gas sold 376.9 355.4 240.8 Other operation and maintenance 844.7 784.0 736.3 Depreciation, decommissioning and amortization 274.1 276.2 267.9 Property and revenue taxes 76.3 72.6 71.7 Total Operating Expenses 2,157.4 2,050.6 1,810.6 Operating Income 459.2 471.3 485.3 Other Income and Deductions, Net 33.5 31.5 24.3 Interest Expense 89.6 91.2 92.7 Income Before Income Taxes 403.1 411.6 416.9 Income Taxes 153.2 154.9 157.7 Net Income 249.9 256.7 259.2 Preferred Stock Dividend Requirement 1.2 1.2 1.2 Earnings Available for Common Stockholder $ 248.7 $ 255.5 $ 258.0 The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

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WISCONSIN ELECTRIC POWER COMIPANY CONSOLIDATED BALANCE SHEETS December 31 ASSETS 2004 2003 (Millions of Dollars)

Property, Plant and Equipment Electric $5,752.0 $5,726.6 Gas 687.5 671.0 Steam 76.3 69.7 Common 302.1 299.0 Other 55.1 52.8 6,873.0 6,819.1 Accumulated depreciation (2,637.9) (2,571.4) 4,235.1 4,247.7 Construction work in progress 153.6 68.3 Leased facilities, net 98.9 104.6 Nuclear fuel, net 85.0 78.4 Net Property, Plant and Equipment 4,572.6 4,499.0 Investments Nuclear decommissioning trust fund 737.8 674.4 Equity investment in transmission affiliate 165.3 136.2 Other 0.5 0.7 Total Investments 903.6 811.3 Current Assets Cash and cash equivalents 26.1 20.0 Accounts receivable, net of allowance for doubtful accounts of $20.2 and $26.6 253.3 239.3 Accrued revenues 164.5 149.8 Materials, supplies and inventories 273.8 276.2 Prepayments 86.9 95.6 Deferred income taxes - current 42.4 Other 1.4 3.6 Total Current Assets 806.0 826.9 Deferred Charges and Other Assets Regulatory assets 644.7 443.4 Other 123.4 64.0 Total Deferred Charges and Other Assets 768.1 507.4 Total Assets $7.050.3 S6.644.6 The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

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WISCONSIN ELECTRIC POWER COMIPANY CONSOLIDATED BALANCE SHEETS December 31 CAPITALIZATION AND LIABILITIES 2004 2003 (Millions of Dollars)

Capitalization Common equity $2,204.2 $2,131.9 Preferred stock 30.4 30.4 Long-term debt 1,683.1 1,435.3 Total Capitalization 3,917.7 3,597.6 Current Liabilities Long-term debt due currently 23.7 164.2 Short-term debt 189.5 315.9 Accounts payable 249.8 184.9 Payroll and vacation accrued 65.2 58.1 Taxes accrued - income and other 38.3 103.7 Interest accrued 8.7 12.2 Deferred income taxes - current 6.7 Other 86.3 91.1 Total Current Liabilities 668.2 930.1 Deferred Credits and Other Liabilities Asset retirement obligations 762.2 732.0 Regulatory liabilities 600.2 561.7 Deferred income taxes - long-term 548.5 456.4 Minimum pension liability 248.0 113.8 Accumulated deferred investment tax credits 56.9 61.4 Other long-term liabilities 248.6 191.6 Total Deferred Credits and Other Liabilities 2,464.4 2,116.9 Commitments and Contingencies (Note P)

Total Capitalization and Liabilities $7,050.3 $6,644.6 The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

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WISCONSIN ELECTRIC POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31 2004 2003 2002 (Millions of Dollars)

Operating Activities Net income $249.9 S256.7 S259.2 Reconciliation to cash Depreciation, decommissioning and amortization 294.9 301.9 282.3 Nuclear fuel expense amortization 24.0 25.3 27.3 Equity in earnings of unconsolidated affiliate (26.4) (22.8) (20.4)

Distribution from unconsolidated affiliate 20.4 17.6 18.1 Deferred income taxes and investment tax credits, net 136.8 (1.7) (31.9)

Accrued income taxes, net (64.4) (6.0) 37.2 Deferred transmission costs (36.3) (9.5) (40.2)

Deferred lease costs (28.2) (17.4)

Change in - Accounts receivable and accrued revenues (28.7) 5.3 (26.1)

Other accounts receivable 116.4 Inventories 2.4 (31.7) (17.4)

Other current assets (6.5) (5.9) 2.0 Accounts payable 57.1 (8.7) (20.0)

Other current liabilities 5.0 7.5 22.3 Other 30.8 3.6 47.5 Cash Provided by Operating Activities 630.8 514.2 656.3 Investing Activities Capital expenditures (358.9) (343.7) (365.7)

Investments (23.2)

Nuclear fuel (30.0) (38.3) (20.7)

Nuclear decommissioning funding (17.6) (17.6) (17.6)

Other 5.8 (3.2) (12.1)

Cash Used in Investing Activities (423.9) (402.8) (416.1)

Financing Activities Dividends paid on common stock (179.6) (179.6) (179.6)

Dividends paid on preferred stock (1.2) (1.2) (1.2)

Issuance of long-term debt 397.0 635.5 1.3 Retirement and redemption of long-term debt (290.1) (502.5) (251.1)

Change in short-term debt (126.4) (38.9) 182.4 Other (0.5) (18.0)

Cash Used in Financing Activities (200.8) (104.7) (248.2)

Change in Cash and Cash Equivalents 6.1 6.7 (8.0)

Cash and Cash Equivalents at Beginning of Year 20.0 13.3 21.3 Cash and Cash Equivalents at End of Year S26.1 $20.0 S13.3 Supplemental Information - Cash Paid For Interest (net of amount capitalized) $103.9 $112.1 SI 14.8 Income taxes (net of refunds) S53.6 $148.7 S124.1 The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

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WISCONSIN ELECTRIC POWER COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31 2004 2003 (Millions of Dollars)

Common Equity (See Consolidated Statements of Common Equity)

Common stock - $10 par value; authorized 65,000,000 shares; outstanding - 33,289,327 shares $332.9 $332.9 Other paid in capital 538.3 532.4 Retained earnings 1,339.9 1,270.8 Accumulated other comprehensive income (loss) (6.9) (4.2)

