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

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

SCHEDULE 14C

Information Statement Pursuant to Section 14(c)

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

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Wisconsin Electric Power Company
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Gale E. Klappa

Chairman, President and

Chief Executive Officer

231 W Michigan Street

Milwaukee, WI 53203

April 6, 2009

Dear Stockholder:

Wisconsin Electric Power Company, which does business under the trade name of We Energies, will hold its Annual Meeting of Stockholders on Friday, May 1, 2009, at 10:00 a.m., in Conference Room P449 of the Public Service Building, 231 West Michigan Street, Milwaukee, Wisconsin 53203.

We are not soliciting proxies for this meeting, as over 99% of the voting stock is owned, and will be voted, by Wisconsin Electric Power Company’s parent, Wisconsin Energy Corporation. If you wish, you may vote your shares of preferred stock in person at the meeting; however, the business session will be very brief.

As an alternative, you might consider attending Wisconsin Energy Corporation’s Annual Meeting of Stockholders to be held Thursday, May 7, 2009, at 10:00 a.m., Central time, in the Cedarburg Performing Arts Center, W68 N611 Evergreen Boulevard, Cedarburg, Wisconsin 53012.

By attending this meeting, you would have the opportunity to meet many of the Wisconsin Electric Power Company officers and directors. Although you cannot vote your shares of Wisconsin Electric Power Company preferred stock at the Wisconsin Energy Corporation meeting, you may find the activities worthwhile. An admission ticket will be required to enter the meeting. To obtain an admission ticket, please contact Wisconsin Energy Corporation’s Stockholder Services, 231 West Michigan Street, P.O. Box 1331, Milwaukee, Wisconsin 53201, or simply call 800-881-5882.

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

Thank you for your support.

Sincerely,

NOTICE OF ANNUAL MEETING OF STOCKHOLDERS

April 6, 2009

To the Stockholders of Wisconsin Electric Power Company:

The 2009 Annual Meeting of Stockholders of Wisconsin Electric Power Company will be held on Friday, May 1, 2009, at 10:00 a.m., Central time, in Conference Room P449 at the Public Service Building, 231 West Michigan Street, Milwaukee, Wisconsin 53203, for the following purposes:

1. To elect the nine members of the Board of Directors to hold office until the 2010 Annual Meeting of Stockholders; and

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

Stockholders of record at the close of business on February 26, 2009, are entitled to vote. The following pages provide additional details about the meeting as well as other useful information.

Important Notice Regarding the Availability of Materials Related to the Stockholder Meeting to Be Held on May 1, 2009 – The Information Statement and 2008 Annual Report to Stockholders are available at:

http://bnymellon.mobular.net/bnymellon/welpp

By Order of the Board of Directors,

Susan H. Martin

Vice President, Corporate Secretary and Associate General Counsel

231 West Michigan Street

Milwaukee, Wisconsin 53203

INFORMATION STATEMENT

This information statement is being furnished to stockholders beginning on or about April 6, 2009, in connection with the annual meeting of stockholders of Wisconsin Electric Power Company (“WE” or the “Company”) to be held on Friday, May 1, 2009 (“the Meeting”), at 10:00 a.m., Central time, in Conference Room P449 at the Public Service Building, 231 West Michigan Street, Milwaukee, Wisconsin 53203, and all adjournments or postponements of the Meeting, for the purposes listed in the preceding Notice of Annual Meeting of Stockholders. If you need directions to the Meeting, please call our toll-free stockholder hotline at 800-881-5882. The WE annual report to stockholders is attached as Appendix A to this information statement.

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

VOTING SECURITIES

As of February 26, 2009, WE had outstanding 44,498 shares of $100 par value Six Per Cent. Preferred Stock; 260,000 shares of $100 par value 3.60% Serial Preferred Stock; and 33,289,327 shares of common stock. Each outstanding share of each class is entitled to one vote. Stockholders of record at the close of business on February 26, 2009 will be entitled to vote at the Meeting. In order to conduct the Meeting, a majority of the outstanding shares entitled to vote must be represented at the Meeting. This is known as a “quorum.” All of WE’s outstanding common stock owned by Wisconsin Energy Corporation (“WEC”) will be represented at the Meeting.

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

INTERNET AVAILABILITY OF INFORMATION

The following documents can be found athttp://bnymellon.mobular.net/bnymellon/welpp:

• Notice of Annual Meeting;

• Information Statement; and

• 2008 Annual Report to Stockholders.

ELECTION OF DIRECTORS

At the Meeting, there will be an election of nine directors. The individuals named below have been nominated by the WE Board of Directors (the “Board”) to serve a one-year term expiring at the 2010 Annual Meeting of Stockholders and until they are re-elected or until their respective successors are duly elected and qualified. Currently, directors of WEC also serve as the directors of WE.

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

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

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Information About Nominees for Election to the Board of Directors for Terms Expiring in 2010.

Biographical information regarding each nominee is shown below. WE and Wisconsin Gas LLC (WG) do business as We Energies and are wholly-owned subsidiaries of WEC. Ages and biographical information are as of March 1, 2009.

John F. Bergstrom. Age 62.

• Bergstrom Corporation – Chairman since 1982 and Chief Executive Officer since 1974. Bergstrom Corporation owns and operates numerous automobile sales and leasing companies.

• Director of Advance Auto Parts Inc. and Kimberly-Clark Corporation.

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

Barbara L. Bowles. Age 61.

• Profit Investment Management – Retired Vice Chair. Served as Vice Chair from January 2006 until retirement in December 2007. Profit Investment Management is an investment advisory firm.

• The Kenwood Group, Inc. – Retired Chairman. Served as Chairman from 2000 until June 2006 when The Kenwood Group, Inc. merged into Profit Investment Management. Chief Executive Officer from 1989 to December 2005.

• Director of Black & Decker Corporation and Hospira, Inc.

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

Patricia W. Chadwick.Age 60.

• Ravengate Partners, LLC – President since 1999. Ravengate Partners, LLC provides businesses and not-for-profit institutions with advice about the financial markets.

• Director of AMICA Mutual Insurance Company and ING Mutual Funds.

• Director of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas LLC since 2006.

Robert A. Cornog. Age 68.

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

• Director of Johnson Controls, Inc.

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

Curt S. Culver. Age 56.

• 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 61.

• Fischer Financial Consulting LLC – Principal since 2002. Fischer Financial Consulting LLC provides consulting on corporate financial, accounting and governance matters.

• Arthur Andersen LLP – Retired as Managing Partner of the Milwaukee office in 2002. Served as Managing Partner from 1993 and as Partner from 1980. 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 2005.

Gale E. Klappa. Age 58.

• 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.

• Director of Joy Global Inc.

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

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Ulice Payne, Jr.Age 53.

• 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.

• Director of Badger Meter, Inc. and Manpower Inc., and 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 69.

• Briggs & Stratton Corporation – Chairman Emeritus since 2003. Chairman of the Board from 2001 to 2003. Chairman and Chief Executive Officer from 1986 until 2001. Briggs & Stratton Corporation is a manufacturer of small gasoline engines.

• Director of Baird Funds, Inc. and Weyco Group, Inc.

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

OTHER MATTERS

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

CORPORATE GOVERNANCE – FREQUENTLY ASKED QUESTIONS

Does WE have Corporate Governance Guidelines?	The WE Board of Directors follows WEC’s Corporate Governance Guidelines that WEC has maintained since 1996. These Guidelines provide a framework under which the Board conducts its business. The Guidelines are available in the “Governance” section of WEC’s website atwww.wisconsinenergy.com and are available in print to any stockholder who requests them in writing from the Corporate Secretary.
How are directors determined to be independent?	No director qualifies as independent unless the Board affirmatively determines that the director has no material relationship with the Company. WEC’s Corporate Governance Guidelines provide that the WEC Board should consist of at least a two-thirds majority of independent directors and currently, directors of WEC also serve as the directors of WE.
What are the Board’s standards of independence?	The guidelines the Board uses in determining director independence are located in Appendix A of WEC’s Corporate Governance Guidelines. These standards of independence, which are 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. A director will be considered independent by the Board if 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 $120,000 per year in direct compensation from the Company, other than director fees or deferred compensation for prior service;
	•        is not a current partner or employee of a firm that is the Company’s internal or external auditor, was not within the last three years a partner or employee of such a firm and personally worked on the Company’s audit within that time, or has no immediate family member who is a current employee of such a firm and personally works on the Company’s audit;
	•        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 thande 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;

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	•        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 thande 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 the Company’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. For purposes of the above discussion, “Company” refers to WEC and its subsidiaries, including WE.
Who are the independent directors?	The Board has affirmatively determined that Directors Bergstrom, Bowles, Chadwick, Cornog, Culver, Fischer, Payne and Stratton have no relationships within the Board’s standards of independence noted above and otherwise have no material relationships with WE or WEC and are independent. This represents 89% of the Board. Director Klappa is not independent due to his present employment with WEC and its affiliates. John F. Ahearne, who did not stand for re-election at the 2008 Annual Meeting of Stockholders, was independent.
What are the committees of the Board?	The Board of Directors of WE has the following committees: Audit and Oversight, Compensation, Finance, and Executive. All committees, except the Executive Committee, operate under a charter approved by the Board. A copy of each committee charter is posted in the “Governance” section of WEC’s website atwww.wisconsinenergy.com and are available in print to any stockholder who requests it in writing from the Corporate Secretary. The members and the responsibilities of each committee are listed later in this information statement under the heading “Committees of the Board of Directors.”
Are the Audit and Oversight and Compensation Committees comprised solely of independent directors?	Yes, these committees are comprised solely of independent directors, as determined under New York Stock Exchange rules and WEC’s Corporate Governance Guidelines. In addition, 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 non-management (non-employee) directors meet in executive session without any management present. All non-management directors are independent. Currently, Director Bowles presides at these sessions.
How can interested parties contact the members of the Board?	Correspondence may be sent to the directors, including the non-management directors, in care of the Corporate Secretary, Susan H. Martin, at the Company’s principal business office, 231 West Michigan Street, P.O. Box 2046, Milwaukee, Wisconsin 53201.
	All communication received as set forth above will be opened by the Corporate Secretary for the sole purpose of 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 WE and 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; confidentiality; fair dealing; protection and proper use of Company assets; and compliance with

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	laws, rules and regulations (including insider trading laws). The Company has not provided any waiver to the Code for any director, executive officer or other employee.
	The Code of Business Conduct is posted in the “Governance” section of WEC’s website atwww.wisconsinenergy.com. It is also available in print to any stockholder upon request in writing to the Corporate Secretary. The Company has contracted with an independent call center for employees to confidentially report suspected violations of the Code of Business Conduct or other concerns regarding accounting, internal accounting controls or auditing matters.
Does the Company have policies and procedures in place to review and approve related party transactions?	All employees of the Company, including executive officers and members of the Board, are required to comply with WEC’s Code of Business Conduct. The Code addresses, among other things, what actions are required when potential conflicts of interest may arise, including those from related party transactions. Specifically, executive officers and members of the Board are required to obtain approval of the Audit and Oversight Committee chair (1) before obtaining any financial interest in or participating in any business relationship with any company, individual or concern doing business with WEC or any of its subsidiaries, including WE, (2) before participating in any joint venture, partnership or other business relationship with WEC or any of its subsidiaries, including WE, and (3) before serving as an officer or member of the board of any substantial outside for-profit organization (except the Chief Executive Officer must obtain the approval of the full Board before doing so and members of the Board of Directors must obtain the prior approval of WEC’s Corporate Governance Committee). Executive officers must obtain the prior approval of the Chief Executive Officer before accepting a position with a substantial non-profit organization; members of the Board must notify the Compliance Officer when joining such a non-profit organization, but do not need to obtain approval prior to joining the organization.
	In addition, WEC’s Code of Business Conduct requires employees to notify the Compliance Officer of situations where family members are a supplier or significant customer of WEC or the Company or employed by one. To the extent the Compliance Officer deems it appropriate, she will consult with the Audit and Oversight Committee chair in situations involving executive officers and members of the Board.
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 consider 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; monitoring threats and overseeing opportunities critical to the Company; and operating in a manner that ensures open communication, candid and constructive dialogue as well as critical questioning. WEC’s Corporate Governance Committee uses the results of this process as part of its annual review of the Corporate Governance Guidelines and to foster continuous improvement of the Board’s activities.
Is Board committee 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. Each committee may adjust its charter, with Board approval, based on the evaluation results.

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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 and 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 Electric Power Company and Wisconsin Energy Corporation to be service on the audit committee of one public company because of the commonality of the issues considered by those committees.
What are the principal processes and procedures used by the Compensation Committee to determine executive and director compensation?	One of the principal responsibilities of the Compensation Committee is to provide a competitive, performance-based executive and director compensation program. This includes: (1) determining and periodically reviewing the Committee’s compensation philosophy; (2) determining and reviewing the compensation paid to executive officers (including base salaries, incentive compensation and benefits); (3) oversight of the compensation and benefits to be paid to other officers and key employees; and (4) establishing and administering the Chief Executive Officer compensation package. The Compensation Committee is also charged with administering the compensation package of the non-employee directors. Although it has not chosen to do so, the Committee may delegate all or a portion of its duties and responsibilities to a subcommittee of the Committee.
	The Chief Executive Officer, after reviewing compensation data compiled by Towers Perrin, a compensation consulting firm, and each executive officer’s individual experience, performance, responsibility and contribution to the results of the Company’s operations, makes compensation recommendations to the Committee for all executive officers other than himself. The Compensation Committee is free to make adjustments to such recommendations as it deems appropriate.
	Although the Compensation Committee relies on compensation data regarding general industry and the energy services industry compiled by Towers Perrin, Towers Perrin does not recommend the amount or form of executive and director compensation. WEC engaged Towers Perrin to provide a variety of compensation-related services on a consolidated basis, one of which is to provide the compensation data. Towers Perrin was not engaged directly by the Compensation Committee. However, the Committee has unrestricted access to Towers Perrin and may retain its own compensation consultant at its discretion. For more information regarding our executive compensation processes and procedures, please refer to the “Compensation Discussion and Analysis” later in this information statement.
Does the Board have a nominating committee?	WE does not have a nominating committee. WE relies on WEC’s Corporate Governance Committee for, among other things, identifying and evaluating director nominees. The chair of the Committee coordinates this effort. The WEC Board has determined that all members of the WEC Corporate Governance Committee are independent under New York Stock Exchange rules applicable to nominating committee members. The WEC Corporate Governance Committee operates under a charter approved by the WEC Board, a copy of which is posted in the “Governance” section of WEC’s website atwww.wisconsinenergy.com.
What is the process used to identify director nominees and how do I recommend a nominee to WEC’s Corporate Governance Committee?	Candidates for director nomination may be proposed by stockholders, WEC’s Corporate Governance Committee and other members of the Board. The Committee may pay a third party to identify qualified candidates; however, no such firm was engaged with respect to the nominees listed in this information statement. No stockholder nominations or recommendations for director candidates were received from holders of either series of the Company’s preferred stock. Stockholders wishing to propose director candidates for consideration and recommendation by WEC’s Corporate Governance Committee for election at the Company’s 2010 Annual Meeting of Stockholders must submit the candidates’ names and qualifications to WEC’s Corporate Governance Committee no later than November 2, 2009, via the Corporate Secretary, Susan H. Martin, at WEC’s principal business office, 231 West Michigan Street, P.O. Box 1331, Milwaukee, Wisconsin 53201.

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What are the criteria and process used to evaluate director nominees?	WE relies on WEC’s Corporate Governance Committee for identifying and evaluating director nominees. WEC’s Corporate Governance Committee has not established minimum qualifications for director nominees; however, the criteria for evaluating all candidates, which are reviewed annually, include characteristics such as: proven integrity, mature and independent judgment, vision and imagination, ability to objectively appraise problems, ability to evaluate strategic options and risks, sound business experience and acumen, relevant technological, political, economic or social/cultural expertise, social consciousness, achievement of prominence in career, familiarity with national and international issues affecting WEC and the Company’s businesses, contribution to the Board’s desired diversity and balance and availability to serve for five years before reaching the directors’ retirement age of 72 as set forth in WEC’s Corporate Governance Guidelines.
	In evaluating director candidates, WEC’s Corporate Governance Committee reviews potential conflicts of interest, including interlocking directorships and substantial business, civic and/or social relationships with other members of the Board that could impair the prospective Board member’s ability to act independently from the other Board members and management.
	Once a person has been identified by WEC’s Corporate Governance Committee as a potential candidate, the Committee may collect and review publicly available information regarding the person to assess whether the person should be considered further. If the Committee determines that the candidate warrants further consideration, the chair or another member of the Committee contacts the person. Generally, if the person expresses a willingness to be considered and to serve on the Board, the Committee requests information from the candidate, reviews the person’s accomplishments and qualifications and conducts one or more interviews with the candidate. In certain instances, Committee members may contact one or more references provided by the candidate or may contact other members of the business community or other persons who 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 and stability to allow it to effectively meet the many challenges WE and WEC face in today’s changing business environment.
What is WE’s policy regarding director attendance at annual meetings?	Directors are not expected to attend WE’s annual meetings of stockholders, as they are only short business meetings. All directors are expected to attend WEC’s annual meetings of stockholders. All current directors attended WEC’s 2008 Annual Meeting.

COMMITTEES OF THE BOARD OF DIRECTORS

Members	Principal Responsibilities; Meetings
Audit and Oversight Thomas J. Fischer, Chair John F. Bergstrom Barbara L. Bowles Robert A. Cornog	•        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 information statement.
	•        Establish procedures for the submission of complaints and concerns regarding WE’s accounting or auditing matters.
	•        The Committee conducted six meetings in 2008.
Compensation John F. Bergstrom, Chair Ulice Payne, Jr. Frederick P. Stratton, 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.
	•        The Committee conducted six meetings in 2008, including one joint meeting with WEC’s Corporate Governance Committee.

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Finance Curt S. Culver, Chair Patricia W. Chadwick 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 four meetings in 2008, and executed one signed, written unanimous consent.

Wisconsin Electric relies on WEC’s Corporate Governance Committee for identifying and evaluating director nominees. WEC’s Corporate Governance Committee is also responsible for establishing and reviewing the WEC Corporate Governance Guidelines which are followed by the Board. The members of WEC’s Corporate Governance Committee are Barbara L. Bowles (Chair), Robert A. Cornog, Curt S. Culver and Frederick P. Stratton, Jr. WEC’s Corporate Governance Committee conducted four meetings in 2008, including one joint meeting with Wisconsin Electric’s Compensation Committee.

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 2008.

In addition to the number of committee meetings listed in the preceding table, the Board met six times in 2008 and executed one signed, written unanimous consent. The average meeting attendance during the year was 93%. No director attended fewer than 83% of the total number of meetings of the Board and Board committees on which he or she served.

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INDEPENDENT AUDITORS’ FEES AND SERVICES

Deloitte & Touche LLP served as the independent auditors for the Company for the last seven fiscal years beginning with the fiscal year ended December 31, 2002. They have been selected by the Audit and Oversight Committee as independent auditors for the Company for the fiscal year ending December 31, 2009, subject to ratification by the stockholders of Wisconsin Energy Corporation at WEC’s Annual Meeting of Stockholders on May 7, 2009.

Representatives of Deloitte & Touche LLP are not expected to be present at the Meeting, but are expected to attend WEC’s Annual Meeting of Stockholders on May 7, 2009. They will have an opportunity to make a statement at WEC’s Annual Meeting, if they so desire, and are expected to respond to appropriate questions that may be directed at them.

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 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 or by the Public Company Accounting Oversight Board to be performed by the Company’s independent auditors. These services include bookkeeping or other services related to the accounting records or financial statements 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 or human resources, broker-dealer, investment advisor or investment banking services, legal services and expert services unrelated to the audit, services provided for a contingent fee or commission and services related to planning, marketing or opining in favor of the tax treatment of a confidential transaction or an aggressive tax position transaction that was initially recommended, directly or indirectly, by the independent auditors. In addition, the Committee has determined that the independent auditors may not provide any services, including personal financial counseling and tax services, to any officer of the Company or member of the Audit and Oversight Committee or an immediate family member of these individuals, including spouses, spousal equivalents and dependents.

Fee Table.The following table shows the fees, all of which were pre-approved by the Audit and Oversight Committee, for professional audit services provided by Deloitte & Touche LLP for the audit of Wisconsin Electric’s annual financial statements for fiscal years 2008 and 2007 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 Exchange Act of 1934, as amended.

	2008		2007
Audit Fees(1)	$	1,253,390	$	807,645
Audit-Related Fees(2)		—		38,689
Tax Fees(3)		697,860		631,814
All Other Fees(4)		3,675		3,646
Total	$	1,954,925	$	1,481,794

⁽¹⁾ Audit Feesconsist of fees for professional services rendered in connection with the audit of Wisconsin Electric’s annual financial statements, reviews of financial statements included in Form 10-Q filings of the Company and services normally provided in connection with statutory and regulatory filings or engagements.

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

⁽³⁾ Tax Feesconsist of fees for professional services rendered with respect to federal and state tax compliance and tax advice. During 2008 and 2007, this included tax strategy consulting.

⁽⁴⁾ All Other Fees consist of costs for certain employees to attend accounting/tax seminars hosted by Deloitte & Touche LLP in 2008 and 2007.

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AUDIT AND OVERSIGHT COMMITTEE REPORT

The Audit and Oversight Committee, which is comprised solely of independent directors, oversees the integrity of the financial reporting process on behalf of the Board of Directors of Wisconsin Electric Power Company. In addition, the Committee 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 Wisconsin Energy Corporation’s website atwww.wisconsinenergy.com.

The Committee is also responsible for the appointment, compensation, retention and oversight of the Company’s independent auditors, as well as the oversight of the Company’s internal audit function. The Committee selected Deloitte & Touche LLP to remain as the Company’s independent auditors for 2009, subject to ratification by Wisconsin Energy Corporation’s stockholders.

Management is responsible for the Company’s financial reporting process, the preparation of consolidated financial statements in accordance with generally accepted accounting principles and the system of internal controls and procedures designed to 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 six meetings during 2008. 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 unaudited quarterly and audited 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. 114 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 the auditors’ independence from Deloitte & Touche LLP, as required by applicable requirements of the Public Company Accounting Oversight Board regarding Deloitte & Touche LLP’s communications with the Committee concerning independence. The Committee discussed with Deloitte & Touche LLP its independence and also considered the compatibility of non-audit services provided by Deloitte & Touche LLP with maintaining its independence.

Based on these reviews and discussions, the Audit and Oversight Committee recommended to the Board of Directors that the audited financial statements be included in Wisconsin Electric Power Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008 and filed with the Securities and Exchange Commission.

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

Thomas J. Fischer, Committee Chair

John F. Bergstrom

Barbara L. Bowles

Robert A. Cornog

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COMPENSATION DISCUSSION AND ANALYSIS

General Overview.The primary objective of our executive compensation program is to provide a competitive, performance-based plan that enables the Company to attract and retain key individuals and to motivate them to achieve both the Company’s long-term and short-term goals. Our program has been designed to provide a level of compensation that is strongly dependent upon the achievement of goals that are aligned with the interests of WEC’s stockholders and our customers. As a result, a substantial portion of pay is at risk.

The Compensation Committee of the Company is comprised of the same individuals who are members of the Compensation Committee of the Board of Directors of Wisconsin Energy Corporation (the “WEC Compensation Committee” and, together with the Company’s Compensation Committee, the “Compensation Committee”). The named executive officers of the Company are the same as the named executive officers of WEC, and the WEC Compensation Committee and the Company’s Compensation Committee each have responsibility for making compensation decisions regarding these executive officers.

The following discussion provides an overview and analysis of our executive compensation program, including the role of the Compensation Committee, the elements of our executive compensation program, the purposes and objectives of these elements and the manner in which we established the compensation of our executive officers for fiscal year 2008.

References to “we”, “us”, “our” and the “Company” in this discussion and analysis mean Wisconsin Electric Power Company and its management, as applicable, and references to “WEC” mean Wisconsin Energy Corporation.

Compensation Committee.The Compensation Committee is responsible for making decisions regarding compensation for executive officers of WEC and its principal subsidiaries, including the Company, and for developing our executive compensation philosophy. The assessment of the Chief Executive Officer’s performance and determination of the CEO’s compensation are among the principal responsibilities of the Compensation Committee. The Compensation Committee also approves the compensation of each of our other executive officers and recommends the compensation of our Board of Directors, with input from WEC’s Corporate Governance Committee, for approval by the Board. In addition, the Compensation Committee administers our long-term incentive compensation programs, including the WEC 1993 Omnibus Stock Incentive Plan, as amended, and the WEC Performance Unit Plan, as amended, which are discussed further below.

The Compensation Committee is comprised solely of directors who are “independent directors” under WEC’s corporate governance guidelines (which are also applicable to the Company) and the rules of the New York Stock Exchange. No member of the Compensation Committee is a current or former employee of WEC or its subsidiaries, including the Company.

Elements of the Executive Compensation Program.The principal goal of the Compensation Committee is to provide an executive compensation program that is competitive with programs of comparable employers, aligns management’s incentives with the short-term and long-term interests of WEC’s stockholders and encourages the retention of top performers. To achieve this goal, we compensate executives through a mix of compensation elements that includes:

• annual base salary;

• annual cash incentive compensation (based principally on WEC earnings and cash flow performance);

• long-term incentive compensation through a mix of: (1) WEC stock options; (2) WEC performance units; and (3) dividends on the performance units;

• retirement programs; and

• other employee benefit programs, including a limited number of executive perquisites.

In addition, under our compensation program, each executive officer is entitled to severance compensation if his or her employment is terminated in connection with a change in control of WEC.

With respect to each of these elements, we analyze market data provided by Towers Perrin, a compensation consulting firm retained by management, to determine the appropriate levels of compensation for each named executive officer. A more detailed discussion of each of these elements and the extent to which we analyze market data in establishing each individual element is set forth below. Other than comparing each element of compensation with the appropriate market data and as otherwise described in this Compensation Discussion and Analysis, we do not have any formal policy with respect to the allocation of cash versus non-cash compensation or short-term versus long-term incentive compensation.

Competitive Data.As a general matter, we believe the labor market for WEC executive officers is consistent with that of general industry. Although we recognize WEC’s business is focused on the energy services industry, our goal is to have an executive compensation program that will allow us to be competitive in recruiting the most qualified candidates to serve as executive officers of the Company, including individuals who may be employed outside of the energy services industry. Further, in order to retain top performing executive officers, we believe our compensation practices must be competitive with those of general industry.

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In order to confirm that our annual executive compensation is competitive with the market, we consider the market data obtained from Towers Perrin. For 2008, Towers Perrin provided us with compensation data from its 2008 Executive Compensation Data Bank, which contains information obtained from approximately 416 companies of varying sizes in a wide range of businesses throughout general industry, including information from approximately 104 companies within the “energy services” industry (i.e., companies with regulated and/or unregulated utility operations and independent power producers).

For Messrs. Klappa, Leverett and Fleming, the term “market median” means the median level for an executive officer serving in a comparable position in a comparably sized company to WEC (revenues of $3 billion to $6 billion) in general industry based on our analysis of the Towers Perrin survey data. With respect to Mr. Kuester, given the nature of his position as principal executive officer of WEC’s electric utility generation operations, we consider the average of (1) the median level for an individual serving as the top generation officer of a company comparable in size to We Energies (revenues of $3 billion to $6 billion) in the energy services industry and (2) the median level for the chief executive officer in general industry in a business comparable in size to the generation operations of WEC. With respect to Ms. Rappé, given the scope of her responsibilities as Chief Administrative Officer of WEC and the Company, we consider the average of (1) the median level for an individual serving as the top administrative officer of a company comparable in size to We Energies in the energy services industry and (2) the median level for the top administrative officer in general industry in a business comparable in size to WEC.

Annual Base Salary.The annual base salary component of our executive compensation program provides each executive officer with a fixed level of annual cash compensation. We believe that providing annual cash compensation through a base salary is an established market practice and is a necessary component of a competitive overall executive compensation program.

In determining the annual base salaries to be paid to our named executive officers, we generally target base salaries to be within 10% of the market median for each named executive officer. However, the Compensation Committee may, in its discretion, adjust base salaries outside of this 10% band when the Committee deems it appropriate. Actual salary determinations in 2008 were made taking into consideration factors such as the relative levels of individual experience, performance, responsibility and contribution to the results of both WEC’s and the Company’s operations.

With respect to Mr. Klappa, based on the factors described above and the results of the Board’s annual CEO evaluation, the Compensation Committee approved an annual base salary of $1,129,008 for 2008, which represented an increase of approximately 5.0% from 2007. This resulted in an annual base salary that was nominally above our target range. The Compensation Committee determined that this was appropriate, recognizing Mr. Klappa’s demonstrated leadership abilities, WEC’s and the Company’s results in 2007 and WEC’s and the Company’s continued achievement of record financial and operational performance.

With respect to each other named executive officer, Mr. Klappa recommended an annual base salary to the Compensation Committee based on a review of market compensation data and the factors described above. The Compensation Committee approved Mr. Klappa’s recommendations, which represented an increase in base salary of approximately (i) 5.5% for Messrs. Leverett and Kuester, (ii) 5.0% for Mr. Fleming and (iii) 4.5% for Ms. Rappé over 2007 levels. Mr. Klappa based his recommendations on their pay relative to the comparative data provided by Towers Perrin and each individual’s contributions to the overall results of WEC and the Company. The annual base salaries of Messrs. Kuester and Fleming, and Ms. Rappé, were within 10% of the appropriate market median. The annual base salary for Mr. Leverett was above the target range. We believe that Mr. Leverett’s responsibilities and contributions vary widely from those of his counterparts within general industry, and thus, additional compensation is warranted. In recognition of his significant responsibilities and contributions to the strategic direction of WEC and the Company beyond those of a typical principal financial officer, the Compensation Committee approved a higher level of base salary for Mr. Leverett.

In light of the economic conditions in our service territories, the Compensation Committee agreed with Mr. Klappa’s recommendation to freeze 2009 salaries at 2008 levels for all officers, including the named executive officers, of WEC and its subsidiaries, including the Company.

Annual Cash Incentive Compensation.We provide annual cash incentive compensation through WEC’s Short-Term Performance Plan (STPP). The STPP provides for annual cash awards to named executive officers based upon the achievement of pre-established WEC 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. Payments under the STPP are intended to reward achievement of short-term goals that contribute to WEC stockholder value, as well as individual contributions to successful operations.

2008 Target Awards.Each year, the Compensation Committee approves a target level of compensation under the STPP for each of our named executive officers. This target level of compensation is expressed as a percentage of base salary. Each of Messrs. Klappa, Leverett and Kuester, and Ms. Rappé, has an employment agreement with WEC that specifies a minimum target level of compensation under the STPP based on a percentage of such executive officer’s annual base salary. Under the terms of these employment agreements, the target award may not be adjusted below these minimum levels unless the WEC Board of Directors or Compensation Committee takes action resulting in the lowering of target awards for the entire senior executive group. Mr. Fleming’s

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employment agreement provides for a target level of compensation under the STPP equal to 70% of his annual base salary. The target levels contained in the employment agreements were negotiated and, we believe, consistent with market practice at the time the agreements were entered into. Based upon our annual review of these target levels in 2008, we determined that they continue to be supported by market data.

For 2008, the Compensation Committee approved the following target awards under the STPP for each named executive officer, which are the same as those set forth in their employment agreements:

Executive Officer	Target STPP Award as a Percentage of Base Salary
Mr. Klappa	100%
Mr. Leverett	80%
Mr. Kuester	80%
Mr. Fleming	70%
Ms. Rappé	60%

For 2008, the possible payout for any named executive officer ranged from 0% of the target award to 210% of the target award, based on WEC’s performance.

2008 Performance Goals.The Compensation Committee adopted the 2008 STPP with a continued principal focus on financial results. In December 2007, the Compensation Committee approved the two primary performance measures to be used in 2008: (1) WEC’s earnings per share from ongoing operations (75% weight); and (2) WEC’s cash flow (25% weight). We believe these measures are key indicators of financial strength and performance and are recognized as such by the investment community. In January 2008, the Compensation Committee approved threshold level, target level, above target level and maximum payout level performance goals for each of these performance measures under the STPP. If the threshold level, target level, above target level or maximum payout level performance goal was achieved for both performance measures, officers participating in the STPP could receive 50%, 100%, 125% or 200%, respectively, of the target award.

WEC’s earnings per share from ongoing operations goals for 2008 were a threshold level goal of $2.75 per share, a target level goal of $2.81 per share, an above target level goal of $2.84 per share and a maximum payout level goal of $2.90 per share. The performance goals for WEC’s cash flow were set at a threshold level goal of ($448.2) million, a target level goal of ($430.6) million, an above target level goal of ($421.8) million and a maximum payout level goal of ($395.5) million.

The Compensation Committee established the target levels for WEC’s earnings per share based upon expected earnings growth in 2008 in the utility industry as indicated by other utilities in their published earnings guidance. For example, the target level performance goal was set to approximate the median level of expected earnings growth in the utility industry while the maximum payout level goal would only be earned if WEC’s actual earnings per share growth in 2008 exceeded the 75^th percentile of expected earnings growth in the utility industry. The Committee projected WEC’s 2008 earnings growth off of WEC’s year-end earnings per share from continuing operations in 2007. The Committee then established WEC’s cash flow target levels to correspond to the budget necessary to achieve the same levels of earnings per share performance (i.e., the 100% WEC cash flow target corresponds to the budget necessary to achieve the 100% WEC earnings per share target).

In December 2007 and January 2008, the Compensation Committee also approved operational performance measures and targets under the annual incentive plan. Annual incentive awards could be increased or decreased by up to 10% of the target award based upon WEC’s performance in the operational areas of customer satisfaction (5% weight), supplier and workforce diversity (2.5%) and safety (2.5%). Although the Compensation Committee believes the achievement of financial performance goals are necessary, it also recognizes the importance of strong operational results to the success of WEC and the Company.

In addition to applying these financial and operational factors, the Compensation Committee retains the right to exercise discretion in adjusting awards under the STPP when it deems appropriate.

2008 Performance Under the STPP.In January 2009, the Compensation Committee reviewed WEC’s actual performance for 2008 against the financial and operational performance goals established under the STPP, subject to final audit. In 2008, WEC’s financial performance satisfied the maximum payout level goals established for both earnings per share from ongoing operations and cash flow. In 2008, WEC’s earnings per share from ongoing operations were $3.03 per share and WEC’s cash flow was ($158.9) million. WEC’s cash flow is measured by subtracting cash used in investing activities, excluding an investment in our transmission affiliate and net proceeds from asset sales, from cash provided by operations. In addition, when calculating the cash flow measure, WEC reclassified the $345.1 million of bill credits provided to our customers from the net proceeds of the sale of the Point Beach Nuclear Plant from cash used in investing activities to cash provided by operations. Although generally accepted accounting principles require WEC to

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record the bill credits as an investment activity because WEC is collecting the cash from restricted accounts and not our customers, WEC considers this as a source of revenue. This reclassification strictly reflects how WEC and the Company view the bill credits and did not have any impact on the cash flow measure. WEC’s cash flow measure is not a measure of financial performance under generally accepted accounting principles.

By satisfying the maximum payout level performance goals with respect to both WEC’s earnings per share from ongoing operations and cash flow, officers participating in the STPP, including the named executive officers, earned 200% of the target award from the financial goal component of the STPP.

With respect to operational goals in 2008, the performance at WEC and its subsidiaries, including the Company, generated an additional 6.25% based on achievement in customer satisfaction and supplier diversity. In 2008, performance exceeded targeted levels with respect to both measures. The Compensation Committee measured customer satisfaction levels based on the results of surveys that an independent third party conducted of customers who had direct contact with WEC and its subsidiaries, including the Company, during the year, which measured (1) customers’ satisfaction with WEC and its subsidiaries in general and (2) customers’ satisfaction with respect to their particular interactions with WEC and its subsidiaries. With respect to safety measures, although WEC and its subsidiaries exceeded the target level for lost-time injuries, they did not meet the target level for Occupational Safety and Health Administration (OSHA) recordable injuries, resulting in a neutral impact on the STPP award. WEC also achieved target level performance with respect to workforce diversity, which did not result in a further increase in the STPP award for 2008.

Based on performance against the financial and operational goals established by the Compensation Committee, Mr. Klappa received annual incentive cash compensation under the STPP of $2,328,579 for 2008. This represented 206.25% of his annual base salary. Messrs. Leverett, Kuester and Fleming, and Ms. Rappé, received annual cash incentive compensation for 2008 under the STPP equal to 165%, 165%, 144.4% and 123.8% of their respective annual base salaries, representing 206.25% of the target award for each officer.

In view of the discretionary component of the annual cash incentive plan, the Compensation Committee also considered other significant accomplishments of WEC and its subsidiaries, including the Company, in 2008. These included:

• Strong financial performance

• Record WEC earnings from continuing operations of $3.03 per share.

• Cash from WEC’s operations was at an all-time high.

• A 25% increase in WEC’s dividend effective with the first quarter payment in 2009.

• WEC’s debt to total capital ratio of 55.4% at year-end 2008, attributing 50% common equity treatment to WEC’s 2007 Series A Junior Subordinated Notes, which WEC believes is consistent with the treatment given by the majority of rating agencies. The year-end debt to total capital ratio was significantly better than WEC’s target of 60.0%.

• WEC common stock performance for 2008 ranked in the top 20% of all stocks listed in the United States and in the top 15% of major American utilities.

• Operational excellence

• Continued progress in WEC’sPower the Future strategic plan; WEC added more megawatts of new generating capacity than any other year in its history.

• Continued improvements in customer satisfaction based on customer surveys. Data from 2008 indicated that WEC performed in the top quartile of the industry.

• Best employee safety record in WEC’s history in 2008, with a 39% reduction in lost-time accidents and a 16% reduction in OSHA recordable injuries.

• Best outage restoration times since WEC began keeping records.

• Continued leadership and excellence in corporate governance as evidenced by continued receipt by WEC during 2008 of a rating of “10,” the highest possible score, from GovernanceMetrics International (only one of four companies worldwide to consistently earn this distinction).

• WEC named one of America’s 15 best corporate citizens by Corporate Responsibility Officer magazine.

• Completed 2008 with our retail electric rates ranking approximately 8% below the national average.

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In view of the financial and operational accomplishments and the accomplishments listed above, the Compensation Committee determined that the awards under the STPP were appropriate in relation to WEC’s and the Company’s 2008 performance without any further adjustment.

