Edgar Filing: WISCONSIN ENERGY CORP

Notice and Proxy Statement

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

SCHEDULE 14A

Proxy Statement Pursuant to Section 14(a) of the Securities Exchange Act of 1934 (Amendment No. )

Filed by the Registrant x

Filed by a Party other than the Registrant ¨

Check the appropriate box:

¨ Preliminary Proxy Statement

¨ Confidential, for use of the Commission Only (as permitted by Rule 14a-6(e)(2))

x Definitive Proxy Statement

¨ Definitive Additional Materials

¨ Soliciting Material Pursuant to (S) 240.14a-11(c) or (S) 240.14a-12

Wisconsin Energy Corporation

(Name of Registrant as Specified In Its Charter)

(Name of Person(s) Filing Proxy Statement, if other than the Registrant)

Payment of Filing Fee (Check the appropriate box):

x	No fee required.

¨	Fee computed on table below per Exchange Act Rules 14a-6(i)(4) and 0-11.

(1)

Title of each class of securities to which transaction applies:

(2)

Aggregate number of securities to which transaction applies:

(3)

Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (set forth the amount on which the filing fee is calculated and state how it was determined):

(4)

Proposed maximum aggregate value of transaction:

(5)

Total fee paid:

¨	Fee paid previously with preliminary materials.

¨	Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration statement number, or the Form or Schedule and the date of its filing.

(1)

Amount Previously Paid:

(2)

Form, Schedule or Registration Statement No.:

(3)

Filing Party:

(4)

Date Filed:

LOGO

•

Notice of 2005 Annual Meeting of Stockholders

•

Proxy Statement

•

Annual Financial Statements and Review of Operations

NOTICE OF ANNUAL MEETING OF STOCKHOLDERS

March 18, 2005

To the Stockholders of Wisconsin Energy Corporation:

You are cordially invited to attend the 2005 Annual Meeting of Stockholders. Regardless of whether you plan to attend, please take a moment to vote your proxy. The Meeting will be held as follows:


WHEN:		Thursday, May 5, 2005 10:00 a.m., Central Time

WHERE:		Concordia University Wisconsin R. John Buuck Field House 12800 North Lake Shore Drive Mequon, Wisconsin 53097

ITEMS OF BUSINESS:		• Election of nine directors for terms expiring in 2006.

		• Ratification of Deloitte & Touche LLP as independent auditors for 2005.

		• Consideration of any other matters that may properly come before the Meeting.

RECORD DATE:		February 25, 2005

VOTING BY PROXY:		Your vote is important. You may vote:

		• using the Internet; • by telephone; or • by returning the proxy card in the envelope provided.

By Order of the Board of Directors

Anne K. Klisurich

Vice President and Corporate Secretary

TABLE OF CONTENTS


		Page
Notice of Annual Meeting of Stockholders

Proxy Statement

General Information – Frequently Asked Questions		1

Proposals to be Voted Upon		3

Proposal 1: Election of Directors – Terms Expiring in 2006		3

Information About Nominees for Election to the Board of Directors		4

Proposal 2: Ratification of Deloitte & Touche LLP as Independent Auditors for 2005		6

Independent Auditors’ Fees and Services		6

Corporate Governance – Frequently Asked Questions		8

Committees of the Board of Directors		12

Audit and Oversight Committee Report		13

Compensation of the Board of Directors		14

Compensation Committee Report on Executive Compensation		15

Executive Officers’ Compensation		19

Employment and Severance Arrangements		22

Retirement Plans		24

WEC Common Stock Ownership		26

Section 16(a) Beneficial Ownership Reporting Compliance		27

Certain Relationships and Related Transactions		27

Performance Graph		28

Availability of Form 10-K		29

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

PROXY STATEMENT

This proxy statement is being furnished to stockholders beginning on or about March 18, 2005, in connection with the solicitation of proxies by the Wisconsin Energy Corporation (“WEC” or the “Company”) Board of Directors (the “Board”) to be used at the Annual Meeting of Stockholders on May 5, 2005 (the “Meeting”) at 10:00 a.m. Central Time, at the R. John Buuck Field House at Concordia University Wisconsin, located at 12800 North Lake Shore Drive, Mequon, Wisconsin 53097, and at all adjournments or postponements of the Meeting, for the purposes listed in the preceding Notice of Annual Meeting of Stockholders.

GENERAL INFORMATION – FREQUENTLY ASKED QUESTIONS


What am I voting on?		Proposal 1: Election of nine directors for terms expiring in 2006.

		Proposal 2: Ratification of Deloitte & Touche LLP as independent auditors for 2005.

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

What are the Board’s voting recommendations?		The Board of Directors recommends a vote: • FOR each of the nine nominated directors, and • FOR ratification of Deloitte & Touche LLP as independent auditors for 2005.

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

		Proposal 2: Ratification of the independent auditors requires the affirmative vote of a majority of the votes cast in person or by proxy at the Meeting.

Who can vote?		Common stockholders as of the close of business on the record date, February 25, 2005, can vote. Each outstanding share of WEC common stock is entitled to one vote upon each matter presented. A list of stockholders entitled to vote will be available for inspection by stockholders at WEC’s principal business office, 231 West Michigan Street, Milwaukee, Wisconsin 53203, prior to the Meeting. The list also will be available at the Meeting.

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

		• By Internet. To save costs, the Company encourages you to vote this way.

		• By toll-free touch-tone telephone.

		• By completing and mailing the enclosed proxy card.

		• By written ballot at the Meeting.

		Instructions to vote through the Internet or by telephone are listed on your proxy card or the information forwarded to you by your bank or broker. The Internet and telephone voting facilities will close at 10:00 a.m., Central Time, on May 5, 2005.

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

		If you are a beneficial owner and your broker holds your shares in its name, the broker is permitted to vote your shares on the election of directors and ratification of the independent auditors even if the broker does not receive voting instructions from you. If your shares are held in the name of a broker, bank or other holder of record, you are invited to attend the Meeting, but may not vote at the Meeting unless you have first obtained a proxy executed in your favor from the holder of record.


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

What constitutes a quorum?		As of the record date, there were 116,985,602 shares of WEC common stock outstanding. In order to conduct the Meeting, a majority of the outstanding shares entitled to vote must be represented in person or by proxy. This is known as a “quorum.” Abstentions and shares which are the subject of broker non-votes will count toward establishing a quorum.

Can I change my vote?		You may change your vote or revoke your proxy at any time prior to the closing of the polls, by:

		• entering a new vote by Internet or phone;

		• returning a later-dated proxy card;

		• voting in person at the Meeting; or

		• notifying WEC’s Corporate Secretary by written revocation letter.

		The Corporate Secretary is Anne K. Klisurich. Any revocation should be filed with her at WEC’s principal business office, 231 West Michigan Street, P. O. Box 1331, Milwaukee, Wisconsin 53201.

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

Who conducts the proxy solicitation?		The WEC Board is soliciting these proxies. WEC will bear the cost of the solicitation of proxies. WEC contemplates that proxies will be solicited principally through the use of the mail, but employees of WEC or its subsidiaries may solicit proxies by telephone, personally or by other communications, without compensation apart from their normal salaries. It is not anticipated that any other persons will be engaged to solicit proxies or that compensation will be paid for that purpose. However, WEC may seek the services of an outside proxy solicitor in the event that such services become necessary.

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

What steps has WEC taken to reduce the cost of proxy solicitation?		WEC has implemented several practices that reduce the printing and postage costs and are friendly to the environment. The Company has:

		• encouraged Internet and telephone voting of your proxies;

		• encouraged stockholders to view the proxy statement and annual report on the Internet instead of receiving them via mail; and

		• implemented “householding” whereby stockholders sharing a single address receive a single annual report and proxy statement, unless the Company received instructions to the contrary.

		If you received multiple copies of the annual report and proxy statement, you may wish to contact the Company’s transfer agent, The Bank of New York, at 1-800-558-9663 to request householding, or you may provide written instructions to The Bank of New York, Church Street Station, P.O. Box 11258, New York, New York, 10286-1258. If you wish to receive separate copies of the annual report and proxy statement now or in the future, or to discontinue householding entirely, you may contact the Company’s transfer agent using the contact information provided above. Upon request, the Company will promptly send a separate copy of either document. Whether or not a stockholder is householding, each stockholder will continue to receive a proxy card. If your shares are held through a bank, broker or other holder of record, you may request householding by contacting the holder of record.

Who do I contact if I have questions about the Meeting or my account?		If you need more information about the Meeting, write to Stockholder Services, 231 West Michigan Street, P.O. Box 1331, Milwaukee, Wisconsin 53201, or call us at 1-800-881-5882. For information about shares registered in your name or your Stock Plus account, call our transfer agent, The Bank of New York, at 1-800-558-9663, or access your account via the Internet at www.stockbny.com.

PROPOSALS TO BE VOTED UPON

PROPOSAL 1: ELECTION OF DIRECTORS – TERMS EXPIRING IN 2006

At the Annual Meeting of Stockholders on May 5, 2004, the stockholders of WEC approved an amendment to the Company’s Bylaws that eliminates classification of the Board into three classes and requires each director to be elected annually. This proposal received the required vote of 80% of the outstanding shares of WEC common stock. Under the previous classified structure, each director was elected to a three-year term. That meant approximately one-third of the Board stood for election each year.

The amendment to declassify the Board becomes effective at the Meeting. Directors elected at the Meeting will hold office for a one-year term expiring at the 2006 Annual Meeting of Stockholders.

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

The Board’s nominees for election are

•

John F. Ahearne

•

John F. Bergstrom

•

Barbara L. Bowles

•

Robert A. Cornog

•

Curt S. Culver

•

Gale E. Klappa

•

Ulice Payne, Jr.

•

Frederick P. Stratton, Jr.

•

George E. Wardeberg

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. The Corporate Governance Committee 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 of Directors 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.

Each nominee has consented to being nominated and to serve if elected. In the unlikely event that any nominee becomes unable to serve for any reason, the proxies will be voted for a substitute nominee selected by the WEC Board upon the recommendation of the Corporate Governance Committee of the Board. Biographical information regarding each nominee is shown on the next pages.

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

INFORMATION ABOUT NOMINEES FOR ELECTION TO THE BOARD OF DIRECTORS

Wisconsin Electric Power Company (WE) and Wisconsin Gas LLC (WG) 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 as of March 18, 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 graduate students and conducts national meetings on major scientific issues. • Resources for the Future – Adjunct Professor since 1993. Resources for the Future is an economic research, non-profit institute. • Duke University – Lecturer since 1995. Adjunct Professor from 1996 to 2002. • United States Nuclear Regulatory Commission – Commissioner from 1978 to 1983, serving as Chairman from 1979 to 1981. • Director of Wisconsin Energy Corporation and Wisconsin Electric Power Company since 1994. Director of Wisconsin Gas LLC since 2000.


		John F. Bergstrom. Age 58. • Bergstrom Corporation – Chairman and Chief Executive Officer since 1997. President from 1974 through 1996. Bergstrom Corporation owns and operates numerous automobile sales and leasing companies. • Director of Banta Corporation, Kimberly-Clark Corporation, Midwest Air Group, Inc. and Sensient Technologies Corporation. • Director of Wisconsin Energy Corporation since 1987. Director of Wisconsin Electric Power Company since 1985. Director of Wisconsin Gas 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 Corporation 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 Corporation. • 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 Officer and Treasurer from March 2001 to April 2003. Chief Strategic Officer from October 1999 to March 2001. Southern Company is a public utility holding company serving the southeastern United States. • Director of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas LLC since 2003.


		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. Wardeberg. 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.

PROPOSAL 2: RATIFICATION OF DELOITTE & TOUCHE LLP AS INDEPENDENT AUDITORS FOR 2005

The Audit and Oversight Committee of the Board of Directors has sole authority to select, evaluate and, where appropriate, terminate and replace the independent auditors. The Audit and Oversight Committee has appointed Deloitte & Touche LLP as the Company’s independent auditors for the fiscal year ending December 31, 2005. The Committee believes that stockholder ratification of this matter is important considering the critical role the independent auditors play in maintaining the integrity of the Company’s financial statements. If stockholders do not ratify the selection of Deloitte & Touche LLP, the Audit and Oversight Committee will reconsider the selection.

Deloitte & Touche LLP also served as the independent auditors for the Company for the fiscal years ended December 31, 2004, 2003 and 2002.

Representatives of Deloitte & Touche LLP are expected to be present at the Meeting. They will have an opportunity to make a statement if they so desire and are expected to respond to appropriate questions that may be directed to them.

The appointment of Deloitte & Touche LLP as independent auditors for 2005 will be ratified if the number of votes cast in favor of the proposal exceeds the number of votes cast against the proposal. Accordingly, presuming a quorum is present, abstentions and broker non-votes will have no effect on the outcome of this proposal.

The Board of Directors recommends that you vote “FOR”

the ratification of Deloitte & Touche LLP as independent auditors for 2005.

INDEPENDENT AUDITORS’ FEES AND SERVICES

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 the annual financial statements of the Company and its subsidiaries 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 ⁽¹⁾	$	1,540,156	$	1,032,885
Audit-Related Fees ⁽²⁾		199,000		138,133
Tax Fees ⁽³⁾		216,684		323,093
All Other Fees ⁽⁴⁾		—		—

Total	$	1,955,840	$	1,494,111

⁽¹⁾

Audit Fees consist of fees for professional services rendered in connection with the audit of annual financial statements of the Company and its subsidiaries, review of financial statements included in Form 10-Q filings of the Company and its subsidiaries and services normally provided in connection with statutory and regulatory filings or engagements. In 2004, audit fees also include fees for professional services rendered for the audits of (i) management’s assessment of the effectiveness of internal control over financial reporting and (ii) the effectiveness of internal control over financial reporting.

⁽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, consultations regarding implementation of accounting standards and due diligence related to mergers and acquisitions.

⁽³⁾

Tax Fees consist of fees for professional services rendered with respect to federal, state and international 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.

CORPORATE GOVERNANCE – FREQUENTLY ASKED QUESTIONS


Does WEC have Corporate Governance Guidelines?		Yes, the Board has maintained Corporate Governance Guidelines since 1996 which provide a framework from which the Board conducts its business. The 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 the Company’s website at www.wisconsinenergy.com.

How are directors determined to be independent?		No director qualifies as independent unless the Board affirmatively determines that the director has no material relationship with the Company. The Corporate Governance Guidelines provide that the Board should consist of at least a two-thirds majority of independent directors.

What are the Board’s standards of independence?		The guidelines the Board uses in determining director independence are located in Appendix A of the Corporate Governance Guidelines. These standards of independence, which are 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 where any of the Company’s present executives serve on that other company’s compensation committee;

		• in the past three years, has not been an employee of a company that makes payments to, or receives payments from, the Company for property or services in an amount which in any single fiscal year is the greater of $1 million or 2% of such other company’s consolidated gross revenues;

		• has not received, in the past three years, remuneration, other than de minimus remuneration, as a result of services as, or being affiliated with an entity that serves as, an advisor, consultant, legal counsel or significant supplier to the Company or to a member of the Company’s senior management;

		• has no personal service contract(s) with the Company or any member of the Company’s senior management;

		• is not an employee or officer with a not-for profit entity that receives 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.

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


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

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

Are the Audit and Oversight, Corporate Governance and Compensation Committees comprised solely of independent directors?		Yes, these committees are comprised solely of independent directors, as determined under New York Stock Exchange rules and the Board’s Corporate Governance Guidelines. 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 directors meet separately from management?		Yes, at every regularly scheduled Board meeting an executive session of non-management (non-employee) directors is held without any management present. Annually, an executive session of independent directors is held without any management or non-independent directors present. The chair of the Corporate Governance Committee, currently Director Davis, presides at these sessions.

How can I contact the members of the Board?		Correspondence may be sent to the directors, including the non-employee directors, in care of the Corporate Secretary, Anne K. Klisurich, at the Company’s principal business office, 231 West Michigan Street, P.O. Box 1331, 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 written code of ethics?		Yes, all WEC directors, executive officers and employees, including the principal 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 the Company’s website at www.wisconsinenergy.com. It is also available in print to any stockholder upon request.

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

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


Does the Board evaluate its own performance?		Yes, the Board annually evaluates its own collective performance. Each director is asked to rate the performance of the Board on such things as: the establishment of appropriate corporate governance practices; providing appropriate oversight for key affairs of the Company (including its strategic plans, long-range goals, financial and operating performance and customer satisfaction initiatives); 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. The Corporate Governance Committee uses the results of this process as part of its annual review of the Corporate Governance Guidelines and to foster continuous improvement of the Board’s activities.

Is Board committee performance evaluated?		Yes, each committee, except the Executive Committee, conducts an annual performance evaluation 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 committee financially literate and does the committee have an “audit committee financial expert”?		Yes, the Board has determined that all of the members of the Audit and Oversight Committee are financially literate as required by New York Stock Exchange rules. The Board has also determined that Directors Barbara L. Bowles (Chair), John F. Bergstrom, Robert A. Cornog, Curt S. Culver, Ulice Payne, Jr. and Frederick P. Stratton, Jr. qualify as audit committee financial experts within the meaning of Securities and Exchange Commission rules. In addition, no member of the Audit and Oversight Committee serves as an audit committee member of more than three public companies. For this purpose, the Company considers service on the audit committees of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin 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 nominating committee?		Yes, the Corporate Governance Committee is responsible for, among other things, identifying and evaluating director nominees. The chair of the Committee coordinates this effort. The Board has determined that all members of the Corporate Governance Committee are independent under the New York Stock Exchange rules applicable to nominating committee members.

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

		Stockholders wishing to propose director candidates for consideration and recommendation by the Corporate Governance Committee for election at the 2006 Annual Meeting of Stockholders must submit the name(s) and qualifications of any proposed candidate(s) to the Corporate Governance Committee no later than November 1, 2005 via the Corporate Secretary, Anne K. Klisurich, at the Company’s principal business office, 231 West Michigan Street, P.O. Box 1331, Milwaukee, Wisconsin 53201.

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

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


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

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

What is the deadline for stockholders to submit proposals for the 2006 Annual Meeting of Stockholders?		Stockholders who intend to have a proposal considered for inclusion in the Company’s proxy materials for presentation at the 2006 Annual Meeting of Stockholders must submit the proposal to the Company no later than November 18, 2005. Stockholders who intend to present a proposal at the 2006 Annual Meeting of Stockholders without inclusion of such proposal in the Company’s proxy materials, or who propose to nominate a person for election as a director at the 2006 Annual Meeting, are required to provide notice of such proposal or nomination, containing the information required by the Company’s Bylaws, to the Company at least 70 days and not more than 100 days prior to the scheduled date of the 2006 Annual Meeting of Stockholders.


		Correspondence in this regard should be directed to the Corporate Secretary, Anne K. Klisurich, at the Company’s principal business office, 231 West Michigan Street, P.O. Box 1331, Milwaukee, Wisconsin 53201.

What is WEC’s policy regarding director attendance at annual meetings?		All directors are expected to attend the Company’s annual meetings of stockholders. All directors attended the 2004 Annual Meeting.

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

COMMITTEES OF THE BOARD OF DIRECTORS


Members		Principal Responsibilities; Meetings
Audit and Oversight Barbara L. Bowles, Chair John F. Bergstrom Robert A. Cornog Curt S. Culver Ulice Payne, Jr. Frederick P. Stratton, Jr.		• Oversee the integrity of the financial statements. • Oversee management compliance with legal and regulatory requirements. • Review, approve and evaluate the independent auditors’ services. • Oversee the performance of the internal audit function and independent auditors. • Prepare the report required by the SEC for inclusion in the proxy statement. • Establish procedures for the submission of complaints and concerns regarding WEC’s accounting or auditing matters. • The Committee conducted seven meetings in 2004

Compensation John F. Bergstrom, Chair John F. Ahearne Willie D. Davis		• Identify through succession planning potential executive officers. • Provide a competitive, performance-based executive and director compensation program. • Set goals for the CEO, annually evaluate the CEO’s performance against such goals and 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 proxy statement. • The Committee conducted six meetings in 2004.

Corporate Governance Willie D. Davis, Chair Barbara L. Bowles Robert A. Cornog		• Establish and review the Corporate Governance Guidelines to ensure the Board is effectively performing its fiduciary responsibilities to stockholders. • Identify and recommend candidates to be named as nominees of the Board for election as directors. • Lead the Board in its annual review of the Board’s performance. • The Committee conducted one meeting in 2004.

Finance Frederick P. Stratton, Jr., Chair John F. Bergstrom Barbara L. Bowles Robert A. Cornog Curt S. Culver Ulice Payne, Jr.		• Review and monitor the Company’s current and long-range financial policies and strategies, including its capital structure and dividend policy. • Authorize the issuance of corporate debt within limits set by the Board. • Discuss policies with respect to risk assessment and risk management. • Review, approve and monitor the Company’s capital and operating budgets. • The Committee conducted three meetings in 2004.

Nuclear Oversight John F. Ahearne, Chair Frederick P. Stratton, Jr.		• Advise and assist the Board in the proper and complete discharge of its responsibilities relating to the Company’s nuclear operations. • The Committee conducted two meetings in 2004.

The Nuclear Oversight Committee also includes one employee member and three other non-directors who serve as ad hoc members due to their considerable expertise in nuclear matters. The employee member of the Committee is Frederick D. Kuester, Executive Vice President of Wisconsin Energy Corporation and Wisconsin Gas LLC, and Executive Vice President and Chief Operating Officer of Wisconsin Electric Power Company. The other non-director members are Mr. Leon R. Eliason, former President—Generation at Northern States Power Company and former President—Nuclear Business Unit and Chief Nuclear Officer at Public Service Enterprise Group Incorporated; Dr. Thomas E. Murley, former director of the Nuclear Regulatory Commission’s Office of Nuclear Reactor Regulation; and Dr. C. Frederick Sears, formerly Vice President, Nuclear and Environmental Engineering for Northeast Utilities and currently the Director, Radiation Science and Engineering Center at Pennsylvania State University.

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.

AUDIT AND OVERSIGHT COMMITTEE REPORT

The Audit and Oversight Committee, which is comprised solely of independent directors, oversees the integrity of the financial reporting process on behalf of the Board of Directors of Wisconsin Energy Corporation. In addition, the Committee 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 the Company’s website at www.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 stockholder ratification.

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 seven 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 Energy Corporation’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 Energy Corporation stockholders by the Audit and Oversight Committee of the Board of Directors.

Barbara L. Bowles, Committee Chair

John F. Bergstrom

Robert A. Cornog

Curt S. Culver

Ulice Payne, Jr.

