Edgar Filing: WISCONSIN ENERGY CORP

Notice & Proxy Statement

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

SCHEDULE 14A

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LOGO

NOTICE OF ANNUAL MEETING OF STOCKHOLDERS

March 16, 2006

To the Stockholders of Wisconsin Energy Corporation:

You are cordially invited to attend the 2006 Annual Meeting of Stockholders. An admission ticket will be required to enter the meeting. Your admission ticket, which also includes a map to the meeting, is attached to your proxy statement. Instructions on how to obtain an admission ticket if you received your proxy materials electronically are provided on page 2 of the proxy statement. 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 4, 2006
		10:00 a.m., Central time

WHERE:		Pettit National Ice Center
		500 South 84^th Street
		Milwaukee, Wisconsin 53214

ITEMS OF BUSINESS:		• Election of nine directors for terms expiring in 2007.

		• Ratification of Deloitte & Touche LLP as independent auditors for 2006.

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

RECORD DATE:		February 24, 2006

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
Annual Meeting Admission Ticket

Proxy Statement

General Information – Frequently Asked Questions		1

Proposals to be Voted Upon		3

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

Information About Nominees for Election to the Board of Directors		4

Proposal 2: Ratification of Deloitte & Touche LLP as Independent Auditors for 2006		6

Independent Auditors’ Fees and Services		7

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

Performance Graph		18

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

Availability of Form 10-K		27

Appendix A: Audit and Oversight Committee Charter		A-1

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

PROXY STATEMENT

This proxy statement is being furnished to stockholders beginning on or about March 16, 2006, 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 Thursday, May 4, 2006 (the “Meeting”) at 10:00 a.m., Central time, at the Pettit National Ice Center located at 500 South 84^th Street, Milwaukee, Wisconsin 53214, and at all adjournments or postponements of the Meeting, for the purposes listed in the preceding Notice of Annual Meeting of Stockholders.

GENERAL INFORMATION – FREQUENTLY ASKED QUESTIONS


What am I voting on?		Proposal 1: Election of nine directors for terms expiring in 2007.

		Proposal 2: Ratification of Deloitte & Touche LLP as independent auditors for 2006.

		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 2006.

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 24, 2006, 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 Thursday, May 4, 2006.

		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 in 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 116,980,775 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.

How can I attend the Meeting?		The Meeting is open to all stockholders of WEC. You must bring an admission ticket or other evidence of your ownership to enter the Meeting. If you received proxy materials by mail, your admission ticket is attached to your proxy statement. The admission ticket admits the stockholder and one guest. If your shares are jointly owned or you participate in our “householding” program and you need an additional ticket, or you have questions regarding this process, contact Stockholder Services, 231 West Michigan Street, P.O. Box 1331, Milwaukee, Wisconsin 53201 or call (800) 881-5882.

How do I obtain an admission ticket if I received my proxy materials electronically?		If your shares are registered in your name, you can print an admission ticket by following the instructions provided in the e-mail which transmitted your proxy materials. If you hold your shares through a bank, brokerage firm, or other nominee, call (800) 881-5882 or write to Stockholder Services at the above address to request an admission ticket. We will send you an admission ticket upon verification of your ownership. You may also bring a copy of your account statement or other evidence of your ownership as of the record date to the Meeting. This document will serve as your admission ticket.

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 (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 (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 (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 2007

WEC’s Bylaws require each director to be elected annually to hold office for a one-year term. 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

•

Thomas J. Fischer

•

Gale E. Klappa

•

Ulice Payne, Jr.

•

Frederick P. Stratton, Jr.

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, Thomas J. Fischer was elected as a director by the Board effective July 21, 2005. George E. Wardeberg 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. Proxies may not be voted for more than nine persons in the election of directors.

Each nominee has consented to being nominated and to serve if elected. In the unlikely event that any nominee becomes unable to serve for any reason, the proxies will be voted for a substitute nominee selected by the 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) do business as We Energies and are wholly-owned subsidiaries of Wisconsin Energy Corporation. Effective July 28, 2004, Wisconsin Gas Company converted to a Wisconsin 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 Wisconsin Gas Company. Ages are as of March 16, 2006.


		John F. Ahearne. Age 71. • 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 59. • 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 and Midwest Air Group, Inc. Director Bergstrom is also a director of Sensient Technologies Corporation, but his term will expire in April 2006, and he will not stand for re-election. • 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 58. • Profit Investment Management – Vice Chair since January 2006. Profit Investment Management is an investment advisory firm. • The Kenwood Group, Inc. – Chairman since 2000. Chief Executive Officer from 1989 to December 2005. President from 1989 to 2000. The Kenwood Group is an investment advisory firm and is a subsidiary of Profit Investment Management. • Director of Black & Decker Corporation and Dollar General Corporation. • Director of Wisconsin Energy Corporation and Wisconsin Electric Power Company since 1998. Director of Wisconsin Gas LLC since 2000.

		Robert A. Cornog. Age 65. • 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. and Oshkosh Truck Corporation. • 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 53. • MGIC Investment Corporation – Chairman since 2005, Chief Executive Officer since 2000 and President from 1999 to January 2006. MGIC Investment Corporation is the parent of Mortgage Guaranty Insurance Corporation. • Mortgage Guaranty Insurance Corporation – Chairman since 2005, Chief Executive Officer since 1999 and President from 1996 to January 2006. 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 2004.

		Thomas J. Fischer. Age 58. • Fischer Financial Consulting LLC – Principal since 2002. Fischer Financial Consulting LLC provides consulting on corporate financial, accounting and governance matters. • Retired Partner of Arthur Andersen LLP from 1980 to 2002 (Managing Partner – Milwaukee office from 1993 to 2002). Arthur Andersen LLP was an independent public accounting firm. • Director of Actuant Corporation, Badger Meter, Inc. and Regal-Beloit Corporation. • Director of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas LLC since July 2005.

		Gale E. Klappa. Age 55. • 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. • The 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. The 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 50. • Addison-Clifton, LLC – Managing Member since 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. and Midwest Air Group, Inc. Trustee of The Northwestern Mutual Life Insurance Company. • Director of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas LLC since 2003.

		Frederick P. Stratton, Jr. Age 66. • 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.

PROPOSAL 2: RATIFICATION OF DELOITTE & TOUCHE LLP AS INDEPENDENT AUDITORS FOR 2006

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, 2006. 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, 2005, 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 2006 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 2006.

INDEPENDENT AUDITORS’ FEES AND SERVICES

Pre-Approval Policy. The Audit and Oversight Committee has 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 2005 and 2004 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.


	2005		2004
Audit Fees ⁽¹⁾	$	1,426,755	$	1,540,156
Audit-Related Fees ⁽²⁾		37,410		199,000
Tax Fees ⁽³⁾		16,978		216,684
All Other Fees ⁽⁴⁾		2,750		—

Total	$	1,483,893	$	1,955,840

⁽¹⁾

Audit Fees consist of fees for professional services rendered in connection with the audits of (i) annual financial statements of the Company and its subsidiaries, (ii) management’s assessment of the effectiveness of internal control over financial reporting and (iii) the effectiveness of internal control over financial reporting. This category also includes reviews 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.

⁽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 consultations regarding implementation of accounting standards and due diligence related to mergers and acquisitions. In 2004, audit-related fees also include fees for professional services rendered for benefit plan audits. Beginning in 2005, Deloitte & Touche LLP no longer audits the Company’s benefit plans.

⁽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 2005 or 2004.

⁽⁴⁾	All Other Fees consist of costs for certain employees to attend an accounting/tax seminar hosted by Deloitte & Touche LLP in 2005. Deloitte & Touche did not provide any services in 2004 that should be reported in this category.

CORPORATE GOVERNANCE – FREQUENTLY ASKED QUESTIONS


Does WEC have Corporate Governance Guidelines?		Yes, since 1996 the Board has maintained Corporate Governance Guidelines that provide a framework under which it conducts business. The Corporate Governance Committee reviews the Guidelines annually to ensure that the Board is providing 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 at the same time serves or served 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, or legal counsel to the Company or to a member of the Company’s senior management, or a significant supplier of the Company;

		• 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 well as whether a director has any relationships with WEC’s affiliates for certain of the above criteria, when determining the director’s independence. Any relationship between a director and the Company not meeting the above criteria is considered an immaterial relationship with the Company for purposes of determining independence.

Who are the independent directors?		The Board has affirmatively determined that Directors Ahearne, Bergstrom, Bowles, Cornog, Culver, Fischer, 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 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 Audit and Oversight Committee charter is attached as Appendix A. 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 Bowles, 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 communication received as set forth above will be opened by the Corporate Secretary for the sole purpose of confirming the contents represent a message to the Company’s directors. All communication, other than advertising, promotion 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 with constituencies, demonstrated 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 compares the performance of each committee with the requirements of its charter. The results of the annual evaluations are used by each committee to identify both its strengths and areas where its governance practices can be improved. 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 Frederick P. Stratton, Jr. (Chair), John F. Bergstrom, Barbara L. Bowles, Robert A. Cornog, Curt S. Culver, Thomas J. Fischer and Ulice Payne, Jr. qualify as audit committee financial experts within the meaning of Securities and Exchange Commission rules. Director Fischer serves on the audit committee of three other public companies. The Board determined that his service on these other audit committees will not impair Director Fischer’s ability to effectively serve on the Audit and Oversight Committee. No other 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 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 2007 Annual Meeting of Stockholders must submit the candidates’ names and qualifications to the Corporate Governance Committee no later than November 1, 2006, 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 2007 Annual Meeting of Stockholders?		Stockholders who intend to have a proposal considered for inclusion in the Company’s proxy materials for presentation at the 2007 Annual Meeting of Stockholders must submit the proposal to the Company no later than November 16, 2006.
		Stockholders who intend to present a proposal at the 2007 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 2007 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 2007 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 current directors attended the 2005 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. The site includes 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 Frederick P. Stratton, Jr., Chair John F. Bergstrom Barbara L. Bowles Robert A. Cornog Curt S. Culver Thomas J. Fischer Ulice Payne, 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 2005.

Compensation John F. Bergstrom, Chair John F. Ahearne Ulice Payne, Jr.		• 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 five meetings in 2005 and executed one signed, written unanimous consent.

Corporate Governance Barbara L. Bowles, Chair Robert A. Cornog Curt S. Culver		• 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 two meetings in 2005 and executed one signed, written unanimous consent.

Finance Curt S. Culver, Chair John F. Bergstrom Barbara L. Bowles Robert A. Cornog Ulice Payne, Jr. Frederick P. Stratton, 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 five meetings in 2005.

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 2005. The Board dissolved the Nuclear Oversight Committee in 2005, but named Director Ahearne as lead nuclear director.

In addition to the number of committee meetings listed in the preceding table, the Board met six times in 2005 and executed two signed, written unanimous consents. The average meeting attendance during the year was 95%. No director attended fewer than 87% 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, and is attached hereto as Appendix A.

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 2006, 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 provide reasonable assurance regarding 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 2005. 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 provide reasonable assurance regarding 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, and we discussed with Deloitte & Touche LLP matters required by Statement on Auditing Standards No. 61, as amended, relating to communications with audit committees, 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, 2005 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.

Frederick P. Stratton, Jr., Committee Chair

John F. Bergstrom

Barbara L. Bowles

Robert A. Cornog

Curt S. Culver

Thomas J. Fischer

Ulice Payne, Jr.

COMPENSATION OF THE BOARD OF DIRECTORS

During 2005, each non-employee director received an annual retainer fee of $36,000. 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. Non-employee directors were paid $300 for each signed, written unanimous consent in lieu of a meeting. The lead nuclear director received a quarterly retainer of $1,250, an attendance fee of $1,500 for each business meeting/site visit and a per diem fee of $1,250 for travel on Company business for each day on which a business meeting/site visit was not also held. Each non-employee director also 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. 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 do not receive any directors’ fees.

For 2006, the fees paid to non-employee directors will be the same as in 2005. In addition, each non-employee director received on January 3, 2006, the 2006 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 assets of 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. In addition, the Board has 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.

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. 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 executive officers 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 (consisting of compensation paid in the current year and long-term compensation under the Company’s 1993 Omnibus Stock Incentive Plan and Performance Unit Plan) is strongly dependent upon achievement of goals that are aligned with the interests of WEC’s stockholders and customers. During 2005, 73% to 80% of such total compensation paid to the named executive officers was tied to WEC performance as measured by goals established by the Committee each year.

The primary elements of WEC’s executive compensation program are base salary, annual incentive compensation and long-term incentive compensation. Generally, 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 companies with comparable revenue.

In order to determine appropriate compensation levels, including the allocation between long-term and current year compensation and between cash and non-cash compensation, 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 companies in general industry with comparable revenues. 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.

Specific values of 2005 compensation for the 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. With respect to executive compensation paid to the named executive officers other than Mr. Klappa, the Committee considered the recommendations of Mr. Klappa.

Base Salary. For 2005, we targeted base salaries for WEC officers to be within 10% of the reported median of general industry. For Wisconsin Electric Power Company and Wisconsin Gas LLC officers, we targeted base salaries to be within 10% of the reported median of the energy services industry. We then made adjustments to these targeted amounts taking into consideration factors such as the relative levels of individual experience, performance, responsibility and contribution to the results of Company operations. Base salaries for 2005 for each of the named executive officers are shown in the Summary Compensation Table under the heading of “Salary.” For 2006, the base salaries for Messrs. Klappa, Kuester, Leverett and Salustro, and Ms. Rappé, are $1,005,000, $582,000, $538,200, $424,872, and $360,528, respectively.

Annual Incentive Compensation. The annual incentive plan provides for annual cash 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 companies with comparable revenues and the executive’s responsibilities and experience, awards for 2005 were targeted at 35% to 100% of base salary; however, actual awards may range from 0% to 210% of base salary based upon performance. The plan also provides the Committee with the discretion to recognize individual performance.

At the Committee’s direction, the annual incentive plan for 2005 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 2005, the target for earnings from ongoing operations excluded the effects of asset sales not in the normal course of business, impairment charges and certain one-time tax benefits associated with state loss carry forwards. The Company’s financial performance exceeded the targets for 2005. 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, increased awards by 0.625%. Based upon these results, awards paid to executives for 2005 exceeded the target levels. Awards to the named executive officers are shown in the Summary Compensation Table under the heading of “Bonus.”

The annual incentive plan for 2006 will again depend upon financial achievement determined by Company performance against earnings from ongoing operations and cash flow targets. As was the case in 2005, 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 tied 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.

Beginning in 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. With the use of performance shares, the amount of the benefit ultimately vested is dependent upon the Company’s total stockholder return over a three-year period, as compared to the total stockholder return of the Custom Peer Group identified in the “Performance Graph” section of this proxy statement. Total stockholder return is 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. For 2005, the Committee adopted WEC’s Performance Unit Plan. The performance units granted under this plan are similar to performance shares except that upon vesting, the performance units will be settled in cash while the performance shares granted in 2004 will be settled in WEC common stock. Executives receive a cash dividend when WEC declares a dividend on its common stock in an amount equal to the number of performance units and 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 2005 are included in the Summary Compensation Table under the heading “Other Annual Compensation.” For 2006, the Committee awarded performance units under the Performance Unit Plan.

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” (SFAS 123(R)), which requires the expensing of unvested options over the remaining vesting period of the options beginning January 1, 2006. 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 had 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. 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 $961,752 for 2005. Mr. Klappa’s base salary for 2005 as Chairman, President and Chief Executive Officer was targeted at the median for CEOs at companies with comparable revenues as reflected in the survey of general industry compensation practices. Mr. Klappa’s annual incentive compensation award was targeted at 100% of base pay. The award for 2005 was $1,929,511, or 200.625% of base salary, and was based upon achievement of the financial and operational objectives described above under Annual Incentive Compensation.

In view of the discretionary component of the annual incentive plan, the Committee also noted other significant accomplishments of Mr. Klappa in 2005. However, given the overall achievements by the Company with regard to its financial and operational goals, no adjustment to Mr. Klappa’s annual incentive award was made. Significant accomplishments for Mr. Klappa included, among other things:

•

Progress in Wisconsin Energy Corporation’s Power the Future strategic plan:

•

Commenced construction of two 615-megawatt coal-fired generating units that are part of our Oak Creek expansion in June 2005 following receipt of a positive decision by the Supreme Court of Wisconsin and all remaining permits.

•

Added 545 megawatts of natural gas-fired generation in July 2005 when the first unit at Port Washington Generating Station began commercial operation; project was completed on time and within PSCW-approved cost parameters.

•

Completed the sale of approximately a 17% ownership interest in the two coal units being constructed as part of the Oak Creek expansion to two unaffiliated entities, who will share ratably in the construction costs.

•

High utility operating effectiveness:

•

Ranked second in the Midwest and tied for fifth out of 53 electric utilities nationwide in the J.D. Power and Associates’ 2005 Electric Utility Business Customer Satisfaction Study.

•

Realized a record 472 consecutive days of operation between planned refueling outages at one of our two generating units at Point Beach Nuclear Plant.

•

Received approval of a twenty year license extension from the United States Nuclear Regulatory Commission in December 2005 permitting the operation of Point Beach Unit 1 until 2030 and Point Beach Unit 2 until 2033.

•

Named by Forbes as one of the top 10 utilities in the country in the magazine’s annual evaluation and listing of the “Best Managed Companies in America.”

•

Continued leadership and excellence in corporate governance as evidenced by the rating of a “10”, the highest possible score, from GovernanceMetrics International (only one of four U.S. companies to earn a fourth consecutive “10”).

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 2005 in the form of stock options, as set forth in the “Long-Term Compensation Awards” column of the Summary Compensation Table, and performance units, as set forth in “Long-Term Incentive Plans – Awards in Last Fiscal Year.”

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 and performance unit awards under WEC’s Performance Unit Plan 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

Ulice Payne, Jr.

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, 2000, in each of:

•

WEC common stock;

•

a Custom Peer Group Index; and

•

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

WEC uses the Custom Peer Group Index for peer comparison purposes because the Company believes the Index provides an accurate representation of WEC’s peers. 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 long-term strategies.

As noted elsewhere in this proxy statement, a comparison of WEC’s total stockholder return to the total stockholder return of the Custom Peer Group is used to determine a portion of the long-term executive compensation awards.

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


	12/31/2000		12/31/2001		12/31/2002		12/31/2003		12/31/2004		12/31/2005
Wisconsin Energy Corporation	$	100	$	104	$	120	$	164	$	170	$	201
Custom Peer Group Index	$	100	$	96	$	92	$	110	$	130	$	147
S&P 500	$	100	$	88	$	69	$	89	$	99	$	104

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 and each of WEC’s other four most highly compensated executive officers (the “named executive officers”).

Summary Compensation Table


Name and Principal Position	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	2005	961,752	1,929,511	54,838		—	280,000	80,344
and Chief Executive Officer	2004	856,668	1,791,202	212,573	⁽³⁾	—	200,000	47,450
of WEC, WE and WG ⁽⁴⁾	2003	458,179	1,075,000	131,740	⁽³⁾	1,006,320	250,000	12,952
Frederick D. Kuester
Executive Vice President of	2005	557,004	893,985	31,565		—	100,000	40,578
WEC and WG; Executive	2004	520,004	795,606	103,017	⁽³⁾	—	150,000	24,600
Vice President and Chief Operating Officer of WE ⁽⁴⁾	2003	110,508	400,000	1,976		749,547	200,000	2,500
Allen L. Leverett
Executive Vice President and	2005	515,004	826,575	29,064		—	100,000	43,711
Chief Financial Officer of	2004	484,996	942,044	93,895	⁽³⁾	—	150,000	30,750
WEC, WE and WG ⁽⁴⁾	2003	230,004	690,000	66,025	⁽³⁾	846,748	200,000	6,900
Larry Salustro
Executive Vice President and	2005	406,572	652,553	27,916		—	100,000	29,869
General Counsel of WEC,	2004	385,000	589,050	17,612		—	150,000	24,241
WE and WG ⁽⁴⁾	2003	360,000	375,000	2,550		306,600	125,000	14,370
Kristine A. Rappé
Senior Vice President and Chief	2005	345,000	415,294	25,455		—	65,000	18,918
Administrative Officer of	2004	273,332	285,599	16,354		—	20,925	20,503
WEC, WE and WG ⁽⁴⁾

⁽¹⁾

There were no restricted stock awards made to the named executive officers during fiscal 2005 and 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 vested 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. Mr. Salustro has announced that he intends to retire no later than early 2007, at which time he will have reached the age of 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, 2005, the named executive officers held the following number of shares of restricted stock with the following values (based on a closing price of $39.06 on December 30, 2005, the last trading day of 2005): Mr. Klappa—33,882 shares ($1,323,431); Mr. Kuester—20,355 shares ($795,066); Mr. Leverett—10,228 shares ($399,506); Mr. Salustro—29,725 shares ($1,161,059); and Ms. Rappé—8,640 shares ($337,478).

During 2005, the Company awarded performance units to Messrs. Klappa, Kuester, Leverett and Salustro, and Ms. Rappé. These performance units are not reflected in the table or footnote discussion above. These performance unit awards are reflected in the table under the heading “Long-Term Incentive Plans – Awards in Last Fiscal Year.”

⁽²⁾	All Other Compensation for 2005 for each of Messrs. Klappa, Kuester, Leverett and Salustro, and Ms. Rappé, consists of:

•

employer matching of contributions into the 401(k) plan in the amount of $6,300 for each named executive officer; and

•

“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 $74,044, $34,278, $37,411, $23,569 and $12,618, respectively.

⁽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. 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 as President. He was appointed to the additional positions of Chairman of the Board and Chief Executive Officer effective May 2004. Mr. Kuester commenced employment with WEC in October 2003 as Chief Operating Officer of Wisconsin Electric Power Company and was appointed to the additional position of Executive Vice President effective May 2004. Mr. Leverett commenced employment with WEC in July 2003 as Chief Financial Officer. He was appointed to the additional position of Executive Vice President effective May 2004. Mr. Salustro served as Senior Vice President and General Counsel from July 2000 until May 2004 when he was appointed Executive Vice President and General Counsel. Ms. Rappé became an executive officer of WEC in May 2004.

Option Grants in Last Fiscal Year

This table shows additional data regarding the options granted in 2005 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	280,000	21.07	34.20	01/18/2015	$	2,329,600
Frederick D. Kuester	100,000	7.52	34.20	01/18/2015	$	832,000
Allen L. Leverett	100,000	7.52	34.20	01/18/2015	$	832,000
Larry Salustro	100,000	7.52	34.20	01/18/2015	$	832,000
Kristine A. Rappé	65,000	4.89	34.20	01/18/2015	$	540,800

⁽¹⁾

Consists of non-qualified stock options to purchase shares of WEC common stock granted on January 18, 2005, 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. These options were granted for a term of ten years, subject to earlier termination in certain events related to termination of employment. The options fully vest and become exercisable three years from the date of grant. Notwithstanding the preceding sentence, the options become immediately exercisable upon certain events related to termination of employment or a change in control of the Company. 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.

⁽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: $34.20; exercise price of option: $34.20; stock volatility: 19.0%; annualized risk-free interest rate: 4.42%; exercise at the end of the 10-year option term; and dividend yield: 2.456%. 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 2005 and the number and value of exercisable and unexercisable “in-the-money” options held by the named executive officers at fiscal year-end.


Name	Shares Acquired on Exercise (#)	Value Realized ($)⁽¹⁾	Number of Securities Underlying Unexercised Options at Fiscal Year-End (#)		Value of Unexercised In the Money Options at Fiscal Year-End ($)⁽³⁾
Name	Shares Acquired on Exercise (#)	Value Realized ($)⁽¹⁾	Exercisable⁽²⁾	Unexercisable⁽²⁾	Exercisable⁽²⁾	Unexercisable⁽²⁾
Gale E. Klappa	—	—	450,000	280,000	4,562,500	1,360,800
Frederick D. Kuester	—	—	350,000	100,000	2,441,750	486,000
Allen L. Leverett	—	—	350,000	100,000	2,829,750	486,000
Larry Salustro	—	—	535,000	100,000	6,806,087	486,000
Kristine A. Rappé	39,341	606,746	70,430	65,000	721,750	315,900

⁽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 the unexercisable options represent options granted to the named executive officers on January 18, 2005.

⁽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 2005 to the named executive officers.


Name	Number of shares, units or other rights (#)	Performance or other period until maturation or payment	Estimated future pay-outs under non-stock price based plans
Name	Number of shares, units or other rights (#)		Threshold (#)	Target (#)	Maximum (#)
Gale E. Klappa	20,500	3 years from date of grant	5,125	20,500	35,875
Frederick D. Kuester	9,000	3 years from date of grant	2,250	9,000	15,750
Allen L. Leverett	9,000	3 years from date of grant	2,250	9,000	15,750
Larry Salustro	9,000	3 years from date of grant	2,250	9,000	15,750
Kristine A. Rappé	6,000	3 years from date of grant	1,500	6,000	10,500

The table set forth above reflects the award of performance units to the named executive officers in 2005 under the Wisconsin Energy Corporation Performance Unit Plan. Upon vesting, the performance units will be settled in cash in an amount determined by multiplying the number of performance units which have become vested by the fair market value (the average of the high and low sales price on the relevant date) of the Company’s common stock on the date of vesting. The number of performance units ultimately vested is dependent upon WEC’s total stockholder return over a three-year period as compared to the total stockholder return of the Custom Peer Group identified in the “Performance Graph” section of this proxy statement. Several mergers have been announced by companies within the Custom Peer Group. Should these anticipated mergers occur during 2006, the Custom Peer Group will be slightly altered to reflect the merged entities for purposes of vesting of 2005 and 2004 performance awards. Total stockholder return is 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 units is as follows:


Percentile Rank	Vesting Percent
< 25^th Percentile	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 units 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 units 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 units (based upon the target 100% rate) 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 units 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. The performance units have no voting rights attached to them.

EMPLOYMENT AND SEVERANCE ARRANGEMENTS

WEC has adopted severance policies that provide for severance benefits to designated executives and other key employees. The policies 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 allow for a deferral opportunity for participants who may become entitled to benefits.