Long-Term Incentive Compensation.The Compensation Committee administers WEC’s 1993 Omnibus Stock Incentive Plan which is a WEC stockholder approved, long-term incentive plan designed to link the interests of executives and other key employees of WEC and its subsidiaries, including the Company, to creating long-term stockholder value. It allows for various types of awards tied to the performance of WEC common stock, including stock options, stock appreciation rights, restricted stock and performance shares. In 2005, the Compensation Committee approved the Wisconsin Energy Corporation Performance Unit Plan, under which the Compensation Committee may award WEC performance units. The Compensation Committee primarily uses (1) WEC stock options and (2) WEC performance units to deliver long-term incentive opportunities.

Each year, the Compensation Committee makes annual stock option grants as part of our long-term incentive program. These stock options have an exercise price equal to the fair market value of WEC common stock on the date of grant and expire on the 10^th anniversary of the grant date. Since management benefits from a stock option award only to the extent WEC’s stock price appreciates above the exercise price of the stock option, stock options align the interests of management with those of WEC’s stockholders in attaining long-term stock price appreciation.

The Compensation Committee also makes annual grants of “performance units” under WEC’s Performance Unit Plan. The WEC performance units are designed to provide a form of long-term incentive compensation that also aligns the interests of management with those of a typical utility stockholder who is focused not only on stock price appreciation but also on receiving dividend payments. Under the terms of the performance units, payouts are based on WEC’s level of “total stockholder return” (stock price appreciation plus dividends) in comparison to a peer group of companies over a three-year performance period. In addition, each holder of performance units receives 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 holder at the target 100% rate multiplied by the amount of the dividend paid on a share of WEC’s common stock. The performance units are settled in cash.

Aggregate 2008 Long-Term Incentive Awards.In establishing the target value of long-term incentive awards for each named executive officer in 2008, we analyzed the market compensation data included in the Towers Perrin survey. For Messrs. Klappa and Fleming, and Ms. Rappé, we determined the ratio of (1) the market median value of long-term incentive compensation to (2) the market median level of annual base salary, and multiplied each annual base salary by the applicable market ratio to determine the value of long-term incentive awards to be granted. For Messrs. Leverett and Kuester, we used the average of the results obtained for each to develop a uniform target level of long-term incentive compensation that applied to each officer. We used this method to establish the amount of long-term incentive awards granted to Messrs. Leverett and Kuester as we wanted to establish parity in long-term incentive opportunity between the heads of the financial and key operational areas of WEC and the Company because of the critical role each plays in executing WEC’s and the Company’s long-term strategy. This target value of long-term incentive compensation for each named executive officer was presented to and approved by the Compensation Committee.

In 2008, the Compensation Committee approved a WEC stock option grant designed to represent approximately two-thirds of the value of the long-term incentive award and a WEC performance unit grant designed to represent approximately one-third of the value of the long-term incentive award. As the market continues to decrease the emphasis on stock options as reflected in the Towers Perrin data, we have increased the size of the performance unit award as a component of our long-term incentive plan and decreased the relative size of the stock option award. For 2009, the Compensation Committee made approximately 72% of the long-term incentive award WEC performance units and approximately 28% WEC stock options. Although the market data provided by Towers Perrin indicates that long-term incentive awards are approximately 60% performance awards and 40% stock options, because of the significant decrease in the Black-Scholes value of WEC’s stock options due to market events that occurred in 2008, WEC would have needed to issue more stock options to meet the 40% level of the long-term incentive award than the Compensation Committee thought was prudent. Therefore, for 2009, the Committee decided to further increase the number of performance awards and decrease the number of stock options granted.

2008 Stock Option Grants.In December 2007, the Compensation Committee approved the grant of WEC stock options to each of our named executive officers and established an overall pool of options that were granted to approximately 135 other employees. These option grants were made effective January 2, 2008, the first trading day of 2008. The options were granted with an exercise price equal to the average of the high and low prices reported on the New York Stock Exchange for shares of WEC common stock on the January 2, 2008 grant date. The options were granted in accordance with our standard practice of making annual stock option grants in January of each year, and the timing of the grants was not tied to the timing of any release of material non-public information. These stock options have a term of 10 years and vest 100% on the third anniversary of the date of grant. The vesting of the WEC stock options may be accelerated in connection with a change in control of WEC or an executive officer’s termination of employment. See “Potential Payments upon Termination or Change in Control” under “Executive Officers’ Compensation” for additional information.

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For purposes of determining the appropriate number of options to grant to a particular named executive officer, the value of an option was determined based on the Black-Scholes option pricing model. We use the Black-Scholes option pricing model for purposes of the compensation valuation primarily because the market information we review from Towers Perrin calculates the value of option awards on this basis. The following table provides the number of WEC stock options granted to each named executive officer.

Executive Officer	Options Granted
Mr. Klappa	300,000
Mr. Leverett	164,250
Mr. Kuester	164,250
Mr. Fleming	61,500
Ms. Rappé	50,200

For financial reporting purposes under SFAS 123R, the WEC stock options granted in 2008 had a grant date fair value of $10.48 per option for Messrs. Klappa, Leverett and Kuester, and Ms. Rappé, and a grant date fair value of $8.29 for Mr. Fleming. Mr. Fleming is considered to be “retirement eligible.” Therefore, his options are presumed to have a shorter expected life than the other named executive officers, which results in a lower option value.

2008 Performance Units.In 2008, the Compensation Committee granted WEC performance units to each of our named executive officers and approved a pool of WEC performance units that were granted to approximately 135 other employees. With respect to the 2008 WEC performance units, the amount of the benefit that ultimately vests will be dependent upon WEC’s total stockholder return over a three-year period ending December 31, 2010, as compared to the total stockholder return of a custom peer group of companies described below. Total stockholder return is the calculation of total WEC 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.

Upon vesting, the WEC performance units will be settled in cash in an amount determined by multiplying the number of performance units that have vested by the closing price of WEC’s common stock on the last trading day of the performance period.

The peer group used for purposes of the performance units is comprised of: Allegheny Energy, Inc.; Alliant Energy Corporation; Ameren Corporation; American Electric Power Company, Inc.; Avista Corporation; Consolidated Edison, Inc.; DTE Energy Company; Duke Energy Corp.; FirstEnergy Corp.; Great Plains Energy; Integrys Energy Group, Inc.; NiSource Inc.; Northeast Utilities; Nstar; OGE Energy Corp.; Pinnacle West Capital Corporation; Pepco Holdings, Inc.; PG&E Corporation; Portland General; Progress Energy Inc.; SCANA Corporation; Sempra Energy; Sierra Pacific Resources (n/k/a NV Energy, Inc.); The Southern Company; Westar Energy, Inc.; Wisconsin Energy Corporation; and Xcel Energy Inc. This peer group was chosen because we believe these companies are similar to WEC in terms of business model and long-term strategies.

The required performance percentile rank and the applicable vesting percentage are set forth in the chart below.

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

If WEC’s rank is between the benchmarks identified above, the vesting percentage will be determined by interpolating the appropriate vesting percentage. Unvested performance units generally are immediately forfeited upon a named executive officer’s cessation of employment with WEC prior to completion of the three-year performance period. However, the performance units will vest immediately at the target 100% rate upon (1) the termination of the named executive officer’s employment by reason of disability or death or (2) a change in control of WEC while the named executive officer is employed by WEC or its subsidiaries, including 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.

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For purposes of determining the appropriate number of performance units to grant to a particular named executive officer, the value of a unit was determined based on an assumed approximate value of $47.88 per unit. The assumed approximate value was based on trading prices for WEC’s common stock on October 31, 2007 as we were analyzing target compensation levels for 2008 during October and November 2007. The following table provides the number of units granted to each named executive officer at the 100% target level.

Executive Officer	Performance Units Granted
Mr. Klappa	30,000
Mr. Leverett	15,850
Mr. Kuester	15,850
Mr. Fleming	6,100
Ms. Rappé	4,850

For financial reporting purposes under SFAS 123R, the WEC performance units granted to the above named executive officers in 2008 had a grant date fair value of $47.80 per unit.

2008 Payouts Under Previously Granted Long-Term Incentive Awards.In 2006, the Compensation Committee granted WEC performance unit awards to participants in the plan, including the named executive officers. The terms of the WEC performance units granted in 2006 were substantially similar to those of the WEC performance units granted in 2008 described above. The required performance percentile ranks and related vesting schedule were identical to that of the 2008 units described above.

Payouts under the 2006 WEC performance units were based on WEC’s total stockholder return for the three-year performance period ended December 31, 2008 against substantially the same group of peer companies used for the 2008 WEC performance unit awards, except that the peer group of companies for the 2006 award (i) included Entergy Corporation, Exelon Corporation, FPL Group, Inc., Public Service Enterprise Group Incorporated and Puget Energy, Inc., and (ii) excluded Great Plains Energy, PG&E Corporation and Portland General. Energy East Corporation, which was originally part of the 2006 peer group, was purchased by a foreign utility holding company and is no longer a public company. Therefore, we are unable to measure its total stockholder return. In October 2007, Puget Energy announced that it was entering into a merger agreement. There was a subsequent increase in its stock price related to this announcement, which we believe was not the result of ongoing operating performance. Puget Energy’s common stock performance continues to reflect this extraordinary event. Therefore, the Compensation Committee modified the peer group established for the 2006 WEC performance unit grant to exclude Puget Energy. The Compensation Committee believes WEC’s total stockholder return should be compared to the total stockholder return of companies whose results are based on operating performance and not extraordinary events. Therefore, the Committee excluded Puget Energy even though such exclusion caused the payout under the 2006 WEC performance unit grant to increase.

For the three-year performance period ended December 31, 2008, WEC’s total stockholder return was at approximately the 85^th percentile of the peer group (excluding Puget Energy), resulting in the performance units vesting at a level of 159.0%. If Puget Energy were included in the calculation, WEC’s total stockholder return would have been at approximately the 82^nd percentile of the peer group, which would have resulted in the performance units vesting at a level of 148.8%. The actual payouts were determined by multiplying the number of vested performance units by the closing price of WEC’s common stock ($41.98) on December 31, 2008, the last trading day of the performance period. The actual payout to each named executive officer is reflected in the “Option Exercises and Stock Vested for Fiscal Year 2008” table below. This table also reflects amounts realized by any named executive officer in connection with the exercise in 2008 of any vested WEC stock options and the amounts realized by any named executive officer in connection with the vesting of previously granted WEC restricted stock. For information on other outstanding equity awards held by our named executive officers at December 31, 2008, please refer to the table entitled “Outstanding Equity Awards at Fiscal Year-End 2008” below.

Stock Ownership Guidelines.The Compensation Committee believes that an important adjunct to the long-term incentive program is significant stock ownership by officers who participate in the program, including the named executive officers. Accordingly, the Compensation Committee has implemented WEC stock ownership guidelines for officers of WEC and the Company. These guidelines provide that each executive officer should, over time (generally within five years of appointment as an executive officer), acquire and hold WEC common stock having a minimum fair market value ranging from 150% to 300% of base salary. In addition to certificated shares, holdings of each of the following are included in determining compliance with stock ownership guidelines: WEC restricted stock; WEC phantom stock units held in the Executive Deferred Compensation Plan; WEC stock held in the 401(k) plan; WEC performance units at target; vested WEC stock options; WEC shares held in WEC’s dividend reinvestment plan; and WEC shares held by a brokerage account, jointly with an immediate family member or in a trust.

Policy Regarding Hedging the Economic Risk of Stock Ownership. Certain forms of hedging or monetization transactions, such as zero-cost collars and forward sale contracts, allow a director, officer or employee to lock in much of the value of his or her stock

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holdings, often in exchange for all or part of the potential for upside appreciation in the stock. These transactions allow the director, officer or employee to continue to own the covered securities, but without the full risks and rewards of ownership. When that occurs, the director, officer or employee may no longer have the same objectives as WEC’s other stockholders. Therefore, we have a policy under which directors, officers and employees are prohibited from engaging in any such transactions.

Analysis of Aggregate Salary, Annual Incentive and Long-Term Incentive Compensation.The discussion above describes the manner in which we determined the (1) annual base salary, (2) target level annual cash incentive compensation and (3) long-term incentive compensation awards for each named executive officer. As we developed preliminary target compensation levels for each of these elements of total compensation, we compared the aggregate amount of these elements to the market compensation data. The purpose of this review was to confirm that the aggregate targeted compensation did not deviate significantly from market medians.

Retirement Programs. WEC also maintains four different retirement plans in which our named executive officers participate: a defined benefit pension plan of the cash balance type, two supplemental executive retirement plans and individual letter agreements with each of the named executive officers. We believe WEC’s retirement plans are a valuable benefit in the attraction and retention of our employees, including our executive officers. We believe that providing a foundation for long-term financial security for our employees, beyond their employment with the Company, is a valuable component of our overall compensation program which will inspire increased loyalty and improved performance. For more information about our retirement plans, see “Pension Benefits at Fiscal Year-End 2008” and “Retirement Plans” later in this information statement.

Other Benefits, Including Perquisites. The Company provides its executive officers with employee benefits and a limited number of perquisites. Except as specifically noted elsewhere in this information statement, the employee benefits programs in which executive officers participate (which provide benefits such as medical benefits coverage, 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 made available to executive officers include the availability of financial planning, limited spousal travel, membership in a service that provides healthcare and safety management when traveling outside the United States and payment of the cost of a mandatory physical exam that the Board requires annually. The Company also pays periodic dues and fees for certain club memberships for the named executive officers and other designated officers. In addition, executive officers receive tax gross-ups to reimburse the officer for certain tax liabilities. For a more detailed discussion of perquisites made available to our named executive officers, please refer to the notes following the Summary Compensation Table below.

We periodically review market data regarding executive perquisite practices. We reviewed a survey conducted by The Ayco Company, L.P., a financial services firm (“AYCO”), in 2007 of 272 companies throughout general industry. Based upon this review, we believe that the perquisites we provide to our executive officers are generally market competitive. AYCO only conducts this survey bi-annually, so the 2007 survey was the most recent information available. We reimburse executives for taxes paid on income attributable to the financial planning benefits provided to our executives only if the executive uses the Company’s identified preferred provider, AYCO. We believe the use of our preferred financial adviser provides administrative benefits and eases communication between Company personnel and the financial adviser. We pay periodic dues and fees for certain club memberships as we have found that the use of these facilities helps foster better customer relationships. Officers, including the named executive officers, are expected to use clubs for which the Company pays dues primarily for business purposes. We do not pay any additional expenses incurred for personal use of these facilities, and officers are required to reimburse the Company to the extent it pays for any such personal use. The total annual club dues are included in the Summary Compensation Table. We do not permit personal use of the airplane in which WEC owns a partial interest. We do allow spousal travel if an executive’s spouse is accompanying the executive on business travel and the airplane is not fully utilized by WEC personnel. There is no incremental cost to WEC or the Company for this travel, other than the reimbursement for taxes paid on imputed income attributable to the executives for this perquisite, as the airplane cost is the same regardless of whether an executive’s spouse travels.

In addition, each of our executive officers participates in a death benefit only plan. Under the terms of the plan, upon an executive 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 us at the time of death or the after-tax value of one times final base salary if death occurs post-retirement.

Severance Benefits and Change in Control.Competitive practices dictate that companies should provide reasonable severance benefits to employees. In addition, we believe it is important to provide protections to our executive officers in connection with a change in control of WEC. Our belief is that the interests of WEC’s stockholders will be best served if the interests of our executive officers are aligned with them, and providing change in control benefits should eliminate, or at least reduce, the reluctance of management to pursue potential change in control transactions that may be in the best interests of WEC’s stockholders.

Each of Messrs. Klappa, Leverett, Kuester and Fleming, and Ms. Rappé, has an employment agreement with WEC, which includes change in control and severance provisions. Under the terms of these agreements, the applicable named executive officer is entitled to certain benefits in the event of a termination of employment. In the event of a termination of employment (1) by WEC for any reason

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other than cause, death or disability in anticipation of or following a change in control of WEC, (2) by the applicable executive officer for good reason in connection with or in anticipation of a change in control of WEC or (3) by the applicable executive officer after completing one year of service following a change in control of WEC, each named executive officer is generally entitled to:

• A lump sum payment equal to three times: (1) the highest annual base salary in effect during the last three years and (2) the higher of the current year target bonus amount or the highest bonus paid in any of the last three years (except for Ms. Rappé, whose payment is based upon the current year target bonus amount);

• A lump sum payment assuming three years of additional credited service under the qualified and non-qualified retirement plans based upon the higher of (1) the annual base salary in effect at the time of termination and (2) any salary in effect during the 180 day period preceding the termination date, plus the highest bonus amount (except for Ms. Rappé, whose payment is based upon the current year target bonus amount);

• A lump sum payment equal to the value of three additional years of WEC match in the 401(k) plan and the WEC Executive Deferred Compensation Plan;

• Continuation of health and certain other welfare benefit coverage for three years following termination of employment;

• Full vesting of WEC stock options, WEC restricted stock and WEC performance units;

• Financial planning services and other benefits; and

• A gross-up payment should any payments trigger federal excise taxes.

In the absence of a change in control, if WEC terminates the employment of the applicable executive officer for any reason other than cause, death or disability, or the applicable executive officer terminates his or her employment for good reason, the payments to the applicable named executive officer will be the same as those described above, except that with respect to Messrs. Leverett, Kuester and Fleming, and Ms. Rappé, (1) the multiple for the lump sum payment in the first bullet point will be reduced to two, (2) the number of additional years of credited service for qualified and non-qualified retirement plans will be two, (3) the number of additional years of matching in the 401(k) plan and the WEC Executive Deferred Compensation Plan will be two, and (4) health and certain other welfare benefits will continue for two years following termination of employment.

We believe the amounts payable under these agreements are consistent with market standards as confirmed by our periodic analysis of data provided by Towers Perrin. The amounts payable under these arrangements were last reviewed by the Compensation Committee in 2008 and compared to market data provided by Towers Perrin in 2007.

In addition, our supplemental pension plan provides that in the event of a change in control of WEC, each named executive officer will be entitled to a lump sum payment of amounts due under the plan if employment is terminated within 18 months of the change in control.

For a more detailed discussion of the benefits and tables that describe payouts under various termination scenarios, see “Potential Payments upon Termination or Change in Control” later in this information statement.

Impact of Prior Compensation.The Compensation Committee did not consider the amounts realized or realizable from prior incentive compensation awards in establishing the levels of short-term and long-term incentive compensation for 2008.

Section 162(m) of the Internal Revenue Code.Section 162(m) of the Internal Revenue Code limits the deductibility of certain executives’ compensation that exceeds $1 million per year, unless the compensation is performance-based under Section 162(m) and is issued through a plan that has been approved by stockholders. Although the Compensation Committee takes into consideration the provisions of Section 162(m), maintaining tax deductibility is but one consideration among many in the design of our executive compensation program.

With respect to 2008 compensation for the named executive officers, the annual stock option grants under the 1993 Omnibus Stock Incentive Plan have been structured to qualify as performance-based compensation under Section 162(m). Annual cash incentive awards under the STPP and performance units under the WEC Performance Unit Plan do not qualify for tax deductibility under Section 162(m).

409A Amendments to Executive Arrangements.On October 29, 2008, the Compensation Committee authorized and approved amendments to certain executive compensation arrangements for our named executive officers and directors in order to bring such arrangements into documentary compliance with Section 409A of the Internal Revenue Code of 1986, as amended, and corresponding regulations (collectively, “Section 409A”). The amendments are generally technical in nature and affect the timing, but not the amount, of benefits payable to the named executive officers or directors.

As part of the actions taken by the Compensation Committee, the Wisconsin Energy Corporation Executive Deferred Compensation Plan (the “Legacy EDCP”), the Wisconsin Energy Corporation Directors’ Deferred Compensation Plan (the “Legacy DDCP”) and the Wisconsin Energy Corporation Supplemental Executive Retirement Plan (the “Legacy SERP”) were renamed and amended effective as of January 1, 2005 to (i) provide that amounts earned, deferred, vested, credited and/or accrued under such plans as of

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December 31, 2004 are preserved and frozen so that such amounts are exempt from Section 409A, and (ii) provide that no new employees (or directors for the Legacy DDCP) may participate in these plans as of January 1, 2005. The Compensation Committee also adopted new deferred compensation plans effective January 1, 2005 which offer features substantially similar to the Legacy EDCP, Legacy DDCP and Legacy SERP, but with changes necessary to comply with Section 409A.

In addition, the following plans and agreements were also amended and restated as of the dates indicated below to bring them into documentary compliance with Section 409A:

• Wisconsin Energy Corporation Short-Term Performance Plan (effective January 1, 2005);

• Amended and Restated Wisconsin Energy Corporation Executive Severance Policy (effective January 1, 2008);

• Wisconsin Energy Corporation Omnibus Stock Incentive Plan (effective January 1, 2008);

• Wisconsin Energy Corporation Performance Unit Plan (effective October 11, 2007);

• Amended and Restated Senior Officer and Non-Compete Agreement between Wisconsin Energy Corporation and Gale E. Klappa (effective January 1, 2005);

• Senior Officer Employment and Non-Compete Agreement between Wisconsin Energy Corporation and Allen L. Leverett (effective January 1, 2005);

• Senior Officer Employment and Non-Compete Agreement between Wisconsin Energy Corporation and Frederick D. Kuester (effective January 1, 2005);

• Letter Agreement by and between Wisconsin Energy Corporation and James C. Fleming (effective November 23, 2005); and

• Amended and Restated Senior Officer, Change in Control, Severance and Non-Compete Agreement between Wisconsin Energy Corporation and Kristine A. Rappé (effective January 1, 2008).

COMPENSATION COMMITTEE REPORT

The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management and, based on such review and discussions, the Compensation Committee recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this information statement.

The Compensation Committee

John F. Bergstrom, Committee Chair

Ulice Payne, Jr.

Frederick P. Stratton, Jr.

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EXECUTIVE OFFICERS’ COMPENSATION

The following table summarizes total compensation awarded to, earned by or paid to the Company’s Chief Executive Officer, Chief Financial Officer and each of the Company’s other three most highly compensated executive officers (the “named executive officers”) during 2008, 2007 and 2006. The amounts shown in this and all subsequent tables in this information statement are WEC consolidated compensation data.

Summary Compensation Table

(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)		(i)	(j)
Name and Principal Position	Year	Salary ($)	Bonus ($)	Stock Awards (2) ($)	Option Awards (2) ($)	Non-Equity Incentive Plan Compensation (3) ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings (4) ($)		All Other Compensation (11) (12) ($)	Total ($)
Gale E. Klappa
Chairman of the Board, President and Chief Executive Officer of WEC, WE and WG	2008	1,129,008	—	2,310,259	2,517,800	2,328,579	1,328,616	(5)	261,040	9,875,302
	2007	1,075,356	—	1,338,713	2,246,334	2,177,596	4,700,118	(5)	223,749	11,761,866
	2006	1,005,000	—	1,392,112	1,422,493	2,060,250	1,838,928	(5)	209,828	7,928,611
Allen L. Leverett
Executive Vice President and Chief Financial Officer of WEC, WE and WG	2008	607,680	—	1,082,379	1,209,456	1,002,672	88,151	(6)	101,049	4,091,387
	2007	576,000	—	610,603	913,011	933,120	197,018	(6)	84,733	3,314,485
	2006	538,200	—	767,686	520,850	882,648	—	(7)	79,542	2,788,926
Frederick D. Kuester
Executive Vice President of WEC and WG; Executive Vice President and Chief Operating Officer of WE	2008	657,000	—	1,101,916	1,209,456	1,084,050	927,165	(8)	136,983	5,116,570
	2007	622,752	—	630,140	913,011	1,008,859	2,650,828	(8)	110,334	5,935,924
	2006	582,000	—	787,223	520,850	954,480	689,533	(8)	116,210	3,650,296
James C. Fleming
Executive Vice President and General Counsel of WEC, WE and WG	2008	441,000	—	551,615	889,045	636,694	219,296	(9)	76,298	2,813,948
	2007	420,000	—	250,780	379,210	595,350	177,938	(9)	66,315	1,889,593
	2006	400,008	150,000	145,153	192,250	574,012	147,488	(9)	271,484	1,880,395
Kristine A. Rappé (1)
Senior Vice President and Chief Administrative Officer of WEC, WE and WG	2008	393,708	—	432,725	471,479	487,214	252,329	(10)	119,066	2,156,521
	2007	376,752	—	288,896	476,379	457,753	438,017	(10)	61,188	2,098,985

⁽¹⁾ Ms. Rappé became a named executive officer in 2007 and, therefore, no information has been provided for 2006.

⁽²⁾ For 2008, the amounts reported reflect the amounts recognized for financial statement reporting purposes during 2008 in WEC’s 2008 consolidated financial statements in accordance with SFAS 123R for WEC stock option awards and WEC performance unit awards made in 2006, 2007 and 2008 and various WEC restricted stock grants that have not yet vested. For 2007, the amounts reported reflect the amounts recognized for financial statement reporting purposes during 2007 in WEC’s 2007 consolidated financial statements in accordance with SFAS 123R for WEC stock option awards and WEC performance unit awards made in 2005, 2006 and 2007 and various WEC restricted stock grants that had not yet vested. For 2006, the amounts reported reflect the amounts recognized for financial statement reporting purposes during 2006 in WEC’s 2006 consolidated financial statements in accordance with SFAS 123R for WEC stock option awards and WEC performance unit awards made in 2005 and 2006, WEC performance share awards made in 2004 and various WEC restricted stock grants that had not yet vested. The expenses related to WEC performance units/shares and restricted stock are reflected in column (e) above, and the expenses related to WEC stock options are reflected in column (f) above. The actual value received by the executives from these awards may range from $0 to greater than the reported amounts recognized for financial statement reporting purposes, depending upon WEC performance and the executive’s number of additional years of service with WEC or its subsidiaries. In accordance with Item 402 of Regulation S-K, the amounts reported in the table above do not reflect the amount of estimated forfeitures related to service-based vesting conditions used for financial reporting purposes. In accordance with SFAS 123R, certain assumptions in the valuation of the WEC stock options, performance units/shares and restricted stock for financial reporting purposes. See “Stock Options” in Note A — Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements in our 2008, 2007 and 2006 Annual Reports on Form 10-K, Note H — Common Equity in the Notes to Consolidated Financial Statements in our 2008

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Form 10-K and Note N — Common Equity in the Notes to Consolidated Financial Statements in our 2007 and 2006 Form 10-Ks for a description of these assumptions. For 2008, the assumptions made in connection with the valuation of WEC stock options are the same as described in Note A in our 2008 Annual Report, except that the expected life of the options is 4.8 years for Mr. Fleming and 7.3 years for the rest of the named executive officers and the expected forfeiture rate is 0%. The change in the expected life of the options to 4.8 years for Mr. Fleming and 7.3 years for the rest of the named executive officers from 6.7 years, as set forth in Note A, resulted from the fact that Mr. Fleming was “retirement eligible” as of December 31, 2008, and none of the other named executive officers were, whereas the assumption described in Note A is a weighted average of all option holders. The change in the expected forfeiture rate to 0% from 2.0%, as set forth in Note A, is due to the assumption that the named executive officers will not forfeit any of their stock options.

For 2007, the assumptions made in connection with the valuation of WEC stock options are the same as described in Note A in our 2008 Annual Report, except that the expected life of the options is 6.5 years for the named executive officers. The change in the expected life of the options to 6.5 years for the named executive officers from 6.0 years, as set forth in Note A, resulted from the fact that none of the named executive officers were “retirement eligible” as of December 31, 2007, while the assumption described in Note A is a weighted average of all option holders, some of who were “retirement eligible.”

For 2006, the assumptions made in connection with the valuation of the WEC stock options are the same as described in Note A in our 2008 Annual Report, except that the expected life of the options is 6.5 years. The change in the expected life of the options to 6.5 years from 6.3 years, as set forth in Note A, resulted from the fact that none of the named executive officers were “retirement eligible” as of December 31, 2006, whereas the assumption in Note A is a weighted average of all option holders, some of who were “retirement eligible.”

The reported amounts for 2008 include expenses attributable to WEC stock options and unvested WEC stock awards granted in prior years, respectively, for each named executive officer as follows: Mr. Klappa –$1,469,800 and $1,890,459; Mr. Leverett – $635,676 and $860,585; Mr. Kuester – $635,676 and $880,122; Mr. Fleming – $379,210 and $466,256; and Ms. Rappé – $296,114 and $364,857. For additional information regarding the value of WEC option awards and WEC stock awards granted in 2008, see column (l) in “Grants of Plan-Based Awards for Fiscal Year 2008.”

The reported amounts for 2007 include expenses attributable to WEC stock options and unvested WEC stock awards granted prior to 2007, respectively, for each named executive officer as follows: Mr. Klappa –$1,422,494 and $900,323; Mr. Leverett –$520,851 and $403,585; Mr. Kuester – $520,851 and $423,122; Mr. Fleming – $192,250 and $151,736; and Ms. Rappé –$328,939 and $210,960.

The reported amounts for 2006 include expenses attributable to WEC stock options and unvested WEC stock awards granted prior to 2006, respectively, for each named executive officer as follows: Mr. Klappa –$776,533 and $923,840; Mr. Leverett –$277,333 and $565,190; Mr. Kuester – $277,333 and $584,727; and Mr. Fleming – $0 and $0. In December 2004, the Compensation Committee approved the acceleration of vesting of all unvested WEC options awarded, including those awarded to executive officers, in 2002, 2003 and 2004 in anticipation of the impact of adoption of SFAS 123R. Therefore, the amounts reported for 2006 only reflect compensation expense for two years of option awards (2005 and 2006).

⁽³⁾ Consists of amounts earned under WEC’s Short-Term Performance Plan for 2008, 2007 and 2006. See Note (2) under “Grants of Plan-Based Awards for Fiscal Year 2008” for a description of the terms of the 2008 awards.

⁽⁴⁾ The amounts reported for 2008, 2007 and 2006 reflect the aggregate change in the actuarial present value of each named executive officer’s accumulated benefit under all defined benefit plans from December 31, 2007 to December 31, 2008, December 31, 2006 to December 31, 2007 and December 31, 2005 to December 31, 2006, respectively. Our employees, including the named executive officers, are eligible to participate in WEC’s defined benefit plans. The named executive officers did not receive any above-market or preferential earnings on deferred compensation in 2008, 2007 or 2006.

⁽⁵⁾ The change in the actuarial present value of Mr. Klappa’s pension benefit does not constitute a cash payment to Mr. Klappa. WEC’s pension benefit obligations to Mr. Klappa will be offset by pension benefits Mr. Klappa is entitled to receive from a prior employer for nearly 29 years of service. The amount reported for Mr. Klappa represents only WEC’s obligation of the aggregate change in the actuarial present value of Mr. Klappa’s accumulated benefit under all defined benefit plans. Based on information received from the prior employer, we have estimated the portion of Mr. Klappa’s total accumulated pension benefit for which WEC will be responsible. If Mr. Klappa’s prior employer becomes unable to pay its portion of his accumulated pension benefit, WEC is obligated to pay the total amount.

For 2008, the total aggregate change in the actuarial present value of Mr. Klappa’s accumulated benefit was $1,347,101 - $18,485 of which we estimate the prior employer is obligated to pay.

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For 2007, the total aggregate change in the actuarial present value of Mr. Klappa’s accumulated benefit was $5,080,365 – $380,247 of which we estimate the prior employer was obligated to pay. A significant reason for the increase in Mr. Klappa’s benefit in 2007 was the result of his years of credited service going from 29.33 to 30.33. At 30 years of service, WEC’s pension plan pays an unreduced benefit for all employees who retire at or after age 62 as opposed to age 65. Therefore, beginning in 2007, Mr. Klappa’s accumulated benefit was calculated assuming he begins receiving benefits at age 62 rather than age 65. The increase in actuarial present value related to the change in the unreduced benefit date was $2,537,230.

For 2006, the total aggregate change in the actuarial present value of Mr. Klappa’s accumulated benefit was $1,970,360 – $131,432 of which we estimate the prior employer was obligated to pay.

⁽⁶⁾ The change in the actuarial present value of Mr. Leverett’s pension benefit does not constitute a cash payment to Mr. Leverett. WEC’s pension benefit obligations to Mr. Leverett will be offset by pension benefits Mr. Leverett is entitled to receive from a prior employer for approximately 15 years of service. The amount reported for Mr. Leverett represents only WEC’s obligation of the aggregate change in the actuarial present value of Mr. Leverett’s accumulated benefit under all defined benefit plans. Based on information received from the prior employer, we have estimated the portion of Mr. Leverett’s total accumulated pension benefit for which WEC will be responsible. If Mr. Leverett’s prior employer becomes unable to pay its portion of Mr. Leverett’s accumulated pension benefit, WEC is obligated to pay the total amount. For 2008, the total aggregate change in the actuarial present value of Mr. Leverett’s accumulated benefit was $75,252. However, because the change in the actuarial present value of his prior employer’s obligation decreased by ($12,899) in 2008, WEC’s obligation for the aggregate change in the actuarial present value of Mr. Leverett’s total accumulated pension benefit is actually $88,151 for 2008.

For 2007, the total aggregate change in the actuarial present value of Mr. Leverett’s accumulated benefit was $190,462. However, because the change in the actuarial present value of his prior employer’s obligation decreased by ($6,556) in 2007, WEC’s obligation for the aggregate change in the actuarial present value of Mr. Leverett’s total accumulated pension benefit was actually $197,018 for 2007.

⁽⁷⁾ A change in the assumptions used to calculate the actuarial present values under WEC’s defined benefit plans as a result of a change in the tax laws caused Mr. Leverett’s reported amount to be negative in 2006. The tax laws no longer allowed for an acceleration of nonqualified retirement benefits, and therefore WEC’s actuarial valuation began to assume a life annuity rather than a lump sum payment for the nonqualified benefits. The discount rate used to measure the actuarial present value under the nonqualified plans changed to 5.75% from 4.68%. The change affected all named executive officers, but only Mr. Leverett’s balance was small enough to result in a negative change in present value. This change in assumptions did not constitute a plan change. The aggregate change in the actuarial present value of Mr. Leverett’s accumulated benefit in 2006 under all defined benefit plans was ($109,950).

⁽⁸⁾ The change in the actuarial present value of Mr. Kuester’s pension benefit does not constitute a cash payment to Mr. Kuester. WEC’s pension benefit obligations to Mr. Kuester will be offset by pension benefits Mr. Kuester is entitled to receive from a prior employer for nearly 32 years of service. The amount reported for Mr. Kuester represents only WEC’s obligation of the aggregate change in the actuarial present value of Mr. Kuester’s accumulated benefit under all defined benefit plans. Based on information received from the prior employer, we have estimated the portion of Mr. Kuester’s total accumulated pension benefit for which WEC will be responsible. If Mr. Kuester’s prior employer becomes unable to pay its portion of Mr. Kuester’s accumulated pension benefit, WEC is obligated to pay the total amount.

For 2008, the total aggregate change in the actuarial present value of Mr. Kuester’s accumulated benefit was $958,973 – $31,808 of which we estimate the prior employer is obligated to pay.

For 2007, the total aggregate change in the actuarial present value of Mr. Kuester’s accumulated benefit was $2,865,319 – $214,491 of which we estimate the prior employer was obligated to pay. A significant reason for the increase in Mr. Kuester’s benefit in 2007 was the result of his years of credited service going from 34.33 to 35.33. At 35 years of service, the WEC pension plan pays an unreduced benefit for all employees who retire at or after age 60 as opposed to age 62. Therefore, beginning in 2007, Mr. Kuester’s accumulated benefit was calculated assuming he begins receiving benefits at age 60 rather than 62. The increase in actuarial present value related to the change in the unreduced benefit date was $1,065,601.

For 2006, the total aggregate change in the actuarial present value of Mr. Kuester’s accumulated benefit was $802,868 – $113,335 of which we estimate the prior employer was obligated to pay.

⁽⁹⁾ The change in the actuarial present value of Mr. Fleming’s pension benefit does not constitute a cash payment to Mr. Fleming. Mr. Fleming participates in WEC’s qualified pension plan and supplemental executive retirement plan. In addition, Mr. Fleming is entitled to a special supplemental pension account. The present value of the amounts credited to this account is $125,177 for 2008, $122,305 for 2007 and $126,418 for 2006, which will be paid upon termination of employment after age 65. See “Pension Benefits at Fiscal Year-End 2008” and “Retirement Plans” later in this information statement for additional details.

23

⁽¹⁰⁾ The change in the actuarial present value of Ms. Rappé’s pension benefit does not constitute a cash payment to Ms. Rappé.

⁽¹¹⁾ During 2008, each named executive received financial planning services and the cost of an annual physical exam; Messrs. Klappa, Leverett and Fleming, and Ms. Rappé, received reimbursement for club dues; and Messrs. Klappa, Leverett and Kuester were provided with membership in a service that provides healthcare and safety management when traveling outside the United States. In addition, the named executives were eligible to receive reimbursement for taxes paid on imputed income attributable to certain perquisites including spousal travel and related costs for industry events where it is customary and expected that officers attend with their spouses. Mr. Klappa was the only named executive who utilized the benefit of spousal travel and any associated tax reimbursement during 2008. These tax reimbursements are reflected separately in the Summary Compensation Table (see the third bullet point in Note 12 below). Other than the tax reimbursement, there is no incremental cost to the Company related to this spousal travel.

⁽¹²⁾ WEC maintains a Death Benefit Only Plan. Pursuant to the terms of the Plan, upon an officer’s death a benefit is paid to his or her designated beneficiary in an amount equal to the after-tax value of three times the officer’s base salary if the officer is employed at the time of death or the after-tax value of one times final base salary if death occurs post-retirement. WEC recognized expenses for the Death Benefit Only Plan as follows in 2008: Mr. Klappa ($74,547), Mr. Leverett ($15,676), Mr. Kuester ($46,644), Mr. Fleming ($12,047) and Ms. Rappé ($14,901).

For Mr. Klappa, the amount reported in All Other Compensation for 2008 includes $15,481 attributable to Wisconsin Energy’s Directors’ Charitable Awards Program in connection with Mr. Klappa’s service on the Company’s Board of Directors. See “Director Compensation” for a description of the Directors’ Charitable Awards Program.

In addition to the perquisites and amounts recognized under the Death Benefit Only Plan and Directors’ Charitable Awards Program identified above, All Other Compensation for Messrs. Klappa, Leverett, Kuester and Fleming, and Ms. Rappé, for 2008 consists of:

• Employer matching of contributions into the 401(k) plan in the amount of $9,200 for Messrs. Klappa, Kuester and Fleming, and Ms. Rappé, and $8,900 for Mr. Leverett;

• “Make-whole” payments under WEC’s Executive Deferred Compensation Plan that provides a match at the same level as the 401(k) plan (4% for up to 7% of wages) for all deferred salary and bonus not otherwise eligible for a match in the amounts of $112,476, $48,066, $57,734, $31,084 and $22,870, respectively; and

• Tax reimbursements or “gross-ups” for all applicable perquisites in the amounts of $22,178, $9,653, $5,765, $8,172 and $19,006, respectively.