Frederick P. Stratton, Jr.

COMPENSATION OF THE BOARD OF DIRECTORS

Effective January 1, 2004, WEC’s Board of Directors approved a change in director compensation practices in order to align WEC’s director compensation with director compensation practices at WEC’s peer companies and to reflect emerging governance and compensation trends with regard to equity compensation. In addition, the Board adopted stock ownership guidelines for directors to further align the Board’s interests with 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 $300 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 the 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. The deferred amounts will be paid out of the general corporate assets or the trust described under “Retirement Plans” in this proxy statement.

Although WEC directors also serve on the Wisconsin Electric Power Company 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 WEC, Wisconsin Electric Power Company and Wisconsin Gas LLC based on services rendered.

The Company has established a Directors’ Charitable Awards Program to help further its philosophy of charitable giving. Under the program, the Company 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. There is a vesting period of three years of service on the Board required for participation in this program. Beneficiary organizations under the program must be approved by the Corporate Governance Committee. 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 the Company. The tax deductibility of these charitable donations mitigates the net cost to the Company.

COMPENSATION COMMITTEE REPORT

ON EXECUTIVE COMPENSATION

Compensation Philosophy and Objectives. The Compensation Committee is responsible for making decisions regarding compensation for the executives of Wisconsin Energy Corporation and its principal subsidiaries. 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 WEC to attract and retain key individuals and to motivate them to achieve WEC’s short- and long-term goals.

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

The primary elements of WEC’s executive compensation program are base salary, annual incentive compensation and long-term incentive compensation. For WEC executives, all elements of compensation are targeted at the 50^th percentile of general industry practices — that is, we target compensation at the median levels paid for similar positions at similarly sized companies.

In order to determine 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. We believe that the labor market for WEC executives is that of general industry in the United States. As a result, we rely upon an analysis of compensation data for similarly sized companies in general industry. Recognizing that a significant portion of WEC’s business is in the energy services industry, we also consider compensation data that analyzes the energy services industry. A greater emphasis is placed upon compensation practices in the energy industry for executives whose positions principally relate to utility operations.

Specific values of 2004 compensation for the current Chief Executive Officer, the retired Chief Executive Officer and the four other most highly compensated executive officers 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 50^th percentile of general industry practices for WEC officers and the 50^th percentile of energy services industry practices for Wisconsin Electric Power Company and Wisconsin Gas LLC officers. In making these adjustments, we also considered factors such as the relative levels of individual experience, performance, responsibility and contribution to the results of Company operations. 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 Committee’s direction, 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 earnings from ongoing operations and cash flow. For 2004, the target for earnings from ongoing operations excluded the effects of asset sales, impairment charges, debt redemption costs and certain severance costs. The Company’s financial performance exceeded the targets for 2004. Performance incentive awards could be increased or decreased by up to 10% based upon the Company’s performance in the operational areas of customer satisfaction (5%), supplier and workforce diversity (2.5%) and safety (2.5%). The Company’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 Company performance against earnings from ongoing operations and cash flow targets. As was the case in 2004, the Company’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. The Committee administers the Company’s 1993 Omnibus Stock Incentive Plan, as amended, which is a stockholder approved, long-term incentive plan designed to link the interests of executives and other key employees to long-term stockholder value. It allows for various types of awards keyed to the performance of the Company’s common stock, including stock options, stock appreciation rights, restricted stock and performance shares. Historically, the Committee has primarily used stock options to deliver competitive long-term incentive opportunities.

For 2004, in order to model best practices, the Committee modified the long-term incentive program to include a 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 the Company’s Total Shareholder Return over a three-year period, as compared to the Total Shareholder Return of the Custom Peer Group identified in the “Performance Graph” section of this proxy statement. “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. The Committee believes this measure better aligns executive financial interests with those of 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 proxy 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.”

For 2005, the Committee adopted a similar plan, except that upon vesting, the 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, the Committee approved the acceleration of vesting of all unvested 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, the 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 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 stock ownership guidelines for officers of the Company. The guidelines provide that each executive officer should, over time (generally within five years of appointment as an executive officer), acquire and hold Company 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 WEC’s 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.

Mr. Klappa’s salary was $856,668 for 2004. This amount reflects his salary as President and the upward adjustment made when he was appointed to the additional positions of Chairman of the Board and Chief Executive Officer 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 as reflected in the survey of general industry compensation practices. Mr. Klappa’s annual incentive compensation award as President was targeted at 90% of base pay, and when he was appointed to the additional positions of Chairman and Chief Executive Officer his award was targeted at 100% of a full year of base pay in such positions. The award for 2004 was $1,791,202 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 the pump and water systems business for approximately $850 million plus the buyer’s assumption of $25 million of third party debt, all of which assisted in the significant reduction of WEC’s consolidated debt.

•

Achievements with respect to WEC’s Power the 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 $155 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:

•

Wisconsin Electric Power Company’s receipt of the National ReliabilityOne Award for superior electric system reliability and its third consecutive Midwest regional award;

•

Wisconsin Electric Power 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 Wisconsin Electric’s and Wisconsin Gas’ residential gas service.

•

Leadership of the Board of Directors through effective corporate governance as evidenced by the rating of a “10,” the highest possible score, from GovernanceMetrics International (GMI) and 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-term incentive compensation in 2004 in the form of stock options, as set forth in the “Long-Term Compensation Awards” column of the Summary Compensation Table, and performance shares, as set forth in “Long-Term Incentive Plans – Awards in Last Fiscal Year.”

In reviewing the performance of Mr. Abdoo, we requested that all independent directors evaluate his performance. The Committee chair met with Mr. Abdoo to discuss the reviews, and the Committee factored the results into our compensation determinations.

Mr. Abdoo’s annual base salary was set at $850,000. Mr. Abdoo’s salary set forth in the “Salary” column of the Summary Compensation Table reflects the portion of his base salary paid to him in 2004 prior to his retirement on April 30, 2004 as Chairman and Chief Executive Officer. Mr. Abdoo’s base salary as the CEO is below the mid-point of the competitive range for CEOs at comparably sized companies as reflected in the survey of general industry compensation practices. Mr. Abdoo’s annual incentive compensation award was targeted at 100% of annual base pay. Mr. Abdoo’s award reflects the portion earned by him prior to his retirement. The award for 2004 was $400,000 and was based upon the financial achievement of the Company during the first quarter of 2004 and the accomplishment described below. Mr. Abdoo also received stock options, as set forth in the “Long-Term Compensation Awards” column of the Summary Compensation Table.

In view of the discretionary component of the annual incentive plan, the Committee also considered Mr. Abdoo’s role in the successful transition of Mr. Klappa to Chairman of the Board and Chief Executive Officer.

As a result of his retirement, Mr. Abdoo received the benefits described under “Employment and Severance Arrangements” and “Retirement Plans” in this proxy statement.

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 the 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 the Company and its stockholders despite the fact that such arrangements might not, in whole or in part, qualify for tax deductibility.

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

John F. Bergstrom, Committee Chair

John F. Ahearne

Willie D. Davis

EXECUTIVE OFFICERS’ COMPENSATION

This table summarizes, for the last three fiscal years, compensation awarded to, earned by or paid to WEC’s Chief Executive Officer, WEC’s retired Chief Executive Officer and each of WEC’s other four most highly compensated executive officers (the “named executive officers”).

Summary Compensation Table


	Year	Annual Compensation				Long-Term Compensation Awards		All Other Compensation⁽²⁾ ($)
Name and Principal Position	Year	Salary ($)	Bonus ($)	Other Annual Compensation ($)		Restricted Stock Awards⁽¹⁾ ($)	Securities Underlying Options (#)	All Other Compensation⁽²⁾ ($)
Gale E. Klappa Chairman of the Board, President and Chief Executive Officer of WEC, WE and WG ⁽⁴⁾	2004 2003	856,668 458,179	1,791,202 1,075,000	212,573 131,740	⁽³⁾ ⁽³⁾	— 1,006,320	200,000 250,000	47,450 12,952

Richard A. Abdoo Retired Chairman of the Board and Chief Executive Officer of WEC; Retired Chairman of the Board of WE and WG ⁽⁵⁾	2004 2003 2002	283,332 794,004 756,300	400,000 1,500,000 859,308	5,748 11,749 11,868		— — —	300,000 300,000 300,000	53,500 49,099 66,959

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

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

Larry Salustro Executive Vice President and General Counsel of WEC, WE and WG	2004 2003 2002	385,000 360,000 336,000	589,050 375,000 323,331	17,612 2,550 2,297		— 306,600 —	150,000 125,000 75,000	24,241 14,370 34,075

Kristine A. Rappé Senior Vice President and Chief Administrative Officer of WEC, WE and WG ⁽⁴⁾	2004	273,332	285,599	16,354		—	20,925	20,503

⁽¹⁾

There were no restricted stock awards made during fiscal 2004. In 2003, restricted stock awards 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 $25.47, $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 the Company 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 the Company 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 ($1,254,282); Mr. Kuester—22,419 shares ($755,744); Mr. Leverett—29,973 shares ($1,010,390); Mr. Salustro—29,034 shares ($978,736); and Ms. Rappé—8,439 shares ($284,479).

During 2004, the Company awarded performance shares to Messrs. Klappa, Kuester, Leverett and Salustro, and Ms. Rappé. 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. Klappa, Abdoo, Kuester, Leverett and Salustro, and Ms. Rappé, 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 Executive Deferred Compensation Plan with respect to matching in the 401(k) plan on deferred salary or salary received but not otherwise eligible for matching in the amounts of $41,300, $47,350, $18,450, $24,600, $9,788 and $5,250, respectively; and

•

gain in value of life insurance policies prior to the policies termination in the amounts of $8,303 for Mr. Salustro and $9,103 for Ms. Rappé.

⁽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 the Company 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. Mr. Kuester commenced employment with WEC in October 2003. Mr. Leverett commenced employment with WEC in July 2003. Ms. Rappé became an executive officer of WEC in May 2004.

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


	Individual Grants⁽¹⁾				Grant Date Value
Name	Number of Securities Underlying Options Granted (#)	Percent of Total Options Granted to Employees in Fiscal Year (%)	Exercise or Base Price ($/Share)	Expiration Date	Grant Date Present Value⁽²⁾ ($)
Gale E. Klappa	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. Rappé	20,925	1.13	33.435	01/02/2014	$	197,672

⁽¹⁾

Consists of incentive and non-qualified stock options to purchase shares of WEC common stock granted on January 2, 2004 pursuant to the 1993 Omnibus Stock Incentive Plan, as amended. These options have exercise prices equal to the fair market value of the WEC shares on the date of grant. By action of the 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 of ten years, subject to earlier termination in certain events related to termination of employment. In the discretion of the Compensation Committee, the exercise price may be paid by delivery or attestation of already-owned shares. Tax withholding obligations related to exercise may be satisfied by withholding shares otherwise deliverable upon exercise, subject to certain conditions. Subject to the limitations of the 1993 Omnibus Stock Incentive Plan, as amended, the Compensation Committee has the power with the participant’s consent to amend these options and to grant extensions.

⁽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 stock: $33.435; 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%. WEC’s use of this model should not be construed as an endorsement of its accuracy. The ultimate value of the options, if any, will depend upon the future value of 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.


	Shares Acquired on Exercise (#)	Value Realized ($)⁽¹⁾	Number of Securities Underlying Unexercised Options at Fiscal Year-End (#)		Value of Unexercised In the Money Options at Fiscal Year-End ($)⁽³⁾

Name			Exercisable⁽²⁾	Unexercisable⁽²⁾	Exercisable⁽²⁾	Unexercisable
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. Rappé	3,000	15,561	105,477	4,294	686,274	56,127

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

⁽²⁾

By action of the Compensation Committee on December 28, 2004, all options that were granted in 2002, 2003 and 2004, and not otherwise exercisable, became exercisable as of December 31, 2004, including those granted to Messrs. Klappa, Kuester, Leverett and Salustro, and Ms. Rappé. 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 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 non-stock price based plans
Name	Number of shares, units or other rights (#)	Performance or other period until maturation or payment	Threshold (#)	Target (#)	Maximum (#)
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. Rappé	2,115	3 years from date of grant	529	2,115	3,701

The table set forth above reflects the award of performance shares to the named executive officers in 2004 under the 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 identified in the “Performance Graph” section of this proxy 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:


Percentile Rank	Vesting Percent
< 25^thPercentile	0	%
25^th Percentile	25	%
Target (50^th Percentile)	100	%
75^th Percentile	125	%
90^th Percentile	175	%

If the Company’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 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 the Company. 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. Rappé 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.

The Company 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 the Company on April 14, 2003. Under the agreement with Mr. Klappa, severance benefits are provided if his employment is terminated (i) by the Company, other than for cause, death or disability, in anticipation of or following a change in control, (ii) by 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 the Company 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 the Company prior to termination or the change in control, or (iii) an amount calculated by multiplying the highest bonus percentage earned during either of such three fiscal year periods times the highest yearly base salary rate in effect during the three-year period ending prior to termination. The agreement also provides for three years’ continuation of health and certain other welfare benefit coverage, eligibility for retiree health coverage thereafter, a payment equal to the value of three additional years’ of participation in the applicable qualified and non-qualified retirement plans, full vesting in all outstanding stock options, restricted stock and other equity awards, certain financial planning services and other benefits and a “gross-up” payment should any payments or benefits under the agreements trigger federal excise taxes under the “parachute payment” provisions of the tax law. Mr. Klappa is eligible to receive a supplemental retirement benefit from the Company which is further described under the “Retirement Plans” section of this proxy 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 the Company. 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 $350,000 (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 and Chief Executive Officer, Mr. Klappa’s target bonus opportunity increased to 100% of his base salary. Upon his employment with the Company, Mr. Klappa was granted a non-qualified stock option for 250,000 shares of the Company’s common stock. He was 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. 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 the Company. 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 the Company’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 the Company which is further described under the “Retirement Plans” section of this proxy 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 $100,000 paid on his employment starting date and the balance paid six months later). Mr. Kuester’s target bonus opportunity is fixed at 80% of base salary, with a minimum guaranteed bonus of $150,000 for 2003. Upon his employment with WEC, Mr. Kuester was granted a non-qualified stock option for 200,000 shares of WEC’s common stock. Mr. Kuester was also granted a restricted stock award for 24,140 shares, which vest at the rate of 10% for each year of service until 100% vesting occurs on the 10^th anniversary of his employment starting date, provided that the restricted stock will become 100% vested due to a termination of employment by death or disability.

•

Mr. Leverett commenced employment with the Company on July 1, 2003. Mr. Leverett’s employment agreement is substantially similar to Mr. Klappa’s, except that if Mr. Leverett’s employment is terminated by the Company 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 the Company which is further described under the “Retirement Plans” section of this proxy 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 $250,000 (with $150,000 paid on his employment starting date and the balance paid six months later). Mr. Leverett’s target bonus opportunity is fixed at 80% of base salary, with a minimum guaranteed bonus of $368,000 for 2003. Upon his employment with the Company, Mr. Leverett was granted a non-qualified stock option for 200,000 shares of the Company’s common stock. Mr. Leverett was also granted a restricted stock award for 28,850 shares on his employment starting date. Two-thirds of the shares vest on July 1, 2005, the second anniversary of his employment starting date, and the remaining one-third

vest at the rate of 20% for each year of service thereafter until 100% vesting occurs on the seventh anniversary of the employment starting date, provided that the restricted stock will become 100% vested due to a termination of employment by death or disability.

Long-Term Incentive Compensation Plans Special Vesting Provisions. Under the terms of the Company’s long-term incentive compensation plans, including the 1993 Omnibus Stock Incentive Plan, as amended, and the 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. The Company provides its executive officers with employee benefits and perquisites. Except as specifically noted elsewhere in this proxy 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. The Company also pays the periodic dues and fees for certain club memberships for the named executive officers and other designated officers.

Death Benefit Only Plan. The Company 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 by the Company 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 Summary Compensation 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):

Pension Plan Table – WEC Plan (Prior Plan Formula)


		Years of Service
Remuneration		15	20	25	30	35	40
$	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. Rappé, is $1,191,219, $1,856,185, $682,073, $770,000, $615,043, and $322,649, respectively. Messrs. Klappa, Abdoo, Kuester, Leverett and Salustro, and Ms. Rappé, 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. Rappé, are not entitled to these supplemental benefits until they attain the age of 60.

Other Retirement Benefits. Designated officers of WEC and Wisconsin Electric Power Company, 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.

WEC COMMON STOCK OWNERSHIP

Directors, Nominees and Executive Officers. The following table lists the beneficial ownership of WEC common stock of each director, nominee, named executive officer and all of the directors and executive officers as a group as of 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 common stock.


	Shares Beneficially Owned⁽¹⁾
Name	Shares Owned^{(2) (3) (4)}	Option Shares Exercisable Within 60 Days		Total
Richard A. Abdoo	40,763	741,229		781,992
John F. Ahearne	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. Rappé	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⁾

⁽¹⁾

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

⁽²⁾

Certain 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. Rappé (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 WEC directors and executive officers hold shares of restricted stock (included in table above) over which the holders have sole voting but no investment power: Dr. Ahearne (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. Rappé (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.

Owners of More than 5%. The following table shows stockholders who reported beneficial ownership of more than 5% of WEC common stock, based on the information they have reported. This information is based upon the Forms 13G filed in February 2005 and reflects stock holdings as of December 31, 2004.


	Voting Authority		Dispositive Authority		Total Shares Beneficially Owned	Percent of WEC Common Stock
Name and Address	Sole	Shared	Sole	Shared	Total Shares Beneficially Owned	Percent of WEC Common Stock
AXA Financial, Inc. ⁽¹⁾ 1290 Avenue of the Americas New York, NY 10104	4,663,558	1,314,092	9,043,738	3,793	9,047,531	7.7	%
FMR Corp. ⁽²⁾ 82 Devonshire Street Boston, MA 02109	2,826,450	0	10,083,330	0	10,083,330	8.6	%
Pzena Investment Management, LLC 120 West 45^th Street, 34^th Floor New York, NY 10036	4,346,010	0	7,156,485	0	7,156,485	6.1	%

⁽¹⁾	AXA Financial is a parent holding company and part of a “group” as that term is used in Section 13(d)(3) of the Securities and Exchange Act of 1934. Other members of the group are AXA Assurances I.A.R.D. Mutuelle, AXA Assurances Vie Mutuelle, AXA Courtage Assurance Mutuelle and AXA.

⁽²⁾	FMR Corp. is a parent holding company. Edward C. Johnson 3d, as Chairman of FMR Corp., and Abigail P. Johnson, as a director of FMR Corp., and both as members of a controlling group of FMR Corp., may be deemed to beneficially own the shares of common stock of WEC beneficially owned by FMR Corp.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

Section 16(a) of the Securities Exchange Act of 1934, as amended, requires the Company’s executive officers, directors, and persons owning more than ten percent of WEC’s common stock to file reports of ownership and changes in ownership of equity and derivative securities of WEC with the Securities and Exchange Commission and the New York Stock Exchange. Specific due dates for those reports have been established, and the Company is required to disclose in this proxy statement any failure to file by those dates during the 2004 fiscal year. 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 RELATIONSHIPS AND RELATED TRANSACTIONS

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

As reported in the Summary Compensation Table, Mr. Kuester received benefits in 2004 under the Company’s relocation program. In addition, in 2004 Mr. Kuester sold his home in the city of his former employment for $770,000 to a third-party relocation company hired by the Company to assist in Mr. Kuester’s relocation. The amount of $770,000 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 the Company paid a total of $211,762 to the relocation company for the loss of $152,750 on the resale of Mr. Kuester’s home and $59,012 of closing costs and real estate commissions related thereto.

As reported in the Summary Compensation Table, Mr. Leverett also received benefits under the Company’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 the Company paid a net total of $28,542 to the relocation company for the gain of $14,125 on the resale of Mr. Leverett’s home and $42,667 of closing costs and real estate commissions related thereto.

PERFORMANCE GRAPH

The performance graph below shows a comparison of the cumulative total return, assuming reinvestment of dividends, over the last five years had $100 been invested at the close of business on December 31, 1999, in each of:

•

WEC common stock;

•

a Custom Peer Group Index; and

•

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

In 2003, WEC began to use the Custom Peer Group Index for peer comparison purposes because the Company believes the Index provides an accurate representation of WEC’s peers. In addition, as previously described, the Board’s Compensation Committee uses total stockholder return thresholds for the Custom Peer Group Index to determine a portion of the long-term executive compensation awards.

The Custom Peer Group Index is a market-capitalization-weighted index consisting of 30 companies, including WEC. These companies are similar to WEC in terms of business model and size, as well as long-term strategies. All of the companies in the Custom Peer Group Index receive at least 80% of their revenue from gas and/or electric utility operations.

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

FIVE-YEAR CUMULATIVE RETURN CHART

LOGO

Value of Investment at Year-End


	12/31/1999		12/31/2000		12/31/2001		12/31/2002		12/31/2003		12/31/2004
Wisconsin Energy Corporation	$	100	$	125	$	129	$	149	$	203	$	210
Custom Peer Group Index	$	100	$	151	$	145	$	139	$	167	$	197
S&P 500	$	100	$	91	$	80	$	62	$	80	$	89

AVAILABILITY OF FORM 10-K

A copy (without exhibits) of WEC’s Annual Report on Form 10-K for the fiscal year ended December 31, 2004, as filed with the Securities and Exchange Commission, is available without charge to any stockholder of record or beneficial owner of WEC common stock by writing to the Corporate Secretary, Anne K. Klisurich, at the Company’s principal business office, 231 West Michigan Street, P. O. Box 1331, Milwaukee, Wisconsin 53201. The WEC consolidated financial statements and certain other information found in the Form 10-K are provided in Appendix A to this proxy statement.