Under the current severance policies, participants have been designated into one of four benefit levels. Of the individuals named in the Summary Compensation Table, Mr. Salustro is a Tier 2 participant. Messrs. Klappa, Kuester and Leverett, and Ms. Rappé, do not participate in the severance policy, but each has a separate change in control and severance agreement as described below. Ms. Rappé entered into an employment agreement with the Company on July 28, 2005, which supersedes her participation in the severance policies.

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. Mr. Salustro will not be entitled to these severance benefits upon his retirement.

The Company has entered into written agreements with each of Messrs. Klappa, Kuester and Leverett, and Ms. Rappé, 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, or (ii) the highest bonus paid in any of the last three fiscal years of the Company prior to termination or the change in control. 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. Pursuant to the terms of his employment agreement, Mr. Klappa’s target bonus opportunity was fixed at 90% of his base salary. 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. The target bonus opportunity may not be adjusted below 90%, except by action of the Board or a committee thereof lowering the target for all executive officers. 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.

•

WEC entered into an employment agreement with Mr. Kuester, which became effective on October 13, 2003. Mr. Kuester’s employment agreement is substantially similar to Mr. Klappa’s, except that if Mr. Kuester’s employment is terminated by the Company for any reason other than cause, death or disability or by Mr. Kuester 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 in effect for the three years preceding his termination and his highest bonus amount, (ii) health and certain other 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. 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. Mr. Kuester’s target bonus opportunity is fixed at 80% of base salary. The target bonus opportunity may not be adjusted below 80%, except by action of the Board or a committee thereof lowering the target for all executive officers. 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 tenth 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. The agreement contains a one-year non-compete provision applicable on termination of employment.

•

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 in effect for the three years preceding his termination and his highest bonus amount, (ii) health and certain other 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. Mr. Leverett’s target bonus opportunity is fixed at 80% of base salary. The target bonus opportunity may not be adjusted below 80%, except by action of the Board or a committee thereof lowering the target for all executive officers. 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 vested 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. The agreement contains a one-year non-compete provision applicable on termination of employment.

•

Ms. Rappé was appointed to her position as Senior Vice President and Chief Administrative Officer effective May 12, 2004, and entered into an employment agreement with the Company on July 28, 2005. Ms. Rappé’s employment agreement is substantially similar to Mr. Klappa’s, except that if Ms. Rappé’s employment is terminated by the Company for any reason other than cause, death or disability or by Ms. Rappé for good reason in the absence of a change in control, (i) the special lump sum severance benefit is two times the sum of her highest annual base salary in effect for the three years preceding her termination and her target bonus amount, (ii) health and certain other welfare benefits are provided for a two-year period and (iii) the special retirement plan lump sum is calculated as if her employment continued for a two-year period following termination of employment. In addition, for a termination in connection with a change in control, the lump sum severance benefit is three times the base salary and target bonus amount. Ms. Rappé is eligible to receive a supplemental retirement benefit from the Company which is further described under the “Retirement Plans” section of this proxy statement. Pursuant to the terms of the agreement, Ms. Rappé’s target bonus opportunity will not be less than 60% of base salary. The target bonus opportunity may not be adjusted below 60%, except by action of the Board or a committee thereof lowering the targets for all executive officers. The agreement contains a one-year non-compete provision applicable on termination of employment.

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 (based upon the target 100% rate) 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. This amount will continue to increase until January 1, 2011, at which time it will be frozen. Upon retirement, participants will receive the greater of this amount or the cash balance.

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 2005, 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)


Remuneration		Years of Service
Remuneration		15		20		25		30		35		40
$	300,000	$	74,165	$	98,887	$	123,609	$	148,331	$	162,379	$	176,428
	500,000		125,915		167,887		209,859		251,831		275,629		299,428
	700,000		177,665		236,887		296,109		355,331		388,879		422,428
	900,000		229,415		305,887		382,359		458,831		502,129		545,428
	1,100,000		281,165		374,887		468,609		562,331		615,379		668,428
	1,300,000		332,915		443,887		554,859		665,831		728,629		791,428
	1,500,000		384,665		512,887		641,109		769,331		841,879		914,428
	1,700,000		436,415		581,887		727,359		872,831		955,129		1,037,428
	1,900,000		488,165		650,887		813,609		976,331		1,068,379		1,160,428
	2,100,000		539,915		719,887		899,859		1,079,831		1,181,629		1,283,428
	2,300,000		591,665		788,887		986,109		1,183,331		1,294,879		1,406,428

The compensation considered for purposes of the retirement plans and the various supplemental plans for Messrs. Klappa, Kuester, Leverett and Salustro, and Ms. Rappé, is $1,767,859, $985,712, $1,062,528, $790,632, and $445,713, respectively. These amounts represent the average compensation paid during the consecutive 36-month period for which such compensation is highest. Messrs. Klappa, Kuester, Leverett and Salustro, and Ms. Rappé, currently have or are considered to have 28, 33, 17, 34 and 23

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 WEC 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, under the SERP, Mr. Salustro and Ms. Rappé also will receive 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 at or after age 60 or death.

WEC has entered into an agreement with Mr. 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. 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. Mr. Salustro has announced that he intends to retire no later than early 2007, at which time he will have reached the age of 60.

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 retirement benefits payable to Messrs. Klappa, Kuester and Leverett will be offset by the value of any qualified or non-qualified defined benefit pension plans of prior employers.

Pursuant to the terms of her employment agreement, Ms. Rappé’s SERP benefit is not subject to early retirement reduction factors if she retires at or after age 60.

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, 2006. 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, 2006. 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.


Name	Shares Beneficially Owned⁽¹⁾
Name	Shares Owned^{(2) (3) (4)}	Option Shares Exercisable Within 60 Days		Total
John F. Ahearne	11,141	16,333		27,474
John F. Bergstrom	8,660	24,333		32,993
Barbara L. Bowles	8,869	24,333		33,202
Robert A. Cornog	13,395	24,333		37,728
Curt S. Culver	4,665	—		4,665
Thomas J. Fischer	5,205	—		5,205
Gale E. Klappa	39,507	450,000		489,507
Frederick D. Kuester	22,505	350,000		372,505
Allen L. Leverett	11,142	350,000		361,142
Ulice Payne, Jr.	6,760	8,333		15,093
Kristine A. Rappé	15,127	70,430		85,557
Larry Salustro	38,861	535,000		573,861
Frederick P. Stratton, Jr.	14,260	21,333		35,593
George E. Wardeberg	30,094	278,333	⁽⁵⁾	308,427
All directors and executive officers as a group (17 persons)	250,427	2,364,643	⁽⁵⁾	2,615,070	⁽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 other executive officers also hold share units in the WEC phantom common stock account under WEC’s deferred compensation plans as indicated: Mr. Bergstrom (7,314), Mr. Cornog (12,960), Mr. Culver (2,698), Mr. Kuester (2,550), Ms. Rappé (6,753), Mr. Salustro (3,124), Mr. Stratton (9,139), Mr. Wardeberg (1,234) and all directors and executive officers as a group (46,787). 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 other 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 (23,899) and all directors and executive officers as a group (36,506).

⁽⁴⁾

Certain 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 (5,660), Mr. Bergstrom (5,660), Ms. Bowles (5,660), Mr. Cornog (5,660), Mr. Culver (4,665), Mr. Fischer (2,468), Mr. Klappa (33,882), Mr. Kuester (20,355), Mr. Leverett (10,228), Mr. Payne (5,660), Ms. Rappé (8,640), Mr. Salustro (29,725), Mr. Stratton (5,660), Mr. Wardeberg (5,660) and all directors and executive officers as a group (161,361).

⁽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 2.2% of total WEC common stock outstanding on February 15, 2006.

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 2006 and reflects stock holdings as of December 31, 2005.


Name and Address	Voting Authority		Dispositive Authority		Total Shares Beneficially Owned	Percent of WEC Common Stock
Name and Address	Sole	Shared	Sole	Shared	Total Shares Beneficially Owned	Percent of WEC Common Stock
AXA Financial, Inc. ⁽¹⁾ 1290 Avenue of the Americas New York, NY 10104	5,404,144	1,582,613	10,209,217	0	10,209,217	8.7	%
FMR Corp. ⁽²⁾ 82 Devonshire Street Boston, MA 02109	42,680	0	6,898,680	0	6,898,680	5.897	%
Pzena Investment Management, LLC 120 West 45^th Street, 20^th Floor New York, NY 10036	4,075,660	0	7,167,635	0	7,167,635	6.13	%

⁽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 as a member 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 2005 fiscal year. To the Company’s knowledge, based on information provided by the reporting persons, all applicable reporting requirements for fiscal year 2005 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.

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, 2005, 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 B to this proxy statement.

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

APPENDIX A

WISCONSIN ENERGY CORPORATION

AUDIT AND OVERSIGHT COMMITTEE OF THE BOARD OF DIRECTORS

CHARTER

Approved: February 10, 2003

PURPOSE

The principal purpose of the Audit and Oversight Committee (Committee) is to (A) assist the Board of Directors in carrying out its oversight responsibility of (i) the integrity of the Company’s financial statements, (ii) the Company’s compliance with legal and regulatory requirements, (iii) the independent auditor’s qualifications and independence, and (iv) the performance of the Company’s internal audit function and independent auditors, and (B) prepare the report that Securities and Exchange Commission rules require to be included in the Company’s proxy statement. With respect to item (i), preparation of the financial statements is the role of Company management, not the Committee. The Committee shall report all significant findings to the Board.

COMPOSITION

The Committee shall consist of three or more independent directors who are periodically appointed by the Board. Members shall serve at the pleasure of the Board and for such term or terms as the Board may determine. Each member shall, in the judgment of the Board, meet the independence standards of the New York Stock Exchange, the Sarbanes-Oxley Act of 2002 and the Securities and Exchange Commission. Each member shall be financially literate as the Board of Directors interprets such qualification in its judgment. The Board shall determine whether any director serving on the Committee is an “audit committee financial expert,” as such term is defined in the rules and regulations promulgated by the Securities and Exchange Commission. No director may serve as a member of the Committee if such director serves on the audit committees of more than three public companies unless the Board determines that such simultaneous service would not impair the ability of such director to effectively serve on the Committee and discloses this determination in Wisconsin Energy Corporation’s proxy statement. No member of the Committee may receive any compensation from the Company other than (i) directors’ fees which may be received in cash, stock options or other in-kind consideration, (ii) other deferred compensation for prior service that is not contingent on future service, and (iii) any other benefits that other directors receive for their service to the Company as a director. One of the directors shall be appointed Chair for a term to be determined by the Board and shall preside over the meetings of the Committee. In the event the Committee Chair is unable to serve as Chair for a specific meeting, he/she shall designate one of the Committee members to preside.

DUTIES AND RESPONSIBILITIES

The Committee shall have unrestricted access to the independent auditor, Company personnel and documentation pertinent to the scope of its duties and responsibilities. The duties and responsibilities of the Committee shall be to:

Independent Auditor

•

Evaluate the services of the independent auditor, or other independent auditors under consideration, and approve a firm to be engaged for the coming year. The Committee shall have the sole and ultimate authority and responsibility to evaluate and, where appropriate, terminate and replace the independent auditor. The independent auditor is ultimately accountable to the Committee.

•

Review and approve proposed audit and non-audit services for the year, and any additional audit or non-audit services subsequently proposed, and assure that such services will not affect the independence of the auditor. Approve in advance any non-audit engagements of the independent auditor permitted by Section 201 of the Sarbanes-Oxley Act of 2002 and assure that approval is disclosed in the Company’s periodic reports as required by law. Authority to pre-approve services can be delegated to one or more members of the Audit and Oversight Committee, but any pre-approval decision by the delegate must be reported to the full Audit and Oversight Committee at its next regularly scheduled meeting.

•

Prior to the start of the annual audit, approve the audit plan and the terms and estimated fees for the engagement following the independent auditor’s presentation of the audit plan and objectives of the audit.

•

Review with management and the independent auditor, at least annually, recent accounting, tax, and financial reporting developments and auditing standards.

A-1

•

Ensure that the independent auditor submits, at least on an annual basis, to the Committee a formal written statement delineating all relationships between the auditor and the Company consistent with Independence Standards Board Standard No. 1. Engage in a dialogue with the independent auditor with respect to any disclosed relationships or services that may impact the objectivity and independence of the outside auditor. Take appropriate action, when necessary, to ensure the independence of the independent auditor.

•

Discuss with the independent auditor the matters to be discussed by Statement on Auditing Standards No. 61 relating to the conduct of the audit.

•

Set clear hiring policies for employees or former employees of the independent auditors.

•

Oversee the resolution of any disagreements between the Company’s independent auditors and management regarding financial reporting.

•

Review on a regular basis with the Company’s independent auditors any problems or difficulties encountered by the independent auditors in the course of any audit work, including management’s response with respect thereto, any restrictions on the scope of the independent auditors’ activities or on access to requested information, and any significant disagreements with management. In connection therewith, the Committee should review with the independent auditors:

(i)

any accounting adjustments that were noted or proposed by the independent auditors but were not recorded by management (due to immateriality or other reasons);

(ii)

any significant “management” or “internal control” comments; and

(iii)

the responsibilities, budget and staffing of the Company’s internal auditors.

•

Ensure that the audit partners scheduled to perform the current year’s audit of the Company’s financial statements satisfy the rules governing audit partner rotation.

•

Ensure that the Chief Executive Officer, Controller, Chief Financial Officer, Chief Accounting Officer or other person serving in an equivalent position of the Company, was not, within one year prior to the initiation of the audit, an employee of the independent auditors who participated in any capacity in the Company’s audit.

Annual and Interim Financials

•

After the annual audit, review the financial statements and other related financial information to be included in the Company’s Annual Report on Form 10-K, including the Company’s disclosure under “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” with appropriate Company management and the independent auditor. Review with the independent auditor its report to the Committee regarding the audit and its opinion to be issued on the financial statements. Recommend to the Board any action considered necessary, including that audited financials be included in the Form 10-K.

•

Prior to the filing of the Company’s Quarterly Report on Form 10-Q, review the interim financial statements to be included in the 10-Q with management and the independent auditor.

•

Review the certifications of the Chief Executive Officer and Chief Financial Officer related to the annual and interim reports as required by the Sarbanes-Oxley Act of 2002 as well as any significant reports of management’s Disclosure Committee.

•

Discuss earnings press releases, as well as financial information and earnings guidance provided to analysts and rating agencies. The Committee need not discuss in advance each earnings release or each instance in which the Company may provide earnings guidance.

•

Review and discuss with management, the independent auditors and the internal auditing department:

(i)

critical accounting policies and such other accounting policies of the Company as are deemed appropriate for review by the Committee prior to any interim or year-end filings with the Securities and Exchange Commission or other regulatory body, including any financial reporting issues which could have a material impact on the Company’s financial statements;

(ii)

major issues regarding accounting principles and financial statement presentations, including (A) any significant changes in the Company’s selection or application of accounting principles and (B) any analyses prepared by management and/or

A-2

the independent auditors setting forth significant financial reporting issues and judgments made in connection with the preparation of the financial statements, including analyses of the ramifications and effects of alternative generally accepted accounting principles on the Company’s financial statements;

(iii)

all alternative treatments of financial statement presentation that have been discussed by the independent auditors and management, ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the independent auditors; and

(iv)

the effect of regulatory and accounting initiatives, as well as, off balance sheet transactions, on the financial statements of the Company.

Internal Controls

•

At least annually, obtain and review a report by the independent auditor describing: the auditor’s internal quality-control procedures; any material issues raised by the most recent internal quality-control review, or peer review, of the auditor, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the auditor, and any steps taken to deal with any such issues; and (to assess the auditor’s independence) all relationships between the independent auditor and the Company.

•

Review with the Company’s Chief Executive Officer and Chief Financial Officer and other senior members of management, the Company’s internal auditors and independent auditors:

(i)

all significant deficiencies in the design or operation of internal controls which could adversely affect the Company’s ability to record, process, summarize, and report financial data, including any material weaknesses in internal controls identified by the Company’s independent auditor;

(ii)

any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal controls; and

(iii)

any significant changes in internal controls or in other factors that could significantly affect internal controls, including any corrective actions with regard to significant deficiencies and material weaknesses.

Internal Auditor

Meet at least semi-annually with the internal auditor to review internal audit’s independence, coordination with the independent auditor, staffing, audit scope, significant audit results, management’s responsiveness to recommendations, evaluation of internal control systems, and other relevant matters.

Code of Business Conduct

•

Review any reports submitted regarding compliance with Wisconsin Energy Corporation’s Code of Business Conduct and approve, as appropriate, any pre-approvals or waivers thereto for directors, executive officers and senior financial officers and ensure that any waivers are disclosed in accordance with applicable laws.

•

Establish procedures for (i) the receipt, retention and treatment of complaints received by the Company regarding accounting, internal accounting controls or auditing matters, and (ii) the confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters.

Oversight of Legal/Litigation, Regulatory and Environmental Matters

•

Meet at least annually with the general counsel, and outside counsel when appropriate, to review legal and regulatory matters, including any matters that may have a material impact on the financial statements of the Company.

•

Review and provide oversight of:

(i)

litigation matters, to ensure appropriate management and supervision is being afforded significant actual and potential litigation and insurance claims; and

A-3

(ii)

environmental compliance matters, including review of the Company’s regulatory and civil litigation exposure concerning environmental contamination and/or toxic torts and to ensure that appropriate management attention is being given to such matters.

•

The Committee shall have direct access to and meet as needed with the officer in charge of each function, without management present, as appropriate. The officers shall report all significant matters to the Committee.

Risk Assessment and Risk Management

Discuss the Company’s major risk exposures and the steps management has taken to monitor and control such exposures. In this regard, review the process used by the Board’s Finance Committee to discuss policies with respect to the Company’s risk assessment and risk management.

Annual Performance Evaluation

Produce and provide to the Board an annual performance evaluation of the Committee. The evaluation shall compare the performance of the Committee with the requirements of this Charter. Recommend to the Board any improvements to the Charter.

Other

•

Prepare the report required by the rules of the Securities and Exchange Commission to be included in Wisconsin Energy Corporation’s annual proxy statement.

•

Recommend to the Board special audits or studies the Committee considers necessary or advisable. Review the reports issued for such special audits or studies and recommend to the Board any action considered necessary.

•

The Committee shall also be responsible for any other matters as may from time to time be requested by the Board and/or the Chief Executive Officer.

•

The Committee may, in its discretion, delegate all or a portion of its duties and responsibilities to a subcommittee of the Committee.

The Committee shall be notified promptly by management, the internal auditor or independent auditor of the discovery of fraudulent, questionable or illegal events which could have a material impact on the financial statements or reputation of the Company.

MEETINGS

The Committee shall meet once every fiscal quarter, or more frequently if circumstances warrant. As deemed necessary by the Committee, meetings shall be attended by Company personnel. Both the internal auditor and the independent auditor shall (i) meet alone with the Committee at each regularly scheduled meeting to discuss any matters that the Committee or any of these persons or firms believe should be discussed privately and (ii) have authority and are expected to contact the Committee on any matters requiring its attention.

The Committee may obtain advice and assistance from outside legal, accounting or other advisors. The Committee may retain these advisors without seeking Board approval.

The Committee may meet separately with management and request any officer, employee or Company’s outside counsel to attend a Committee meeting or to meet with any advisors or consultants to the Committee.

A-4

APPENDIX B

WISCONSIN ENERGY CORPORATION

2005 ANNUAL FINANCIAL STATEMENTS

and

REVIEW of OPERATIONS

B-1

SELECTED FINANCIAL AND OPERATING DATA

WISCONSIN ENERGY CORPORATION

CONSOLIDATED SELECTED FINANCIAL AND STATISTICAL DATA


	2005			2004		2003		2002		2001
Financial
Year Ended December 31
Net income-Continuing Operations (Millions)	$	303.6		$	219.6	$	201.3	$	135.9	$	189.9
Earnings per share of common stock- Continuing operations
Basic	$	2.59		$	1.87	$	1.72	$	1.18	$	1.62
Diluted	$	2.56		$	1.84	$	1.70	$	1.17	$	1.61
Dividends per share of common stock	$	0.88		$	0.83	$	0.80	$	0.80	$	0.80
Operating revenues (Millions)
Utility energy	$	3,793.0		$	3,375.4	$	3,263.9	$	2,852.1	$	2,964.8
Non-utility energy		40.0			19.9		12.3		165.0		337.3
Other including eliminations		(17.5	)		10.8		5.9		15.6		22.5

Total operating revenues	$	3,815.5		$	3,406.1	$	3,282.1	$	3,032.7	$	3,324.6

At December 31 (Millions)
Total assets	$	10,462.0		$	9,565.4	$	10,014.5	$	9,465.9	$	9,454.2
Long-term debt and mandatorily redeemable trust preferred securities (including current maturities of long-term debt)	$	3,527.0		$	3,340.5	$	3,736.7	$	3,266.6	$	3,917.4
Utility Energy Statistics
Electric
Megawatt-hours sold (Thousands)		32,470.2			31,648.4		31,183.4		30,862.6		31,062.6
Customers (End of year)		1,115,347			1,104,112		1,090,513		1,078,710		1,066,275
Gas
Therms delivered (Millions)		2,168.8			2,068.1		2,171.2		2,121.3		1,997.2
Customers (End of year)		1,029,732			1,014,799		998,201		982,066		966,817

CONSOLIDATED SELECTED QUARTERLY FINANCIAL DATA (Unaudited)


	(Millions of Dollars, Except Per Share Amounts) (a)
	March (c)					June (c)
Three Months Ended	2005			2004		2005			2004
Operating revenues	$	1,094.7		$	1,059.4	$	788.5		$	710.4
Operating income		166.8			181.7		89.9			74.0
Income from Continuing Operations		90.0			82.4		56.8			21.3
Income (loss) from Discontinued Operations		(0.1	)		8.4		5.2			17.3

Total Net Income	$	89.9		$	90.8	$	62.0		$	38.6

Earnings per share of common stock (basic) (b)
Continuing operations	$	0.77		$	0.69	$	0.48		$	0.18
Discontinued operations		—			0.07		0.04			0.15

Total earnings per share (basic)	$	0.77		$	0.76	$	0.52		$	0.33

Earnings per share of common stock (diluted) (b)
Continuing operations	$	0.76		$	0.69	$	0.48		$	0.18
Discontinued operations		—			0.07		0.04			0.14

Total earnings per share (diluted)	$	0.76		$	0.76	$	0.52		$	0.32


	September					December
Three Months Ended	2005			2004		2005			2004
Operating revenues	$	797.3		$	690.4	$	1,135.0		$	945.9
Operating income		128.4			100.5		177.8			173.8
Income from Continuing Operations		65.8			31.4		91.0			84.5
Income (loss) from Discontinued Operations		0.4			53.0		(0.4	)		8.1

Total Net Income	$	66.2		$	84.4	$	90.6		$	92.6

Earnings per share of common stock (basic) (b)
Continuing operations	$	0.57		$	0.27	$	0.77		$	0.72
Discontinued operations		—			0.45		—			0.07

Total earnings per share (basic)	$	0.57		$	0.72	$	0.77		$	0.79

Earnings per share of common stock (diluted) (b)
Continuing operations	$	0.56		$	0.26	$	0.77		$	0.71
Discontinued operations		—			0.45		—			0.07

Total earnings per share (diluted)	$	0.56		$	0.71	$	0.77		$	0.78

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

(b)	Quarterly earnings per share may not total to the amounts reported for the year since the computation is based on the weighted average common shares outstanding during each quarter.

(c)	Amounts do not correspond to those reported on the Form 10-Q’s for March and June due to the presentation of Minergy Neenah, LLC as a discontinued operation.

B-2

WISCONSIN ENERGY CORPORATION

CONSOLIDATED SELECTED UTILITY OPERATING DATA


Year Ended December 31	2005			2004			2003		2002			2001
Electric Utility
Operating Revenues (Millions)
Residential	$	827.6		$	731.3		$	715.5	$	703.0		$	654.5
Small Commercial/Industrial		746.1			668.0			642.0		606.3			592.9
Large Commercial/Industrial		602.4			549.9			519.3		483.1			479.7
Other-Retail/Municipal		112.6			90.7			84.9		77.7			70.6
Resale-Utilities		21.3			24.6			24.0		18.1			56.8
Other Operating Revenues		39.7			34.5			27.9		22.6			12.9

Total Operating Revenues	$	2,349.7		$	2,099.0		$	2,013.6	$	1,910.8		$	1,867.4

Megawatt-hour Sales (Thousands)
Residential		8,562.7			8,053.9			8,099.3		8,310.9			7,773.4
Small Commercial/Industrial		9,192.7			8,840.4			8,740.6		8,719.5			8,595.4
Large Commercial/Industrial		11,687.5			11,686.4			11,401.8		11,129.6			11,177.6
Other-Retail/Municipal		2,713.6			2,405.5			2,225.9		2,051.9			1,828.6
Resale-Utilities		313.7			662.2			715.8		650.7			1,687.6

Total Sales		32,470.2			31,648.4			31,183.4		30,862.6			31,062.6

Number of Customers (Average)
Residential		997,014			985,811			973,575		963,988			950,271
Small Commercial/Industrial		109,583			107,843			106,469		105,551			103,908
Large Commercial/Industrial		705			709			707		709			710
Other		2,444			2,415			2,392		2,389			2,363

Total Customers		1,109,746			1,096,778			1,083,143		1,072,637			1,057,252

Gas Utility
Operating Revenues (Millions)
Residential	$	898.9		$	798.6		$	769.3	$	591.0		$	645.9
Commercial/Industrial		465.4			396.5			386.0		279.7			313.4
Interruptible		20.4			17.0			16.9		12.6			17.0

Total Retail Gas Sales		1,384.7			1,212.1			1,172.2		883.3			976.3
Transported Gas		46.3			41.4			36.6		39.4			37.9
Other Operating Revenues		(13.5	)		(1.1	)		17.3		(4.6	)		60.3

Total Operating Revenues	$	1,417.5		$	1,252.4		$	1,226.1	$	918.1		$	1,074.5

Therms Delivered (Millions)
Residential		791.0			809.9			853.7		817.1			756.3
Commercial/Industrial		460.7			464.0			492.5		463.1			427.7
Interruptible		23.4			24.7			27.5		29.4			25.8

Total Retail Gas Sales		1,275.1			1,298.6			1,373.7		1,309.6			1,209.8
Transported Gas		893.7			769.5			797.5		811.7			787.4

Total Therms Delivered		2,168.8			2,068.1			2,171.2		2,121.3			1,997.2

Number of Customers (Average)
Residential		931,845			916,921			901,322		888,626			875,339
Commercial/Industrial		86,422			85,031			83,915		82,973			79,503
Interruptible		62			68			67		79			82
Transported Gas		1,461			1,459			1,440		1,508			4,468

Total Customers		1,019,790			1,003,479			986,744		973,186			959,392

Degree Days (a)
Heating (6,697 Normal)		6,628			6,663			7,063		6,551			6,338
Cooling (700 Normal)		949			442			606		897			711

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

B-3

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

INTRODUCTION

Wisconsin Energy Corporation is a diversified holding company with subsidiaries primarily in a utility energy segment 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 and its subsidiaries (collectively, We Power). 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 Regarding Forward - Looking Statements: 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, coal and 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, 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. We disclaim any obligation to update these forward-looking statements.