Percentages of Total Compensation.

For Messrs. Klappa, Leverett, Kuester, and Fleming, and Ms. Rappé, (1) salary (as reflected in column (c) above) represented approximately 11%, 15%, 13%, 16% and 18%, respectively, of total compensation (as shown in column (j) above) for 2008, (2) annual incentive compensation (as reflected in column (g) above) represented approximately 24%, 25%, 21%, 23% and 23%, respectively, of total compensation in 2008, and (3) salary and annual incentive compensation together represented approximately 35%, 39%, 34%, 38% and 41%, respectively, of total compensation in 2008.

For Messrs. Klappa, Leverett, Kuester and Fleming, and Ms. Rappé, (1) salary (as reflected in column (c) above) represented approximately 9%, 17%, 10%, 22% and 18%, respectively, of total compensation (as shown in column (j) above) for 2007, (2) annual incentive compensation (as reflected in column (g) above) represented approximately 19%, 28%, 17%, 32% and 22%, respectively, of total compensation in 2007, and (3) salary and annual incentive compensation together represented approximately 28%, 46%, 27%, 54% and 40%, respectively, of total compensation in 2007.

For Messrs. Klappa, Leverett, Kuester and Fleming, (1) salary (as reflected in column (c) above) represented approximately 13%, 19%, 16% and 21%, respectively, of total compensation (as shown in column (j) above) for 2006, (2) annual incentive compensation (as reflected in column (g) above) represented approximately 26%, 32%, 26% and 31%, respectively, of total compensation in 2006, and (3) salary and annual incentive compensation together represented approximately 39%, 51%, 42% and 52%, respectively, of total compensation in 2006.

24

Grants of Plan-Based Awards for Fiscal Year 2008

The following table shows additional data regarding incentive plan awards to the named executive officers in 2008.

(a)	(b)		(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)		(l)
			Estimated Possible Payouts Under Non-Equity Incentive Plan Awards(2)			Estimated Future Payouts Under Equity Incentive Plan Awards(3)			All Other Stock Awards: Number of Shares of Stock or Units (#)	All Other Option Awards(4)			Grant Date Fair Value of Stock and Option Awards(7) ($)
Name	Grant Date	Action Date(1)	Threshold ($)	Target ($)	Maximum ($)	Threshold (#)	Target (#)	Maximum (#)		Number of Securities Underlying Options (#)	Exercise or Base Price(5) ($/Sh)	Closing Market Price (6) ($/Sh)
Gale E.	1/17/08	—	564,504	1,129,008	2,370,917	—	—	—	—	—	—	—	—
Klappa	1/02/08	12/6/07	—	—	—	7,500	30,000	52,500	—	—	—	—	1,434,000
	1/02/08	12/6/07	—	—	—	—	—	—	—	300,000	48.035	47.80	3,144,000
Allen L.	1/17/08	—	243,072	486,144	1,020,902	—	—	—	—	—	—	—	—
Leverett	1/02/08	12/6/07	—	—	—	3,963	15,850	27,738	—	—	—	—	757,630
	1/02/08	12/6/07	—	—	—	—	—	—	—	164,250	48.035	47.80	1,721,340
Frederick D.	1/17/08	—	262,800	525,600	1,103,760	—	—	—	—	—	—	—	—
Kuester	1/02/08	12/6/07	—	—	—	3,963	15,850	27,738	—	—	—	—	757,630
	1/02/08	12/6/07	—	—	—	—	—	—	—	164,250	48.035	47.80	1,721,340
James C.	1/17/08	—	154,350	308,700	648,270	—	—	—	—	—	—	—	—
Fleming	1/02/08	12/6/07	—	—	—	1,525	6,100	10,675	—	—	—	—	291,580
	1/02/08	12/6/07	—	—	—	—	—	—	—	61,500	48.035	47.80	509,835
Kristine A.	1/17/08	—	118,113	236,225	496,073	—	—	—	—	—	—	—	—
Rappé	1/02/08	12/6/07	—	—	—	1,213	4,850	8,488	—	—	—	—	231,830
	1/02/08	12/6/07	—	—	—	—	—	—	—	50,200	48.035	47.80	526,096

⁽¹⁾ On December 6, 2007, the Compensation Committee awarded the 2008 option and performance unit grants effective the first trading day of 2008 (January 2, 2008).

⁽²⁾ Non-equity incentive plan awards consist of awards under WEC’s Short-Term Performance Plan. The target bonus levels established for each of Messrs. Klappa, Leverett, Kuester and Fleming, and Ms. Rappé, for 2008 were 100%, 80%, 80%, 70% and 60% of base salary, respectively. Pursuant to the terms of their respective employment agreements, the target bonus levels for each of Messrs. Klappa, Leverett and Kuester, and Ms. Rappé, may not be adjusted downward except by an action of the Board or Compensation Committee which lowers the target bonus for the entire senior executive group. Based on certain financial and operational goals established by the Compensation Committee, actual payments to the named executive officers could have ranged from 0% of the target award to 210% of the target. Based on actual performance for 2008, each named executive officer earned 206.25% of the target award and these amounts are reported above in the Summary Compensation Table. For a more detailed description of WEC’s Short-Term Performance Plan, see the Compensation Discussion and Analysis above.

⁽³⁾ Consists of performance units awarded under the WEC Performance Unit Plan. Upon vesting, the WEC performance units will be settled in cash in an amount determined by multiplying the number of performance units which have become vested by the closing price of WEC’s common stock on the last trading day of the performance period. The number of WEC performance units that ultimately will vest is dependent upon WEC’s total stockholder return over a three-year period ending December 31, 2010 as compared to the total stockholder return of a Custom Peer Group consisting of 27 companies. These companies are: Allegheny Energy, Inc.; Alliant Energy Corporation; Ameren Corporation; American Electric Power Company, Inc.; Avista Corporation; Consolidated Edison, Inc.; DTE Energy Company; Duke Energy Corp.; FirstEnergy Corp.; Great Plains Energy; Integrys Energy Group, Inc.; NiSource Inc.; Northeast Utilities; Nstar; OGE Energy Corp.; Pinnacle West Capital Corporation; Pepco Holdings, Inc.; PG&E Corporation; Portland General; Progress Energy Inc.; SCANA Corporation; Sempra Energy; Sierra Pacific Resources (n/k/a NV Energy, Inc.); The Southern Company; Westar Energy, Inc.; Wisconsin Energy Corporation; and Xcel Energy Inc.

Total stockholder return is the calculation of total WEC 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:

25

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

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

The performance units will vest immediately at the target 100% rate upon (1) the termination of the named executive officer’s employment by reason of disability or death or (2) a change in control of WEC while 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 by reason of retirement prior to the end of the three-year performance period. Participants, including the 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 WEC 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 WEC common stock. The performance units have no voting rights attached to them.

⁽⁴⁾ Consists of non-qualified stock options to purchase shares of WEC common stock pursuant to WEC’s 1993 Omnibus Stock Incentive Plan. These options have exercise prices equal to the fair market value of WEC common stock 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 the occurrence of a change in control of WEC or termination of employment by reason of retirement, disability or death. The exercise price may be paid by delivery of already-owned shares. Tax withholding obligations related to exercise may be satisfied by withholding shares otherwise deliverable upon exercise, subject to certain conditions. Subject to the limitations of WEC’s 1993 Omnibus Stock Incentive Plan, the Compensation Committee has the power to amend the terms of any option (with the participant’s consent).

⁽⁵⁾ The exercise price of the option awards is equal to the fair market value of WEC’s common stock on the date of grant, January 2, 2008. 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 grant date.

⁽⁶⁾ Reflects the closing market price of WEC common stock reported in the New York Stock Exchange Composite Transaction Report on the grant date.

⁽⁷⁾ Grant date fair value of each award as determined in accordance with SFAS 123R, which includes the value of the right to receive dividends. The actual value received by the executives from these awards may range from $0 to greater than the reported amounts, depending upon WEC performance and the executive’s number of additional years of service with WEC or its subsidiaries.

26

Outstanding Equity Awards at Fiscal Year-End 2008

The following table reflects the number and value of exercisable and unexercisable WEC options as well as the number and value of other WEC stock awards held by the named executive officers at fiscal year-end 2008.

(a)	(b)	(c)	(d)	(e)	(f)	(g)		(h)	(i)		(j)
	Option Awards					Stock Awards
Name	Number of Securities Underlying Unexercised Options: Exercisable (1) (#)	Number of Securities Underlying Unexercised Options: Unexercisable (2) (#)	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)	Option Exercise Price ($)	Option Expiration Date	Number of Shares or Units of Stock that Have Not Vested (#)		Market Value of Shares or Units of Stock that Have Not Vested (3) ($)	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights that Have Not Vested (#)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights that Have Not Vested (3) ($)
Gale E.	250,000	—	—	25.310	4/14/13	—		—	—		—
Klappa	200,000	—	—	33.435	1/02/14	—		—	—		—
	280,000	—	—	34.200	1/18/15	—		—	—		—
	—	252,000	—	39.475	1/03/16	—		—	—		—
	—	271,000	—	47.755	1/03/17	—		—	—		—
	—	300,000	—	48.035	1/02/18	—		—	—		—
	—	—	—	—	—	22,236	(4)	933,467	—		—
	—	—	—	—	—	—		—	47,250	(9)	1,983,555	(9)
	—	—	—	—	—	—		—	52,500	(10)	2,203,950	(10)
Allen L.	200,000	—	—	29.130	7/01/13	—		—	—		—
Leverett	150,000	—	—	33.435	1/02/14	—		—	—		—
	100,000	—	—	34.200	1/18/15	—		—	—		—
	—	95,000	—	39.475	1/03/16	—		—	—		—
	—	129,000	—	47.755	1/03/17	—		—	—		—
	—	164,250	—	48.035	1/02/18	—		—	—		—
	—	—	—	—	—	4,346	(5)	182,445	—		—
	—	—	—	—	—	—		—	22,313	(9)	936,700	(9)
	—	—	—	—	—	—		—	27,738	(10)	1,164,441	(10)
Frederick D.	200,000	—	—	31.070	10/13/13	—		—	—		—
Kuester	150,000	—	—	33.435	1/02/14	—		—	—		—
	100,000	—	—	34.200	1/18/15	—		—	��		—
	—	95,000	—	39.475	1/03/16	—		—	—		—
	—	129,000	—	47.755	1/03/17	—		—	—		—
	—	164,250	—	48.035	1/02/18	—		—	—		—
	—	—	—	—	—	13,335	(6)	559,803	—		—
	—	—	—	—	—	—		—	22,313	(9)	936,700	(9)
	—	—	—	—	—	—		—	27,738	(10)	1,164,441	(10)
James C.	—	75,000	—	39.475	1/03/16	—		—	—		—
Fleming	—	61,500	—	47.755	1/03/17	—		—	—		—
	—	61,500	—	48.035	1/02/18	—		—	—		—
	—	—	—	—	—	1,596	(7)	67,000	—		—
	—	—	—	—	—	—		—	10,675	(9)	448,137	(9)
	—	—	—	—	—	—		—	10,675	(10)	448,137	(10)
Kristine A.	10,000	—	—	27.313	6/02/09	—		—	—		—
Rappé	20,925	—	—	33.435	1/02/14	—		—	—		—
	65,000	—	—	34.200	1/18/15	—		—	—		—
	—	58,000	—	39.475	1/03/16	—		—	—		—
	—	48,500	—	47.755	1/03/17	—		—	—		—
	—	50,200	—	48.035	1/02/18	—		—	—		—
	—	—	—	—	—	4,150	(8)	174,217	—		—
	—	—	—	—	—	—		—	8,400	(9)	352,632	(9)
	—	—	—	—	—	—		—	8,488	(10)	356,326	(10)

⁽¹⁾ All options reported in this column are fully vested and exercisable.

⁽²⁾ All options reported in this column with an exercise price of $39.475 and an expiration date of January 3, 2016, fully vest and become exercisable on January 3, 2009. All options reported in this column with an exercise price of $47.755 and an expiration

27

date of January 3, 2017, fully vest and become exercisable on January 3, 2010. All options reported in this column with an exercise price of $48.035 and an expiration date of January 2, 2018, fully vest and become exercisable on January 2, 2011.

⁽³⁾ Based on the closing price of WEC common stock reported in the New York Stock Exchange Composite Transaction Report on December 31, 2008, the last trading day of the year.

⁽⁴⁾ Effective April 14, 2003, Mr. Klappa was granted a WEC restricted stock award of 39,510 shares, which vest at the rate of 10% for each year of service until 100% vesting occurs on April 14, 2013. Earlier vesting may occur due to (1) a termination of employment by (a) death, (b) disability, (c) a change in control of WEC, (d) Mr. Klappa for good reason, or (e) WEC without cause, or (2) action by the Compensation Committee. The number of shares reported includes WEC shares acquired pursuant to the reinvestment of dividends on the WEC restricted stock.

⁽⁵⁾ Effective July 1, 2003, Mr. Leverett was granted a WEC restricted stock award of 28,850 shares. Two-thirds of the shares vested on July 1, 2005 and the remaining one-third vest at the rate of 20% for each year of service after that date until 100% vesting occurs on July 1, 2010. Earlier vesting may occur due to (1) a termination of employment by (a) death, (b) disability, (c) a change in control of WEC, (d) Mr. Leverett for good reason, or (e) WEC without cause, or (2) action by the Compensation Committee. The number of shares reported includes WEC shares acquired pursuant to the reinvestment of dividends on WEC restricted stock.

⁽⁶⁾ Effective October 13, 2003, Mr. Kuester was granted a WEC restricted stock award of 24,140 shares, which vest at the rate of 10% for each year of service until 100% vesting occurs on October 13, 2013. Earlier vesting may occur due to (1) a termination of employment by (a) death, (b) disability, (c) a change in control of WEC, (d) Mr. Kuester for good reason, or (e) WEC without cause, or (2) action by the Compensation Committee. The number of shares reported includes WEC shares acquired pursuant to the reinvestment of dividends on the WEC restricted stock.

⁽⁷⁾ Effective January 6, 2006, Mr. Fleming was granted a WEC restricted stock award of 2,500 shares, which vest at the rate of 20% for each year of service until 100% vesting occurs on January 6, 2011. Earlier vesting may occur due to termination of employment by death, disability or a change in control of WEC or by action of the Compensation Committee. The number of shares reported includes WEC shares acquired pursuant to the reinvestment of dividends on the WEC restricted stock.

⁽⁸⁾ Effective each of June 2, 1999, October 21, 2000 and February 7, 2001, Ms. Rappé was granted shares of WEC restricted stock that vest in full ten years from the respective grant date, subject to a performance accelerator. The performance accelerator is triggered by achieving certain WEC cumulative earnings per share targets measured from the respective grant date. Ten percent annually is available for accelerated vesting and the stock is subject to cumulative vesting. Earlier vesting may occur due to termination of employment by death, disability or a change in control of WEC or by action of the Compensation Committee. In addition, the stock vests upon retirement at or after attainment of age 60. The number of shares reported includes WEC shares acquired pursuant to the reinvestment of dividends on WEC restricted stock.

⁽⁹⁾ The number of WEC performance units reported vest at the end of the three-year performance period ending December 31, 2009. The number of performance units reported and their corresponding value are based upon a payout at the maximum amount.

⁽¹⁰⁾ The number of WEC performance units reported vest at the end of the three-year performance period ending December 31, 2010. The number of performance units reported and their corresponding value are based upon a payout at the maximum amount.

28

Option Exercises and Stock Vested for Fiscal Year 2008

This table shows the number and value of (1) WEC stock options that were exercised by the named executive officers, (2) WEC restricted stock awards that vested and (3) WEC performance units that vested in 2008.

(a)	(b)	(c)	(d)		(e)
	Option Awards		Stock Awards
Name	Number of Shares Acquired on Exercise (#)	Value Realized on Exercise ($)	Number of Shares Acquired on Vesting (#)		Value Realized on Vesting ($)
Gale E. Klappa	—	—	4,576	(1)	207,476	(2)
	—	—	47,064	(3)	1,975,747	(4)
Allen L. Leverett	—	—	2,189	(1)	98,768	(2)
	—	—	20,352	(3)	854,377	(4)
Frederick D. Kuester	—	—	2,792	(1)	112,099	(2)
	—	—	20,352	(3)	854,377	(4)
James C. Fleming	—	—	528	(1)(5)	25,814	(2)(5)
	—	—	12,561	(3)	527,311	(4)
Kristine A. Rappé	—	—	3,124	(1)(5)	150,783	(2)(5)
	—	—	9,858	(3)	413,839	(4)

⁽¹⁾ Reflects the number of shares of WEC restricted stock that vested in 2008.

⁽²⁾ Restricted stock value realized is determined by multiplying the number of shares of WEC restricted stock that vested by the fair market value of WEC common stock on the date of vesting. We compute fair market value as the average of the high and low prices of WEC common stock reported in the New York Stock Exchange Composite Transaction Report on the vesting date.

⁽³⁾ Reflects the number of WEC performance units that vested as of December 31, 2008, the end of the applicable three-year performance period. The performance units were settled in cash.

⁽⁴⁾ Performance units value realized is determined by multiplying the number of performance units that vested by the closing market price of WEC common stock on December 31, 2008.

⁽⁵⁾ Mr. Fleming and Ms. Rappé deferred $25,814 and $148,658, respectively, into the WEC Executive Deferred Compensation Plan. The number of WEC phantom stock units received in the WEC Executive Deferred Compensation Plan equaled the number of shares of WEC restricted stock deferred.

29

Pension Benefits at Fiscal Year-End 2008

The following table sets forth information for each named executive officer regarding their pension benefits at fiscal year-end 2008 under WEC’s four different retirement plans discussed below.

(a)	(b)	(c)		(d)	(e)
Name	Plan Name	Number of Years Credited Service (1) (#)		Present Value of Accumulated Benefit (2)(3) ($)	Payments During Last Fiscal Year ($)
Gale E. Klappa	WEC Plan	5.67		93,234	—
	SERP A	5.67		947,748	—
	Individual Letter Agreement	31.33		10,721,933	—
Allen L. Leverett	WEC Plan	5.50		75,466	—
	SERP A	5.50		460,141	—
	Individual Letter Agreement	20.00		626,689	—
Frederick D. Kuester	WEC Plan	5.17		82,812	—
	SERP A	5.17		421,226	—
	Individual Letter Agreement	36.33		6,454,253	—
James C. Fleming	WEC Plan	3.00		47,375	—
	SERP A	3.00		123,448	—
	Individual Letter Agreement	3.00		373,900	—
Kristine A. Rappé	WEC Plan	26.33		534,461	—
	SERP A	26.33		1,292,045	—
	SERP B	—	(4)	392,754	—
	Individual Letter Agreement	—		—	—

⁽¹⁾ Years of service are computed as of December 31, 2008, the pension plan measurement date used for financial statement reporting purposes. Messrs. Klappa, Leverett and Kuester have been credited with 25.66, 14.5 and 31.16 years of service, respectively, pursuant to the terms of their Individual Letter Agreements (ILAs). The increase in the aggregate amount of each of Messrs. Klappa’s, Leverett’s and Kuester’s accumulated benefit under all of WEC’s retirement plans resulting from the additional years of credited service is the amount identified in connection with each respective ILA set forth in column (d).

⁽²⁾ The key assumptions used in calculating the actuarial present values reflected in this column are:

• First projected unreduced retirement age based on current service:

• For Mr. Klappa, age 62.

• For Messrs. Leverett and Fleming, and Ms. Rappé, age 65.

• For Mr. Kuester, age 60.

• Discount rate of 6.50%.

• Cash balance interest crediting rate of 6.75%.

• Form of payment:

• WEC Plan: Lump sum.

• SERP: Life annuity.

• ILA: Life annuity, other than Mr. Fleming who we assume will receive a lump sum payment.

• Mortality Table, for life annuity:

• Messrs. Klappa, Leverett and Kuester - RP2000 with projection to 2010 - Male.

• Mr. Fleming – N/A.

• Ms. Rappé - RP2000 with projection to 2010 - Female.

⁽³⁾ WEC’s pension benefit obligations to Messrs. Klappa, Leverett and Kuester will be partially offset by pension benefits Messrs. Klappa, Leverett and Kuester are entitled to receive from their former employers. The amounts reported for Messrs. Klappa, Leverett and Kuester represent only WEC’s obligation of the aggregate actuarial present value of each of their accumulated benefit under all of the plans. The total aggregate actuarial present value of each of Messrs. Klappa’s, Leverett’s and Kuester’s accumulated benefit under all of the plans is $14,599,114, $1,336,398 and $9,385,294, respectively, $2,836,200, $174,102 and $2,427,003 of which we estimate the prior employer is obligated to pay. If Mr. Klappa’s, Mr. Leverett’s or Mr. Kuester’s former employer becomes unable to pay its portion of his respective accumulated pension benefit, WEC is obligated to pay the total amount.

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⁽⁴⁾ Pursuant to the terms of SERP B, participants are not entitled to any payments until after they retire at or after age 60, regardless of how many years they have been employed with WEC or its subsidiaries. Therefore, there are no years of credited service associated with participation in SERP B.

Retirement Plans

WEC maintains four different plans providing for retirement payments and benefits: a defined benefit pension plan of the cash balance type (WEC Plan); two supplemental executive retirement plans (SERP A and SERP B); and Individual Letter Agreements with each of the named executive officers. The compensation currently considered for purposes of the retirement plans (other than the WEC Plan) for Messrs. Klappa, Leverett and Kuester, and Ms. Rappé, is $3,125,575, $1,454,743, $1,573,027 and $815,828, respectively. These amounts represent the average compensation (consisting of base salary and annual incentive compensation) for the 36 highest consecutive months. Under the terms of Mr. Fleming’s employment agreement with WEC, the compensation considered for purposes of the retirement plans (other than the WEC Plan) is $1,036,350. This amount represents Mr. Fleming’s 2008 base salary plus his 2007 STPP award paid in 2008. As of December 31, 2008, Messrs. Klappa, Leverett, Kuester and Fleming, and Ms. Rappé, currently have or are considered to have 31.33, 20.00, 36.33, 3.00 and 26.33 credited years of service, respectively, under the various supplemental plans described below. Messrs. Klappa, Leverett and Kuester, and Ms. Rappé, are not entitled to these supplemental benefits until they attain the age of 60. Neither Mr. Fleming nor Ms. Rappé were granted additional years of credited service.

The WEC Plan.Most regular full-time and part-time employees, including the named executive officers, participate in the WEC Plan. 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 average compensation (consisting of base salary) 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 through 2007, a participant received annual credits to the account equal to 5% of base pay (including 401(k) plan 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%.

Beginning January 1, 2008, the interest credit on all prior accruals no longer fluctuates based upon the trust’s investment return for the year. Instead, the interest credit percentage is set at either the long-term corporate bond third segment rate, published by the Internal Revenue Service, or 4%, whichever is greater. For participants in the WEC Plan on December 31, 2007, their WEC Plan benefit starting January 1, 2008 will never be less than the benefit accrued as of December 31, 2007. The WEC Plan benefit will be calculated under both formulas to provide participants with the greater benefit; however, in calculating a participant’s benefit accrued as of December 31, 2007, interest credits as defined under the prior WEC Plan formula will be taken into account but not any additional pay credits. Additionally, the WEC Plan continues to provide that up to an additional 2% of base pay may be earned based upon achievement of earnings targets. Participants who were “grandfathered” as of December 31, 1995 as discussed below, will still receive the greater of the grandfathered benefit or the cash balance benefit.

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 December 31, 2010, at which time it will be frozen. Upon retirement, participants will receive the greater of this frozen amount or the accumulated cash balance.

For the named executive officers other than Mr. Fleming who does not participate in the prior plan formula, estimated benefits under the “grandfathered” formula are higher than under the cash balance plan formula. Although all of the named executive officers, other than Ms. Rappé who is grandfathered under the prior plan formula, participate in the cash balance plan formula, pursuant to the agreements discussed below, Messrs. Klappa’s, Leverett’s and Kuester’s total retirement benefits would currently be determined by the prior plan benefit formula if they were to retire at or after age 60. These benefits are payable under the Individual Letter Agreements, not the WEC Plan. The named executive officers, other than Ms. Rappé, would receive the cash balance in their accounts if they were to terminate employment prior to attaining the age of 60. Ms. Rappé would receive benefits under either the grandfathered formula or the cash balance plan formula, whichever is higher, if she were to terminate employment prior to attaining the age of 60.

Under the WEC Plan, participants receive unreduced pension benefits upon reaching one of the following three thresholds: (1) age 65; (2) age 62 with 30 years of service; or (3) age 60 with 35 years of service.

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Pursuant to the Internal Revenue Code, only $230,000 of pension eligible earnings (base pay and annual incentive compensation) may be considered for purposes of the WEC Plan.

Supplemental Executive Retirement Plans and Individual Letter Agreements.Designated officers of WEC and Wisconsin Electric, including all of the named executive officers, participate in SERP A and SERP B (collectively, the “SERP”), which are part of the Supplemental Pension Plan (the “SPP”) adopted to comply with Section 409A of the Internal Revenue Code. SERP A 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, including amounts deferred to the WEC Executive Deferred Compensation Plan. In addition, pursuant to the terms of SERP B, Ms. Rappé also will receive a supplemental lifetime annuity, equal to 10% of the average compensation (consisting of base salary and annual incentive compensation) for the 36 highest consecutive months. Except for a “change in control” of WEC, as defined in the SPP, and pursuant to the terms of the Individual Letter Agreements discussed below, no payments are made until after the participant’s retirement at or after age 60 or death. If a participant in the SERP dies prior to age 60, his or her beneficiary is entitled to receive retirement benefits under the SERP. SERP B is only provided to a grandfathered group of officers and was designed to provide an incentive to key employees to remain with WEC until retirement or death. The Compensation Committee determined to eliminate the SERP B benefit a number of years ago.

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

Messrs. Klappa’s, Leverett’s and Kuester’s agreements also provide for a pre-retirement spousal benefit to be paid to their spouses in the event of the executive’s death while employed by WEC. The benefit payable is equal to the amount which would have been received by the executive’s spouse under the WEC Plan as in effect on December 31, 1995, had the benefit formula then in effect continued until the executive’s death, calculated without regard to Internal Revenue Code limits, and as if the executive had started at the ages or dates indicated above for each executive. The spousal benefit payable would be offset by one-half of the value of any qualified or non-qualified deferred benefit pension plans of Messrs. Klappa’s, Leverett’s and Kuester’s prior employers.

WEC has entered into an agreement with Mr. Fleming to provide him a special supplemental pension to keep him whole for pension benefits he would have received from his prior employer. WEC will credit Mr. Fleming’s account with a minimum of $80,000 annually, and will credit up to an additional $40,000 annually based on performance against corporate goals as determined by the Compensation Committee. The amounts credited to Mr. Fleming’s account will earn interest as if it had been credited to the WEC Plan. The account balance vests at the earlier of five years from the date Mr. Fleming commenced employment (January 3, 2011) or age 65, and will be paid pursuant to the terms of the SPP. Mr. Fleming also participates in the WEC Plan and SERP A, without any additional years of credited service.

The purpose of these agreements is to ensure that Messrs. Klappa, Leverett, Kuester and Fleming do not lose pension earnings by joining the executive management team at WEC and the Company they otherwise would have received from their former employers. Since retirement plans operate in a manner where accrued amounts increase substantially as a participant increases in age and years of service, these officers forfeited substantial pension benefits by coming to work for us. Without providing a means to retain these pension benefits, it would have been difficult for us to attract these officers.

In order to allow Ms. Rappé to retire at age 60 with an unreduced pension benefit, WEC entered into an agreement with Ms. Rappé whereby her SERP A benefit will not be subject to early retirement reduction factors if she retires at or after age 60. Under this agreement, if Ms. Rappé were to retire at age 60, she would be granted less than one year of additional credited service.

The SPP provides for a mandatory lump sum payment upon a change in control if the executive’s employment is terminated within 18 months after the change in control of WEC. The WEC Amended Non-Qualified Trust, a grantor trust, was established to fund certain non-qualified benefits, including the SPP and the Individual Letter Agreements, as well as WEC’s Executive Deferred Compensation Plan and WEC’s Directors’ Deferred Compensation Plan discussed later in this information statement. See “Potential Payments upon Termination or Change in Control” later in this information statement for additional information.

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Nonqualified Deferred Compensation for Fiscal Year 2008

The following table reflects activity by the named executive officers during 2008 in WEC’s Executive Deferred Compensation Plan discussed below.

(a)	(b)	(c)	(d)		(e)	(f)
Name	Executive Contributions in Last Fiscal Year (1) ($)	Registrant Contributions in Last Fiscal Year (2) ($)	Aggregate Earnings In Last Fiscal Year ($)		Aggregate Withdrawals / Distributions ($)	Aggregate Balance at Last Fiscal Year- End (3) ($)
Gale E. Klappa	496,516	112,476	89,126		—	2,155,440
Allen L. Leverett	98,525	48,066	(274,323	)	—	1,660,956
Frederick D. Kuester	139,211	57,734	49,365		—	1,520,367
James C. Fleming	159,977	31,084	(120,424	)	—	281,991
Kristine A. Rappé	199,089	22,870	(148,959	)	—	1,465,639

⁽¹⁾ Other than $47,522 and $148,658 of Mr. Fleming’s and Ms. Rappé’s contribution, respectively, all of the amounts are reported as compensation in the Summary Compensation Table of this information statement. These amounts consist of the value of WEC restricted stock that vested during 2008 and/or dividends paid on WEC performance units during 2008. The grant date fair value of shares of WEC restricted stock and the value of the right to receive dividends on the WEC performance units are expensed by WEC in accordance with SFAS 123R, and the expensed amounts recognized for financial statement reporting purposes in 2008 are included in the Summary Compensation Table in this information statement.

⁽²⁾ All of the reported amounts are reported as compensation in the Summary Compensation Table of this information statement.

⁽³⁾ $1,217,187, $1,186,401, $962,650, $188,291 and $125,013 of the reported amounts were reported as compensation in the Summary Compensation Tables in prior information statements for Messrs. Klappa, Leverett, Kuester and Fleming, and Ms. Rappé, respectively. Messrs. Klappa, Leverett and Kuester have been named executive officers since commencing employment with the Company in 2003. Mr. Fleming has been a named executive officer since commencing employment with the Company in January 2006. Ms. Rappé was a named executive officer in 2004 and 2005, and became a named executive officer again in 2007.

Executive Deferred Compensation Plan

WEC maintains two executive deferred compensation plans, the Legacy Wisconsin Energy Corporation Executive Deferred Compensation Plan (the “Legacy EDCP”) and the new Wisconsin Energy Corporation Executive Deferred Compensation Plan (the “EDCP”), adopted effective January 1, 2005 to comply with Section 409A of the Internal Revenue Code. Executive officers and certain other highly compensated employees are eligible to participate in both plans. The Legacy EDCP provides that (i) amounts earned, deferred, vested, credited and/or accrued as of December 31, 2004 are preserved and frozen so that these amounts are exempt from Section 409A and (ii) no new employees may participate in the Legacy EDCP as of January 1, 2005. As of January 1, 2005, all deferrals are made to the EDCP. The provisions of each of these plans are described below.

The Legacy EDCP. Under the plan, a participant could have deferred up to 100% of his or her base salary, annual incentive compensation, long-term incentive compensation (including the value of any stock option gains, vested awards of restricted stock, performance shares and units and dividends earned on unvested performance units), severance payments due under WEC’s Executive Severance Policy or under any change in control agreement between WEC and a participant, and any “make-whole” pension supplements.

Deferral elections were made annually by each participant for the upcoming plan year. WEC maintains detailed records tracking each participant’s “account balance.” In addition to deferrals made by the participants, WEC was also able to credit each participant’s account balance by matching a certain portion of each participant’s deferral. Such deferral matching was determined by a formula taking into account the matching rate applicable under WEC’s 401(k) plan, the percentage of compensation subject to such matching rate, the participant’s gross compensation eligible for matching and the amount of eligible compensation actually deferred. Also, WEC, in its discretion, could have credited any other amounts, as appropriate, to each participant’s account. Additionally, “make-whole” payments could have been made to participants who were not eligible to participate in the SERP and whose deferrals resulted in lesser payments under WEC’s qualified pension plan.

WEC tracks each participant’s account balance as though the balance was actually invested in one or more of several measurement funds. Measurement fund elections are not actual investments, but are elections chosen only for purposes of calculating market gain or

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loss on deferred amounts for the duration of the deferral period. Each participant may select the amount of deferred compensation to be allocated among any one or more of the available measurement funds. Participants may elect from among eight measurement funds that correspond to investment options in WEC’s 401(k) plan in addition to the prime rate fund and WEC’s stock measurement fund. Deferred amounts relating to the value of participants’ WEC stock option gains and vested WEC restricted stock are always deemed invested in the WEC’s stock measurement fund and may not be transferred to any other measurement fund. Contributions and deductions may be made to each participant’s account based on the performance of the measuring funds elected. The table below shows the funds available under the EDCP and their annual rate of return for the calendar year ended December 31, 2008:

Name of Fund	Rate of Return (%)
Fidelity Balanced Fund	(31.31	)
Fidelity Diversified International Fund	(45.21	)
Fidelity Equity – Income Fund	(41.64	)
Fidelity Growth Company Fund	(40.90	)
Fidelity Low-Priced Stock Fund	(36.17	)
Fidelity U.S. Bond Index Fund	3.76
Prime Rate	5.22
S&P 500 Fund	(37.00	)
Vanguard Mid-Cap Index	(41.82	)
WEC Common Stock Fund	(11.72	)

Each participant’s account balance is debited or credited periodically based on the performance of the measurement fund(s) elected by the participant. Subject to certain restrictions, participants may make changes to their measurement fund elections by notice to the committee administering the plan.

At the time of his or her deferral election, each participant designated a prospective payout date for any or the entire amount deferred, plus any amounts debited or credited to the deferred amount as of the designated payout date. A participant may elect, at any time, to withdraw part (a minimum of $25,000) or all of his or her account balance, subject to a withdrawal penalty of 10%. Payout amounts may be limited to the extent to which they are deductible under Section 162(m) of the Internal Revenue Code.

The balance of a participant’s account is payable on his or her retirement in either a lump sum payout or in annual installments, at the election of the participant. Upon the death of a participant after retirement, payouts are made to the deceased participant’s beneficiary in the same manner as though such payout would have been made to the participant had the participant survived. In the event of a participant’s termination of employment prior to retirement, the participant may elect to receive a payout beginning the year after termination in the amount of his account balance as of the termination date either in a lump sum or in annual installments over a period of five years. Any participant who suffers from a continued disability will be entitled to the benefits of plan participation unless and until the committee administering the plan determines that the participant has been terminated for purposes of continued participation in the plan. Upon any such determination, the disabled participant is paid out as though the participant had retired. Except in certain limited circumstances, participants’ account balances will be paid out in a lump sum (1) upon the occurrence of a change in control of WEC, as defined in the plan, or (2) upon any downgrade of WEC’s senior debt obligations to less than “investment grade.” The deferred amounts will be paid out of the general corporate assets or the assets of the WEC Amended Non-Qualified Trust.

The EDCP.Under the plan, a participant may defer up to 75% of his or her base salary and annual incentive compensation and up to 100% of his or her long-term incentive compensation (including vested awards of restricted stock, performance units and dividends earned on unvested performance units). Stock option gains may not be deferred into the EDCP.

Generally, deferral elections are made annually by each participant for the upcoming plan year. WEC maintains detailed records tracking each participant’s “account balance.” In addition to deferrals made by the participants, WEC may also credit each participant’s account balance by matching a certain portion of each participant’s deferral. Such deferral matching is determined by a formula taking into account the matching rate applicable under WEC’s 401(k) plan, the percentage of compensation subject to such matching rate, the participant’s gross compensation eligible for matching and the amount of eligible compensation actually deferred. Also, WEC, in its discretion, may credit any other amounts, as appropriate, to each participant’s account.

The Company tracks each participant’s account balance as though the balance was actually invested in one or more of several measurement funds. Measurement fund elections are not actual investments, but are elections chosen only for purposes of calculating market gain or loss on deferred amounts for the duration of the deferral period. Each participant may select the amount of deferred compensation to be allocated among any one or more of the same ten measurement funds described under “the Legacy EDCP” above. Deferred amounts relating to the value of participants’ vested restricted stock are always deemed invested in the WEC’s stock measurement fund and may not be transferred to any other measurement fund. Contributions and deductions may be made to each participant’s account based on the performance of the measuring funds elected.

Each participant’s account balance is debited or credited periodically based on the performance of the measurement fund(s) elected by the participant. Subject to certain restrictions, participants may make changes to their measurement fund elections by notice to the committee administering the plan.

At the time of his or her deferral election, each participant may designate a prospective payout date for any or the entire amount deferred, plus any amounts debited or credited to the deferred amount as of the designated payout date. Amounts deferred into the

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EDCP may not be withdrawn at the discretion of the participant and a change to the designated payout date delays the initial payment five years beyond the originally designated payout date. WEC may not limit payout amounts in order to deduct such amounts under Section 162(m) of the Internal Revenue Code.

The balance of a participant’s account is payable on his or her retirement in either a lump sum payout or in annual installments, at the election of the participant. Upon the death of a participant after retirement, payouts are made to the deceased participant’s beneficiary in the same manner as though such payout would have been made to the participant had the participant survived. In the event of a participant’s termination of employment prior to retirement, the participant may elect to receive a payout beginning the year after termination in the amount of his account balance as of the termination date either in a lump sum or in annual installments over a period of five years. Disability is not itself a payment event until the participant terminates employment with WEC or its subsidiaries. A participant’s account balance will be paid out in a lump sum if the participant separates from service with WEC or its subsidiaries within 18 months after a change in control of WEC, as defined in the plan. The deferred amounts will be paid out of the general corporate assets or the assets of the WEC Amended Non-Qualified Trust.