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

APPENDIX A

WISCONSIN ENERGY CORPORATION

ANNUAL FINANCIAL STATEMENTS

and

REVIEW of OPERATIONS

A-1

SELECTED FINANCIAL AND OPERATING DATA

WISCONSIN ENERGY CORPORATION

CONSOLIDATED SELECTED FINANCIAL AND STATISTICAL DATA


Financial	2004		2003		2002		2001		2000 (a)
Year Ended December 31
Net income (Millions)	$	306.4	$	244.3	$	167.0	$	219.0	$	154.2
Earnings per share of common stock
Basic	$	2.60	$	2.09	$	1.45	$	1.87	$	1.28
Diluted	$	2.57	$	2.06	$	1.44	$	1.86	$	1.27
Dividends per share of common stock	$	0.83	$	0.80	$	0.80	$	0.80	$	1.37

Operating revenues (Millions)
Utility energy	$	3,375.4	$	3,263.9	$	2,852.1	$	2,964.8	$	2,556.7
Non-utility energy		21.6		14.4		167.2		337.3		372.8
Other		34.1		30.0		31.7		41.3		51.0

Total operating revenues	$	3,431.1	$	3,308.3	$	3,051.0	$	3,343.4	$	2,980.5

At December 31 (Millions)
Total assets	$	9,565.4	$	10,014.5	$	9,465.9	$	9,454.2	$	9,564.7
Total debt	$	3,678.5	$	4,327.5	$	4,223.9	$	4,472.0	$	4,374.2

Utility Energy Statistics
Electric
Megawatt-hours sold (Thousands)		31,648.4		31,183.4		30,862.6		31,062.6		32,042.4
Customers (End of year)		1,104,112		1,090,513		1,078,710		1,066,275		1,048,711
Gas
Therms delivered (Millions)		2,068.1		2,171.2		2,121.3		1,997.2		1,621.5
Customers (End of year)		1,014,799		998,201		982,066		966,817		952,177

CONSOLIDATED SELECTED QUARTERLY FINANCIAL DATA (Unaudited)


	(Millions of Dollars, Except Per Share Amounts) (b)
	March					June
Three Months Ended	2004			2003		2004		2003
Operating revenues	$	1,065.9		$	1,051.4	$	716.4	$	708.2
Operating income (loss)	$	181.7		$	172.2	$	73.4	$	92.6
Income (loss) from Continuing Operations	$	82.4		$	82.5	$	20.9	$	35.0
Income from Discontinued Operations		8.4			9.5		17.7		14.3

Total Net Income	$	90.8		$	92.0	$	38.6	$	49.3

Earnings (loss) per share of common stock (basic)
Continuing operations	$	0.70		$	0.71	$	0.18	$	0.30
Discontinued operations		0.07			0.08		0.15		0.12

Total earnings per share (basic)	$	0.77		$	0.79	$	0.33	$	0.42

Earnings (loss) per share of common stock (diluted)
Continuing operations	$	0.69		$	0.71	$	0.17	$	0.30
Discontinued operations		0.07			0.08		0.15		0.12

Total earnings per share (diluted)	$	0.76		$	0.79	$	0.32	$	0.42


	September					December
Three Months Ended	2004			2003		2004		2003
Operating revenues	$	696.6		$	695.8	$	952.2	$	852.9
Operating income (loss)		($49.8	)	$	79.0	$	174.5	$	138.4

Income (loss) from Continuing Operations		($66.2	)	$	21.3	$	85.1	$	61.6
Income from Discontinued Operations		150.6			9.6		7.5		10.5

Total Net Income	$	84.4		$	30.9	$	92.6	$	72.1

Earnings (loss) per share of common stock (basic)
Continuing operations		($0.56	)	$	0.18	$	0.73	$	0.52
Discontinued operations		1.28			0.08		0.06		0.09

Total earnings per share (basic)	$	0.72		$	0.26	$	0.79	$	0.61

Earnings (loss) per share of common stock (diluted)
Continuing operations		($0.56	)	$	0.18	$	0.73	$	0.51
Discontinued operations		1.27			0.08		0.06		0.09

Total earnings per share (diluted)	$	0.71		$	0.26	$	0.79	$	0.60

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

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

A-2

WISCONSIN ENERGY CORPORATION

CONSOLIDATED SELECTED UTILITY OPERATING DATA


Year Ended December 31	2004			2003		2002			2001		2000 (a)
Electric Utility
Operating Revenues (Millions)
Residential	$	731.3		$	715.5	$	703.0		$	654.5	$	606.7
Small Commercial/Industrial		668.0			642.0		606.3			592.9		550.0
Large Commercial/Industrial		549.9			519.3		483.1			479.7		472.8
Other - Retail/Municipal		90.7			84.9		77.7			70.6		64.7
Resale - Utilities		24.6			24.0		18.1			56.8		79.1
Other Operating Revenues		34.5			27.9		22.6			12.9		24.5

Total Operating Revenues	$	2,099.0		$	2,013.6	$	1,910.8		$	1,867.4	$	1,797.8

Megawatt-hour Sales (Thousands)
Residential		8,053.9			8,099.3		8,310.9			7,773.4		7,633.2
Small Commercial/Industrial		8,840.4			8,740.6		8,719.5			8,595.4		8,524.7
Large Commercial/Industrial		11,686.4			11,401.8		11,129.6			11,177.6		11,824.0
Other - Retail/Municipal		2,405.5			2,225.9		2,051.9			1,828.6		1,755.8
Resale - Utilities		662.2			715.8		650.7			1,687.6		2,304.7

Total Sales		31,648.4			31,183.4		30,862.6			31,062.6		32,042.4

Number of Customers (Average)
Residential		985,811			973,575		963,988			950,271		934,494
Small Commercial/Industrial		107,843			106,469		105,551			103,908		101,665
Large Commercial/Industrial		709			707		709			710		716
Other		2,415			2,392		2,389			2,363		2,327

Total Customers		1,096,778			1,083,143		1,072,637			1,057,252		1,039,202

Gas Utility
Operating Revenues (Millions)
Residential	$	798.6		$	769.3	$	591.0		$	645.9	$	450.2
Commercial/Industrial		396.5			386.0		279.7			313.4		225.2
Interruptible		17.0			16.9		12.6			17.0		13.7

Total Retail Gas Sales		1,212.1			1,172.2		883.3			976.3		689.1
Transported Gas		41.4			36.6		39.4			37.9		32.8
Other Operating Revenues		(1.1	)		17.3		(4.6	)		60.3		14.4

Total Operating Revenues	$	1,252.4		$	1,226.1	$	918.1		$	1,074.5	$	736.3

Therms Delivered (Millions)
Residential		809.9			853.7		817.1			756.3		569.0
Commercial/Industrial		464.0			492.5		463.1			427.7		336.5
Interruptible		24.7			27.5		29.4			25.8		24.9

Total Retail Gas Sales		1,298.6			1,373.7		1,309.6			1,209.8		930.4
Transported Gas		769.5			797.5		811.7			787.4		691.1

Total Therms Delivered		2,068.1			2,171.2		2,121.3			1,997.2		1,621.5

Number of Customers (Average)
Residential		916,921			901,322		888,626			875,339		697,570
Commercial/Industrial		85,031			83,915		82,973			79,503		62,626
Interruptible		68			67		79			82		72
Transported Gas		1,459			1,440		1,508			4,468		3,253

Total Customers		1,003,479			986,744		973,186			959,392		763,521

Degree Days (b)
Heating (6,739 Normal)		6,663			7,063		6,551			6,338		6,716
Cooling (714 Normal)		442			606		897			711		566

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

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

A-3

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

INTRODUCTION

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

Our utility energy segment, consisting of Wisconsin Electric Power Company (Wisconsin Electric) and Wisconsin Gas LLC (Wisconsin Gas), both doing business under the trade name of “We Energies”, and Edison Sault Electric Company (Edison Sault), is engaged primarily in the business of generating electricity and distributing electricity and natural gas in Wisconsin and the Upper Peninsula of Michigan. Our non-utility energy segment primarily consists of W.E. Power, LLC (We Power) and Wisvest Corporation (Wisvest). We Power is principally engaged in the engineering, construction and development of electric power generating facilities for long-term lease to Wisconsin Electric.

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, Forward-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” below, 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

We seek to increase shareholder value by leveraging on our core competencies. Our key corporate strategy, announced in September 2000, is Power the Future. 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 is also 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. Our Power the Future strategy, which is discussed further below, is expected to have a significant impact on our utility and non-utility energy segments. Since 2000, we have been selling our non-core assets to direct more attention to the utility business and to finance Power the Future while reducing our debt.

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

Non-Utility Energy Segment: We are primarily focusing this segment on improving the supply of electric generation in Wisconsin. We Power was formed to design, construct, own, finance and lease new generation assets under the Power the Future strategy. We have divested of the majority of Wisvest’s assets in order to direct capital and management’s attention to Power the Future.

Power the Future Strategy: In February 2001, we filed a petition with the Public Service Commission of Wisconsin (PSCW) that would allow us to begin implementing our 10-year Power the Future strategy to improve

A-4

the supply and reliability of electricity in Wisconsin. Power the Future is intended to meet a growing demand for electricity and ensure a diverse fuel mix while keeping electricity prices reasonable. Under Power the Future, we plan to add new coal-fired and natural gas-fired generating capacity to the state’s power portfolio which would allow Wisconsin Electric to maintain approximately the same fuel mix as exists today. As part of our Power the Future strategy, we plan to (1) invest 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) upgrade Wisconsin Electric’s existing electric generating facilities and (3) invest in upgrades of our existing energy distribution system.

Subsequent to our February 2001 filing, the state legislature amended several laws, making changes which are critical to the implementation of Power the 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 us 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, we created We Power to design, construct, own, finance and lease the new generating capacity. Wisconsin Electric will lease each new facility from We Power as well as operate and maintain the new plants under 25 to 30-year lease agreements approved by the PSCW. Based upon the structure of the leases, we expect to recover the initial investments in We Power’s new facilities over the initial lease term. At the end of the leases, Wisconsin Electric will have the right to acquire the plants outright at market value or to renew the leases. Wisconsin Electric expects 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 our Power the Future strategy, we expect 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, we:

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.

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 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 We Power and Wisconsin Electric.

We expect to finance the majority of our Power the Future strategy with internally generated cash and debt financings. Additionally, in the future we expect to have some limited asset sales, but at levels significantly below the prior five year level. We expect to maintain our debt to total capital ratio at no more than 61.5% during the period we are constructing our new gas- and coal- fired generation plants. We currently do not plan to issue any new equity as part of our Power the Future financing plan.

A-5

Our primary risks under Power the Future are associated with successful, timely resolution of court challenges of our Elm Road facility, timely receipt of remaining permits for Elm Road, and construction risks associated with the schedule and costs for both our Elm Road and Port Washington generating stations.

For further information concerning Power the Future capital requirements, see “Liquidity and Capital Resources” below. 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.

Divestiture of Non-Core Assets

Our Power the Future strategy led to a decision to divest non-core businesses. These non-core businesses primarily included non-utility generation assets located outside of the Midwest and a substantial amount of Wispark’s real estate portfolio, as well as the manufacturing business. Since 2000, we have received total proceeds of approximately $1.97 billion from the divestiture of non-core assets as follows:


Proceeds from non-core divestitures:	(Millions of Dollars)
Non-Utility Energy	$	579.4
Transmission		119.8
Real Estate		387.6
Manufacturing		857.0
Other		26.2

Total	$	1,970.0

RESULTS OF OPERATIONS

CONSOLIDATED EARNINGS

The following table compares our operating income by business segment and our net income for 2004, 2003 and 2002.


Wisconsin Energy Corporation	2004			2003			2002
	(Millions of Dollars)
Utility Energy	$	528.6		$	544.1		$	562.1
Non-Utility Energy		(120.4	)		(61.5	)		(132.0	)
Corporate and Other		(28.4	)		(0.4	)		(29.7	)

Total Operating Income		379.8			482.2			400.4
Other Income, Net		16.1			42.2			43.7
Interest Expense		193.4			213.8			227.1

Income From Continuing Operations Before Income Taxes		202.5			310.6			217.0
Income Taxes		80.3			110.2			85.3

Income From Continuing Operations		122.2			200.4			131.7
Income From Discontinued Operations, Net of Tax (a)		184.2			43.9			35.3

Net Income	$	306.4		$	244.3		$	167.0

Diluted Earnings Per Share	$	2.57		$	2.06		$	1.44

(a)	Effective July 31, 2004, we sold our manufacturing business. We began reporting this business as a discontinued operation in the first quarter of 2004 and have restated prior year information.

A-6

2004 vs. 2003: Our diluted earnings per share were $2.57 during 2004 compared with $2.06 per share during 2003. During 2004, our diluted earnings per share were positively impacted by $1.28 per share due to the gain on the sale of our manufacturing business offset in part by non-cash, non-utility asset valuation charges of $0.81 per share, severance costs of $0.16 per share primarily in our utility energy segment, and debt redemption costs of $0.13 per share. During 2003, our diluted earnings per share were negatively impacted by non-cash, non-utility asset valuation charges of $0.32 per share partially offset by $0.07 of gain on the sale of non-utility investments.

2003 vs. 2002: Our diluted earnings per share of $2.06 during 2003 was $0.62 per share higher than the $1.44 per share earned during 2002. As noted above, our 2003 earnings were negatively impacted by non-cash, non-utility asset valuation charges of $0.32 per share partially offset by $0.07 of gain on non-utility investments. During 2002, our diluted earnings per share were negatively impacted by non-cash, non-utility asset valuation charges of $0.79 per share.

An analysis of contributions to operating income by segment follows.

UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

2004 vs. 2003: Our utility energy segment contributed $528.6 million of operating income during 2004 compared with $544.1 million of operating income during 2003. 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: Utility energy segment operating income during 2003 decreased by $18.0 million compared with 2002. The decline in utility operating income was primarily due to cooler summer weather, higher fuel and purchased power costs, increases in pension, medical and other benefit costs, higher nuclear costs and costs associated with our Power the Future growth strategy. This decline was somewhat mitigated by a March 2003 rate increase associated with fuel and purchased power expenses, higher gas margins, growth in our base electric business and litigation settlements in 2002 compared with the receipt of insurance recoveries in 2003, primarily related to the Giddings & Lewis/City of West Allis litigation.

The following table summarizes our utility energy segment’s operating income during 2004, 2003 and 2002.


Utility Energy Segment	2004		2003		2002
	(Millions of Dollars)
Operating Revenues
Electric	$	2,099.0	$	2,013.6	$	1,910.8
Gas		1,252.4		1,226.1		918.1
Other		24.0		24.2		23.2

Total Operating Revenues		3,375.4		3,263.9		2,852.1
Fuel and Purchased Power		591.7		569.5		496.8
Cost of Gas Sold		890.9		863.3		574.9

Gross Margin		1,892.8		1,831.1		1,780.4
Other Operating Expenses
Other Operation and Maintenance		963.0		891.0		830.2
Depreciation, Decommissioning and Amortization		315.5		316.2		308.3
Property and Revenue Taxes		85.7		79.8		79.8

Operating Income	$	528.6	$	544.1	$	562.1

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.

A-7


	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	$	731.3	$	715.5	$	703.0	8,053.9	8,099.3	8,310.9
Small Commercial/Industrial		668.0		642.0		606.3	8,840.4	8,740.6	8,719.5
Large Commercial/Industrial		549.9		519.3		483.1	11,686.4	11,401.8	11,129.6
Other-Retail/Municipal		90.7		84.9		77.7	2,405.5	2,225.9	2,051.9
Resale-Utilities		24.6		24.0		18.1	662.2	715.8	650.7
Other Operating Revenues		34.5		27.9		22.6	—	—	—

Total Electric Operating Revenues		2,099.0		2,013.6		1,910.8	31,648.4	31,183.4	30,862.6

Fuel and Purchased Power
Fuel		334.7		298.5		278.9
Purchased Power		250.3		264.3		211.1

Total Fuel and Purchased Power		585.0		562.8		490.0

Total Electric Gross Margin	$	1,514.0	$	1,450.8	$	1,420.8

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 twenty-year moving average.

Electric Utility Revenues and Sales

2004 vs. 2003: During 2004, our total electric utility operating revenues increased by $85.4 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, Wisconsin Electric received an order from the PSCW authorizing an annualized increase in electric rates of approximately $59.5 million to cover construction costs associated with our Power the Future program 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 465.0 thousand megawatt-hours or 1.5% between 2004 and 2003. Residential sales were down 0.6%, and small commercial/industrial sales were up just 1.1% 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 1.5%. Sales to municipal utilities, the other retail/municipal customer class, increased 8.1% 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 $102.8 million or 5.4% when compared with 2002, primarily due to the impact of rate increases related to fuel and purchased power costs and to a surcharge related to transmission costs. The total rate impact was approximately $83.3 million in 2003. In March 2003, Wisconsin Electric received an interim increase in rates of $55.1 million annually to recover increases in fuel and purchased power costs. In October 2003, we received the final rate order, which authorized an additional $6.1 million of annual revenues. In spite of the interim fuel order, we under recovered fuel costs by approximately $7.6 million during 2003, which is approximately $5.3 million worse than our under recovery during 2002. Much of

A-8

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 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 1.0% during 2003. Residential sales fell 2.5% due to the impact of unfavorable weather conditions on cooling load during the second and third quarters of 2003. Sales to Wisconsin Electric’s largest customers, two iron ore mines, increased by 238.4 thousand megawatt-hours or 12.1% between the comparative periods despite temporary curtailments of electric sales in the second and fourth quarters of 2003 resulting from a flood-related outage at our Presque Isle Power Plant and a transmission outage. During the first and third quarters of 2002, the mines had extended outages. Excluding these two mines, our total electric energy sales increased by 0.3% between the comparative periods, and sales volumes to the remaining large commercial/industrial customers improved by 0.4%. Sales to municipal utilities, the other retail/municipal customer class, increased 8.5% 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 utilities increased by $22.2 million or 3.9% 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 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 $72.8 million or 14.9% due in large part to increases in fuel prices, especially for natural gas, the primary fuel source for our purchased power, resulting in a 14% increase in the cost per megawatt hour of purchased power. Average commodity gas market prices were $5.39 for 2003 compared to $3.22 for 2002 on a per dekatherm basis. Fuel and purchased power costs also increased due to higher purchased capacity costs and a higher need for purchased energy in 2003 compared with the same period in 2002. Approximately $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	$	1,252.4	$	1,226.1	$	918.1
Cost of Gas Sold		890.9		863.3		574.9

Gross Margin	$	361.5	$	362.8	$	343.2

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.

A-9


	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	$	238.0	$	233.0	$	224.6	809.9	853.7	817.1
Commercial/Industrial		71.9		71.0		67.4	464.0	492.5	463.1
Interruptible		1.8		2.0		2.1	24.7	27.5	29.4

Total Gas Sold		311.7		306.0		294.1	1,298.6	1,373.7	1,309.6
Transported Gas		43.8		41.8		41.9	769.5	797.5	811.7
Other Operating		6.0		15.0		7.2	—	—	—

Total	$	361.5	$	362.8	$	343.2	2,068.1	2,171.2	2,121.3

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 slightly from $362.8 million in 2003 to $361.5 million in 2004 due largely to a decrease in therm deliveries resulting from less favorable weather. Total therm deliveries were 4.7% 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 $12.9 million between the comparative periods. Our gas margins were favorably impacted by a price increase that became effective in February 2004. This annual price increase of $25.9 million favorably impacted gas margins by $19.6 million in 2004. However, in 2004, we recognized $8.8 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 $19.6 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 $7.4 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 increased by 2.4% during 2003 but varied within customer classes. Volume deliveries for the residential and commercial/industrial customer classes increased by 4.5% and 6.3%, respectively, reflecting the colder weather.

Other Operation and Maintenance Expenses

2004 vs. 2003: Other operation and maintenance expenses increased by $72.0 million or 8.1% 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 our Power the Future plan. Under the lease agreement, Wisconsin Electric is 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 $12.8 million of increased public benefits costs which were also included in the May 2004 price increase.

In addition, our benefit costs increased $15.0 million due to increased pension and medical costs. We also incurred $28.2 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 an $11.9 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 $60.8 million or 7.3% 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

A-10

approximately $30 million during 2003. Overall, nuclear costs were $8.7 million higher during 2003 compared with 2002 due to an extended outage and costs associated with supplemental inspections at Point Beach by the U.S. Nuclear Regulatory Commission (NRC). Insurance recoveries of approximately $11.1 million in 2003 compared to associated settlement costs of $17.3 million in 2002, both primarily related to the Giddings & Lewis/City of West Allis litigation, offset some of the increase in other operation and maintenance expenses. We spent approximately $7.2 million more in 2003 than in 2002 on the implementation of our Power the Future strategy.

NON-UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

As part of our ongoing efforts to divest non-core assets, we have significantly reduced Wisvest’s operations since 2002. The following table compares our non-utility energy segment’s operating loss during 2004, 2003 and 2002.


Non-Utility Energy Segment	2004			2003			2002
	(Millions of Dollars)
Operating Revenues	$	21.6		$	14.4		$	167.2
Fuel and Purchased Power		1.2			1.3			97.3

Gross Margin		20.4			13.1			69.9
Other Operating Expenses
Other Operation and Maintenance		11.6			16.6			64.9
Depreciation, Decommissioning and Amortization		6.1			7.4			5.1
Property and Revenue Taxes		1.1			1.6			6.8
Asset Valuation Charges, Net		122.0			49.0			125.1

Operating Income (Loss)	($	120.4	)	($	61.5	)	($	132.0	)

2004 vs. 2003: Our non-utility energy operating losses increased from $61.5 million during 2003 to $120.4 million during 2004, primarily because of a non-cash asset valuation charge of $122.0 million in the third quarter of 2004 associated with our Calumet Energy facility. During 2003, we recorded $59.5 million of non-cash asset valuation charges related to our investment in an entity that owns a co-generation plant in Maine (Androscoggin) and to a natural gas power island which we sold in the fourth quarter of 2003. In 2003, we also realized gains on the sale of non-utility energy assets of $10.5 million.

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

The operating loss incurred in 2003 included total asset valuation charges of $59.5 million offset in part by gains on the sale of assets of $10.5 million. The asset valuation charges recorded in 2003 relate to our investment in Androscoggin and to costs associated with a 500-megawatt natural gas power island. In 2002 we recorded a non-cash asset valuation charge of which $125.1 million related to the non-utility energy segment.

CORPORATE AND OTHER CONTRIBUTION TO OPERATING INCOME

The following table identifies the components of operating loss attributable to our corporate operations and to other affiliates during 2004, 2003 and 2002.

A-11


Corporate and Other Affiliates	2004			2003			2002
	(Millions of Dollars)
Operating Revenues	$	34.1		$	30.0		$	31.7
Other Operating Expenses
Other Operation and Maintenance		28.1			26.6			38.7
Depreciation, Decommissioning and Amortization		5.5			6.2			5.1
Property and Revenue Taxes		0.5			1.0			1.2
Asset (Gain) Valuation Charges, Net		28.4			(3.4	)		16.4

Operating Income (Loss)	($	28.4	)		($0.4	)	($	29.7	)

2004 vs. 2003: We had net corporate and other affiliate operating losses of $28.4 million during 2004 compared with net operating losses of $0.4 million in 2003. The change reflects a non-cash valuation charge of $27.0 million in the third quarter of 2004 related to our Minergy-Neenah facility.