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. In July 2005, the first of four new electric generating units under our Power the Future strategy was placed into service. 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. In 2005, we increased our generating capacity by 545-megawatts with the completion of the first unit under the Power the Future strategy, and we plan to continue increasing our generating capacity through three additional electric generating units that We Power is constructing.

Non-Utility Energy Segment: Our primary focus in this segment is to improve the supply of electric generation in Wisconsin. We Power was formed to design, construct, own and lease new generation assets under the Power the Future strategy.

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 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 approximately $2.6 billion in 2,120 megawatts of new natural gas-fired and coal-

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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 were 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 and lease the new generating capacity. Wisconsin Electric will lease each new generating 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 payments under the plant leases 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 Generating Station (PWGS) and the Oak Creek expansion.

As of December 31, 2005, 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. The first unit was placed into service in July 2005 and is fully operational. Unit 1 was completed within the PSCW approved cost parameters. The second unit is expected to be operational in 2008.

•

Began site preparation for 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 adjacent to the site of our existing Oak Creek Power Plant in Oak Creek, Wisconsin (the Oak Creek expansion), with the first unit expected to be in service in 2009 and the second unit in 2010. The CPCN was granted contingent upon us obtaining the necessary environmental permits. We have received all permits necessary to commence construction. In June 2005, construction commenced at the site.

•

Completed the planned sale in November 2005 of approximately a 17% ownership interest in the Oak Creek expansion to two co-owners.

•

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, excluding environmental trust securities that we may issue, 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.

Our primary risks under Power the Future are construction risks associated with the schedule and costs for both our Oak Creek expansion and the PWGS, continuing legal challenges to permits obtained and changes in applicable laws or regulations, adverse interpretation or enforcement of permit conditions, laws and regulations by the permitting agencies, the inability to obtain necessary operating permits in a timely manner, obtaining the investment capital from outside sources necessary to implement the strategy, governmental actions and events in the global economy.

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, and specific regulatory approvals in Factors Affecting Results, Liquidity and Capital Resources below.

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Divestiture of 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 Wisconsin and a substantial amount of Wispark’s real estate portfolio, as well as our manufacturing business. In addition, in 2001 we contributed our transmission assets to the American Transmission Company LLC (ATC) and received cash proceeds of $119.8 million and an economic interest in ATC. Since 2000, we have received total proceeds of approximately $2.1 billion from the divestiture of assets as follows:


Proceeds from divestitures:	(Millions of Dollars)
Manufacturing	$	857.0
Non-Utility Energy		616.8
Real Estate		442.1
Transmission		119.8
Other		33.5

Total	$	2,069.2

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RESULTS OF OPERATIONS

CONSOLIDATED EARNINGS

The following table compares our operating income by business segment and our net income for 2005, 2004, and 2003.


Wisconsin Energy Corporation	2005		2004			2003
	(Millions of Dollars)
Utility Energy	$	542.4	$	528.6		$	544.1
Non-Utility Energy		19.5		4.6			(55.7	)
Corporate and Other		1.0		(3.2	)		(4.3	)

Total Operating Income		562.9		530.0			484.1
Other Income, Net		63.3		15.8			41.7
Interest Expense		173.4		193.4			213.8

Income From Continuing Operations Before Income Taxes		452.8		352.4			312.0
Income Taxes		149.2		132.8			110.7

Income From Continuing Operations		303.6		219.6			201.3
Income From Discontinued Operations, Net of Tax (a)		5.1		86.8			43.0

Net Income	$	308.7	$	306.4		$	244.3

Diluted Earnings Per Share	$	2.61	$	2.57		$	2.06

Diluted Earnings Per Share - Discontinued Operations	$	0.05	$	0.73		$	0.36

(a)

Income from Discontinued Operations, Net of Tax includes: (1) the operations of Minergy Neenah which we began reporting as discontinued operations in the third quarter of 2005, (2) the manufacturing segment, which was sold effective July 31, 2004 and (3) the operations of Calumet which were sold effective May 31, 2005. Prior periods reported in this table have been restated to reflect discontinued operations.

The following table identifies significant items that are included in our Diluted Earnings per Share from Continuing Operations.


	2005			2004		2003
Asset Valuation Charge	$	—		$	—	$	0.32
Voluntary Severance Program	$	—		$	0.16	$	—
Debt Redemption Costs	$	—		$	0.13	$	—
Reduction of Tax Valuation Allowance	($	0.14	)	$	—	$	—

An analysis of contributions to operating income by segment and a more detailed analysis of results in 2005, 2004 and 2003 follow.

UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

2005 vs. 2004: Our utility energy segment contributed $542.4 million of operating income during 2005 compared with $528.6 million of operating income during 2004. During 2005, we experienced an increase in revenues due to favorable weather and pricing increases. Also, during 2004, we recorded severance costs under a voluntary severance program. The year to year increase in operating income was partially offset by higher fuel and purchased power costs and increased operation and maintenance expenses during 2005. We had two scheduled outages at our nuclear plant in 2005 in comparison to one scheduled outage in 2004.

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 more than offset by higher pension and medical costs, severance costs recorded during the second half of 2004 and unfavorable weather.

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The following table summarizes our utility energy segment’s operating income during 2005, 2004 and 2003.


Utility Energy Segment	2005		2004		2003
	(Millions of Dollars)
Operating Revenues
Electric	$	2,349.7	$	2,099.0	$	2,013.6
Gas		1,417.5		1,252.4		1,226.1
Other		25.8		24.0		24.2

Total Operating Revenues		3,793.0		3,375.4		3,263.9
Fuel and Purchased Power		780.8		591.7		569.5
Cost of Gas Sold		1,047.3		890.9		863.3

Gross Margin		1,964.9		1,892.8		1,831.1
Other Operating Expenses
Other Operation and Maintenance		1,010.4		963.0		891.0
Depreciation, Decommissioning and Amortization		324.1		315.5		316.2
Property and Revenue Taxes		88.0		85.7		79.8

Operating Income	$	542.4	$	528.6	$	544.1

Electric Utility Gross Margin

The following table compares our electric utility gross margin during 2005 with similar information for 2004 and 2003, including a summary of electric operating revenues and electric sales by customer class.


Electric Utility Operations	Electric Revenues and Gross Margin						Electric Megawatt-Hour Sales
Electric Utility Operations	2005		2004		2003		2005	2004	2003
	(Millions of Dollars)						(Thousands, Except Degree Days)
Customer Class
Residential	$	827.6	$	731.3	$	715.5	8,562.7	8,053.9	8,099.3
Small Commercial/Industrial		746.1		668.0		642.0	9,192.7	8,840.4	8,740.6
Large Commercial/Industrial		602.4		549.9		519.3	11,687.5	11,686.4	11,401.8
Other-Retail/Municipal		112.6		90.7		84.9	2,713.6	2,405.5	2,225.9
Resale-Utilities		21.3		24.6		24.0	313.7	662.2	715.8
Other Operating Revenues		39.7		34.5		27.9	—	—	—

Total Electric Operating Revenues	$	2,349.7	$	2,099.0	$	2,013.6	32,470.2	31,648.4	31,183.4

Fuel and Purchased Power
Fuel		432.7		334.7		298.5
Purchased Power		340.3		250.3		264.3

Total Fuel and Purchased Power		773.0		585.0		562.8

Total Electric Gross Margin	$	1,576.7	$	1,514.0	$	1,450.8

Weather — Degree Days (a)
Heating (6,697 Normal)							6,628	6,663	7,063
Cooling (700 Normal)							949	442	606

(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

2005 vs. 2004: During 2005, our total electric utility operating revenues increased by $250.7 million or 11.9% when compared with 2004 primarily due to favorable weather during the summer of 2005 and pricing increases.

During 2005, we estimate that pricing increases contributed an additional $145.8 million of revenues than in 2004. The most significant impact to rates was a March 2005 interim order received by Wisconsin Electric from the PSCW authorizing an annualized increase in electric rates of approximately $114.9 million due to the increased costs of fuel and purchased power. In November 2005, Wisconsin Electric received the final rate order, which authorized an additional $7.7 million of annual revenues. Additional orders impacting rates in 2005 were the May 2004 and May 2005 orders received by Wisconsin Electric from the PSCW authorizing

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annualized increases in electric rates of approximately $59.0 million and $59.7 million, respectively, primarily to cover construction costs associated with our Power the Future program.

Total electric sales increased by 821.8 thousand megawatt-hours or 2.6% between 2005 and 2004. Residential sales volumes increased 6.3% due to the favorable summer weather in 2005. Total sales volumes to commercial/industrial customers increased 1.7% between comparative periods. Sales volumes to commercial/industrial customers, excluding our largest customers, two iron ore mines, increased 2.3% due to the favorable weather during the summer of 2005. We estimate that weather increased our electric revenues by approximately $68.8 million during 2005 as compared to the prior year. As measured by cooling degree days, 2005 was 114.7% warmer than in 2004.

Sales volumes in the Resale-Utilities class decreased 52.6% primarily due to the reduced availability of base-load capacity for sale at competitive prices as a result of limited fuel supplies and outages. Sales volumes to municipal utilities, the other retail/municipal customer class, increased 12.8% between the periods due to higher off-peak demand from lower margin municipal wholesale power customers.

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 $59.0 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.

Electric Fuel and Purchased Power Expenses

2005 vs. 2004: Gross fuel and purchased power costs for our electric utilities increased by a total of $260.8 million during 2005 when compared with 2004. During 2005, we deferred $72.8 million of fuel and purchased power costs which resulted in a net increase of fuel and purchased power expense of $188.0 million or 32.1% during 2005 when compared to 2004. The increase in fuel and purchased power expense was driven by a 2.6% increase in megawatt-hour sales and an increase in our average cost of fuel and purchased power from $17.49 per megawatt-hour in 2004 to $22.44 per megawatt-hour in 2005, or 28.3% between the comparative periods.

The increase in our average cost of fuel and purchased power is due primarily to (1) the reduced availability of nuclear generation due to scheduled refueling outages, (2) higher natural gas prices that increased the cost of power supplied by natural gas, (3) the impact of the implementation of the Midwest Independent Transmission System Operator, Inc.’s (MISO) bid based energy market (MISO Midwest Market) in April 2005 and (4) limitations on coal supplies due to transportation shortfalls.

During 2005, we had two scheduled refueling outages at our nuclear plant and in 2004 we had one scheduled refueling outage. As a result, we had approximately 1,145,000 fewer megawatt hours of nuclear generation in 2005. Our average fuel cost for nuclear generation is approximately $5 per megawatt hour, while the average energy cost for purchased power was approximately $55 per megawatt hour. We estimate that the reduction in nuclear generation resulted in approximately $57 million of increased fuel and purchased power costs in 2005 as compared to 2004. During the 2005 outages we replaced both reactor vessel heads resulting in longer outages. This work, along with other planned maintenance, lasted longer than originally expected due to delays. During 2006,

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we have one planned refueling outage at our nuclear plant. For more information regarding the scheduled refueling outages, see Factors Affecting Results, Liquidity and Capital Resources — Nuclear Operations.

In 2005, we experienced significant increases in the cost of natural gas used in our own generating assets and in the price of purchased energy which is highly influenced by the price of natural gas. This increase was most significant in the last six months of 2005 due to market related factors including the hurricanes in the Gulf of Mexico. The average combined cost per megawatt hour of purchased energy and natural gas fired units in 2005 was 47.7% higher than in 2004, increasing total cost by approximately $77.2 million.

In April 2005, we began participating in the MISO Midwest Market which fundamentally changed the way we dispatch our generating units and obtain purchased energy. As part of this new market, we are subject to new types of charges which, among other things, recognize the cost of transmission congestion, megawatt-hour losses and other costs associated with operating the generating units in an uneconomic fashion to support the MISO Midwest Market service territory. Because the State of Wisconsin has a constrained transmission system, we believe these costs are higher for us than in other parts of the MISO Midwest Market service territory. The incremental costs associated with the MISO Midwest Market charges identified above were approximately $28 million in 2005. For more information regarding MISO and the MISO Midwest Market, see Factors Affecting Results, Liquidity and Capital Resources — Industry Restructuring and Competition — Electric Transmission and Energy Markets.

Our 2005 operations were also adversely impacted by limitations on deliveries of coal supply due to the failure of our primary rail delivery supplier to deliver contracted quantities of coal to our units. The largest limitation was related to critical rail track maintenance in the Powder River basin. This, in turn, resulted in reduced coal deliveries of the coal which primarily serves our Oak Creek and Pleasant Prairie generating units from June through December 2005. In response to the reduced deliveries, we limited the generating capability of these units in off-peak periods and purchased more expensive replacement power and, where possible, took measures to purchase and transport higher cost coal in place of contracted supplies. We estimate that this increased our costs by approximately $52 million in 2005. For additional information on the decreased coal deliveries, see Factors Affecting Results, Liquidity and Capital Resources — Market Risks and Other Significant Risks — Commodity Price Risk below.

Under the State of Wisconsin fuel rules, we are allowed to request recovery in fuel revenues if our projected fuel and purchased power costs exceed bands established by the PSCW. In March 2005, we received a rate order that allowed us to increase our annual revenues by $114.9 million (final order received in November 2005 for an annual increase of $122.6 million) due to increased fuel and purchased power costs. As provided under the Wisconsin rules, we are also allowed to request deferral for the costs associated with adverse events which materially impact fuel and purchased power costs which were not anticipated, or for which costs could not be reasonably estimated at the time of the fuel recovery request for consideration in future rate proceedings. During 2005, we deferred approximately $72.8 million of fuel and purchased power costs due to the extended outage at Point Beach Unit 2, the coal delivery problems and increased costs associated with the MISO Midwest Market. During 2005, we estimate that we under-recovered fuel and purchased power costs by $108.4 million before these deferred items. Adjusted for the allowed deferrals, our net under-recovered fuel and purchased power costs were approximately $35.6 million.

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.

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 2005, 2004 and 2003.


Gas Utility Operations	2005		2004		2003
	(Millions of Dollars)
Operating Revenues	$	1,417.5	$	1,252.4	$	1,226.1
Cost of Gas Sold		1,047.3		890.9		863.3

Gross Margin	$	370.2	$	361.5	$	362.8

We believe 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 2005, 2004 and 2003.

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Gas Utility Operations	Gas Gross Margin						Gas Therm Deliveries
	2005		2004		2003		2005	2004	2003
	2005		2004		2003		2005	2004	2003
	(Millions of Dollars)						(Millions, Except Degree Days)
Customer Class
Residential	$	240.5	$	238.0	$	233.0	791.0	809.9	853.7
Commercial/Industrial		72.9		71.9		71.0	460.7	464.0	492.5
Interruptible		1.8		1.8		2.0	23.4	24.7	27.5

Total Gas Sold		315.2		311.7		306.0	1,275.1	1,298.6	1,373.7
Transported Gas		48.5		43.8		41.8	893.7	769.5	797.5
Other Operating		6.5		6.0		15.0	—	—	—

Total	$	370.2	$	361.5	$	362.8	2,168.8	2,068.1	2,171.2

Weather - Degree Days (a)
Heating (6,697 Normal)							6,628	6,663	7,063

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

2005 vs. 2004: Gas utility gross margin increased by $8.7 million or 2.4% between comparative periods. This increase reflects $6.5 million of price increases which reflects the full year’s impact of a $25.9 million annual rate increase, which became effective in March 2004. Total therm deliveries were 4.9% higher during 2005 primarily due to increased transport gas deliveries of 124.2 million therms. Transport volumes increased between the comparative periods due to a higher amount of electric generation from natural gas within our service territory. A portion of these sales are eliminated in consolidation. Our margins on these transport gas volumes are significantly lower than our margins for retail gas sales. The price increases and increased transport volumes were offset, in part, by a decrease in residential therm deliveries. Residential therm deliveries decreased 2.3% as compared to 2004, due to slightly warmer weather and a decrease in use per customer that was driven in part by higher commodity prices. As measured by heating degree days, 2005 was less than 1% warmer than 2004.

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 March 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.

Other Operation and Maintenance Expenses

2005 vs. 2004: Other operation and maintenance expenses increased by $47.4 million or 4.9% during 2005 compared with 2004. The most significant changes in our operation and maintenance expense related to increased lease costs and increased nuclear outage costs. Partially offsetting these increases were a charge in 2004 for severance costs related to the voluntary severance program and lower employee costs in 2005 due to fewer employees.

The largest operations and maintenance increase for the utility energy segment related to $50.0 million of costs that we recognized under lease agreements between We Power and Wisconsin Electric in connection with our Power the Future plan. Initially, Wisconsin Electric defers the lease payments and then amortizes the payments to expense as we recover revenues from our customers under specific pricing agreements. As noted in the electric revenue discussion, in May 2004 and May 2005 the PSCW approved pricing increases to recover the Wisconsin retail portion of these lease costs.

In addition to the increased lease costs, our nuclear operating and maintenance expense increased approximately $11.0 million due to two scheduled refueling outages in 2005 where we also replaced the reactor vessel heads. In 2004, we had one scheduled refueling outage and in 2006 we only have one scheduled refueling outage. This increase was partially offset by a $10.0 million settlement we received to resolve a vendor dispute.

Additionally, in 2004 we recognized $28.2 million of severance related costs due to the voluntary severance program that was implemented in the second half of 2004. In 2005, we had approximately 210 fewer employees, which reduced operation and maintenance costs by $12.9 million.

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Benefit costs increased $7.0 million between comparative periods due to increased pension and medical costs. In October 2005, we announced that we were offering to our retirees a Medicare Advantage program as an option within our existing post-retirement medical and drug plans. As a result of the Medicare Advantage program we anticipate that our 2006 post-retirement costs will be approximately $13.0 million less than our 2005 costs. However, we expect an increase in our 2006 pension costs to offset this reduction due to lower discount rates and lower than expected historical returns on plan assets.

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 our Power the Future plan. In May 2004, the PSCW approved a pricing increase to recover the Wisconsin retail portion of these lease costs. 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 2004, 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 severance program 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.

Depreciation, Decommissioning and Amortization Expense

2005 vs. 2004: Depreciation, decommissioning and amortization expense increased by $8.6 million in 2005 as compared to 2004. This increase was primarily due to increased depreciable plant balances. In November 2005, the PSCW approved new depreciation rates which are effective January 1, 2006. We expect the new depreciation rates to reduce annual depreciation expense by approximately $17 million due to the lengthening of nuclear plant lives.

2004 vs. 2003: Depreciation, decommissioning and amortization expense decreased by $0.7 million in 2004 as compared to 2003. This slight decrease was due to a $7.7 million reduction in decommissioning expense in 2004 due to the tax impacts associated with rebalancing the nuclear decommissioning trusts. This decrease was partially offset by increased depreciation expense on increased depreciable plant balances.

NON-UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Effective May 31, 2005, we sold our Calumet facility, which was previously included in the operations of the non-utility energy segment. As a result of this sale, we have determined that the Calumet operations meet the definition of discontinued operations under Statement of Financial Accounting Standards (SFAS) 144, Accounting for the Impairment or Disposal of Long-Lived Assets. All periods presented have been restated to exclude the results of the Calumet operations. See Results of Operations — Discontinued Operations below for further information.

The most significant subsidiary included in this segment is We Power, which constructs and owns power plants associated with our Power the Future plan and leases them to Wisconsin Electric. This segment reflects revenues billed under the PWGS Unit 1 lease and the depreciation expense related to PWGS Unit 1. The following table compares our non-utility energy segment’s operating income (loss) during 2005, 2004 and 2003.


Non-Utility Energy Segment	2005		2004		2003
	(Millions of Dollars)
Operating Revenues	$	40.0	$	19.9	$	12.3
Other Operating Expenses
Other Operation and Maintenance		14.4		12.9		16.2
Depreciation, Decommissioning and Amortization		5.9		1.4		1.3
Property and Revenue Taxes		0.2		1.0		1.5
Asset Valuation Charges, Net		—		—		49.0

Operating Income (Loss)	$	19.5	$	4.6	($	55.7	)

2005 vs. 2004: Our non-utility energy segment had operating income of $19.5 million during 2005 compared with $4.6 million during 2004. The increase in operating income between the comparative periods is primarily due to Unit 1 at PWGS commencing service in July 2005. This unit had operating income of $18.9 million during its six months of operation in 2005.

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2004 vs. 2003: Our non-utility energy segment had operating income of $4.6 million during 2004 compared with an operating loss of $55.7 million in 2003. 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.

CORPORATE AND OTHER CONTRIBUTION TO OPERATING INCOME

In August 2005, we announced our intent to sell our Minergy Neenah facility, which was previously included in the operations of corporate and other affiliates. As a result of this announcement, we have determined that the Minergy Neenah operations meet the definition of discontinued operations under SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets. All periods presented have been restated to exclude the results of Minergy Neenah operations. See Results of Operations — Discontinued Operations below for further information. This segment primarily reflects the operations of Wispark and holding company costs that are not allocated to subsidiaries.

2005 vs. 2004: Corporate and other affiliates had operating income of $1.0 million in 2005 compared with an operating loss of $3.2 million in 2004. The improved results reflect increased earnings from Wispark. However, we are reducing our Wispark assets and we expect to see lower Wispark earnings in the future.

2004 vs. 2003: We had net corporate and other affiliates operating losses of $3.2 million during 2004 compared with net operating losses of $4.3 million in 2003.

CONSOLIDATED OTHER INCOME AND DEDUCTIONS, NET

The following table identifies the components of consolidated other income and deductions, net during 2005, 2004 and 2003.


Other Income and Deductions, Net	2005			2004			2003
Other Income and Deductions, Net	2005			2004			2003
	(Millions of Dollars)
Equity in Earnings of ATC	$	34.6		$	30.1		$	26.0
Carrying Costs on Deferred Transmission Charges		20.5			13.9			9.3
Allowance for Funds Used During Construction		9.2			2.8			5.1
Debt Redemption Costs		—			(22.9	)		—
Other, net		(1.0	)		(8.1	)		1.3

Total Other Income and Deductions, Net	$	63.3		$	15.8		$	41.7

2005 vs. 2004: Other income and deductions, net increased by $47.5 million in 2005 compared to 2004. In 2004, we recognized $22.9 million of debt redemption costs associated with the early redemption of approximately $500 million of long-term debt. Similar debt redemption costs were not incurred in 2005. We recognized higher carrying costs on deferred electric transmission costs of $6.6 million. The allowance for funds used during construction increased $6.4 million in 2005 due to a higher average balance of allowance for funds used during construction (AFUDC) - qualifying utility construction projects in 2005.

2004 vs. 2003: Other income and deductions, net decreased by $25.9 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 approximately $500 million of the sales proceeds for early redemption of long-term debt.

CONSOLIDATED INTEREST EXPENSE

2005 vs. 2004: Total interest expense decreased by $20.0 million in 2005 compared with 2004. The decrease in interest expense primarily reflects lower average debt levels in 2005 as compared to 2004. During 2004, we reduced debt levels by $654.2 million primarily with proceeds from the sale of our manufacturing segment. However, due to the increased construction activity our year end debt balances have increased by $291.9 million. To the extent that we incur debt associated with construction in progress, we capitalize the interest costs in accordance with our accounting policies.

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%.

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CONSOLIDATED INCOME TAXES

2005 vs. 2004: Our effective tax rate applicable to continuing operations was 33.0% in 2005 compared to 37.7% in 2004. In 2005, we reversed $16.3 million of valuation allowances associated with state net operating loss carry forwards as we concluded that it was more likely than not that we would realize these benefits. Excluding this nonrecurring item, our effective tax rate was 36.6%. For further information see Note H — Income Taxes in the Notes to Consolidated Financial Statements.

2004 vs. 2003: In 2004, our effective income tax rate from continuing operations was 37.7% compared with a 35.5% rate during 2003. The increase in the effective tax rate is due primarily to the inability to deduct state income taxes on losses of certain non-utility subsidiaries.

DISCONTINUED OPERATIONS

Our discontinued operations include our manufacturing operations which were sold effective July 31, 2004, our Calumet facility which was sold in May 2005 and our Minergy Neenah facility. As of December 31, 2005, we are considering offers to sell our Minergy Neenah facility.

The following table identifies the primary components of income from discontinued operations during 2005, 2004 and 2003.


Discontinued Operations	2005		2004			2003
	(Millions of Dollars)
Manufacturing	$	—	$	184.2		$	43.9
Non-Utility and Other		5.1		(97.4	)		(0.9	)

Income from Discontinued Operations, Net	$	5.1	$	86.8		$	43.0

Our 2005 earnings from discontinued operations reflect a gain on the sale of the Calumet facility, the favorable resolution of liabilities at Calumet and an adjustment to the carrying value of Minergy Neenah.

Our 2004 earnings from discontinued operations reflect an after-tax gain of $152.3 million on the sale of our manufacturing business. Our 2004 earnings from discontinued operations also reflect valuation charges of $79.3 million after-tax related to Calumet and $17.6 million after-tax related to Minergy Neenah.

Our 2003 earnings from discontinued operations reflect net operating earnings of $43.9 million related to our manufacturing segment.