Potential Payments upon Termination or Change in Control

The tables below reflect the amount of compensation payable to each of our named executive officers in the event of termination of each executive’s employment. These amounts are in addition to each named executive officers’ aggregate balance in the EDCP at fiscal year-end 2008, as reported in column (f) under “Nonqualified Deferred Compensation for Fiscal Year 2008.” The amount of compensation payable to each named executive officer upon voluntary termination, normal retirement, for-cause termination, involuntary termination (by WEC for any reason other than cause, death or disability or by the executive for “good reason”), termination following a “change in control” of WEC, disability and death are set forth below. The amounts shown assume that such termination was effective as of December 31, 2008 and include amounts earned through that date, and are estimates of the amounts which would be paid out to the named executive officers upon termination. The amounts shown under “Normal Retirement” assume the named executive officers were retirement eligible with no reduction of retirement benefits. The amounts shown under “Termination Upon a Change in Control” assume the named executive officers terminated employment as of December 31, 2008, which was within 18 months of a change in control of WEC. The amounts reported in the row “Retirement Plans” in each table below are not in addition to the amounts reflected under “Pension Benefits at Fiscal Year-End 2008.” The actual amounts to be paid out can only be determined at the time of an officer’s termination of employment.

Payments Made Upon Voluntary Termination or Termination for Cause, Death or Disability.In the event a named executive officer voluntarily terminates employment or is terminated for cause, death or disability, the officer will receive:

• accrued but unpaid base salary and, for termination by death or disability, pro-rated annual incentive compensation;

• 401(k) plan and EDCP account balances;

• the WEC Plan cash balance;

• in the case of death or disability, full vesting in all outstanding WEC stock options, restricted stock and performance units (otherwise, the ability to exercise already vested options within three months of termination); and

• if termination occurs after age 60 or by death or disability, vesting in the SERP and Individual Letter Agreements.

Named executive officers are also entitled to the value of unused vacation days, if any, and for termination by death, benefits payable under the Death Benefit Only Plan.

Payments Made Upon Normal Retirement.In the event of the retirement of a named executive officer, the officer will receive:

• full vesting in all outstanding WEC stock options and restricted stock, and a prorated amount of WEC performance units;

• full vesting in all retirement plans, including the WEC Plan, SERP and Individual Letter Agreements; and

• 401(k) plan and EDCP account balances.

Named executive officers are also entitled to the value of unused vacation days, if any.

Payments Made Upon a Change in Control or Involuntary Termination. WEC has entered into written employment agreements with each of Messrs. Klappa, Leverett, Kuester and Fleming, and Ms. Rappé, which provide for certain severance benefits as described below.

Under the agreement with Mr. Klappa, severance benefits are provided if his employment is terminated:

• in anticipation of or following a change in control by WEC for any reason, other than cause, death or disability;

• by Mr. Klappa for good reason in anticipation of or following a change in control;

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• by Mr. Klappa within six months after completing one year of service following a change in control of WEC; or

• in the absence of a change in control of WEC, by WEC for any reason other than cause, death or disability or by Mr. Klappa for good reason.

Upon the occurrence of one of these events, Mr. Klappa’s 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;

• three years’ continuation of health and certain other welfare benefit coverage and 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 based upon the higher of (1) the annual base salary in effect at the time of termination and (2) any salary in effect during the 180 day period preceding termination, plus the highest bonus amount;

• a payment equal to the value of three additional years of WEC match in the 401(k) plan and the EDCP;

• full vesting in all outstanding WEC stock options, restricted stock and other equity awards;

• 401(k) plan and EDCP account balances;

• certain financial planning services and other benefits; and

• in the event of a change in control, a “gross-up” payment should any payments or benefits under the agreements trigger federal excise taxes under the “parachute payment” provisions of the tax law.

The highest bonus amount would be calculated as the largest of (1) the current target bonus for the fiscal year in which employment termination occurs, or (2) the highest bonus paid in any of the last three fiscal years prior to termination or the change in control of WEC. The agreement contains a one-year non-compete provision applicable on termination of employment.

Mr. Leverett’s, Mr. Kuester’s and Mr. Fleming’s agreements are substantially similar to Mr. Klappa’s, except that if their employment is terminated by WEC for any reason other than cause, death or disability or by them for good reason in the absence of a change in control of WEC:

• the special lump sum severance benefit is two times the sum of their highest annual base salary in effect for the three years preceding their termination and their highest bonus amount;

• health and certain other welfare benefits are provided for a two-year period;

• the special retirement plan lump sum is calculated as if their employment continued for a two-year period following termination of employment; and

• the payment for 401(k) plan and EDCP match is equal to two years of WEC match.

Mr. Leverett’s and Mr. Kuester’s agreements contain a one-year non-compete provision applicable on termination of employment.

Ms. Rappé’s agreement is substantially similar to Mr. Klappa’s, except that if Ms. Rappé’s employment is terminated upon a change in control of WEC, (1) the special lump sum severance benefit is three times the sum of her highest annual base salary in effect for the three years preceding termination and her target bonus amount, and (2) the payment related to the retirement plans is based upon the same base salary amount calculated as set forth above plus her target bonus amount. In addition, if Ms. Rappé’s employment is terminated by WEC for any reason other than cause, death or disability or by Ms. Rappé for good reason in the absence of a change of control of WEC:

• 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;

• health and certain other welfare benefits are provided for a two-year period;

• the special retirement plan lump sum is calculated as if her employment continued for a two-year period following termination of employment; and

• the payment for 401(k) plan and EDCP match is equal to two years of WEC match.

Ms. Rappé’s agreement contains a one-year non-compete provision applicable on termination of employment.

Pursuant to the terms of the SPP and Individual Letter Agreements, retirement benefits are paid to the named executive officers upon termination of employment within 18 months of a change in control of WEC. Participants in SERP A, including the named executive officers, are also eligible to receive a supplemental disability benefit in an amount equal to the difference between the actual amount of the benefit payable under the long-term disability plan applicable to all employees and what such disability benefit would have been if calculated without regard to any limitation imposed by the broad-based plan on annual compensation recognized thereunder.

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Generally, pursuant to the agreements, a change in control is deemed to occur:

(1) if any person or group acquires WEC common stock that constitutes more than 50% of the total fair market value or total voting power of WEC;

(2) if any person or group acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such person or group) WEC common stock that constitutes 30% or more of the total voting power of WEC;

(3) if a majority of the members of WEC’s Board is replaced during any 12-month period by directors whose appointment or election is not endorsed by a majority of WEC’s Board before the date of appointment or election; or

(4) if any person or group acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such person or group) assets from WEC that have a total gross fair market value equal to or more than 40% of the total gross value of all the assets of WEC immediately before such acquisition or acquisitions, unless the assets are transferred to:

• an entity that is controlled by the shareholders of the transferring corporation;

• a shareholder of WEC in exchange for or with respect to its stock;

• an entity of which WEC owns, directly or indirectly, 50% or more of its total value or voting power; or

• a person or group (or an entity of which such person or group owns, directly or indirectly, 50% or more of its total value or voting power) that owns, directly or indirectly, 50% or more of the total value or voting power of WEC.

Generally, pursuant to the agreements, good reason means:

(1) solely in the context of a change in control of WEC, a material reduction of the executive’s duties and responsibilities (other than Mr. Kuester’s agreement);

(2) a material reduction in the executive’s base compensation;

(3) a material change in the geographic location at which the executive must perform services; or

(4) a material breach of the agreement by WEC.

The following table shows the potential payments upon termination or a change in control of WEC for Gale E. Klappa.

Executive Benefits and Payments Upon Separation	Voluntary Termination ($)	Normal Retirement ($)	For Cause Termination ($)	Involuntary Termination ($)	Termination Upon a Change in Control ($)	Disability ($)	Death ($)
Compensation:
Cash Severance	—	—	—	9,919,812	9,919,812	—	—
Additional Pension Credited Service	—	—	—	2,163,678	2,163,678	—	—
Additional 401(k) and EDCP Match	—	—	—	396,792	396,792	—	—
Long-Term Incentive Compensation:
Performance Units	—	1,175,440	—	2,392,860	2,392,860	2,392,860	2,392,860
Restricted Stock	—	933,471	—	933,471	933,471	933,471	933,471
Options *	—	631,260	—	631,260	631,260	631,260	631,260
Benefits & Perquisites:
Retirement Plans	93,234	11,762,914	93,234	10,644,188	10,644,188	11,762,914	5,365,763
Health and Welfare Benefits	—	—	—	36,903	36,903	—	—
Excise Tax Gross-Up	—	—	—	—	10,231,949	—	—
Financial Planning	—	—	—	45,000	45,000	—	—
Outplacement	—	—	—	30,000	30,000	—	—
Death Benefit Only Plan	—	—	—	—	—	—	3,387,024
Total	93,234	14,503,085	93,234	27,193,964	37,425,913	15,720,505	12,710,378

* Excludes options that are out-of-the-money as of December 31, 2008.

37

The following table shows the potential payments upon termination or a change in control of WEC for Allen L. Leverett.

Executive Benefits and Payments Upon Separation	Voluntary Termination ($)	Normal Retirement ($)	For Cause Termination ($)	Involuntary Termination ($)	Termination Upon a Change in Control ($)	Disability ($)	Death ($)
Compensation:
Cash Severance	—	—	—	3,081,600	4,622,400	—	—
Additional Pension Credited Service	—	—	—	420,734	554,903	—	—
Additional 401(k) and EDCP Match	—	—	—	123,264	184,896	—	—
Long-Term Incentive Compensation:
Performance Units	—	578,624	—	1,200,628	1,200,628	1,200,628	1,200,628
Restricted Stock	—	182,485	—	182,485	182,485	182,485	182,485
Options *	—	237,975	—	237,975	237,975	237,975	237,975
Benefits & Perquisites:
Retirement Plans	75,466	1,162,296	75,466	1,282,192	1,293,380	1,162,296	1,015,344
Health and Welfare Benefits	—	—	—	24,602	36,903	—	—
Excise Tax Gross-Up	—	—	—	—	3,877,206	—	—
Financial Planning	—	—	—	45,000	45,000	—	—
Outplacement	—	—	—	30,000	30,000	—	—
Death Benefit Only Plan	—	—	—	—	—	—	1,823,040
Total	75,466	2,161,380	75,466	6,628,480	12,265,776	2,783,384	4,459,472

* Excludes options that are out-of-the-money as of December 31, 2008.

The following table shows the potential payments upon termination or a change in control of WEC for Frederick D. Kuester.

Executive Benefits and Payments Upon Separation	Voluntary Termination ($)	Normal Retirement ($)	For Cause Termination ($)	Involuntary Termination ($)	Termination Upon a Change in Control ($)	Disability ($)	Death ($)
Compensation:
Cash Severance	—	—	—	3,331,718	4,997,577	—	—
Additional Pension Credited Service	—	—	—	735,350	1,309,471	—	—
Additional 401(k) and EDCP Match	—	—	—	133,269	199,903	—	—
Long-Term Incentive Compensation:
Performance Units	—	578,624	—	1,200,628	1,200,628	1,200,628	1,200,628
Restricted Stock	—	559,803	—	559,803	559,803	559,803	559,803
Options *	—	237,975	—	237,975	237,975	237,975	237,975
Benefits & Perquisites:
Retirement Plans	82,812	6,958,291	82,812	6,738,792	6,113,592	6,958,291	2,745,202
Health and Welfare Benefits	—	—	—	24,602	36,903	—	—
Excise Tax Gross-Up	—	—	—	—	6,911,041	—	—
Financial Planning	—	—	—	45,000	45,000	—	—
Outplacement	—	—	—	30,000	30,000	—	—
Death Benefit Only Plan	—	—	—	—	—	—	1,971,000
Total	82,812	8,334,693	82,812	13,037,137	21,641,893	8,956,697	6,714,608

* Excludes options that are out-of-the-money as of December 31, 2008.

38

The following table shows the potential payments upon termination or a change in control of WEC for James C. Fleming.

Executive Benefits and Payments Upon Separation	Voluntary Termination ($)	Normal Retirement ($)	For Cause Termination ($)	Involuntary Termination ($)	Termination Upon a Change in Control ($)	Disability ($)	Death ($)
Compensation:
Cash Severance	—	—	—	2,072,700	3,109,050	—	—
Additional Pension Credited Service	—	—	—	385,089	577,634	—	—
Additional 401(k) and EDCP Match	—	—	—	82,908	124,362	—	—
Long-Term Incentive Compensation:
Performance Units	—	256,078	—	512,156	512,156	512,156	512,156
Restricted Stock	—	67,015	—	67,015	67,015	67,015	67,015
Options *	—	187,875	—	187,875	187,875	187,875	187,875
Benefits & Perquisites:
Retirement Plans	170,823	544,722	170,823	545,468	550,825	544,722	542,916
Health and Welfare Benefits	—	—	—	24,602	36,903	—	—
Excise Tax Gross-Up	—	—	—	—	2,107,184	—	—
Financial Planning	—	—	—	45,000	45,000	—	—
Outplacement	—	—	—	30,000	30,000	—	—
Death Benefit Only Plan	—	—	—	—	—	—	1,323,000
Total	170,823	1,055,690	170,823	3,952,813	7,348,004	1,311,768	2,632,962

* Excludes options that are out-of-the-money as of December 31, 2008.

The following table shows the potential payments upon termination or a change in control of WEC for Kristine A. Rappé.

Executive Benefits and Payments Upon Separation	Voluntary Termination ($)	Normal Retirement ($)	For Cause Termination ($)	Involuntary Termination ($)	Termination Upon a Change in Control ($)	Disability ($)	Death ($)
Compensation:
Cash Severance	—	—	—	1,259,865	1,889,798	—	—
Additional Pension Credited Service	—	—	—	207,123	307,704	—	—
Additional 401(k) and EDCP Match	—	—	—	50,395	75,592	—	—
Long-Term Incentive Compensation:
Performance Units	—	202,204	—	405,107	405,107	405,107	405,107
Restricted Stock	—	174,221	—	174,221	174,221	174,221	174,221
Options *	—	145,290	—	145,290	145,290	145,290	145,290
Benefits & Perquisites:
Retirement Plans	534,461	2,219,260	534,461	2,983,202	2,945,201	2,219,260	1,501,453
Health and Welfare Benefits	—	—	—	24,602	36,903	—	—
Excise Tax Gross-Up	—	—	—	—	3,671,394	—	—
Financial Planning	—	—	—	30,000	30,000	—	—
Outplacement	—	—	—	30,000	30,000	—	—
Death Benefit Only Plan	—	—	—	—	—	—	1,181,124
Total	534,461	2,740,975	534,461	5,309,805	9,711,210	2,943,878	3,407,195

* Excludes options that are out-of-the-money as of December 31, 2008.

39

DIRECTOR COMPENSATION

The following table summarizes total compensation awarded to, earned by or paid to each of the Company’s non-employee directors during 2008. The amounts shown in this table are WEC consolidated compensation data.

(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)
Name	Fees Earned or Paid In Cash ($)	Stock Awards (2)(3)(4) ($)	Option Awards (5) ($)	Non-Equity Incentive Plan Compensation ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)	All Other Compensation (6) ($)	Total ($)
John F. Ahearne (1)	76,875	145,728	—	—	—	26,511	249,114
John F. Bergstrom	80,000	71,434	—	—	—	19,917	171,351
Barbara L. Bowles	80,000	71,434	—	—	—	18,272	169,706
Patricia W. Chadwick	75,000	60,405	—	—	—	21,063	156,468
Robert A. Cornog	75,000	71,434	—	—	—	39,897	186,331
Curt S. Culver	80,000	71,434	—	—	—	14,204	165,638
Thomas J. Fischer	82,500	71,434	—	—	—	24,101	178,035
Ulice Payne, Jr.	75,000	71,434	—	—	—	10,082	156,516
Frederick P. Stratton, Jr.	75,000	71,434	—	—	—	45,062	191,496

⁽¹⁾ Dr. Ahearne did not stand for re-election to the Board of Directors in May 2008. On May 1, 2008, the Compensation Committee approved the acceleration of all of Dr. Ahearne’s 4,914 unvested shares of WEC restricted stock.

⁽²⁾ The amounts reported reflect the amounts recognized for financial statement reporting purposes in WEC’s 2008 consolidated financial statements in accordance with SFAS 123R for annual WEC restricted stock awards made to directors in 2006, 2007 and 2008. Each restricted stock award vests in full on the third anniversary of the grant date. We made certain assumptions in our valuation of the WEC restricted stock awarded to the directors. See Note H — Common Equity in the Notes to Consolidated Financial Statements in our 2008 Annual Report on Form 10-K for a description of these assumptions.

⁽³⁾ The grant date fair value of each award made in 2008 determined in accordance with SFAS 123R is $75,000.

⁽⁴⁾ Directors held the following number of shares of WEC restricted stock as of December 31, 2008: Mr. Bergstrom (5,002), Ms. Bowles (5,002), Ms. Chadwick (4,118), Mr. Cornog (5,002), Mr. Culver (5,002), Mr. Fischer (5,002), Mr. Payne (5,002) and Mr. Stratton (5,002).

⁽⁵⁾ Directors held the following number of options to purchase WEC common stock as of December 31, 2008, all of which are exercisable: Dr. Ahearne (13,000), Mr. Bergstrom (20,000), Ms. Bowles (10,000), Mr. Cornog (23,000), Mr. Payne (10,000) and Mr. Stratton (17,000).

⁽⁶⁾ All amounts represent costs for the WEC Directors’ Charitable Awards Program. See “Compensation of the Board of Directors” below for additional information regarding this program.

Compensation of the Board of Directors

During 2008, each non-employee director received an annual retainer fee of $75,000. Non-employee chairs of Board committees received a quarterly retainer of $1,250, except the chair of the Audit and Oversight Committee who received a quarterly retainer of $1,875. Former Director Ahearne, as the Lead Nuclear Director, also received a quarterly annual retainer of $1,875 until the 2008 Annual Meeting of Stockholders. The Company reimbursed non-employee directors for all out-of-pocket travel expenses (which reimbursed amounts are not reflected in the table above). Each non-employee director also received on January 2, 2008, the 2008 annual stock compensation award in the form of WEC restricted stock equal to a value of $75,000, with all shares vesting three years from the grant date. Employee directors do not receive these fees. Insurance is also provided for director liability coverage, fiduciary and employee benefit liability coverage and travel accident coverage for director travel on Company business. The premiums paid for this insurance are not included in the amounts reported in the table above.

40

Non-employee directors may defer all or a portion of director fees pursuant to WEC’s Directors’ Deferred Compensation Plan, adopted effective January 1, 2005 to comply with Section 409A of the Internal Revenue Code. Prior to January 1, 2005, amounts were deferred to the Legacy Directors’ Deferred Compensation Plan and are preserved and frozen in that plan, which is not subject to 409A. Deferred amounts can be credited to any of ten measurement funds, including a WEC phantom stock account. The value of these accounts will appreciate or depreciate based on market performance, as well as through the accumulation of reinvested dividends. Deferral amounts are credited to accounts in the name of each participating director on the books of WEC, are unsecured and are payable only in cash following termination of the director’s service to WEC and its subsidiaries, including Wisconsin Electric. The deferred amounts will be paid out of general corporate assets or the assets of the WEC Amended Non-Qualified Trust.

Although Wisconsin Electric directors also serve on the Wisconsin Energy and Wisconsin Gas boards and their committees, a single annual retainer fee and quarterly committee chair retainer were paid. Fees were allocated among Wisconsin Electric, Wisconsin Energy and Wisconsin Gas based on services rendered.

The Company has a Directors’ Charitable Awards Program to help further WEC’s philosophy of charitable giving. Under the program, WEC intends to contribute up to $100,000 per year for 10 years to one or more charitable organizations chosen by each director, including employee directors, upon the director’s death. Directors are provided with one charitable award benefit for serving on the boards of WEC and its subsidiaries, including Wisconsin Electric. 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 WEC. The tax deductibility of these charitable donations mitigates the net cost to WEC. The Directors’ Charitable Awards Program has been eliminated for any new directors elected after January 1, 2007. Directors already participating as of that date, which includes all of the current directors, were grandfathered.

In December 2008, the Compensation Committee reviewed director compensation and determined that no changes should be made for 2009.

STOCK OWNERSHIP OF DIRECTORS, NOMINEES AND EXECUTIVE OFFICERS

None of the Wisconsin Electric directors, nominees or executive officers own any of Wisconsin Electric’s stock, but do beneficially own shares of its parent company, Wisconsin Energy Corporation. The following table lists the beneficial ownership of WEC common stock of each Wisconsin Electric director, nominee, named executive officer and all of the directors and executive officers as a group as of February 12, 2009. In general, “beneficial ownership” includes those shares as to which the indicated persons have voting power or investment power and WEC stock options that are exercisable currently or within 60 days of February 12, 2009. Included are shares owned by each individual’s spouse, minor children or any other relative sharing the same residence, as well as shares held in a fiduciary capacity or held in WEC’s Stock Plus Investment Plan and 401(k) plan. None of these persons beneficially owns more than 1% of the outstanding WEC common stock.

Name	Shares Beneficially Owned(1)
	Shares Owned(2) (3) (4) (5)	Option Shares Exercisable Within 60 Days	Total
John F. Bergstrom	10,778	20,000	30,778
Barbara L. Bowles	13,817	10,000	23,817
Patricia W. Chadwick	5,895	—	5,895
Robert A. Cornog	14,514	20,000	34,514
Curt S. Culver	5,019	—	5,019
Thomas J. Fischer	10,587	—	10,587
James C. Fleming	1,598	75,000	76,598
Gale E. Klappa	38,580	982,000	1,020,580
Frederick D. Kuester	19,419	545,000	564,419
Allen L. Leverett	7,063	545,000	552,063
Ulice Payne, Jr.	9,983	10,000	19,983
Kristine A. Rappé	11,349	153,925	165,274
Frederick P. Stratton, Jr.	16,378	17,000	33,378
All directors and executive officers as a group (15 persons)	201,820	2,559,891	2,761,711	(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 WEC’s proxy statement. It is not necessarily to be construed as an admission of beneficial ownership for other purposes.

41

⁽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 (12,107), Mr. Cornog (18,141), Mr. Culver (13,674), Mr. Fleming (1,617), Mr. Kuester (2,725), Ms. Rappé (12,489), Mr. Stratton (14,057) and all directors and executive officers as a group (75,100). 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 the table above) as indicated: Mr. Bergstrom (3,000), Mr. Cornog (5,007), Mr. Klappa (2,500), Mr. Leverett (1,744), Mr. Stratton (4,600) and all directors and executive officers as a group (16,851).

⁽⁴⁾ Certain directors and executive officers hold shares of WEC restricted stock (included in the table above) over which the holders have sole voting but no investment power: Mr. Bergstrom (5,019), Ms. Bowles (5,019), Ms. Chadwick (5,895), Mr. Cornog (5,019), Mr. Culver (5,019), Mr. Fischer (5,019), Mr. Fleming (1,054), Mr. Klappa (22,236), Mr. Kuester (13,335), Mr. Leverett (4,346), Mr. Payne (5,019), Ms. Rappé (3,876), Mr. Stratton (5,019) and all directors and executive officers as a group (93,741).

⁽⁵⁾ None of the shares beneficially owned by the directors, named executive officers and all directors and executive officers as a group are pledged as security.

⁽⁶⁾ Represents 2.4% of total WEC common stock outstanding on February 12, 2009.

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 a registered class of the Company’s equity securities to file reports of ownership and changes in ownership of equity and derivative securities of Wisconsin Electric with the Securities and Exchange Commission. Specific due dates for those reports have been established by the Securities and Exchange Commission, and the Company is required to disclose in this information statement any failure to file by those dates during the 2008 fiscal year. To the Company’s knowledge, based on information provided by the reporting persons, all applicable reporting requirements for fiscal year 2008 were complied with in a timely manner.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

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

AVAILABILITY OF FORM 10-K

A copy (without exhibits) of Wisconsin Electric Power Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, as filed with the Securities and Exchange Commission, is available without charge to any stockholder of record or beneficial owner of Wisconsin Electric preferred stock by writing to the Corporate Secretary, Susan H. Martin, at the Company’s principal business office, 231 West Michigan Street, P. O. Box 2046, Milwaukee, Wisconsin 53201. The Wisconsin Electric consolidated financial statements and certain other information found in the Form 10-K are included in the Wisconsin Electric Power Company 2008 Annual Report to Stockholders, attached hereto as Appendix A.

42

APPENDIX A

WISCONSIN ELECTRIC POWER COMPANY

2008 ANNUAL REPORT TO STOCKHOLDERS

2008 ANNUAL FINANCIAL STATEMENTS

And

REVIEW of OPERATIONS

A-1

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below.

Wisconsin Electric Subsidiary and Affiliates

Primary Subsidiary and Affiliates
Bostco	Bostco LLC
Edison Sault	Edison Sault Electric Company
We Power	W.E. Power, LLC
Wisconsin Energy	Wisconsin Energy Corporation
Wisconsin Gas	Wisconsin Gas LLC
Significant Assets
OC 1	Oak Creek expansion Unit 1
OC 2	Oak Creek expansion Unit 2
PWGS	Port Washington Generating Station
PWGS 1	Port Washington Generating Station Unit 1
PWGS 2	Port Washington Generating Station Unit 2
Other Affiliates
ATC	American Transmission Company LLC
ERS	Elm Road Services, LLC
Federal and State Regulatory Agencies
DOA	Wisconsin Department of Administration
DOE	United States Department of Energy
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
IRS	Internal Revenue Service
MDEQ	Michigan Department of Environmental Quality
MPSC	Michigan Public Service Commission
NRC	United States Nuclear Regulatory Commission
PSCW	Public Service Commission of Wisconsin
SEC	Securities and Exchange Commission
WDNR	Wisconsin Department of Natural Resources
Environmental Terms
Act 141	2005 Wisconsin Act 141
BART	Best Available Retrofit Technology
BTA	Best Technology Available
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CAVR	Clean Air Visibility Rule
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act
CO2	Carbon Dioxide
CWA	Clean Water Act
NAAQS	National Ambient Air Quality Standards
NOx	Nitrogen Oxide
PM 2.5	Fine Particulate Matter
RACT	Reasonably Available Control Technology
RI/FS	Remedial Investigation and Feasibility Study
SIP	State Implementation Plan
SO2	Sulfur Dioxide
WPDES	Wisconsin Pollution Discharge Elimination System

A-2

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS - (Cont’d)

The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below.

Other Terms and Abbreviations
ALJ	Wisconsin Administrative Law Judge
AQCS	Air Quality Control System
ARRs	Auction Revenue Rights
Bechtel	Bechtel Power Corporation
Compensation Committee	Compensation Committee of the Board of Directors of Wisconsin Energy
CPCN	Certificate of Public Convenience and Necessity
D&D Fund	Uranium Enrichment Decontamination and Decommissioning Fund
Energy Policy Act	Energy Policy Act of 2005
Fitch	Fitch Ratings
FNTP	Full Notice To Proceed
FPL	FPL Group, Inc.
FTRs	Financial Transmission Rights
GCRM	Gas Cost Recovery Mechanism
GDP	Gross Domestic Product
Guardian	Guardian Pipeline L.L.C.
LLC	Limited Liability Company
LMP	Locational Marginal Price
LSEs	Load Serving Entities
MAIN	Mid-America Interconnected Network, Inc.
MISO	Midwest Independent Transmission System Operator, Inc.
MISO Energy Markets	MISO Energy and Operating Reserves Market
Moody’s	Moody’s Investor Service
NMC	Nuclear Management Company, LLC
NYMEX	New York Mercantile Exchange
OTC	Over-the-Counter
PJM	PJM Interconnection, L.L.C.
Point Beach	Point Beach Nuclear Power Plant
PRSG	Planning Reserve Sharing Groups
PTF	Power the Future
PUHCA 1935	Public Utility Holding Company Act of 1935
PUHCA 2005	Public Utility Holding Company Act of 2005
RFC	Reliability First Corporation
RSG	Revenue Sufficiency Guarantee
RTO	Regional Transmission Organizations
S&P	Standard & Poor’s Ratings Services
Measurements
Btu	British thermal unit(s)
Dth	Dekatherm(s) (One Dth equals one million Btu)
kW	Kilowatt(s) (One kW equals one thousand watts)
kWh	Kilowatt-hour(s)
MW	Megawatt(s) (One MW equals one million watts)
MWh	Megawatt-hour(s)
Watt	A measure of power production or usage
Accounting Terms
AFUDC	Allowance for Funds Used During Construction
ARO	Asset Retirement Obligation
CWIP	Construction Work in Progress
FASB	Financial Accounting Standards Board
FIN	FASB Interpretation

A-3

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS - (Cont’d)

The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below.

FSP	FASB Staff Position
GAAP	Generally Accepted Accounting Principles
OPEB	Other Post-Retirement Employee Benefits
SFAS	Statement of Financial Accounting Standards
Accounting Pronouncements
FIN 46	Consolidation of Variable Interest Entities
FIN 46R	Consolidation of Variable Interest Entities (Revised 2003)
FIN 47	Accounting for Conditional Asset Retirement Obligations
FIN 48	Accounting for Uncertainty in Income Taxes
FSP FIN 46(R)-8	Disclosures about Consolidation of Variable Interest Entities
SFAS 13	Accounting for Leases
SFAS 71	Accounting for the Effects of Certain Types of Regulation
SFAS 87	Employers’ Accounting for Pensions
SFAS 106	Employers’ Accounting for Postretirement Benefits Other Than Pensions
SFAS 109	Accounting for Income Taxes
SFAS 123R	Share-Based Payment (Revised 2004)
SFAS 133	Accounting for Derivative Instruments and Hedging Activities
SFAS 143	Accounting for Asset Retirement Obligations
SFAS 149	Amendment of SFAS 133 on Derivative Instruments and Hedging Activities
SFAS 157	Fair Value Measurements
SFAS 158	Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans
SFAS 159	The Fair Value Option for Financial Assets and Financial Liabilities
SFAS 161	Disclosures about Derivative Instruments and Hedging Activities

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Certain statements contained in this report are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. 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 these forward-looking statements. Forward-looking statements include, among other things, statements concerning management’s expectations and projections regarding earnings, 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. In some cases, 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,” “guidance,” “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. 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, 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; environmental incidents; electric transmission or gas pipeline system constraints; unanticipated organizational structure or key personnel changes; collective bargaining agreements with union employees or work stoppages; or inflation rates.

• Factors affecting the economic climate in our service territories such as customer growth; customer business conditions, including demand for their products and services; and changes in market demand and demographic patterns.

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• Timing, resolution and impact of future rate cases and negotiations, including recovery for new investments as part of Wisconsin Energy’s PTF strategy, environmental compliance, transmission service, fuel costs and costs associated with the implementation of the MISO Energy Markets.

• Regulatory factors such as changes in rate-setting policies or procedures; changes in regulatory accounting policies and practices; industry restructuring initiatives; transmission or distribution system operation and/or administration initiatives; required changes in facilities or operations to reduce the risks or impacts of potential terrorist activities; required approvals for new construction; and the siting approval process for new generation and transmission facilities and new pipeline construction.

• Increased competition in our electric and gas markets and continued industry consolidation.

• Factors which impede or delay execution of Wisconsin Energy’s PTF strategy, including the adverse interpretation or enforcement of permit conditions by the permitting agencies; construction delays; and obtaining the investment capital from outside sources necessary to implement the strategy.

• Factors which may affect successful implementation of the settlement agreement with the two parties who were challenging the WPDES permit for the Oak Creek expansion.

• The impact of recent and future federal, state and local legislative and regulatory changes, including electric and gas industry restructuring initiatives; changes to the Federal Power Act and related regulations under the Energy Policy Act and enforcement thereof by FERC and other regulatory agencies; changes in allocation of energy assistance, including state public benefits funds; changes in environmental, tax and other laws and regulations to which we are subject; and changes in the application of existing laws and regulations.

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

• Impacts of the significant contraction in the global credit markets affecting the availability and cost of capital.

• Other factors affecting our ability to access the capital markets, including general capital market conditions; our capitalization structure; market perceptions of the utility industry, us or our subsidiary; and our credit ratings.

• The investment performance of Wisconsin Energy’s pension and other post-retirement benefit plans.

• The effect of accounting pronouncements issued periodically by standard setting bodies.

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

• Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading markets and fuel suppliers and transporters.

• Other business or investment considerations that may be disclosed from time to time in our SEC filings or in other publicly disseminated written documents.

Wisconsin Electric Power Company expressly disclaims any 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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WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED SELECTED FINANCIAL AND STATISTICAL DATA

Financial	2008		2007		2006		2005		2004
Year Ended December 31
Earnings available for common stockholder (Millions)	$	280.1	$	287.7	$	275.6	$	283.6	$	248.7
Operating revenues (Millions)
Electric	$	2,660.6	$	2,674.6	$	2,499.5	$	2,320.9	$	2,070.8
Gas		709.2		611.9		590.0		593.6		523.8
Steam		40.3		35.1		27.2		23.5		22.0
Total operating revenues	$	3,410.1	$	3,321.6	$	3,116.7	$	2,938.0	$	2,616.6
At December 31 (Millions)
Total assets	$	8,775.4	$	8,312.8	$	8,257.8	$	7,909.2	$	7,050.3
Long-term debt and capital lease obligations (including current maturities)	$	2,886.4	$	1,990.4	$	2,152.1	$	2,058.5	$	1,706.8

CONSOLIDATED SELECTED QUARTERLY FINANCIAL DATA (Unaudited)

	(Millions of Dollars) (a)
	March				June
Three Months Ended	2008		2007		2008		2007
Total operating revenues	$	985.9	$	915.5	$	782.0	$	758.2
Operating income	$	141.1	$	119.6	$	86.8	$	88.0
Earnings available for common stockholder	$	83.6	$	69.9	$	51.9	$	55.6
	September				December
Three Months Ended	2008		2007		2008		2007
Total operating revenues	$	750.9	$	784.7	$	891.3	$	863.2
Operating income	$	119.4	$	140.7	$	134.6	$	142.5
Earnings available for common stockholder	$	73.7	$	84.8	$	70.9	$	77.4

(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.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

INTRODUCTION

Wisconsin Electric Power Company, a wholly-owned subsidiary of Wisconsin Energy, is engaged primarily in the business of generating electricity and distributing electricity and natural gas in Wisconsin and the Upper Peninsula of Michigan. Unless qualified by their context, when used in this document the terms Wisconsin Electric, the Company, our, us or we refer to Wisconsin Electric Power Company and its subsidiary.

Wisconsin Energy is also the parent company of Wisconsin Gas, a natural gas distribution utility, which serves customers throughout Wisconsin; Edison Sault, an electric utility which serves customers in the Upper Peninsula of Michigan; and We Power. We Power is principally engaged in the engineering, construction and development of electric generating power facilities for long-term lease to us under Wisconsin Energy’s PTF strategy. Wisconsin Electric and Wisconsin Gas have combined common functions and operate under the trade name of “We Energies.”

CORPORATE STRATEGY

Business Opportunities

Wisconsin Energy’s key corporate strategy is PTF, which was announced in September 2000. This strategy is designed to address Wisconsin’s growing electric supply needs by increasing the electric generating capacity in the state while maintaining a fuel-diverse, reasonably priced electric supply. It 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. Wisconsin Energy’s PTF strategy, which is discussed further below, is having, and is expected to continue to have, a significant impact on us. In July 2005, the first of four new electric generating units under the PTF strategy was placed into service. The second unit was placed into service in May 2008. Construction on the remaining two units is underway with OC 1 scheduled to be placed in service by the end of 2009 and OC 2 scheduled to be placed in service in the fall of 2010.

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

Power the Future Strategy: In February 2001, Wisconsin Energy filed a petition with the PSCW that would allow Wisconsin Energy to begin implementing its 10-year PTF strategy to improve the supply and reliability of electricity in Wisconsin. PTF is intended to meet a growing demand for electricity and ensure a diverse fuel mix while keeping electricity prices reasonable. Under PTF, Wisconsin Energy is (1) investing approximately $2.6 billion in 2,120 MW of new natural gas-fired and coal-fired generating capacity at existing sites; (2) upgrading our existing electric generating facilities; and (3) investing in upgrades of our existing energy distribution system.

In November 2001, Wisconsin Energy created We Power to design, construct, own and lease the new generating capacity. We 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, Wisconsin Energy expects to recover the investments in We Power’s new facilities over the initial lease term. At the end of the leases, we will have the right to acquire the plants outright at market value or to renew the leases. We expect that payments under the plant leases will be recoverable in rates under the provisions of the Wisconsin Leased Generation Law.

Under the PTF strategy, we expect a significant portion of our future generation needs will be met through We Power’s construction of the PWGS units and the Oak Creek expansion.

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As of December 31, 2008, Wisconsin Energy:

• Completed the construction of two 545 MW natural gas-fired intermediate load units in Port Washington, Wisconsin (PWGS 1 and PWGS 2). PWGS 1 and PWGS 2 were placed in service in July 2005 and May 2008, respectively. Both units are fully operational and were completed within the PSCW approved cost parameters.

• Has made significant progress on construction of the two 615 MW coal-fired base load units (OC 1 and OC 2) adjacent to the site of our existing Oak Creek Power Plant in Oak Creek, Wisconsin (the Oak Creek expansion), with OC 1 scheduled to be in service in late 2009 and OC 2 in fall 2010. All environmental permits have been received. The WDNR issued a final modified WPDES Permit in July 2008.

• Completed the planned sale of approximately a 17% (200 MW) ownership interest in the Oak Creek expansion to two co-owners. We will lease We Power’s approximate 515 MW interest in each unit.

Primary risks under PTF are construction risks associated with the schedule and costs for Wisconsin Energy’s Oak Creek expansion; changes in applicable laws or regulations; adverse interpretation or enforcement of permit conditions, laws or regulations by the permitting agencies; the ability 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 additional information regarding risks associated with the PTF strategy, including a discussion of the claims submitted by Bechtel, the contractor for the Oak Creek expansion, and the regulatory process and specific regulatory approvals, see Factors Affecting Results, Liquidity and Capital Resources below.

Sale of Point Beach: In September 2007, we sold Point Beach to an affiliate of FPL for approximately $924 million. Pursuant to the terms of the sale agreement, the buyer purchased Point Beach, its nuclear fuel and associated inventories, and assumed the obligation to decommission the plant. We retained approximately $506 million of the sales proceeds, which represents the net book value of the assets sold and certain transaction costs. In addition, we deferred the net gain on the sale of approximately $418 million as a regulatory liability and deposited those proceeds into a restricted cash account.

In connection with the sale, we also transferred $390 million of decommissioning funds to the buyer. We then liquidated the balance of the decommissioning trust assets and retained approximately $552 million, which was also placed into the restricted cash account. We are using the cash in the restricted cash account and the interest earned on the balance for the benefit of our customers and to pay certain taxes related to the liquidation of the qualified decommissioning trust. Our regulators are directing the manner in which these proceeds will benefit customers. For further information on the 2008 rate case, see Factors Affecting Results, Liquidity and Capital Resources — Rates and Regulatory Matters in this report.