2003 vs. 2002: We realized net operating losses of $0.4 million in 2003 from corporate and other affiliate operations compared to a net operating loss of $29.7 million in 2002. This change primarily reflects a $2.7 million gain from the sale of investment assets in the third quarter of 2003 and a non-cash asset valuation charge of $16.4 million recorded in 2002 related to the decline in value of a venture capital investment.

CONSOLIDATED OTHER INCOME AND DEDUCTIONS, NET

2004 vs. 2003: Net consolidated other income and deductions decreased by $26.1 million in 2004 compared to 2003, primarily due to $22.9 million of debt redemption costs incurred during 2004. In connection with the sale of our manufacturing business, we used most of the proceeds to retire short and long-term debt. These increased costs were partially offset by an $8.7 million increase in our interest in the earnings of unconsolidated affiliates during 2004.

2003 vs. 2002: Net consolidated other income and deductions decreased by $1.5 million in 2003 compared to 2002. This decrease is primarily due to $21.1 million ($12.7 million after tax) in Statement of Financial Accounting Standard (SFAS) 133 gains recognized in 2002 on fuel oil contracts at Wisvest-Connecticut’s two power plants which were sold in December 2002, a $3.2 million civil penalty we agreed to pay in 2003 pursuant to the terms of a consent decree with the U.S. Environmental Protection Agency (EPA) and higher returns associated with investments in rabbi trusts.

CONSOLIDATED INTEREST EXPENSE

2004 vs. 2003: Total interest expense decreased by $20.4 million in 2004 compared with 2003. This decrease primarily reflects the reduction in debt levels due to the retirement of debt with the proceeds from the sale of our manufacturing business, which was effective July 31, 2004. From December 31, 2003 to December 31, 2004, we reduced our debt levels by $654.2 million or 15%.

2003 vs. 2002: Total interest expense decreased by $13.3 million in 2003 compared to 2002. This decline was due to a combination of reduced average debt levels, increased capitalized interest and lower interest rates.

CONSOLIDATED INCOME TAXES

2004 vs. 2003: In 2004, our effective income tax rate from continuing operations was 39.6% compared with a 35.5% rate during 2003. The increase in the effective income tax rate is due primarily to the inability to receive a state tax benefit from the $150.4 million of asset valuation charges which were recorded in 2004.

2003 vs. 2002: Our effective tax rate applicable to continuing operations was 35.5% compared with a 39.3% rate during 2002. This decrease was primarily related to the inability to deduct state income taxes on losses of certain non-utility subsidiaries. In 2002, we had $141.5 million of asset impairment charges which did not receive a state tax benefit as compared with $45.6 million of net impairment charges in 2003.

A-12

DISCONTINUED OPERATIONS

In 2004, we showed our manufacturing business as a discontinued operation, and it was sold effective July 31, 2004. All prior years have been restated to show the manufacturing business as a discontinued operation. During 2004, this business earned $31.9 million of net income from operations for the seven months that we owned this business. This compares with net income of $43.9 million and $35.3 million for twelve months of operations during 2003 and 2002, respectively. In 2004, we recorded a gain of $152.3 million on the sale of the manufacturing business.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

The following table summarizes our cash flows during 2004, 2003 and 2002:


Wisconsin Energy Corporation	2004			2003			2002
	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$	598.7		$	529.9		$	660.9
Investing Activities	$	243.1		($	596.2	)	($	382.5	)
Financing Activities	($	834.3	)	$	59.4		($	282.3	)

Operating Activities

Cash provided by operating activities increased to $598.7 million during 2004 compared with $529.9 million during the same period in 2003. This increase was due in large part to stronger cash earnings (net earnings plus non-cash valuation charges) as well as improvements in working capital.

Cash provided by operating activities decreased to $529.9 million during 2003 compared with $660.9 million during the same period in 2002. This decrease was primarily due to a $116 million refund received in the first quarter of 2002 from a favorable court ruling in the Giddings & Lewis/City of West Allis litigation and an increase in the use of working capital in 2003.

Investing Activities

During 2004, we had $243.1 million of net cash inflows from investing activities. In 2003 and 2002, we had net cash outflows from investing activities of $596.2 million and $382.5 million, respectively. The most significant investing activities relate to the sale of assets, particularly the sale of the manufacturing business, and capital expenditures. In connection with our growth strategy which was announced in 2000, we have been focusing on divesting non-core assets and investing in core regulated assets.

The following table identifies capital expenditure by year:


Capital Expenditures	2004		2003		2002
	(Millions of Dollars)
Regulated Energy	$	426.5	$	455.6	$	405.4
We Power		190.4		162.9		52.9
Other Non-Utility Energy		0.6		0.7		39.8
Other		19.3		29.8		43.7

Total Capital Expenditures	$	636.8	$	649.0	$	541.8

The increase in capital expenditures at We Power reflects the increased construction activity related to the first unit at Port Washington which is expected to be in service early in the third quarter of 2005. In addition, during 2004 we

A-13

incurred expenditures for the second unit at Port Washington, as well as limited expenditures associated with the Elm Road coal units.

The following table identifies cash proceeds from asset sales:


Asset Sales	2004		2003		2002
	(Millions of Dollars)
Manufacturing	$	857.0	$	—	$	—
Power Island		—		25.0		—
Wisvest Connecticut		—		—		220.2
Other		42.6		30.3		89.8

Total Asset Sales	$	899.6	$	55.3	$	310.0

A significant amount of the net proceeds from asset sales was used to retire debt.

Financing Activities

The following table summarizes our cash flows from financing activities:


	2004			2003			2002
	(Millions of Dollars)
Increase (Reduce) Debt	($	654.2	)	$	120.7		($	190.2	)
Dividends on Stock		(97.8	)		(93.7	)		(92.4	)
Common Stock, net		(81.8	)		56.1			0.3
Other		(0.5	)		(23.7	)		—

Cash Provided by (Used in ) Financing	($	834.3	)	$	59.4		($	282.3	)

During 2004, the proceeds from asset sales as well as improved cash flows from operations allowed us to retire $654.2 million of debt, including $200 million of 6.85% Trust Preferred Securities and $300 million of 5.875% senior notes due April 1, 2006. For further information regarding our long-term debt issuances, redemptions and refinancings, see “Note J — Long-Term Debt” in the Notes to Consolidated Financial Statements.

In September 2000, the Board of Directors amended the common stock repurchase program to authorize us to purchase up to $400 million of our shares of common stock in the open market. In March 2004, we announced that under this plan we would resume purchasing approximately $50 million of our common shares in the open market with the proceeds from the sale of the manufacturing business, which was effective July 31, 2004. During 2004, we purchased approximately 1.6 million shares of common stock for $50.4 million under this plan. We ceased repurchasing shares in October 2004. The program expired in December 2004. Over the life of the plan we repurchased and retired 14.9 million shares at a cost of $344.0 million.

During January and February 2004, we issued approximately 0.2 million new shares of common stock in connection with our dividend reinvestment plan and various employee benefit plans. In 2003 and 2002, we issued approximately 2.7 million new shares of common stock in each of those years in connection with these plans. In 2004, 2003 and 2002, we received payments aggregating $4.8 million, $62.9 million and $52.6 million, respectively. In February 2004, we announced that we did not expect to issue new shares under these programs; rather we instructed the plan agents to begin purchasing the shares in the open market in lieu of issuing new shares. During 2004, our plan agents purchased 3.2 million shares at a cost of $102.3 million to fulfill exercised stock options. In 2004, we received proceeds of $66.1 million related to the exercise of stock options. Prior to February 2004, we issued new shares to fulfill these obligations.

A-14

CAPITAL RESOURCES AND REQUIREMENTS

In 2000, we announced a growth strategy which, among other things, called for us to sell non-core assets. The proceeds from these asset sales were used to retire debt and help fund capital expenditures in our other businesses. During the five years ended December 31, 2004, we received $1.97 billion in proceeds from asset sales. Since announcing the growth strategy in September 2000, our debt to total capital ratio has decreased from 68.3% at September 30, 2000 to 59.3% at December 31, 2004. Over the next several years, we expect to have some limited asset sales, but at levels significantly below the prior five year level.

In 2002, we initiated the construction of the first of our four planned power plants under our Power the Future program. We expect to spend over $2.8 billion if all four plants are approved. We expect that two unaffiliated entities will collectively invest approximately $330 million in the Power the Future coal units and receive an ownership interest of approximately 17% in the units or 200 megawatts. If the two unaffiliated entities choose to participate in the coal units, our net investment would be approximately $2.5 billion. Over the next several years, we expect to fund these plants with cash from operations and debt offerings.

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 and construction financing.

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

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, Wisconsin Electric 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 Wisconsin Electric 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 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.

Wisconsin Energy, Wisconsin Electric and Wisconsin Gas credit agreements provide liquidity support for each company’s obligations with respect to commercial paper.

As of December 31, 2004, we had approximately $1.2 billion of available unused lines of bank back-up credit facilities on a consolidated basis and approximately $338 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:


Company	Total Facility		Letters of Credit		Credit Available		Facility Maturity	Facility Term
	(Millions of Dollars)
Wisconsin Energy	$	300.0	$	—	$	300.0	June-2007	3 year
Wisconsin Energy	$	300.0	$	3.7	$	296.3	Apr-2006	3 year
Wisconsin Electric	$	250.0	$	3.0	$	247.0	June-2007	3 year
Wisconsin Electric	$	125.0	$	—	$	125.0	Nov-2007	3 year
Wisconsin Gas	$	200.0	$	—	$	200.0	June-2007	3 year

A-15

On June 23, 2004, Wisconsin Energy entered into an unsecured three year $300 million bank back-up credit facility to replace a $300 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 June 23, 2004, Wisconsin Electric entered into an unsecured three year $250 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 June 23, 2004, Wisconsin Gas entered into an unsecured three year $200 million bank back-up credit facility to replace a $200 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, Wisconsin Electric entered into an unsecured three year $125 million bank back-up credit facility to replace a $100 million 11-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(a)
			(Millions of Dollars)
Common Equity	$	2,492.4	40.2	%	$	2,358.7	35.1	%
Preferred Stock of Subsidiaries		30.4	0.5	%		30.4	0.5	%
Long-Term Debt (including current maturities)		3,340.5	53.9	%		3,736.7	55.6	%
Short-Term Debt		338.0	5.4	%		590.8	8.8	%

Total	$	6,201.3	100.0	%	$	6,716.6	100.0	%

Ratio of Debt to Total Capital			59.3	%			64.4	%

(a)	Excludes debt classified as Liabilities held for sale on our Consolidated Condensed Balance Sheets as of December 31, 2003.

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

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


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

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

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

Wisconsin Energy Capital Corporation
Unsecured Debt	BBB+	A3	A-

A-16

The security rating outlooks assigned by S&P, Moody’s and Fitch for Wisconsin Energy, Wisconsin Electric, Wisconsin Gas and Wisconsin Energy Capital Corporation are all stable.

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

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

In October 2003, Fitch downgraded certain of our security ratings and the security ratings of our subsidiaries. Fitch lowered the senior unsecured debt ratings of Wisconsin Energy and Wisconsin Energy Capital Corporation from A to A- and the commercial paper rating of Wisconsin Energy from F1 to F2. Fitch lowered Wisconsin Electric’s senior secured debt rating from AA to AA-, senior unsecured rating from AA- to A+ and preferred stock rating from AA- to A. Fitch lowered Wisconsin Gas’ senior unsecured debt rating from AA- to A+. Fitch lowered the commercial paper ratings of Wisconsin Electric and Wisconsin Gas from F1+ to F1. The rating outlook for Wisconsin Energy, Wisconsin Electric, Wisconsin Gas and Wisconsin Energy Capital Corporation is stable.

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

Capital Requirements

Total capital expenditures, excluding the purchase of nuclear fuel, are currently estimated to be $823.7 million during 2005 attributable to the following operating segments:


	Estimated		Actual
Capital Expenditures	2005		2004
	(Millions of Dollars)
Utility Energy	$	500.0	$	426.5
Non-Utility Energy		317.0		191.0
Other		6.7		19.3

Total	$	823.7	$	636.8

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

A-17

Our estimated capital requirements through 2010 for Power the Future include a net of approximately $2.5 billion to construct 2,120 megawatts of new natural gas-fired and coal-fired generating capacity of which we have expended approximately $414.9 million through the end of 2004. We expect that two unaffiliated entities will collectively invest approximately $330 million in the Power the Future coal units and receive an ownership interest of approximately 17% in the units or 200 megawatts. Total cost of all four units, including the two unaffiliated entities’ portion, is estimated to be $2.8 billion with total output at 2,320 megawatts.

We expect the capital requirements to support our investment in new generation under Power the Future to come from a combination of internal and external sources. The new generating plants will be constructed by We Power, a non-utility subsidiary, and leased to Wisconsin Electric under 25-30 year lease agreements. We expect that Wisconsin Electric will recover the lease payments in its utility rates. We anticipate that we will need external debt financing as the plants are constructed. We believe that the construction debt, cash flows from the lease payments and strong internal cash flow will be sufficient to fund our Power the Future capital expenditures.

Investments in Outside Trusts: We have funded our pension obligations, certain other post-retirement obligations and future nuclear obligations in outside trusts. Collectively, these trusts had investments that exceeded $1.9 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 O — 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 construction projects, commodity contracts and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors. For further information, see “Note P — 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.

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


	Payments Due by Period
Contractual Obligations (a)	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
					(Millions of Dollars)
Long-Term Debt Obligations (b)	$	5,629.0	$	215.0	$	1,015.5	$	642.7	$	3,755.8
Capital Lease Obligations (c)		586.8		54.1		88.7		75.0		369.0
Operating Lease Obligations (d)		270.4		50.4		99.3		54.6		66.1
Purchase Obligations (e)		987.4		341.7		332.2		121.4		192.1
Other Long-Term Liabilities		1.9		1.0		0.9		—		—

Total Contractual Obligations	$	7,475.5	$	662.2	$	1,536.6	$	893.7	$	4,383.0

A-18

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

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

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

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

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

Obligations for utility operations by our utility affiliates have historically been included as part of the rate making process and therefore are generally recoverable from customers.

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 the Port Washington Generating Station (Port Washington units) consisting of two 545-megawatt natural gas-fired combined cycle generating units on the site of Wisconsin Electric’s existing Port Washington Power Plant. The order approves key financial terms of the leased generation contracts including fixed construction cost of the two Port Washington units at $309.6 million and $280.3 million (2001 dollars), respectively, subject to escalation at the GDP inflation rate and force majeure and excused events provisions.

In addition, in November 2003, the PSCW issued a written order granting a CPCN to commence construction of two 615-megawatt super critical pulverized coal generating units (Elm Road units) on the site of Wisconsin Electric’s existing Oak Creek Power Plant. The order approves key financial terms of the leased generation contracts including fixed construction cost of the two Elm Road units. 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 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. If final costs for the construction of the Port Washington units or the Elm Road units exceed the fixed costs allowed in the PSCW order, this excess cannot be recovered from Wisconsin Electric or its customers unless specifically allowed by the PSCW. Project costs above the authorized amount, but below the 5% cap will be subject to a prudence determination by the PSCW.

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

As noted below in Commodity Price Risk, the electric operations of Wisconsin Electric operate under a fuel cost adjustment clause in the Wisconsin retail jurisdiction for fuel and purchased power costs associated with the generation and delivery of electricity. This clause establishes a fuel base for fuel and purchased power costs, and Wisconsin Electric assumes the risks and benefits of fuel cost variances that are within 3% of the fuel base. Wisconsin Electric is 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

A-19

authorizing new fuel cost adjustment rules to be implemented in the Wisconsin retail jurisdiction. The new rules will not be effective for Wisconsin Electric until January 2006, the end of a five year rate freeze associated with the WICOR Merger Order. Until this time, Wisconsin Electric will operate under an approved transaction mechanism similar to the old fuel cost adjustment procedure. For 2004, 2003 and 2002, actual fuel and purchased power costs at Wisconsin Electric exceeded fuel base rates by $0.8 million, $7.6 million and $2.3 million, respectively. In 2004, 2003 and 2002, the electric rates included a fuel surcharge.

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

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

The PSCW has authorized dollar for dollar recovery for the majority of natural gas costs for the gas utility operations of Wisconsin Electric and Wisconsin Gas through gas cost recovery mechanisms, which mitigates most of the risk of gas cost variations. For additional information concerning the electric utility fuel cost adjustment procedure and the natural gas utilities’ gas cost recovery mechanisms, see “Utility 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 has increased.

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

Weather: The rates of Wisconsin Electric and Wisconsin Gas are set by the PSCW based upon estimated temperatures which approximate 20-year averages. Wisconsin Electric’s electric revenues are unfavorably sensitive to below normal temperatures during the summer cooling season, and to some extent, to above normal temperatures during the winter heating season. The gas revenues of Wisconsin Electric and Wisconsin Gas are unfavorably sensitive to above normal temperatures during the winter heating season. A summary of actual weather information in the utility segment’s service territory during 2004, 2003 and 2002, as measured by degree-days, may be found above in “Results of Operations”.

Temperature can also impact demand for electricity in regions where we have invested in non-utility energy assets or projects.

A-20

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 $338.0 million short-term debt with a weighted average interest rate of 2.35% and $187.5 million of variable-rate long-term debt with a weighted average interest rate of 1.88%. A one-percentage point change in interest rates would cause our annual interest expense to increase or decrease by approximately $3.4 million before taxes from short-term borrowings and $1.9 million before taxes from variable rate long-term debt outstanding.

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

At December 31, 2004, we held the following total trust fund assets at fair value, primarily consisting of publicly traded debt and equity security investments.


Wisconsin Energy Corporation	Millions of Dollars
Pension trust funds	$	998.5
Nuclear decommissioning trust funds	$	737.8
Other post-retirement benefits trust funds	$	183.6

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.

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

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, in the event of a credit ratings change to below investment grade, a termination payment 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 $118.7 million.

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

A-21

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 our 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 by We Power to Wisconsin Electric under long-term leases, and we expect Wisconsin Electric to recover the lease payments in its electric rates.

Power the Future - Port Washington

Background: In December 2002, the PSCW issued a written order (the Port Order) granting Wisconsin Energy, Wisconsin Electric and We Power a CPCN to commence construction of the Port Washington Generating Station consisting of two 545-megawatt natural gas-fired combined cycle generating units (Port Units 1 and 2) on the site of Wisconsin Electric’s existing Port Washington Power Plant. The Port Order also authorized Wisconsin Gas to proceed with the construction of a connecting natural gas lateral and American Transmission Company LLC (ATC) to construct required transmission system upgrades to serve Port Units 1 and 2 as a result of their concurrent applications. In January 2003, Wisconsin Electric commenced demolition of two of its existing coal-fired units on the site to make room for the new units. In July 2003, We Power began construction of Unit 1, and we expect the unit to be operational early in the third quarter of 2005. In October 2003, we received approval from the Federal Energy Regulatory Commission (FERC) to transfer by long-term lease certain associated FERC jurisdictional assets from We Power to Wisconsin Electric. In May 2004, we 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 Wisconsin Electric will staff, operate and maintain Port Units 1 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 $280.3 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, Wisconsin Electric filed a request with the PSCW to defer costs for recovery in future rates. The PSCW approved the request in an open meeting in April 2003. (See “Limited Rate Adjustment Request” below for further information.) We Power began collecting certain costs from Wisconsin Electric in the third quarter of 2003 as provided for in lease generation contracts that were signed in May 2003. We defer the lease costs on our balance sheet, and we amortize the costs to expense as we recover the costs in rates.

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.

A-22

The construction of Port Units 1 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 1 and 2, we needed the approval from the Wisconsin Department of Natural Resources (WDNR) for the construction of a natural gas lateral which will deliver fuel to the Units. After several discussions with the WDNR, we agreed to modify the planned route and mitigate certain environmental impacts. In July 2003, we received approval for construction for the natural gas lateral and the lateral was completed in December 2004.

Power the Future - Elm Road:

Background: In November 2003, the PSCW issued an order (the Elm Road Order) granting Wisconsin Energy, Wisconsin Electric, and We Power a CPCN to commence construction of two 615-megawatt coal-fired units (the Elm Road units) to be located near the site of Wisconsin Electric’s 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 permits. In April 2004, we entered into a contract with Bechtel to secure necessary engineering, design and construction services and major equipment components for these units. We expect that we 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 Wisconsin Electric and We Power for the Elm Road units. Key terms of the leased generation contracts include:

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

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

Ø	Recovery of carrying costs during construction; and

Ø	Ongoing PSCW supervisory authority over those lease terms 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 us 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 our application and in its decisions on several other points.

We, 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 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.

A-23

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.

We have 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, we have 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 Wisconsin Electric 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 our 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. We are 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 our 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.

UTILITY RATES AND REGULATORY MATTERS

The PSCW regulates our retail electric, natural gas, steam and water rates in the state of Wisconsin, while the FERC regulates wholesale power, electric transmission and interstate gas transportation service rates. The Michigan Public Service Commission (MPSC) regulates retail electric rates in the state of Michigan. Within our regulated segment, we estimate that approximately 87% of our electric revenues are regulated by the PSCW, 8% are regulated by the MPSC and the balance of our electric revenues are regulated by the FERC. All of our natural gas 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 www.michigan.gov/mpsc/.

Overview: In the state of Wisconsin, We Energies, (the trade name of Wisconsin Electric and Wisconsin Gas) rates are governed by an order from the PSCW issued in March 2000 in connection with the approval of the WICOR acquisition. Under this order, We Energies is 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:

A-24

Ø	Governmental mandates;

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

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

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.

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


Service – Wisconsin Electric	Incremental Annualized Revenue Increase		Percent Change in Rates		Effective Date
	(Millions)		(%)
Fuel electric, Michigan	$	3.4	8.0	%	January 1, 2005
Fuel electric, Michigan	$	1.3	3.1	%	October 1, 2004
Retail steam, Wisconsin	$	0.5	3.4	%	May 5, 2004
Retail electric, Wisconsin (a)	$	59.0	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 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 $55.1 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 $48.1 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 $3.2 million for Wisconsin Electric. In addition, the September 2002 order issued by the MPSC authorized us to include the transmission costs from ATC prospectively in its Power Supply Cost Recovery clause.