See Note D — Asset Sales, Divestitures and Discontinued Operations in the Notes to Consolidated Financial Statements for further information regarding the transactions described above.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

The following table summarizes our cash flows during 2005, 2004 and 2003:


Wisconsin Energy Corporation	2005			2004			2003
	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$	576.9		$	599.0		$	528.9
Investing Activities	($	697.1	)	$	242.8		($	595.2	)
Financing Activities	$	157.8		($	834.3	)	$	59.4

Operating Activities

Cash provided by continuing operating activities decreased to $576.9 million during 2005 compared with $599.0 million during 2004. This decline reflected increased working capital needs for our utility business and an increase in deferred costs, offset in part by lower cash taxes and increased cash earnings. During 2005, we experienced significant increases in natural gas costs which increased our

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working capital requirements for natural gas in storage. The increased natural gas costs also led to an increase in accounts receivable as the cost of gas is recovered dollar for dollar in our natural gas revenues. During 2005, we also experienced increased deferred costs related to transmission costs and deferred fuel. We would not expect similar levels of deferred transmission costs in 2006 as we received a rate order in January 2006 which increased our recoveries of transmission costs by approximately $67.5 million per year. The deferred fuel costs related primarily to an extended outage at our nuclear plant, increased costs associated with problems in our vendors’ ability to deliver coal via the railroad system and costs related to the implementation of the MISO Midwest Market. During 2005, our cash taxes were lower than 2004 due to the ability to realize tax benefits on the sale of non-utility assets and accelerated tax depreciation on PWGS Unit 1.

Cash provided by operating activities increased to $599.0 million during 2004 compared with $528.9 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.

Investing Activities

During 2005, we had $697.1 million of net cash outflows from investing activities. In 2004, we had net cash inflows from investing activities of $242.8 million and in 2003 we had net cash outflows of $595.2 million. In 2005, capital expenditures increased related to our Power the Future plan at We Power and for compliance with the consent decree entered into with the United States Environmental Protection Agency (EPA) (See Factors Affecting Results, Liquidity and Capital Resources — Environmental Matters). In addition, expenditures associated with nuclear fuel purchases were higher during 2005. In 2004, we recognized proceeds of $857.0 million for the sale of our manufacturing segment.

The following table identifies capital expenditures by year:


Capital Expenditures	2005		2004		2003
	(Millions of Dollars)
Utility Energy	$	458.6	$	426.5	$	455.6
Non-Utility Energy		276.6		191.0		163.6
Other		9.9		19.0		28.8

Total Capital Expenditures	$	745.1	$	636.5	$	648.0

We Power, which is included in the Non-Utility Energy segment, had capital expenditures of $275.1 million, $190.4 million and $162.9 million for the three years ended December 31, 2005, 2004 and 2003.

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. As a result, the sale of assets is a significant component of our investing activities.

The following table identifies cash proceeds from asset sales:


Asset Sales	2005		2004		2003
	(Millions of Dollars)
Real Estate	$	54.5	$	38.7	$	17.4
Wisvest		37.1		—		37.7
We Power		34.6		—		—
Manufacturing		—		857.0		—
Other		7.6		3.9		0.2

Total Asset Sales	$	133.8	$	899.6	$	55.3

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Financing Activities

The following table summarizes our cash flows from financing activities:


	2005			2004			2003
	(Millions of Dollars)
Increase (Reduce) Debt	$	291.9		($	654.2	)	$	120.7
Dividends on Common Stock		(102.9	)		(97.8	)		(93.7	)
Common Stock, net		(28.1	)		(81.8	)		56.1
Other		(3.1	)		(0.5	)		(23.7	)

Cash Provided by (Used in ) Financing	$	157.8		($	834.3	)	$	59.4

During 2005, cash provided by financing activities was $157.8 million compared to $834.3 million of cash used for financing activities during 2004. In 2005, the primary uses of cash were to pay dividends on common stock and to purchase common stock to satisfy benefit plan obligations.

In July 2005, PWGS issued $155.0 million of 4.91% senior notes in a private placement. The senior notes have a mortgage style repayment feature and have an average life approximating 15 years. The final payment is due July 15, 2030. Proceeds from the sale of the senior notes were used primarily to repay short-term debt incurred during construction at PWGS. For further information, see Note E — Port Washington Generating Station in the Notes to Consolidated Financial Statements.

Wisconsin Gas retired at the scheduled maturity date $65 million of 6-3/8% Notes due November 1, 2005. In November 2005, Wisconsin Gas issued $90 million of 5.90% Debentures due December 1, 2035. The securities were issued under shelf registration statements filed with the SEC. The proceeds from the sale were used to repay a portion of our outstanding commercial paper. The commercial paper was incurred to both retire the $65 million of 6-3/8% Notes and for working capital requirements.

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.

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.

No new shares of common stock were issued in 2005. 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, we issued approximately 2.7 million new shares of common stock in connection with these plans. In 2004 and 2003, we received payments aggregating $4.8 million and $62.9 million, respectively. In February 2004, we announced that we did not expect to issue new shares under these programs; rather we instructed the independent plan agents to begin purchasing the shares in the open market in lieu of issuing new shares. During 2005 and 2004, our plan agents purchased 2.0 million shares at a cost of $75.1 million and 3.2 million shares at a cost of $102.3 million, respectively, to fulfill exercised stock options. In 2005, we received proceeds of $47.0 million related to the exercise of stock options compared with $66.1 million in 2004. Prior to February 2004, we issued new shares to fulfill these obligations.

CAPITAL RESOURCES AND REQUIREMENTS

In 2000, we announced a growth strategy which, among other things, called for us to sell non-core assets and reduce our debt levels. Our debt to total capital ratio has decreased from 68.3% at September 30, 2000 to 59.5% at December 31, 2005 due primarily to asset sales. Over the next several years, we expect to have some limited asset sales, but at levels significantly lower than the previous six year level.

In 2002, we initiated the construction of the first of our four planned generating units under our Power the Future program. The first unit at PWGS was completed and placed into service in July 2005. We expect to spend approximately $1.9 billion to complete construction of the remaining three generating units. Over the next several years, we expect to fund these plants with cash from operations and debt offerings.

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Capital Resources

We anticipate meeting our capital requirements during 2006 and the next several years 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.

We have access to 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.

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. We will continue to evaluate the potential issuance of environmental trust bonds.

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, 2005, we had approximately $1.2 billion of available unused lines of bank back-up credit facilities on a consolidated basis and approximately $456.3 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, 2005:


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	$	1.8	$	298.2	Apr-2006	3 year
Wisconsin Electric	$	250.0	$	7.0	$	243.0	June-2007	3 year
Wisconsin Electric	$	125.0	$	—	$	125.0	Nov-2007	3 year
Wisconsin Gas	$	200.0	$	—	$	200.0	June-2007	3 year

Each of these facilities may be extended for an additional 364 days beyond the date of expiration, subject to lender agreement.

We are currently in the process of renewing Wisconsin Energy’s $300 million credit facility which expires on April 8, 2006. In addition, we are also reviewing the possibility of amending and extending the other existing Wisconsin Energy, Wisconsin Electric and Wisconsin Gas credit facilities.

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


Capitalization Structure	2005				2004
	(Millions of Dollars)
Common Equity	$	2,680.1	40.0	%	$	2,492.4	40.2	%
Preferred Stock of Subsidiaries		30.4	0.5	%		30.4	0.5	%
Long-Term Debt (including current maturities)		3,527.0	52.7	%		3,340.5	53.9	%
Short-Term Debt		456.3	6.8	%		338.0	5.4	%

Total	$	6,693.8	100.0	%	$	6,201.3	100.0	%

Ratio of Debt to Total Capital			59.5	%			59.3	%

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As described in Note J — 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, 2005.


	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-

On March 29, 2005, S&P affirmed the security ratings of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas and changed the security ratings outlook from stable to negative for all three companies. The security rating outlooks assigned by 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.

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.

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.

B-18

Capital Requirements

Our current estimated 2006, 2007 and 2008 capital expenditures, excluding the purchase of nuclear fuel, are as follows:


Capital Expenditures	Actual 2005		Estimated 2006		Estimated 2007		Estimated 2008
	(Millions of Dollars)
Utility Energy	$	458.6	$	503.0	$	450.0	$	500.0
Non-Utility Energy		276.6		512.5		675.0		475.0
Other		9.9		4.5		—		—

Total	$	745.1	$	1,020.0	$	1,125.0	$	975.0

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 estimated capital requirements through 2010 for Power the Future include approximately $2.6 billion to construct 2,120 megawatts of new natural gas-fired and coal-fired generating capacity of which we have expended approximately $673.9 million through the end of 2005. In the fourth quarter of 2005, we completed the sale of approximately a 17% interest (200 megawatts) in the Oak Creek expansion to two parties, at which time we received approximately $34.6 million in cash. The co-owners will share ratably in the construction costs. Total output of all four units, including the two unaffiliated entities’ portion, is 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. We Power, a non-utility subsidiary, is constructing the new generating plants, which will be leased to Wisconsin Electric under 25-30 year lease agreements. We expect that Wisconsin Electric will recover the lease payments in its utility rates.

In June 2005, we purchased the development rights to two wind farm projects from Navitas Energy Inc. We plan to develop the wind sites and construct wind turbines with a combined generating capability between 130 to 200-megawatts at a cost in the range of $250 to $320 million. We anticipate the cost to build the wind farm projects would be recovered in our rates. We plan to file the necessary regulatory and environmental applications in 2006. We expect the turbines to be placed in service between 2007 and 2008 dependent upon the availability of wind turbines and the receipt of necessary regulatory approvals.

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, 2005. 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 as reflected in the table below. 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 G — Variable Interest Entities in the Notes to Consolidated Financial Statements.

B-19

Contractual Obligations/Commercial Commitments: We have the following contractual obligations and other commercial commitments as of December 31, 2005:


	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)	$	5,944.6	$	639.7	$	896.7	$	299.2	$	4,109.0
Capital Lease Obligations (c)		577.6		60.3		102.8		81.7		332.8
Operating Lease Obligations (d)		225.1		51.1		84.9		40.8		48.3
Purchase Obligations (e)		2,835.7		758.7		1,468.2		423.4		185.4
Other Long-Term Liabilities		3.8		1.4		0.9		1.5		—

Total Contractual Obligations	$	9,586.8	$	1,511.2	$	2,553.5	$	846.6	$	4,675.5

(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 construction, 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. For a discussion of 2006, 2007 and 2008 estimated capital expenditures, see Capital Requirements above.

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 PWGS 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 approved key financial terms of the leased generation contracts including fixed construction costs of the PWGS at $309.6 million and $280.3 million (2001 dollars), respectively, subject to escalation at the GDP inflation rate, force majeure, excused events and event of loss provisions. For additional information, see Power the Future — Port Washington below.

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 (Oak Creek expansion) adjacent to the site of Wisconsin Electric’s existing Oak Creek Power Plant. The order approves key financial terms of the leased generation contracts including a target construction cost of the Oak Creek expansion of $2.191 billion, plus, subject to PSCW approval, cost over-runs of up to 5%, costs attributable to force majeure events, excused events and event of loss provisions. For additional information, see Power the Future — Oak Creek Expansion 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, continuing legal challenges to permits obtained, changes in applicable laws or regulations, adverse interpretation or enforcement of permit conditions, laws and regulations by the permitting agencies, the inability to obtain necessary operating permits in a timely manner, governmental actions and events in the global economy.

B-20

If final costs for the construction of PWGS exceed the fixed costs allowed in the PSCW order, absent a finding by the PSCW of extraordinary circumstances such as force majeure conditions, this excess will not adjust the amount of the lease payments recovered from Wisconsin Electric. If final costs of the Oak Creek expansion are within 5% of the target cost, and the additional costs are deemed to be prudent by the PSCW, the final lease payments for the Oak Creek expansion recovered from Wisconsin Electric would be adjusted to reflect the actual construction costs. Costs above the 5% cap would not be included in lease payments or recovered from customers absent a finding by the PSCW of extraordinary circumstances such as force majeure conditions.

Regulatory Recovery Risk: The electric operations of Wisconsin Electric burn natural gas in its leased power plants, in several of its peaking power plants and as a supplemental fuel at several coal-fired plants. In addition, the cost of purchased power is generally tied to the cost of natural gas. Wisconsin Electric bears regulatory risk for the recovery of these fuel and purchased power costs when these costs 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. Since our merger with WICOR in 2000 through December 31, 2005, we were allowed to request recovery of fuel and purchased power costs from retail electric customers in the Wisconsin jurisdiction through our rate review process with the PSCW and in interim fuel cost hearings when such annualized costs were expected to be more than 3% higher than the forecasted costs used to establish rates. In January 2006, the PSCW approved a plan for Wisconsin Electric to refund any over-collection of fuel costs on an annual basis for 2006 to Wisconsin ratepayers and any under-collection will be subject to a 2% band. Beginning in 2007, the electric operations of Wisconsin Electric will operate under a fuel cost adjustment clause in the Wisconsin retail jurisdiction for under- and over- collection within a 2% band.

For 2005, 2004 and 2003, actual net fuel and purchased power costs at Wisconsin Electric exceeded fuel costs included in rates by $35.6 million, $0.8 million and $7.6 million, respectively.

Our utility energy segment accounts for its regulated operations in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation. Our rates are determined by regulatory authorities. Our primary regulator is the PSCW. SFAS 71 allows regulated entities to defer certain costs that would otherwise be charged to expense, if the regulated entity believes the recovery of these costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators, and recovery of these deferred costs in future rates is subject to the review and approval of those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of these costs is not approved by our regulators, the costs are charged to income in the current period. We expect to recover our outstanding regulatory assets in rates over a period of no longer than 20 years. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. Under SFAS 71, we record these items as regulatory liabilities.

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 optimize utilization of their available generating capacity and energy during periods when available power resources are projected to be greater than or less than our load 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. In addition, effective April 1, 2005, our electric utilities became market participants in the MISO Midwest Market. For additional information on the MISO Midwest Market see Utility Rates and Regulatory Matters — Other Utility Rate Matters and Industry Restructuring and Competition — Electric Transmission and Energy Markets below. 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. In addition, we manage our natural gas price risk by utilizing a gas hedging program.

In July 2005, we received a letter from Union Pacific Corporation notifying us that a force majeure event requiring maintenance on a Union Pacific railroad line was expected to result in a 15-20% reduction in the amount of contracted deliveries of Powder River Basin coal to certain of our coal generating facilities from June 2005 through November 2005. In response, we reduced generation at certain coal fueled units, primarily during lower cost off peak periods, to conserve coal inventories. This required us to obtain additional megawatt hour purchases through other potentially higher cost generating resources in the MISO Midwest Market. In August 2005, we requested and received approval from the PSCW to defer incremental fuel costs associated with reduced coal deliveries. Through December 31, 2005, we deferred approximately $26.0 million of incremental fuel costs and we expect to recover these costs in future rates, subject to review and approval of the PSCW. We do not expect to defer any additional costs related to this matter.

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

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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, both because the supply of natural gas in recent years has not kept pace with the demand for natural gas and due to the impacts of hurricanes on offshore Gulf of Mexico natural gas production. 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 and result 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.

In February 2005, the PSCW authorized the use of the escrow method of accounting for bad debt costs allowing for deferral of Wisconsin residential bad debt expense that exceed amounts allowed in rates. In 2004 and 2003, we had approval from the PSCW to defer residential bad debt net write-offs that exceed amounts allowed in rates.

As a result of gas cost recovery mechanisms, our gas distribution subsidiaries receive dollar for dollar recovery on 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. In addition, we are experiencing reduced usage of natural gas by our residential customers, who contribute higher margins than other customer classes, due to the increased natural gas costs. We expect to continue to experience this reduced usage during the 2006 winter heating season.

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 2005, 2004 and 2003, as measured by degree-days, may be found above in Results of Operations.

Interest Rate Risk: We have various short-term borrowing arrangements to provide working capital and general corporate funds. We also have variable rate long-term debt outstanding at December 31, 2005. 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, 2005 of our outstanding portfolio of $456.3 million of short-term debt with a weighted average interest rate of 4.39% and $189.8 million of variable-rate long-term debt with a weighted average interest rate of 3.77%. A one-percentage point change in interest rates would cause our annual interest expense to increase or decrease by approximately $4.6 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. Through December 31, 2005, we were operating under a PSCW-ordered, qualified five-year rate restriction period. For further information about the rate restriction, see Utility Rates and Regulatory Matters below.

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At December 31, 2005, 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	$	976.9
Nuclear decommissioning trust funds	$	782.1
Other post-retirement benefits trust funds	$	186.0

Fiduciary oversight of the pension and other post-retirement plan trust fund investments is the responsibility of an 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 8.5%.

Fiduciary oversight for the nuclear decommissioning trust fund investments is also the responsibility of the 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.

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, 2005, we estimate that the potential payments under these agreements that could result from credit rating downgrades totaled approximately $78.2 million.

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

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 PWGS and the Oak Creek expansion by We Power. We Power will lease the new plants 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 PWGS consisting of two 545-megawatt natural gas-fired combined cycle generating units (PWGS 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, which was completed in December 2004, and American Transmission Company LLC (ATC) to construct required transmission system upgrades to serve PWGS Units 1 and 2 as a result of their concurrent applications. PWGS Unit 1 was completed in July 2005 and placed into service at that time. Unit 1 was completed within the PSCW approved cost parameters. In October 2003, we received approval from the Federal Energy Regulatory Commission (FERC) to transfer by long-term lease certain associated FERC jurisdictional transmission

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related assets from We Power to Wisconsin Electric. 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 PWGS 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;

•

Authorized rate of return of 12.7% on equity;

•

Fixed construction cost of the PWGS Units 1 and 2 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. 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: There are currently no legal challenges to the construction of the PWGS and all construction permits have been received for Units 1 and 2. As a result of the enactment of the Energy Policy Act of 2005 (the Energy Policy Act) the FERC, through an amendment to Section 203 of the Federal Power Act, has been given jurisdiction over the acquisition of generation (which includes leasing generation), an activity that previously was not subject to the FERC’s jurisdiction. Under the FERC’s recently issued rules implementing the Energy Policy Act, Wisconsin Electric will be required to seek FERC authorization in order to lease the remaining PWGS unit prior to the unit being placed into service. We are unable to determine at this time the magnitude of the impact of this new regulatory requirement on the Power the Future plan, if any.

Power the Future - Oak Creek Expansion

Background: In November 2003, the PSCW issued an order (the Oak Creek Order) granting Wisconsin Energy, Wisconsin Electric and We Power a CPCN to commence construction of two 615-megawatt coal-fired units (the Oak Creek expansion) to be located adjacent to the site of Wisconsin Electric’s existing Oak Creek Power Plant. We anticipate the first unit will be operational in 2009 and the second unit will be operational in 2010. The Oak Creek 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 $2.191 billion, 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. All necessary permits have been received at this time. In June 2005, construction commenced at the site.

In November 2005, we completed the sale of approximately a 17% interest in the project to two unaffiliated entities, who will share ratably in the construction costs.

Lease Terms: In October 2004, the PSCW approved the lease generation contracts between Wisconsin Electric and We Power for the Oak Creek expansion. Key terms of the leased generation contracts include:

•

Initial lease term of 30 years with the potential for subsequent renewals at reduced rates;

•

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

•

Imputed capital structure of 55% equity, 45% debt;

•

Authorized rate of return of 12.7% on equity;

•

Recovery of carrying costs during construction; and

•

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

In April 2004, the PSCW approved the deferral of certain costs related to the Oak Creek expansion for recovery in future rates. (See Limited Rate Adjustment Request below for further information).

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Legal and Regulatory Matters: The CPCN granted for the construction of the Oak Creek expansion was the subject of a number of legal challenges by third parties; these legal challenges were resolved in June 2005. We have received all permits necessary to commence construction. Certain of these permits continue to be contested, but remain in effect unless and until overturned by a reviewing court or administrative law judge. The major permits are discussed below.

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. The Dane County Circuit Court’s decision was appealed and in June 2005, the Supreme Court of Wisconsin issued its decision which reversed the Dane County Circuit Court’s decision that vacated the PSCW order authorizing us to build the Oak Creek expansion and upheld the PSCW’s order in all respects. The CPCN granted by the PSCW was reinstated and is in full force and effect.

As a result of the delay to the start of construction caused by litigation, the project cost is expected to increase by $50 to $55 million. This represents an increase of approximately 2.4% to 2.6% in the total cost of the project. We believe these costs are ultimately recoverable under the terms of the lease agreements between We Power and Wisconsin Electric. However, recovery is subject to our final calculation of costs and also to review and approval by the PSCW.

In September 2003, several parties filed a request with the Wisconsin Department of Natural Resources (WDNR) for a contested case hearing in connection with our application to the WDNR for a Chapter 30 permit for wetlands and waterways alterations and construction on the bed of Lake Michigan for the construction of the Oak Creek expansion. That request was granted and assigned to an administrative law judge. The hearing took place in August 2004 and in November 2004, the administrative law judge approved the WDNR’s issuance of the Chapter 30 permit for the Oak Creek expansion. In December 2004, 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 based on procedural errors. The WDNR joined in this motion. In March 2005, the court dismissed the appeal. The opponents appealed the court’s dismissal to the Wisconsin Court of Appeals. In February 2006, the Wisconsin Court of Appeals affirmed the lower court’s dismissal of the case. The opponents can seek reconsideration of the court’s decision or can petition the Wisconsin Supreme Court for review.

We applied to the WDNR to modify the existing Wisconsin Pollution Discharge Elimination System (WPDES) permit that is required for operation of the water intake and discharge system for the planned Oak Creek expansion and existing Oak Creek generating units. In March 2005, the WDNR determined that the proposed cooling water intake structure and water discharge system meets regulatory requirements and reissued the WPDES permit with specific limitations and conditions. The opponents filed a petition for judicial review in Dane County Circuit Court and a request for a contested case proceeding with the WDNR. In September 2005, the judicial review proceeding in Dane County Circuit Court was dismissed. All parties to this action agreed to the dismissal. The WDNR granted a contested case hearing and the administrative law judge has scheduled a hearing for March 2006. We anticipate a decision by the administrative law judge in 2006.

In May 2005, we received the Army Corps of Engineers federal permit necessary for the construction of the Oak Creek expansion. Opponents may appeal the permit in federal court.

In January 2004, the WDNR issued the Air Pollution Control Construction Permit (Air Permit) to Wisconsin Electric for the Oak Creek expansion. The permit was opposed and a contested case hearing with the WDNR was held in October 2004. In February 2005, an administrative law judge issued a decision affirming the WDNR January 2004 issuance of the Air Permit. The decision was opposed and project opponents filed a petition for judicial review with the Dane County Circuit Court. In September 2005, the Dane County Circuit Court dismissed with prejudice the appeal of the administrative law judge’s decision. All parties to this action agreed to the dismissal. This dismissal is the final resolution of all legal challenges to the issuance of the Air Permit.

In addition, as a result of the enactment of the Energy Policy Act the FERC, through an amendment to Section 203 of the Federal Power Act, has been given jurisdiction over the acquisition of generation (which includes leasing generation), an activity that previously was not subject to the FERC’s jurisdiction. Under the FERC’s recently issued rules implementing the Energy Policy Act, Wisconsin Electric will be required to seek FERC authorization in order to lease the two units that are part of the Oak Creek expansion prior to the units being placed into service. We are unable to determine at this time the magnitude of the impact of this new regulatory requirement on the Power the Future plan, if any.

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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: For the period from March 2000 until December 31, 2005, the rates of We Energies (the trade name of Wisconsin Electric and Wisconsin Gas) were governed by an order from the PSCW in connection with the approval of the WICOR acquisition. Under this order, We Energies was restricted from increasing Wisconsin rates for a five year period ending December 31, 2005, with certain limited exceptions.

Wisconsin Electric: In July 2005, we filed an electric and steam price increase request with the PSCW. Under a limited rate proceeding, we requested an increase in electric rates of $143.6 million for 2006, and an $8.8 million total increase in rates for steam over the two year period of 2006 and 2007. The requested electric rate increase included: (1) costs associated with the continued investment in our Power the Future strategy; (2) recovery of transmission costs incurred that exceed the amount we are currently collecting from customers; (3) additional sources of renewable energy; and (4) a rate freeze for day to day operations of the electric system until 2008. The requested steam rate increase was due to (1) the costs of maintaining the steam system, (2) the cost of fuel and (3) the costs associated with making changes to our steam utility operations as part of the reconstruction of the Marquette Interchange project in downtown Milwaukee, Wisconsin.

Subsequent to the initial filing of this pricing request, we experienced a significant increase in the cost of fuel and purchased power due to the increases in natural gas prices and the reductions in coal deliveries as discussed above. In October 2005, we filed a letter with the PSCW informing them of our need to include the increased cost of natural gas used for generation of electricity in our pending 2006 pricing request. The PSCW considered these additional costs and approved an increase in electric rates of $222.0 million in January 2006. In addition, the PSCW approved an increase in steam rates of $7.8 million or 31.5% to be phased in over the two year period of 2006 and 2007. These rate increases became effective on January 26, 2006 and we anticipate will remain in effect through December 2007.

The January 2006 order also addressed Wisconsin Electric’s under- and over-collection of fuel costs in its electric rates. For 2006, the PSCW approved a plan for Wisconsin Electric to refund any over-collection of fuel costs on an annual basis to ratepayers and the band for under-collection of fuel costs will be 2%. Beginning in 2007, the electric operations of Wisconsin Electric will operate under a fuel cost adjustment clause in the Wisconsin retail jurisdiction with a plus or minus 2% band.

In June 2005, we filed with the PSCW a natural gas price increase request of $27.4 million for Wisconsin Electric. The increase was requested to address the higher costs associated with adding and maintaining gas mains and infrastructure to maintain safety and reliability and certain costs related to gas in storage. In January 2006, we received approval from the PSCW for a rate increase of $21.4 million or 2.9% for Wisconsin Electric. This rate increase became effective on January 26, 2006 and we anticipate will remain in effect through December 2007.

The January 2006 order approved a return on equity for Wisconsin Electric operations of 11.2%. In 2005, Wisconsin Electric’s approved return on equity was 12.2%.

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The table below summarizes the anticipated annualized revenue impact of recent rate changes.