A long-term power purchase agreement with the buyer became effective upon closing of the sale. Pursuant to this agreement, we are purchasing all of the energy produced by Point Beach. The power purchase agreement extends through 2030 for Unit 1 and 2033 for Unit 2. Based on the agreement, we are paying a predetermined price per MWh for energy delivered. For additional information on the sale of Point Beach, see Nuclear Operations under Factors Affecting Results, Liquidity and Capital Resources in this report.

RESULTS OF OPERATIONS

EARNINGS

2008 vs. 2007: Earnings decreased to $280.1 million in 2008 compared with $287.7 million in 2007. Operating income decreased $8.9 million between the comparative periods. During 2008, we experienced less favorable weather in the summer months, which decreased electric sales. In addition, our fuel and purchased power costs increased primarily as a result of the power purchase agreement entered into upon the sale of Point Beach. Finally, our other operation and maintenance expenses were higher primarily due to increased regulatory amortizations allowed in rates. These items were largely offset by our rate increases and increased margin from gas sales due to colder weather.

2007 vs. 2006: Earnings increased to $287.7 million in 2007 compared with $275.6 million in 2006. Operating income increased $34.9 million between the comparative periods. During 2007, we experienced more favorable weather which increased electric and gas sales. In addition, we experienced an increase in retail sales as a result of customer growth and we reached a settlement regarding a billing dispute with our largest customers, two iron ore mines. These items were partially offset by an increase in fuel and purchased power expenses.

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The following table summarizes our consolidated earnings during 2008, 2007 and 2006:

	2008			2007			2006
	(Millions of Dollars)
Utility Gross Margin
Electric (See below)	$	1,431.5		$	1,693.3		$	1,710.1
Gas (See below)		182.8			170.0			158.4
Steam		27.1			24.3			18.6
Total Gross Margin		1,641.4			1,887.6			1,887.1
Other Operating Expenses
Other operation and maintenance		1,295.2			1,041.9			1,074.5
Depreciation, decommissioning and amortization		256.0			269.7			270.9
Property and revenue taxes		96.4			91.7			85.8
Amortization of gain		(488.1	)		(6.5	)		—
Operating Income		481.9			490.8			455.9
Equity in Earnings of Transmission Affiliate		45.4			37.9			33.9
Other Income and Deductions, net		9.9			41.7			42.9
Interest Expense, net		86.6			93.0			87.0
Income Before Income Taxes		450.6			477.4			445.7
Income Taxes		169.3			188.5			168.9
Preferred Stock Dividend Requirement		1.2			1.2			1.2
Earnings Available for Common Stockholder	$	280.1		$	287.7		$	275.6

In September 2007, we sold Point Beach and commenced purchasing power from the new owner under a power purchase agreement. As a result of the sale and the power purchase agreement, our 2008 earnings reflect higher fuel and purchased power costs as compared to 2007. In addition, our 2008 operating income reflects lower other operation and maintenance costs and lower depreciation, decommissioning and amortization costs as we no longer own Point Beach.

In January 2008, we received a rate order from the PSCW that authorized a 17.2% increase in electric rates to recover increased costs associated with transmission expenses, Wisconsin Energy’s PTF program, environmental expenditures, continued investment in renewable and efficiency programs and recovery of previously deferred regulatory assets. The PSCW allowed us to issue bill credits to our customers from the proceeds of the net gain and excess decommissioning funds associated with the sale of Point Beach to mitigate this increase. As a result of these bill credits, we estimate that the January 2008 PSCW rate order resulted in a net 3.2% increase in electric rates paid by our Wisconsin customers in 2008 and will result in another net increase of 3.2% in 2009. The bill credits that we issue to our customers and the proceeds immediately applied to regulatory assets are reflected on our income statement in the amortization of the gain on the sale of Point Beach. As we issue the bill credits, we transfer the cash from a restricted account to an unrestricted account. The transferred cash is equal to the bill credits, less taxes.

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Electric Utility Gross Margin

The following table compares our electric utility gross margin during 2008 with similar information for 2007 and 2006, including a summary of electric operating revenues and electric sales by customer class:

	Electric Revenues and Gross Margin						Electric MWh Sales
Electric Utility Operations	2008		2007		2006		2008	2007	2006
	(Millions of Dollars)						(Thousands, Except Degree Days)
Customer Class
Residential	$	962.5	$	915.5	$	870.8	8,277.1	8,416.1	8,154.0
Small Commercial/Industrial		869.7		840.6		796.0	9,023.7	9,185.4	8,899.0
Large Commercial/Industrial		646.3		664.2		637.0	10,691.7	11,036.7	10,972.2
Other - Retail		20.8		19.2		18.9	161.5	162.4	163.7
Total Retail Sales		2,499.3		2,439.5		2,322.7	28,154.0	28,800.6	28,188.9
Wholesale - Other		77.7		83.5		68.1	2,620.7	1,939.6	1,819.0
Resale - Utilities		37.7		110.7		73.5	881.0	1,920.7	1,436.2
Other Operating Revenues		45.9		40.9		35.2	—	—	—
Total	$	2,660.6	$	2,674.6	$	2,499.5	31,655.7	32,660.9	31,444.1
Fuel and Purchased Power
Fuel		570.6		570.0		487.7
Purchased Power		658.5		411.3		301.7
Total Fuel and Purchased Power		1,229.1		981.3		789.4
Total Electric Gross Margin	$	1,431.5	$	1,693.3	$	1,710.1
Weather - Degree Days (a)
Heating (6,677 Normal)							7,073	6,508	6,043
Cooling (719 Normal)							593	800	723

(a) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.

Electric Utility Revenues and Sales

2008 vs. 2007: Our electric utility operating revenues decreased by $14.0 million, or 0.5%, when compared to 2007. The largest factor in this decline was a one-time $62.5 million FERC-approved refund to our wholesale customers associated with their share of the gain on the sale of Point Beach. Consistent with our past practices, the refund was recorded as a reduction in wholesale revenues. Because the refund came from the restricted cash associated with the sale of Point Beach, a corresponding entry was made to amortize the gain on the sale of Point Beach.

We also estimate that weather reduced our revenues by approximately $28.3 million for the year ended December 31, 2008 as compared to the same period in 2007. As measured by cooling degree days, 2008 was approximately 25.9% cooler than 2007 and 17.5% cooler than normal. Opportunity sales declined by approximately $73.0 million partially due to Edison Sault switching from a resale customer to a wholesale customer as of January 1, 2008, and because of less favorable weather, which reduced demand for our higher cost generation that was not being utilized to serve our retail customers. In addition, we experienced a $9.0 million decrease in revenue related to the settlement of a billing dispute with our largest customers, two iron ore mines, that occurred in 2007. Partially offsetting these decreases, we estimate that our electric revenues were approximately $142.9 million higher than the same period in 2007 because of pricing increases we received in the January 2008 PSCW rate case, the interim April 2008 and final July 2008 PSCW fuel orders, and a wholesale rate increase effective in May 2007. For more information on the pricing increases and the fuel cost adjustment clause, see Rates and Regulatory Matters in Factors Affecting Results, Liquidity and Capital Resources.

We estimate that sales to large commercial and industrial customers will decline in 2009 because of the current economic conditions. However, we expect our total electric utility operating revenues to increase in 2009 primarily due to the scheduled reduction of Point Beach bill credits, the full year impact of the 2008 rate increase and the impact of the one-time refund to FERC wholesale customers in 2008.

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2007 vs. 2006: Our electric utility operating revenues increased by $175.1 million, or 7.0%, when compared to 2006. The biggest drivers of the increase in revenues relate to the recognition of revenues attributable to fuel and purchased power of approximately $37.4 million and increased revenues related to Resale - Utilities of approximately $37.2 million. Our policy for electric fuel revenues is to not recognize revenue for any currently billable amounts if it is probable that we will refund those amounts to customers. In 2006, we experienced lower than expected fuel and purchased power costs, and we established $37.4 million of reserves to reflect amounts that were refunded to customers. No such reserves were established in 2007 as we experienced higher fuel and purchased power costs. The increase in Resale - Utilities reflects our ability to sell electricity into the MISO and PJM markets due to the increased availability of our baseload plants. Under the Wisconsin fuel rules, sales to other utilities reduce fuel costs charged to customers.

In addition, we estimate that $27.1 million of the increase in operating revenues relates to pricing increases. This increase primarily reflects rate increases received in late January 2006 that were in effect for the entire twelve months ended December 31, 2007 and a wholesale rate increase effective May 2007. We also estimate that $28.9 million of the increase was due to more favorable weather and $22.8 million relates to sales growth in residential and commercial sales. Finally, approximately $9.0 million of the increase relates to the settlement in the second quarter of 2007 of a billing dispute with our largest customers, two iron ore mines.

Our retail electric sales volume grew by approximately 2.2%. The increase in retail sales was driven by growth in residential and commercial sales and more favorable weather in 2007 as compared to the same period in 2006. In 2007, heating degree days increased by approximately 7.7% compared to 2006, and cooling degree days increased by approximately 10.7%.

Electric Fuel and Purchased Power Expenses

2008 vs. 2007: Our electric fuel and purchased power costs increased by $247.8 million, or approximately 25.3%, when compared to 2007. The largest factor related to this increase was the power purchase agreement we entered into in connection with the sale of Point Beach, which increased costs by approximately $247.0 million. In addition, in connection with the January 2008 PSCW rate order, we recorded a $41.2 million one-time amortization of deferred fuel costs in the first quarter of 2008. After adjusting for the Point Beach power purchase agreement and one-time amortization of deferred fuel costs, fuel and purchased power costs decreased by approximately $40.4 million, or 4.1%. Cost increases resulting from higher natural gas prices, purchased energy and coal and related transportation prices were more than offset by lower costs resulting from reduced MWh sales during 2008 as compared to 2007.

We expect that electric fuel and purchased power expenses in 2009 will be impacted by the price of natural gas, the increased cost of coal and related transportation prices, and changes in electric sales.

2007 vs. 2006: Our fuel and purchased power expenses increased by $191.9 million, or approximately 24.3%, when compared to 2006. Our total electric sales volume increased by approximately 3.9%, when compared to 2006. However, our average fuel and purchased power costs increased by $4.87 per MWh, or approximately 20.6%. The largest factors for the higher cost per MWh are the power purchase agreement entered into in connection with the sale of Point Beach, which increased total purchased power costs by approximately $47.0 million, increased coal and transportation costs, increased market prices for purchased energy and an increase in production of gas-fired generation used for opportunity sales.

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 2008, 2007 and 2006:

Gas Utility Operations	2008		2007		2006
	(Millions of Dollars)
Operating Revenues	$	709.2	$	611.9	$	590.0
Cost of Gas Sold		526.4		441.9		431.6
Gross Margin	$	182.8	$	170.0	$	158.4

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We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under our GCRM. The following table compares our gas utility gross margin and therm deliveries by customer class during 2008, 2007 and 2006:

	Gross Margin						Therm Deliveries
Gas Utility Operations	2008		2007		2006		2008	2007	2006
	(Millions of Dollars)						(Millions, Except Degree Days)
Customer Class
Residential	$	120.5	$	113.1	$	104.8	364.7	342.6	313.2
Commercial/Industrial		41.9		38.7		35.5	216.2	199.6	190.3
Interruptible		0.7		0.7		0.6	6.9	7.1	6.0
Total Retail Gas Sales		163.1		152.5		140.9	587.8	549.3	509.5
Transported Gas		15.8		15.6		15.4	313.3	333.7	303.1
Other		3.9		1.9		2.1	—	—	—
Total	$	182.8	$	170.0	$	158.4	901.1	883.0	812.6
Weather — Degree Days (a)
Heating (6,677 Normal)							7,073	6,508	6,043

(a) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.

2008 vs. 2007: Our gas margin increased by $12.8 million, or approximately 7.5%, when compared to 2007. We estimate that approximately $3.9 million of this increase related to pricing increases that we received in the January 2008 PSCW rate order. In addition, during 2008, approximately $2.6 million of additional revenues were earned under the incentive portion of the GCRM. We estimate that weather had a positive impact on our gas margin of approximately $5.2 million. Temperatures (as measured by heating degree days) were 8.7% colder in 2008 as compared to 2007 and 5.9% colder than normal. See Rates and Regulatory Matters under Factors Affecting Results, Liquidity and Capital Resources for information on our GCRM.

We expect our gas margin in 2009 will be impacted by weather; however, as noted above, 2008 was colder than normal.

2007 vs. 2006: Our gas margin increased by $11.6 million, or 7.3%, between the comparative periods. We estimate that approximately $8.7 million of this increase related to increased sales as a result of more normal winter weather. Temperatures (as measured by heating degree days) were approximately 7.7% colder in 2007 as compared to 2006. As a result, our retail therm deliveries increased approximately 7.8% from 2006. In addition, we estimate that our gas margin improved by $2.3 million due to a rate order that went into effect in the latter part of January 2006 and was effective for the entire twelve months ended December 31, 2007.

Other Operation and Maintenance Expense

2008 vs. 2007: Our other operation and maintenance expense increased by approximately $253.3 million, or 24.3%, when compared to 2007. The January 2008 PSCW rate order allowed for pricing increases related to transmission costs, PTF lease costs and the amortization of other deferred costs. These items were $243.1 million higher in 2008 as compared to 2007. In addition to these regulatory amortizations, in connection with the January 2008 PSCW rate order, we recorded a one-time $43.8 million amortization of deferred bad debt costs in the first quarter of 2008. We also incurred approximately $64.1 million of increased expenses related to the operation and maintenance of our power plants and electric distribution system. These increased costs were also considered in the rate setting process. These increases were partially offset by a $119.7 million decrease in nuclear operation and maintenance expense related to Point Beach as we no longer own the plant.

Our operation and maintenance expenses are influenced by wage inflation, employee benefit costs, plant outages and the amortization of regulatory assets. We expect our 2009 other operation and maintenance expense to decrease due to the impact of the $43.8 million one-time amortization of deferred bad debt costs in 2008 and other overall cost reduction efforts implemented in response to the current economic recession.

2007 vs. 2006: Our other operation and maintenance expense decreased by $32.6 million, or 3.0%, when compared to 2006. This decrease was primarily because of a decline in nuclear operations expense of approximately $37.8 million because we owned Point Beach for only nine months in 2007 as compared to a full year in 2006. Additionally, fossil operations expense decreased by approximately $6.0 million due to fewer planned outages in 2007 as compared to 2006. These decreases were partially offset by an increase of $11.4 million in regulatory amortizations as a result of the January 2006 rate order. The January 2006 rate order covered increased expenses related to transmission costs, bad debt costs and PTF costs.

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Depreciation, Decommissioning and Amortization Expense

2008 vs. 2007: Depreciation, decommissioning and amortization expense decreased by approximately $13.7 million, or 5.1%, when compared to 2007. The 2007 sale of Point Beach reduced depreciation, decommissioning and amortization expense by approximately $24 million as we no longer own the plant. Partially offsetting this decline was higher depreciation related to new projects including the Blue Sky Green Field wind project that was placed in service in May 2008.

We expect depreciation, decommissioning and amortization expense to increase in 2009 because of normal plant additions and a full year of depreciation on the Blue Sky Green Field wind project.

2007 vs. 2006: Depreciation, decommissioning and amortization expense decreased by $1.2 million, or 0.4%, when compared to 2006. This decrease reflects a reduction in depreciation and decommissioning costs related to the sale of Point Beach in September 2007 offset, in part, by normal plant additions.

Amortization of Gain

In connection with the September 2007 sale of Point Beach, we reached agreements with our regulators to allow for the net gain on the sale of approximately $902.2 million to be used for the benefit of our customers. The majority of the benefits are being returned to customers in the form of bill credits. The net gain was originally recorded as a regulatory liability, and it is being amortized to the income statement as we issue bill credits or make refunds to our customers. When the bill credits and refunds are issued to customers, we transfer cash from the restricted accounts to the unrestricted accounts, adjusted for taxes.

During 2008 and 2007, the Amortization of Gain was as follows:

Amortization of Gain	2008		2007
	(Millions of Dollars)
Bill Credits -Retail	$	340.6	$	6.5
One-Time FERC Refund		62.5		—
One-Time Amortization to Offset Regulatory Asset		85.0		—
Total Amortization of Gain	$	488.1	$	6.5

In 2009, we expect to see a reduction in the Amortization of Gain because of the one-time entries identified above as well as an approximate $100 million decrease in bill credits compared to 2008.

Other Income and Deductions, net

The following table identifies the components of consolidated other income and deductions, net during 2008, 2007 and 2006:

Other Income and Deductions, net	2008			2007			2006
	(Millions of Dollars)
Carrying Costs	$	0.8		$	28.8		$	25.0
Gain on Property Sales		2.3			12.9			3.2
AFUDC - Equity		7.5			5.1			14.5
Donations and Contributions		(12.0	)		(10.3	)		(6.0	)
Other, net		11.3			5.2			6.2
Total Other Income and Deductions, net	$	9.9		$	41.7		$	42.9

2008 vs. 2007: Other income and deductions, net decreased by $31.8 million when compared to 2007. In connection with the January 2008 PSCW rate order, we stopped accruing carrying charges on regulatory assets as we are now allowed a current return on them. Additionally, in 2007 we recognized approximately $12.9 million on property sales, most of which related to land sales in northern Wisconsin and the Upper Peninsula of Michigan, as compared to $2.3 million in 2008.

During 2009, we expect to see an increase in other income and deductions, net as we expect AFUDC - Equity to increase for the Oak Creek AQCS project.

2007 vs. 2006: Other income and deductions, net decreased by $1.2 million when compared to 2006. The reduction primarily reflects a decrease in AFUDC of $9.4 million in connection with environmental controls related to the new scrubber placed in service

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at our Pleasant Prairie Power Plant in the fourth quarter of 2006. This scrubber was installed as part of the implementation of our EPA Consent Decree. For further information on the Consent Decree with the EPA, see Note Q — Commitments and Contingencies in the Notes to Consolidated Financial Statements in this report. This reduction was offset, in part, by an increase in gains on sales of property primarily associated with land sold in northern Wisconsin and the Upper Peninsula of Michigan.

Interest Expense, net

Interest Expense, net	2008		2007		2006
	(Millions of Dollars)
Gross Interest Costs	$	89.6	$	94.8	$	92.1
Less: Capitalized Interest		3.0		1.8		5.1
Interest Expense, net	$	86.6	$	93.0	$	87.0

2008 vs. 2007: Interest expense, net decreased by $6.4 million in 2008 when compared with 2007. Our gross interest costs decreased by $5.2 million because of lower short-term interest rates that were offset in part by higher short-term debt balances. Our capitalized interest increased by $1.2 million primarily because of increased capital expenditures related to the Blue Sky Green Field wind project.

During 2009, we expect gross interest expense to increase due to a full year of interest expense on our $550 million of debt issued in the fourth quarter of 2008 and increased debt levels to fund our planned construction activity. We expect our capitalized interest to increase slightly due to increased capital expenditures. As a result, we expect our net interest expense to increase in 2009.

2007 vs. 2006: Interest expense, net increased by $6.0 million in 2007 when compared with 2006. This increase was due to a full year of interest on the $300 million of 5.70% Debentures that we issued in November 2006 and a reduction in capitalized interest due to lower construction levels.

Income Taxes

2008 vs. 2007: Our effective income tax rate was 37.6% in 2008 compared with 39.5% in 2007. For further information regarding income taxes, see Note F — Income Taxes in the Notes to Consolidated Financial Statements.

2007 vs. 2006: Our effective income tax rate was 39.5% in 2007 compared with 38.0% in 2006.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

The following table summarizes our cash flows during 2008, 2007 and 2006:

Wisconsin Electric	2008			2007			2006
	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$	362.9		$	213.8		$	498.5
Investing Activities	($	212.7	)	$	236.2		($	473.8	)
Financing Activities	($	143.8	)	($	446.2	)		($29.7	)

Operating Activities

2008 vs. 2007: Cash provided by operating activities was $362.9 million during 2008, which was $149.1 million higher than 2007. The primary drivers of this increase were the increased amortizations of deferred costs associated with regulatory assets and lower tax payments.

During 2008, we experienced increased amortizations of deferred costs associated with regulatory assets. During 2008, our cash income taxes were $326.9 million lower than 2007, primarily because of additional tax depreciation, increased deductions for contributions to Wisconsin Energy’s pension plan for our employees and deferred taxes associated with the nuclear decommissioning

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trust assets. In accordance with IRS guidelines, we completed a review in 2008 and concluded that certain timing items that historically had been capitalized and depreciated for tax purposes could be deducted currently. In January 2009, we contributed approximately $265 million to Wisconsin Energy’s qualified pension plan, which resulted in a tax deduction for 2008.

2007 vs. 2006: Cash provided by operating activities was $213.8 million during 2007, which is $284.7 million lower than 2006. This decline was primarily due to higher tax payments, lower fuel recoveries and changes in working capital. In 2007, we paid approximately $108 million in cash taxes because of the Point Beach sale and the liquidation of the nuclear decommissioning trust. In addition, cash taxes from operating income were higher due to higher taxable income. Our cash from fuel collections was unfavorable in 2007 as compared to 2006 because in 2006 we over-collected fuel and purchased power costs and in 2007 we under-collected such costs.

Investing Activities

2008 vs. 2007: Cash used in investing activities was $212.7 million compared to $236.2 million provided by investing activities during 2007. This reflects a reduction in proceeds from asset sales and increased capital expenditures during 2008, partially offset by an increase in restricted cash from the sale of Point Beach released to us.

During 2008, we released $345.1 million of restricted cash. In September 2007, we sold Point Beach and received approximately $924 million and retained approximately $552 million of decommissioning funds. We placed approximately $924 million in restricted accounts to be used for the payment of taxes and for the benefit of our customers. We release the restricted cash, adjusted for taxes, as we issue bill credits to our customers, which is reflected as an amortization of the gain on our income statement. We expect to release approximately $214.1 million of restricted cash during 2009 as we issue fewer bill credits to our retail customers from the Point Beach proceeds pursuant to the terms of our 2008 rate order.

During 2008, our capital expenditures increased by $42.7 million primarily due to increased construction spending related to the completion of our Blue Sky Green Field wind project and the start of construction of the Oak Creek AQCS project.

2007 vs. 2006: During 2007, net cash inflows from investing activities were $236.2 million compared with cash outflows of $473.8 million in 2006. The most significant factor related to cash provided by investing activities relates to the unrestricted proceeds we received from the sale of Point Beach as well as the liquidation of the decommissioning trusts. Our 2007 capital expenditures increased $82.3 million over 2006. This increase was expected and it primarily reflects our construction activity for environmental controls.

During 2007, we experienced a significant inflow of cash related to the sale of Point Beach; however, we restricted a significant amount of that cash as it will be used for the benefit of our customers. The 2007 cash flows related to the Point Beach sale are summarized as follows:

	(Millions of Dollars)
Proceeds from the sale of Point Beach	$	924.1
Proceeds from the liquidation of decommissioning trusts		552.4
Total Proceeds		1,476.5
Less: Proceeds restricted for the benefit of customers, net of taxes and bill credits		(731.6	)
Unrestricted cash to the Company	$	744.9

As the gain on the Point Beach sale is given back to customers, primarily in the form of bill credits, we release the restricted cash.

Financing Activities

The following table summarizes our cash flows from financing activities:

	2008			2007			2006
	(Millions of Dollars)
Dividends to Wisconsin Energy	($	367.0	)	($	179.6	)	($	179.6	)
Capital Contribution from Wisconsin Energy		—			—			100.0
Increase (Reduction) in Total Debt		225.3			(271.9	)		50.0
Other		(2.1	)		5.3			(0.1	)
Cash Used in Financing		($143.8)			($446.2)			($29.7)

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2008 vs. 2007: Cash used in financing activities was $143.8 million during 2008 as compared to $446.2 million during 2007. During 2008, we issued $550 million of debentures. The net proceeds were used to repay short-term debt and for other general corporate purposes, including the payment of a $150 million special dividend to Wisconsin Energy to rebalance our capital structure for the impact of the sale of Point Beach. For additional information on the debt issuances, see Note I — Long-Term Debt in the Notes to Consolidated Financial Statements.

2007 vs. 2006: During 2007, we used $446.2 million for net financing activities compared with $29.7 million during 2006. During 2007, we retired $250 million of unsecured 3.50% debentures due December 1, 2007 at their scheduled maturity.

CAPITAL RESOURCES AND REQUIREMENTS

Capital Resources

We anticipate meeting our capital requirements during 2009 primarily through internally generated funds and short-term borrowings, supplemented by the issuance of intermediate or long-term debt securities, depending on market conditions and other factors. Beyond 2009, we anticipate meeting our capital requirements through internally generated funds supplemented, when required, by short-term borrowings, the issuance of debt securities and equity contributions from our parent.

During the second half of 2008, the global credit markets suffered a significant contraction, including the failure of some large financial institutions. As a result, interest rates on our short-term and variable rate tax-exempt debt increased during the second half of 2008, but have since stabilized. Despite the turmoil in the credit markets, we were able to remarket our $147 million tax-exempt bonds in August 2008 and to issue in October 2008 $300 million of 6.00% Debentures due April 1, 2014 and in December 2008 $250 million of 6.25% Debentures due December 1, 2015.

As indicated above, despite the recent turmoil in the global credit markets, we still currently have access to the capital markets and have been able to generate funds internally and externally to meet our capital requirements. Our ability to attract the necessary financial capital at reasonable terms is critical to our overall strategic plan. We currently believe that we have adequate capacity to fund our operations for the foreseeable future through our existing borrowing arrangement, access to capital markets and internally generated cash. Our short-term interest rates have stabilized and currently are lower than they were during the second half of 2008.

We maintain a bank back-up credit facility that provides liquidity support for our obligations with respect to commercial paper and for general corporate purposes.

An affiliate of Lehman Brothers Holdings, which filed for bankruptcy in September 2008, committed approximately $23.6 million under our bank back-up credit facility. We have no current plans to replace Lehman’s commitment. Excluding Lehman’s commitment, as of December 31, 2008, we had approximately $472.3 million of available, undrawn lines under our bank back-up credit facility. As of December 31, 2008, we had approximately $29.6 million of short-term debt outstanding that was supported by the available line of credit.

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 facility as of December 31, 2008:

Total Facility *	Letters of Credit		Credit Available *		Facility Expiration	Facility Term
	(Millions of Dollars)
$476.4	$	4.1	$	472.3	March 2011	5 year

* Excludes Lehman’s commitment

This facility has a renewal provision for two one-year extensions, subject to lender approval.

In connection with the conversion of the interest rate determination method for certain of our tax-exempt bonds in August 2008, we terminated our $100 million six-month bank back-up credit facility that was scheduled to expire in September 2008.

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The following table shows our consolidated capitalization structure as of December 31:

Capitalization Structure	2008				2007
	(Millions of Dollars)
Common Equity	$	2,582.8	46.7	%	$	2,656.2	52.8	%
Preferred Stock		30.4	0.6	%		30.4	0.6	%
Long-Term Debt (a)		1,885.3	34.1	%		1,338.1	26.6	%
Capital Lease Obligations (a)		1,001.1	18.1	%		652.3	13.0	%
Short-Term Debt (b)		29.6	0.5	%		354.3	7.0	%
Total	$	5,529.2	100.0	%	$	5,031.3	100.0	%

(a) Includes current maturities

(b) Includes subsidiary note payable to Wisconsin Energy

We recorded a $331.1 million capital lease in May 2008 in connection with the in-service date of PWGS 2. We recorded a $162.1 million capital lease in November 2007 in connection with the in-service date of the Oak Creek coal handling system. For additional information, see Note I — Long-Term Debt in the Notes to Consolidated Financial Statements.

Access to capital markets at a reasonable cost is determined in large part by credit quality. The following table summarizes the ratings of our debt securities and preferred stock by S&P, Moody’s and Fitch as of December 31, 2008:

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

In July 2008, S&P affirmed our corporate credit rating and revised our ratings outlook from stable to positive.

On April 30, 2008, Fitch affirmed our ratings and our stable ratings outlook.

Our security ratings outlook assigned by Moody’s is stable.

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

Capital Requirements

Total capital expenditures are currently estimated to be approximately $600 million during 2009. Due to changing environmental and other regulations such as air quality standards and electric reliability initiatives that impact us, future long-term capital requirements may vary from recent capital requirements. We currently expect these capital expenditures to be between $600 million and $1 billion per year during the next three years.

The expected increase in our capital expenditures is related to the Oak Creek AQCS project that is expected to be completed in 2012 and the Glacier Hills Wind Park that is also expected to be completed by 2012.

Investments in Outside Trusts: We have funded our pension obligations and certain OPEB obligations in outside trusts. Collectively, these trusts had investments of approximately $608 million as of December 31, 2008. These trusts hold investments that are subject to the volatility of the stock market and interest rates.

We have defined benefit pension plans that cover substantially all of our employees. During 2008, we contributed $37.9 million to Wisconsin Energy’s qualified pension plan. As of December 31, 2008, the returns on Wisconsin Energy’s pension plan assets were significantly below the expected annual returns of 8.5%. In January 2009, we contributed approximately $265 million to Wisconsin Energy’s qualified pension plan. Future contributions to the plans will be dependent upon many factors, including the performance of

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existing plan assets and long-term discount rates. For further information, see Note M — Benefits in the Notes to Consolidated Financial Statements.

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

We have identified two tolling and purchased power agreements with third parties but have been unable to determine if we are the primary beneficiary of these two variable interest entities as defined by 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 contract as an operating lease, and both are reflected in the Contractual Obligations/Commercial Commitments table below. A similar power purchase agreement expired during the second quarter of 2008. For additional information, see Note E — Variable Interest Entities in the Notes to Consolidated Financial Statements.

Contractual Obligations/Commercial Commitments: We have the following contractual obligations and other commercial commitments as of December 31, 2008:

	Payments Due by Period
Contractual Obligations (a)	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
	(Millions of Dollars)
Long-Term Debt Obligations (b)	$	3,922.7	$	101.1	$	202.9	$	496.1	$	3,122.6
Capital Lease Obligations (c)		3,609.1		158.9		320.9		326.5		2,802.8
Operating Lease Obligations (d)		97.8		23.6		41.6		20.0		12.6
Purchase Obligations (e)		14,211.9		977.2		1,738.5		976.8		10,519.4
Other Long-Term Liabilities (f)		66.4		64.9		1.5		—		—
Total Contractual Obligations	$	21,907.9	$	1,325.7	$	2,305.4	$	1,819.4	$	16,457.4

(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 Long-Term Debt (excluding capital lease obligations).

(c) Capital Lease Obligations for power purchase commitments and the PTF leases.

(d) Operating Lease Obligations for power purchase commitments and vehicle and rail car leases.

(e) Purchase Obligations under various contracts for the procurement of fuel, power, gas supply and associated transportation and for information technology and other services for utility operations. This includes the power purchase agreement for all of the energy produced by Point Beach.

(f) Other Long-Term Liabilities include the expected 2009 supplemental executive retirement plan obligation and non-discretionary pension contribution. For additional information on employer contributions to our benefit plans see Note M — Benefits in the Notes to Consolidated Financial Statements.

The table above does not include FIN 48 liabilities. For further information regarding FIN 48 liabilities, refer to Note F — Income Taxes in the Notes to Consolidated Financial Statements in this report.

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

FACTORS AFFECTING RESULTS, LIQUIDITY AND CAPITAL RESOURCES

MARKET RISKS AND OTHER SIGNIFICANT RISKS

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

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Regulatory Recovery: We account for our regulated operations in accordance with SFAS 71. 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 Prices: In the normal course of providing energy, we are subject to market fluctuations of the costs of coal, natural gas, purchased power and fuel oil used in the delivery of coal. 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, natural gas and fuel oil. In addition, we manage the risk of price volatility by utilizing gas and electric hedging programs.

Wisconsin’s retail electric fuel cost adjustment procedure mitigates some of our risk of electric fuel cost fluctuation. If cumulative fuel and purchased power costs for electric utility operations deviate from a prescribed range (plus or minus 2% for 2009) when compared to the costs projected in the most recent retail rate proceeding, retail electric rates may be adjusted prospectively. For information regarding the current fuel rules, see Rates and Regulatory Matters.

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

Natural Gas Costs: Significant volatility in the cost of natural gas affects our electric and gas utility operations. Although the cost of natural gas has decreased recently, natural gas costs have generally increased since 2003. 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 resources are developed.

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 over the recent year, our risks related to bad debt expenses have 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 exceeds amounts allowed in rates. In July 2008, we filed an application with the PSCW for a three year extension of use of the escrow method for bad debt costs. In December 2008, the PSCW approved a one year extension of use of the escrow method of accounting for bad debt costs through March 2010.

As a result of our GCRM, our gas distribution operation receives 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.

Weather: Our Wisconsin utility rates are set by the PSCW based upon estimated temperatures which approximate 20-year averages. Our electric revenues are unfavorably sensitive to below normal temperatures during the summer cooling season, and to some extent, to above normal temperatures during the winter heating season. Our gas revenues are unfavorably sensitive to above normal temperatures during the winter heating season. A summary of actual weather information in our service territory during 2008, 2007 and 2006, as measured by degree-days, may be found above in Results of Operations.

Interest Rate: We have various short-term borrowing arrangements to provide working capital and general corporate funds. We also have variable rate long-term debt outstanding as of December 31, 2008. Borrowing levels under these arrangements vary from period to period depending on 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, 2008 of our outstanding portfolio of commercial paper and variable rate long-term debt. As of December 31, 2008, we did not have any commercial paper outstanding. We had $164.4 million of variable-rate long-term debt outstanding with a weighted average interest rate of 0.92%. A one-percentage point change in interest rates would cause our annual interest expense to increase or decrease by approximately $1.6 million before taxes from variable rate long-term debt outstanding.

Marketable Securities Return: We fund our pension and OPEB obligations through various trust funds, which in turn invest in debt and equity securities. Changes in the market prices of these assets can affect future pension and OPEB expenses. Additionally, future

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contributions 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.

At December 31, 2008, we held, or Wisconsin Energy held on our behalf, the following total trust fund assets at fair value, primarily consisting of publicly traded debt and equity security investments:

Wisconsin Electric Power Company	Millions of Dollars
Pension trust funds	$	510.7
Other post-retirement benefits trust funds	$	97.0

Fiduciary oversight of the pension and OPEB 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 8.25%.

Credit Ratings: 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 contracts and employee benefit plans that could require collateral or a termination payment only in the event of a credit rating change to below investment grade. As of December 31, 2008, we estimate that the collateral or the termination payment required under these agreements totaled approximately $160.3 million. In addition, we have commodity contracts that in the event of a credit rating downgrade could result in a reduction of our unsecured credit granted by counterparties.

Economic Conditions: We are exposed to market risks in the regional Midwest economy. Although the economy in our service territories has not been hit as hard as in other parts of the country, we are beginning to see an increase in unemployment and declines in industrial production demand. We expect the weakening economy to negatively impact our sales growth and bad debt levels.

Inflation: We continue to monitor the impact of inflation, especially with respect to the costs of medical plans, fuel, transmission access, construction costs, regulatory and environmental compliance and new generation in order to minimize its effects in future years through pricing strategies, productivity improvements and cost reductions. We do not believe the impact of general inflation will have a material impact on our future results of operations.

For additional information concerning risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report.

POWER THE FUTURE

Under Wisconsin Energy’s PTF 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 us under long-term leases, and we expect to recover the lease payments in our electric rates. Our lease payments are based on the cash costs authorized by our primary regulator to We Power.

The PTF units include PWGS 1, PWGS 2, OC 1 and OC 2. The following table identifies certain key items related to the units:

Unit Name	Scheduled In Service	Authorized Cash Costs (a)
PWGS 1	July 2005 (Actual)	$	333 million	(Actual)
PWGS 2	May 2008 (Actual)	$	331 million	(Actual)
OC 1	Late 2009	$	1,300 million
OC 2	Fall 2010	$	640 million

(a) Authorized cash costs represent the PSCW approved costs and the increases for factors such as inflation as identified in the PSCW approved lease terms and adjusted for Wisconsin Energy’s ownership percentages in the case of OC 1 and OC 2.

Power the Future - Port Washington

Background: In December 2002, the PSCW issued a written order (the Port Order) granting a CPCN for the construction of PWGS consisting of two 545 MW natural gas-fired combined cycle generating units on the site of our existing Port Washington Power Plant,

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the natural gas lateral to supply the new plant, and the transmission system upgrades required of ATC. PWGS 1 and PWGS 2 were completed within the PSCW approved cost parameters and were placed in service in July 2005 and May 2008, respectively.

Lease Terms: The PSCW approved the lease agreements and related documents under which we will staff, operate and maintain PWGS 1 and PWGS 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% after tax on equity;

• Fixed construction cost of PWGS 1 and PWGS 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.

Legal and Regulatory Matters: As a result of the enactment of the Energy Policy Act, 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). Under FERC’s rules implementing the Energy Policy Act, we, along with Wisconsin Energy and We Power, filed a joint application for FERC authorization to transfer the generating assets and limited interconnection facilities of PWGS 2 through a lease arrangement between We Power and us. Approval was received from FERC for this asset transfer in December 2006.

Power the Future - Oak Creek Expansion

Background: In November 2003, the PSCW issued an order (the Oak Creek Order) granting us, along with Wisconsin Energy and We Power, a CPCN to commence construction of two 615 MW coal-fired units (the Oak Creek expansion) to be located adjacent to the site of our existing Oak Creek Power Plant. OC 1 is scheduled to be operational in late 2009 and OC 2 is scheduled to be operational in fall 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. Costs above the 5% cap would not be included in lease payments or recovered from customers absent a finding by the PSCW of extenuating circumstances, such as force majeure conditions. 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, Wisconsin Energy completed the sale of approximately a 17% interest in the project to two unaffiliated entities who will share ratably in the construction costs.

The Oak Creek expansion includes a new coal handling system that will serve both the existing units at Oak Creek and OC 1 and OC 2. The new coal handling system was placed into service during the fourth quarter of 2007 at a cost of approximately $175.0 million. A total of $24.1 million of additional costs related to the coal handling system were incurred during 2008. The most significant component of this additional cost was the rail cars, which were placed in service in 2008, that will supply coal to OC 1 and OC 2.

The Oak Creek expansion also includes a new water intake system that will serve both the existing units at Oak Creek and OC 1 and OC 2. The new water intake system was placed into service in January 2009 at a cost of approximately $133.0 million.

Lease Terms: In October 2004, the PSCW approved the lease generation contracts between us 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% after tax 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.