Wisconsin Gas: As discussed above, Wisconsin Gas is also under the five year rate restriction period which ends December 31, 2005. In March 2004, the PSCW approved an annual rate increase of $25.9 million related to increased costs associated with the construction of the Ixonia lateral and for increased costs associated with low-income energy assistance.

Limited Rate Adjustment Requests

2005 Revenue Deficiencies: In May 2004, Wisconsin Electric 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 our Power the

A-25

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 $84.8 million (4.5%) for the electric operations of Wisconsin Electric, and $0.5 million (3.6%) for Wisconsin Electric’s steam operations. In January 2005, as a result of the litigation involving our 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, Wisconsin Electric 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, Wisconsin Electric 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: Wisconsin Electric divested of its transmission assets with the formation of the ATC in January 2001. In connection with the formation of the ATC, our transmission costs have escalated due to the socialization of costs within the 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 and we expect to begin to recover these costs beginning in 2006.

Fuel Cost Adjustment Procedure: Within the state of Wisconsin, Wisconsin Electric operates under a fuel cost adjustment clause for fuel and purchased power costs associated with the generation and delivery of electricity and purchase power contracts. 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.

Edison Sault and our Wisconsin Electric operations in Michigan operate 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. During 2004, $0.2 million of additional revenues were earned under the incentive portion of the GCRM and $9.0 million and $1.6 million of additional revenues were earned in 2003 and 2002 under the GCRM.

Bad Debt Costs: Prior to October 2002, Wisconsin Gas expensed amounts included in rates for bad debt expense. If actual bad debt costs exceeded amounts allowed in rates, these amounts were deferred as a regulatory asset. Effective October 2002, the PSCW issued an order which eliminated escrow accounting for bad debts. The escrow amount accumulated at September 30, 2002 of approximately $6.9 million is expected to be collected in future rates, but future bad debt expense at Wisconsin Gas will no longer be subject to this separate true-up mechanism.

In 2003 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 a letter from the PSCW which allowed Wisconsin Electric and Wisconsin Gas 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 $21.2 million and $15.6 million in 2004 and 2003 related to bad debt costs.

A-26

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.

Midwest Independent Transmission System Operator, Inc. (Midwest 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.

Nuclear Refueling 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 $15.0 million. We anticipate receiving a decision related to this request in the first quarter of 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 our Power the Future strategy. We are taking some immediate steps to reduce the likelihood of outages by upgrading substations and rebuilding lines to upgrade voltages and reliability. These improvements, along with better technology for analysis of our existing system, better resource management to speed restoration and improved customer communication, are near-term efforts to enhance our current electric distribution infrastructure. In the long-term, we are initiating a new asset management strategy that is expected to consistently provide the level of reliability needed for a digital economy, using new 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 our Power the Future strategy is subject to a number of state and federal regulatory approvals. For additional information, see “Power the Future” above.

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

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

A-27

Wisconsin Electric expects to have adequate capacity to meet all of its firm load obligations during 2005. However, extremely hot weather, unexpected equipment failure or unavailability could require Wisconsin Electric to call upon load management procedures during 2005 as it has 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 and non-utility energy segments include but are not limited to (1) air emissions such as carbon dioxide (CO₂), sulfur dioxide (SO₂), nitrogen oxide (NO_x), small particulates and mercury, (2) disposal of combustion by-products such as fly ash, (3) remediation of former manufactured gas plant sites, (4) disposal of used nuclear fuel, and (5) the eventual decommissioning of nuclear power plants.

We are currently pursuing a proactive strategy to manage our environmental issues including (1) substituting new and cleaner generating facilities for older facilities as part of our Power the Future strategy, (2) developing additional sources of renewable electric energy supply, (3) participating in regional initiatives to reduce the emissions of NO_x from our fossil fuel-based generating facilities, (4) entering into agreements with the WDNR and EPA to reduce emissions of SO₂ and NO_x by more than 65% and mercury by 50% within 10 years from Wisconsin Electric’s coal-fired power plants in Wisconsin and Michigan, (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 10 years ending 2013. For further information concerning the consent decree, see “Note S — Commitments and Contingencies” in the Notes to Consolidated Financial Statements in this report. For further information concerning disposal of used nuclear fuel and nuclear power plant decommissioning, see “Nuclear Operations” below and “Note H — Nuclear Operations” in the Notes to Consolidated Financial Statements in this report, respectively.

National Ambient Air Quality Standards: In 2004, EPA began implementing the National Ambient Air Quality Standards (NAAQS) for 8-hour ozone and fine particulate matter (PM _2.5 ) by designating nonattainment areas in the country. The states are currently developing rules to implement the new standards. Although specific emission control requirements are not yet defined, Wisconsin Electric believes that the revised standards will likely require significant reductions in SO₂ and NO_x emissions from coal-fired generating facilities. Wisconsin Electric expects that reductions needed to achieve compliance with the 8-hour ozone attainment standard will be implemented in stages from 2007 through 2010, beginning with the 1-hour ozone reductions. 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. Wisconsin Electric is 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-Attainment Standards: The 1-hour ozone nonattainment rules currently being implemented by the state of Wisconsin and ozone transport rules implemented by the state of Michigan limit NO_x emissions in phases over the next five years.

Wisconsin Electric currently expects to incur total annual operation and maintenance costs of $1-2 million during the period 2004 through 2007 to comply with the Michigan and Wisconsin rules. In January 2000, the PSCW approved Wisconsin Electric’s comprehensive plan to meet the Wisconsin regulations, permitting recovery in rates of NO_x emission reduction costs over an accelerated 10-year recovery period.

In April 2004, the EPA designated 10 counties in Southeastern Wisconsin as nonattainment 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. Wisconsin Electric believes that compliance with the NO_x 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 PM _2.5 nonattainment 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 SO₂ and NO_x. The proposed rules would require NO_x and SO₂ emission

A-28

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. Wisconsin Electric believes that compliance with the NO_x and SO₂ emission reductions requirements under the agreements with the WDNR and EPA will substantially mitigate costs to comply with the CAIR rule.

Mercury Emission Control Rulemaking: As required by the 1990 amendments to the Federal Clean Air Act, the EPA issued a regulatory determination in December 2000 that utility mercury emissions should be regulated. The EPA issued draft rules in December 2003 and 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 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.

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

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

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

LEGAL MATTERS

Presque Isle Flood: During the second quarter of 2003, our Presque Isle Power Plant was temporarily shut down due to the failure of a hydroelectric reservoir dike which flooded Marquette, Michigan. We estimate that our fuel and purchased power costs increased by approximately $8 million due to the need for replacement power during the plant outage. These increased costs were included as part of the fuel surcharge request discussed above. In addition, we incurred approximately $13.5 million in damage to equipment and property. We are pursuing recovery from insurance carriers and other parties for the above costs. 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 Wisconsin Electric 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 its 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 a jury verdict against Wisconsin Electric in a stray voltage lawsuit and held that even though a utility company’s

A-29

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 a jury 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 Wisconsin Electric with respect to stray voltage and ground currents are not expected to have a material adverse effect on its financial statements, we continue to evaluate various options and strategies to mitigate this risk.

NUCLEAR OPERATIONS

Point Beach Nuclear Plant: Wisconsin Electric owns two 518-megawatt electric generating units (Unit 1 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 of the Company and affiliates of other unaffiliated utilities. During 2004, 2003 and 2002, Point Beach provided approximately 25% of Wisconsin Electric’s net electric energy supply.

Each Unit at the Plant has a scheduled refueling outage approximately every 18 months. In 2004, Unit 1 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 1 is scheduled to have a refueling outage over the third and fourth quarters. During the 2005 scheduled refueling outages we 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 outages 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 1 and in March 2013 for Unit 2. In February 2004, NMC and Wisconsin Electric 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 7 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.

A-30

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

Temporary storage alternatives at Point Beach are necessary until the United States Department of Energy takes ownership of and permanently removes the used fuel as mandated by the Nuclear Waste Policy Act of 1982, as amended in 1987. The 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 Wisconsin Electric has 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, Wisconsin Electric filed a complaint on November 16, 2000 against the Department of Energy in the Court of Federal Claims. The matter is pending. Wisconsin Electric has incurred substantial damages to date and damages continue to accrue. We are seeking recovery of our damages in this lawsuit.

In July 2002, the President 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, Nevada. The Department of Energy has indicated that it does not expect a permanent used fuel repository to be available any earlier than 2010. It is not possible, at this time, to predict with certainty when the Department of Energy will actually begin accepting used nuclear fuel.

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 our Power the Future growth strategy.

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

Addition of new generating capacity in the state;

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

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

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

A-31

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

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

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

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

Restructuring in Illinois: In 1999, the state of Illinois passed legislation that introduced retail electric choice for large customers and introduced choice for all retail customers in May 2002. This legislation is not expected to have a material impact on Wisconsin Electric’s business. Wisconsin Electric has one wholesale customer in Illinois, the City of Geneva, whose contract is scheduled to expire on December 31, 2005. However, Wisvest’s wholly-owned subsidiary, Calumet Energy Team, LLC, does compete in the Illinois electric generation market with power produced from its 308-megawatt gas based peaking plant that entered commercial operation in 2002. Since May 1, 2004, Calumet has operated under the control of PJM Interconnection, L.L.C. (PJM), an RTO that also operates bid based energy and capacity markets. Since operating under PJM, there has been a change in the anticipated economics of the facility and the determination of an impairment of the facility. An impairment charge was recorded in the third quarter of 2004. For further information see “Note F — Asset Valuation Charges” - in the Notes to the Consolidated Financial Statements.

Electric Transmission and Energy Markets

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

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

Midwest ISO: In connection with its 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 Wisconsin Electric and other WUMS utilities, to minimize the potential

A-32

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 Wisconsin Electric and Edison Sault. The Midwest ISO recently completed its first allocation of FTRs for the period starting April 1, 2005 and ending August 31, 2005. Wisconsin Electric received 94% of the FTRs that it 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 Wisconsin Electric 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 Wisconsin Electric and Edison Sault.

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 impacts on Wisconsin Electric and Edison Sault.

Lost Revenue Charges: The FERC permits transmission owning utilities that have not joined an RTO to propose a charge to recover revenues that would be lost as a result of RTO membership. These lost revenues result from FERC’s requirement that, within an RTO and for transmission between the systems operated by the Midwest ISO and PJM, 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 Wisconsin Electric 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 permitted 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.

Congestion Charges on Other 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

A-33

transmission service on Commonwealth Edison’s facilities. Wisconsin Electric was allocated FTRs for virtually all of its 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, Wisconsin Electric has experienced minimal net congestion costs associated with its FTRs in PJM. Congestion costs are included under the definition of fuel for the Wisconsin Fuel Cost Adjustment Procedure.

Natural Gas Utility Industry

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

ACCOUNTING DEVELOPMENTS

New Pronouncements: In 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 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” and “Note I — Common Equity” in the Notes to Consolidated Financial Statements in this report for additional information.

CRITICAL ACCOUNTING ESTIMATES

Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles (GAAP) requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions. In addition, the financial and operating environment also may have a significant effect, not only on the operation of our business, but on our results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied have not changed.

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

Regulatory Accounting: Our utility subsidiaries operate under rates established by state and federal regulatory commissions which are designed to recover the cost of service and provide a reasonable return to investors. Developing competitive pressures in the utility industry may result in future utility prices which are based upon factors other than the traditional original cost of investment. In this situation, continued deferral of certain regulatory asset and liability amounts on the utilities’ books, as allowed under Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71), may no longer be appropriate and the unamortized regulatory assets net of the regulatory liabilities would be recorded as an extraordinary after-tax non-cash charge to earnings. As of December 31, 2004, we had $849.4 million in regulatory assets and $922.4 million in regulatory liabilities. We continually review the applicability of SFAS 71 and have determined that it is currently appropriate to continue following SFAS 71. See “Note C — Regulatory Assets and Liabilities” in the Notes to Consolidated Financial Statements for additional information.

Pension and Other Post-retirement Benefits: Our reported costs of providing non-contributory defined pension benefits (described in “Note O — Benefits” in the Notes to Consolidated Financial Statements) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. Pension costs are impacted by actual employee demographics (including age, compensation levels and employment periods), the level

A-34

of contributions made to plans and earnings on plan assets. Changes made to the provisions of the plans may also impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs.

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

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 Plan Actuarial Assumption (a)	Impact on Annual Cost
	(Millions of Dollars)
0.5% decrease in discount rate	$	6.6
0.5% decrease in expected rate of return on plan assets	$	4.8

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

In addition to pension plans, we maintain other post-retirement benefit plans which provide health and life insurance benefits for retired employees (described in “Note O — Benefits” in the Notes to Consolidated Financial Statements). We account for these plans in accordance with SFAS No. 106, Employers’ Accounting for Post-retirement Benefits Other Than Pensions (SFAS 106). Our reported costs of providing these post-retirement benefits are dependent upon numerous factors resulting from actual plan experience including employee demographics (age and compensation levels), our contributions to the plans, earnings on plan assets and health care cost trends. Changes made to the provisions of the plans may also impact current and future post-retirement benefit costs. Other post-retirement benefit costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the post-retirement benefit obligation and post-retirement costs. Our other post-retirement benefit plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased other post-retirement costs in future periods. Similar to accounting for pension plans, the regulators of our utility segment have adopted SFAS 106 for rate making purposes.

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


Other Post-retirement Benefit Plan Actuarial Assumption (a)	Impact on Reported Annual Cost
	(Millions of Dollars)
0.5% decrease in discount rate	$	2.2
0.5% decrease in health care cost trend rate		($1.5	)
0.5% decrease in expected rate of return on plan assets	$	0.8

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

A-35

Unbilled Revenues: We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated. This unbilled revenue is estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses and applicable customer rates. Significant fluctuations in energy demand for the unbilled period or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. Total utility operating revenues during 2004 of $3.4 billion included accrued utility revenues of $245.1 million at December 31, 2004.

Asset Retirement 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 our utility energy segment’s 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	$	250
1% decrease in inflation rate		($185)

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. 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 L — Asset Retirement Obligations” and “Note H — Nuclear Operations” in the Notes to Consolidated Financial Statements.

Deferred Tax Assets Valuation Allowance: At December 31, 2004, we had a valuation allowance of approximately $40.5 million of which approximately $22.0 million related to state net operating loss carryforwards (state NOLs), and the remainder related primarily to potential state tax benefits of asset impairment charges. Of the $22.0 million, $15.1 million relates to state NOLs of the parent company that begin to expire in 2010, and $6.9 million relates to state NOLs of various other non-utility subsidiaries that begin to expire in 2008. The state NOLs have been generated over a period of many years due to taxable losses in the separate state income tax returns. The losses at the Parent were primarily due to interest expense. We had established the valuation allowance against the state NOLs each year as the taxable losses occurred because management concluded that it was more likely than not that the state NOLs would not be realized prior to expiration.

The Power the Future generating units will be owned by our subsidiaries organized as Limited Liability Corporations (LLCs). Once the plants become operational, taxable income or loss of the LLCs will flow through to and be reported in the separate state income tax return of the Parent. As a result, the Parent no longer expects to generate large state losses if all plants are in service. The determination of future state taxable income of the Parent is a significant estimate. Factors affecting the estimate include the ultimate resolution of legal challenges to the construction of the plants, amounts spent and timing for construction of the Power the Future generating units, the

A-36

amount of debt and interest expense at the Parent and the consideration of available tax planning strategies. We concluded at December 31, 2004 it was more likely than not that all of the deferred tax assets related to state NOLs would expire before being realized.

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

CAUTIONARY FACTORS

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

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

Regulatory factors such as unanticipated changes in rate-setting policies or procedures; unanticipated changes in regulatory accounting policies and practices; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of costs of previous investments made under traditional regulation; recovery of costs associated with adoption of changed accounting standards; required changes in facilities or operations to reduce the risks or impacts of potential terrorist activities; required approvals for new construction; changes in the United States Nuclear Regulatory Commission’s regulations related to Point Beach Nuclear Plant or a permanent repository for used nuclear fuel; changes in the 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.

Ø	Unexpected difficulties or unanticipated effects of the qualified five-year electric and gas rate freeze ordered by the Public Service Commission of Wisconsin as a condition of approval of the WICOR merger in 2000.

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

Unanticipated operational and/or financial consequences related to implementation of the Midwest Independent Transmission System Operator, Inc. bid-based energy market that will 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.

A-37

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

Factors which impede execution of our Power the Future strategy announced in September 2000 and revised in February 2001, including receipt of necessary state and federal regulatory approvals, 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.

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

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

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

Ø	The cost and other effects of legal and administrative proceedings, settlements, investigations and claims and changes in those matters.

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

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

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

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

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

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

Ø	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 in this report for information concerning potential market risks to which Wisconsin Energy and its subsidiaries are exposed.

A-38

WISCONSIN ENERGY CORPORATION

CONSOLIDATED INCOME STATEMENTS

Year Ended December 31


	2004		2003		2002
	(Millions of Dollars, Except Per Share Amounts)
Total Operating Revenues	$	3,431.1	$	3,308.3	$	3,051.0
Operating Expenses
Fuel and purchased power		592.9		570.8		594.1
Cost of gas sold		890.9		863.3		574.9
Other operation and maintenance		1,002.7		934.2		933.8
Depreciation, decommissioning and amortization		327.1		329.8		318.5
Property and revenue taxes		87.3		82.4		87.8
Asset valuation charges, net		150.4		45.6		141.5

Total Operating Expenses		3,051.3		2,826.1		2,650.6

Operating Income		379.8		482.2		400.4
Other Income and Deductions, Net		16.1		42.2		43.7
Interest Expense		193.4		213.8		227.1

Income from Continuing Operations Before Income Taxes		202.5		310.6		217.0
Income Taxes		80.3		110.2		85.3

Income from Continuing Operations		122.2		200.4		131.7
Income from Discontinued Operations, Net of Tax		184.2		43.9		35.3

Net Income	$	306.4	$	244.3	$	167.0

Earnings Per Share (Basic)
Continuing Operations	$	1.04	$	1.71	$	1.14
Discontinued Operations	$	1.56	$	0.38	$	0.31

Total Earnings Per Share (Basic)	$	2.60	$	2.09	$	1.45

Earnings Per Share (Diluted)
Continuing Operations	$	1.03	$	1.69	$	1.13
Discontinued Operations	$	1.54	$	0.37	$	0.31

Total Earnings Per Share (Diluted)	$	2.57	$	2.06	$	1.44

Weighted Average Common Shares Outstanding (Millions)
Basic		117.7		117.1		115.4
Diluted		119.1		118.4		116.3

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

A-39

WISCONSIN ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

December 31

ASSETS


	2004			2003
	(Millions of Dollars)
Property, Plant and Equipment
In service	$	8,238.4		$	8,342.4
Accumulated depreciation		(3,121.6	)		(3,021.3	)

		5,116.8			5,321.1
Construction work in progress		602.4			296.2
Leased facilities, net		98.9			104.6
Nuclear fuel, net		85.0			78.4

Net Property, Plant and Equipment		5,903.1			5,800.3

Investments
Nuclear decommissioning trust fund		737.8			674.4
Equity investment in transmission affiliate		187.8			154.4
Other		99.5			122.5

Total Investments		1,025.1			951.3

Current Assets
Cash and cash equivalents		35.6			28.1
Accounts receivable, net of allowance for doubtful accounts of $40.1 and $ 51.1		349.3			333.7
Accrued revenues		245.1			212.2
Materials, supplies and inventories		409.5			385.6
Deferred income taxes - current		4.9			56.5
Prepayments and other		132.1			111.7
Assets held for sale		—			938.0

Total Current Assets		1,176.5			2,065.8

Deferred Charges and Other Assets
Regulatory assets		849.4			612.3
Goodwill, net		441.9			441.9
Other		169.4			142.9

Total Deferred Charges and Other Assets		1,460.7			1,197.1

Total Assets	$	9,565.4		$	10,014.5

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

A-40

WISCONSIN ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

December 31

CAPITALIZATION AND LIABILITIES


	2004		2003
	(Millions of Dollars)
Capitalization
Common equity	$	2,492.4	$	2,358.7
Preferred stock of subsidiary		30.4		30.4
Long-term debt		3,239.5		3,570.5

Total Capitalization		5,762.3		5,959.6

Current Liabilities
Long-term debt due currently		101.0		166.2
Short-term debt		338.0		590.8
Accounts payable		309.7		248.7
Payroll and vacation accrued		74.3		67.3
Taxes accrued - income and other		12.1		23.0
Interest accrued		28.1		35.8
Other		129.2		80.2
Liabilities held for sale		—		251.7

Total Current Liabilities		992.4		1,463.7

Deferred Credits and Other Liabilities
Regulatory liabilities		922.4		887.7
Asset retirement obligations		762.2		732.0
Deferred income taxes - long-term		530.4		570.8
Accumulated deferred investment tax credits		61.0		66.0
Minimum pension liability		152.8		34.7
Other long - term liabilities		381.9		300.0

Total Deferred Credits and Other Liabilities		2,810.7		2,591.2

Commitments and Contingencies (Note S)		—		—

Total Capitalization and Liabilities	$	9,565.4	$	10,014.5

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

A-41

WISCONSIN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31


	2004			2003			2002
	(Millions of Dollars)
Operating Activities
Net income	$	306.4		$	244.3		$	167.0
Income from discontinued operations, net of tax		(184.2	)		(43.9	)		(35.3	)
Reconciliation to cash
Depreciation, decommissioning and amortization		360.2			360.3			337.9
Nuclear fuel expense amortization		24.0			25.3			27.3
Equity in earnings of unconsolidated affiliates		(30.9	)		(22.2	)		(22.9	)
Distribution from unconsolidated affiliates		44.7			32.9			23.1
Asset valuation charges, net		150.4			45.6			141.5
Deferred income taxes and investment tax credits, net		6.5			64.5			(32.4	)
Accrued income taxes, net		(8.5	)		(30.1	)		27.4
Change in - Accounts receivable and accrued revenues		(48.5	)		9.1			(66.3	)
Other accounts receivable		—			—			116.4
Inventories		(23.9	)		(72.3	)		14.4
Other current assets		(20.5	)		(23.1	)		5.6
Accounts payable		39.3			(27.9	)		10.0
Other current liabilities		23.2			12.7			(2.8	)
Other		(39.5	)		(45.3	)		(50.0	)