Total Common Equity 2,204.2 2,131.9 Preferred Stock Six Per Cent. Preferred Stock - $100 par value; authorized 45,000 shares; outstanding - 44,498 shares 4.4 4.4 Serial preferred stock -

$100 par value; authorized 2,286,500 shares; 3.60% Series redeemable at $101 per share; outstanding - 260,000 shares 26.0 26.0

$25 par value; authorized 5,000,000 shares; none outstanding Total Preferred Stock 30.4 30.4 Long-Term Debt First mortgage bonds 7-1/4% due 2004 140.0 Debentures (unsecured) 6-5/8% due 2006 200.0 200.0 9.47% due 2006 1.4 2.1 3.50% due 2007 250.0 4.50% due 2013 300.0 300.0 6-1/2% due 2028 150.0 150.0 5.625% due 2033 335.0 335.0 6-7/8% due 2095 100.0 100.0 Notes (secured, nonrecourse) 2% stated rate due 2011 1.3 1.3 4.81 % effective rate due 2030 2.0 2.0 Notes (unsecured) 6.36% effective rate due 2006 2.4 3.6 2.10% variable rate due 2006 (a) 1.0 1.0 2.10% variable rate due 2015 (a) 17.4 17.4 1.25% variable rate due 2016 (b) 67.0 1.65% variable rate due 2016 (a) 67.0 1.52% variable rate due 2030 (b) 80.0 1.70% variable rate due 2030 (a) 80.0 Obligations under capital leases 212.9 213.2 Unamortized discount (13.6) (13.1)

Long-term debt currently due (23.7) (164.2)

Total Long-Term Debt 1,683.1 1,435.3 Total Capitalization $3,917.7 $3,597.6 (a) Variable interest rate as of December 31, 2004.

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

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

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VISCONSIN ELECTRIC POWVER CONIPANY CONSOLIDATED STATEMENTS OF COMM1ON EQUITY Accumulated Other Common Other Paid Retained Comprehensive Stock In Capital Earnings Income (Loss) Total (Millions of Dollars)

Balance - December 31, 2001 5332.9 $530.7 SI,1 16.5 S- S1,980.1 Net income 259.2 259.2 Other comprehensive income (loss)

Minimum pension liability (8.1) (8.1)

Hedging, net (0.5) (0.5)

Comprehensive Income (loss) 259.2 (8.6) 250.6 Cash dividends Common stock (179.6) (179.6)

Preferred stock (1.2) (1.2)

Balance - December 31, 2002 $332.9 $530.7 $1,194.9 (S8.6) $2,049.9 Net income 256.7 256.7 Other comprehensive income Minimum pension liability 3.9 3.9 Iledging, net 0.5 0.5 Comprehensive Income -- 256.7 4.4 261.1 Cash dividends Common stock (179.6) (179.6)

Preferred stock (1.2) (1.2)

Tax benefit of exercised stock options allocated from Parent 1.7 1.7 Balance - December 31, 2003 $332.9 $532.4 S1,270.8 (S4.2) S2,131.9 Net income 249.9 249.9 Other comprehensive income Minimum pension liability (2.9) (2.9)

Iledging, net 0.2 0.2 Comprehensive Income - 249.9 (2.7) 247.2 Cash dividends Common stock (179.6) (179.6)

Preferred stock (1.2) (1.2)

Tax benefit of exercised stock options allocated from Parent 5.9 5.9 Balance - December 31, 2004 $332.9 $538.3 S1,339.9 (S6.9) S2,204.2 The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

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NAISCONSIN ELECTRIC POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS A -

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES General: Wisconsin Electric Power Company (Wisconsin Electric, the Company, our, us or we), a wholly-owned subsidiary of Wisconsin Energy Corporation (Wisconsin Energy), is an electric, gas and steam utility which services electric customers in Wisconsin and the Upper Peninsula of Michigan, gas customers in Wisconsin and steam customers in metro Milwaukee, Wisconsin. We consolidate our wholly owned subsidiary Bostco LLC (Bostco).

Bostco owns real estate properties, with total assets of $41.8 million as of December 31, 2004 that are eligible for historical rehabilitation tax credits.

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

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

Reclassifications: We have reclassified certain prior year financial statement amounts to conform to their current year presentation. These reclassifications had no effect on net income, total assets or cash flow from operations.

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

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

Our retail gas rates include monthly adjustments which permit the recovery or refund of actual purchased gas costs.

We defer any difference between actual gas costs incurred (adjusted for a sharing mechanism) and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year and any residual balance at the annual October 31 reconciliation date is subsequently refunded to or recovered from customers.

Other Income and Deductions, Net: We had the following other income and deductions for the years ended December 31:

Other Income and Deductions, Net 2004 2003 2002 (Millions of Dollars)

Equity in Earnings of Unconsolidated Affiliate $26.4 $22.8 $20.4 Carrying Costs on Deferred Assets 12.4 9.3 6.1 AFUDC-Equity 1.7 2.4 3.5 Interest Income 0.3 0.6 2.1 Donations and Contributions (5.6) (3.1) (2.8)

EPA Consent Decree Civil Penalty - (3.2)

Debt Redemption Costs - - (5.3)

Other, net (1.7) 2.7 0.3 Total Other Income and Deductions $33.5 $31.5 S24.3 A-39

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

We collect future removal costs in our rates 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 regulatory liability was $419.1 million as of December 31, 2004 and $400.6 million as of December 31, 2003.

We include capitalized software costs associated with our regulated operations under the caption "Property, Plant and Equipment" on the Consolidated Balance Sheets. As of December 31, 2004 and 2003, the net book value of our capitalized software totaled $27.7 million and $34.1 million, respectively. The estimated useful life of our capitalized software is five years.

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 4.3% in 2004, 4.2% in 2003 and 4.5% in 2002. 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, overheads 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, Net in the Consolidated Income Statements.

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

,Allowtantce 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 (AFUDC-debt) used during plant construction and a return on stockholders' capital (AFUDC-equity) used for construction purposes. AFUDC-debt is recorded as a reduction in interest expense and AFUDC-equity is recorded in Other Income and Deductions, Net.

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

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

In addition, the August 2000 PSCW order provided a current return on half of other utility construction work in progress and authorized AFUDC accruals on the remaining 50% of these projects.