Service - Wisconsin Electric	Incremental Annualized Revenue Increase		Percent Change in Rates		Effective Date
	(Millions)		(%)
Retail electric, Wisconsin	$	222.0	10.6	%	January 26, 2006
Retail gas, Wisconsin	$	21.4	2.9	%	January 26, 2006
Retail steam, Wisconsin (a)	$	7.8	31.5	%	January 26, 2006
Fuel electric, Michigan	$	2.7	5.9	%	January 1, 2006
Fuel electric, Wisconsin (b)	$	7.7	0.3	%	November 24, 2005
Fuel electric, Michigan	$	2.5	5.8	%	November 1, 2005
Retail electric, Wisconsin	$	59.7	3.1	%	May 19, 2005
Retail steam, Wisconsin	$	0.5	3.6	%	May 19, 2005
Fuel electric, Wisconsin (b)	$	114.9	5.9	%	March 18, 2005
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 (c)	$	59.0	3.3	%	May 5, 2004
Fuel electric, Michigan	$	3.3	7.6	%	January 1, 2004
Fuel electric, Wisconsin (d)	$	6.1	0.3	%	October 2, 2003
Fuel electric, Wisconsin (d)	$	55.1	3.3	%	March 14, 2003
Fuel electric, Michigan	$	0.9	2.0	%	January 1, 2003

(a)	In January 2006, the PSCW issued a final order authorizing an increase in steam rates of $7.8 million over the two year period of 2006 and 2007.

(b)

In November 2005, the PSCW issued a final order authorizing a fuel surcharge for $7.7 million of additional fuel costs. In March 2005, the PSCW issued an interim order authorizing a fuel surcharge for $114.9 million that was effective until the November 2005 final order was issued by the PSCW. The final November 2005 order for $122.6 million superseded the March 2005 interim order.

(c)	In May 2004, the PSCW issued a final order authorizing an increase in electric rates for costs associated with the PWGS under construction and increased costs associated with low-income energy assistance.

(d)	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.

Wisconsin Gas: As discussed above, Wisconsin Gas was also under the five year rate restriction period which ended December 31, 2005.

In June 2005, we filed with the PSCW a natural gas price increase request, as well as all materials for the PSCW and other parties to commence the rate review required by the March 2000 order. We requested a rate increase of $53.2 million to address the higher costs associated with adding and maintaining gas mains and infrastructure to maintain safety and reliability and certain costs related to gas in storage. In January 2006, we received approval from the PSCW for a rate increase of $38.7 million or 3.7% for Wisconsin Gas. This rate increase became effective on January 26, 2006 and we anticipate will remain in effect through December 2007.

The January 2006 order approved a return on equity for Wisconsin Gas operations of 11.2%. In 2005, Wisconsin Gas had an approved return on equity of 11.8%.

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 PWGS and the Oak Creek expansion being constructed as part of our Power the Future strategy, (2) costs associated with our energy efficiency procurement plan and (3) costs associated with making changes to our steam utility systems as part of the reconstruction of the Marquette Interchange highway

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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 Oak Creek expansion, we amended this filing to reduce the total revenue request to $52.4 million. In May 2005, the PSCW issued its final written order implementing an annualized increase in electric rates of $59.7 million (3.1%) and an increase of $0.5 million (3.6%) in steam rates.

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 received approval for the increase in fuel recoveries on an interim basis in March 2005. In November 2005, we received the final rate order, which authorized an additional $7.7 million in rate increases, for a total increase of $122.6 million (6.2%). In December 2005, two parties filed suit against the PSCW in Dane County Circuit Court challenging the PSCW’s decision to allow fuel cost recovery, while allowing us to keep the savings that resulted from the WICOR acquisition. As a condition of the PSCW approval of the WICOR acquisition, Wisconsin Electric and Wisconsin Gas were restricted from increasing Wisconsin rates for a five year period ending December 31, 2005, with certain limited exceptions, but we were allowed to keep the savings generated from the merger. We believe the challenge of the PSCW’s decision is without merit, however the ultimate outcome of this matter cannot be determined at this time.

Other Utility Rate Matters

Electric Transmission Cost Recovery: Wisconsin Electric divested of its transmission assets with the formation of the ATC in January 2001. We now procure transmission service from ATC at FERC approved tariff rates. 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 infrastructure 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, 2005, we have deferred $169.4 million of unrecovered transmission costs. In January 2006, our rates were increased by approximately $67.5 million annually to recover transmission costs that were not currently in rates. We will continue to accrue carrying costs on the unrecovered balances.

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 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 band, and actual interim costs fall outside of established ranges, then we may file for a change in fuel recoveries on a prospective basis. For 2006, the upper band is 2% and we will refund any over-recovered annual fuel costs. For 2007, the band is plus or minus 2%.

Edison Sault and our Wisconsin Electric operations in Michigan operate under a Power Supply Cost Recovery 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 2005, no additional revenues were earned under the incentive portion of the GCRM and $0.2 million and $9.0 million of additional revenues were earned in 2004 and 2003 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 being collected in rates.

In 2003 and 2004, due to a combination of unusually high natural gas prices, a soft economy within our utility service territories, and limited governmental assistance available to low-income customers, we saw a significant increase in residential uncollectible accounts receivable. Because of this, we requested and received letters from the PSCW which allowed 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.

In January 2006, the PSCW issued an order approving the amortization over the next five years of the bad debts deferred in 2004 and 2003 for Wisconsin Gas and Wisconsin Electric gas operations. The bad debts deferred in 2004 and 2003 related to electric operations will be considered for recovery in future rates, subject to audit and approval of the PSCW.

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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 was 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 the use of escrow accounting. The final decision was received in March 2005. The escrow method of accounting for bad debt costs allows for deferral of Wisconsin residential bad debt expense that exceed amounts allowed in rates. As a result of this approval from the PSCW, we escrowed approximately $17.2 million in 2005 related to bad debt costs. These amounts were not addressed in the January 2006 rate order, and will therefore be considered for recovery in future rates, subject to audit and approval of the PSCW. We will continue following the escrow method of accounting for bad debts as approved in the March 2005 PSCW order.

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. We will continue to evaluate the potential issuance of environmental trust bonds.

MISO Midwest Market: In January 2005, we requested deferral accounting treatment from the PSCW for certain incremental costs or benefits that may occur due to the implementation on April 1, 2005 of the MISO Midwest Market. We received approval for this accounting treatment in March 2005. Additionally, in March 2005 we submitted a joint proposal to the PSCW with other utilities requesting escrow accounting treatment for the MISO Midwest Market costs until each utility’s first rate case following April 1, 2008. The purpose of the March 2005 request for escrow accounting was to provide clarification on costs not included in the March 2005 approval for deferral accounting treatment. We anticipate receiving a decision on this request in 2006. For additional information see Industry Restructuring and Competition — Electric Transmission and Energy Markets — MISO below.

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 that occurred in the fall of 2005. In March 2005, the PSCW denied this request. In May 2005, we requested and we received approval from the PSCW to defer replacement power costs incurred after May 30, 2005 due to the longer-than-expected outage at Point Beach Unit 2. We deferred $22.1 million of incremental purchased power costs related to the extended outage. We expect to recover these deferred costs in future rates, subject to PSCW audit and approval. For additional information see Nuclear Operations below.

Reduced Coal Deliveries: In August 2005, we requested and received approval from the PSCW to defer incremental fuel costs associated with reduced coal deliveries. Through December 31, 2005, we deferred approximately $26.0 million of incremental fuel costs and we expect to recover these costs in future rates, subject to review and approval of the PSCW. We do not anticipate deferring additional costs under this order in 2006. For further information regarding rates see Management’s Discussion and Analysis—Factors Affecting Results, Liquidity and Capital Resources — Market Risks and Other Significant Risks — Commodity Price Risk.

Depreciation Rates: In January 2005, Wisconsin Electric and Wisconsin Gas filed a joint application with the PSCW for certification of depreciation rates for specific classes of utility plant assets. In November 2005, we received notice from the PSCW that the proposed estimated lives, net salvage values and depreciation rates were approved and became effective January 1, 2006. We expect the new depreciation rates to reduce annual depreciation expense by approximately $17 million due to the lengthening of nuclear plant lives which will reduce annual expense.

ELECTRIC SYSTEM RELIABILITY

In response to customer demand for higher quality power required by modern equipment, we are evaluating and updating our electric distribution system. We are taking 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. For the long-term, we have developed a distribution system asset management strategy that requires increased levels of automation of both substations and line equipment to consistently provide the level of reliability needed for a digital economy.

Wisconsin Electric had adequate capacity to meet all of its firm electric load obligations during 2005. All of Wisconsin Electric’s generating plants performed well during the warmest 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.

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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.

Wisconsin Electric expects to have adequate capacity to meet all of its firm load obligations during 2006. However, extremely hot weather, unexpected equipment failure or unavailability could require Wisconsin Electric to call upon load management procedures during 2006 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) adding emission control equipment to existing facilities to comply with new ambient air quality standards and federal clean air rules, (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% by 2013 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 consent decree is estimated to be approximately $600 million over the 10 years ending 2013. Through December 31, 2005, we have spent approximately $216.5 million associated with implementing the EPA agreement. There could be additional costs of compliance with the EPA consent decree should Wisconsin Electric elect to control rather than retire Units 5 and 6 at the Oak Creek Power Plant. We believe this additional cost may add approximately $150 million to $350 million to the estimate. 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 I — Nuclear Operations in the Notes to Consolidated Financial Statements in this report, respectively.

National Ambient Air Quality Standards: In 2000 and 2001, Michigan and Wisconsin finalized state rules implementing phased emission reductions required to meet the National Ambient Air Quality Standard (NAAQS) for 1-hour ozone. In 2004, the EPA began implementing NAAQS for 8-hour ozone and fine particulate matter (PM _2.5 ). 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. Reductions associated with the 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 until the states develop rules and submit State Implementation Plans to the EPA to demonstrate how they intend to comply with the 8-hour ozone and fine particulate matter NAAQS.

1-hour Ozone Standard: The 1-hour ozone nonattainment rules currently being implemented by the State of Wisconsin and the ozone transport rules implemented by the State of Michigan limit NO_x emissions in phases over the 2003 - 2008 time period.

Wisconsin Electric currently expects to incur total annual operation and maintenance costs of $2-3 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 rules, permitting recovery in rates of NO_x emission reduction costs over an accelerated 10-year recovery period.

8-hour Ozone Standard: In April 2004, the EPA designated 10 counties in Southeastern Wisconsin as nonattainment areas for the 8-hour ozone NAAQS. States are required to develop and submit State Implementation Plans to the EPA by June 2007 to demonstrate how they intend to comply with the 8-hour ozone NAAQS. We expect that reductions needed to achieve compliance with the 8-hour ozone attainment standard will be implemented in stages from 2007 through 2010, and

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that some or all of these reductions will be accomplished through implementation of the Clean Air Interstate Rule (CAIR). See below for further information regarding CAIR. 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. However, the timing of the requirements may be impacted by requiring earlier installation of NO_x controls at some units, depending on how the states implement the rules.

PM_2.5 Standard: In December 2004, the EPA designated PM_2.5 nonattainment areas in the country. All counties in the State of Wisconsin and all counties in the Upper Peninsula of Michigan were designated as in attainment with the standard. It is unknown at this time whether Wisconsin or Michigan will require additional emission reductions as part of state or regional implementation of the PM_2.5 standard and what impact those requirements would have on operation of our existing coal-fired generation facilities.

Clean Air Interstate Rule: The EPA issued the final CAIR regulation in March 2005 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. CAIR requires NO_x and SO₂ emission reductions in two phases from electric generating units located in a 28-state region within the eastern United States. Wisconsin and Michigan are affected states under CAIR. The phase 1 compliance deadline is January 1, 2009 for NO_x and January 1, 2010 for SO₂, and the phase 2 compliance deadline is January 1, 2015 for both NO_x and SO₂. Overall, the CAIR is expected to result in a 70% reduction in SO₂ emissions and a 65% reduction in NO_x emissions from 2002 emission levels. The states are required to develop and submit implementation plans by October 2006, and until those plans are in place, it is not possible to estimate the impact of the CAIR. 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.

Clean Air Mercury Rule: The EPA issued the final Clean Air Mercury Rule (CAMR) in March 2005 following the agency’s 2000 regulatory determination that utility mercury emissions should be regulated. CAMR limits mercury emissions from new and existing coal-fired power plants, and caps utility mercury emission in two phases, applicable in 2010 and 2018. The caps limit emissions at approximately 20% and ultimately 70% below today’s utility mercury levels. The states are required to develop and submit implementation plans by November 2006. Until those plans are in place, it is not possible to estimate the final impact of the CAMR, but additional expenditures are anticipated in order to meet both phases of the federal rule. Because the technology is under development, it is difficult to estimate the cost. We believe the range of possible expenditures could be approximately $50 million to $200 million. The construction air permit issued for the Oak Creek expansion is not impacted by the new rule.

The federal rule is being challenged by a number of states including Wisconsin and Michigan. Depending on the litigation, the timing for compliance may be affected.

The WDNR independently developed mercury emission control rules that affect electric utilities in Wisconsin and issued state-only mercury control rules in October 2004. 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. We anticipate that the state rules will be revised or replaced, consistent with the CAMR requirements, and that no additional emission control investments will be needed as a result of the state-only rules.

Clean Air Visibility Rule: The EPA issued the Clean Air Visibility Rule (CAVR) in June 2005 to address regional haze, or regionally-impaired visibility caused by multiple sources over a wide area. The rule defines Best Available Retrofit Technology (BART) requirements for electric generating units and how BART will be addressed in the 28 states subject to EPA’s CAIR. Under CAVR, states are required to identify certain industrial facilities and power plants that affect visibility in the nation’s 156 Class I protected areas. States then determine the types of emission controls that those facilities must use to control their emissions. The pollutants from power plants that reduce visibility include particulate matter or compounds that contribute to fine particulate formation, NO_x, SO₂ and ammonia. States must submit plans to implement CAVR to the EPA by December 2007. The reductions associated with the state plans are scheduled to begin to take effect in 2014 with full implementation before 2018. Wisconsin Electric is currently unable to predict the impact that CAVR might have on the operations of our existing coal-fired generating facilities until the states develop rules and submit implementation plans to the EPA.

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Clean Water Act: Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impact. This law dates back to 1972; however, prior to September 2004, there have not been federal rules that define precisely how states and EPA regions would determine that an existing intake meets BTA requirements. This rule establishes, for the first time, national performance standards and compliance alternatives for existing facilities that are designed to minimize the potential adverse environmental impacts to aquatic organisms associated with water withdrawals from cooling water intakes. Costs associated with implementation of the rule for Wisconsin Electric’s Oak Creek Power Plant, We Power’s Oak Creek expansion and PWGS have been included in project costs. Studies to determine costs, if any, that may be associated with Wisconsin Electric’s other existing facilities are expected to take place over the next three years.

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 - Proposed Consent Decree: Wisconsin Electric entered into a proposed consent decree with the EPA to address all matters relating to information requests received from the EPA 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.

Greenhouse Gases: There have been international efforts seeking legally binding reductions in emissions of greenhouse gases, principally carbon dioxide (CO₂), including the United Nations Framework Convention on Climate Change held in Kyoto, Japan. While the Bush Administration has not supported U.S. ratification of the Kyoto Protocol or other legislation requiring reductions in CO₂, in 2002, the Bush Administration announced a goal of reducing the greenhouse gas intensity of the U.S. economy by 18% by 2012. In addition, in December 2004, the U.S. Department of Energy announced the Climate VISION program in furtherance of reduced greenhouse gas emissions. We continue to take voluntary measures to reduce our emissions of greenhouse gases; however, the impact of any future legislation that would require reductions in greenhouse gases cannot be assessed at this time.

Wisconsin Electric continues to support flexible, market-based strategies to curb greenhouse gas emissions. These strategies include emissions trading, joint implementation projects and credit for early actions. Wisconsin Electric also supports a voluntary approach that encourages technology development and transfer and includes all sectors of the economy and all significant global emitters.

Wisconsin Electric emissions in future years will continue to be influenced by several actions planned or underway as part of the Power the Future plan, including:

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Repowering the Port Washington Power Plant from coal to natural gas combined cycle units.

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Adding coal-fired units using state-of-the-art technology as part of the Oak Creek expansion.

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Increasing investment in energy efficiency and conservation.

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Maintaining and increasing non-emitting generation by potentially adding approximately 130 to 200-megawatts of wind capacity and increasing customer participation in the Energy for Tomorrow ^® renewable energy program.

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Successful renewal of the Point Beach Nuclear units’ operating licenses.

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 have reached settlements with an insurance carrier and other third parties. Through litigation, we are continuing to pursue recovery against other third parties.

Arbitration Proceedings: Our largest electric customer owns two mines that operate in the Upper Peninsula of Michigan. The mines represent approximately 7% of our annual electric sales and less than 1% of our annual net income. The mines have special negotiated contracts that expire in December 2007. The contracts have price caps for approximately 80% of the energy sales. The mines are billed at rates reflecting incremental costs and amounts billed that exceed the price caps are refunded without interest in the year following the contract year. We do not recognize revenue on amounts billed that exceed the price caps.

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The incremental power costs in the Upper Peninsula of Michigan are now determined by MISO. In April 2005, we began to bill the mines the incremental power costs as quantified by the MISO Midwest Market. The mines have notified us that they are disputing these billings and they have placed the disputed amounts in escrow. In September 2005, the mines notified us that they filed for formal arbitration related to the contracts. We have notified the mines that we believe that they have failed to comply with certain notification provisions related to annual production as specified within the contracts. As of December 31, 2005, the mines have placed $70.6 million in escrow. As noted above, the amounts that have been placed in escrow primarily relate to amounts that would have been refunded without interest in the year following the contract year. At this time, we are unable to predict the outcome of the formal arbitration process, but we believe that it will not have a material impact on our financial condition or results of operations.

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, awarding $1.2 million to the plaintiffs in a stray voltage lawsuit. The Supreme Court rejected the argument that if a utility company’s measurement of stray voltage is below the PSCW “level of concern,” that utility could not 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 2005, 2004 and 2003, Point Beach provided approximately 20% of Wisconsin Electric’s net electric energy supply.

Each Unit at the Plant has a scheduled refueling outage approximately every 18 months. In 2005, Unit 2 had a scheduled refueling outage over the second and third quarters and Unit 1 had a scheduled refueling outage over the third and fourth quarters. During the 2005 scheduled refueling outages we replaced the reactor vessel heads at each Unit. As expected, this work, along with other planned maintenance, resulted 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. See Results of Operations for further discussion regarding the costs associated with nuclear outages. In the fourth quarter of 2006, Unit 2 is scheduled to have a refueling outage. 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 February 2004, NMC and Wisconsin Electric filed an application with the United States Nuclear Regulatory Commission (NRC) to renew the operating license for both Units for an additional 20 years. The NRC approved the license renewal request in December 2005. The new operating licenses expire in October 2030 for Unit 1 and March 2033 for Unit 2.

In February 2006, we announced that we are undertaking a formal review this year regarding our options for the ownership and operation of Point Beach. At December 31, 2005, NMC operated seven nuclear generating units, down from eight units at December 31, 2004. As of February 2006, that number has decreased to six units and another owner has announced the planned sale of their unit, which would further reduce the size of the fleet operated by NMC. Given these changes, we believe it is prudent to evaluate a range of options for Point Beach. The options that we are planning to evaluate include: (1) continued operation by NMC, (2) continued operation by a third party operator other than NMC, (3) a return to in-house operation of the plant by Wisconsin Electric and (4) a sale of the Point Beach facility. We plan to complete this formal review in the fourth quarter of 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

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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.

Used Nuclear Fuel Storage and Disposal: Wisconsin Electric is authorized by the PSCW to load and store sufficient dry fuel storage containers to allow Point Beach Units 1 and 2 to operate to the end of their original operating licenses, but not to exceed the original 48-canister capacity of the dry fuel storage facility. The original operating licenses were set to expire in October 2010 for Unit 1 and in March 2013 for Unit 2 before they were renewed by the NRC in December 2005.

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 $207.4 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. In October 2004, the Court of Federal Claims granted Wisconsin Electric’s motion for summary judgment on liability. The Court has subsequently scheduled the trial for March 2007. Wisconsin Electric has incurred substantial damages to date and damages continue to accrue. We are seeking recovery of our damages in this lawsuit and we expect that any recoveries would be considered in setting future rates.

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 support large regional transmission organizations (RTOs), which will affect the structure of the wholesale market. To this end, the MISO implemented a bid-based market, the MISO Midwest Market, including the use of locational marginal pricing (LMP) to value electric transmission congestion. The MISO Midwest Market commenced operation on April 1, 2005. The timeline for restructuring and retail access continues to be stretched out, and it is uncertain when

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retail access will happen in Wisconsin; however, Michigan has adopted retail choice which potentially affects our Michigan operations. In August 2005, President Bush signed into law the Energy Policy Act, which impacts the electric utility industry. (See Other Matters below for additional information on the Energy Policy Act). In addition, major issues in industry restructuring, implementation of RTO markets and market power mitigation received substantial attention in 2005. 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:

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Addition of new generating capacity in the state;

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

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Development of a regional independent electric transmission system operator; and

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

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

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

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 has not had, and is not expected to have a material impact on Wisconsin Electric’s business. Wisconsin Electric had one wholesale customer in Illinois, the City of Geneva, whose contract expired on December 31, 2005.

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.

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

MISO: In connection with its status as a FERC approved RTO, MISO implemented a bid-based energy market, the MISO Midwest Market, which commenced operations on April 1, 2005. As part of this energy market, the MISO developed a market-based platform for valuing transmission congestion premised upon the LMP system that has been implemented in certain northeastern and mid-Atlantic states. The LMP system includes the ability to mitigate or eliminate congestion costs through the use of Financial Transmission Rights (FTRs). FTRs are allocated to market participants by MISO. The first allocation of FTRs was completed for the period of April 1, 2005 through August 31, 2005. The FTR allocation process was then performed again for the period from September 1, 2005 to May 31, 2006. To date, our unhedged congestion charges have not been material.

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MISO deferred the costs to develop and start-up its energy market (new software systems and personnel). Now that the market is operational, the development and start-up costs are charged to MISO 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 certain incremental costs or benefits that may occur due to the implementation of the MISO Midwest Market. Our request excluded LMP energy costs because these costs are subject to recovery under the Wisconsin Fuel Cost Adjustment Procedure. In March 2005, the PSCW accepted our request. We submitted another joint proposal with other utilities in March 2005, requesting escrow accounting treatment for MISO Midwest Market costs until each utility’s first rate case following April 1, 2008. The purpose of the March 2005 request for escrow accounting was to provide clarification on costs not included in the March 2005 approval for deferral accounting treatment. For further information on the accounting for MISO transactions see Critical Accounting Estimates below.

In MISO, base transmission costs are currently being paid by load serving entities (LSEs) located in the service territories of each MISO 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 MISO on or around February 1, 2008. In addition, FERC ordered a seams elimination charge to be paid by MISO 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 MISO and PJM Interconnection, L.L.C. 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. A decision from the hearing process is expected in the second half of 2006. In January 2006, Wisconsin Electric along with certain other parties to the proceeding, submitted an offer of settlement to the presiding administrative law judge that, if approved, will resolve all issues set for hearing that impact Wisconsin Electric with regard to the continued payment of through and out transmission charges as well as the seams elimination charge. To date, neither the administrative law judge nor the FERC has addressed the merits of the settlement. If the settlement offer is approved by the FERC as submitted, Wisconsin Electric would receive a small refund of transmission charges in excess of the seams elimination charge.

Natural Gas Utility Industry

Restructuring in Wisconsin: The PSCW previously 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.

OTHER MATTERS

In August 2005, President Bush signed into law the Energy Policy Act. Among other things, the Energy Policy Act includes tax subsidies for electric utilities and the repeal of the Public Utility Holding Company Act of 1935 (PUHCA 1935). The Energy Policy Act also amends federal energy laws and provides the FERC with new oversight responsibilities for the electric utility industry. Implementation of the Energy Policy Act requires the development of regulations by federal agencies, including the FERC. As noted above, the Energy Policy Act and corresponding rules require us to seek FERC authorization to allow Wisconsin Electric to lease from We Power the three Power the Future units that are currently being constructed by We Power. Additionally, the Energy Policy Act repealed PUHCA 1935 and enacted the Public Utility Holding Company Act of 2005 (PUHCA 2005), transferring jurisdiction over holding companies from the SEC to the FERC. Wisconsin Energy and Wisconsin Electric will be required to notify the FERC of their status as holding companies and to seek from FERC the exempt status similar to that held under PUHCA 1935. As federal agencies continue to develop new rules to implement the Energy Policy Act, we expect additional impacts on Wisconsin Energy and its subsidiaries in the future.

ACCOUNTING DEVELOPMENTS

New Pronouncements: In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS 123 (revised 2004), Share-Based Payment (SFAS 123R), which amended SFAS 123, Accounting for Stock-Based Compensation. In March 2005, the SEC issued Staff Accounting Bulletin 107 (SAB 107) regarding the SEC’s interpretation of SFAS 123R and the valuation of share-based payment for public companies. In April 2005, the SEC deferred the effective date of SFAS 123R to January 1, 2006. This

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statement requires that the compensation costs relating to such transactions be recognized in the consolidated income statement. We adopted SFAS 123R and SAB 107 effective January 1, 2006 using the modified prospective method. See Note A — Summary of Significant Accounting Policies and Note B — Recent Accounting Pronouncements in the Notes to Consolidated Financial Statements in this report for additional information.

In March 2005, the FASB issued Interpretation 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), an interpretation of FASB Statement 143. We adopted FIN 47 effective December 31, 2005. For further information see Note F — Asset Retirement Obligations.

We adopted FASB Staff Position FIN 46R - 5, Implicit Variable Interests under FASB Interpretation 46 (revised December 2003), in the second quarter of 2005. This statement requires that holdings of implicit variable interests are evaluated when applying Interpretation 46R. See Note G — Variable Interest Entities for further information.

In May 2005, the FASB issued SFAS 154, Accounting Changes and Error Corrections, a replacement of Accounting Principles Board (APB) Opinion 20 and SFAS 3. This statement requires a retrospective application of direct changes in accounting principles to prior periods’ financial statements, unless it is impracticable to determine the period-specific or cumulative effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. In addition, SFAS 154 instructs that a change in depreciation, amortization or depletion method for long-lived, non-financial assets must be recorded as a change in accounting estimate affected by a change in accounting principle. We adopted SFAS 154, effective January 1, 2006. The adoption of SFAS 154 has not had an impact on our consolidated financial position or results of operations, as we have not had a change in accounting principle that we were required to implement to date in 2006.