Cash Provided by Operating Activities		598.7			529.9			660.9

Investing Activities
Capital expenditures		(636.8	)		(649.0	)		(541.8	)
Acquisitions and investments		(26.4	)		(7.6	)		(39.7	)
Proceeds from asset sales		899.6			55.3			310.0
Nuclear fuel		(30.0	)		(38.3	)		(20.7	)
Nuclear decommissioning funding		(17.6	)		(17.6	)		(17.6	)
Cash from/(to) Discontinued Operations		32.4			61.2			(31.6	)
Other		21.9			(0.2	)		(41.1	)

Cash (Used in) Provided by Investing Activities		243.1			(596.2	)		(382.5	)

Financing Activities
Issuance of common stock and exercise of stock options		70.9			62.9			52.6
Repurchase of common stock		(152.7	)		(6.8	)		(52.3	)
Dividends paid on common stock		(97.8	)		(93.7	)		(92.4	)
Issuance of long-term debt		397.0			984.7			12.0
Retirement and redemption of long-term debt		(798.4	)		(526.2	)		(450.1	)
Change in short-term debt		(252.8	)		(337.8	)		247.9
Other		(0.5	)		(23.7	)		—

Cash (Used in) Provided by Financing Activities		(834.3	)		59.4			(282.3	)

Change in Cash and Cash Equivalents from Continuing Operations		7.5			(6.9	)		(3.9	)
Cash and Cash Equivalents at Beginning of Year		28.1			35.0			38.9

Cash and Cash Equivalents at End of Year	$	35.6		$	28.1		$	35.0

Supplemental Information - Cash Paid For
Interest (net of amount capitalized)	$	232.2		$	220.9		$	233.6
Income taxes (net of refunds)	$	80.5		$	92.2		$	89.8

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

A-42

WISCONSIN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMMON EQUITY


	Common Stock		Other Paid In Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Unearned Compensation		Stock Options Exercisable			Total
	(Millions of Dollars)
Balance - December 31, 2001	$	1.2	$	763.8		$	1,284.9			($10.8	)	($4.2	)	$	21.2		$	2,056.1
Net Income							167.0											167.0
Other comprehensive income
Foreign currency translation										3.0								3.0
Minimum pension liability										(0.8	)							(0.8	)
Hedging, net										1.1								1.1

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

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

Comprehensive income		—		—			244.3			10.6		—			—			254.9
Common stock cash dividends $0.80 per share							(93.7	)										(93.7	)
Common stock issued				62.9														62.9
Repurchase of common stock				(6.8	)													(6.8	)
Restricted stock awards												(2.8	)					(2.8	)
Amortization and forfeiture of restricted stock				(0.3	)							1.4						1.1
Stock options exercised				3.8											(3.8	)		—
Tax benefit of stock options exercised				5.0														5.0
Other				(1.3	)													(1.3	)

Balance - December 31, 2003	$	1.2	$	841.8		$	1,510.1		$	3.1		($4.7	)	$	7.2		$	2,358.7
Net Income						$	306.4											306.4
Other comprehensive income
Foreign currency translation										(8.6	)							(8.6	)
Minimum pension liability										(3.7	)							(3.7	)
Hedging, net										1.8								1.8

Comprehensive income		—		—			306.4			(10.5	)	—			—			295.9
Common stock cash dividends $0.83 per share							(97.8	)										(97.8	)
Common stock issued				70.9														70.9
Repurchase of common stock				(152.7	)													(152.7	)
Restricted stock awards												(0.6	)					(0.6	)
Performance option awards				5.9								(5.9	)					—
Amortization and forfeiture of restricted stock				(0.9	)							3.6						2.7
Stock options exercised				4.8											(4.8	)		—
Tax benefit of stock options exercised				15.3														15.3

Balance - December 31, 2004	$	1.2	$	785.1		$	1,718.7			($7.4	)	($7.6	)	$	2.4		$	2,492.4

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

A-43

WISCONSIN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CAPITALIZATION

December 31


		2004			2003
		(Millions of Dollars)
Common Equity (See Consolidated Statements of Common Equity)
Common stock - $.01 par value; authorized 325,000,000 shares; outstanding - 116,985,822 and 118,425,546 shares		$	1.2		$	1.2
Other paid in capital			785.1			841.8
Retained earnings			1,718.7			1,510.1
Accumulated other comprehensive income (loss)			(7.4	)		3.1
Unearned compensation - restricted stock awards			(7.6	)		(4.7	)
Stock options exercisable			2.4			7.2

Total Common Equity			2,492.4			2,358.7
Preferred Stock
Wisconsin Energy $.01 par value; authorized 15,000,000 shares; none outstanding			—			—
Wisconsin Electric Six Per Cent. Preferred Stock - $100 par value; authorized 45,000 shares; outstanding - 44,498 shares			4.4			4.4
Serial preferred stock -
$100 par value; authorized 2,286,500 shares; 3.60% Series redeemable at $101 per share; outstanding - 260,000 shares			26.0			26.0
$25 par value; authorized 5,000,000 shares; none outstanding			—			—
Wisconsin Gas
$.01 par value; authorized - zero and 3,000,000 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
	6.60% due 2013		45.0			45.0
	5.20% due 2015		125.0			125.0
	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

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

A-44

WISCONSIN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CAPITALIZATION - (Cont’d)

December 31


		2004			2003
		(Millions of Dollars)
Long-Term Debt - (Cont’d)
Notes (secured, nonrecourse)
	3.79% variable rate due 2005 (a)	$	6.5		$	6.8
	6.36% effective rate due 2006		2.2			3.3
	6.90% due 2006		1.1			1.1
	2% stated rate due 2011		1.3			1.3
	4.81% effective rate due 2030		2.0			2.0
	2.67% variable rate due 2028 (a)		15.6			16.0
Notes (unsecured)
	6-³/8% due 2005		65.0			65.0
	6.85% due 2005		10.0			10.0
	2.10% variable rate due 2006 (a)		1.0			1.0
	5.875% due 2006		250.0			550.0
	6.36% effective rate due 2006		2.4			3.6
	7.00% to 8.00% due 2001-2008		2.1			2.3
	5.50% due 2008		300.0			300.0
	6.21% due 2008		20.0			20.0
	6.48% due 2008		25.4			25.4
	5-¹/2% due 2009		50.0			50.0
	6.50% due 2011		450.0			450.0
	6.51% due 2013		30.0			30.0
	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			—
	6.94% due 2028		50.0			50.0
	1.52% variable rate due 2030 (b)		—			80.0
	1.70% variable rate due 2030 (a)		80.0			—
	6.20% due 2033		200.0			200.0
Junior subordinated debentures (unsecured)
	6.85% due 2039 (see Note J)		—			206.2
Obligations under capital leases			212.9			213.2
Unamortized discount, net and other			(27.8	)		(32.0	)
Long-term debt due currently			(101.0	)		(166.2	)

Total Long-Term Debt			3,239.5			3,570.5

Total Capitalization		$	5,762.3		$	5,959.6

(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.

A-45

WISCONSIN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

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

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

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

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

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

The most significant reclassifications relate to the reporting of discontinued operations pursuant to Statement of Financial Accounting Standards (SFAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Effective July 31, 2004, we sold our manufacturing business. This segment is now classified as a discontinued operation. The footnotes contained herein have been restated to reflect continuing operations for all periods presented. For further information see Note E - Asset Sales, Divestitures and Discontinued Operations.

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

Wisconsin Electric’s 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 expected to be more than 3% higher than the forecasted costs used to establish rates.

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

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

A-46


Other Income and Deductions, Net	2004			2003		2002
	(Millions of Dollars)
Equity in Earnings of Unconsolidated Affiliates	$	30.9		$	22.2	$	22.9
Carrying Costs on Deferred Assets		12.4			9.3		6.1
Debt Redemption Costs		(22.9	)		—		—
Gain on Derivative Contracts (See Note M)		—			—		21.1
Other, net		(4.3	)		10.7		(6.4	)

Total Other Income and Deductions	$	16.1		$	42.2	$	43.7

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 had the following property in service by segment at December 31:


Property In Service	2004		2003
	(Millions of Dollars)
Utility Energy	$	7,986.3	$	7,890.4
Non-Utility Energy		57.7		179.8
Other		194.4		272.2

Total	$	8,238.4	$	8,342.4

Our regulated utilities collect in their rates future removal costs for many assets that do not have an associated legal asset retirement obligation. We record a regulatory 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 $599.3 million as of December 31, 2004 and $571.1 million as of December 31, 2003.

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

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

We include capitalized software costs associated with our utility energy segment under the caption “Property, Plant and Equipment” on the Consolidated Balance Sheets. As of December 31, 2004 and 2003, the net book value of regulated capitalized software totaled $28.8 million and $36.0 million, respectively. The net book value of other capitalized software was approximately $2.6 million and $2.2 million as of December 31, 2004 and 2003, respectively.

Our utility depreciation rates are certified by the state regulatory commissions and include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 4.2% in 2004, 4.2% in 2003, and 4.5% in 2002. Nuclear plant decommissioning costs are accrued and included in depreciation expense (see Note H).

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.

We had the following Construction Work in Progress (CWIP) by segment at December 31:

A-47


	2004		2003
	(Millions of Dollars)
Utility Energy	$	160.8	$	76.2
Non-Utility Energy		432.6		219.8
Other		9.0		0.2

Total	$	602.4	$	296.2

Allowance For Funds Used During Construction - Regulated: 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 of interest expense and AFUDC - equity is recorded in Other Income and Deductions, Net.

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

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

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

Our regulated segment recorded the following AFUDC for the years ended December 31:


	2004		2003		2002
	(Millions of Dollars)
AFUDC - Debt	$	1.5	$	2.9	$	2.3
AFUDC - Equity	$	2.8	$	5.1	$	4.3

Capitalized Interest and Carrying Costs - Non-Regulated Energy: As part of the construction of our power plants under the Power the Future program, we capitalize interest during construction in accordance with SFAS No. 34, Capitalization of Interest Cost. We will amortize capitalized interest over the life of the power plants. For the years ended December 31, 2004 and 2003, we capitalized $17.9 million and $6.5 million of interest costs, at an average rate of 6.1% and 5.7%.

Under the lease agreements associated with our Power the Future power plants, we are able to collect from utility customers the carrying costs associated with the construction of our power plants. We defer these carrying costs on our balance sheet and they will be amortized to revenue over the individual lease term. For the years ended December 31, 2004 and 2003, we have deferred $38.2 million and $17.1 million of carrying costs related to the Power the Future power plants.

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

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


Materials, Supplies and Inventories	2004		2003
	(Millions of Dollars)
Fossil Fuel	$	90.0	$	108.0
Natural Gas in Storage		226.7		184.4
Materials and Supplies		92.8		93.2

Total	$	409.5	$	385.6

A-48

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

Regulatory Accounting: Our utility energy segment accounts for its regulated operations in accordance with 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 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 $62.0 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 M.

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

Asset Retirement Obligations: We adopted SFAS 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 L.

Goodwill and Intangible Assets: We account for goodwill and other intangible assets following SFAS 142, Goodwill and Other Intangible Assets, effective January 1, 2002. As of December 31, 2004 and 2003, we had recorded $441.9 million of goodwill related to our Utility Energy Segment. As of December 31, 2003, we had recorded $394.0 million of goodwill related to our Manufacturing Segment in Assets Held for Sale.

Under SFAS 142, goodwill and other intangibles with indefinite lives are not subject to amortization. However, goodwill and other intangibles are subject to fair value-based rules for measuring impairment, and resulting write-downs, if any, are to be reflected in operating expense. We assess the fair value of our SFAS 142 reporting unit by considering future discounted cash flows, a comparison of fair value based on public company trading multiples, and merger and acquisition transaction multiples for similar companies. This evaluation utilizes the information available under the circumstances, including reasonable and supportable assumptions and projections. We perform our annual impairment test for the reporting unit as of August 31. There was no impairment to the recorded goodwill balance as of our annual 2004 impairment test date for our reporting unit.

Impairment or Disposal of Long Lived Assets: We carry property, equipment and goodwill related to businesses held for sale at the lower of cost or estimated fair value less costs to sell. As of December 31, 2004, we had no assets classified as Held for Sale. The manufacturing segment had been reclassified as Held for Sale at December 31, 2003. Consistent with SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that their carrying value may not be recoverable from the use and eventual disposition of the asset based on the remaining useful life. For further information, see Note F.

Investments: 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, we had a total ownership interest of approximately 37.8% and 39.4%, in American Transmission Company (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.

Income Taxes: We follow the liability method in accounting for income taxes as prescribed by SFAS No. 109, Accounting for Income Taxes (SFAS 109). SFAS 109 requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances

A-49

to reflect tax rate changes. Tax credits associated with regulated operations are deferred and amortized over the life of the assets. We file a consolidated Federal income tax return. Accordingly, we allocate Federal current tax expense benefits and credits to our subsidiaries based on their separate tax computations. For further information, see Note G.

Stock Options: We account for stock options under Accounting Principles Board Opinion 25, Accounting for Stock Issued to Employees (APB 25) and adopted the disclosure provisions of SFAS No. 123, Accounting for Stock-Based Compensation, as amended by SFAS 148, Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of SFAS 123 (See Notes B and I).

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

B — RECENT ACCOUNTING PRONOUNCEMENTS

Share Based Compensation: 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 123R 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. 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 I for information regarding the pro forma impact of this statement.

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 O)	$	342.8	$	189.4
Deferred electric transmission costs		109.6		73.3
Deferred income tax related		99.9		133.0
Plant related — capital lease (See Note J)		61.1		54.5
Environmental costs		58.0		55.6
Unrecovered plant costs		45.9		9.0
Bad debt costs		41.7		21.5
Other, net		90.4		76.0

Total Regulatory Assets	$	849.4	$	612.3


Regulatory Liabilities	2004		2003
	(Millions of Dollars)
Cost of removal obligations (See Notes H and L)	$	599.3	$	571.1
Deferred pension - income		116.9		128.3
Income tax related		109.4		126.8
Other, net		96.8		61.5

Total Deferred Regulatory Liabilities	$	922.4	$	887.7

We record a minimum pension liability to reflect the funded status of our pension plans (see Note O). 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 energy segment qualify as a regulatory asset.

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

A-50

In October 2002, the PSCW issued an order authorizing Wisconsin Electric to implement a surcharge for recovery of annual electric transmission costs projected through 2005. 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.

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 $58.0 million of environmental costs associated with manufactured gas plant sites as a regulatory asset, including $31.4 million of deferrals for actual remediation costs incurred and a $26.6 million accrual for estimated future site remediation (See Note S). In addition, we have deferred $16.7 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 our 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. This deferred unrecovered plant costs totaled $45.9 million at December 31, 2004.

As of December 31, 2004, we have deferred a regulatory asset of $41.7 million for bad debt costs. Prior to October 2002, Wisconsin Gas used the escrow method of accounting for bad debt costs whereby it deferred actual bad debt write-off that exceeded amounts that were allowed in its rates. In 2003 and 2004, the PSCW approved our request to defer bad debt write-offs at Wisconsin Gas and Wisconsin Electric to the extent that the write-offs exceeded amounts allowed in rates. We have requested that this deferral accounting continue in 2005. We will request approval to recover these costs in our next Wisconsin rate case.

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

D — VARIABLE INTEREST ENTITIES

In January 2003, the FASB issued Interpretation 46, Consolidation of Variable Interest Entities (FIN 46). This standard requires an enterprise that is the primary beneficiary of a variable interest entity to consolidate that entity. We applied the Interpretation to any existing interests in variable interest entities beginning in the third quarter of 2003. In October 2003, the FASB deferred the adoption of FIN 46 for all entities commonly referred to as special-purpose entities to the first reporting period ending after December 15, 2003. In December 2003, the FASB 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.

E — ASSET SALES, DIVESTITURES AND DISCONTINUED OPERATIONS

We have been pursuing a corporate strategy since September 2000, which, among other things, identified the divestiture of non-core investments. These assets primarily related to our manufacturing business, non-utility energy investments and real estate.

Manufacturing: Effective July 31, 2004, we sold WICOR, Inc. to Pentair, Inc. and received cash proceeds of $857 million, and Pentair, Inc. assumed approximately $25 million of third party debt.

A-51

WICOR’s only asset at the time of the sale consisted of its interest in WICOR Industries. As a condition of the sale, WICOR transferred its ownership of Wisconsin Gas to Wisconsin Energy through a stock redemption. Prior to the transaction, Wisconsin Gas converted from a corporation to a limited liability company (collectively the “Wisconsin Gas transfer”). We expect to pay cash taxes of approximately $114 million as a result of the stock redemption described above. However, we also expect to receive future tax deductions from a step-up in the tax basis of the Wisconsin Gas assets as a result of the Wisconsin Gas transfer. We therefore expect that substantially all of the cash taxes paid on the stock redemption will be recovered as deferred income tax assets through future deductions.

Pursuant to the terms of the sales agreement, Wisconsin Energy agreed to customary indemnification provisions related to certain environmental, asbestos, and product liability matters associated with the manufacturing business. We have established reserves related to these customary indemnification matters. In addition, the amount of cash taxes and future deferred income tax benefits are subject to a number of factors including appraisals of the fair value of Wisconsin Gas assets and applicable tax laws. Any changes in the estimates of taxes and indemnification matters will be recorded as an adjustment to the gain on sale and reported in discontinued operations in the period the adjustment is determined.

In accordance with SFAS 144, the assets and liabilities associated with our manufacturing segment have been reclassified as held for sale in the accompanying December 31, 2003 balance sheet. SFAS 144 requires that a long-lived asset classified as held for sale be measured at the lower of its carrying amount or fair value, less costs to sell, and cease being depreciated. We also reclassified our manufacturing segment as discontinued operations in the accompanying income statements. Included in discontinued operations is interest expense associated with third-party debt that was assumed by the buyer upon completion of the sale. A summary of the components of Income from Discontinued Operations, Net of Tax in our Consolidated Condensed Income Statements follows:


	Year Ended December 31
	2004 (a)		2003			2002
	(Millions of Dollars)
Operating revenues	$	481.0	$	746.1		$	685.2
Operating expenses		429.8		677.5			627.6
Interest expense and other		0.3		(0.2	)		1.9

Income before income taxes		50.9		68.8			55.7
Income tax expense		19.0		24.9			20.4

Income from operations, net of tax		31.9		43.9			35.3
Gain on Sale, net of taxes of $2.1 million		152.3		—			—

Income from discontinued operations, net of tax	$	184.2	$	43.9		$	35.3

(a)	Includes the results of our manufacturing segment through July 31, 2004.

A summary of the components of cash flows for discontinued operations follows:


	Year Ended December 31
	2004(a)			2003			2002
	(Millions of Dollars)
Net cash flows received from operating activities	$	36.9		$	93.9		$	50.5
Net cash flows received from (used in) investing activities		(41.3	)		(70.9	)		16.6
Net cash flows used in financing activities		(2.0	)		(6.1	)		(66.6	)

Net (decrease) increase in cash and temporary cash investments		($6.4	)	$	16.9		$	0.5

Supplemental cash flow information:
Interest	$	0.5		$	1.0		$	2.0
Income taxes, net of refunds	$	8.5		$	7.8		$	1.1

(a)	Includes the results of our manufacturing segment through July 31, 2004.

A-52

Cash and temporary cash investments of discontinued operations as of December 31, 2003 totaled $25.4 million and are included in Assets held for sale in the Consolidated Balance Sheet.

Non-Utility: During 2003, we sold our investment in two energy marketing companies, a small investment in assets of a Minergy Corp. project, a 500 megawatt natural gas power island and miscellaneous small real estate and other sales. These sales resulted in net cash proceeds of approximately $56.0 million and $32.0 million in tax benefits. In addition, we received $15.0 million in dividends from certain of these companies at closing.

During 2002, we completed the sale of Wisvest—Connecticut LLC (Wisvest Connecticut), which resulted in net cash proceeds of approximately $220.0 million.

F —ASSET VALUATION CHARGES

In the third quarter of 2004, we recorded non-cash asset valuation charges of $149.0 million ($96.9 million after-tax) related to Minergy Neenah and Calumet. These charges are discussed below. During 2003, we recorded asset valuation charges totaling $59.5 million, of which $19.4 million related to the write-off of our remaining investment in Androscoggin LLC, an independent power project and $40.1 million related to an investment in a power island. The power island is discussed in more detail below. During the first quarter of 2002, we recorded $141.5 million of impairment charges of which $125.1 million was related to our non-utility energy segment (primarily Wisvest - Connecticut) and a $16.4 million charge related to a decline in a venture capital investment. Wisvest—Connecticut was sold in the fourth quarter of 2002.

Minergy Neenah: Minergy Neenah is a waste to energy facility that recycles paper sludge from area paper mills into steam, renewable electricity and glass aggregate. One of Minergy Neenah’s key revenue sources is a long-term steam contract with a paper company whereby Minergy Neenah sells steam to the paper company’s facility in Neenah. The paper company contacted Minergy Neenah to request a renegotiation of the steam contract to help sustain the long-term viability of the paper company’s facility. Given the importance of the long-term steam contract to Minergy Neenah, we believed it was important to help maintain the viability of the paper company’s facility. In October 2004, we signed an amendment to the steam contract which will reduce estimated steam revenues through 2017. We concluded the asset was impaired and recorded a non-cash asset valuation charge of $27.0 million

($ 17.6 million after-tax) in the third quarter of 2004.

Calumet: Calumet is a 308 megawatt natural gas-based peaking power plant located in Chicago, Illinois. Since May 1, 2004, Calumet has operated under the control of PJM Interconnection, L.L.C. (PJM), a regional transmission organization that also operates bid based energy and capacity markets. In the third quarter of 2004, we determined that (i) Calumet has significant risk associated with liquidated damages for certain energy sales within the PJM market, (ii) the elimination of the risk is not guaranteed via assumption of the risk by a third party marketer or through the availability of appropriate insurance, and (iii) nonacceptance of, or failure to arrange for, coverage of the risk greatly diminishes the ability to viably sell merchant capacity, which has resulted in a change in the anticipated economics of the facility and the determination of an impairment of the facility. We concluded that this asset was impaired and recorded a non-cash asset valuation charge of $122.0 million ($79.3 million after-tax) in the third quarter of 2004.

Power Island: Wisvest had purchased a 500 megawatt power island consisting of gas turbine generators and related equipment. This power island was not identified for a specific project. In 2002, we took possession of the power island and put it in storage. In the third quarter of 2003, we recorded a non-cash asset valuation charge of $40.1 million ($26.0 million after tax) to reflect the impairment of this asset. We determined in the third quarter of 2003 based on information obtained from our efforts to market the power island, that the carrying value of this asset exceeded market values. We estimated the fair market value of our 500 megawatt power island based upon a definitive agreement we entered into to sell the asset. This asset was sold in the fourth quarter of 2003 with no additional loss.