We recorded the following AFUDC for the years ended December 31:

2004 2003 2002 (Millions of Dollars)

AFUDC-Debt S0.9 S1.2 S.7 AFUDC-Equity SI.7 S2.4 S3.5 A-40

AMaterials, Supplies andInventories: Our inventory at December 31 consisted of:

Materials, Supplies and Inventories 2004 2003 (Millions of Dollars)

Natural Gas in Storage $102.9 $83.8 Fossil Fuel 86.3 107.0 Materials and Supplies 84.6 85.4 Total $273.8 $276.2 We price substantially all fossil fuel, materials and supplies and natural gas in storage inventories using the weighted-average method of accounting.

Regulatory Accounting: We account for our regulated operations in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. 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, 2004, we had approximately $43.3 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). For further information, see Note C.

Derivative Financial Instruments: We have derivative physical and financial instruments as defined by SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. However, our use of financial instruments is limited. For further information, see Note J.

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

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

Asset Retirement Obligations: We adopted SFAS No. 143, Accounting for Asset Retirement Obligations, 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. For further information see Note I.

Investments: We consolidate investments in affiliated companies in which we have a controlling financial interest.

We account for investments in other affiliated companies in which we do not maintain control using the equity method. As of December 31, 2004 and 2003, wve had a total ownership interest of approximately 33.2% and 34.6%,

respectively, in American Transmission Company LLC (ATC). We are represented by one out of ten ATC board members, each of whom has one vote. Due to the voting requirements, no individual member has more than 10% of the voting control. We account for our investment in ATC under the equity method. For more information on ATC, see Note 0.

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Vrtclear Frtel/Aortiatioit: 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.

Income Tares: We follow the liability method in accounting for income taxes as prescribed by SFAS No. 109, Accounting for Income Taxes. 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. For further informiation, see Note E.

We are included in Wisconsin Energy's consolidated Federal income tax return. Wisconsin Energy allocates Federal tax expense or credits to us based on our separate tax computation.

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

Historical rehabilitation credits are reported in income in the year claimed.

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

B - RECENT ACCOUNTING PRONOUNCEMENTS Share Based Compenzsation: In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123 (revised 2004), Share-Based Payment (SFAS 123R), which amended SFAS 123, Accounting for Stock-Based Compensation. This statement supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees.

SFAS I 23R addresses the accounting for share-based payment transactions with employees and other third parties, eliminates the ability to account for share-based compensation transactions using APB 25 and requires that the compensation costs relating to such transactions be recognized in the consolidated income statement. WVe are currently evaluating the provisions of SFAS 123R and expect to adopt it on July 1, 2005.

C -- REGULATORY ASSETS AND LIABILITIES Our regulatory assets and liabilities at December 31 consist of:

Regulatory Assets 2004 2003 (Millions of Dollars)

Unrecognized pension costs (See Note L) S202.5 $70.4 Deferred electric transmission costs 109.6 73.3 Deferred income tax related 96.4 132.3 Plant related -- capital lease (See Note G) 61.1 54.5 Unrecovered plant costs 45.9 9.0 Environmental costs 45.5 48.7 Bad debt costs 22.7 10.9 Other, net 61.0 44.3 Total Regulatory Assets $644.7 S443.4 Regulatory Liabilities 2004 2003

(,NIillions of Dollars)

Cost of removal obligations (See Notes F and 1) $419.1 S400.6 Income tax related 96.8 112.2 Other, net 84.3 48.9 Total Deferred Regulatory Liabilities $600.2 S561.7 A-42

We record a minimum pension liability to reflect the funded status of our pension plans (see Note L). We have concluded that substantially all of the unrecognized pension costs resulting from the recognition of our minimum pension liability that relate to our utility operations qualify as a regulatory asset.

In October 2002, the PSCW issued an order authorizing us to implement a surcharge for recovery of annual electric transmission costs projected through 2005. In addition, the PSCW order authorized escrow accounting treatment for transmission costs. The difference between actual incremental transmission costs incurred and the amount being recovered is charged to the escrow account. We have deferred a total of$ 109.6 million of electric transmission costs as a regulatory asset through December 31, 2004.

We record deferred regulatory assets and liabilities representing the future expected impact of deferred taxes on utility revenues (see Note A).

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, 2004, we have recorded $45.5 million of environmental costs associated with manufactured gas plant sites as a regulatory asset, including $29.3 million of deferrals for actual remediation expenditures and a $16.2 million accrual for estimated future site remediation (See Note P). In addition, we have deferred $10.6 million of insurance recoveries associated with the environmental costs as regulatory liabilities. We expect to include total actual remediation costs incurred net of the related insurance recoveries in our next rate case at which time we would begin amortizing these costs over the following five years.

As part of Wisconsin Energy's Power the Future initiative, the PSCW approved the retirement and removal of the Port Washington Power Plant coal units to make way for construction of gas fired facilities. In a September 27, 2003 order, the Commission authorized transferring the undepreciated costs and related removal amounts to a regulatory asset account. These deferred unrecovered plant costs totaled S45.9 million at December 31, 2004.

In 2003 and 2004, the PSCW approved our request to defer bad debt write-offs to the extent that the write-offs exceeded amounts allowed in rates. As of December 31, 2004, we have deferred a regulatory asset of $22.7 million for bad debt costs. In February 2005, the PSCW approved our request for escrow accounting for residential bad debts in 2005. We will request approval to recover all deferred residential bad debt costs in our next Wisconsin rate case.

D -- VARIABLE INTEREST ENTITIES In January 2003, the Financial Accounting Standards Board 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 issued FIN 46R, which revised FIN 46 and deferred the effective date for interests held in variable interest entities other than special purpose entities to financial statements for periods ending after March 15, 2004. We adopted FIN 46R in the first quarter of 2004.

We continue to evaluate our tolling and purchased power agreements with third parties on a quarterly basis. After making an exhaustive effort, we concluded that for three of these agreements, we are unable to obtain the information necessary to determine whether we are the primary beneficiary of these variable interest entities.

Pursuant to the terms of two of the three agreements, we deliver fuel to the entity's facilities and receive electric power. We pay the entity a "toll" to convert our fuel into the electric energy. The output of the facility is available for us to dispatch during the term of the respective agreement. In the other agreement, we have rights to the firm capacity of the entity's facility. We have approximately $736.3 million of required payments over the remaining term of these three agreements, which expire over the next 18 years. We believe the required payments will continue to be recoverable in rates. We account for one of these agreements as a capital lease.