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 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, 2005, we had $1,025.6 million in regulatory assets and $1,373.2 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 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.

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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	$	7.1
0.5% decrease in expected rate of return on plan assets	$	4.9

(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 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	$	2.1
0.5% decrease in health care cost trend rate		($1.4	)
0.5% decrease in expected rate of return on plan assets	$	0.9

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

Unbilled Revenues: We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated. This unbilled revenue is estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses and applicable customer rates. Significant fluctuations in energy demand for the unbilled period or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. Total utility operating revenues during 2005 of $3,793.0 million included accrued utility revenues of $262.9 million at December 31, 2005.

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 SFAS 143, Accounting for Asset Retirement Obligations (SFAS 143) and Accounting for Conditional Asset Retirement Obligations (FIN 47), an Interpretation of 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 $309.8 million at December 31, 2005. As it relates to our operations, FIN 47 applies primarily to asbestos removal costs. At December 31, 2005, we recorded an obligation of $37.4 million related to asbestos.

Calculation of the nuclear decommissioning 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 and the discount rate applied to future cash flows. Assuming the following changes in key assumptions and

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holding all other assumptions constant, we estimate that our nuclear asset retirement obligation at December 31, 2005 would have changed by the following amounts:


Change in Assumption	Change in Liability
	(Millions of Dollars)
1% increase in inflation rate	$101.1
1% decrease in inflation rate	($76.2	)

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 $3.1 million.

For additional information concerning SFAS 143 and our estimated nuclear asset retirement obligation, see Note F — Asset Retirement Obligations and Note I — Nuclear Operations in the Notes to Consolidated Financial Statements.

Deferred Tax Assets Valuation Allowance: We record deferred tax asset valuation allowances in accordance with SFAS 109, Accounting for Income Taxes. As of December 31, 2005, we had approximately $11.8 million of valuation allowances that relate to state net operating loss carryforwards (state NOLs) of various non-utility subsidiaries. These NOL’s begin to expire in 2008 and it is not likely that we will be able to utilize them.

During 2005, we reduced our valuation allowances by $16.3 million as we were able to conclude that it was likely that we would be able to realize certain state NOL’s recorded at the Parent company. This conclusion was based on the favorable decision by the Supreme Court of Wisconsin in June 2005 that allowed the construction of the Oak Creek expansion as part of our Power the Future plan.

The Power the Future generating units will be owned by our subsidiaries organized as limited liability companies (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 taxable losses if all plants are in service. During 2005, the first of the four generating units was put into service. The determination of future state taxable income of the Parent is a significant estimate. Factors affecting the estimate include the amounts spent and timing for construction of the Power the Future generating units, the amount of debt and interest expense at the Parent and the consideration of available tax planning strategies.

If we would conclude in a future period that it was more likely than not that some or all of the remaining state NOLs would be realized before expiration, GAAP 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.

MISO Bid-Based Energy Market: Effective April 1, 2005, MISO implemented the MISO Midwest Market, a bid-based energy market. The market requires that all market participants submit day-ahead and/or real-time bids and offers for energy at locations across the MISO region. MISO then calculates the most efficient solution for all the bids and offers made into the market that day and establishes a LMP which reflects the market price for energy. As a participant in the new MISO Midwest Market, we are required to follow MISO’s instructions when dispatching generating units to support MISO’s responsibility for maintaining stability of the transmission system. To the extent the established LMP price for energy is not sufficient to recover the cost of running a generating unit dispatched at MISO’s request, the tariff provides a mechanism for us to recover the deficiency (the “make-whole payment”). Since the start of the MISO Midwest Market, MISO has significantly increased the amount of generation provided by our higher cost combustion turbines. We have recorded a receivable from MISO for the make-whole payments associated with this operation. A reserve has been established for a portion of these receivables that are currently in dispute. Additionally, the MISO Midwest Market subjects us to additional costs primarily associated with constraints in the transmission system. We expect to recover these deferred costs in future rates, subject to PSCW audit and approval.

MISO settles each Operating Day a minimum of four times. A settlement statement is issued at 7, 14, 55 and 105 days after each Operating Day. In addition, since the market start, MISO has employed a non-standard settlement statement at 155 days after the Operating Day. MISO has also announced plans to issue a non-standard statement at 365 days after the Operating Day for days April 1, 2005 through August 31, 2005. Each subsequent statement may contain billing adjustments which alter our obligation to MISO.

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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 “anticipates,” “believes,” “estimates,” “expects,” “forecasts,” “intends,” “may,” “objectives,” “plans,” “possible,” “potential,” “projects” 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 events causing scheduled generation outages to last longer than expected; unanticipated changes in fossil fuel, nuclear fuel, purchased power, coal supply, 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 or distribution 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.

•

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 started in April 2005, the associated outcome of our March 2005 request of the Public Service Commission of Wisconsin to escrow potential future rate recovery for the incremental costs or benefits resulting from this new energy market and the ultimate determination by the Federal Energy Regulatory Commission on the details of the seams elimination charges.

•

Consolidation of the industry as a result of the combination and acquisition of utilities in the Midwest, nationally and globally as a result of the repeal of the Public Utility Holding Company Act of 1935 or otherwise.

•

Factors which impede execution of our Power the Future strategy, 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, including the adverse interpretation or enforcement of permit conditions by the permitting agencies, and obtaining the investment capital from outside sources necessary to implement the strategy.

•

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.

•

Changes in social attitudes regarding the utility and power industries.

•

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

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•

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

•

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

•

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

•

Implementation of the Energy Policy Act and the effect of state level proceedings and the development of regulations by federal and other agencies, including the Federal Energy Regulatory Commission, as well as the ultimate authorization of the Federal Energy Regulatory Commission to allow Wisconsin Electric to lease the three Power the Future units that are currently being constructed by We Power.

•

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

•

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

•

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; and risks associated with minority investments, where there is a limited ability to control the development, management or operation of the project.

•

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.

•

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

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

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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.

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WISCONSIN ENERGY CORPORATION

CONSOLIDATED INCOME STATEMENTS

Year Ended December 31


	2005		2004		2003
	(Millions of Dollars, Except Per Share Amounts)
Operating Revenues	$	3,815.5	$	3,406.1	$	3,282.1
Operating Expenses
Fuel and purchased power		776.7		591.7		569.5
Cost of gas sold		1,047.3		890.9		863.3
Other operation and maintenance		1,007.9		985.3		916.9
Depreciation, decommissioning and amortization		332.0		319.5		320.5
Property and revenue taxes		88.7		87.3		82.2
Asset valuation charges, net		—		1.4		45.6

Total Operating Expenses		3,252.6		2,876.1		2,798.0

Operating Income		562.9		530.0		484.1
Other Income and Deductions, Net		63.3		15.8		41.7
Interest Expense		173.4		193.4		213.8

Income from Continuing Operations Before Income Taxes		452.8		352.4		312.0
Income Taxes		149.2		132.8		110.7

Income from Continuing Operations		303.6		219.6		201.3
Income from Discontinued Operations, Net of Tax		5.1		86.8		43.0

Net Income	$	308.7	$	306.4	$	244.3

Earnings Per Share (Basic)
Continuing Operations	$	2.59	$	1.87	$	1.72
Discontinued Operations	$	0.05	$	0.73	$	0.37

Total Earnings Per Share (Basic)	$	2.64	$	2.60	$	2.09

Earnings Per Share (Diluted)
Continuing Operations	$	2.56	$	1.84	$	1.70
Discontinued Operations	$	0.05	$	0.73	$	0.36

Total Earnings Per Share (Diluted)	$	2.61	$	2.57	$	2.06

Weighted Average Common Shares Outstanding (Millions)
Basic		117.0		117.7		117.1
Diluted		118.4		119.1		118.4

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

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WISCONSIN ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

December 31

ASSETS


	2005			2004
	(Millions of Dollars)
Property, Plant and Equipment
In service	$	8,849.6		$	8,170.7
Accumulated depreciation		(3,288.5	)		(3,090.4	)

		5,561.1			5,080.3
Construction work in progress		596.6			602.2
Leased facilities, net		93.2			98.9
Nuclear fuel, net		112.0			85.0

Net Property, Plant and Equipment		6,362.9			5,866.4
Investments
Nuclear decommissioning trust fund		782.1			737.8
Equity investment in transmission affiliate		205.8			187.8
Other		92.1			99.5

Total Investments		1,080.0			1,025.1
Current Assets
Cash and cash equivalents		73.2			35.6
Accounts receivable, net of allowance for doubtful accounts of $36.6 and $ 40.1		441.8			345.7
Accrued revenues		262.9			245.1
Materials, supplies and inventories		451.6			403.1
Prepayments and other		130.1			136.8
Assets held for sale		17.4			54.2

Total Current Assets		1,377.0			1,220.5
Deferred Charges and Other Assets
Regulatory assets		1,025.6			849.4
Goodwill, net		441.9			441.9
Other		174.6			162.1

Total Deferred Charges and Other Assets		1,642.1			1,453.4

Total Assets	$	10,462.0		$	9,565.4

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

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WISCONSIN ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

December 31

CAPITALIZATION AND LIABILITIES


	2005		2004
	(Millions of Dollars)
Capitalization
Common equity	$	2,680.1	$	2,492.4
Preferred stock of subsidiary		30.4		30.4
Long-term debt		3,031.0		3,239.5

Total Capitalization		5,741.5		5,762.3
Current Liabilities
Long-term debt due currently		496.0		101.0
Short-term debt		456.3		338.0
Accounts payable		418.1		306.1
Payroll and vacation accrued		75.2		74.3
Accrued taxes		31.0		12.0
Accrued interest		28.2		28.1
Other		137.9		128.4
Liabilities held for sale		4.1		4.5

Total Current Liabilities		1,646.8		992.4
Deferred Credits and Other Liabilities
Regulatory liabilities		1,373.2		922.4
Asset retirement obligations		355.5		762.2
Deferred income taxes - long-term		593.7		530.4
Accumulated deferred investment tax credits		56.3		61.0
Minimum pension liability		274.4		152.8
Other long-term liabilities		420.6		381.9

Total Deferred Credits and Other Liabilities		3,073.7		2,810.7
Commitments and Contingencies (Note S)		—		—

Total Capitalization and Liabilities	$	10,462.0	$	9,565.4

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

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WISCONSIN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31


	2005			2004			2003
	(Millions of Dollars)
Operating Activities
Net income	$	308.7		$	306.4		$	244.3
Income from discontinued operations, net of tax		(5.1	)		(86.8	)		(43.0	)
Reconciliation to cash
Depreciation, decommissioning and amortization		350.0			352.6			351.0
Nuclear fuel expense amortization		23.0			24.0			25.3
Equity in earnings of unconsolidated affiliates		(34.0	)		(30.9	)		(22.2	)
Distribution from unconsolidated affiliates		27.4			44.7			32.9
Asset valuation charges, net		—			1.4			45.6
Deferred income taxes and investment tax credits, net		63.4			6.5			64.5
Change in - Accounts receivable and accrued revenues		(124.6	)		(48.9	)		7.2
Inventories		(48.5	)		(20.4	)		(72.5	)
Other current assets		6.5			(20.0	)		(23.8	)
Accounts payable		93.4			37.6			(27.6	)
Accrued income taxes, net		6.1			(8.5	)		(30.1	)
Deferred costs, net		(143.6	)		(48.8	)		(61.9	)
Other current liabilities		29.2			26.8			13.5
Other		25.0			63.3			25.7

Cash Provided by Operating Activities		576.9			599.0			528.9
Investing Activities
Capital expenditures		(745.1	)		(636.5	)		(648.0	)
Acquisitions and investments		(10.5	)		(26.4	)		(7.6	)
Proceeds from asset sales		133.8			899.6			55.3
Nuclear fuel		(49.7	)		(30.0	)		(38.3	)
Nuclear decommissioning funding		(17.6	)		(17.6	)		(17.6	)
Proceeds from investments within nuclear decommissioning trust		435.7			327.2			474.6
Purchases of investments within nuclear decommissioning trust		(435.7	)		(327.2	)		(474.6	)
Cash from/(to) Discontinued Operations		—			32.4			61.2
Other		(8.0	)		21.3			(0.2	)

Cash (Used in) Provided by Investing Activities		(697.1	)		242.8			(595.2	)
Financing Activities
Issuance of common stock and exercise of stock options		47.0			70.9			62.9
Repurchase of common stock		(75.1	)		(152.7	)		(6.8	)
Dividends paid on common stock		(102.9	)		(97.8	)		(93.7	)
Issuance of long-term debt		285.8			397.0			984.7
Retirement and redemption of long-term debt		(112.2	)		(798.4	)		(526.2	)
Change in short-term debt		118.3			(252.8	)		(337.8	)
Other		(3.1	)		(0.5	)		(23.7	)

Cash Provided by (Used in) Financing Activities		157.8			(834.3	)		59.4

Change in Cash and Cash Equivalents from Continuing Operations		37.6			7.5			(6.9	)
Cash and Cash Equivalents at Beginning of Year		35.6			28.1			35.0

Cash and Cash Equivalents at End of Year	$	73.2		$	35.6		$	28.1

Supplemental Information - Cash Paid For
Interest (net of amount capitalized)	$	195.4		$	224.4		$	225.2
Income taxes (net of refunds)	$	47.5		$	91.5		$	92.2

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

B-46

WISCONSIN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMMON EQUITY


	Common Stock		Other Paid In Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)		Unearned Compensation		Stock Options Exercisable			Total
	(Millions of Dollars)
Balance - December 31, 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 share awards				5.9							(5.9	)					—
Amortization and forfeiture of performance shares and 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
Net Income							308.7										308.7
Other comprehensive income
Minimum pension liability									(4.1	)							(4.1	)

Comprehensive income		—		—			308.7		(4.1	)	—			—			304.6
Common stock cash dividends $0.88 per share							(102.9	)									(102.9	)
Common stock issued				47.0													47.0
Repurchase of common stock				(75.2	)												(75.2	)
Restricted stock awards											(0.6	)					(0.6	)
Performance share awards				0.9							(0.9	)					—
Amortization and forfeiture of performance shares and restricted stock				—							3.7						3.7
Stock options exercised				1.4										(1.4	)		—
Tax benefit of stock options exercised				11.1													11.1

Balance - December 31, 2005	$	1.2	$	770.3		$	1,924.5		($11.5)		($5.4)		$	1.0		$	2,680.1

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

B-47

WISCONSIN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CAPITALIZATION

December 31


	2005			2004
	(Millions of Dollars)
Common Equity (See Consolidated Statements of Common Equity)
Common stock - $.01 par value; authorized 325,000,000 shares; outstanding - 116,980,775 and 116,985,822 shares	$	1.2		$	1.2
Other paid in capital		770.3			785.1
Retained earnings		1,924.5			1,718.7
Accumulated other comprehensive income (loss)		(11.5	)		(7.4	)
Unearned compensation - restricted stock and performance share awards		(5.4	)		(7.6	)
Stock options exercisable		1.0			2.4

Total Common Equity		2,680.1			2,492.4
Preferred Stock
Wisconsin Energy
$.01 par value; authorized 15,000,000 shares; none outstanding		—			—
Wisconsin Electric
Six Per Cent. Preferred Stock - $100 par value; authorized 45,000 shares; outstanding - 44,498 shares		4.4			4.4
Serial preferred stock -
$100 par value; authorized 2,286,500 shares; 3.60% Series redeemable at $101 per share; outstanding - 260,000 shares		26.0			26.0
$25 par value; authorized 5,000,000 shares; none outstanding		—			—

Total Preferred Stock		30.4			30.4
Long-Term Debt
Debentures (unsecured)
6-5/8% due 2006		200.0			200.0
9.47% due 2006		0.7			1.4
3.50% due 2007		250.0			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
5.90% due 2035		90.0			—
6-7/8% due 2095		100.0			100.0
Notes (secured, nonrecourse)
3.79% variable rate due 2005 (a)		—			6.5
6.36% effective rate due 2006		1.1			2.2
6.90% due 2006		—			1.1
7.25% variable rate due 2006 (b)		9.3			—
2% stated rate due 2011		1.2			1.3
4.55% variable rate due 2028 (b)		15.1			15.6
4.81% effective rate due 2030		2.0			2.0
4.91% due 2006-2030		153.7			—

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

B-48

WISCONSIN ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CAPITALIZATION - (Cont’d)

December 31


	2005			2004
	(Millions of Dollars)
Long-Term Debt - (Cont’d)
Notes (unsecured)
6-3/8% due 2005		—			65.0
6.85% due 2005		—			10.0
3.55% variable rate due 2006 (b)		1.0			1.0
5.875% due 2006		250.0			250.0
6.36% effective rate due 2006		1.2			2.4
7.40% to 8.00% due 2006-2008		0.8			2.1
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
3.55% variable rate due 2015 (b)		17.4			17.4
3.50% variable rate due 2016 (b)		67.0			67.0
6.94% due 2028		50.0			50.0
3.50% variable rate due 2030 (b)		80.0			80.0
6.20% due 2033		200.0			200.0
Obligations under capital leases		230.8			212.9
Unamortized discount, net and other		(24.7	)		(27.8	)
Long-term debt due currently		(496.0	)		(101.0	)

Total Long-Term Debt		3,031.0			3,239.5

Total Capitalization	$	5,741.5		$	5,762.3

(a)	Variable interest rate as of December 31, 2004.

(b)	Variable interest rate as of December 31, 2005.

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

B-49

WISCONSIN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

•

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

•

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.

Our other non-utility segment primarily includes 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 total assets, 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) 144, Accounting for the Impairment or Disposal of Long-Lived Assets. The footnotes contained herein reflect continuing operations for all periods presented. For further information see Note D.

We have changed the presentation of the investments within our nuclear decommissioning trusts on the Consolidated Statement of Cash Flows for the three years ended December 31, 2005, to present proceeds from investments within the nuclear decommissioning trusts and purchases of investments within the nuclear decommissioning trusts. Previously these items were excluded from the Consolidated Statement of Cash Flows as the nuclear decommissioning trusts are restricted investments. This change had no impact to net cash provided by (used in) operating, investing or financing activities.

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

Wisconsin Electric’s Wisconsin retail rates are established by the Public Service Commission of Wisconsin (PSCW) and include base amounts for fuel and purchase power costs. The Wisconsin electric fuel rules allow Wisconsin Electric to request rate increases if fuel and purchased power costs exceed bands established by the PSCW. In a rate order issued in January 2006, the PSCW approved a plan to refund any over-collected fuel on an annual basis for 2006. In 2006, any under-collection will be subject to a 2% band. For 2007, the band will be plus or minus 2%.

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.

Property and Depreciation: We record property, plant and equipment at cost. Cost includes material, labor, overheads and capitalized interest. Utility property also includes allowance for equity 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.

B-50

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


Property In Service	2005		2004
	(Millions of Dollars)
Utility Energy	$	8,311.0	$	7,986.3
Non-Utility Energy		389.0		23.1
Other		149.6		161.3

Total	$	8,849.6	$	8,170.7

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, 2005 and 2004, the net book value of regulated capitalized software totaled $22.3 million and $28.8 million, respectively. The net book value of other capitalized software was approximately $2.4 million and $2.6 million as of December 31, 2005 and 2004, 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 3.9% in 2005, 4.0% in 2004, and 4.1% in 2003. Nuclear plant decommissioning costs are accrued and included in depreciation expense (see Note I). In November 2005, the PSCW approved new depreciation rates, which became effective January 1, 2006. We estimate that the 2006 composite rate will be approximately 3.7% with the new depreciation rates.

For assets other than our regulated assets, we accrue depreciation expense at straight-line rates over the estimated useful lives of the assets. Estimated useful lives for non-regulated assets are 3 to 40 years for furniture and equipment, 2 to 5 years for software and 30 to 40 years for buildings.

Our regulated utilities collect in their rates future removal costs for many assets that do not have an associated 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 $604.2 million as of December 31, 2005 and $599.3 million as of December 31, 2004.

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


	2005		2004
	(Millions of Dollars)
Utility Energy	$	237.7	$	160.8
Non-Utility Energy		354.5		432.5
Other		4.4		8.9

Total	$	596.6	$	602.2

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

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

B-51

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


	2005		2004		2003
	(Millions of Dollars)
AFUDC - Debt	$	4.6	$	1.5	$	2.9
AFUDC - Equity	$	9.2	$	2.8	$	5.1

Capitalized Interest and Carrying Costs - Non-Regulated Energy: As part of the construction of the power plants under our Power the Future program, we capitalize interest during construction in accordance with SFAS 34, Capitalization of Interest Cost. For the years ended December 31, 2005, 2004, and 2003 we capitalized $24.3 million, $17.9 million and $6.5 million of interest costs, at an average rate of 6.5%, 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 these 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, 2005, 2004 and 2003, we have deferred $54.7 million, $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	2005		2004
	(Millions of Dollars)
Fossil Fuel	$	90.4	$	86.3
Natural Gas in Storage		265.5		225.7
Materials and Supplies		95.7		91.1

Total	$	451.6	$	403.1

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 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. 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). We expect to recover our outstanding regulatory assets in rates over a period of no longer than 20 years. For further information, see Note C.

Derivative Financial Instruments: We have derivative physical and financial instruments as defined by SFAS 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.

We have nuclear decommissioning trusts that hold investments in debt and equity securities. All assets within the nuclear decommissioning trusts are restricted to nuclear decommissioning activities as set forth by regulations promulgated by the Internal Revenue Service (IRS) and by the PSCW. The accompanying Consolidated Statement of Cash Flows includes proceeds from investments within the nuclear decommissioning trusts and purchases of investments within the nuclear decommissioning trusts.

B-52

Asset Retirement Obligations: We adopted SFAS 143, Accounting for Asset Retirement Obligations, effective January 1, 2003. In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), an interpretation of FASB Statement 143. FIN 47 defines the term conditional asset retirement obligation as used in Statement 143. As defined in FIN 47, a conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. We adopted FIN 47 effective December 31, 2005. 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 F.

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, 2005 and 2004, we had $441.9 million of goodwill recorded at the Utility Energy Segment, which related to our acquisition of Wisconsin Gas in 2000.

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 2005 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, 2005, we have classified the assets and liabilities of Minergy Neenah as Held for Sale. 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. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset. For further information, see Note D.

Investments: We account for investments in other affiliated companies in which we do not maintain control using the equity method. As of December 31, 2005 and 2004, we had a total ownership interest of approximately 33.5% and 37.8%, in American Transmission Company LLC (ATC). We are represented by one out of ten ATC board members, each of whom has one vote. Due to the voting requirements, no individual member has more than 10% of the voting control. For further information regarding such investments, see Note R.

Income Taxes: We follow the liability method in accounting for income taxes as prescribed by SFAS 109, Accounting for Income Taxes (SFAS 109). SFAS 109 requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. We have established a valuation allowance against certain deferred tax assets. Generally accepted accounting principles require that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, 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 in income tax expense.

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 H.

Stock Options: Prior to 2006, we accounted for stock-based compensation using the intrinsic value method provided by Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees, and related interpretations under which no compensation cost has been recognized for stock option grants. Effective January 1, 2006, we adopted SFAS 123R, Share-Based Payment (Revised). See Note B for further discussion of this new standard and the impacts to our consolidated financial statements.

B-53

We previously adopted the disclosure provisions of SFAS 123, Accounting for Stock-Based Compensation, as amended by SFAS 148, Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of SFAS 123. The fair value of options at date of grant was estimated using the Black-Scholes option-pricing model with the following weighted average assumptions:


	2005			2004			2003
Risk free interest rate		4.4	%		4.6	%		4.5	%
Dividend yield		2.5	%		2.5	%		3.1	%
Expected volatility		19.00	%		23.10	%		25.73	%
Expected life (years)		10			10			10
Pro forma weighted average fair value of our stock options granted	$	8.32		$	9.45		$	7.04

As described more fully in the following table, our diluted earnings would have been reduced by $0.02, $0.24 and $0.06 per share, respectively, had we expensed the 2005, 2004 and 2003 grants for stock-based compensation plans under SFAS 123. In 2004, the pro forma expense increased, in part, due to the effect of accelerating the vesting of stock options, which resulted in a pro forma expense of $0.16 per share. For further information regarding equity based compensation see Note B and Note J.


	2005		2004		2003
	(Millions of Dollars, Except Per Share Amounts)
Net Income - as reported	$	308.7	$	306.4	$	244.3
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects		2.3		2.5		0.7
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		4.5		31.5		8.5

Net Income - Pro forma	$	306.5	$	277.4	$	236.5

Basic Earnings Per Common Share
As reported	$	2.64	$	2.60	$	2.09
Pro forma	$	2.62	$	2.36	$	2.02
Diluted Earnings Per Common Share
As reported	$	2.61	$	2.57	$	2.06
Pro forma	$	2.59	$	2.33	$	2.00

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

Conditional Asset Retirement Obligations: In March 2005, the FASB issued Interpretation 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), an interpretation of FASB Statement 143. We adopted FIN 47 effective December 31, 2005. For further information see Note F.

Implicit Variable Interests: We adopted FASB Staff Position FIN 46R - 5, Implicit Variable Interests under FASB Interpretation 46 (revised December 2003), in the second quarter of 2005. This statement requires that holdings of implicit variable interests are evaluated when applying Interpretation 46R. See Note G for further information.

Share Based Compensation: In December 2004, the FASB issued SFAS 123 (revised 2004), Share-Based Payment (SFAS 123R), which is a revision of SFAS 123. SFAS 123R supersedes APB Opinion 25, and amends SFAS 95, Statement of Cash Flows. Generally, the approach in SFAS 123R is similar to the approach described in SFAS 123. However, SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative under the new standard.

B-54

We adopted SFAS 123R effective January 1, 2006 using the modified prospective method. We will use the binomial pricing model to estimate the fair value of stock options granted subsequent to December 31, 2005. We estimate that our 2006 earnings will reflect stock option expense of $0.04 per share. Prior to 2006 and the adoption of SFAS 123R, we presented all tax benefits resulting from the exercise of stock options as operating cash flows in the Consolidated Statement of Cash Flows. SFAS 123R requires that cash flows resulting from tax deductions in excess of the cumulative compensation cost recognized for options exercised be classified as financing cash flows.