A-53

G — 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	$	73.8		$	93.9		$	138.9
Deferred income taxes, net		11.3			21.2			(48.7	)
Investment tax credit, net		(4.8	)		(4.9	)		(4.9	)

Total Income Tax Expense	$	80.3		$	110.2		$	85.3

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 as a result of the following:


	2004					2003					2002
Income Tax Expense	Amount			Effective Tax Rate		Amount			Effective Tax Rate		Amount			Effective Tax Rate
						(Millions of Dollars)
Expected tax at statutory federal tax rates	$	70.9		35.0%		$	08.7		35.0%		$	76.0		.0%
State income taxes net of federal tax benefit		20.2		10.0%			21.0		6.8%			21.5		9.9%
Investment tax credit restored		(4.8	)	(2.4%	)		(4.9	)	(1.6%	)		(4.9	)	(2.3%	)
Federal Historical rehabilitation credits (net)		(1.0	)	(0.5%	)		(1.7	)	(0.5%	)		(6.0	)	(2.7%	)
Other, net		(5.0	)	(2.5%	)		(12.9	)	(4.2%	)		(1.3	)	(0.6%	)

Total Income Tax Expense	$	80.3		39.6%		$	110.2		35.5%		$	85.3		39.3%

The state income tax rate between 2004 and 2003 was adversely affected by the inability to receive state tax benefits from certain asset valuation charges.

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	$	—		$	—	$	634.8		$	693.8
Construction advances		—			—		(80.1	)		(82.9	)
Decommissioning trust		—			—		(74.5	)		(65.5	)
Recoverable gas costs		8.1			6.4		—			—
Prepaid taxes and insurance		(29.5	)		—		—			—
Uncollectible account expense		(3.0	)		16.6		—			—
Employee benefits and compensation		13.7			10.7		(12.3	)		1.4
Deferred transmission costs		—			—		40.5			21.8
State NOL’s		—			—		(22.0	)		(18.0	)
Valuation allowance		—			—		40.5			22.5
Other		15.6			22.8		3.5			(2.3	)

Total Deferred Income Taxes	$	4.9		$	56.5	$	530.4		$	570.8

We had not recorded $22.0 million and $18.0 million of tax benefits as of December 31, 2004 and 2003 primarily related to state loss carryforwards due to the uncertainty of the ability to benefit from these losses in the future. These loss carryforwards begin to expire in 2008 and have been reduced by a valuation allowance.

A-54

H — NUCLEAR OPERATIONS

Point Beach Nuclear Plant: Wisconsin Electric owns two 518-megawatt electric generating units at Point Beach Nuclear Plant in Two Rivers, Wisconsin. We currently expect the two units at Point Beach to operate to the end of their operating licenses, which expire in October 2010 for Unit 1 and in March 2013 for Unit 2. In February 2004, Nuclear Management Company (NMC) and Wisconsin Electric filed an application with the United States Nuclear Regulatory Commission (NRC) to renew the operating licenses for both of Wisconsin Electric’s 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 (Wisconsin Electric owns two) with a limit of $10 million per reactor within one calendar year. As the owner of Point Beach, Wisconsin Electric would be obligated to pay its proportionate share of any such assessment.

Wisconsin Electric, through its membership in Nuclear Electric Insurance Limited (NEIL), carries decontamination, property damage and decommissioning shortfall insurance covering losses of up to $2.1 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. Wisconsin Electric’s maximum retrospective liability under the above policies is $16.5 million.

Wisconsin Electric also maintains insurance with NEIL through which it 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. Wisconsin Electric’s 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 Wisconsin Electric from material adverse impact.

Nuclear Decommissioning: We record decommissioning expense in amounts equal to the amounts collected in rates and funded to the external trusts. Nuclear decommissioning costs are accrued over the expected service lives of the nuclear generating units and are included in electric rates. Decommissioning 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 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, Wisconsin Electric’s debt and equity security investments in the Nuclear Decommissioning Trust Fund are classified as available for sale. Gains and losses on the fund are determined on the basis of specific identification; net unrealized 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 L.

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

A-55

assumptions differ significantly from the assumptions used by the PSCW to calculate the nuclear decommissioning liability for funding purposes.

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.

Decontamination and Decommissioning Fund: The Energy Policy Act of 1992 established a Uranium Enrichment Decontamination and Decommissioning Fund (D&D Fund) for the United States Department of Energy’s nuclear fuel enrichment facilities. Deposits to the D&D Fund are derived in part from special assessments on utilities using enrichment services. As of December 31, 2004, Wisconsin Electric recorded its remaining estimated liability equal to projected special assessments of $7.2 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.

I — COMMON EQUITY

Common Stock Activity: In September 2000, the Board of Directors amended the common stock repurchase plan to authorize us to purchase up to $400 million of our shares of common stock in the open market. In 2004, we purchased and retired approximately 1.6 million shares of common stock for $50.4 million. The plan expired on December 31, 2004. Over the life of the plan we purchased and retired approximately 14.9 million shares of common stock for $344.0 million.

Prior to February 2004, we issued shares of our common stock to fulfill obligations under various employee benefit plans and the dividend reinvestment plan. We received proceeds of approximately $4.8 million, $62.9 million, and $52.6 million during 2004, 2003, and 2002, related to these share issuances. In February 2004, we announced that we did not expect to issue new shares under these programs; rather we instructed the plan agents to begin purchasing the shares in the open market in lieu of issuing new shares. During 2004, our plan agents purchased 3.2 million shares at a cost of $102.3 million to fulfill exercised stock options. In 2004, we received proceeds of $66.1 million related to the exercise of stock options.

Stock Based Compensation Plans: Our 1993 Omnibus Stock Incentive Plan, as amended (OSIP), as approved by stockholders, enables us to provide a long-term incentive through equity interests in Wisconsin Energy, to outside directors, selected officers and key employees of the Company and its subsidiaries. The OSIP provides for the granting of stock options, stock appreciation rights, stock awards and performance units. Awards may be paid in common stock, cash or a combination thereof.

The exercise price of a stock option under the OSIP is to be no less than 100% of the common stock’s fair market value on the grant date and options may not be exercised within six months of the grant date except in the event of a change in control. The stock options that were granted prior to 2005 generally vest on a straight line basis over a four year period and expire no later than ten years from the date of grant.

The following is a summary of our stock options issued through December 31, 2004. In addition to the OSIP, the table below reflects our assumption of former WICOR options in 2000, which were converted into options to purchase shares of Wisconsin Energy common stock on the same terms and conditions as were applicable under the WICOR options.

A-56


	2004				2003				2002
Stock Options	Number of Options		Weighted- Average Exercise Price		Number of Options		Weighted- Average Exercise Price		Number of Options		Weighted- Average Exercise Price
Outstanding at January 1	9,823,935		$	22.87	8,307,190		$	21.21	7,135,463		$	19.16
Granted	1,844,765		$	33.44	2,913,289		$	26.05	2,465,815		$	22.88
Exercised	(3,249,688	)	$	20.97	(1,357,197	)	$	19.55	(1,284,500	)	$	13.47
Forfeited	(128,701	)	$	28.21	(39,347	)	$	21.97	(9,588	)	$	24.38

Outstanding at December 31	8,290,311		$	25.88	9,823,935		$	22.87	8,307,190		$	21.21

Exercisable at December 31	8,090,987		$	25.99	4,303,482		$	21.25	4,267,604		$	20.56

In December, 2004, the Compensation Committee of the Board of Directors approved certain changes to unvested options and to future grants. The Compensation Committee approved the acceleration of vesting of all unvested options awarded to executive officers and other key employees in 2002, 2003 and 2004 in anticipation of the changes in accounting required under the new accounting standard for share based payments which is effective July 1, 2005. In addition, the Compensation Committee determined that future option grants would be non-qualified stock options and they would vest on a cliff-basis after a three year period. The Company recorded a $0.4 million charge, net of tax, in connection with the accelerated vesting of unvested stock options.

In January 2005, the Compensation Committee awarded 1,328,966 non-qualified stock options to our officers and key employees under its normal schedule of awarding long-term incentive compensation.

The following table summarizes information about stock options outstanding at December 31, 2004:


	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number	Average Exercise Price		Life (years)	Number	Average Exercise Price
$ 9.30 to $ 19.97	797,094	$	17.99	4.6	797,094	$	17.99
$ 20.39 to $ 23.05	2,428,418	$	21.89	6.6	2,270,760	$	21.97
$ 24.58 to $ 27.65	2,542,747	$	25.71	7.3	2,501,081	$	25.71
$ 29.13 to $ 33.44	2,522,052	$	32.40	8.1	2,522,052	$	32.40

	8,290,311	$	25.88	7.1	8,090,987	$	25.99

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


	2004			2003			2002
Risk free interest rate		4.6	%		4.5	%		5.6	%
Dividend yield		2.5	%		3.1	%		3.5	%
Expected volatility		23.10	%		25.73	%		25.5	%
Expected life (years)		10			10			10
Pro forma weighted average fair value of our stock options granted	$	9.45		$	7.04		$	6.25

As described more fully in the following table, our diluted earnings would have been reduced by $0.24, $0.06 and $0.05 per share, respectively, had we expensed the 2004, 2003 and 2002 grants for stock-based compensation plans under SFAS 123. The 2004 pro forma expense includes the effect of accelerating the vesting of stock options, as described above, which resulted in a pro forma expense of $0.16 per share.

A-57


	2004		2003		2002
	(Millions of Dollars, Except Per Share Amounts)
Net Income
As reported	$	306.4	$	244.3	$	167.0
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects	$	2.5	$	0.7	$	0.3
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	$	31.5	$	8.5	$	5.3

Pro forma	$	277.4	$	236.5	$	162.0

Basic Earnings Per Common Share
As reported	$	2.60	$	2.09	$	1.45
Pro forma	$	2.36	$	2.02	$	1.40
Diluted Earnings Per Common Share
As reported	$	2.57	$	2.06	$	1.44
Pro forma	$	2.33	$	2.00	$	1.39

The Compensation Committee has also approved restricted stock grants to certain key employees and directors. The following restricted stock activity occurred during 2004, 2003 and 2002:


	2004				2003				2002
Restricted Shares	Number of Shares		Weighted- Average Market Price		Number of Shares		Weighted- Average Market Price		Number of Shares		Weighted- Average Market Price
Outstanding at January 1	294,920				219,052				243,941
Granted	16,570		$	33.36	104,500		$	27.72	—			—
Released / Forfeited	(90,127	)	$	22.87	(28,632	)	$	22.84	(24,889	)	$	20.64

Outstanding at December 31	221,363				294,920				219,052

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

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

In January 2004, the Compensation Committee granted 159,159 performance shares to officers and other key employees. The ultimate number of shares of Common Stock which will be awarded under this program is dependent upon the achievement of certain financial performance of the Company’s stock over a three year period ending December 31, 2006. Under the terms of the award, participants may earn between 0% and 175% of the base performance award. We are accruing compensation costs over the three year period based on our estimate of the final expected value of the award.

In January 2005, the Compensation Committee granted 101,834 performance units to executive officers and other key employees. These awards are similar to the January 2004 grant, except that these units will be settled in cash instead of shares of our common stock.

Restrictions: Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our principal utility subsidiaries to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. Under Wisconsin law,

A-58

Wisconsin Electric and Wisconsin Gas are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy. We do not believe that these restrictions will materially affect our operations.

J — LONG-TERM DEBT

First Mortgage Bonds, Debentures and 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	$	86.3
2006		455.8
2007		251.0
2008		346.5
2009		50.8
Thereafter		1,965.0

Total	$	3,155.4

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

In August 2004, Wisconsin Electric retired $140 million of 7-1/4% First Mortgage Bonds at their scheduled maturity. Wisconsin Electric financed this retirement through the issuance of short-term commercial paper.

In September 2004, we used cash proceeds from the sale of WICOR Industries for the redemption of $300 million of Wisconsin Energy 5.875% senior notes due April 1, 2006. In September 2004, we recorded approximately $17.0 million of costs associated with this early redemption, which are included in Other Income and Deductions, Net in our Consolidated Income Statement for the year ended December 31, 2004.

In November 2004, Wisconsin Electric sold $250 million of unsecured 3.50% debentures due December 1, 2007. The securities were issued under an existing $665 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, Wisconsin Electric refinanced $147 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 March 2003, Wisconsin Energy sold $200 million of unsecured 6.20% Senior Notes due April 1, 2033. These securities were issued under a shelf registration statement filed with the SEC. The proceeds of the offering were used to repay a portion of our outstanding commercial paper as it matured.

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

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

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

Obligations Under Capital Leases: In 1997, Wisconsin Electric entered into a 25 year power purchase contract with an unaffiliated independent power producer. The contract, for 236 megawatts of firm capacity from a gas-fired cogeneration facility, includes no minimum energy requirements. When the contract expires in 2022, Wisconsin Electric may, at its option and with proper notice, renew for another ten years or purchase the generating facility at fair value or allow the contract to expire. We account for this contract as a capital lease and recorded the leased facility and corresponding obligation under the capital lease at the estimated fair

A-59

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 $24.3 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 deferred regulatory asset - 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.

Wisconsin Electric also has a nuclear fuel leasing arrangement with Wisconsin Electric Fuel Trust (Trust) which is treated as a capital lease. We lease and amortize the nuclear fuel to fuel expense as power is generated, generally over a period of 60 months. Lease payments include charges for the cost of fuel burned, financing costs and management fees. In the event that Wisconsin Electric or the Trust terminates the lease, the Trust would recover its unamortized cost of nuclear fuel from Wisconsin Electric. Under the lease terms, Wisconsin Electric is in effect the ultimate guarantor of the Trust’s commercial paper and line of credit borrowings that finance the investment in nuclear fuel. We 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 Wisconsin Electric’s 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:

A-60


Capital Lease Obligations	Purchase Power Commitment			Nuclear Fuel Lease			Total
	(Millions of Dollars)
2005	$	30.1		$	24.0		$	54.1
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	)

	$	160.0		$	31.1		$	191.1

Trust Preferred Securities: In March 1999, WEC Capital Trust I, a Delaware business trust of which we own all of the outstanding common securities, issued $200 million of 6.85% trust preferred securities to the public. The sole asset of WEC Capital Trust I was $206.2 million of 6.85% junior subordinated debentures issued by us and due March 31, 2039. The terms and interest payments on these debentures corresponded to the terms and distributions on the trust preferred securities. WEC Capital Trust I had been consolidated into our financial statements prior to adoption of Interpretation 46. In March 2004, WEC Capital Trust I, the issuer of our trust preferred securities, redeemed all of the $200 million of the outstanding trust preferred securities, which required us to redeem our long-term notes due to WEC Capital Trust I. We financed this redemption through the issuance of short-term commercial paper. In March 2004, we recorded approximately $5.9 million of costs associated with this early redemption, which are included in Other Income and Deductions, Net in our Consolidated Income Statement for the year ended December 31, 2004.

K — SHORT-TERM DEBT

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


	2004				2003
Short-Term Debt	Balance		Interest Rate		Balance		Interest Rate
	(Millions of Dollars, except for percentages)
Commercial paper	$	338.0	2.35	%	$	590.8	1.18	%

On December 31, 2004, we had approximately $1.2 billion of available unused lines of bank back-up credit facilities on a consolidated basis. We had approximately $338.0 million of total consolidated short-term debt outstanding on such date. Our bank back-up credit facilities mature beginning April 2006 through November 2007.

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


	2004		2003
	(Millions of Dollars, except for percentages)
Maximum Short-Term Debt Outstanding	$627.8		$930.7
Average Short-Term Debt Outstanding	434.9		642.9
Weighted Average Interest Rate	1.41	%	1.28	%

A-61

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

Wisconsin Energy’s bank back-up credit facilities require us to maintain a minimum ratio of consolidated EBITDA (Earnings before interest, taxes, depreciation and amortization) to consolidated interest expense. For the twelve months ended December 31, 2004 we were in compliance.

L — ASSET RETIREMENT OBLIGATIONS

SFAS 143, Accounting for Asset Retirement Obligations, primarily applies to the future decommissioning costs for our Point Beach Nuclear Plant (Point Beach). Prior to January 2003, we recorded a long-term liability for accrued nuclear decommissioning costs. See Note H for further information about the nuclear decommissioning of Point 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 12/31/03		Liabilities Incurred		Liabilities Settled		Accretion		Cash Flow Revisions		Balance at 12/31/04
	(Millions of Dollars)
Asset Retirement Obligations	$	732.0	$	—	$	7.1	$	37.3	$	—	$	762.2

M — 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 energy related physical and financial contracts in our regulated operations 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.

Wisvest - Connecticut LLC, which was sold December 6, 2002, had fuel oil contracts utilized to mitigate the commodity risk associated with generation costs. These contracts were defined as derivatives under SFAS 133 and did not qualify or were not designated for hedge accounting treatment. For the year ended December 31, 2002, we recorded non-cash, after - tax income of $12.7 million to reflect the changes in fuel oil prices during the year and the settlement of transactions.

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 for utility operations and gas used in testing a new generating unit under construction. 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 for utility operations are reported in earnings and amounts related to the new generating unit are capitalized.

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. The maximum length of time over which we are hedging our exposure to the variability in future cash flows of forecasted transactions as of December 31, 2004 was six months. We estimate that $0.6 million will be reclassified from Accumulated Other Comprehensive Income to earnings or capitalized to Plant during the first six months of 2005.

During March 2003, we settled several treasury lock agreements entered into earlier in the first quarter of 2003 and during the third quarter of 2002 to mitigate interest rate risk associated with the issuance of $200 million of long-term unsecured senior notes in

A-62

March 2003. As these agreements qualified for cash flow hedging accounting treatment under SFAS 133, the payment made upon settlement of these agreements is deferred in Accumulated Other Comprehensive Income and is being amortized as an increase to Interest Expense over the same period in which the interest cost is recognized in income.

We reclassified $0.8 million in treasury lock agreement settlement payments deferred in Accumulated Other Comprehensive Income, as an increase to Interest Expense for the year ended December 31, 2004. We estimate that during the next twelve months, $0.6 million will be reclassified from Accumulated Other Comprehensive Income as a reduction in earnings. We reclassified $0.8 million to Interest Expense for the year ended December 31, 2003.

In addition, during 2004, in conjunction with the redemption of $300 million of Wisconsin Energy 5.875% senior notes due April 1, 2006, $0.6 million of a treasury lock agreement settlement payment previously deferred in Accumulated Other Comprehensive Income was reclassified to Other Income and Deductions, Net.

N — FAIR VALUE OF FINANCIAL INSTRUMENTS

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


	2004				2003
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair 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	$	3,155.4	$	3,301.0	$	3,555.5	$	3,699.0

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 H). The fair value of our preferred stock is estimated based upon the quoted market value for the same or similar issues. The fair value of our long-term debt, including the current portion of long-term debt but excluding capitalized leases, is estimated based upon quoted market value for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the issuing company’s bond rating and the present value of future cash flows. The fair values of gas commodity instruments are equal to their carrying values as of December 31, 2004.

O — BENEFITS

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

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

A-63


	Pension Benefits									Other Post-retirement Benefits
Status of Benefit Plans	2004			2003			2002			2004			2003			2002
	(Millions of Dollars)
Change in Benefit Obligation
Benefit Obligation at January 1	$	1,100.6		$	1,010.0		$	974.8		$	366.0		$	327.6		$	262.5
Service cost		30.2			30.6			22.1			12.0			10.8			8.0
Interest cost		69.1			67.4			68.5			21.8			22.3			19.8
Plan participants’ contributions		—			—			—			—			0.9			6.9
Plan amendments		2.0			19.4			(1.2	)		0.7			5.1			2.3
Actuarial loss		103.8			33.7			32.8			9.9			14.8			51.6
Acquisitions / divestitures		—			—			(20.3	)		—			—			(1.9	)
Benefits paid		(100.7	)		(60.5	)		(66.7	)		(14.9	)		(15.5	)		(21.6	)

Benefit Obligation at December 31	$	1,205.0		$	1,100.6		$	1,010.0		$	395.5		$	366.0		$	327.6

Change in Plan Assets
Fair Value at January 1	$	926.3		$	801.6		$	993.9		$	166.8		$	137.8		$	148.8
Actual earnings (loss) on plan assets		95.4			183.0			(119.0	)		12.3			24.7			(11.1	)
Employer contributions		77.5			2.2			5.4			19.4			18.9			16.0
Plan participants’ contributions		—			—			—			—			0.9			6.9
Acquisitions / divestitures		—			—			(12.0	)		—			—			(1.2	)
Benefits paid		(100.7	)		(60.5	)		(66.7	)		(14.9	)		(15.5	)		(21.6	)

Fair Value at December 31	$	998.5		$	926.3		$	801.6		$	183.6		$	166.8		$	137.8

Funded Status of Plans
Funded status at December 31		($206.5	)		($174.3	)		($208.4	)		($211.8	)		($199.2	)		($189.8	)
Unrecognized
Net actuarial loss		360.7			281.6			352.1			129.2			124.2			131.1
Prior service cost		34.0			36.8			22.2			6.9			6.9			2.4
Net transition (asset) obligation		(0.1	)		(2.3	)		(4.6	)		12.6			14.2			15.8

Net Asset (Accrued Benefit Cost)	$	188.1		$	141.8		$	161.3			($63.1	)		($53.9	)		($40.5	)

Amounts recognized in the Balance Sheet consist of:
Regulatory assets (See Note C)	$	342.8		$	189.4					$	—		$	—
Other deferred charges		34.3			45.1						51.5			50.0
Minimum pension liability		(152.8	)		(34.7	)					—			—
Other long-term liabilities		(45.4	)		(61.0	)					(114.6	)		(103.9	)
Other comprehensive income		9.2			3.0						—			—

Net amount recognized at end of year	$	188.1		$	141.8						($63.1	)		($53.9	)

The accumulated benefit obligation for all defined benefit plans was $1,195.5 million and $1,013.5 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 are as follows:


	2004		2003
	(Millions of Dollars)
Projected benefit obligation	$	1,189.1	$	1,081.2
Accumulated benefit obligation	$	1,181.1	$	994.8
Fair value of plan assets	$	998.5	$	926.3

A-64

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


Benefit Plan Cost Components	Pension Benefits									Other Post-retirement Benefits
Benefit Plan Cost Components	2004			2003			2002			2004			2003			2002
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	30.2		$	30.6		$	22.1		$	12.0		$	10.8		$	8.0
Interest cost		69.1			67.4			68.5			21.8			22.3			19.8
Expected return on plan assets		(85.6	)		(87.3	)		(93.6	)		(14.1	)		(11.6	)		(12.6	)
Amortization of:
Transition (asset) obligation		(2.3	)		(2.3	)		(2.3	)		1.6			1.6			1.6
Prior service cost		4.8			4.8			3.4			0.7			0.6			0.2
Actuarial loss		15.0			3.4			3.1			6.6			8.6			4.6

Net Periodic Benefit Cost	$	31.2		$	16.6		$	1.2		$	28.6		$	32.3		$	21.6

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		4.0 to 5.0			4.0 to 5.0			4.0 to 5.0			4.0 to 5.0			4.0 to 5.0			4.0 to 5.0
Weighted-Average assumptions used to determine net cost for year ended Dec. 31
Discount rate		6.25	%		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		4.0 to 5.0			4.0 to 5.0			4.0 to 5.0			4.0 to 5.0			4.0 to 5.0			4.0 to 5.0
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

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

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	$	28.7	($	25.9	)
Total of service and interest cost components	$	3.5		($3.0	)

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 FASB 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 reduction of $24.1 million in our benefit obligation and reduced our 2004 SFAS 106 expense by $4.7 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

A-65

& 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. The final regulations have not yet addressed account based plans similar to the Cash Balance Medical Plan covering former Wisconsin Gas employees. These plans are expected to be addressed by the regulations in February 2005. At this point, we do not expect the final regulations will change our estimates.