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

Income Tax Expense 2004 2003 2002 (Millions of Dollars' Current tax expense $16.4 $156.6 S1 89.7 Deferred income taxes, net 141.2 2.8 (27.5)

Investment tax credit, net (4.4) (4.5) (4.5)

Total Income Tax Expense $153.2 $154.9 $157.7 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:

2004 2003 2002 Effective Effective Effective Income Tax Expense Amount Tax Rate Amount Tax Rate Amount Tax Rate (Millions of Dollars)

Expected tax at statutory federal tax rates S141.1 35.0% S144.1 35.0% S145.9 35.0%

State income taxes net of federal tax benefit 19.0 4.7% 19.3 4.7% 20.2 4.8%

Investment tax credit restored (4.4) (1.1%) (4.5) (.1I%) (4.5) (1.0%)

Historical rehabilitation credits (1.0) (0.2%) (3.3) (1.0%) (2.5) (0.6%)

Other, net (1.5) (0.4%) (0.7) (1.4) (0.4%)

Total Income Tax Expense $153.2 38.0% $154.9 37.6% $157.7 37.8%

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

Current Assets (Liabilities) Long-Term Liabilities (Assets)

Deferred Income Taxes 2004 2003 2004 2003 (Millions of Dollars)

Property-related S721.9 $632.5 Construction advances (80.1) (82.9)

Decommissioning trust (74.5) (65.5)

Prepaid taxes and insurance (29.5)

Uncollectible account expense (3.9) 9.8 Employee benefits and compensation 10.5 10.6 (62.4) (44.3)

Deferred transmission costs 40.5 21.8 Other 16.2 22.0 3.1 (5.2)

Total Deferred Income Taxes (S6.7) $42.4 $548.5 S456.4 We have also recorded deferred regulatory assets and liabilities representing the future expected impact of deferred taxes on utility revenues (See Note C).

F - NUCLEAR OPERATIONS Point Beach NVclear Plant: We own two 518-megawatt electric generating units at Point Beach Nuclear Plant (Point Beach) in Two Rivers, Wisconsin. We currently expect the two units at Point Beach to operate to the end of A-44

their operating licenses, which expire in October 2010 for Unit I and in March 2013 for Unit 2. In February 2004, we and Nuclear Management Company (NMC) filed an application with the United States Nuclear Regulatory Commission (NRC) to renew the operating licenses for both of our nuclear reactors for an additional 20 years. We expect the NRC to make a decision on the license extension application by January 2006, based upon the NRC's published schedule.

Nuclear Insurance: The Price-Anderson Act currently limits the total public liability for damages arising from a nuclear incident at a nuclear power plant to approximately $ 10.6 billion, of which $300 million is covered by liability insurance purchased from private sources. The remaining $10.3 billion is covered by an industry retrospective loss sharing plan whereby in the event of a nuclear incident resulting in damages exceeding the private insurance coverage, each owner of a nuclear plant would be assessed a deferred premium of up to $99.2 million per reactor (we own two) with a limit of$ 10.0 million per reactor within one calendar year. As the owner of Point Beach, we would be obligated to pay our proportionate share of any such assessment.

Through our membership in Nuclear Electric Insurance Limited (NEIL), we carry decontamination, property damage and decommissioning shortfall insurance covering losses of up to $2.1 billion at Point Beach. Under policies issued by NEIL, the insured member may be liable for a retrospective premium in the event of catastrophic losses exceeding the full financial resources of NEIL. Our maximum retrospective liability under the above policies is $16.5 million.

We also maintain insurance with NEIL through which we can recover up to $3.5 million per week, subject to a total limit of $490 million, during any prolonged outage at Point Beach caused by accidental property damage. Our maximum retrospective liability under this policy is $9.6 million.

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

Nuclear Decommissioning: We record decommissioning expense in amounts equal to the amounts collected in rates and funded to the external trusts. Nuclear decommissioning costs are accrued over the expected service lives of the nuclear generating units and are included in electric rates. Decommissioning funding was $17.6 million for each of the years ended 2004, 2003 and 2002. As of December 31, 2004 and 2003, we had the following investments in Nuclear Decommissioning Trusts, stated at fair value.

2004 2003 (Millions of Dollars)

Funding and Realized Earnings $529.1 $485.2 Unrealized Gains 208.7 189.2 Total Investments $737.8 $674.4 As of December 31, 2004, approximately 66.7% of the trusts' assets were invested in equity securities and 33.3%

were invested in debt securities. In accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities, our debt and equity security investments in the Nuclear Decommissioning Trust Fund are classified as available for sale. Gains and losses on the fund are determined on the basis of specific identification; net unrealized gains on the fund are recorded as part of the fund.

We record an Asset Retirement Obligation (ARO) under SFAS 143 for future decommissioning costs based upon the net present value of the expected cash flows associated with our legal obligation to decommission our nuclear plants. As of December 31, 2004 and 2003, our ARO associated with nuclear decommissioning totaled

$745.3 million and $708.5 million, respectively. We recover decommissioning costs in our regulated rates. We record a regulatory asset to the extent that our decommissioning ARO exceeds amounts collected in rates and cumulative investment gains (our nuclear trust investments). In the future, to the extent that our nuclear trust investments exceed the decommissioning ARO, we would expect to record a regulatory liability. For further information on ARO's see Note I.

The decommissioning ARO is calculated using several significant assumptions including the timing of future cash flows, future inflation rates, the extent of work that is expected to be 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.

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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 decommissioning ARO. The 2002 site specific study estimated that the cost to decommission the plant in 2003 year dollars was approximately $1.1 billion. At least every four years these studies are reviewed which could result in future changes to the decommissioning ARO. The differences between the regulatory funding liability and the decommissioning ARO 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 significant nuclear decommissioning expenditures before the year 2011.

Decontaminationand Decommznissioninig 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, 2004, we had recorded our remaining estimated liability equal to projected special assessments of S7.2 million. The deferred regulatory asset will be amortized to nuclear fuel expense and included in utility rates over the next three years ending in 2007.

G - LONG-TERMI DEBT FirstMlfortgage Bonds, Debentuiresand Notes: At December 31, 2004, the maturities and sinking fund requirements through 2009 and thereafter for the aggregate amount of our long-term debt outstanding (excluding obligations under capital leases) were:

(Millions of Dollars) 2005 S 1.9 2006 203.0 2007 250.2 2008 0.2 2009 0.2 Thereafter 1,052.0 Total $1,507.5 Long-term debt premium or discount and expense of issuance arc amortized over the lives of the debt issues and included as interest expense.