Construction Status: In July 2008, Bechtel, the contractor of the Oak Creek expansion under a fixed price contract, notified We Power in a letter that it forecasts the in-service date of unit 1 to be delayed three months beyond the guaranteed contract date of September 29, 2009. Bechtel also advised We Power in the letter that it forecasts the in-service date of unit 2 to be one month earlier than the guaranteed contract date of September 29, 2010.

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According to the letter, reasons for the delay of unit 1 include severe winter weather experienced during the winters of 2006-2007 and 2007-2008, exacerbated by severe rain storms in April and June of 2008, changes in local labor conditions from those anticipated by Bechtel, the cumulative impact of a large number of change orders and delay in receiving FNTP in 2005 as a result of the court challenges by certain opposition groups to the CPCN for the Oak Creek expansion. Bechtel advised that they expected to submit a claim for cost and schedule relief associated with these issues by the end of 2008.

Based on Bechtel’s earlier communications, We Power notified Bechtel on September 29, 2008 that it was invoking the formal dispute resolution process provided in the contract in order to resolve certain issues related to the rights of the parties under the contract.

We Power received Bechtel’s claims for schedule and cost relief on December 22, 2008. Bechtel’s claims are based on the alleged effects of severe winter weather and certain labor-related matters, as well as the alleged effects of ERS-directed changes and delays allegedly caused by ERS prior to the issuance of the FNTP in July 2005. Bechtel continues to target an in-service date for unit 1 three months beyond the guaranteed contract date of September 29, 2009, and an in-service date for unit 2 one month earlier than the guaranteed contract date of September 29, 2010.

We Power is currently in the mediation phase with respect to determining the parties’ rights under the contract and Bechtel’s claims. We Power is currently unable to predict the ultimate outcome of the claims.

WPDES Permit: In March 2007, on appeal, the Dane County Circuit Court affirmed in part an earlier decision by an ALJ in a contested case hearing to uphold the WDNR’s issuance of the WPDES permit. The Court also remanded certain aspects of the ALJ’s decision for further consideration based on the January 2007 decision by the United States Court of Appeals for the Second Circuit that found certain portions of the federal rule concerning cooling water intake systems for existing facilities (the Phase II rule) impermissible and remanded several parts of the rule to the EPA for further consideration or potential rulemaking. In July 2007, the EPA formally suspended the Phase II rule in its entirety and directed states to use their “best professional judgment” in evaluating intake systems for existing facilities.

In November 2007, the ALJ determined that the Oak Creek expansion units were new facilities under Section 316(b) of the Clean Water Act. The ALJ remanded the WPDES permit to the WDNR and directed the WDNR to reissue or modify the permit to reflect “best technology available” to comply with the standards applicable to new facilities under Wisconsin state law. In July 2008, the WDNR issued the final modified permit. The time period for any party to challenge the modified WPDES permit has expired.

In July 2008, we, along with the joint owners of the Oak Creek expansion, reached an agreement with Clean Wisconsin, Inc. and Sierra Club, the groups who were opposing the WPDES permit. Under the settlement agreement, these groups agreed to withdraw their opposition to the modified WPDES permit for the existing and expansion units at Oak Creek.

In the agreement with Clean Wisconsin, Inc. and Sierra Club, we committed to contribute our share of $5 million (approximately $4.2 million) towards projects to reduce greenhouse gas emissions. We also agreed (i) for the 25 year period ending 2034, subject to regulatory approval and cost recovery, to contribute our share of up to $4 million per year (approximately $3.3 million) to fund projects to address Lake Michigan water quality, and (ii) subject to regulatory approval and cost recovery, to develop new solar and biomass generation projects. We also agreed to support state legislation to increase the renewable portfolio standard to 10 percent by 2013 and 25 percent by 2025, and to retire 116 MW of coal-fired generation at our Presque Isle Power Plant.

Other Regulatory Matters: As a result of the enactment of the Energy Policy Act, 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). Under FERC’s rules implementing the Energy Policy Act, we, along with Wisconsin Energy and We Power, filed a joint application for FERC authorization to transfer the generating assets and limited interconnection facilities of OC 1 and OC 2 through a lease arrangement between We Power and us. We received approval from FERC on these leases in December 2006.

RATES AND REGULATORY MATTERS

The PSCW regulates our retail electric, natural gas and steam rates in the state of Wisconsin, while FERC regulates our wholesale power and electric transmission service rates. The MPSC regulates our retail electric rates in the state of Michigan. We estimate that approximately 91% of our electric revenues are regulated by the PSCW, 5% are regulated by the MPSC and the balance of our electric revenues is regulated by FERC. All of our natural gas and steam 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/.

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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)
Fuel electric, Michigan	$	5.4	4.0	%	January 1, 2009
Retail electric, Michigan	$	7.2	4.6	%	January 1, 2009
Fuel electric, Wisconsin	$	118.9	5.1	%	July 8, 2008
Retail electric, Wisconsin	$	389.1	17.2	%	January 17, 2008
Retail gas, Wisconsin	$	4.0	0.6	%	January 17, 2008
Retail steam, Wisconsin	$	3.6	11.2	%	January 17, 2008
Retail electric, Michigan	$	0.3	0.6	%	May 23, 2007
Fuel electric, Michigan	$	3.4	7.5	%	January 1, 2007
Retail electric, Wisconsin	$	222.0	10.6	%	January 26, 2006
Retail gas, Wisconsin	$	21.4	2.9	%	January 26, 2006
Retail steam, Wisconsin	$	7.8	31.5	%	January 26, 2006
Fuel electric, Michigan	$	2.7	5.9	%	January 1, 2006

2008 Pricing: During 2007, we initiated rate proceedings. We asked the PSCW to approve a comprehensive plan which would result in price increases of $648.6 million for our electric customers in Wisconsin. This price increase would be reduced by expected bill credits resulting from the sale of Point Beach. The initial rate filing estimated bill credits of $371.0 million in 2008 and $187.5 million in 2009, resulting in net pricing increases of 7.5% in 2008 and 7.5% in 2009. In addition, we requested a 1.8% price increase in 2008 for our gas customers and an approximately 16.0% price increase in 2008 for all steam customers in metropolitan Milwaukee.

Electric pricing increases were needed to allow us to continue progress on previously approved initiatives, including: costs associated with the new PTF plants; recovery of costs associated with transmission; compliance with environmental regulations; continuation of investment in renewable and efficiency programs, including the Blue Sky Green Field wind project; and scheduled recovery of regulatory assets.

On January 17, 2008, the PSCW approved pricing increases for us as follows:

• $389.1 million (17.2%) in electric rates—the pricing increase will be offset by $315.9 million in bill credits in 2008 and $240.7 million in bill credits in 2009, resulting in a net increase of $73.2 million (3.2%) and $75.2 million (3.2%), respectively;

• $4.0 million (0.6%) for natural gas service; and

• $3.6 million (11.2%) for steam service.

In addition, the PSCW lowered our return on equity from 11.2% to 10.75%. The PSCW also determined that $85.0 million of the Point Beach proceeds should be immediately applied to offset certain regulatory assets.

We expect to provide a total of approximately $710.0 million of bill credits to our Wisconsin customers over the three year period ending December 31, 2010. As of December 31, 2008, we have issued approximately $296.4 million of bill credits to Wisconsin retail customers.

Michigan Price Increase: In January 2008, we filed a rate increase request with the MPSC. This request represents an increase in electric rates of 14.7%, or $22.0 million, to support the growing demand for electricity, continued investment in renewable programs, compliance with environmental regulations, addition of distribution infrastructure and increased operational expenses. In November 2008, a settlement agreement with the MPSC staff and intervenors for a rate increase of $7.2 million, or 4.6%, was approved by the MPSC, effective January 1, 2009.

2006 Pricing: In January 2006, we received an order from the PSCW that allowed us to increase annual electric revenues by approximately $222.0 million, or 10.6%, to recover increased costs associated with investments in Wisconsin Energy’s PTF units, transmission services and fuel and purchased power, as well as costs associated with additional sources of renewable energy. The rate increase was based on an authorized return on equity of 11.2%. The order also required us to refund to customers, with interest, any fuel revenues that we receive that are in excess of fuel and purchased power costs that we incur, as defined by the Wisconsin fuel rules. The original order stipulated that any refund would also include interest at short-term rates. This refund provision did not extend past December 31, 2006.

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During 2006, we experienced lower than expected fuel and purchased power costs. In September 2006, we requested and received approval from the PSCW to refund favorable fuel recoveries including accrued interest at a short-term rate. In addition, in September 2006 the PSCW determined that if the total recoveries for 2006 exceeded $36 million, interest on the amount in excess of $36 million would be paid at the rate of 11.2%, our authorized return on equity rather than at short-term rates as originally set forth in the order. During October 2006, we refunded $28.7 million, including interest, to Wisconsin retail customers as a credit on their bill and we received approval from the PSCW to refund an additional $10 million, including interest, in the first quarter of 2007.

Our gas operations went through a traditional rate proceeding whereby the revenues were set to recover projected costs and to provide a return on rate base. The January 2006 order provided for an increase in gas revenues totaling $21.4 million, or 2.9%. The rate increase was based on an authorized return on equity of 11.2%.

The steam rate proceeding was a traditional rate proceeding. The January 2006 order provided for an increase in steam rates of $7.8 million, or 31.5%, to be phased in over a two year period beginning in 2006. The rate increase was based on an authorized return on equity of 11.2%.

2010 Pricing: We anticipate filing a rate case in the first half of 2009 for new rates effective in January 2010.

Limited Rate Adjustment Requests

2008 Fuel Recovery Request: In March 2008, we filed a rate increase request with the PSCW to recover forecasted increases in fuel and purchased power costs. The increase in fuel costs was being driven primarily by increases in the price of natural gas and the higher cost of transporting coal by rail as a result of increases in the cost of diesel fuel. On April 11, 2008, the PSCW approved an annual increase of $76.9 million (3.3%) in Wisconsin retail electric rates on an interim basis. In July 2008, we received the final rate order, which authorized an additional $42.0 million in rate increases, for a total increase of $118.9 million (5.1%). Any over-collection of fuel surcharge revenue in calendar year 2008 was subject to refund with interest at a rate of 10.75%. During the first quarter of 2009, we expect to refund approximately $8.6 million, including interest, to Wisconsin retail customers related to the over-collection of fuel costs in 2008.

Other Rate Matters

Oak Creek Air Quality Control System Approval: As anticipated, in July 2008 we received approval from the PSCW granting us authority to construct wet flue gas desulfurization and selective catalytic reduction facilities at Oak Creek Power Plant Units 5-8. Construction of these emission controls began in late July 2008, and we expect the installation to be completed during 2012. We originally estimated the cost of this project to be $830 million including AFUDC ($750 million excluding AFUDC). We now expect the cost of completing this project to be approximately $885 million including AFUDC ($800 million excluding AFUDC). The cost increase is primarily attributable to increases in material prices that occurred prior to the commencement of construction and material procurement activities in July 2008. The cost of constructing these facilities is included in our estimates of the costs to implement the Consent Decree with the EPA. The Citizens Utility Board and Clean Wisconsin, Inc., the two groups that opposed controlling Oak Creek Power Plant Units 5-8, petitioned the PSCW for rehearing and reconsideration of its order. The PSCW denied their request and the petitioners did not appeal the PSCW’s decision.

Michigan Legislation: During October 2008, Michigan enacted legislation to make significant changes in regulatory procedures, which should provide for more timely cost recovery. Public Act 286 allows the use of a forward-looking test year in rate cases, rather than historical data, and allows us to put interim rates into effect six months after filing a complete case. Rate filings for which an order is not issued within 12 months are deemed approved. In addition, we could seek a CPCN for new investment, and could recover interest on the investment during construction. Public Act 286 also gives the MPSC expanded authority over proposed mergers and acquisitions, and requires action within 180 days of filing. In addition, Public Act 295 calls for the implementation of a renewable portfolio standard of 10% by 2015, and energy optimization (efficiency) targets up to 1% annually by 2015. Public Act 295 specifically calls for current recovery of costs incurred to meet the standards, and provides for ongoing review and revision to assure the measures taken are cost-effective.

Fuel Cost Adjustment Procedure: Within the state of Wisconsin, we operate under a fuel cost adjustment clause for fuel and purchased power costs associated with the generation and delivery of electricity and purchase power contracts. Embedded within our 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 embedded 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 costs fall outside of established fuel bands, then we may file for a change in fuel recoveries on a prospective basis.

In June 2006, the PSCW opened a docket (01-AC-224) to consider revisions to the existing fuel rules (Chapter PSC 116). Public comments from stakeholders, including regulated utilities, were received by the PSCW. In July 2008, the PSCW ordered a second

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comment period on a revised rule, and hearings were held in August 2008. The current version of the revised rule recommends modifications to allow for annual plan and reconciliation filings of fuel costs by each regulated utility. In the period between plan and reconciliation, escrow accounting would be used to record fuel costs outside a plus or minus 2% annual band of the total fuel costs allowed in rates. The proposed rule further recommends that the escrow balance be trued-up annually following the end of each calendar year. The earliest that we expect any possible action on the fuel rules is the summer of 2009.

Our electric operations in Michigan operate under a Power Supply Cost Recovery mechanism which generally allows for the recovery of fuel and purchased power costs on a dollar for dollar basis.

Electric Transmission Cost Recovery: We divested our transmission assets with the formation of ATC in January 2001. We now procure transmission service from ATC at FERC approved tariff rates. In connection with the formation of ATC, our transmission costs have escalated due to the socialization of costs within 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 us to use escrow accounting whereby we defer transmission costs that exceed amounts embedded in our rates. We are allowed to earn a return on the unrecovered transmission costs we deferred at our weighted average cost of capital. As of December 31, 2008, we have deferred $199 million of unrecovered transmission costs. The January 2008 rate order provided for the recovery of these costs over six years beginning in January 2008, and the escrow accounting treatment has been discontinued.

Gas Cost Recovery Mechanism: Our natural gas operations operate under a 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 2008, approximately $2.6 million of additional revenues were earned under the incentive portion of the GCRM. During 2007 and 2006, no additional revenues were earned under the incentive portion of the GCRM.

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 for our gas operations. The bad debts deferred in 2004 related to electric operations will be considered for recovery in future rates, subject to audit and approval of the PSCW.

In March 2005, the PSCW approved our use of escrow accounting for residential bad debt costs. 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, which extends through March 2009, we escrowed approximately $5.2 million, $9.5 million and $6.0 million in 2008, 2007 and 2006, respectively, related to bad debt costs. In July 2008, we filed an application with the PSCW for a three year extension of use of the escrow method for bad debt costs. In December 2008, the PSCW approved a one year extension for the use of the escrow method of accounting for bad debt costs through March 2010.

MISO Energy Markets: The PSCW approved deferral treatment for our costs related to the implementation of the MISO Energy Markets. Amounts deferred through December 31, 2007 are being recovered in rates. For additional information, see Industry Restructuring and Competition — Electric Transmission and Energy Markets.

Coal Generation Forced Outage - 2007: In March 2007, we requested and received approval from the PSCW to defer as a regulatory asset approximately $13.2 million related to replacement power costs due to a forced outage of Unit 1 at the Pleasant Prairie Power Plant. The outage extended from February 2007 through March 2007. These costs were recovered as part of the $85 million one-time recovery using Point Beach proceeds pursuant to the 2008 rate order in a write-off during the first quarter of 2008.

Wholesale Electric Pricing: In August 2006, we filed a wholesale rate case with FERC. The filing requested an annual increase in rates of approximately $16.7 million applicable to four existing wholesale electric customers. This includes a mechanism for fuel and other cost adjustments. In November 2006, FERC approved the rate filing subject to refund with interest. Three of the existing customers’ rates were effective in January 2007. The remaining wholesale customer’s rates were effective in May 2007. FERC approved a settlement of the rate filing in September 2007.

In August 2008, we issued a one-time $62.5 million refund to our wholesale customers pursuant to a FERC-approved settlement related to the sale of Point Beach.

Depreciation Rates: Periodically, we engage consultants to perform depreciation studies on our utility assets to determine our depreciation rates. In 2008, a consultant completed a depreciation study that concluded that we should reduce our utility depreciation rates because of longer asset lives and increased salvage values. The consultant estimated that the new proposed rates would reduce annual depreciation expense by approximately $41 million. In January 2009, we filed the depreciation study with the PSCW. If the PSCW approves the depreciation study, we would expect to implement the new depreciation rates in late 2009. We do not expect the new depreciation rates to have a material impact on earnings because we anticipate that the new depreciation rates will be considered when the PSCW sets our 2010 electric and gas prices. For information on our current depreciation rates, see Note A — Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements.

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Renewables, Efficiency and Conservation: In March 2006, Wisconsin revised the requirements for renewable energy generation by enacting Act 141. Act 141 defines “baseline renewable percentage” as the average of an energy provider’s renewable energy percentage for 2001, 2002 and 2003. A utility’s renewable energy percentage is equal to the amount of its total retail energy sales that are provided by renewable sources. Our baseline renewable energy percentage is 2.27%. Act 141 provides that for the years 2006-2009, we may not decrease our renewable energy percentage, and for the years 2010-2014, we must increase our renewable energy percentage at least two percentage points to a level of 4.27%. Act 141 further requires that for the year 2015 and beyond, the renewable energy percentage must increase at least six percentage points above the baseline to a level of 8.27%. Act 141 establishes a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. Assuming the bulk of additional renewables is wind generation, we must obtain approximately 362 MW of additional renewable capacity by 2012 and another approximately 300 MW of additional renewable capacity by 2015 to meet the requirements of Act 141. We have already started development of additional sources of renewable energy which will assist us in complying with Act 141. See Wind Generation discussion below.

In 2008, the Governor of Wisconsin established the Governor’s Task Force on Global Warming. The Task Force issued its final report in July 2008 that includes an increased renewable portfolio standard. Pursuant to the Task Force’s recommendations, the renewable portfolio standard would increase to 10% by 2013, 20% by 2020 and 25% by 2025. The legislature is expected to review these recommendations in 2009.

Act 141 allows the PSCW to delay a utility’s implementation of the renewable portfolio standard if it finds that achieving the renewable requirement would result in unreasonable rate increases or would lessen reliability, or that new renewable projects could not be permitted on a timely basis or could not be served by adequate transmission facilities. The previous law did not include similar provisions. Act 141 provides that if a utility is in compliance with the renewable energy and energy efficiency requirements as determined by the PSCW, then the utility may not be ordered to achieve additional energy conservation or efficiency. Prior to Act 141, there had been no agreement on how to determine compliance with the Energy Priorities law, which provides that it is the policy of the PSCW, to the extent it is cost-effective and technically feasible, to consider the following options in the listed order when reviewing energy-related applications: (1) energy conservation and efficiency, (2) noncombustible renewable energy resources, (3) combustible renewable energy resources, (4) natural gas, (5) oil or low sulfur coal and (6) high sulfur coal and other carbon-based fuels.

Act 141 also redirects the administration of energy efficiency, conservation and renewable programs from the DOA back to the PSCW and/or contracted third parties. In addition, Act 141 requires that 1.2% of utilities’ annual operating revenues be used to fund these programs. The Governor of Wisconsin’s Task Force on Global Warming recommended in July 2008 that this amount be increased to approximately 4%. It is not known at this time if that recommendation will be implemented.

Public Act 295 enacted in Michigan calls for the implementation of a renewable portfolio standard by 2015 and energy optimization (efficiency) targets up to 1% annually by 2015. Public Act 295 specifically calls for current recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective.

Wind Generation: In June 2005, we purchased the development rights to a wind farm project (Blue Sky Green Field) from Navitas Energy, Inc. We began construction in June 2007 and the project reached commercial operation in May 2008. Land restoration, road repairs and other post construction activities are near completion. The cost of this project was approximately $301.7 million, including AFUDC, as of December 31, 2008.

In addition, in October 2007 we provided notice to FPL Energy, a subsidiary of FPL, that we were exercising the option we received in connection with the sale of Point Beach to purchase all rights to a new wind farm site in central Wisconsin, Glacier Hills Wind Park. In July 2008, the purchase was completed and in October 2008, we filed a request for a CPCN with the PSCW for the Glacier Hills Wind Park. We currently expect to install wind turbines with approximately 132 to 207 MW of generating capacity, subject to the final site configuration and the turbine equipment selected. We expect 2012 to be the first full year of operation, subject to regulatory approvals and turbine availability.

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.

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We had adequate capacity to meet all of our firm electric load obligations during 2008 and 2007. All of our 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 and we did not interrupt or curtail service to non-firm customers who participate in load management programs.

We expect to have adequate capacity to meet all of our firm load obligations during 2009. However, extremely hot weather, unexpected equipment failure or unavailability could require us to call upon load management procedures as we have in past years.

ENVIRONMENTAL MATTERS

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation challenges related to current and past operations. Specific environmental issues affecting us include, but are not limited to, (1) air emissions such as CO₂, SO₂, NO_x, small particulates and mercury, (2) disposal of combustion by-products such as fly ash and (3) remediation of former manufactured gas plant sites.

We are currently pursuing a proactive strategy to manage our environmental issues including (1) improving our overall energy portfolio by adding more efficient generation as part of Wisconsin Energy’s PTF strategy, (2) developing additional sources of renewable electric energy supply, (3) reviewing water quality matters such as discharge limits and cooling water requirements, (4) adding emission control equipment to existing facilities to comply with new ambient air quality standards and federal clean air rules, (5) entering into an agreement with the EPA to reduce emissions of SO₂ and NO_x by more than 65% by 2013, (6) evaluating and implementing improvements to our cooling water intake systems, (7) continuing the beneficial re-use of ash and other solid products from coal-fired generating units and (8) conducting the clean-up of former manufactured gas plant sites. The capital costs of implementing the EPA Consent Decree are estimated to be approximately $1.2 billion over the 10 years ending 2013. These costs are principally associated with the installation of air quality controls on Pleasant Prairie Units 1 and 2 and Oak Creek Units 5-8. In June 2007, we submitted an application to the PSCW requesting approval to construct environmental controls at Oak Creek Units 5-8 by 2012 as required by the Consent Decree. We expect the cost of completing this project to be approximately $885 million, including AFUDC. Through December 31, 2008, we have spent approximately $506.7 million associated with implementing the EPA Consent Decree. For further information concerning the Consent Decree, see Note Q — Commitments and Contingencies in the Notes to Consolidated Financial Statements in this report.

National Ambient Air Quality Standards: In 2000 and 2001, Michigan and Wisconsin finalized state rules implementing phased emission reductions required to meet the NAAQS for 1-hour ozone. In 2004, the EPA began implementing NAAQS for 8-hour ozone and PM_2.5. In December 2006, the EPA further revised the PM_2.5 standard, and in March 2008, the EPA announced its decision to further lower the 8-hour ozone standard.

8-hour Ozone Standard: In April 2004, the EPA designated 10 counties in southeastern Wisconsin as non-attainment areas for the 8-hour ozone NAAQS. States were required to develop and submit SIPs to the EPA by June 2007 to demonstrate how they intended to comply with the 8-hour ozone NAAQS. Instead of submitting a SIP, Wisconsin submitted a request to redesignate all counties in southeastern Wisconsin to be in attainment with the standard. In addition to the request for redesignation, Wisconsin also adopted the RACT rule that applies to emissions from our power plants in the affected areas of Wisconsin. We believe compliance with the NO_x emission reduction requirements under the Consent Decree will substantially mitigate costs to comply with the RACT rule. In March 2008, the EPA issued a determination that the state of Wisconsin had failed to submit a SIP. We do not anticipate any further requirements to reduce emissions as a result of this finding, but we are unable to predict that outcome until Wisconsin responds to this finding (expected in July 2009) and the EPA subsequently takes a final approval action. In March 2008, the EPA announced its decision to further lower the 8-hour standard. Although additional counties may be designated as non-attainment areas under the revised standard, until those designations become final and until any potential additional rules are adopted, we are unable to predict the impact on the operation of our existing coal-fired generation facilities.

PM_2.5Standard: In December 2004, the EPA designated PM_2.5 non-attainment areas in the country. All counties in Wisconsin and all counties in the Upper Peninsula of Michigan were designated as in attainment with the standard. In December 2006, a more restrictive federal standard became effective; however, on February 24, 2009, the D.C. Circuit Court of Appeals issued a decision on the revised standard and remanded it back to the EPA for revision. The court’s decision will likely result in an even more stringent annual PM_2.5 standard. Until such time as the EPA revises the standard consistent with the court’s decision and the states develop rules and submit SIPs to the EPA to demonstrate how they intend to comply with the standard, we are unable to predict the impact of this more restrictive standard on the operation of our existing coal-fired generation facilities or Wisconsin Energy’s new PTF generating units that we are leasing, including OC 1, OC 2 and PWGS.

Clean Air Interstate Rule: The EPA issued the final CAIR 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

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states under CAIR. CAIR was to be implemented in two phases. Overall, CAIR is expected to result in a 70% reduction in SO₂ emissions and a 65% reduction in NO_x emissions from 2002 emission levels. A final CAIR rule was adopted in Wisconsin and Michigan. Subsequently, in July 2008, the U.S. Court of Appeals for the D.C. Circuit vacated CAIR and determined that the EPA must promulgate a rule consistent with its decision, but did not issue a mandate that would put its ruling into effect. In December 2008, the Court remanded CAIR to the EPA but did not vacate it. Therefore, CAIR will remain in place while the EPA drafts a replacement rule. The Court’s decision did not include a deadline for the replacement rule. We previously determined that compliance with the NO_x and SO₂ emission reductions requirements under the Consent Decree would substantially mitigate costs to comply with CAIR and will achieve the levels necessary under at least the first phase of CAIR. It will be necessary to see what the revised rule contains before we can determine if any additional reductions will be required.

Clean Air Mercury Rule: The EPA issued the final CAMR in March 2005, following the agency’s 2000 regulatory determination that utility mercury emissions should be regulated. CAMR would limit mercury emissions from new and existing coal-fired power plants and cap utility mercury emissions in two phases, applicable in 2010 and 2018. The caps would limit emissions at approximately 20% and ultimately 70% below current utility mercury levels.

The federal rule was challenged by a number of states, including Wisconsin and Michigan. In February 2008, the U.S. Court of Appeals for the D.C. Circuit vacated CAMR and sent the rule back to the EPA for re-consideration. The D.C. Circuit denied a request for a rehearing and the parties subsequently petitioned the U.S. Supreme Court for review of the D.C. Circuit’s decision. In February 2009, the U.S. Supreme Court denied the petition for certiorari. In December 2008, a number of environmental groups also filed a complaint with the D.C. Circuit asking that the court place the EPA on a schedule for promulgating Maximum Achievable Control Technology limits for electric utilities. This latest complaint is still being processed by the D.C. Circuit.

In October 2004, the WDNR issued mercury emission control rules that affect electric utilities in Wisconsin. The Wisconsin rules explicitly recognize an underlying state statutory restriction that state regulations cannot be more stringent than those included in any federal program and require that the WDNR must adopt state rule changes within 18 months of publication of any federal rules. In March 2007, the WDNR proposed changes to this rule to include an implementation plan for CAMR, along with a proposal for more stringent state-only rules. The WDNR did not take any final action on the March 2007 rule proposal.

In March 2008, the WDNR once again proposed changes to the existing state-only mercury rule. In June 2008, the Natural Resources Board approved the proposed rule. The rule was approved and went into effect in December 2008. The new rule requires 90% mercury emission reductions from utilities by 2015, or, under a multi-emission option, 70% reductions by 2015, 80% by 2018 and 90% by 2021, provided utilities meet stringent NO_x and SO₂ emission reduction requirements by 2015. The rule eliminates the 2008-2009 emission cap, but retains the 40% emission reduction requirement for the period 2010-2014. Our plan is to maximize mercury reductions from our initial emission control investments. Enhanced mercury reductions from refinements to SO₂ and NO_x controls are expected to be developed over the next several years. Because control technology is under development, it is difficult to estimate what the cost will be to comply with the Wisconsin requirements. We believe the range of possible expenditures could be approximately $50 million to $200 million.

As of January 2008, the MDEQ has also proposed a rule to both implement CAMR and impose state-only requirements for achieving 90% emission reductions in 2015. The MDEQ has revised the draft rule to remove the requirements related to the now vacated CAMR, but is proceeding with the remainder of the state-only rule. As part of a new technology demonstration which we undertook in partnership with the DOE, technology for the control of mercury has been installed at our Presque Isle Power Plant. We plan to continue the operation of that equipment beyond the test period. We anticipate that this equipment will be sufficient to comply with reductions that would be required under the state-only rule.

Clean Air Visibility Rule: The EPA issued CAVR in June 2005 to address Regional Haze, or regionally-impaired visibility caused by multiple sources over a wide area. The rule defines 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 are then required to 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 were required to submit SIPs to implement CAVR to the EPA by December 2007. Wisconsin has not yet submitted a SIP. Michigan submitted a SIP, which was partially approved. The reductions associated with the state plans are scheduled to begin to take effect in 2014, with full implementation before 2018. In response to a citizen suit, in January 2009, the EPA issued a finding of failure to 37 states, including Wisconsin and Michigan, regarding their failure to submit SIPs. The finding starts a two-year review window for the EPA to issue Federal Implementation Plans, unless a state submits and receives SIP approval. Failure to submit an approved SIP does not initiate any federal sanctions against the states.

Wisconsin and Michigan have completed the BART rules, which cover one aspect of CAVR regulations. Wisconsin BART rules became effective in July 2008 and Michigan BART rules became effective in September 2008.

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Both Wisconsin and Michigan BART rules are based, in part, on utility reductions of NO_x and SO₂ that were expected to occur under CAIR. Therefore, we will not be able to determine final impacts of these rules until the EPA completes a new CAIR rule.

Clean Water Act: Section 316(b) of the CWA requires that the location, design, construction and capacity of cooling water intake structures reflect the BTA for minimizing adverse environmental impact. This law dates back to 1972; however, prior to September 2004, there were no federal rules that defined precisely how states and EPA regions determined that an existing intake met BTA requirements. The Phase II rule established, 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 316(b) rules for our Oak Creek Power Plant, We Power’s Oak Creek expansion and PWGS were included in project costs.

In January 2007, the Federal Court of Appeals for the Second Circuit issued a decision concerning the Phase II rule for existing facilities (Riverkeeper, Inc. v. EPA, Nos. 04-6692-ag(L) (2d Cir. 2007)). The Second Circuit found certain portions of the rule impermissible and remanded several parts of the Phase II rule to the EPA for further consideration or potential additional rulemaking. Consistent with its announcement in March, in July 2007, the EPA formally suspended the Phase II rule in its entirety and directed states to use their “best professional judgment” in evaluating intake systems. We will work with the relevant state agencies as permits for our facilities come due for renewal to determine what, if any, actions need to be taken. Until the EPA completes its reconsideration and rulemaking, we cannot predict what impact these changes to the federal rules may have on our facilities. For additional information on this matter related to the Oak Creek expansion, see Factors Affecting Results, Liquidity and Capital Resources —Power the Future — Oak Creek Expansion in this report.

EPA Advance Notice of Proposed Rulemaking: In July 2008, the EPA issued an Advance Notice of Proposed Rulemaking seeking comment on a large array of possible regulatory actions it is contemplating under the federal CAA to reduce greenhouse gas emissions. The proposed rules impact virtually all aspects of the economy including electric and natural gas utilities. The EPA document follows a U.S. Supreme Court decision last year requiring the EPA to regulate greenhouse gas emissions under the CAA if it finds that they endanger public health or welfare. The document seeks comment on whether the EPA should make that finding and, if so, the types of regulations it should adopt. The comment period has closed, and there has been no additional formal activity in the rule process. We cannot predict at this time what impact, if any, such a finding would have on us.

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

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

EPA Consent Decree: In April 2003, we announced along with the EPA that a Consent Decree had been reached that resolved all issues related to a request for information that had been issued by the EPA. The U.S. District Court for the Eastern District of Wisconsin approved the amended Consent Decree and entered it in October 2007. For further information, see Note Q — Commitments and Contingencies in the Notes to Consolidated Financial Statements.

Greenhouse Gases: We continue to take measures to reduce our emissions of greenhouse gases. We support flexible, market-based strategies to curb greenhouse gas emissions, including emissions trading, joint implementation projects and credit for early actions. We support a voluntary approach that encourages technology development and transfer and includes all sectors of the economy and all significant global emitters.

Our emissions in future years will continue to be influenced by several actions completed, planned or underway, including:

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

• Adding coal-fired units as part of the Oak Creek expansion that will be the most thermally efficient coal units in our system.

• Increasing investment in energy efficiency and conservation.

• Additional renewable capacity and promoting increased participation in the Energy for Tomorrow^® renewable energy program.

• Retirement of coal units 1-4 at the Presque Isle Power Plant.

Federal, state, regional and international authorities have undertaken efforts to limit greenhouse gas emissions. Legislative proposals that would impose mandatory restrictions on CO₂emissions continue to be considered in the U.S. Congress, and the new President and his administration have made it clear that they are focused on reducing CO₂ emissions. Although the ultimate outcome of these efforts cannot be determined at this time, mandatory restrictions on our CO₂ emissions could result in significant compliance costs that could affect future results of operations, cash flows and financial condition.

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LEGAL MATTERS

Arbitration Proceedings: In May 2007, we reached a settlement with our largest electric customers, two iron ore mines, that operate in the Upper Peninsula of Michigan. The mines represent approximately 6.6% of our 2008 electric sales; however, they provide a much smaller percentage of our earnings. The mines had special negotiated contracts that expired in December 2007. The contracts had price caps for approximately 80% of the energy sales. We did not recognize revenue on amounts billed that exceeded the price caps.

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 Energy Markets. The mines notified us that they were disputing these billings and a portion of these disputed amounts were deposited in escrow. In September 2005, the mines notified us that they filed for formal arbitration related to the contracts. We notified the mines that we believe that they failed to comply with certain notification provisions related to annual production as specified within the contracts.

In May 2007, we entered into a settlement agreement with the mines. The settlement was a full and complete resolution of all claims and disputes between the parties for electric service rendered by us under the power purchase agreements through March 31, 2007. Pursuant to the settlement, the mines paid us approximately $9.0 million and we released to the mines all funds held in escrow. The settlement also provided a mutually satisfactory pricing structure through the power purchase agreement expiration date of December 31, 2007. Beginning in January 2008, the mines began receiving electric service from us in accordance with tariffs approved by the MPSC.

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

In recent years, dairy farmers have commenced actions or made claims against us for loss of milk production and other damages to livestock allegedly caused by stray voltage, and, more recently, ground currents resulting from the operation of our electrical system, even though that electrical system has been operated within the parameters of the PSCW’s order. The Wisconsin Supreme Court has rejected the arguments 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 has 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.”

In December 2008, a stray voltage lawsuit was filed against us. We do not believe the lawsuit has merit and we will vigorously defend the case. This lawsuit against us is not expected to have a material adverse effect on our financial statements. In June 2007, a stray voltage lawsuit filed against us in May 2005 was settled. This settlement did not have a material adverse effect on our financial condition or results of operations. We continue to evaluate various options and strategies to mitigate this risk.

NUCLEAR OPERATIONS

Point Beach Nuclear Plant: We previously owned two electric generating units (Unit 1 and Unit 2) at Point Beach in Two Rivers, Wisconsin. During 2007 and 2006, Point Beach provided approximately 17.5% and 25.7%, respectively, of our net electric energy supply.

On September 28, 2007, we sold Point Beach to an affiliate of FPL for approximately $924 million. Pursuant to the terms of the sale agreement, the buyer purchased Point Beach, its nuclear fuel and associated inventories, and assumed the obligation to decommission the plant. We retained approximately $506 million of the sales proceeds, which represents the net book value of the assets sold and certain transaction costs. In addition, we deferred the net gain on the sale of approximately $418 million as a regulatory liability and deposited those proceeds into a restricted cash account.

In connection with the sale, we also transferred $390 million of decommissioning funds to the buyer. We then liquidated the balance of the decommissioning trust assets and retained approximately $552 million, which was also placed into the restricted cash account. We are using the cash in the restricted cash account and the interest earned on the balance for the benefit of our customers and to pay certain taxes. Our regulators are directing the manner in which these proceeds will benefit customers. For further information on the 2008 rate case, see Factors Affecting Results, Liquidity and Capital Resources - Rates and Regulatory Matters in this report.

A long-term power purchase agreement with the buyer became effective upon closing of the sale. Pursuant to this agreement, we are purchasing all of the energy produced by Point Beach. The power purchase agreement extends through 2030 for Unit 1 and 2033 for Unit 2. Based on the agreement, we are paying a predetermined price per MWh for energy delivered according to a schedule that is established in the agreement. Under the agreement, if our credit rating from either S&P or Moody’s falls below investment grade, or if

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the holders of any indebtedness in excess of $100.0 million accelerate or have the right to accelerate the maturity of such indebtedness as a result of a default, we would need to provide a parent guaranty or other form of collateral in the amount of $100.0 million (escalating at 3% per year commencing in 2024).

Used Nuclear Fuel Storage and Disposal: During our ownership of Point Beach, we were 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 DOE 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 DOE failed to meet its contractual obligation to begin removing used fuel from Point Beach, a responsibility for which we paid a total of $215.2 million into the Nuclear Waste Fund over the life of our ownership of Point Beach.

In August 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 DOE’s failure to begin performance by January 31, 1998 constituted a breach of the Standard Contract, providing clear grounds for filing complaints in the Court of Federal Claims. Consequently, we filed a complaint in November 2000 against the DOE in the Court of Federal Claims. In October 2004, the Court of Federal Claims granted our motion for summary judgment on liability. The Court held a trial during September and October 2007 to determine damages. We anticipate a decision during 2009. We incurred substantial damages prior to the sale of Point Beach and we are seeking recovery of our damages in this lawsuit, and we expect that any recoveries would be considered in setting future rates.

INDUSTRY RESTRUCTURING AND COMPETITION

Electric Utility Industry

The regulated energy industry continues to experience significant changes. FERC continues to support large RTOs, which will affect the structure of the wholesale market. To this end, the MISO implemented bid-based markets, the MISO Energy Markets, including the use of LMP to value electric transmission congestion and losses. The MISO Energy Markets commenced operation in April 2005 for energy distribution and in January 2009 for operating reserves. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant and adverse financial impact on us. It is uncertain when retail access might be implemented, if at all, in Wisconsin; however, Michigan has adopted retail choice which potentially affects our Michigan operations. The Energy Policy Act, which included tax subsidies for electric utilities, amended federal energy laws and provided FERC with new oversight responsibilities, continues to significantly impact the electric utility industry. We continue to focus on infrastructure issues through Wisconsin Energy’s PTF 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, the PSCW has been focused on electric reliability infrastructure issues for the state of Wisconsin in recent years. These issues include:

• Addition of new generating capacity in the state;

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

• Development of a regional independent electric transmission system operator;

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

• Addition of renewable generation.