C — REGULATORY ASSETS AND LIABILITIES

Our utility energy segment accounts for its regulated operations in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation.

Our primary regulator considers our regulatory assets and liabilities in two categories, escrowed and deferred. In escrow accounting we expense amounts that are included in rates. If actual costs exceed, or are less than the amounts that are allowed in rates, the difference in cost is escrowed on the balance sheet as a regulatory asset or regulatory liability and the escrowed balance is considered in setting future rates. Under deferred cost accounting, we defer amounts to our balance sheet based upon specific orders or correspondence with our primary regulator. These deferred costs will be considered in future rate setting proceedings. As of December 31, 2005, we had approximately $59.0 million of net regulatory assets that were not earning a return.

Our regulatory assets and liabilities as of December 31 consist of:


	2005		2004
	(Millions of Dollars)
Regulatory Assets
Deferred unrecognized pension costs (See Note O)	$	377.2	$	342.8
Escrowed electric transmission costs		169.4		109.6
Deferred income tax related		96.6		99.9
Deferred fuel related costs		72.8		—
Deferred plant related — capital lease (See Note K)		67.0		61.1
Deferred environmental costs		64.2		58.0
Escrowed bad debt costs		58.1		41.7
Escrowed unrecovered plant costs		56.5		45.9
Other, net		63.8		90.4

Total long-term regulatory assets	$	1,025.6	$	849.4

Regulatory Liabilities
Deferred cost of removal obligations (See Notes F and I)	$	604.2	$	599.3
Deferred asset retirement obligations (See Notes F and I)		475.3	$	20.1
Deferred pension and post-retirement benefits		105.6		116.9
Deferred income tax related		103.8		109.4
Other, net		84.3		76.7

Total long-term regulatory liabilities	$	1,373.2	$	922.4

Net long-term regulatory liabilities	$	347.6	$	73.0

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).

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.

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, 2005, we have recorded $64.2 million of environmental costs associated with manufactured gas plant sites as a regulatory asset, including $36.8 million of deferrals for actual remediation

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costs incurred and a $27.4 million accrual for estimated future site remediation (See Note S). In addition, we have deferred $6.8 million of insurance recoveries associated with the environmental costs as regulatory liabilities. We included total actual remediation costs incurred net of the related insurance recoveries in our 2006 rate case. We began amortizing these costs upon receiving PSCW approval. These costs will be amortized over the next 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 PSCW authorized transferring the undepreciated costs and related removal amounts to a regulatory asset account. The escrowed unrecovered plant costs totaled $56.5 million at December 31, 2005.

As of December 31, 2005, we have deferred $72.8 million of fuel related costs. The costs resulted from an extended outage at our nuclear plant, increased costs associated with reduced coal deliveries due to a railroad transportation problem and increased costs associated with the Midwest Independent Transmission System Operator, Inc. (MISO) bid-based energy market (MISO Midwest Market).

As of December 31, 2005, we have $58.1 million of escrowed 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-offs that exceeded amounts that were allowed in its rates. In 2005 and 2004, the PSCW approved our request to account for residential bad debt costs on an escrow basis at Wisconsin Gas and Wisconsin Electric.

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 and post-retirement benefits) that is being amortized over an average remaining service life of 15 years ending 2015.

D — 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 and non-utility energy investments.

Minergy Neenah: In August 2005, we announced our intent to sell Minergy Neenah. The primary assets of Minergy Neenah are the Glass Aggregate plant and related operating contracts. The plant recycles paper sludge from area paper mills into renewable energy and glass aggregate using our patented Glass Aggregate technology.

As a result of the announced intent to sell Minergy Neenah, we have reclassified the assets and liabilities of Minergy Neenah as Assets held for sale in the accompanying Consolidated Balance Sheets. In addition, we have recorded the operating results of Minergy Neenah as Discontinued Operations in the accompanying Consolidated Income Statements. Previously, Minergy Neenah’s results were included in corporate and other affiliates. Total assets held for sale for Minergy Neenah were $17.4 million and $24.4 million at December 31, 2005 and 2004, respectively. See below for a summary of the components of Discontinued Operations for the operations of Minergy Neenah in our Consolidated Income Statements.

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.

Wisvest - Calumet: Effective May 31, 2005, we sold our Calumet facility for approximately $37.0 million in cash to Tenaska Power Fund, L.P. (Tenaska). The primary assets of Calumet were a 308-megawatt natural gas-fired peaking power facility in Chicago, Illinois and related operating contracts. The transaction generated an after tax gain of approximately $4.7 million upon closing and generated approximately $32.0 million in cash tax benefits.

Pursuant to the terms of the sales agreement, Wisvest has agreed to customary indemnification provisions related to environmental conditions and other matters. Except for retention of the full exposure to indemnify Tenaska for environmental claims related to certain property no longer leased or owned by Wisvest or any of its subsidiaries, Wisvest’s maximum aggregate exposure under the

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indemnification provisions is $35 million. Pursuant to the terms of the agreement, we have guaranteed post-closing obligations under the agreement, including indemnity obligations.

In accordance with SFAS 144, we have reclassified the assets and liabilities of Calumet as Assets held for sale in the accompanying December 31, 2004 Consolidated Balance Sheet. In addition, we have recorded the operating results of Calumet as Discontinued Operations in the accompanying Consolidated Income Statements for December 31, 2005, 2004 and 2003. Total assets held for sale for Calumet were $29.8 million at December 31, 2004. See below for a summary of the components of Discontinued Operations for the operations of Calumet in our Consolidated Income Statements. Previously, Calumet’s results were included in the non-utility energy segment.

Subsequent to May 1, 2004, Calumet 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 had significant risk associated with liquidated damages for certain energy sales within the PJM market, (ii) the elimination of the risk was 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 diminished the ability to viably sell merchant capacity, which 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.

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.

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 the final determination of cash taxes to be approximately $105 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. 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. We have established reserves related to these customary indemnification and tax matters.

In accordance with SFAS 144, we 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.

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A summary of the components of Discontinued Operations for the operations of WICOR, Calumet and Minergy Neenah in our Consolidated Income Statements follows:


	Year End December 31
	2005 (a)			2004 (b)			2003
	(Millions of Dollars)
Operating Revenues
WICOR	$	—		$	481.0		$	746.1
Calumet		2.3			5.2			4.2
Minergy Neenah		18.1			19.8			21.9

Total	$	20.4		$	506.0		$	772.2

Income (Loss) Before Income Taxes
WICOR	$	—		$	50.9		$	68.8
Calumet		0.4			(125.0	)		(5.8	)
Minergy Neenah		(6.4	)		(24.9	)		4.4

Total	($	6.0	)	($	99.0	)	$	67.4

Pretax Gain on Sale
WICOR	$	—		$	154.4		$	—
Calumet		7.2			—			—

Total	$	7.2		$	154.4		$	—

(a)	Includes the results of Calumet through May 31, 2005.

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

A summary of the components of cash flows from the discontinued operations of WICOR, Calumet and Minergy Neenah follows. The majority of the cash flow activity in 2004 and 2003 related to WICOR.


	Year Ended December 31
	2005(a)			2004(b)			2003
	(Millions of Dollars)
Net cash flows received from operating activities	$	2.1		$	36.6		$	94.9
Net cash flows used in investing activities		(2.1	)		(41.0	)		(71.9	)
Net cash flows used in financing activities		—			(2.0	)		(6.1	)

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

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

(a)	Includes the results of Calumet through May 31, 2005.

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

Assets held for sale in the Consolidated Balance Sheets does not include any cash or temporary cash investments related to discontinued operations as of December 31, 2005 and 2004.

2003 Non-Utility Sales: 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 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 an independent power project (Androscoggin LLC) and $40.1 million related to our investment in a 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

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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.

E — PORT WASHINGTON GENERATING STATION (PWGS)

In July 2005, the first unit at PWGS, a 545-megawatt natural gas-fired generation unit, was placed in service. This asset has a cost of approximately $364.3 million which includes approximately $31.1 million of capitalized interest. The asset will be depreciated over its estimated useful life of 37 years. The cost of the plant is expected to be recovered through Wisconsin Electric’s rates over a 25 year period at an annual amount of approximately $48 million.

During the construction of the first unit, we collected in rates approximately $72.5 million of carrying costs and recorded this amount as deferred revenues. In July 2005, we began to amortize these deferred revenues to income on a straight-line basis over 25 years.

In July 2005, PWGS issued $155 million of 4.91% senior notes in a private placement. The senior notes have a mortgage style repayment feature with monthly payments of approximately $0.9 million including principal and interest. The final payment is due July 15, 2030. The senior notes are secured by a collateral assignment of the leases between PWGS and Wisconsin Electric relating to the first unit.

F — ASSET RETIREMENT OBLIGATIONS

We follow SFAS 143, Accounting for Asset Retirement Obligations (SFAS 143) and Accounting for Conditional Asset Retirement Obligations (FIN 47).

The following table presents the change in our asset retirement obligations during 2005.


	Balance at 12/31/04		Initial Adoption (a)		Liabilities Incurred		Liabilities Settled		Accretion		Cash Flow Revisions		Balance at 12/31/05
	(Millions of Dollars)
Asset Retirement Obligations	$	762.2	$	38.4	$	0.6	($17.7	)	$	27.2	($455.2	)	$	355.5

(a)	Increase in asset retirement obligation for the initial adoption of FIN 47.

SFAS 143 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. In 2005, due to an updated Nuclear Decommissioning Cost Study and approval of our application for license renewal, we adjusted the long-term liability accrued for nuclear decommissioning costs. See Note I for further information about the nuclear decommissioning of Point Beach including our investments in Nuclear Decommissioning Trusts that are restricted to nuclear decommissioning.

In March 2005, the FASB issued FIN 47, an interpretation of FASB Statement 143. FIN 47 defines a conditional asset retirement obligation as a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. We adopted FIN 47 effective December 31, 2005. At adoption, we recorded additional asset retirement obligations of $38.4 million, of which $37.4 million related to asbestos removal costs.

The adoption of FIN 47 had no impact on our net income in 2005. 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 FIN 47. This treatment is consistent with the adoption of SFAS 143 for our regulated operations.

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If we had adopted interpretation FIN 47 at the beginning of fiscal 2004, we would have reported the following asset retirement obligations on our Consolidated Balance Sheets in “Asset Retirement Obligations” as of December 31:


Asset Retirement Obligations	2005		2004
	(Millions of Dollars)
Reported (b)	$	355.5	$	762.2
Pro forma	$	355.5	$	798.4

(b)	The 2004 reported balance represents the liability recorded under SFAS 143, which is primarily related to nuclear decommissioning costs.

G — 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 $667.5 million of required payments over the remaining term of these three agreements, which expire over the next 17 years. We believe the required payments will continue to be recoverable in rates. We account for one of these agreements as a capital lease.

In March 2005, the FASB issued FASB Staff Position FIN 46R-5, Implicit Variable Interests under FASB Interpretation 46 (revised December 2003). This statement requires that holdings of implicit variable interests are evaluated when applying Interpretation 46R. An implicit variable interest is defined as an implied pecuniary interest in an entity that changes with changes in the fair value of the entity’s net assets exclusive of variable interests. An implicit variable interest acts the same as an explicit variable interest except it involves the absorbing and/or receiving of variability indirectly from the entity (rather than directly). FIN 46R-5 was effective for the first reporting period beginning after March 3, 2005 for entities that had already adopted FIN 46R; accordingly, we adopted FIN 46R-5 in the second quarter of 2005. We have concluded that we currently do not have any implicit variable interests.

H — INCOME TAXES

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


Income Tax Expense	2005			2004			2003
	(Millions of Dollars)
Current tax expense	$	63.7		$	126.3		$	94.4
Deferred income taxes, net		90.2			11.3			21.2
Investment tax credit, net		(4.7	)		(4.8	)		(4.9	)

Total Income Tax Expense	$	149.2		$	132.8		$	110.7

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


	2005					2004					2003
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	$	158.5		35.0	%	$	123.4		35.0	%	$	109.2		35.0	%
State income taxes net of federal tax benefit		21.2		4.7	%		20.2		5.7	%		21.0		6.8	%
Reversal of valuation allowance		(16.3	)	(3.6	%)		—		—	%		—		—	%
Investment tax credit restored		(4.7	)	(1.0	%)		(4.8	)	(1.4	%)		(4.9	)	(1.6	%)
Other, net		(9.5	)	(2.1	%)		(6.0	)	(1.6	%)		(14.6	)	(4.7	%)

Total Income Tax Expense	$	149.2		33.0	%	$	132.8		37.7	%	$	110.7		35.5	%

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


	2005			2004
	(Millions of Dollars)
Deferred Tax Assets
Current
Employee benefits and compensation	$	13.8		$	13.7
Recoverable gas costs		3.3			8.1
Other		5.8			13.0

Total Current Deferred Tax Assets	$	22.9		$	34.8
Non-current
Employee benefits and compensation		117.3			59.4
Decommissioning trust		85.8			74.5
Construction advances		71.6			80.1
Property-related		45.5			7.2
Deferred revenues		28.4			—
State NOL’s		28.0			22.0
Valuation allowance		(11.8	)		(40.5	)
Emission allowances		18.4			—
Other		34.9			24.4

Total Non-current Deferred Tax Assets		418.1			227.1

Total Deferred Tax Assets	$	441.0		$	261.9

Deferred Tax Liabilities
Current
Prepaid items	$	33.2		$	26.9
Uncollectible account expense		8.8			3.0

Total Current Deferred Tax Liabilities	$	42.0		$	29.9
Non-current
Property-related		792.0			601.4
Employee benefits and compensation		68.8			47.1
Deferred transmission costs		64.6			40.5
Investment in transmission affiliate		40.4			40.6
Other		46.0			27.9

Total Non-current Deferred Tax Liabilities		1,011.8			757.5

Total Deferred Tax Liabilities	$	1,053.8		$	787.4


Consolidated Balance Sheet Presentation	2005			2004
Current Deferred Tax Asset (Liability)		($19.1	)		$4.9
Non-current Deferred Tax Asset (Liability)		($593.7	)		($530.4	)

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As of December 31, 2005 and 2004, we had recorded $11.8 million and $40.5 million of valuation allowances primarily related to the uncertainty of our ability to benefit from state loss carryforwards in the future. As of December 31, 2004, we had concluded that it was more likely than not that we would not ultimately realize these tax benefits. In connection with the favorable decision by the Supreme Court of Wisconsin in June 2005 to uphold the CPCN granted by the PSCW for the construction of the Oak Creek expansion, we have concluded that it is more likely than not that we will be able to utilize certain tax benefits associated with state net operating losses of the Parent that have been carried forward from prior years. As such, in 2005 we reversed $16.3 million of valuation allowances associated with the state tax net operating losses that have been carried forward to future years. The remaining state loss carryforwards begin to expire in 2008 and have been reduced by a valuation allowance.

I — NUCLEAR OPERATIONS

Point Beach Nuclear Plant: Wisconsin Electric owns two 518-megawatt electric generating units at Point Beach Nuclear Plant in Two Rivers, Wisconsin, which are operated by Nuclear Management Company (NMC). In February 2004, NMC and Wisconsin Electric filed an application with the United States Nuclear Regulatory Commission (NRC) to renew the operating license for both Units for an additional 20 years. The NRC approved the license renewal request in December 2005. The new operating licenses expire in October 2030 for Unit 1 and March 2033 for Unit 2. The previous operating licenses expired in October 2010 for Unit 1 and in March 2013 for Unit 2.

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 $10.8 billion, of which $300 million is covered by liability insurance purchased from private sources. The remaining $10.5 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 $100.6 million per reactor (Wisconsin Electric owns two) with a limit of $15 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 $17.9 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 $9.9 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 2005, 2004 and 2003. As of December 31, 2005 and 2004, we had the following investments in Nuclear Decommissioning Trusts, stated at fair value.


	2005		2004
	(Millions of Dollars)
Funding and Realized Earnings	$	566.6	$	529.1
Unrealized Gains		215.5		208.7

Total Investments	$	782.1	$	737.8

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As of December 31, 2005 approximately 66% of the trusts were invested in equity securities and 34% were invested in debt securities. In accordance with SFAS 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 fair value our investment in the Nuclear Decommissioning Trust Fund and we are allowed regulatory treatment for the fair value adjustment. Realized gains and losses for the years ended December 31, 2005 and 2004 were as follows:


	2005		2004
	(Millions of Dollars)
Realized Gains	$	19.1	$	25.5
Realized Losses		9.1		6.1

Net Realized Gain	$	10.0	$	19.4

The PSCW requires us to perform periodic Decommissioning Cost Studies to evaluate the funded status of our Nuclear Decommissioning Trusts as compared with the estimated costs to perform the decommissioning work. In June 2005, we filed a new Decommissioning Cost Study with the PSCW. The study was performed by an outside consultant and it included several assumptions as to the timing and scope of the decommissioning work. This study estimated that the cost to decommission the plant would be $712.5 million in 2004 dollars. A prior study had estimated the costs to be $1.1 billion in 2003 dollars. The reduction in the estimated costs to decommission the plant was driven by several factors including the timing and the scope of the work to be performed.

The June 2005 Decommissioning Cost Study was also used to estimate our Asset Retirement Obligation (ARO) for nuclear decommissioning. We record an ARO for future decommissioning costs based upon the net present value of the expected cash flows associated with our legal obligation to decommission our plants. Under SFAS 143, certain costs included in the June 2005 Decommissioning Cost Study that related to fuel management and non-nuclear demolition were excluded from the ARO calculation. Using the June 2005 study, our estimated costs for decommissioning, following SFAS 143, were $473.2 million. After increasing these costs for inflation and then discounting the costs for the time value of money, we calculated our ARO for nuclear decommissioning to be $309.8 million as of December 31, 2005 as compared to $745.3 million as of December 31, 2004.

We recover decommissioning costs in our regulated rates. We have established a regulatory liability to reflect the difference between nuclear decommissioning costs recovered in rates and cumulative investment gains (our nuclear trust investments) in comparison to the ARO for nuclear decommissioning that is calculated under SFAS 143. As of December 31, 2005, we have increased our nuclear decommissioning regulatory liability by $439.7 million in comparison to the liability at December 31, 2004, to reflect the reduction of the ARO for nuclear decommissioning as described above. For further information on ARO’s see Note F.

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 in the future, future inflation rates and discount rates. However, based on the license renewal received by the NRC in December 2005, we do not expect to make any significant nuclear decommissioning expenditures before the year 2030.

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, 2005,

Wisconsin Electric recorded its remaining estimated liability equal to projected special assessments of $3.7 million. The deferred regulatory asset will be amortized to nuclear fuel expense and included in utility rates over the next two years ending in 2007.

J — COMMON EQUITY

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. The OSIP provides for the granting of stock options, stock appreciation rights, stock awards and performance shares. 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.

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The following is a summary of our stock options issued through December 31, 2005.


	2005				2004				2003
Stock Options	Number of Options		Weighted- Average Exercise Price		Number of Options		Weighted- Average Exercise Price		Number of Options		Weighted- Average Exercise Price
Outstanding at January 1	8,290,311		$	25.88	9,823,935		$	22.87	8,307,190		$	21.21
Granted	1,328,966		$	34.20	1,844,765		$	33.44	2,913,289		$	26.05
Exercised	(2,044,145	)	$	23.05	(3,249,688	)	$	20.97	(1,357,197	)	$	19.55
Forfeited	(5,513	)	$	32.47	(128,701	)	$	28.21	(39,347	)	$	21.97

Outstanding at December 31	7,569,619		$	28.10	8,290,311		$	25.88	9,823,935		$	22.87

Exercisable at December 31	6,209,466		$	26.82	8,090,987		$	25.99	4,303,482		$	21.25

In January 2006, the Compensation Committee awarded 1,292,275 non-qualified stock options at the average market price of $39.48 to our officers and key employees under its normal schedule of awarding long-term incentive compensation.

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 became effective January 1, 2006. 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. In 2004, we recorded a $0.4 million charge, net of tax, in connection with the accelerated vesting of unvested stock options. For further information regarding the accounting changes related to stock based compensation see Note A and Note B.

The following table summarizes information about stock options outstanding at December 31, 2005:


	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number	Average Exercise Price		Life (years)	Number	Average Exercise Price
$10.86 to $19.97	397,126	$	18.34	3.8	397,126	$	18.34
$20.39 to $23.05	1,590,320	$	21.94	5.7	1,586,683	$	21.94
$25.31 to $27.65	1,942,601	$	25.74	7.3	1,911,495	$	25.74
$29.13 to $34.20	3,639,572	$	33.11	8.0	2,314,162	$	32.50

	7,569,619	$	28.10	7.1	6,209,466	$	26.82

The Compensation Committee has also approved restricted stock grants to certain key employees and directors. The following restricted stock activity occurred during 2005, 2004 and 2003:


	2005				2004				2003
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	221,363				294,920				219,052
Granted	18,137		$	34.33	16,570		$	33.36	104,500		$	27.72
Released / Forfeited	(45,843	)	$	27.77	(90,127	)	$	22.87	(28,632	)	$	22.84

Outstanding at December 31	193,657				221,363				294,920

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.

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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. In January 2006 and 2005 the Compensation Committee granted 150,281 and 101,834 performance units to officers and other key employees under the Wisconsin Energy Performance Unit Plan. Under the grants, the ultimate number of shares of our common stock or cash which will be awarded is dependent upon the achievement of certain financial performance of the Company’s stock over a three year period. 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. The 2004 grant will be settled in common stock. The 2005 and 2006 grants will be settled in cash instead of shares of our common stock.

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 repurchase plan expired on December 31, 2004. Over the life of the repurchase plan we purchased and retired approximately 14.9 million shares of common stock for $344.0 million.

No new shares of common stock were issued in 2005. 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 and $62.9 million during 2004 and 2003, 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 independent plan agents to begin purchasing the shares in the open market in lieu of issuing new shares. During 2005 and 2004, our plan agents purchased 2.0 million shares at a cost of $75.1 million and 3.2 million shares at a cost of $102.3 million, respectively, to fulfill exercised stock options. In 2005 and 2004, we received proceeds of $47.0 million and $66.1 million, respectively, related to the exercise of stock options.

Restrictions: Wisconsin Energy’s ability as a holding company to pay common dividends primarily depends on the availability of funds received from our principal utility subsidiaries, Wisconsin Electric and Wisconsin Gas. 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. In addition, under Wisconsin law, Wisconsin Electric and Wisconsin Gas are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy.

The Wisconsin Electric and Wisconsin Gas January 2006 rate order from the PSCW requires each company to maintain a capital structure (i.e., the percentage by which each of common stock, preferred stock and debt constitute the total capital invested in the utility), which has a common equity ratio range of between 48.5% and 53.5% (including certain off-balance sheet obligations and capitalized leases, but excluding the PWGS Unit 1 capitalized lease) for both companies. Previously in a June 2004 decision, the PSCW determined that both Wisconsin Electric and Wisconsin Gas must obtain specific approval to pay dividends that exceed normal levels as long as any tax issue or appeals related to the sale of the manufacturing business and/or the conversion of Wisconsin Gas to a limited liability company remain outstanding. The PSCW may modify such provisions by a future order.

Wisconsin Electric may not pay common dividends to Wisconsin Energy under Wisconsin Electric’s Restated Articles of Incorporation if any dividends on Wisconsin Electric’s outstanding preferred stock have not been paid. In addition, pursuant to the terms of Wisconsin Electric’s 3.60% Serial Preferred Stock, Wisconsin Electric’s ability to declare common dividends would be limited to 75% or 50% of net income during a twelve month period if Wisconsin Electric’s common stock equity to total capitalization, as defined, is less than 25% and 20%, respectively.

See Note L for discussion of certain financial covenants related to the bank back-up credit agreements of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas.

We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.

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K — LONG-TERM DEBT

Debentures and Notes: As of December 31, 2005, the maturities and sinking fund requirements of our long-term debt outstanding (excluding obligations under capital leases) were as follows:


	(Millions of Dollars)
2006	$	464.0
2007		250.8
2008		346.3
2009		50.6
2010		0.7
Thereafter		2,208.5

Total	$	3,320.9

We amortize debt premiums, discounts and debt issuance costs over the lives of the debt and we include the costs in interest expense.

Wisconsin Gas retired at the scheduled maturity date $65 million of 6-3/8% Notes due November 1, 2005. In November 2005, Wisconsin Gas issued $90 million of 5.90% Debentures due December 1, 2035. The securities were issued under shelf registration statements filed with the Securities and Exchange Commission (SEC). The proceeds from the sale were used to repay a portion of our outstanding commercial paper. The commercial paper was incurred to both retire the $65 million of 6-3/8% Notes and for working capital requirements.

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 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.

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

We treat the long-term power purchase contract as an operating lease for rate-making purposes and we record our minimum lease payments as purchased power expense on the Consolidated Income Statements. We paid a total of $25.2 million, $24.3 million and $23.4 million in minimum lease payments during 2005, 2004, and 2003, 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 assets - deferred plant related - capital lease in Note C). Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $78.5 million by the year 2009 at which time the regulatory asset will be reduced to zero over the remaining life of the contract. The total obligation under the capital lease increased to $160.2 million at December 31, 2005 and will now be reduced to zero over the remaining life of the contract.

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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 $1.7 million of interest expense on the nuclear fuel lease in fuel expense during 2005 and $1.4 million during 2004 and 2003.