In August 2004, we retired S140 million of 7-1/4% First Mortgage Bonds at their scheduled maturity. We financed this retirement through the issuance of short-term commercial paper.

In November 2004, we sold $250 million of unsecured 3.50% debentures due December 1, 2007. The securities were issued under an existing S665 million shelf registration statement filed with the Securities and Exchange Commission (SEC). The proceeds from the sale were used to repay our outstanding commercial paper.

In December 2004, we refinanced S147 million of the $165 million aggregate principal amount of unsecured variable rate putable weekly reset tax-exempt debt with new "auction" non-putable unsecured variable rate weekly reset tax-exempt debt.

In May 2003, we sold S635 million of unsecured Debentures (S300 million of ten-year 4.50% Debentures due 2013 and $335 million of thirty-year 5.625% Debentures due 2033) under an $800 million shelf registration statement filed with the SEC. We used a portion of the proceeds from the Debentures to repay short-term debt, which was originally incurred to retire debt that matured in December 2002. The balance of the proceeds were used to redeem

$425 million of our debt securities in June 2003 and to fund the early redemption in August 2003 of another

$60 million debt issue.

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

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

We treat the long-term power purchase contract as an operating lease for rate-making purposes and we record our minimum lease payments as purchased power expense on the Consolidated Income Statements. We paid a total of S24.3 million, $23.4 million and $22.3 million in minimum lease payments during 2004, 2003, and 2002, 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 regulatory assets - plant related - capital lease in Note C). Due to the timing of the minimum lease payments, we expect the regulatory asset to increase to approximately $78.5 million by the year 2009 and the total obligation under the capital lease to increase to $160.2 million by the end of 2005 before each is reduced to zero over the remaining life of the contract.

We also have a nuclear fuel leasing arrangement with Wisconsin Electric Fuel Trust (Trust) which is treated as a capital lease. We lease and amortize the nuclear fuel to fuel expense as power is generated, generally over a period of 60 months. Lease payments include charges for the cost of fuel burned, financing costs and management fees. In the event that we or the Trust terminates the lease, the Trust would recover its unamortized cost of nuclear fuel from us. Under the lease terms, we are in effect the ultimate guarantor of the Trust's commercial paper and line of credit borrowings that finance the investment in nuclear fuel. We recorded $1.4 million of interest expense on the nuclear fuel lease in fuel expense during 2004 and 2003 and $1.9 million during 2002.

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

Capital Lease Assets 2004 2003 (Millions of Dollars)

Leased Facilities Long-term purchase power commitment $140.3 $140.3 Accumulated amortization (41.4) (35.7)

Total Leased Facilities $98.9 $104.6 Nuclear Fuel Under capital lease $120.2 $115.9 Accumulated amortization (74.0) (67.0)

In process/stock 38.8 29.5 Total Nuclear Fuel $85.0 $ 78.4 Future minimum lease payments under our capital leases and the present value of our net minimum lease payments as of December 31, 2004 are as follows:

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Purchase Power Nuclear Capital Lease Obligations Commitment Fuel Lease Total (Millions of Dollars) 2005 $30.1 $24.0 S54.1 2006 31.2 16.5 47.7 2007 32.4 8.6 41.0 2008 33.6 5.4 39.0 2009 34.9 1.1 36.0 Thereafter 369.0 369.0 Total Minimum Lease Payments 531.2 55.6 586.8 Less: Estimated Executory Costs (113.8) (113.8)

Net Minimum Lease Payments 417.4 55.6 473.0 Less: Interest (257.4) (2.7) (260.1)

Present Value of Net Minimum Lease Payments 160.0 52.9 212.9 Less: Due Currently (21.8) (21.8)

S 160.0 $31.1 $191.1 11-- SHORT-TERINM DEBT Short-term notes payable balances and their corresponding weighted-average interest rates as of December 31 consist of:

2004 2003 Interest Interest Short-Term Debt Balance Rate Balance Rate (Millions of Dollars)

Commercial paper $156.7 2.35% $280.7 1.15%

Other 32.8 6.52% 35.2 6.13%

Total Short-Term Debt $189.5 3.07% $315.9 1.70%

On December 31, 2004, we had $372.0 million of available unused lines of bank back-up credit facilities on a consolidated basis. We had S189.5 million of total consolidated short-term debt outstanding on such date. Our bank back-up credit facilities mature beginning June 2007 through November 2007.

The following information relates to Short-Term Debt for the years ended December 31, 2004 and 2003:

2004 2003 (Millions of Dollars, except for percentages)

Maximum Short-Term Debt Outstanding S280.9 $332.0 Average Short-Temi Debt Outstanding 155.5 180.2 Weighted Average Interest Rate 1.43% 1.24%

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

1- 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-termn liability for accrued nuclear decommissioning costs. See Note F for further information about the nuclear decommissioning of Point A-48

Beach including our investments in Nuclear Decommissioning Trusts that are restricted to nuclear decommissioning.

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.

The following table presents the change in our asset retirement obligations during 2004.

Balance at Liabilities Liabilities Cash Flow Balance at 12/31/03 Incurred Settled Accretion Revisions 12/31/04 (Millions of Dollars)

Asset Retirement Obligations $732.0 $ - $7.1 $37.3 $- $762.2 J -- DERIVATIVE INSTRUMENTS We follow SFAS 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, effective July 1, 2003, which requires that every derivative instrument 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. For most of our energy-related physical and financial contracts that qualify as derivatives under SFAS 133, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities.

We have a limited number of financial contracts that are defined as derivatives under SFAS 133 and qualify for cash flow hedge accounting. These contracts are utilized to manage the cost of gas. Changes in the fair market values of these instruments 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.

For the years ended December 31, 2004 and 2003, the amount of hedge ineffectiveness was immaterial. We did not exclude any components of derivative gains or losses from the assessment of hedge effectiveness. We estimate that

$0.2 million will be reclassified from Accumulated Other Comprehensive Income to earnings during the first month of 2005.

K - 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:

2004 2003

- Carrying Fair Carrying Fair Financial Instruments Amount Value Amount Value (Millions of Dollars)

Nuclear decommissioning trust fund $737.8 $737.8 $674.4 $674.4 Preferred stock, no redemption required $30.4 $22.7 $30.4 $20.9 Long-term debt including current portion $1,507.5 - $1,546.4 $1,399.4 $1,417.9 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. 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 A-49

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 arc equal to their carrying values as of December 31, 2004.