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

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

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Electric Transmission and Energy Markets

In MISO, base transmission costs are currently being paid by LSEs located in the service territories of each MISO transmission owner. In February 2008, FERC issued several orders confirming that the current transmission cost allocation methodology is just and reasonable and should continue in the future. These orders are subject to rehearings or appeals.

In April 2006, FERC issued an order determining that MISO had not applied its energy markets tariff correctly in the assessment of RSG charges. FERC ordered MISO to resettle all affected transactions retroactive to the commencement of the energy market. In October 2006 and March 2007, we received additional rulings from FERC on these issues. FERC’s rulings have been challenged by MISO and numerous other market participants. MISO commenced with the resettlement of the market in accordance with the orders in July 2007. The resettlement was completed in January 2008 and resulted in a net cost increase of $7.5 million to us. Several entities filed formal complaints with FERC on the assessment of these charges. We filed in support of these complaints.

In November 2007, FERC issued another RSG order related to the rehearing requests previously filed. This order provided a clarification that was contrary to how MISO implemented the last resettlement. Once again, we filed for rehearing and/or clarification with FERC, along with several other parties.

In addition, FERC ruled on the formal complaints filed by other entities in August 2007. FERC ruled that the current RSG cost allocation methodology may be unjust and unreasonable and established a refund effective date of August 10, 2007. MISO was ordered to file a new cost allocation methodology by March 2008. MISO filed new tariff language which indicated the new cost allocation methodology cannot be applied retroactively. We extended our previous rehearing/clarification request to include the timeframe from the established refund date through March 2008. In September 2008, FERC set a paper hearing for the formal complaints filed in 2007. FERC ruled on the outstanding rehearing/clarification requests and formal complaints in November 2008. FERC’s ruling orders the resettlements to begin from the date the MISO Energy Markets commenced in order to correct the RSG cost allocation methodology. Additionally, the order also set a new RSG cost allocation effective August 10, 2007. However, numerous entities filed rehearing requests in objection of these rulings. MISO requested a postponement of the resettlements until the matter is resolved. Based on our analysis of the FERC decision and MISO’s proposed implementation of FERC’s ruling, we estimate that there could be a refund to us of up to $15 million. Due to the uncertainty around the ultimate outcome of the RSG cost allocation, we have not reflected the potential impact of this potential resettlement on our financial statements as of December 31, 2008.

As part of MISO, a market-based platform was developed 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 ARRs and FTRs. ARRs are allocated to market participants by MISO and FTRs are purchased through auctions. A new allocation and auction was completed for the period of June 1, 2008 through May 31, 2009. The resulting ARR valuation and the secured FTRs should adequately mitigate our transmission congestion risk for that period.

MISO has developed a market for two ancillary services, regulation reserves and contingency reserves. In February 2007, MISO filed tariff revisions to include ancillary services. The MISO ancillary services market began in January 2009. We previously self-provided both regulation reserves and contingency reserves. In the MISO ancillary services market, we buy/sell regulation and contingency reserves from/to the market. The MISO ancillary services market is expected to reduce overall ancillary services costs in the MISO footprint. The MISO ancillary services market is also expected to enable MISO to assume significant balancing area responsibilities such as frequency control and disturbance control.

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

ACCOUNTING DEVELOPMENTS

New Pronouncements: See Note B — Recent Accounting Pronouncements in the Notes to Consolidated Financial Statements for information on new accounting pronouncements.

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CRITICAL ACCOUNTING ESTIMATES

Preparation of financial statements and related disclosures in compliance with 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: We 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. Under SFAS 71, the actions of our regulators may allow us to defer costs that non-regulated companies would expense. The actions of our regulators may also require us to accrue liabilities that non-regulated entities would not. As of December 31, 2008, we had $1,062.8 million in regulatory assets and $1,094.2 million in regulatory liabilities. In the future, if we move to market based rates, or if the actions of our regulators change, we may conclude that we are unable to follow SFAS 71. In this situation, continued deferral of certain regulatory asset and liability amounts on our books, as allowed under 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. We continually review the applicability of SFAS 71 and have determined that it is currently appropriate to continue following SFAS 71. In addition, each quarter we perform a review of our regulatory assets and our regulatory environment and we evaluate whether we believe that it is probable that we will recover the regulatory assets in future rates. See Note C — Regulatory Assets and Liabilities in the Notes to Consolidated Financial Statements for additional information.

Pension and OPEB: Our reported costs of providing non-contributory defined pension benefits (described in Note M — 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 and SFAS 158, changes in pension obligations associated with these factors may not be immediately recognized as pension costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants.

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

Pension Plan Actuarial Assumption	Impact on Annual Cost
	(Millions of Dollars)
0.5% decrease in discount rate and lump sum conversion rate	$	5.4
0.5% decrease in expected rate of return on plan assets	$	3.6

In addition to pension plans, we maintain OPEB plans which provide health and life insurance benefits for retired employees (described in Note M — Benefits in the Notes to Consolidated Financial Statements). We account for these plans in accordance with 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 OPEB costs. OPEB 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 OPEB and post-retirement costs. Our OPEB 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, our regulators have adopted SFAS 106 for rate making purposes.

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The following chart reflects OPEB 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:

OPEB Plan Actuarial Assumption	Impact on Annual Cost
	(Millions of Dollars)
0.5% decrease in discount rate	$	1.8
0.5% decrease in health care cost trend rate in all future years		($2.3	)
0.5% decrease in expected rate of return on plan assets	$	0.5

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 operating revenues during 2008 of approximately $3.4 billion included accrued revenues of $233.1 million as of December 31, 2008.

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WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED INCOME STATEMENTS

Year Ended December 31

	2008		2007		2006
	(Millions of Dollars)
Operating Revenues	$	3,410.1	$	3,321.6	$	3,116.7
Operating Expenses
Fuel and purchased power		1,242.3		992.1		798.0
Cost of gas sold		526.4		441.9		431.6
Other operation and maintenance		1,295.2		1,041.9		1,074.5
Depreciation, decommissioning and amortization		256.0		269.7		270.9
Property and revenue taxes		96.4		91.7		85.8
Total Operating Expenses		3,416.3		2,837.3		2,660.8
Amortization of Gain		488.1		6.5		—
Operating Income		481.9		490.8		455.9
Equity in Earnings of Transmission Affiliate		45.4		37.9		33.9
Other Income and Deductions, net		9.9		41.7		42.9
Interest Expense, net		86.6		93.0		87.0
Income Before Income Taxes		450.6		477.4		445.7
Income Taxes		169.3		188.5		168.9
Net Income		281.3		288.9		276.8
Preferred Stock Dividend Requirement		1.2		1.2		1.2
Earnings Available for Common Stockholder	$	280.1	$	287.7	$	275.6

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

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WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

December 31

ASSETS

	2008			2007
	(Millions of Dollars)
Property, Plant and Equipment
Electric	$	6,348.3		$	5,887.9
Gas		830.3			768.8
Steam		83.6			82.3
Common		236.5			252.1
Other		61.6			61.7
		7,560.3			7,052.8
Accumulated depreciation		(2,721.2	)		(2,577.4	)
		4,839.1			4,475.4
Construction work in progress		188.4			302.1
Leased facilities, net		870.2			547.3
Net Property, Plant and Equipment		5,897.7			5,324.8
Investments
Restricted cash		172.4			323.5
Equity investment in transmission affiliate		243.1			209.9
Other		0.4			0.4
Total Investments		415.9			533.8
Current Assets
Cash and cash equivalents		28.4			22.0
Restricted cash		214.1			408.1
Accounts receivable, net of allowance for doubtful accounts of $27.2 and $21.9		278.1			264.8
Accrued revenues		233.1			213.4
Materials, supplies and inventories		296.5			285.6
Prepayments		122.3			105.3
Regulatory assets		69.9			153.0
Other		69.1			81.1
Total Current Assets		1,311.5			1,533.3
Deferred Charges and Other Assets
Regulatory assets		992.9			787.3
Other		157.4			133.6
Total Deferred Charges and Other Assets		1,150.3			920.9
Total Assets	$	8,775.4		$	8,312.8

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

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WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

December 31

CAPITALIZATION AND LIABILITIES

	2008		2007
	(Millions of Dollars)
Capitalization
Common equity	$	2,582.8	$	2,656.2
Preferred stock		30.4		30.4
Long-term debt		1,885.3		1,338.1
Capital lease obligations		991.8		646.6
Total Capitalization		5,490.3		4,671.3
Current Liabilities
Long-term debt and capital lease obligations due currently		9.3		5.7
Short-term debt		—		323.3
Subsidiary note payable to Wisconsin Energy		29.6		31.0
Accounts payable		365.4		371.0
Payroll and vacation accrued		65.4		61.0
Accrued taxes		9.6		60.4
Accrued interest		13.3		8.4
Regulatory liabilities		307.7		560.8
Other		124.0		56.6
Total Current Liabilities		924.3		1,478.2
Deferred Credits and Other Liabilities
Regulatory liabilities		786.5		1,011.0
Deferred income taxes - long-term		691.7		468.5
Accumulated deferred investment tax credits		39.1		45.0
Asset retirement obligations		52.3		50.0
Pension and other benefit obligations		614.3		395.4
Other long-term liabilities		176.9		193.4
Total Deferred Credits and Other Liabilities		2,360.8		2,163.3
Commitments and Contingencies (Note Q)
Total Capitalization and Liabilities	$	8,775.4	$	8,312.8

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

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WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31

	2008			2007			2006
	(Millions of Dollars)
Operating Activities
Net income	$	281.3		$	288.9		$	276.8
Reconciliation to cash
Depreciation, decommissioning and amortization		263.4			279.3			280.5
Amortization of gain		(488.1	)		(6.5	)		—
Equity in earnings of transmission affiliate		(45.4	)		(37.9	)		(33.9	)
Distributions from transmission affiliate		34.2			29.2			26.7
Deferred income taxes and investment tax credits, net		264.6			8.9			(59.3	)
Contributions to benefit plans		(37.9	)		(23.2	)		(58.0	)
Change in - Accounts receivable and accrued revenues		(33.0	)		8.3			(2.0	)
Inventories		(10.9	)		2.8			(15.5	)
Other current assets		(43.3	)		(17.4	)		(19.4	)
Accounts payable		45.2			19.7			(2.0	)
Accrued income taxes, net		(61.5	)		(154.7	)		49.5
Deferred costs, net		81.5			(56.3	)		(29.1	)
Other current liabilities		78.7			(19.3	)		(15.8	)
Other, net		34.1			(108.0	)		100.0
Cash Provided by Operating Activities		362.9			213.8			498.5
Investing Activities
Capital expenditures		(523.7	)		(481.0	)		(398.7	)
Investment in transmission affiliate		(22.2	)		—			(12.8	)
Proceeds from asset sales, net		7.1			938.8			5.6
Proceeds from liquidation of nuclear decommissioning trust		—			552.4			—
Change in restricted cash		345.1			(731.6	)		—
Nuclear fuel		—			(23.8	)		(47.7	)
Proceeds from investments within nuclear decommissioning trust		—			1,528.7			530.7
Other activity within nuclear decommissioning trust		—			(1,528.7	)		(530.7	)
Other, net		(19.0	)		(18.6	)		(20.2	)
Cash (Used in) Provided by Investing Activities		(212.7	)		236.2			(473.8	)
Financing Activities
Dividends paid on common stock		(367.0	)		(179.6	)		(179.6	)
Dividends paid on preferred stock		(1.2	)		(1.2	)		(1.2	)
Issuance of long-term debt		697.0			23.4			327.9
Retirement and repurchase of long-term debt		(147.0	)		(345.4	)		(229.4	)
Change in total short-term debt		(324.7	)		50.1			(48.5	)
Capital contribution from parent		—			—			100.0
Other, net		(0.9	)		6.5			1.1
Cash Used in Financing Activities		(143.8	)		(446.2	)		(29.7	)
Change in Cash and Cash Equivalents		6.4			3.8			(5.0	)
Cash and Cash Equivalents at Beginning of Year		22.0			18.2			23.2
Cash and Cash Equivalents at End of Year	$	28.4		$	22.0		$	18.2

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

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WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

December 31

	2008			2007
	(Millions of Dollars)
Common Equity (See Consolidated Statements of Common Equity)
Common stock - $10 par value; authorized 65,000,000 shares; outstanding - 33,289,327 shares	$	332.9		$	332.9
Other paid in capital		688.8			675.3
Retained earnings		1,561.1			1,648.0
Total Common Equity		2,582.8			2,656.2
Preferred Stock
Six Per Cent. Preferred Stock - $100 par value; authorized 45,000 shares; outstanding - 44,498 shares		4.4			4.4
Serial preferred stock -
$100 par value; authorized 2,286,500 shares; 3.60% Series redeemable at $101 per share; outstanding - 260,000 shares		26.0			26.0
$25 par value; authorized 5,000,000 shares; none outstanding		—			—
Total Preferred Stock		30.4			30.4
Long-Term Debt
Debentures (unsecured)                   4.50% due 2013		300.0			300.0
6.00% due 2014		300.0			—
6.25% due 2015		250.0			—
6-1/2% due 2028		150.0			150.0
5.625% due 2033		335.0			335.0
5.70% due 2036		300.0			300.0
6-7/8% due 2095		100.0			100.0
Notes (secured, nonrecourse)           2% stated rate due 2011		0.1			0.2
4.81% effective rate due 2030		2.0			2.0
Notes (unsecured)                            1.92% variable rate due 2015 (a)		17.4			17.4
0.80% variable rate due 2016 (a)		67.0			67.0
0.80% variable rate due 2030 (a)		80.0			80.0
Obligations under capital leases		1,001.1			652.3
Unamortized discount, net		(16.2	)		(13.5	)
Long-term debt and capital lease obligations due currently		(9.3	)		(5.7	)
Total Long-Term Debt		2,877.1			1,984.7
Total Capitalization	$	5,490.3		$	4,671.3

(a) Variable interest rate as of December 31, 2008.

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

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WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF COMMON EQUITY

	Common Stock		Other Paid In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
	(Millions of Dollars)
Balance - December 31, 2005	$	332.9	$	542.6	$	1,443.9		$	(8.5	)	$	2,310.9
Net income						276.8						276.8
Other comprehensive income
Minimum pension liability									2.2			2.2
Comprehensive Income		—		—		276.8			2.2			279.0
Cash dividends
Common stock						(179.6	)					(179.6	)
Preferred stock						(1.2	)					(1.2	)
Cash contribution from Parent				100.0								100.0
Stock-based compensation				6.8								6.8
Tax benefit of exercised stock options allocated from Parent				6.4								6.4
Adoption of SFAS 158									6.3			6.3
Balance - December 31, 2006		332.9		655.8		1,539.9			—			2,528.6
Net income						288.9						288.9
Other comprehensive income						—						—
Comprehensive Income		—		—		288.9			—			288.9
Cash dividends
Common stock						(179.6	)					(179.6	)
Preferred stock						(1.2	)					(1.2	)
Stock-based compensation				10.8								10.8
Tax benefit of exercised stock options allocated from Parent				8.7								8.7
Balance - December 31, 2007		332.9		675.3		1,648.0			—			2,656.2
Net income						281.3						281.3
Other comprehensive income						—						—
Comprehensive Income		—		—		281.3			—			281.3
Cash dividends
Common stock						(367.0	)					(367.0	)
Preferred stock						(1.2	)					(1.2	)
Stock-based compensation				11.3								11.3
Tax benefit of exercised stock options allocated from Parent				2.2								2.2
Balance - December 31, 2008	$	332.9	$	688.8	$	1,561.1		$	—		$	2,582.8

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

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WISCONSIN ELECTRIC POWER COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General: Wisconsin Electric Power Company (Wisconsin Electric, the Company, our, us or we), a wholly-owned subsidiary of Wisconsin Energy, is an electric, gas and steam utility which services electric customers in Wisconsin and the Upper Peninsula of Michigan, gas customers in Wisconsin and steam customers in metro Milwaukee, Wisconsin. We consolidate our wholly-owned subsidiary Bostco, which owns real estate properties that are eligible for historical rehabilitation tax credits. Bostco had total assets of $37.1 million as of December 31, 2008.

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

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

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

Our retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchase power costs. The electric fuel rules in Wisconsin allow us to request rate increases if fuel and purchased power costs exceed the band established by the PSCW. We are also required to reduce rates if fuel and purchased power costs fall below the band established by the PSCW.

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

Accounting for MISO Energy Transactions: MISO implemented the MISO Energy Markets on April 1, 2005. The MISO Energy Markets operate under both day-ahead and real-time markets. We record energy transactions in the MISO Energy Markets on a net basis for each hour.

Other Income and Deductions, net: We recorded the following items in other income and deductions, net for the years ended December 31:

Other Income and Deductions, net	2008			2007			2006
	(Millions of Dollars)
Carrying Costs	$	0.8		$	28.8		$	25.0
Gain on Property Sales		2.3			12.9			3.2
AFUDC - Equity		7.5			5.1			14.5
Donations and Contributions		(12.0	)		(10.3	)		(6.0	)
Other, net		11.3			5.2			6.2
Total Other Income and Deductions, net	$	9.9		$	41.7		$	42.9

Property and Depreciation: We record property, plant and equipment at cost. Cost includes material, labor, overheads and capitalized interest. Utility property also includes AFUDC - Equity. 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.

Our utility depreciation rates are certified by the PSCW and MPSC and include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 3.6% in 2008 and 3.7% in 2007 and 2006.

For assets other than our regulated assets and leased equipment, we accrue depreciation expense at straight-line rates over the estimated useful lives of the assets, or over the non-cancellable lease term for leased equipment.

We collect in our rates amounts representing future removal costs for many assets that do not have an associated ARO. 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 $472.5 million as of December 31, 2008 and $454.3 million as of December 31, 2007.

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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.

During 2008, we accrued AFUDC at a rate of 9.09% as authorized by the PSCW in our 2008 test year in docket 5-UR-103. Consistent with that order, we accrue AFUDC on 50% of all utility CWIP projects except our Oak Creek AQCS project, which accrues AFUDC on 100% of CWIP. Our rates were set to provide a current return on CWIP that does not accrue AFUDC. During 2007 and 2006, we accrued AFUDC at a rate of 8.94%, as authorized by the PSCW.

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

	2008		2007		2006
	(Millions of Dollars)
AFUDC - Debt	$	3.0	$	1.8	$	5.1
AFUDC - Equity	$	7.5	$	5.1	$	14.5

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

Materials, Supplies and Inventories	2008		2007
	(Millions of Dollars)
Fossil Fuel	$	132.2	$	125.0
Materials and Supplies		93.1		88.5
Natural Gas in Storage		71.2		72.1
Total	$	296.5	$	285.6

Substantially all fossil fuel, materials and supplies and natural gas in storage inventories are recorded using the weighted-average method of accounting.

Regulatory Accounting: We account for our regulated operations in accordance with SFAS 71. This statement sets forth the application of GAAP 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 on 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, the PSCW. 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. Regulatory assets and liabilities that are expected to be amortized within one year are recorded as current on the balance sheet. For further information, see Note C.

Derivative Financial Instruments: We have derivative physical and financial instruments as defined by SFAS 133 which we report at fair value. For further information, see Note K.

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

Restricted Cash: Cash proceeds that we received from the sale of Point Beach that are to be used for the benefit of our customers are recorded as restricted cash.

Margin Accounts: Cash deposited in brokerage accounts for margin requirements is recorded in Other Current Assets on our Consolidated Balance Sheets.

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

Asset Retirement Obligations: Consistent with SFAS 143 and FIN 47, we record a liability for a legal ARO 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

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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 AROs in rates and when we would recognize these costs under SFAS 143. 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, 2008 and 2007, we had a total ownership interest of approximately 23.0% and 23.6%, in 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 P.

Income Taxes: We follow the liability method in accounting for income taxes as prescribed by 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.

Investment tax credits related to regulated utility assets are recorded as a deferred credit on the balance sheet and amortized to income over the applicable service lives of related properties in accordance with regulatory treatment. We are included in Wisconsin Energy’s consolidated Federal income tax return. Wisconsin Energy allocates Federal tax expense or credits to us based on our separate tax computation. For further information on income taxes, see Note F.

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

We recognize interest and penalties accrued related to unrecognized tax benefits in Income Taxes in our Consolidated Income Statements, as well as regulatory assets or regulatory liabilities in our Consolidated Balance Sheets.

We collect sales and use taxes from our customers and remit these taxes to governmental authorities. These taxes are recorded in our Consolidated Income Statements on a net basis.

Stock Options: Our employees participate in the Wisconsin Energy stock-based compensation plan. The amounts reported represent the allocated costs related to options held by our employees.

Effective January 1, 2006, Wisconsin Energy adopted SFAS 123R, using the modified prospective method. Wisconsin Energy uses a binomial pricing model to estimate the fair value of stock options granted subsequent to that date. Historically, all stock options have been granted with an exercise price equal to the fair market value of the common stock on the date of grant and expire no later than ten years from the grant date. Accordingly, no compensation expense was recognized in connection with option grants. SFAS 123R requires that excess tax benefits be reported as a financing cash inflow. In addition, SFAS 123R requires Wisconsin Energy to report unearned stock-based compensation associated with non-vested restricted stock and performance awards within other paid in capital in its Consolidated Statements of Common Equity. For further discussion of this standard and the impacts to our Consolidated Financial Statements, see Note H.

The fair value of each Wisconsin Energy option was calculated using a binomial option pricing model using the following weighted average assumptions:

	2008	2007	2006
Risk-free interest rate	2.9% - 3.9%	4.7% - 5.1%	4.3% - 4.4%
Dividend yield	2.1%	2.2%	2.4%
Expected volatility	20.0%	13.0% - 20.0%	17.0% - 20.0%
Expected life (years)	6.7	6.0	6.3
Expected forfeiture rate	2.0%	2.0%	2.0%
Pro forma weighted average fair value of stock options granted	$9.93	$8.72	$7.55

B – RECENT ACCOUNTING PRONOUNCEMENTS

Fair Value Measurements: In September 2006, the FASB issued SFAS 157. SFAS 157 defines fair value, provides guidance for using fair value to measure assets and liabilities as well as a framework for measuring fair value and expands disclosures related to fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We partially adopted the provisions of SFAS 157 effective January 1, 2008. We fully adopted the provisions of SFAS 157 effective

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January 1, 2009. The adoption of SFAS 157 did not have a significant financial impact on our consolidated financial statements. See Note L — Fair Value Measurements for further information on SFAS 157.

Fair Value Option: In February 2007, the FASB issued SFAS 159. SFAS 159 permits an entity to measure certain financial assets and financial liabilities at fair value and also establishes presentation and disclosure requirements. SFAS 159 is effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. We adopted the provisions of SFAS 159 effective January 1, 2008. The adoption of SFAS 159 did not have any financial impact on our consolidated financial statements.

Disclosures about Derivative Instruments and Hedging Activities: In March 2008, the FASB issued SFAS 161. SFAS 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. SFAS 161 is effective for fiscal years beginning after November 15, 2008. We adopted the provisions of SFAS 161 effective January 1, 2009. The adoption of SFAS 161 did not have any financial impact on our consolidated financial statements.

Disclosures by Public Entities about Interests in Variable Interest Entities: In December 2008, the FASB issued FSP FIN 46(R)-8. FSP FIN 46(R)-8 amends FIN 46 to require public entities, including sponsors that have a variable interest in a variable interest entity, to provide additional disclosures regarding their involvement with variable interest entities. FSP FIN 46(R)-8 is effective for the first operating period (interim or annual) ending after December 15, 2008. We adopted the provisions of FSP FIN 46(R)-8 effective December 31, 2008. The adoption of FSP FIN 46(R)-8 did not have any financial impact on our consolidated financial statements. See Note E — Variable Interest Entities for further information on FSP FIN 46(R)-8.

C – REGULATORY ASSETS AND LIABILITIES

We account for our regulated operations in accordance with SFAS 71.

Our primary regulator, the PSCW, 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 orders or correspondence with our primary regulator. These deferred costs will be considered in future rate setting proceedings. As of December 31, 2008 and 2007, we had approximately $20.0 million and $32.2 million, respectively, of net regulatory assets that were not earning a return.

In January 2008, the PSCW issued a rate order that, among other things, reaffirmed our accounting for the regulatory assets and liabilities identified below. In addition, the rate order provided for the immediate recovery in January 2008 of $85.0 million related to deferred fuel costs and escrowed bad debt costs. The rate order also provided for the recovery over a six year period of the balance of the deferred fuel costs, escrowed bad debt costs and escrowed transmission costs. The order also specified that the deferred Point Beach gain would be passed on to customers over a three year period. Finally, the order eliminated the use of escrow accounting for transmission costs that are incurred after December 31, 2007.

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

	2008		2007
	(Millions of Dollars)
Regulatory Assets
Deferred unrecognized pension costs	$	392.0	$	189.9
Escrowed electric transmission costs		199.0		240.9
Deferred plant related — capital leases		130.9		104.1
Deferred income tax related		70.1		87.8
Deferred SFAS 133 amounts		57.0		12.6
Deferred fuel related costs		47.1		86.7
Other, net		166.7		218.3
Total regulatory assets	$	1,062.8	$	940.3
Regulatory Liabilities
Deferred cost of removal obligations	$	472.5	$	454.3
Deferred Point Beach related		431.5		906.8
Deferred income tax related		83.8		111.9
Other, net		106.4		98.8
Total regulatory liabilities	$	1,094.2	$	1,571.8

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We have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of the pension and OPEB plans qualify as a regulatory asset.

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

Consistent with a generic order from, and past rate-making practices of, the PSCW, we defer as a regulatory asset costs associated with the remediation of former manufactured gas plant sites. As of December 31, 2008, we have recorded $28.0 million of environmental costs associated with manufactured gas plant sites as a regulatory asset, including $15.2 million of deferrals for actual remediation costs incurred and a $12.8 million accrual for estimated future site remediation (see Note Q). In addition, we have deferred $6.9 million of insurance recoveries associated with the environmental costs as regulatory liabilities. We amortize the deferred costs actually incurred and insurance recoveries over five years in accordance with rate-making treatment.

As of December 31, 2008, we have $7.4 million of escrowed bad debt costs. The PSCW authorized escrow accounting for residential bad debt costs whereby we defer actual bad debt write-offs that exceed amounts allowed in rates.

D – ASSET RETIREMENT OBLIGATIONS

The following table presents the change in our AROs during 2008:

	Balance at 12/31/07		Liabilities Incurred		Liabilities Settled	Accretion		Cash Flow Revisions		Balance at 12/31/08
	(Millions of Dollars)
AROs	$	50.0	$	—	($0.5)	$	2.8	$	—	$	52.3

Our AROs were significantly reduced during 2007 due to the sale of Point Beach. Upon closing of the sale, the buyer assumed the liability to decommission the plant, including the ARO, spent fuel and the obligation to return the site to greenfield status.

E – VARIABLE INTEREST ENTITIES

Under FIN 46 and FIN 46R, the primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. In December 2008, the FASB issued FSP FIN 46(R)-8 requiring additional disclosures by sponsors, significant interest holders in variable interest entities and potential variable interest entities.

We assess our relationships to potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal and gas transporters, and other counterparties in power purchase agreements and joint ventures as prescribed by FIN 46R. We consider the potential that our contracts or other arrangements provide subordinated financial support, the potential for us to absorb losses or rights to residual returns of the entity, the ability to directly or indirectly make decisions about the entities’ activities and other factors.

We have identified two tolling and purchased power agreements with third parties but have been unable to determine if we are the primary beneficiary of these two variable interest entities as defined by FIN 46. The requested information required to make this determination has not been supplied. 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 contract as an operating lease. A similar power purchase agreement expired during the second quarter of 2008. We continue to evaluate our tolling and purchased power agreements with third parties on a quarterly basis. We have approximately $471.5 million of required payments over the remaining terms of these two agreements, which expire over the next 14 years. We believe the required payments or any replacement power purchased will continue to be recoverable in rates. Total capacity and minimum lease payments under these contracts in 2008, 2007 and 2006 were $66.4 million, $70.4 million and $68.9 million, respectively.

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F – INCOME TAXES

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

Income Taxes	2008			2007			2006
	(Millions of Dollars)
Current tax (benefit) expense		($95.3)		$	284.2		$	228.2
Deferred income taxes, net		270.5			(91.9	)		(55.4	)
Investment tax credit, net		(5.9	)		(3.8	)		(3.9	)
Total Income Tax Expense	$	169.3		$	188.5		$	168.9

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

	2008					2007					2006
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	$	157.3		35.0	%	$	166.7		35.0	%	$	155.6		35.0	%
State income taxes net of federal tax benefit		23.5		5.2	%		24.5		5.1	%		22.6		5.1	%
Domestic production activities deduction		(7.9	)	(1.8	%)		—		—	%		—		—	%
Investment tax credit restored		(5.9	)	(1.3	%)		(3.8	)	(0.8	%)		(3.9	)	(0.9	%)
Other, net		2.3		0.5	%		1.1		0.2	%		(5.4	)	(1.2	%)
Total Income Tax Expense	$	169.3		37.6	%	$	188.5		39.5	%	$	168.9		38.0	%

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

	2008			2007
	(Millions of Dollars)
Deferred Tax Assets
Current
Deferred gain	$	37.0		$	98.0
Employee benefits and compensation		11.0			10.3
Recoverable gas costs		0.2			—
Other		5.5			0.6
Total Current Deferred Tax Assets	$	53.7		$	108.9
Non-current
Deferred revenues	$	204.5		$	122.0
Construction advances		105.7			97.3
Employee benefits and compensation		80.8			116.2
Deferred gain		27.2			77.5
Emission allowances		13.0			20.3
Other		(9.6	)		10.3
Total Non-current Deferred Tax Assets	$	421.6		$	443.6
Total Deferred Tax Assets	$	475.3		$	552.5

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	2008			2007
	(Millions of Dollars)
Deferred Tax Liabilities
Current
Prepaid items	$	42.8		$	38.7
Uncollectible account expense		—			11.8
Total Current Deferred Tax Liabilities	$	42.8		$	50.5
Non-current
Property-related	$	870.7		$	720.2
Employee benefits and compensation		80.4			—
Deferred transmission costs		76.4			95.9
Investment in transmission affiliate		52.2			45.0
Other		33.6			51.0
Total Non-current Deferred Tax Liabilities	$	1,113.3		$	912.1
Total Deferred Tax Liabilities	$	1,156.1		$	962.6
Consolidated Balance Sheet Presentation	2008			2007
Current Deferred Tax Asset	$	10.9		$	58.4
Non-current Deferred Tax Liability		($691.7	)		($468.5	)

Consistent with ratemaking treatment, deferred taxes are offset in the above table for temporary differences which have related regulatory assets or liabilities.

We adopted the provisions of FIN 48 on January 1, 2007. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

	2008			2007
	(Millions of Dollars)
Balance as of January 1	$	12.1		$	12.4
Additions based on tax positions related to the current year		—			—
Additions for tax positions of prior years		5.4			—
Reductions for tax positions of prior years		(0.3	)		(0.3	)
Reductions due to statute of limitations		—			—
Settlements during the period		—			—
Balance as of December 31	$	17.2		$	12.1

The amount of unrecognized tax benefits as of December 31, 2008 and 2007 excludes FIN 48 related deferred tax assets of $9.1 million and $4.0 million, respectively. As of December 31, 2008 and 2007, the net amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was approximately $8.1 million.

We recognize interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense. For the years ended December 31, 2008 and 2007, we recognized approximately $1.7 million and $1.1 million, respectively, of accrued interest in the Consolidated Income Statements. For the years ended December 31, 2008 and 2007, we recognized no penalties in the Consolidated Income Statements. We had approximately $3.6 million and $2.0 million of interest accrued in the Consolidated Balance Sheets as of December 31, 2008 and 2007, respectively.

We do not anticipate any significant increases or decreases in the total amounts of unrecognized tax benefits within the next twelve months.

Our primary tax jurisdictions include Federal and the state of Wisconsin. Currently, the tax years of 2004 through 2008 are subject to Federal and Wisconsin examination.

G – NUCLEAR OPERATIONS

Point Beach: Prior to September 28, 2007, we owned two 518 MW electric generating units (Unit 1 and Unit 2) at Point Beach in Two Rivers, Wisconsin. During 2007 and 2006, Point Beach provided approximately 17.5% and 25.7%, respectively, of our net electric energy supply.

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On September 28, 2007, we sold Point Beach to an affiliate of FPL for approximately $924 million. Pursuant to the terms of the sale agreement, the buyer purchased Point Beach, its nuclear fuel and associated inventories, and assumed the obligation to decommission the plant. We retained approximately $506 million of the sales proceeds, which represents the net book value of the assets sold and certain transaction costs. In addition, we have deferred the net gain on the sale of approximately $418 million as a regulatory liability and have deposited those proceeds into a restricted cash account.

In connection with the sale, we also transferred $390 million of decommissioning funds to the buyer. We then liquidated the balance of the decommissioning trust assets and retained approximately $552 million of that cash. This cash was also placed into the restricted cash account. We are using the cash in the restricted cash account, and the interest earned on the balance, for the benefit of our customers and to pay certain taxes. Our regulators are directing the manner in which these proceeds will benefit customers. As of December 31, 2008, we have recorded a regulatory liability of approximately $431.5 million that represents deferred gains that will be used for the benefit of our customers.

A long-term power purchase agreement with the buyer became effective upon closing of the sale. Pursuant to this agreement, we are purchasing all of the energy produced by Point Beach. The power purchase agreement extends through 2030 for Unit 1 and 2033 for Unit 2. Based on the agreement, we will be paying a predetermined price per MWh for energy delivered. Under the agreement, if our credit rating from either S&P or Moody’s falls below investment grade, or if the holders of any indebtedness in excess of $100.0 million accelerate or have the right to accelerate the maturity of such indebtedness as a result of a default, we would need to provide a parent guarantee or other form of collateral in the amount of $100.0 million (escalating at 3% per year commencing in 2024).

The discussion below reflects decommissioning and nuclear operations through September 28, 2007.

Nuclear Decommissioning: We recorded decommissioning expense in amounts equal to the amounts collected in rates and funded to the external trusts. Nuclear decommissioning costs were accrued over the expected service lives of the nuclear generating units and were included in electric rates. The decommissioning funding was $11.2 million through September 2007 and $17.6 million for the year ended 2006. We liquidated our decommissioning trust assets as part of the sale of Point Beach. We had no investments in our Nuclear Decommissioning Trusts as of December 31, 2008 and 2007.

Our investments in the trusts were recorded at fair value and we were allowed regulatory treatment for the fair value adjustment. Realized gains and losses for the years ended December 31, 2008 and 2007 were as follows:

	2008		2007
	(Millions of Dollars)
Realized Gains	$	—	$	320.6
Realized (Losses)		—		(8.3	)
Net Realized Gain	$	—	$	312.3

Total gains and total losses by security type for the years ended December 31, 2008 and 2007 were as follows:

2008	Total Gains		Total (Losses)			Net Gain (Loss)
Debt	$	—	$	—		$	—
Equity		—		—			—
Total	$	—	$	—		$	—
2007	Total Gains		Total (Losses)			Net Gain (Loss)
Debt	$	2.2		($3.0	)		($0.8	)
Equity		318.4		(5.3	)		313.1
Total	$	320.6		($8.3	)	$	312.3

Decontamination and Decommissioning Fund: The Energy Policy Act of 1992 established a D&D Fund for the DOE’s nuclear fuel enrichment facilities. Deposits to the D&D Fund are derived in part from special assessments on utilities using enrichment services. In October 2006, a final payment was made to the DOE. As a result, a liability no longer exists for this fund. The deferred regulatory asset was amortized to nuclear fuel expense and included in utility rates through September 2007.

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H – COMMON EQUITY

Share-Based Compensation Plans: Employees of Wisconsin Electric participate in a plan approved by Wisconsin Energy stockholders that provides a long-term incentive through equity interests in Wisconsin Energy to outside directors, selected officers and key employees of Wisconsin Energy and its subsidiaries. The plan provides for the granting of Wisconsin Energy stock options, stock appreciation rights, restricted stock awards and performance shares. Awards may be paid in Wisconsin Energy common stock, cash or a combination thereof. Effective January 1, 2006, Wisconsin Energy adopted SFAS 123R using the modified prospective method. We utilize the straight-line attribution method for recognizing share-based compensation expense under SFAS 123R. Accordingly, for employee awards classified as equity, share-based compensation cost is measured at the grant date based on the fair value of the award and is recognized as expense over the requisite service period. There were no modifications to the terms of outstanding Wisconsin Energy stock options during the period.

The following table summarizes recorded pre-tax share-based compensation expense and the related tax benefit for Wisconsin Energy share-based awards made to our employees and directors during the years ended December 31:

	2008		2007		2006
	(Millions of Dollars)
Stock options	$	11.3	$	10.8	$	6.9
Performance units		8.7		5.0		6.1
Restricted stock		0.3		0.5		0.4
Share-based compensation expense	$	20.3	$	16.3	$	13.4
Related Tax Benefit	$	8.1	$	6.6	$	5.4

Stock Options: The exercise price of a Wisconsin Energy stock option under the plan 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. Option grants consist of non-qualified stock options and vest on a cliff-basis after a three year period. Options expire no later than ten years from the date of grant. For further information regarding stock-based compensation and the valuation of Wisconsin Energy stock options, see Note A.

The following is a summary of Wisconsin Energy stock options issued to and held by our employees through December 31, 2008:

Stock Options	Number of Options		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life (Years)	Aggregate Intrinsic Value (Millions)
Outstanding as of January 1, 2008	6,512,147		$	35.31
Granted	1,266,645		$	48.04
Exercised	(352,810	)	$	26.35
Forfeited	(2,045	)	$	48.04
Outstanding as of December 31, 2008	7,423,937		$	37.91	6.4	$	45.1
Exercisable as of December 31, 2008	4,084,268		$	31.83	5.0	$	42.6

We expect that substantially all of the outstanding options as of December 31, 2008 will be exercised.

In January 2009, the Compensation Committee awarded 1,129,315 Wisconsin Energy non-qualified stock options at an exercise price of $42.22 to our officers and key executives under its normal schedule of awarding long-term incentive compensation.