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


Capital Lease Assets	2005			2004
	(Millions of Dollars)
Leased Facilities
Long-term purchase power commitment	$	140.3		$	140.3
Accumulated amortization		(47.1	)		(41.4	)

Total Leased Facilities	$	93.2		$	98.9


Nuclear Fuel
Under capital lease	$	125.6		$	120.2
Accumulated amortization		(60.2	)		(74.0	)
In process/stock		46.6			38.8

Total Nuclear Fuel	$	112.0		$	85.0

Future minimum lease payments under our capital leases and the present value of our net minimum lease payments as of December 31, 2005 are as follows:


Capital Lease Obligations	Purchase Power Commitment			Nuclear Fuel Lease			Total
	(Millions of Dollars)
2006	$	31.2		$	29.1		$	60.3
2007		32.4			20.8			53.2
2008		33.6			16.0			49.6
2009		34.9			7.6			42.5
2010		36.2			3.0			39.2
Thereafter		332.8			—			332.8

Total Minimum Lease Payments		501.1			76.5			577.6
Less: Estimated Executory Costs		(108.9	)		—			(108.9	)

Net Minimum Lease Payments		392.2			76.5			468.7
Less: Interest		(232.0	)		(5.9	)		(237.9	)

Present Value of Net Minimum Lease Payments		160.2			70.6			230.8
Less: Due Currently		(0.8	)		(27.0	)		(27.8	)

	$	159.4		$	43.6		$	203.0

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L — SHORT-TERM DEBT

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


	2005				2004
Short-Term Debt	Balance		Interest Rate		Balance		Interest Rate
	(Millions of Dollars, except for percentages)
Commercial paper	$	456.3	4.39	%	$	338.0	2.35	%

On December 31, 2005, we had approximately $1.2 billion of available unused lines of bank back-up credit facilities on a consolidated basis. We had approximately $456.3 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, 2005 and 2004:


	2005			2004
	(Millions of Dollars, except for percentages)
Maximum Short-Term Debt Outstanding	$	464.2		$	627.8
Average Short-Term Debt Outstanding	$	222.8		$	434.9
Weighted Average Interest Rate		3.20	%		1.41	%

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, subject to certain exceptions, 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.

The Wisconsin Energy, Wisconsin Electric and Wisconsin Gas bank back-up credit agreements contain customary covenants, including certain limitations on the respective companies’ ability to sell assets. The credit agreements also contain customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, ERISA defaults and change of control.

At December 31, 2005, we were in compliance with all covenants.

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.

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. In addition, these contracts were utilized in 2004 and the first half of 2005 for gas used in testing PWGS Unit 1. 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 PWGS Unit 1 test gas were capitalized.

For the years ended December 31, 2005 and 2004 the amount of hedge ineffectiveness was immaterial. We did not exclude any components of derivative gains or losses from the assessment of hedge effectiveness.

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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 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.

For the years ended December 31, 2005, 2004 and 2003, we reclassified $0.6 million, $0.8 million and $0.8 million in treasury lock agreement settlement payments deferred in Accumulated Other Comprehensive Income as an increase to Interest Expense. We estimate that during the next twelve months, $0.4 million will be reclassified from Accumulated Other Comprehensive Income as a reduction in earnings.

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 as of December 31 are as follows:


	2005				2004
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Millions of Dollars)
Nuclear decommissioning trust fund	$	782.1	$	782.1	$	737.8	$	737.8
Preferred stock, no redemption required	$	30.4	$	22.6	$	30.4	$	22.7
Long-term debt including current portion	$	3,320.9	$	3,386.2	$	3,155.4	$	3,301.0

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 I). 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, 2005.

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.

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	Pension Benefits						Other Post-Retirement Benefits
Status of Benefit Plans	2005			2004			2005			2004
	(Millions of Dollars)
Change in Benefit Obligation
Benefit Obligation at January 1	$	1,205.0		$	1,100.6		$	395.5		$	366.0
Service cost		33.3			30.2			13.6			12.0
Interest cost		69.7			69.1			21.0			21.8
Plan amendments		3.3			2.0			(85.5	)		0.7
Actuarial loss		79.6			103.8			4.1			9.9
Benefits paid		(91.2	)		(100.7	)		(16.8	)		(14.9	)

Benefit Obligation at December 31	$	1,299.7		$	1,205.0		$	331.9		$	395.5

Change in Plan Assets
Fair Value at January 1	$	998.5		$	926.3		$	183.6		$	166.8
Actual earnings on plan assets		65.4			95.4			6.9			12.3
Employer contributions		4.2			77.5			12.3			19.4
Benefits paid		(91.2	)		(100.7	)		(16.8	)		(14.9	)

Fair Value at December 31	$	976.9		$	998.5		$	186.0		$	183.6

Funded Status of Plans
Funded status at December 31		($322.8)			($206.5)			($145.9)		($	211.8	)
Unrecognized
Net actuarial loss		441.7			360.7			134.1			129.2
Prior service cost		32.2			34.0			(67.0	)		6.9
Net transition (asset) obligation		—			(0.1	)		2.4			12.6

Net Asset (Accrued Benefit Cost)	$	151.1		$	188.1			($76.4)			($63.1)

Amounts recognized in the Balance Sheet consist of:
Regulatory assets (See Note C)	$	377.2		$	342.8		$	—		$	—
Other deferred charges		32.4			34.3			53.5			51.5
Minimum pension liability		(274.4	)		(152.8	)		—			—
Other long-term liabilities		—			(45.4	)		(129.9	)		(114.6	)
Other comprehensive income		15.9			9.2			—			—

Net amount recognized at end of year	$	151.1		$	188.1			($76.4)			($63.1)

The accumulated benefit obligation for all defined benefit plans was $1,251.6 million and $1,195.5 million as of December 31, 2005 and 2004, respectively.

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


	2005		2004
	(Millions of Dollars)
Projected benefit obligation	$	1,299.7	$	1,189.1
Accumulated benefit obligation	$	1,251.6	$	1,181.1
Fair value of plan assets	$	976.9	$	998.5

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


	Pension Benefits									Other Post-retirement Benefits
Benefit Plan Cost Components	2005			2004			2003			2005			2004			2003
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	33.3		$	30.2		$	30.6		$	13.6		$	12.0		$	10.8
Interest cost		69.7			69.1			67.4			21.0			21.8			22.3
Expected return on plan assets		(87.6	)		(85.6	)		(87.3	)		(15.4	)		(14.1	)		(11.6	)
Amortization of:
Transition (asset) obligation		—			(2.3	)		(2.3	)		1.3			1.6			1.6
Prior service cost		5.2			4.8			4.8			(2.8	)		0.7			0.6
Actuarial loss		20.6			15.0			3.4			7.7			6.6			8.6

Net Periodic Benefit Cost	$	41.2		$	31.2		$	16.6		$	25.4		$	28.6		$	32.3

Weighted-Average assumptions used to determine benefit obligations at Dec. 31
Discount rate		5.50	%		5.75	%		6.25	%		5.50	%		5.75	%		6.25	%
Rate of compensation increase		4.5 to 5.0			4.0 to 5.0			4.0 to 5.0			4.5 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		5.75	%		6.25	%		6.75	%		5.75	%		6.25	%		6.75	%
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											2011			2010			2009

The expected long-term rate of return on plan assets was 9% in 2005 and 2004. In 2006, the expected rate of return on plan assets will be 8.5%, which is expected to increase pension expense by approximately $5.0 million. 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	$	23.0	($20.7)
Total of service and interest cost components	$	3.2	($2.8)

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 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 2004, in accordance with FSP 106-2, we chose to recognize the effects of the Act retroactively effective January 1, 2004. Calculated actuarially, the Act resulted in a reduction of $24.1 million in our benefit obligation. In addition, we recorded a reduction to SFAS 106 expense of $4.7 million in 2004. In January 2005, the Centers for Medicare & Medicaid Services released final

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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 do not need to be revised.

In October 2005, we announced that we were offering to our retirees a Medicare Advantage program as an option within our existing post-retirement medical and drug plans. The Medicare Advantage program is part of the Act, and offers post-65 medical and drug benefits through private insurance carriers. The Medicare Advantage program is expected to reduce the cost of post-65 medical and drug costs for our retirees and the Company. Due to this change, we remeasured the fair value of our other post-retirement plans in the fourth quarter of 2005 in accordance with SFAS 106, Employers’ Accounting for Post-Retirement Benefits Other than Pensions. In 2005, the impact of this remeasurement and the FSP 106-2 benefit was approximately a $4.4 million reduction to SFAS 106 expense.

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, 2005 and 2004, and our target allocation for 2006, by asset category, are as follows:


Asset Category	Target Allocation		Actual Allocation
	2006		2005		2004
Equity Securities	65	%	65	%	73	%
Debt Securities	35	%	35	%	27	%

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 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, 2005 and 2004, and our target allocation for 2006, by asset category, are as follows:


Asset Category	Target Allocation		Actual Allocation
	2006		2005		2004
Equity Securities	46	%	45	%	45	%
Debt Securities	53	%	54	%	54	%
Other	1	%	1	%	1	%

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	$	4.2	$	12.3

Based on our PSCW approved funding policy and current IRS funding requirements, we expect to contribute $58.2 million to fund pension benefits and $13.2 million to fund other post-retirement benefit plans in 2006. Of the $58.2 million expected to be

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contributed to fund pension benefits in 2006, we estimate $53.0 million will be for our qualified pension plans. We did not make a contribution to our qualified pension plan during 2005. We contributed $55.7 million to our qualified pension plans during 2004.

The entire contribution to the other post-retirement benefit plans during 2005 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:


Year	Pension		Gross Other Post Employment Benefits		Expected Medicare Part D Subsidy
	(Millions of Dollars)
2006	$	79.2	$	23.2		($1.5)
2007	$	89.7	$	22.4		($1.1)
2008	$	87.0	$	22.2		($1.1)
2009	$	91.7	$	19.5	$	—
2010	$	92.5	$	20.3	$	—
2011-2015	$	523.9	$	121.3	$	—

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 $10.7 million, $10.5 million and $10.1 million during 2005, 2004 and 2003, respectively.

Severance Plans: In 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. At December 31, 2004, we accrued $6.6 million for severance benefits. As of December 31, 2005, substantially all of the severance related benefits were paid.

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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, 2005, we had the following guarantees:


	Maximum Potential Future Payments		Outstanding Dec 31, 2005		Liability Recorded at Dec 31, 2005
	(Millions of Dollars)
Wisconsin Energy
Non-Utility Energy	$	—	$	—	$	—
Other		7.0		7.0		—
Wisconsin Electric		235.4		0.1		—
Subsidiary		10.3		10.0		—

Total	$	252.7	$	17.1	$	—

A Non-Utility Energy segment 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 and surety bonds. In the event our affiliates 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 I).

Subsidiary guarantees support loan obligations and surety bonds between our affiliates and third parties. In the event our affiliates fail to perform, 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, excluding severance benefits, for such benefits was $17.3 million as of December 31, 2005.

Q — SEGMENT REPORTING

Our reportable operating segments at December 31, 2005 include a utility energy segment and a non-utility energy segment. In July 2004, our manufacturing segment was sold 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, 2005, 2004 and 2003, 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, which are now included in income from discontinued operations as the sale of these businesses was announced or completed in 2005. In 2003, the segment information includes non-cash impairment charges, net of gains of $45.6 million ($29.7 million after tax or $0.25 per share). These impairment charges primarily related to the Non-Utility Energy segment (See Note D). Substantially all of our long-lived assets and operations are domestic.

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	Reportable Operating Segments						Corporate (b) & Other (c) & Reconciling Eliminations(d)		Total Consolidated
	Energy				Manufacturing (b)
Year Ended	Utility		Non-Utility(a)		Manufacturing (b)
	(Millions of Dollars)
December 31, 2005
Operating Revenues (d)	$	3,793.0	$	40.0	$	—		($17.5)	$	3,815.5
Depreciation, Decommissioning and Amortization	$	324.1	$	5.9	$	—	$	2.0	$	332.0
Operating Income (Loss)	$	542.4	$	19.5	$	—	$	1.0	$	562.9
Equity in Earnings (Losses) of Unconsolidated Affiliates	$	34.6	$	—	$	—		($0.6)	$	34.0
Interest Expense	$	106.1	$	14.4	$	—	$	52.9	$	173.4
Income Tax Expense	$	184.9	$	4.5	$	—		($40.2)	$	149.2
Income (Loss) from Discontinued Operations, Net	$	—	$	5.0	$	—	$	0.1	$	5.1
Net Income (Loss)	$	314.2	$	6.7	$	—		($12.2)	$	308.7
Capital Expenditures	$	458.6	$	276.6	$	—	$	9.9	$	745.1
Total Assets	$	9,601.6	$	749.5	$	—	$	110.9	$	10,462.0
December 31, 2004
Operating Revenues (d)	$	3,375.4	$	19.9	$	—	$	10.8	$	3,406.1
Depreciation, Decommissioning and Amortization	$	315.5	$	1.4	$	—	$	2.6	$	319.5
Operating Income (Loss)	$	528.6	$	4.6		($3.0)		($0.2)	$	530.0
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		($4.3)		($5.0)		($32.4)	$	132.8
Income (Loss) from Discontinued Operations, Net	$	—		($81.2)	$	31.9	$	136.1	$	86.8
Net Income (Loss)	$	283.9		($86.6)	$	26.6	$	82.5	$	306.4
Capital Expenditures	$	426.5	$	191.0	$	—	$	19.0	$	636.5
Total Assets	$	8,775.3	$	506.8	$	—	$	283.3	$	9,565.4
December 31, 2003
Operating Revenues (d)	$	3,263.9	$	12.3	$	—	$	5.9	$	3,282.1
Depreciation, Decommissioning and Amortization	$	316.2	$	1.3	$	—	$	3.0	$	320.5
Operating Income (Loss)	$	544.1		($55.7)		($1.7)		($2.6)	$	484.1
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		($33.1)		($7.0)		($31.8)	$	110.7
Income (Loss) from Discontinued Operations, Net	$	—		($3.8)	$	43.9	$	2.9	$	43.0
Net Income (Loss)	$	294.1		($52.7)	$	30.8		($27.9)	$	244.3
Capital Expenditures	$	455.6	$	163.6	$	—	$	28.8	$	648.0
Total Assets	$	8,303.9	$	397.6	$	938.0	$	375.0	$	10,014.5

(a)

The non-utility energy segment includes discontinued operations for the Calumet operations. The sale of Calumet was completed effective May 31, 2005. In 2005, Calumet is reported as discontinued operations for the five months ended May 31, 2005. The after tax gain of $4.7 million recorded for the sale is included in Income from Discontinued Operations, Net. Certain overheads reported for Calumet continue to exist following the sale and are reported in continuing operations. Certain other costs are directly attributable to the discontinued operations. Total assets in the non-utility segment include the assets held for sale of Calumet of $29.8 million and $155.1 million at December 31, 2004 and 2003, respectively.

(b)

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.

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(c)

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. In August 2005, we announced our intent to sell Minergy Neenah. The operations of Minergy Neenah are currently classified as discontinued operations in other. Certain overheads reported for Minergy Neenah will continue to exist following the sale and are reported in continuing operations. Certain other costs are directly attributable to the discontinued operations. Total assets in other includes Minergy Neenah assets held for sale of $17.4 million, $24.4 million and $51.0 million at December 31, 2005, 2004 and 2003, respectively.

(d)	An elimination for intersegment revenues is included in Operating Revenues of $36.3 million, $6.8 million and $5.9 million for 2005, 2004 and 2003, respectively.

R — RELATED PARTIES

We receive and/or provide certain services to other associated companies in which we have an equity investment.

American Transmission Company LLC: We have a 33.5% interest in ATC, a regional transmission company established in 2000 under Wisconsin legislation. We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance and project management work for ATC, which are reimbursed to us by ATC. Under our Power the Future plan, we are required to pay the cost of needed transmission infrastructure upgrades. ATC will reimburse us for these costs when the units are placed into service. At December 31, 2005 and 2004 we had a receivable of $19.4 million and $4.9 million for these items.

Guardian Pipeline: We have a one third ownership interest in Guardian Pipeline, L.L.C., which owns and operates an interstate natural gas pipeline. We have 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.

Nuclear Management Company: At December 31, 2005, NMC, which operates Point Beach, was owned by our affiliate, WEC Nuclear Corporation, and the affiliates of three other unaffiliated investor-owned utilities in the region. Wisconsin Electric pays NMC a plant operating charge.

We provided and received services from the following associated companies during 2005, 2004 and 2003:


Equity Investee	2005		2004		2003
	(Millions of Dollars)
Services Provided
-American Transmission Company	$	20.9	$	21.6	$	31.7
Services Received
-American Transmission Company	$	130.1	$	115.5	$	96.1
-Nuclear Management Company	$	61.2	$	58.1	$	57.1
-Guardian Pipeline	$	34.0	$	33.6	$	33.8

At December 31, 2005 and 2004 our consolidated balance sheets included receivable and payable balances with the following associated companies:


Equity Investee	2005		2004
	(Millions of Dollars)
Accounts Receivable
-American Transmission Company	$	1.3	$	2.2
Accounts Payable
-American Transmission Company	$	10.6	$	9.6
-Nuclear Management Company	$	2.5	$	3.3
-Guardian Pipeline	$	3.0	$	3.1

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S — COMMITMENTS AND CONTINGENCIES

Capital Expenditures: We have made certain commitments in connection with 2006 capital expenditures. During 2006, we estimate that total capital expenditures will be approximately $1,020.0 million, excluding the purchase of nuclear fuel.

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)
2006	$	51.1
2007		50.4
2008		34.5
2009		21.4
2010		19.4
Thereafter		48.3

	$	225.1

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 sixteen sites at which Wisconsin Electric, Wisconsin Gas, or a predecessor company historically owned or operated a manufactured gas plant. We have substantially completed planned remediation activities at eight of those sites and certain sites are subject to ongoing monitoring. Remediation at additional sites is currently being performed, and other sites are being investigated or monitored. We have also identified other 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 to $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, 2005, we have established reserves of $27.4 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 byproducts. 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 2005, 2004 and 2003, Wisconsin Electric incurred $0.1 million, $1.8 million and $2.1 million, respectively, in coal-ash remediation expenses. As of December 31, 2005, we have no reserves established related to ash landfill sites.

EPA - Proposed Consent Decree: Wisconsin Electric received a request for information in December 2000 from the United States Environmental Protection Agency (EPA) regional office 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 that resolved all issues related to this matter. In July 2003, the court granted the State of Michigan and EPA’s joint motion to amend the consent decree to allow Michigan to become a party. Under the consent decree, Wisconsin Electric is required to significantly reduce its air

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emissions from its coal-fired generating facilities. The reductions are expected to 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. Through December 31, 2005, we have spent approximately $216.5 million associated with implementing the EPA agreement. There may be additional costs of compliance should Wisconsin Electric elect to control rather than retire Units 5 and 6 at the Oak Creek Power Plant. We believe this additional cost may add approximately $150 million to $350 million to the estimate. Under the agreement with EPA, Wisconsin Electric is conducting 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 is contributing $24.8 million in addition to the $20 to $25 million Wisconsin Electric is spending 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 concluded in March 2005. The court may convene additional hearings.

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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, 2005 and 2004, and the related consolidated statements of income, common equity and cash flows for each of the three years in the period ended December 31, 2005. 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, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

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, 2005, 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 27, 2006 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.

Milwaukee, Wisconsin

February 27, 2006

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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 (the “Company”) maintained effective internal control over financial reporting as of December 31, 2005, 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, 2005, 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, 2005, 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, 2005, and the related consolidated statements of income, common equity and cash flows for the year ended December 31, 2005 of the Company and our report dated February 27, 2006 expressed an unqualified opinion on those financial statements.

Milwaukee, Wisconsin

February 27, 2006

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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 Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. 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 Wisconsin Energy Corporation’s and subsidiaries 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 Wisconsin Energy Corporation’s and subsidiaries internal control over financial reporting was effective as of December 31, 2005.

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 Wisconsin Energy Corporation’s and subsidiaries internal control over financial reporting as of December 31, 2005. Deloitte & Touche’s report is included in this report.

Changes in Internal Control Over Financial Reporting

During the fourth quarter of 2005, management implemented federal and state tax software that increased the functionality of ongoing tax estimates and enabled more frequent and reliable analyses of federal and state income tax balances. Apart from this change, there has not been any change in Wisconsin Energy Corporation’s and subsidiaries internal control over financial reporting during the fourth quarter of 2005 that has materially affected, or is reasonably likely to materially affect, Wisconsin Energy Corporation’s and subsidiaries internal control over financial reporting.

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MARKET FOR REGISTRANT’S COMMON

EQUITY AND RELATED STOCKHOLDER MATTERS

NUMBER OF COMMON STOCKHOLDERS

As of December 31, 2005, based upon the number of Wisconsin Energy Corporation stockholder accounts (including accounts in our dividend reinvestment and stock purchase plan), we had 55,532 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 J — Common Equity in the Notes to Consolidated Financial Statements.

On January 18, 2006, our Board of Directors announced that it increased our common stock quarterly dividend rate by 4.5%, to $0.23 per share. With the increase, the new dividend is equivalent to an annual rate of $0.92 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:


	2005						2004
Quarter	High		Low		Dividend		High		Low		Dividend
First	$	36.12	$	33.35	$	0.22	$	34.30	$	31.57	$	0.20
Second	$	39.31	$	34.20		0.22	$	33.00	$	29.50		0.21
Third	$	40.48	$	37.32		0.22	$	32.95	$	31.12		0.21
Fourth	$	40.83	$	36.49		0.22	$	34.60	$	31.50		0.21

Year	$	40.83	$	33.35	$	0.88	$	34.60	$	29.50	$	0.83

BUSINESS OF THE COMPANY

Wisconsin Energy Corporation was incorporated in the State of Wisconsin in 1981 and became a diversified holding company in 1986. We maintain our principal executive offices in Milwaukee, Wisconsin. We conduct our operations primarily in two operating segments: a utility energy segment and a non-utility energy segment. 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 1,092,400 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 446,400 gas customers in Wisconsin and approximately 460 steam customers in metro Milwaukee, Wisconsin; Wisconsin Gas, which serves approximately 583,300 gas customers in Wisconsin and approximately 2,800 water customers in suburban Milwaukee, Wisconsin; and Edison Sault Electric Company (Edison Sault), which serves approximately 22,900 electric customers in the Upper Peninsula of Michigan. Wisconsin Electric and Wisconsin Gas operate under the trade name of “We Energies”.

Non-Utility Energy Segment: Our non-utility energy segment consists primarily of We Power. We Power was formed in 2001 to design, construct, own and lease to Wisconsin Electric 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.

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Discontinued Operations: Effective July 31, 2004, we sold our manufacturing segment. Effective May 31, 2005, we sold our Calumet Energy facility, which was part of our non-utility energy segment. In August 2005, we announced our intent to sell Minergy Neenah, LLC.

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

DIRECTORS AND EXECUTIVE OFFICERS

DIRECTORS

The information under “Proposal 1: Election of Directors - Terms Expiring in 2007” in Wisconsin Energy Corporation’s definitive Proxy Statement dated March 16, 2006, 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.

•

Vice President and 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.

Effective January 3, 2006, James C. Fleming was appointed Executive Vice President of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas LLC.

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, 2005. 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 2006 Annual Meeting of Stockholders. Last year, we filed this certification with the NYSE on May 17, 2005.

B-83

LOGO

YOUR VOTE IS IMPORTANT

VOTE BY INTERNET / TELEPHONE

24 HOURS A DAY, 7 DAYS A WEEK


INTERNET	OR	TELEPHONE	OR	MAIL
https://www.proxyvotenow.com/wec		Toll free: 1-866-756-9925
• 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

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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.

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

Election of Directors

FOR
ALL

WITHHOLD
FOR ALL

EXCEPTIONS

Check here if you plan to attend the annual meeting.

Nominees:

01 - John F. Ahearne

04 - Robert A. Cornog

07 - Gale E. Klappa

02 -John F. Bergstrom
03 -Barbara L. Bowles

05 - Curt S. Culver
06 - Thomas J. Fischer

08 - Ulice Payne, Jr.
09 -Frederick P. Stratton, Jr.

Please remember to bring your Admission Ticket to the meeting.

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

To change your address, please mark this box.


		FOR	AGAINST	ABSTAIN

2.	Ratification of Deloitte & Touche LLP as independent auditors for 2006.	¨	¨	¨


								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 4, 2006 10:00 a.m. Central time
Pettit National Ice Center 500 South 84th Street Milwaukee, WI 53214
If you plan to attend in person, please check the box on the reverse side and bring the Admission Ticket located in your proxy statement with you to the meeting.
Name

Address

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Wisconsin Energy Corporation

Proxy / Voting Instructions for the Annual Meeting of Stockholders

May 4, 2006


This PROXY is solicited by the Board of Directors for use at the Annual Meeting of Stockholders on May 4, 2006. 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, Thomas J. Fischer, Gale E. Klappa, Ulice Payne, Jr., and Frederick P. Stratton, Jr. as Directors.

2. Ratification of Deloitte & Touche LLP as independent auditors for 2006.

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 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.


Admission Ticket
THIS TICKET ADMITS THE STOCKHOLDER AND ONE GUEST

Wisconsin Energy Corporation		This ticket admits the stockholder and one guest. If your shares are jointly owned and you would like an additional ticket, contact (800) 881-5882.
Annual Meeting of Stockholders
Thursday, May 4, 2006

10:00 a.m. Central time		Please Note: The temperature in the Pettit Center may be quite cool. You may want to bring a sweater or a jacket.

Pettit National Ice Center 500 South 84th Street Milwaukee, Wisconsin 53214		All carry-ins are subject to inspection. For security purposes, photographic, video and audio recording devices are not allowed into the meeting.


Pettit National Ice Center Directions
From the west: Heading east on I-94, take the 84th Street exit.
Turn right (south) onto 84th Street. Enter at Gate 6 on your left.
From the east: Heading west on I-94, take the 84th Street exit.
Turn left (south) onto 84th Street. Enter at Gate 6 on your left.
From the north:
Heading south on Highway 45, take the Greenfield Avenue exit.
Go left (east) on Greenfield Avenue. Turn left (north) onto 84th Street.
Enter at Gate 6 on your right.
Heading south on I-43, take I-94 west to the 84th Street exit.
Turn left (south) onto 84th Street. Enter at Gate 6 on your left.
From Chicago and other points south: Take I-94 west to I-894
bypass. Continue on I-894 west to the Greenfield Avenue exit.
Go right (east) on Greenfield Avenue. Turn left (north) onto 84th
Street. Enter at Gate 6 on your right.
From the southwest: Take the I-894 west bypass to the Greenfield
Avenue exit. Go right (east) on Greenfield Avenue. Turn left (north)
onto 84th Street. Enter at Gate 6 on your right.