L-- BENEFITS Pentsions and Othler Post-retirementl Bentefits: Funded and unfunded noncontributory defined benefit pension plans together cover substantially all of our employees. The plans provide defined benefits based upon years of service and final average salary.

Other post-retirement benefit plans also cover 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.

Wisconsin Energy allocates the service cost component of pension costs to participating companies based on labor dollars. The assets, obligations and the components of SFAS 87 pension costs other than service cost (including the minimum pension liability) arc allocated by Wisconsin Energy's actuary to each of the participating companies as if each participating company had its own plan. The disclosures below are based on an allocation to us of the amounts for the Wisconsin Energy Plan.

Other Post-retirement Pension Benefits Benefits Status of Benefit Plans 2004 2003 2002 2004 2003 2002 (Millions of Dollars)

Change in Benefit Obligation Benefit Obligation at January I $932.5 S851.2 S806.2 $289.3 S257.6 S205.3 Service cost 26.9 27.2 18.3 11.4 10.3 7.5 Interest cost 58.4 56.9 56.7 17.1 17.6 15.3 Plan participants' contributions 0.7 6.9 Plan amendments 2.0 18.5 0.1 Actuarial loss 90.4 32.5 28.6 5.6 14.0 39.8 Benefits paid (90.7) . _

(53.8) . _

(58.7) (10.3) (10.9) (17.2)

Benefit Obligation at December 31 $1.019.5 S932.5 $851.2 S313.1 S289.3 S257.6 Change in Plan Assets Fair Value at January I S695.2 $609.6 S756.4 $95.7 $78.6 $81.0 Actual earnings (loss) on plan assets 71.1 138.2 (91.2) 6.3 11.9 (5.1)

Employer contributions 72.4 1.2 3.1 15.7 15.4 13.0 Plan participants' contributions 0.7 6.9 Benefits paid (90.7) (53.8) (58.7) (10.3) (10.9) (17.2)

Fair Value at December 31 S748.0 $695.2 S609.6 S107.4 S95.7 S78.6 Funded Status of Plans Funded status at December 31 (S271.5) ($237.3) ($241.6) (S205.7) (S 193.6) ($179.0)

Unrecognized Net actuarial loss 222.3 153.6 203.2 96.3 94.1 92.1 Prior service cost 33.8 36.6 22.9 0.2 0.2 0.2 Net transition (asset) obligation (0.1) (2.3) (4.5) 12.2 13.8 15.4 Net Asset (Accrued Benefit Cost) (S15.5) ($49.4) (S20.0) (S97.0) (S85.5) ($71.3)

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Other Post-retirement Pension Benefits Benefits Status of Benefit Plans 2004 - 2003 2002 2004 2003 2002 (Millions of Dollars)

Amounts recognized in the Balance Sheet consist of:

Regulatory assets (See Note C) $202.5 $70.4 Other deferred charges 33.6 '36.5 0.1 0.1 Minimum pension liability (248.0) (113.8)

Other long-term liabilities '(15.5) (49.4) (97.1) (85.6)

Other comprehensive income 11.9 6.9 Net amount recognized at end of year ($15.5) ($49.4) ($97.0) ($85.5)

The accumulated benefit obligation for all of our defined benefit plans was $1,010.3 million and $858.5 million at December 31, 2004 and 2003, respectively. -

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

2004 2003 (Millions of Dollars)

Projected benefit obligation $1,003.6 $913.1 Accumulated benefit obligation $995.9 $839.9 Fair value of plan assets $748.0 $695.2 The components of net periodic pension and other post-retirement benefit costs are:

Other Post-retirement Pension Benefits Benefits Benefit Plan Cost Components 2004

• 2003 2002 .20104 2003 2002 (Millions of Dolla rs)

Net Periodic Benefit Cost Service cost $26.9 $27.2 $18.3 $111.4 $10.3' $7.5 Interest cost 58.4  : 56.9 56.7 - I.7.1 17.6 15.3 Expected return on plan assets (62.6) (64.0) (68.2) '7.9) (6.5) (6.8)

Amortization of:

Transition (asset) obligation (2.2) (2.2) (2.2) 1.5 1.5 1.5 Prior service cost 4.8 4.8 3.4 Actuarial loss 13.2 3.0 3.1 5.1 6.6 3.7 Net Periodic Benefit Cost $38.5 $25.7 $11.1 27.2 $29.5 $21.2 Weighted-Average assumptions used to Determine benefit obligations at Dec 31 Discount rate 5.75% 6.25% 6.75% 5.75% 6.25% 6.75%

Rate of compensation increase 4.5 to 4.5 to 4.5 to -4.5 to 4.5 to 4.5 to 5.0 5.0 5.0 5.0 5.0 5.0 Weighted-Average assumptions used to Determine net cost for year ended Dec 31 Discount rate 6.25% 6.75% 7.25% 6.25% 6.75% 7.25%

Expected return on plan assets 9.0 9.0 9.0 9.0 9.0 9.0 Rate of compensation increase 4.5 to 4.5 to 4.5 to 4.5 to 4.5 to 4.5 to 5.0 5.0 5.0 5.0 5.0

• 5.0 Assumed health care cost trend rates at Dec 31 Health care cost trend rate assumed for Next year 10 10 10 Rate that the cost trend rate gradually Declines to 5 5 5 Year that the rate reaches the rate it is Assumed to remain at 2010 2009 2008 A-51

The expected long-term rate of return on plan assets was 9% in 2004 and 2003. This return expectation on plan assets was determined by reviewing actual pension historical returns as well as calculating expected total trust returns using the weighted average of long-term market returns for each of the asset categories utilized in the pension fund.

Other Post-retiremnent Beenefits 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.

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 S26.6 (S23.9)

Total of service and interest cost components $3.3 ($2.9)

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act) was signed into law. The Act introduced a prescription drug benefit program under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans. In the second quarter of 2004, the FASB issued Staff Position (FSP)

SFAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.

In accordance with FSP 106-2, we chose to recognize the effects of the Act retroactively effective January 1, 2004 with the impacts calculated actuarially. The Act resulted in a $20.6 million reduction in our benefit obligation and reduced our 2004 SFAS 106 expense by $4.2 million. Assumptions used to develop this reduction include those used in the determination of the annual SFAS 106 expense and also include expectations of how the federal program will ultimately operate. In January 2005, the Centers for Medicare & Medicaid Services released final regulations to implement the new prescription drug benefit under Part D of Medicare. It was determined that the employer sponsored plans meet these regulations and that the previously determined actuarial measurements are still accurate.