The intrinsic value of Wisconsin Energy options exercised during the years ended December 31, 2008, 2007 and 2006 was $6.9 million, $22.7 million and $16.0 million, respectively. Cash received by Wisconsin Energy from exercises of their options by our employees was $8.0 million, $27.5 million and $21.1 million during the years ended December 31, 2008, 2007 and 2006, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $2.3 million, $8.9 million and $6.4 million, respectively.

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The following table summarizes information about Wisconsin Energy stock options held by our employees and outstanding as of December 31, 2008:

	Options Outstanding			Options Exercisable
		Weighted-Average			Weighted-Average
Range of Exercise Prices	Number of Options	Exercise Price	Remaining Contractual Life (Years)	Number of Options	Exercise Price	Remaining Contractual Life (Years)
$12.79 to $31.07	1,442,787	$25.85	3.7	1,442,787	$25.85	3.7
$33.44 to $39.48	3,454,150	$35.65	6.0	2,445,841	$34.08	5.5
$42.56 to $48.04	2,527,000	$47.87	8.5	195,640	$47.80	8.1
	7,423,937	$37.91	6.4	4,084,268	$31.83	5.0

The following table summarizes information about our non-vested Wisconsin Energy options held by our employees through December 31, 2008:

Non-Vested Stock Options	Number of Options		Weighted- Average Fair Value
Non-vested as of January 1, 2008	3,160,586		$	8.21
Granted	1,266,645		$	9.93
Vested	(1,085,517	)	$	8.36
Forfeited	(2,045	)	$	9.93
Non-Vested as of December 31, 2008	3,339,669		$	8.81

As of December 31, 2008, total compensation costs related to non-vested Wisconsin Energy stock options held by our employees and not yet recognized was approximately $9.0 million, which is expected to be recognized over the next 20 months on a weighted-average basis.

Restricted Shares: The Compensation Committee has also approved grants of Wisconsin Energy restricted stock to certain of our key employees. The following restricted stock activity related to our employees occurred during 2008:

Restricted Shares	Number of Shares		Weighted- Average Market Price
Outstanding as of January 1, 2008	92,177
Granted	—			—
Released / Forfeited	(24,849	)	$	26.52
Outstanding as of December 31, 2008	67,328

Recipients of the Wisconsin Energy 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 restricted stock generally expire 10 years after the award date subject to an accelerated expiration schedule for some of the shares based on the achievement of certain financial performance goals.

Wisconsin Energy records the market value of the restricted stock awards on the date of grant. We then amortize our share of allocated expense over the vesting period of the awards. We also adjust expense for acceleration of vesting due to achievement of performance goals. The intrinsic value of Wisconsin Energy restricted stock vesting was $1.1 million, $1.8 million and $0.9 million for the years ended December 31, 2008, 2007 and 2006, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was $0.3 million, $0.7 million and $0.3 million, respectively.

As of December 31, 2008, total compensation cost related to our share of Wisconsin Energy restricted stock not yet recognized was approximately $0.8 million, which is expected to be recognized over the next 48 months on a weighted-average basis.

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Performance Units: In January 2009, 2008 and 2007, the Compensation Committee granted 309,310, 124,175 and 124,655 Wisconsin Energy performance units, respectively, to our officers and other key employees under the Wisconsin Energy Performance Unit Plan. Under the grants, the ultimate number of units which will be awarded is dependent upon the achievement of certain financial performance of Wisconsin Energy’s common stock over a three year period. Under the terms of the award, participants may earn between 0% and 175% of the base performance award. All grants are settled in cash. We are accruing our share of compensation costs over the three year period based on our estimate of the final expected value of the award. In July 2006, the Compensation Committee amended the terms of performance shares granted in 2004 to allow the recipients to receive cash or Wisconsin Energy common stock upon settlement. Performance units earned as of December 31, 2008, 2007 and 2006 had a total intrinsic value of $7.9 million, $4.7 million and $6.5 million, respectively. The awards were subsequently distributed to our officers and key employees in January 2009, 2008 and 2007. The actual tax benefit realized for the tax deductions from the distribution of performance units was approximately $2.9 million, $1.6 million and $1.9 million, respectively. As of December 31, 2008, total compensation cost related to performance units not yet recognized was approximately $5.8 million, which is expected to be recognized over the next 19 months on a weighted-average basis.

Equity Contribution: Our capitalization reflects the impact of a $100 million equity contribution from Wisconsin Energy in 2006.

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

The January 2008 rate order requires us to maintain a capital structure as set forth by the PSCW. This capital structure differs from GAAP as it reflects regulatory adjustments. We are required to maintain a common equity ratio range of between 48.5% and 53.5%. We must obtain PSCW approval to pay dividends above the test year levels that would cause us to fall below the authorized level of common equity.

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

See Note J for a discussion of certain financial covenants related to our bank back-up credit facility.

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

I — LONG-TERM DEBT

Debentures and Notes: As of December 31, 2008, the maturities and sinking fund requirements of our long-term debt outstanding (excluding obligations under capital leases) were as follows:

	(Millions of Dollars)
2009	$	—
2010		0.1
2011		—
2012		—
2013		300.0
Thereafter		1,601.4
Total	$	1,901.5

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

During 2008, we issued $550 million of debentures under an existing $800 million shelf registration statement filed with the SEC in August 2007. The net proceeds were used to repay short-term debt and for other general corporate purposes, including the payment of a $150 million special dividend to Wisconsin Energy.

We are the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amount of $147 million. The bonds previously bore interest at an “auction rate.” In March 2008, because of substantial disruptions in the auction rate bond market, we purchased (in lieu of redemption) these bonds at a purchase price of par plus accrued interest to the date of purchase. In August 2008, we converted the interest rate determination method for the bonds to a weekly rate and they were remarketed to third parties. Letters of credit from Wells Fargo Bank, National Association now provide credit and liquidity support for the remarketed

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bonds. Prior to the remarketing, we held the bonds and they remained outstanding; however, because they were held by us, they were not reflected in our consolidated long-term debt.

During 2007, we retired $250 million of notes due December 1, 2007 through the issuance of short-term debt.

In November 2006, we issued $300 million of notes due December 1, 2036 under an existing $665 million shelf registration statement filed with the SEC.

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

We treat the long-term power purchase contract as an operating lease for rate-making purposes and we record our minimum lease payments as purchased power expense on the Consolidated Income Statements. We paid a total of $28.1 million, $27.1 million and $26.1 million in minimum lease payments during 2008, 2007 and 2006, respectively. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on our Consolidated Balance Sheets (see Regulatory Assets - Deferred plant related - capital leases 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 during 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 was $154.1 million at December 31, 2008 and will decrease to zero over the remaining life of the contract.

In July 2005, the first 545 MW natural gas-fired generation unit, PWGS 1, was placed in service at the PWGS. We are leasing this unit from We Power under a PSCW approved lease. Pursuant to SFAS 13, Accounting for Leases, we are accounting for this lease as a capital lease and recorded the leased plant and corresponding obligation under the capital lease at the estimated fair value of $337.9 million. We are amortizing the leased plant on a straight-line basis over the original 25-year term of the lease.

This lease is treated as an operating lease for rate-making purposes. We record the lease payments as rent expense in other operation and maintenance in the Consolidated Income Statement. The lease payments are expected to be recovered through our rates. The recoverability of the lease payments is supported by the 2001 lease generation law. We paid a total of $48.3 million, $48.1 million and $47.8 million in minimum lease payments during 2008, 2007 and 2006, respectively. We are recording a deferred regulatory asset for the difference between the lease payments and the sum of imputed interest cost and amortization costs calculated under capital lease accounting (see Regulatory Assets - Deferred plant related - capital leases in Note C). Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $126.8 million in the year 2021 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 was $331.1 million at December 31, 2008 and will decrease to zero over the remaining life of the contract.

In November 2007, we began utilizing the new coal handling system constructed as part of We Power’s new Oak Creek expansion to support the existing units located on the Oak Creek site. We are leasing this unit from We Power under a PSCW approved lease. Pursuant to SFAS 13, Accounting for Leases, we are accounting for this lease as a capital lease and recorded the leased plant and corresponding obligation under the capital lease at the estimated fair value of $185.7 million. We are amortizing the leased plant on a straight-line basis over the 32-year term of the lease.

This lease is treated as an operating lease for rate-making purposes. We record the lease payments as rent expense in other operation and maintenance in the Consolidated Income Statement. The lease payments are expected to be recovered through our rates. The recoverability of the lease payments is supported by the 2001 lease generation law. We paid a total of $24.2 million and $3.8 million in lease payments during 2008 and 2007, respectively. We are recording a deferred regulatory asset for the difference between the lease payments and the sum of imputed interest cost and amortization costs calculated under capital lease accounting (see Regulatory Assets - Deferred plant related - capital leases in Note C). Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $100.7 million in the year 2029 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 was $185.7 million at December 31, 2008 and will decrease to zero over the remaining life of the contract.

In May 2008, the second 545 MW natural gas-fired generation unit, PWGS 2, was placed in service at the PWGS. We are leasing this unit from We Power under a PSCW approved lease. Pursuant to SFAS 13, Accounting for Leases, we are accounting for this lease as a capital lease and recorded the leased plant and corresponding obligation under the capital lease at the estimated fair value of $331.1 million. We are amortizing the leased plant on a straight-line basis over the original 25-year term of the lease.

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This lease is treated as an operating lease for rate-making purposes. We record the lease payments as rent expense in other operation and maintenance in the Consolidated Income Statement. The lease payments are expected to be recovered through our rates. The recoverability of the lease payments is supported by the 2001 lease generation law. We paid a total of $29.7 million in minimum lease payments during 2008. We are recording a deferred regulatory asset for the difference between the lease payments and the sum of imputed interest cost and amortization costs calculated under capital lease accounting (see Regulatory Assets—Deferred plant related - capital leases in Note C). Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $127.1 million in the year 2024 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 was $330.2 million at December 31, 2008 and will decrease to zero over the remaining life of the contract.

We had a nuclear fuel leasing arrangement with Wisconsin Electric Fuel Trust, which was treated as a capital lease. Under this arrangement, we leased and amortized nuclear fuel to fuel expense as power was generated. In connection with the sale of Point Beach, the nuclear fuel leasing arrangement with Wisconsin Electric Fuel Trust was dissolved in September 2007. We terminated the lease and paid off all of Wisconsin Electric Fuel Trust’s outstanding commercial paper, aggregating $76.2 million.

Following is a summary of our capitalized leased facilities as of December 31:

Capital Lease Assets	2008			2007
	(Millions of Dollars)
Leased Facilities
Long-term power purchase commitment	$	140.3		$	140.3
Accumulated amortization		(64.1	)		(58.4	)
Total Leased Facilities	$	76.2		$	81.9
PWGS 1
Under capital lease	$	337.9		$	337.2
Accumulated amortization		(46.6	)		(33.1	)
Total PWGS 1	$	291.3		$	304.1
OC Coal Handling System
Under capital lease	$	185.7		$	162.1
Accumulated amortization		(6.0	)		(0.8	)
Total Coal Handling System	$	179.7		$	161.3
PWGS 2
Under capital lease	$	331.1		$	—
Accumulated amortization		(8.1	)		—
Total PWGS 2	$	323.0		$	—

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Future minimum lease payments under our capital leases and the present value of our net minimum lease payments as of December 31, 2008 are as follows:

Capital Lease Obligations	Power Purchase Commitment			PWGS 1			OC Coal Handling System			PWGS 2			Total
	(Millions of Dollars)
2009	$	34.9		$	48.3		$	26.9		$	48.8		$	158.9
2010		36.2			48.3			26.5			48.8			159.8
2011		37.5			48.3			26.5			48.8			161.1
2012		38.9			48.3			26.5			48.8			162.5
2013		40.4			48.3			26.5			48.8			164.0
Thereafter		215.9			801.8			837.7			947.4			2,802.8
Total Minimum Lease Payments		403.8			1,043.3			970.6			1,191.4			3,609.1
Less: Estimated Executory Costs		(92.9	)		—			—			—			(92.9	)
Net Minimum Lease Payments		310.9			1,043.3			970.6			1,191.4			3,516.2
Less: Interest		(156.8	)		(712.2	)		(784.9	)		(861.2	)		(2,515.1	)
Present Value of Net
Minimum Lease Payments		154.1			331.1			185.7			330.2			1,001.1
Less: Due Currently		(5.1	)		(2.6	)		—			(1.6	)		(9.3	)
	$	149.0		$	328.5		$	185.7		$	328.6		$	991.8

J — SHORT-TERM DEBT

Our commercial paper balance and the corresponding weighted-average interest rate as of December 31 are shown in the following table:

	2008				2007
Short-Term Debt	Balance		Interest Rate		Balance		Interest Rate
	(Millions of Dollars, except for percentages)
Commercial Paper	$	—	—	%	$	323.3	4.77	%

The following information relates to commercial paper outstanding for the years ended December 31:

	2008			2007
	(Millions of Dollars, except for percentages)
Maximum Commercial Paper Outstanding	$	452.5		$	324.0
Average Commercial Paper Outstanding	$	283.3		$	173.7
Weighted-Average Interest Rate		2.71	%		5.28	%

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

An affiliate of Lehman Brothers Holdings, which filed for bankruptcy in September 2008, committed approximately $23.6 million under our bank back-up credit facility. Excluding Lehman’s commitment, as of December 31, 2008, we had approximately $472.3 million of available, undrawn lines under our bank back-up credit facility. Our bank back-up credit facility expires in March 2011, but may be renewed for two one-year extensions, subject to lender approval. As of December 31, 2008, we did not have any commercial paper outstanding and our subsidiary had a $29.6 million note payable to Wisconsin Energy with a weighted-average interest rate of 5.99%.

Our bank back-up credit facility contains customary covenants, including certain limitations on our ability to sell assets. The credit facility also contains 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.

As of December 31, 2008, we were in compliance with all covenants.

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K — DERIVATIVE INSTRUMENTS

We follow SFAS 133, as amended by SFAS 149, 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 do not offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivatives executed with the same counterparty under the same master netting arrangement. As of December 31, 2008, we recognized $57.0 million in regulatory assets and $11.8 million in regulatory liabilities related to derivatives in comparison to $12.6 million in regulatory assets and $14.5 million in regulatory liabilities as of December 31, 2007.

L — FAIR VALUE MEASUREMENTS

We adopted SFAS 157 as of January 1, 2008, which among other things, requires enhanced disclosures about assets and liabilities that are measured and reported at fair value. SFAS 157 establishes a hierarchal disclosure framework which prioritizes and ranks the level of observable inputs used in measuring fair value.

As defined in SFAS 157, fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. Accordingly, we also utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The hierarchy established under SFAS 157 gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).

Assets and liabilities measured and reported at fair value are classified and disclosed in one of the following categories:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Instruments in this category consist of financial instruments such as exchange-traded derivatives, cash equivalents and restricted cash investments.

Level 2 — Pricing inputs are other than quoted prices in active markets, which are either directly or indirectly observable as of the reporting date, and fair value is determined through the use of models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as OTC forwards and options.

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. The inputs in the determination of fair value require significant management judgment or estimation. At each balance sheet date, we perform an analysis of all instruments subject to SFAS 157 and include in Level 3 all instruments whose fair value is based on significant unobservable inputs.

In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, an instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the instrument.

The following table summarizes our financial assets and liabilities by level within the fair value hierarchy as of December 31, 2008:

Recurring Fair Value Measures
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Cash Equivalents	$	8.0	$	—	$	—	$	8.0
Restricted Cash		386.5		—		—		386.5
Derivatives		—		4.1		8.8		12.9
Total	$	394.5	$	4.1	$	8.8	$	407.4
Liabilities:
Derivatives	$	34.0	$	15.3	$	—	$	49.3
Total	$	34.0	$	15.3	$	—	$	49.3

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Cash Equivalents consist of certificates of deposit and money market funds. Restricted Cash consists of certificates of deposit and government backed interest bearing securities and represents the remaining funds to be distributed to customers resulting from the net proceeds received from the sale of Point Beach. Derivatives reflect positions we hold in exchange-traded derivative contracts and OTC derivative contracts. Exchange-traded derivative contracts, which include futures and exchange-traded options, are generally based on unadjusted quoted prices in active markets and are classified within Level 1. Some OTC derivative contracts are valued using broker or dealer quotations, or market transactions in either the listed or OTC markets utilizing a mid-market pricing convention (the mid-point between bid and ask prices), as appropriate. In such cases, these derivatives are classified within Level 2. Certain OTC derivatives may utilize models to measure fair value. Generally, we use a similar model to value similar instruments. Valuation models utilize various inputs which include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs (i.e., inputs derived principally from or corroborated by observable market data by correlation or other means). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Certain OTC derivatives are in less active markets with a lower availability of pricing information which might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in Level 3.

The following table summarizes the fair value of derivatives classified as Level 3 in the fair value hierarchy:

Fair Value of Derivatives	2008
	(Millions of Dollars)
Balance as of January 1	$	13.0
Realized and unrealized gains (losses)		—
Purchases, issuances and settlements		(4.2	)
Transfers in and/or out of Level 3		—
Balance as of December 31	$	8.8
Change in unrealized gains (losses) relating to instruments still held as of December 31	$	—

Derivative instruments reflected in Level 3 of the hierarchy include FTRs allocated by MISO that are measured at fair value each reporting period using monthly or annual auction shadow prices from relevant auctions. Changes in fair value for Level 3 recurring items are recorded on our balance sheet in accordance with SFAS 71. See Note K — Derivative Instruments for further information on the offset to regulatory assets and liabilities.

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

	2008				2007
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	19.0	$	30.4	$	22.3
Long-term debt including current portion	$	1,901.5	$	1,896.3	$	1,351.6	$	1,316.5

The carrying value of net accounts receivable, accounts payable and short-term borrowings approximates fair value due to the short-term nature of these instruments. 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.

M — BENEFITS

Pensions and Other Post-retirement Benefits: We participate in Wisconsin Energy’s defined benefit pension plans that cover substantially all of our employees. The plans provide defined benefits based upon years of service and final average salary.

We also participate in Wisconsin Energy’s OPEB plans that cover substantially all of our employees. The health care plans are contributory with participants’ contributions adjusted annually; the life insurance plans are noncontributory. The accounting for the health care plans anticipates future cost-sharing changes to the written plans that are consistent with our expressed intent to maintain

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the current cost sharing levels. The post-retirement health care plans include a limit on our share of costs for recent and future retirees.

The assets, obligations and the components of our pension costs are allocated by Wisconsin Energy’s actuary to each of the participating companies as if each participating company had its own plan. The disclosures below are based on an allocation to us of the amounts for Wisconsin Energy’s pension plans.

Wisconsin Energy follows SFAS 158 and uses a year-end measurement date to measure the funded status of all of the pension and OPEB plans. Due to the regulated nature of our business, we have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of the pension and OPEB plans qualify as a regulatory asset.

The following table presents details about the pension and OPEB plans:

	Pension						OPEB
Status of Benefit Plans	2008			2007			2008			2007
	(Millions of Dollars)
Change in Benefit Obligation
Benefit Obligation at January 1	$	988.0		$	1,071.8		$	262.3		$	261.2
Service cost		17.0			26.6			9.8			10.5
Interest cost		60.4			60.9			15.9			15.2
Plan amendments		5.1			(4.0	)		—			—
Actuarial gain		(28.4	)		(32.4	)		(27.2	)		(10.3	)
Divestitures		—			(38.9	)		—			(8.0	)
Benefits paid		(75.1	)		(96.0	)		(7.3	)		(7.8	)
Federal subsidy on benefits paid		N/A			N/A			1.1			1.5
Benefit Obligation at December 31	$	967.0		$	988.0		$	254.6		$	262.3
Change in Plan Assets
Fair Value at January 1	$	719.4		$	777.2		$	126.9		$	119.7
Actual (loss) earnings on plan assets		(177.2	)		46.4			(33.6	)		3.5
Employer contributions		43.6			24.6			11.0			11.5
Divestitures		—			(32.8	)		—			—
Benefits paid		(75.1	)		(96.0	)		(7.3	)		(7.8	)
Fair Value at December 31	$	510.7		$	719.4		$	97.0		$	126.9
Net Liability		($456.3)			($268.6)			($157.6)			($135.4)

The accumulated benefit obligation for all the defined benefit plans was $947.6 million and $976.4 million as of December 31, 2008 and 2007, respectively.

The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31 and are recorded as a regulatory asset on our balance sheet:

	Pension				OPEB
	2008		2007		2008			2007
	(Millions of Dollars)
Net actuarial loss	$	367.3	$	167.9	$	78.6		$	65.8
Prior service costs (credits)		19.8		17.1		(22.6	)		(35.1	)
Transition obligation		—		—		1.3			1.6
Total	$	387.1	$	185.0	$	57.3		$	32.3

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The following table shows the estimated amounts that will be amortized as a component of net periodic benefit costs during 2009:

	Pension		OPEB
	(Millions of Dollars)
Net actuarial loss	$	12.3	$	5.5
Prior service costs (credits)		2.1		(12.6	)
Transition obligation		—		0.3
Total	$	14.4		($6.8)

Information for the pension plan, which has an accumulated benefit obligation in excess of the fair value of assets as of December 31 is as follows:

	2008		2007
	(Millions of Dollars)
Projected benefit obligation	$	967.0	$	988.0
Accumulated benefit obligation	$	947.6	$	976.4
Fair value of plan assets	$	510.7	$	719.4

The components of net periodic pension and OPEB costs for the years ended December 31 are as follows:

	Pension									OPEB
Benefit Plan Cost Components	2008			2007			2006			2008			2007			2006
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	17.1		$	26.6		$	30.6		$	9.8		$	10.6		$	11.8
Interest cost		60.4			60.9			59.6			15.9			15.2			14.1
Expected return on plan assets		(60.7	)		(61.0	)		(59.8	)		(10.9	)		(9.5	)		(8.7	)
Amortization of:
Transition obligation		—			—			—			0.3			0.3			0.3
Prior service cost (credit)		2.4			5.4			5.4			(12.6	)		(12.5	)		(13.3	)
Actuarial loss		10.1			13.1			20.2			4.6			5.4			7.0
Net Periodic Benefit Cost	$	29.3		$	45.0		$	56.0		$	7.1		$	9.5		$	11.2

In connection with the sale of Point Beach in September 2007, we incurred a $3.7 million net settlement/curtailment credit related to our benefit plans. We have deferred this net gain as a regulatory liability.

	Pension						OPEB
	2008		2007		2006		2008		2007		2006
	(Millions of Dollars)
Weighted-Average assumptions used to determine benefit obligations at Dec 31
Discount rate	6.50	%	6.05	%	5.75	%	6.50	%	6.10	%	5.75	%
Rate of compensation increase	4.0		4.5 to 5.0		4.5 to 5.0		N/A		N/A		N/A
Weighted-Average assumptions used to determine net cost for year ended Dec 31
Discount rate	6.05	%	5.75	%	5.50	%	6.10	%	5.75	%	5.50	%
Expected return on plan assets	8.5		8.5		8.5		8.5		8.5		8.5
Rate of compensation increase	4.5 to 5.0		4.5 to 5.0		4.5 to 5.0		N/A		N/A		N/A
Assumed health care cost trend rates at Dec. 31
Health care cost trend rate assumed for next year (Pre 65 / Post 65)							7.5/9		8/11		9/11
Rate that the cost trend rate gradually adjusts to							5		5		5
Year that the rate reaches the rate it is assumed to remain at							2014		2014		2011

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The expected long-term rate of return on plan assets was 8.5% in 2008, 2007 and 2006. 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.

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	$	21.8	($	18.4	)
Total of service and interest cost components	$	3.1	($	2.6	)

We use various Employees’ Benefit Trusts to fund a major portion of OPEB. The majority of the trusts’ assets are mutual funds or commingled indexed funds.

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. The pension plans asset allocation as of December 31, 2008 and 2007, and the target allocation for 2009, by asset category, are as follows:

	Target Allocation		Actual Allocation
Asset Category	2009		2008		2007
Equity Securities	65	%	54	%	63	%
Debt Securities	35	%	46	%	37	%
Total	100	%	100	%	100	%

The OPEB plans asset allocation as of December 31, 2008 and 2007, and the target allocation for 2009, by asset category, are as follows:

	Target Allocation		Actual Allocation
Asset Category	2009		2008		2007
Equity Securities	61	%	56	%	61	%
Debt Securities	39	%	43	%	38	%
Other	—	%	1	%	1	%
Total	100	%	100	%	100	%

Wisconsin Energy’s common stock is not included in equity securities.

The target asset allocations were established by an Investment Trust Policy Committee, which oversees investment matters related to all of the funded benefit plans. The asset allocations are monitored by the Investment Trust Policy Committee.

Cash Flows:

Employer Contributions	Pension		OPEB
	(Millions of Dollars)
2006	$	58.2	$	12.5
2007	$	24.6	$	11.5
2008	$	43.6	$	11.0

In January 2009, we contributed approximately $265 million to the qualified pension plan and approximately $19 million to the OPEB plan. We contributed $37.9 million, $19.1 million and $54.0 million to Wisconsin Energy’s qualified pension plan during 2008, 2007 and 2006, respectively.

The entire contribution to the OPEB plans during 2008 was discretionary as the plans are not subject to any minimum regulatory funding requirements.

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

Year	Pension		Gross OPEB		Expected Medicare Part D Subsidy
	(Millions of Dollars)
2009	$	64.2	$	14.4	($	0.8	)
2010	$	76.8	$	15.4	($	0.7	)
2011	$	89.0	$	16.3	($	0.5	)
2012	$	97.4	$	16.0		—
2013	$	93.9	$	17.2		—
2014-2018	$	468.3	$	95.5		—

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 $13.3 million, $9.9 million and $9.3 million during 2008, 2007 and 2006, respectively.

N — GUARANTEES

We enter into various guarantees to provide financial and performance assurance to third parties. As of December 31, 2008, we had the following guarantees:

	Maximum Potential Future Payments		Outstanding		Liability Recorded
	(Millions of Dollars)
Guarantees	$	2.9	$	0.1	$	—

We are subject to the potential retrospective premiums that could be assessed under our insurance program.

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 $13.0 million as of December 31, 2008.

O — SEGMENT REPORTING

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

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

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Summarized financial information concerning our reportable operating segments for each of the years ended December 31, 2008, 2007 and 2006, is shown in the following table:

	Reporting Operating Segments
Year Ended	Electric		Gas		Steam		Other (a)		Total
	(Millions of Dollars)
December 31, 2008
Operating Revenues (b)	$	2,660.6	$	709.2	$	40.3	$	—	$	3,410.1
Depreciation, Decommissioning and Amortization	$	219.8	$	32.5	$	3.7	$	—	$	256.0
Operating Income (c)	$	413.2	$	61.6	$	7.1	$	—	$	481.9
Equity in Earnings of Transmission Affiliate	$	45.4	$	—	$	—	$	—	$	45.4
Capital Expenditures	$	459.0	$	59.1	$	5.6	$	—	$	523.7
Total Assets (d)	$	7,810.5	$	779.8	$	67.7	$	117.4	$	8,775.4
December 31, 2007
Operating Revenues (b)	$	2,674.6	$	611.9	$	35.1	$	—	$	3,321.6
Depreciation, Decommissioning and Amortization	$	234.9	$	31.1	$	3.7	$	—	$	269.7
Operating Income (c)	$	423.7	$	61.2	$	5.9	$	—	$	490.8
Equity in Earnings of Transmission Affiliate	$	37.9	$	—	$	—	$	—	$	37.9
Capital Expenditures	$	440.8	$	38.2	$	2.0	$	—	$	481.0
Total Assets (d)	$	7,469.2	$	669.2	$	58.7	$	115.7	$	8,312.8
December 31, 2006
Operating Revenues (b)	$	2,499.5	$	590.0	$	27.2	$	—	$	3,116.7
Depreciation, Decommissioning and Amortization	$	234.8	$	32.4	$	3.7	$	—	$	270.9
Operating Income (c)	$	407.2	$	47.7	$	1.0	$	—	$	455.9
Equity in Earnings of Transmission Affiliate	$	33.9	$	—	$	—	$	—	$	33.9
Capital Expenditures	$	362.4	$	33.6	$	2.6	$	0.1	$	398.7
Total Assets (d)	$	7,416.6	$	666.2	$	59.2	$	115.8	$	8,257.8

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

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

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

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

P — RELATED PARTIES

We provide to and receive from certain of our Wisconsin Energy affiliates managerial, financial, accounting, legal, data processing and other services in accordance with service agreements approved by the PSCW. In addition, we make lease payments to We Power for PWGS 1, PWGS 2, the Oak Creek coal handling system and the other generating facilities being constructed under Wisconsin Energy’s PTF strategy, and we sell electric energy to an affiliated utility, Edison Sault. We also receive and/or provide certain services to other associated companies in which we have, or Wisconsin Energy has, an equity investment.

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American Transmission Company LLC: As of December 31, 2008, we have a 23.0% interest in ATC. 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. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while projects are under construction, including generating units being constructed as part of Wisconsin Energy’s PTF strategy. ATC will reimburse us for these costs when new generation is placed into service. As of December 31, 2008 and 2007, we had a receivable of $32.6 million and $35.8 million, respectively, for these items.

Summary financial information as of December 31 from the financial statements of ATC is as follows:

	2008		2007		2006
	(Millions of Dollars)
Operating Revenues	$	466.6	$	408.0	$	340.7
Operating Income	$	257.6	$	209.8	$	161.3
Net Income	$	188.0	$	154.1	$	121.9
Current Assets	$	50.8	$	48.3
Non-Current Assets	$	2,480.0	$	2,189.0
Current Liabilities	$	252.0	$	317.1
Non-Current Liabilities	$	1,229.6	$	1,007.6

Nuclear Management Company: Prior to the Point Beach sale, our former affiliate, WEC Nuclear Corporation, had a partial ownership in NMC. NMC held the operating licenses of Point Beach. Upon the sale of Point Beach, NMC transferred the operating licenses to the buyer, the relationship with NMC was terminated and WEC Nuclear Corporation was dissolved.

We provided and received services from the following associated companies during 2008, 2007 and 2006:

Company	2008		2007		2006
	(Millions of Dollars)
Wisconsin Electric Affiliate
Net Services Provided
-We Power (excluding lease payments)	$	1.3	$	3.0	$	3.2
-Wisconsin Gas	$	51.3	$	50.8	$	44.4
-Edison Sault (including electric energy sold)	$	35.3	$	29.3	$	22.6
-Minergy	$	0.6	$	0.4	$	3.6
-Other	$	1.1	$	1.3	$	1.5
Net Services Received
-We Power (lease payments)	$	312.2	$	223.7	$	135.3
-Wisconsin Energy	$	12.6	$	8.3	$	9.1
Equity Investee
Services Provided
-ATC	$	20.0	$	17.1	$	15.8
Services Received
-ATC	$	194.4	$	172.1	$	145.7
-NMC	$	—	$	50.6	$	65.2

As of December 31, 2008 and 2007, our Consolidated Balance Sheets included receivable and payable balances with ATC as follows:

Equity Investee	2008		2007
	(Millions of Dollars)
Services Provided
-ATC	$	2.1	$	0.9
Services Received
-ATC	$	16.2	$	14.1

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Q — COMMITMENTS AND CONTINGENCIES

Capital Expenditures: We have made certain commitments in connection with 2009 capital expenditures. During 2009, we estimate that total capital expenditures will be approximately $600 million.

Operating Leases: We enter into long-term purchase power contracts to meet a portion of our anticipated increase in future electric energy supply needs. These contracts expire at various times through 2013. Certain of these contracts were deemed to qualify as operating leases. In addition, we have various other operating leases, including leases for vehicles and coal cars.

Future minimum payments for the next five years and thereafter for our operating lease contracts are as follows:

	(Millions of Dollars)
2009	$	23.6
2010		20.7
2011		20.9
2012		14.5
2013		5.5
Thereafter		12.6
Total	$	97.8

Divested Assets: Pursuant to the sale of Point Beach, we have agreed to indemnification provisions customary to transactions involving the sale of nuclear assets.

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 our manufactured gas plant sites and related disposal sites, as well as our coal ash disposal/landfill sites. We are working with the WDNR 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 several sites at which we or a predecessor company historically owned or operated a manufactured gas plant. We have substantially completed planned remediation activities at some of those sites and certain other sites are at various stages of investigation, monitoring and remediation. 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 $12 to $30 million over the next ten years. This estimate is dependent upon several variables including, among other things, the extent of remediation, changes in technology and changes in regulation. As of December 31, 2008, we have established reserves of $12.8 million related to future remediation costs.

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

Ash Landfill Sites: We aggressively seek environmentally acceptable, beneficial uses for our coal combustion by-products. However, these coal-ash by-products have been, and to a small degree, continue to be disposed of in company-owned licensed landfills. Some early designed and constructed landfills may allow the release of low levels of constituents resulting in the need for various levels of monitoring or adjusting. Where we have become aware of these conditions, efforts have been made to define the nature and extent of any release, and work has been performed to address these conditions. The costs of these efforts are recovered under our fuel clause and are expensed as incurred. During 2008, 2007 and 2006, we incurred $1.3 million, $0.8 million and $0.5 million, respectively, in coal-ash remediation expenses. As of December 31, 2008, we have no reserves established related to ash landfill sites.

EPA - Consent Decree: In April 2003, we and the EPA announced that a Consent Decree had been reached that resolved all issues related to a request for information that had been issued by the EPA. In July 2003, the Consent Decree was amended to include the state of Michigan. Under the Consent Decree, we agreed to significantly reduce our air emissions from our 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. Through December 31, 2008, we have spent approximately $506.7 million associated with implementing the Consent Decree. The total cost of implementing this agreement is estimated to be

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$1.2 billion through the year 2013. The U.S. District Court for the Eastern District of Wisconsin approved the amended Consent Decree and entered it in October 2007.

Oak Creek: In July 2008, Bechtel, the contractor of the Oak Creek expansion under a fixed price contract, notified We Power in a letter that it forecasts the in-service date of unit 1 to be delayed three months beyond the guaranteed contract date of September 29, 2009. Bechtel also advised We Power in the letter that it forecasts the in-service date of unit 2 to be one month earlier than the guaranteed contract date of September 29, 2010.

According to the letter, reasons for the delay of unit 1 include severe winter weather experienced during the winters of 2006-2007 and 2007-2008, exacerbated by severe rain storms in April and June of 2008, changes in local labor conditions from those anticipated by Bechtel, the cumulative impact of a large number of change orders and delay in receiving FNTP in 2005 as a result of the court challenges by certain opposition groups to the CPCN for the Oak Creek expansion. Bechtel advised that they expected to submit a claim for cost and schedule relief associated with these issues by the end of 2008.

Based on Bechtel’s earlier communications, We Power notified Bechtel on September 29, 2008 that it was invoking the formal dispute resolution process provided in the contract in order to resolve certain issues related to the rights of the parties under the contract.

We Power received Bechtel’s claims for schedule and cost relief on December 22, 2008. Bechtel’s claims are based on the alleged effects of severe winter weather and certain labor-related matters, as well as the alleged effects of ERS-directed changes and delays allegedly caused by ERS prior to the issuance of the FNTP in July 2005. Bechtel continues to target an in-service date for unit 1 three months beyond the guaranteed contract date of September 29, 2009, and an in-service date for unit 2 one month earlier than the guaranteed contract date of September 29, 2010.

We Power is currently in the mediation phase with respect to determining the parties’ rights under the contract and Bechtel’s claims. We Power is currently unable to predict the ultimate outcome of the claims.

R — SUPPLEMENTAL CASH FLOW INFORMATION

During the year ended December 31, 2008, we paid $78.6 million in interest, net of amounts capitalized, and $0.6 million in income taxes, net of refunds. During the year ended December 31, 2007, we paid $92.9 million in interest, net of amounts capitalized, and $327.5 million in income taxes, net of refunds. During the year ended December 31, 2006, we paid $84.9 million in interest, net of amounts capitalized, and $172.7 million in income taxes, net of refunds.

As of December 31, 2008, 2007 and 2006, the amount of accounts payable related to capital expenditures was $22.3 million, $73.0 million and $2.9 million, respectively.

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Deloitte & Touche LLP

555 E. Wells Street, Suite 1400

Milwaukee, WI 53202-3824

USA

Tel: 414-271-3000

Fax: 414-347-6200

www.deloitte.com

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Wisconsin Electric Power Company and subsidiary (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of income, common equity, and cash flows for each of the three years in the period ended December 31, 2008. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Wisconsin Electric Power Company and subsidiary as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.

February 25, 2009

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MARKET FOR OUR COMMON EQUITY

AND RELATED STOCKHOLDER MATTERS

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

Quarter	2008		2007
	(Millions of Dollars)
First	$	54.3	$	44.9
Second		54.3		44.9
Third		204.1		—
Fourth		54.3		89.8
Total	$	367.0	$	179.6

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

Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. Under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy. For additional information regarding restrictions on our ability to pay dividends, see Note H — Common Equity in the Notes to Consolidated Financial Statements.

BUSINESS OF THE COMPANY

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

Electric Operations: We are the largest electric utility in the state of Wisconsin. We generate and distribute electric energy to approximately 1,114,800 customers in southeastern (including the metropolitan Milwaukee area), east central and northern Wisconsin and in the Upper Peninsula of Michigan.

Gas Operations: We purchase, distribute and sell natural gas to retail customers; we also transport customer-owned gas. We have approximately 460,500 customers in three distinct service areas: west and south of the City of Milwaukee, the Appleton area and areas within Iron and Vilas Counties, Wisconsin. We began doing business with Wisconsin Gas, an affiliated gas utility, under the trade name “We Energies” in April 2002.

Steam Operations: We generate, distribute and sell steam supplied by our Valley and Milwaukee County Power Plants. Steam is used by approximately 465 customers in the metropolitan Milwaukee area for processing, space heating, domestic hot water and humidification.

For additional financial information about our operating segments, see Results of Operations in Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note O — Segment Reporting in the Notes to Consolidated Financial Statements.

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DIRECTORS AND EXECUTIVE OFFICERS

DIRECTORS

The information under “Information About Nominees for Election to the Board of Directors for Terms Expiring in 2010” in Wisconsin Electric Power Company’s definitive Information Statement dated April 6, 2009, attached hereto, is incorporated herein by reference.

EXECUTIVE OFFICERS

Gale E. Klappa – Chairman of the Board, President and Chief Executive Officer.

James C. Fleming – Executive Vice President and General Counsel.

Frederick D. Kuester – Executive Vice President and Chief Operating Officer.

Allen L. Leverett – Executive Vice President and Chief Financial Officer.

Charles R. Cole – Senior Vice President.

Kristine A. Rappé – Senior Vice President and Chief Administrative Officer.

Stephen P. Dickson – Vice President and Controller.

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