Plan Assets: In our opinion, current pension trust assets and amounts which are expected to be contributed to the trusts in the future will be adequate to meet pension payment obligations to current and future retirees. Our pension plans asset allocation at December 31, 2004 and 2003, and our target allocation for 2005, by asset category, are as follows:


Asset Category	Target Allocation 2005		Percentage of Pension Plans Assets at December 31
Asset Category	Target Allocation 2005		2004		2003
Equity Securities	72	%	73	%	76	%
Debt Securities	28	%	27	%	24	%

Total	100	%	100	%	100	%

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

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

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:


Asset Category	Target Allocation 2005		Percentage of Other Benefit Plans Assets at December 31
Asset Category	Target Allocation 2005		2004		2003
Equity Securities	46	%	45	%	48	%
Debt Securities	53	%	54	%	50	%
Other	1	%	1	%	2	%

Total	100	%	100	%	100	%

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

Cashflows:


Employer Contributions	Pension Benefits		Other Post- Retirement Benefits
	(Millions of Dollars)
2003	$	2.2	$	18.9
2004	$	77.5	$	19.4
2005 (Expected)	$	5.7	$	20.8

Of the $5.7 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 $55.7 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:

A-66


Year	Pension		Gross Other Post Employment Benefits		Expected Medicare Part D Subsidy
	(Millions of Dollars)
2005	$	81.3	$	21.9	$	—
2006	$	85.2	$	22.9		($1.2	)
2007	$	91.8	$	23.9		($1.3	)
2008	$	92.4	$	24.7		($1.4	)
2009	$	99.8	$	25.6		($1.5	)
2010-2014	$	534.5	$	151.4		($8.7	)

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 $10.5 million, $10.1 million and $10.0 million during 2004, 2003 and 2002, respectively.

Severance Plans: For the year ended December 31, 2004 we incurred $30.5 million ($18.3 million after-tax) of severance costs. The majority of the severance costs related to an enhanced severance package offered to selected management employees of Wisconsin Energy and its subsidiaries who voluntarily resigned in the fourth quarter of 2004. The program was enacted to help reduce the upward pressure on operating expenses.

Approximately 200 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.

P — GUARANTEES

We enter into various guarantees to provide financial and performance assurance to third parties on behalf of our affiliates. As of December 31, 2004 we had the following guarantees:


	Maximum Potential Future Payments		Outstanding Dec 31, 2004		Liability Recorded at Dec 31, 2004
	(Millions of Dollars)
Wisconsin Energy
Non-Utility Energy	$	—	$	—	$	—
Other		45.5		45.5		—

Wisconsin Electric		231.0		0.1		—
Subsidiary		20.5		9.7		0.1

Total	$	297.0	$	55.3	$	0.1

A Non-Utility Energy guarantee in support of Wisvest-Connecticut, which we sold in December 2002 to PSEG, provides financial assurance for potential obligations relating to environmental remediation under the original purchase agreement for Wisvest-Connecticut with United Illuminating. The potential obligations for environmental remediation, which are unlimited, are reimbursable by PSEG under the terms of the sale agreement in the event that we are required to perform under the guarantee.

Other guarantees support obligations of our affiliates to third parties under loan agreements, surety bonds and obligations under legal proceedings of the manufacturing business which was sold in July 2004. In the event our affiliates or the manufacturing business fail to perform, we would be responsible for the obligations.

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

A-67

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

Postemployment benefits: Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $15.6 million as of December 31, 2004.

Q — SEGMENT REPORTING

Our reportable operating segments at December 31, 2004 include a utility energy segment and a non-utility energy segment. Additionally, our manufacturing segment was an operating segment prior to the sale of the segment in July 2004 to Pentair, Inc. We have organized our reportable operating segments based in part upon the regulatory environment in which our utility subsidiaries operate. In addition, the segments are managed separately because each business requires different technology and marketing strategies. The accounting policies of the reportable operating segments are the same as those described in Note A.

Our utility energy segment primarily includes our electric and natural gas utility operations. Our electric utility operation engages in the generation, distribution and sale of electric energy in southeastern (including metropolitan Milwaukee), east central and northern Wisconsin and in the Upper Peninsula of Michigan. Our natural gas utility operation is engaged in the purchase, distribution and sale of natural gas to retail customers and the transportation of customer-owned natural gas throughout Wisconsin. Our non-utility energy segment derives its revenues primarily from the ownership of electric power generating facilities for long-term lease to Wisconsin Electric and economic interests in other energy-related entities.

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. The segment information below includes non-cash impairment charges of $149.0 million ($96.9 million after tax or $0.81 per share) in 2004, $45.6 million ($29.7 million after tax or $0.25 per share), net of gains in 2003 and $141.5 million ($92.0 million after tax or $0.79 per share) in 2002, primarily related to the Non-Utility Energy segment (See Notes E and F). Substantially all of our long-lived assets and operations are domestic.


	Reportable Operating Segments
	Energy					Manufacturing (c)			Other (a), Corp. (c) & Reconciling Elims. (b)			Total Consolidated
Year Ended	Utility		Non-Utility			Manufacturing (c)			Other (a), Corp. (c) & Reconciling Elims. (b)			Total Consolidated
	(Millions of Dollars)
December 31, 2004

Operating Revenues (b)	$	3,375.4	$	21.6		$	—		$	34.1		$	3,431.1
Depreciation, Decommissioning and Amortization	$	315.5	$	6.1		$	—		$	5.5		$	327.1
Operating Income (Loss)	$	528.6		($120.4	)	($	3.0	)		($25.4	)	$	379.8
Equity in Earnings (Losses) of Unconsolidated Affiliates	$	30.1	$	—		$	—		$	0.8		$	30.9
Interest Expense	$	108.6	$	14.6		$	9.9		$	60.3		$	193.4
Income Tax Expense	$	174.5		($48.1	)		($5.0	)		($41.1	)	$	80.3
Income from Discontinued Operations, Net	$	—	$	—		$	31.9		$	152.3		$	184.2
Net Income (Loss)	$	283.9		($86.6	)	$	26.6		$	82.5		$	306.4
Capital Expenditures	$	426.5	$	191.0		$	10.7		$	19.3		$	647.5
Total Assets	$	8,775.3	$	506.8		$	—		$	283.3		$	9,565.4

A-68


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

Operating Revenues (b)	$	3,263.9	$	14.4		$	—		$	30.0		$	3,308.3
Depreciation, Decommissioning and Amortization	$	316.2	$	7.4		$	—		$	6.2		$	329.8
Operating Income (Loss)	$	544.1		($61.5	)		($1.7	)	$	1.3		$	482.2
Equity in Earnings (Losses) of Unconsolidated Affiliates	$	25.9		($8.9	)	$	—		$	5.2		$	22.2
Interest Expense	$	104.1	$	17.7		$	18.6		$	73.4		$	213.8
Income Tax Expense	$	182.6		($35.2	)		($7.0	)		($30.2	)	$	110.2
Income from Discontinued Operations, Net	$	—	$	—		$	43.9		$	—		$	43.9
Net Income (Loss)	$	294.1		($52.7	)	$	30.8			($27.9	)	$	244.3
Capital Expenditures	$	455.6	$	163.6		$	10.4		$	29.8		$	659.4
Total Assets	$	8,303.9	$	397.6		$	938.0		$	375.0		$	10,014.5
December 31, 2002

Operating Revenues (b)	$	2,852.1	$	167.2		$	—		$	31.7		$	3,051.0
Depreciation, Decommissioning and Amortization	$	308.3	$	5.1		$	—		$	5.1		$	318.5
Operating Income (Loss)	$	562.1		($132.0	)		($1.4	)		($28.3	)	$	400.4
Equity in Earnings (Losses) of Unconsolidated Affiliates	$	23.4		($8.5	)	$	—		$	8.0		$	22.9
Interest Expense	$	107.3	$	25.9		$	16.2		$	77.7		$	227.1
Income Tax Expense	$	184.1		($49.3	)		($6.1	)		($43.4	)	$	85.3
Income from Discontinued Operations, Net	$	—	$	—		$	35.3		$	—		$	35.3
Net Income (Loss)	$	295.2		($94.4	)	$	24.0			($57.8	)	$	167.0
Capital Expenditures	$	405.4	$	92.7		$	15.0		$	43.7		$	556.8
Total Assets	$	7,820.5	$	348.7		$	925.5		$	371.2		$	9,465.9

(a)

Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark, non-utility investment in renewable energy and recycling technologies by Minergy as well as interest on corporate debt and in 2004, the gain on the sale of the manufacturing segment.

(b)	An elimination for intersegment revenues is included in Operating Revenues of $6.8 million, $5.9 million and $3.1 million for 2004, 2003 and 2002, respectively.

(c)

The sale of our manufacturing segment was completed effective July 31, 2004. The financial information presented for the manufacturing segment in 2004 is for the seven months ended July 31, 2004. The gain on the sale of the manufacturing segment is reflected in Corporate and Other. Certain corporate overheads reported in the manufacturing segment continue to exist following the sale and are reported in continuing operations. Certain other corporate costs are directly attributable to the discontinued operations.

R — RELATED PARTIES

American Transmission Company: We have a 37.8% interest in ATC, a regional transmission company established in 2000 under Wisconsin legislation. During 2004, 2003 and 2002, we paid ATC $105.8 million, $94.4 million and $87.3 million, respectively, for transmission services. We also provide a variety of operational, maintenance and project management work for ATC, which are reimbursed to us by ATC.

Guardian Pipeline: We have a one third ownership interest in Guardian Pipeline, L.L.C., which owns and operates an interstate natural gas pipeline. Wisconsin Gas has committed to purchase 650,000 dekatherms per day of capacity (approximately 87% of the pipeline’s total capacity) under the terms of a 10 year transportation agreement expiring December 2012.

A-69

S — COMMITMENTS AND CONTINGENCIES

Capital Expenditures: We have made certain commitments in connection with 2005 capital expenditures.

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

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


	(Millions of Dollars)
2005	$	50.4
2006		50.0
2007		49.3
2008		33.8
2009		20.8
Thereafter		66.1

	$	270.4

Environmental Matters: We periodically review our exposure for environmental remediation costs as evidence becomes available indicating that our liability has changed. Given current information, including the following, 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 previously used by Wisconsin Electric or Wisconsin Gas, and coal ash disposal/landfill sites used by Wisconsin Electric, as discussed below. We are working with the Wisconsin Department of Natural Resources in our investigation and remediation planning. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

Manufactured Gas Plant Sites: We have identified fourteen sites at which Wisconsin Electric, Wisconsin Gas, or a predecessor company historically owned or operated a manufactured gas plant. We have completed planned remediation activities at five of those sites. Remediation at additional sites is currently being performed, and other sites are being investigated or monitored. We have identified additional sites that may have been impacted by historical manufactured gas plant activities. Based upon ongoing analysis, we estimate that the future costs for detailed site investigation and future remediation costs may range from $25-$50 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 $26.6 million related to future remediation costs.

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

Ash Landfill Sites: Wisconsin Electric aggressively seeks environmentally acceptable, beneficial uses for its coal combustion by-products. However, these coal-ash by-products have been, and to a small degree, continue to be disposed in company-owned, licensed landfills. Some early designed and constructed landfills may allow the release of low levels of constituents resulting in the need for various levels of monitoring or adjusting. Where Wisconsin Electric has become aware of these conditions, efforts have been expended to define the nature and extent of any release, and work has been performed to address these conditions. The costs of these efforts are included in the fuel costs of Wisconsin Electric. During 2004, 2003 and 2002, Wisconsin Electric 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: Wisconsin Electric received a request for information in December 2000 from the United States Environmental Protection Agency (EPA) regional offices pursuant to Section 114(a) of the Clean Air Act and a supplemental request in December 2002. In April 2003, Wisconsin Electric and EPA announced that a consent decree had been reached which resolved all

A-70

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, Wisconsin Electric will significantly reduce its air emissions from its 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 EPA, Wisconsin Electric will conduct a full scale demonstration at its 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 Wisconsin Electric 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 our Power the Future plan. Wisconsin Electric also agreed to pay a civil penalty of $3.2 million which was charged to earnings in the second quarter of 2003.

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 on February 28, 2005. Following the submission of briefs, the court may convene additional hearings.

A-71

LOGO

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Wisconsin Energy Corporation and subsidiaries (the “Company”) 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 perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of 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 L, on January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 9, 2005 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Deloitte & Touche LLP

Milwaukee, Wisconsin

February 9, 2005

A-72

LOGO

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Wisconsin Energy Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and consolidated statement of capitalization as of December 31, 2004, and the related consolidated statements of income, common equity and cash flows for the year ended December 31, 2004 of the Company and our report dated February 9, 2005 expressed an unqualified opinion on those financial statements.

Deloitte & Touche LLP

Milwaukee, Wisconsin

February 9, 2005

A-73

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal Control - Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2004.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of our financial statements has issued an attestation report on management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004. Deloitte & Touche’s report is included in this report.

Changes in Internal Control Over Financial Reporting

There has not been any change in our internal control over financial reporting during the fourth quarter of 2004 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

A-74

MARKET FOR REGISTRANT’S COMMON

EQUITY AND RELATED STOCKHOLDER MATTERS

NUMBER OF COMMON STOCKHOLDERS

As of December 31, 2004, based upon the number of Wisconsin Energy Corporation stockholder accounts (including accounts in our dividend reinvestment and stock purchase plan), we had 58,168 registered stockholders.

COMMON STOCK LISTING AND TRADING

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

DIVIDENDS AND COMMON STOCK PRICES

Common Stock Dividends of Wisconsin Energy: Cash dividends on our common stock, as declared by the Board of Directors, are normally paid on or about the first day of March, June, September and December of each year. We review our dividend policy on a regular basis. Subject to any regulatory restrictions or other limitations on the payment of dividends, future dividends will be at the discretion of the Board of Directors and will depend upon, among other factors, earnings, financial condition and other requirements. For information regarding restrictions on the ability of our subsidiaries to pay us dividends see “Note I — Common Equity” in the Notes to Consolidated Financial Statements.

On January 20, 2005, our Board of Directors announced that it increased our common stock quarterly dividend rate by 4.8%, to $0.22 per share. With the increase, the new annual dividend rate will be $0.88 per share. The Board has established a goal of increasing the annual dividend at a rate of approximately half of the expected rate of growth in earnings, subject to the factors referred to above.

Range of Wisconsin Energy Common Stock Prices and Dividends:


	2004						2003
Quarter	High		Low		Dividend		High		Low		Dividend
First	$	34.30	$	31.57	$	0.20	$	26.60	$	22.56	$	0.20
Second	$	33.00	$	29.50		0.21	$	29.75	$	25.00		0.20
Third	$	32.95	$	31.12		0.21	$	30.75	$	26.54		0.20
Fourth	$	34.60	$	31.50		0.21	$	33.68	$	30.63		0.20

Year	$	34.60	$	29.50	$	0.83	$	33.68	$	22.56	$	0.80

A-75

BUSINESS OF THE COMPANY

Wisconsin Energy Corporation was incorporated in the state of Wisconsin in 1981 and became a diversified holding company in 1986. We maintain our principal executive offices in Milwaukee, Wisconsin. Historically, we conducted our operations primarily in three operating segments: a utility energy segment, a non-utility energy segment and a manufacturing segment. The sale of our manufacturing segment was completed effective July 31, 2004 and this segment is reported as discontinued operations. Our primary subsidiaries are Wisconsin Electric Power Company (Wisconsin Electric), Wisconsin Gas LLC, formerly Wisconsin Gas Company (Wisconsin Gas) and W.E. Power, LLC (We Power).

Utility Energy Segment: Our utility energy segment consists of: Wisconsin Electric, which serves approximately 1,081,400 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 437,800 gas customers in Wisconsin and approximately 460 steam customers in metro Milwaukee, Wisconsin; Wisconsin Gas, which serves approximately 577,000 gas customers in Wisconsin and about 2,660 water customers in suburban Milwaukee, Wisconsin; and Edison Sault Electric Company (Edison Sault), which serves approximately 22,700 electric customers in the Upper Peninsula of Michigan. In April 2002, Wisconsin Electric and Wisconsin Gas began doing business under the trade name of “We Energies”.

Non-Utility Energy Segment: Our non-utility energy segment consists of We Power and Wisvest Corporation (Wisvest). We Power was formed in 2001 to design, construct, own, finance and lease the new generating capacity included in our Power the Future strategy. See Management’s Discussion and Analysis of Financial Condition and Results of Operations for more information on Power the Future. Wisvest owns an investment in an electric generating facility and has investments in other energy-related entities and assets. We have substantially reduced the operations of Wisvest since 2000.

Manufacturing Segment: Our manufacturing segment consisted of WICOR Industries, LLC (WICOR Industries), an intermediary holding company, and its three primary subsidiaries: Sta-Rite Industries, LLC, SHURflo, LLC and Hypro, LLC, which are manufacturers of pumps, water treatment products and fluid handling equipment with manufacturing, sales and distribution facilities in the United States and several other countries. Effective July 31, 2004, we sold this segment to Pentair, Inc. (Pentair).

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

A-76

DIRECTORS AND EXECUTIVE OFFICERS

DIRECTORS

The information under “Proposal 1: Election of Directors - Terms Expiring in 2006” in Wisconsin Energy Corporation’s definitive proxy statement dated March 18, 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. Rappé

•

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.

A-77

ANNUAL CERTIFICATIONS

We have filed the required certifications of our Chief Executive Officer and Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002 regarding the quality of our public disclosures as Exhibits 31.1 and 31.2 to our Annual Report on Form 10-K for the year ended December 31, 2004. The certification of our Chief Executive Officer regarding compliance with the New York Stock Exchange (NYSE) corporate governance listing standards required by NYSE Rule 303A.12 will be filed with the NYSE following the 2005 Annual Meeting of Stockholders. Last year, we filed this certification with the NYSE on May 20, 2004.

A-78

LOGO


231 W. Michigan Street
P.O. Box 1331
Milwaukee, WI 53201
1.800.558.9663		9341-PS-05
www.wisconsinenergy.com		2K5008-1518-RRD-110K


		YOUR VOTE IS IMPORTANT VOTE BY INTERNET / TELEPHONE 24 HOURS A DAY, 7 DAYS A WEEK

INTERNET		TELEPHONE		MAIL

https://www.proxyvotenow.com/wec	OR	Toll free: 1-866-756-9925	OR
• Go to the website address listed above.		• Use any touch-tone telephone.		• Mark, sign and date your proxy card.
• Have your proxy card ready.		• Have your proxy card ready.		• Detach your proxy card.
• Follow the simple instructions that appear on your computer screen.		• Follow the simple recorded instructions.		• Return your proxy card in the postage-paid envelope provided.
			Your vote is important. Please vote immediately.

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

Please Sign, Date and Return the Proxy Card Promptly Using the Enclosed Envelope.

Votes must be indicated

(x) in Black or Blue ink.

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

Election of Directors

FOR ALL

WITHHOLD

FOR ALL

EXCEPTIONS

Ratification of Deloitte & Touche LLP as independent auditors for 2005.

FOR

AGAINST

ABSTAIN

Nominees: 01 - John F. Ahearne
02 - John F. Bergstrom
03 - Barbara L. Bowles

04 - Robert A. Cornog

05 - Curt S. Culver

06 - Gale E. Klappa

07 - Ulice Payne, Jr.

08 - Frederick P. Stratton, Jr.

09 - George E. Wardeberg

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

(INSTRUCTIONS: To withhold authority to vote for any individual nominee, strike a line through that nominee’s name and check the “Exceptions” box above.)

Check here if you plan to attend the annual meeting.

To change your address, please mark this box.

SCAN LINE

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

Date

Stockholder sign here

Co-Owner sign here


Wisconsin Energy Corporation Annual Meeting of Stockholders Thursday, May 5, 2005 10:00 a.m. Central Time Concordia University Wisconsin R. John Buuck Field House 12800 North Lake Shore Drive Mequon, WI 53097
If you plan to attend in person, please check the box on the reverse side and bring this card with you to the meeting.
Name		________________________________________
		________________________________________
Address		________________________________________
		________________________________________
		________________________________________

Wisconsin Energy Corporation

Proxy / Voting Instructions for the Annual Meeting of Stockholders

May 5, 2005

This PROXY is solicited by the Board of Directors for use at the Annual Meeting of Stockholders on May 5, 2005. Your shares of stock will be voted as you specify on the reverse side of this card. If no choice is specified, your PROXY will be voted “For” Items 1 and 2, and in the discretion of the proxy holder, on any other matter which may properly come before the Annual Meeting of Stockholders and all adjournments or postponements of the meeting.

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

1. Election of John F. Ahearne, John F. Bergstrom, Barbara L. Bowles, Robert A. Cornog, Curt S. Culver, Gale E. Klappa, Ulice Payne, Jr., Frederick P. Stratton, Jr., and George E. Wardeberg as Directors.

2. Ratification of Deloitte & Touche LLP as independent auditors for 2005.

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

WISCONSIN ENERGY CORPORATION

P.O. BOX 11468

NEW YORK, N.Y. 10203-0468

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