PlaniAssets: 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, 2004 and 2003, and our target allocation for 2005, by asset category, are as follows:

Target Percentage of Pension Plans Allocation Assets at December 31 Asset Category 2005 2004 2003 Equity Securities 72% 73% 76%

Debt Securities 28% 27% 24%

Total 100% 100% 100%

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

The target asset allocation was established by a Chairman-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.

Our other post-retirement benefit plans asset allocation at December 31, 2004 and 2003, and our target allocation for 2005, by asset category, are as follows:

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Target Percentage of Other Benefit Allocation Plans Assets at December 31 Asset Category 2005 2004 2003 Equity Securities 34% 32% 35%

Debt Securities 65% 68% 64%

Other 1% 1%

Total 100% 100% 100%

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

The target asset allocation was established by a Chairman-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.

Caslflonws:

Other Post-Pension retirement Employer Contributions Benefits Benefits (Millions of Dollars) 2003 $1.2 $15.4 2004 $72.4 $15.7 2005 (Expected) $4.5 $16.8 Of $4.5 million expected to be contributed to fund pension benefits in 2005, none will be for our qualified plans since there is no minimum required by law. We contributed $51.7 million to our qualified pension plans during 2004. There was no contribution made during 2003 to the qualified pension plans.

The entire contribution to the other post-retirement benefit plans during 2004 was discretionary as the plans are not subject to any minimum regulatory funding requirements.

The following table identifies our expected benefit payments over the next 10 years:

Gross Other Expected Post Medicare

• Employment Part D Year Pension Benefits Subsidy (Millions of Dollars ;)

2005 $71.7 $14.1 2006 $74.8 $15.4 ($0.9) 2007 $81.7 $16.6 ($1.0) 2008 $80.5 -$18.0 ($1.1) 2009 $86.9 $19.6 ($1.2) 2010-2014 $456.4 $119.8 ($7.0)

Savings Plans: We sponsor savings plans which allow employees to contribute a portion of their pre-tax and or after-tax income in accordance with plan-specified guidelines. Under these plans, we expensed matching contributions of $9.1 million, $8.8 million and $8.3 million during 2004, 2003 and 2002, respectively.

Severance Plans: For the year ended December 31, 2004 we incurred $22.3 million ($13.4 million after-tax) of severance costs. The majority of the severance costs related to an enhanced severance package offered to selected management who voluntarily resigned in the fourth quarter of 2004. The program was enacted to help reduce the upward pressure on operating expenses.

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Approximately 150 employees received severance benefits during 2004. As of December 31, 2004 we have accrued

$6.6 million of severance benefits which are expected to be paid during 2005.

l- GUARANTEES We enter into various guarantees to provide financial and performance assurance to third parties. As of December 31, 2004, we had the following guarantees:

Maximum Potential Liability Future Outstanding Recorded at Payments Dec 31, 2004 Dec 31, 2004 (Millions of Dollars)

Guarantees 5231.0 $0.1 We guarantee the potential retrospective premiums that could be assessed under our nuclear insurance program (See Note F).

Postemployient benefits: Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $12.0 million as of December 31, 2004.

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

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

Summarized financial information concerning our reportable operating segments for each of the years ended December 31, 2004, 2003 and 2002, is shown in the following table.

Reportable Operating Segments Year Ended Electric Gas Steam Other (a) Total (Millions of Dollars)

December 31. 2004 Operating Revenues (b) $2,070.8 $523.8 $22.0 $ - S2,616.6 Depreciation, Decommissioning and Amortization $234.9 S36.1 $3.1 $274.1 Operating Income (Loss) (c) S427.2 533.1 (51.1) S459.2 Equity in Earnings of Unconsolidated Affiliate $26.4 5 - S - $ - $26.4 Capital Expenditures $313.7 $33.2 $6.7 $5.3 $358.9 Total Assets (d) S6,153.0 $667.1 $54.0 $176.2 $7,050.3 A-54

Reportable Operating Segments Year Ended Electric Gas Steam Other (a) Total (Millions of Dollars)

December 31. 2003 Operating Revenues (b) $1,986.4 $513.0 $22.5 $ - S2,521.9 Depreciation, Decommissioning and Amortization $234.1 $38.9 $3.2 S276.2 Operating Income (c) $422.3 $49.0 $ - $471.3 Equity in Earnings of Unconsolidated Affiliate $22.8 - $ - S22.8 Capital Expenditures $271.6 $56.8 S2.6 S12.7 $343.7 Total Assets (d) $5,784.9 $628.7 S54.5 S176.5 $6,644.6 December 31, 2002 Operating Revenues (b) $1,884.6 S389.8 $21.5 S - $2,295.9 Depreciation, Decommissioning and Amortization $230.0 $34.6 $3.3 $ - $267.9 Operating Income (Loss) (c) $453.3 $33.5 ($1.5) $ - $485.3 Equity in Earnings of Unconsolidated Affiliate $20.4 5- - $ - $20.4 Capital Expenditures $312.3 $34.7 $1.6 $17.1 $365.7 Total Assets (d) $5,513.3 $566.2 $55.3 $150.3 $6,285.1 (a) Other includes primarily non-utility property and investments, materials and supplies, deferred charges and other corporate items.

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

(c) We evaluate operating income to manage our utility business. Equity in Earnings of Unconsolidated Affiliate, Interest Expense and Income Tax Expense are not included in segment operating income.

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

o- RELATED PARTIES We provide to and receive from certain of our Wisconsin Energy affiliates managerial, financial, accounting, legal, data processing and other services in accordance with service agreements approved by the PSCW. In addition, we are make lease payments to We Power associated with generating facilities being constructed under Wisconsin Energy's Power the Future strategy, and we sell electric energy to an affiliated utility, Edison Sault Electric Company (Edison Sault). We also receive and/or provide certain services to other associated companies in which we have an equity investment. We provided and received services from the following associated companies during 2004, 2003 and 2002:

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Company 2004 2003 2002 (Millions of Dollars)

Wisconsin Energy Affiliate We Power

- Lease payments ($59.5) ($23.5) $-

- Services provided $6.8 $7.7 $6.9 Wisconsin Gas - Net services provided S50.4 S42.4 $40.0 Edison Sault - Electric energy sold S16.4 S16.0 S13.8 Wisconsin Energy - Net services received ($2.9) ($3.0) ($1.7)

Equity Investee American Transmission Company

-Transmission services ($105.8) ($94.4) (S85.1)

- Services provided $20.7 $30.9 S51.5 Nuclear Mianagement Company (S58.1) ($57.1) ($53.6)

Guardian Pipeline (S11.4) ($3.2) $-

P - COMMITMENTS AND CONTINGENCIES CapitalExYpenditures: We have made certain commitments in connection with 2005 capital expenditures.

OperatingLeases: 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) 2005 $50.4 2006 50.0 2007 49.3 2008 33.8 2009 20.8 Thereafter 66.1

$270.4 EnvirontitentalMatters: We periodically review our exposure for environmental remediation costs as evidence becomes available indicating that our liability has changed. We believe that future costs in excess of the amounts accrued and/or disclosed on all presently known and quantifiable environmental contingencies will not be material to our financial position or results of operations.

We have a 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 as well as coal ash disposal/landfill sites used by us, as discussed below. We are working with the Wisconsin Department of Natural Resources in our investigation and remediation planning. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

Mfanufactured Gas Plant Sites: We have identified sites at which we or a predecessor company historically owned or operated a manufactured gas plant. We have completed planned remediation activities at four of those sites.

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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 $15-$30 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, 2004, we have established reserves of $16.2 million related to future remediation costs.

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

Ash LandjilI Sites: We aggressively seek environmentally acceptable, beneficial uses for our coal combustion by-products. However, these coal-ash by-products have been, and to a small degree, continue to be disposed in company-owned, licensed landfills. Some early designed and constructed landfills may allow the release of low levels of constituents resulting in the need for various levels of monitoring or adjusting. Where we have become aware of these conditions, efforts have been expended to define the nature and extent of any release, and work has been performed to address these conditions. The costs of these efforts are included in our fuel costs. During 2004, 2003 and 2002, we incurred $1.8 million, $2.1 million and $2.1 million, respectively, in coal-ash remediation expenses. As of December 31, 2004, we have no reserves established related to ash landfill sites.

EPA Information Requests: We received a request for information in December 2000 from the United States Environmental Protection Agency (EPA) regional offices pursuant to Section 114(a) of the Clean Air Act and a supplemental request in December 2002. In April 2003, we announced that a consent decree had been reached with the EPA that resolved all issues related to this matter. In July 2003, the court granted the state of Michigan and EPA's joint motion to amend the consent decree to allow Michigan to become a party. Under the consent decree, we will significantly reduce air emissions from our coal-fired generating facilities. The reductions will be achieved by 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 the 10 years ending 2013. Under the agreement with the EPA, we will conduct a full scale demonstration at our Presque Isle facility, in cooperation with the United States Department of Energy (DOE), to test new mercury reduction technologies. The DOE will contribute $24.8 million in addition to the $20 to

$25 million that we will spend to implement this project. These steps and the associated costs are consistent with our cost projections for implementing our Wisconsin Multi-Emission Cooperative Agreement and Wisconsin Energy's Power the Future plan. We also agreed to pay a civil penalty of $3.2 million which was charged to earnings in the second quarter of 2003.

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 was completed and the judge heard oral arguments from the parties in August 2004. In September 2004, the court granted the intervenors' request for limited discovery with respect to two facilities within our generation fleet, and ordered that discovery be completed by December 2004. Final briefing is scheduled to be concluded in March 2005.

Following the submission of briefs, the court may convene additional hearings.

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Deloitte.

REPORT OF INDIEPENDENT REGISTEREI) PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholders of Wisconsin Electric Power Company:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Wisconsin Electric Power Company and subsidiary as of December 31, 2004 and 2003, and the related consolidated statements of income, common equity and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perforn the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Wisconsin Electric Power Company and subsidiary at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

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

&A 2 ,? 6a;uCL LL Deloitte & Touche LLP Milwaukee, Wisconsin March 4, 2005 A-58

MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Dividends declared on our common stock during the two most recent fiscal years are set forth below. Dividends were paid entirely in cash. Dividends were paid to our sole common stockholder, Wisconsin Energy Corporation.

There is no established public trading market for our common stock.

Quarter 2004 2003 (Millions of Dollars)

First $44.9 $44.9 Second 44.9 44.9 Third 44.9 44.9 Fourth 44.9 44.9 Total $179.6 $179.6 Subject to any regulatory restriction or other limitations on the payment of dividends, future dividends will be at the discretion of the board of directors and will depend upon, among other factors, earnings, financial condition and other requirements.

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

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

Electric Operations: We are the largest electric utility in the state of Wisconsin. We generate, distribute and sell electric energy to approximately 1,081,400 customers in southeastern (including the metropolitan Milwaukee area),

east central and northern Wisconsin and in the Upper Peninsula of Michigan. On January 1, 2001, we, together with Edison Sault Electric Company, an affiliated electric utility, and with other unaffiliated Wisconsin utilities, transferred our electric transmission assets to American Transmission Company LLC in return for a proportionate ownership interest in this new company.

Gas Operations: Our gas operations purchase, distribute and sell natural gas to retail customers and transports customer-owned gas to approximately 437,800 customers in three distinct service areas in Wisconsin: west and south of the City of Milwaukee, the Appleton area and areas within Iron and Vilas Counties. We began doing business with Wisconsin Gas LLC, an affiliated gas utility, under the trade name "We Energies" in April 2002.

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

For additional financial information about our operating segments, see "Note N -- Segment Reporting" in the Notes to Consolidated Financial Statements.

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DIRECTORS AND EXECUTIVE OFFICERS DIRECTORS The information under "Election of Directors" in Wisconsin Electric Power Company's definitive Information Statement dated March 21, 2005, attached hereto, is incorporated herein by reference.

EXECUTIVE OFFICERS Gale E. Klappa.

Chairman of the Board, President and Chief Executive Officer of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas LLC.

Charles R. Cole.

Senior Vice President of Wisconsin Electric Power Company and Wisconsin Gas LLC.

Stephen P. Dickson.

Controller of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas LLC.

Frederick D. Kuester.

Executive Vice President of Wisconsin Energy Corporation and Wisconsin Gas LLC; Executive Vice President and Chief Operating Officer of Wisconsin Electric Power Company.

Allen L. Leverett.

Executive Vice President and Chief Financial Officer of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas LLC.

Kristine A. Rapp6.

Senior Vice President and Chief Administrative Officer of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas LLC.

Larry Salustro.

Executive Vice President and General Counsel of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas LLC.

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