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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Gale E. Klappa Chairman, President and Chief Executive Officer 231 W Michigan Street Milwaukee, WI 53203

March 31, 2010

Dear Preferred Stockholder:

Wisconsin Electric Power Company, which does business under the trade name of We Energies, will hold its Annual Meeting of Stockholders on Thursday, April 29, 2010, at 10:00 a.m., in the Resource Center on the first floor of the Public Service Building, 231 West Michigan Street, Milwaukee, Wisconsin 53203.

We are not soliciting proxies for this meeting, as more than 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 6, 2010, at 10:00 a.m., Central time, in the R. John Buuck Field House on the campus of Concordia University Wisconsin, 12800 North Lake Shore Drive, Mequon, Wisconsin 53097.

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 of Wisconsin Electric 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

March 31, 2010

To the Stockholders of Wisconsin Electric Power Company:

The 2010 Annual Meeting of Stockholders of Wisconsin Electric Power Company will be held on Thursday, April 29, 2010, at 10:00 a.m., Central time, in the Resource Center on the first floor of 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 2011 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 25, 2010, 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 April 29, 2010 – The Information Statement and 2009 Annual Report to Stockholders are available at:

http://www.wisconsinelectric.com

By Order of the Board of Directors,

Susan H. Martin

Vice President, Corporate Secretary and Associate General Counsel

We Energies 231 West Michigan Street Milwaukee, Wisconsin 53203

INFORMATION STATEMENT

This information statement is being furnished to stockholders beginning on or about March 31, 2010, in connection with the annual meeting of stockholders of Wisconsin Electric Power Company (“WE” or the “Company”) to be held on Thursday, April 29, 2010 (“the Meeting”), at 10:00 a.m., Central time, in the Resource Center on the first floor of 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 25, 2010, WE had outstanding 44,498 shares of $100 par value Six Per Cent. Preferred Stock; 260,000 shares of $100 par value 3.60% Serial Preferred Stock; and 33,289,327 shares of common stock. Each outstanding share of each class is entitled to one vote. Stockholders of record at the close of business on February 25, 2010 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, representing more than 99% of its voting securities, is owned by its parent company, Wisconsin Energy Corporation (“WEC”), and will be represented at the Meeting. The principal business address of WEC 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://www.wisconsinelectric.com:

• Notice of Annual Meeting;

• Information Statement; and

• 2009 Annual Report to Stockholders.

ELECTION OF DIRECTORS

At the Meeting, there will be an election of nine directors. Based upon the recommendation of the Corporate Governance Committee of WEC’s Board of 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 2011 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 2011.

WEC’s Corporate Governance Committee evaluates each individual director nominee in the context of the WEC and WE Boards as a whole with the goal of recommending nominees with diverse backgrounds and experience that, together, can best perpetuate the success of WEC’s and WE’s businesses and represent shareholder interests. In addition to the unique experiences and skills identified below, the WEC Corporate Governance Committee believes that each of the director nominees should possess the following characteristics and skills: proven integrity, mature and independent judgment, vision and imagination, ability to objectively appraise problems, strong leadership and communication skills, ability to evaluate strategic options and risks, sound business experience and acumen, social consciousness, and familiarity with issues affecting WEC’s and the Company’s businesses.

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, 2010.

John F. Bergstrom.Age 63.

• 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. since 2008; and Director of Kimberly-Clark Corporation since 1987.

• Director of Banta Corporation from 1998 to 2007; Director of Midwest Air Group, Inc. from 1993 to 2007 and again from 2008 to 2009; and Director of Sensient Technologies Corporation from 1994 to 2006.

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

Mr. Bergstrom has over 25 years of experience as CEO of Bergstrom Corporation, one of the Top 50 automotive dealership groups in America, with dealerships across eastern Wisconsin, including several in We Energies’ utility service territories. Therefore, Mr. Bergstrom provides the Board experience and insight with respect to understanding the needs of the Company’s retail customers, as well as Wisconsin’s regulatory and political environment. As the CEO of a large, diverse retailer, Mr. Bergstrom has a deep understanding of executive compensation issues and challenges. Mr. Bergstrom also provides the Board with insight gained from his 25 years of service as a director on the Company’s and its affiliates’ Boards, over 50 years of combined experience as a director on the boards of several other publicly traded U.S. corporations, and past or present directorships on the boards of several regional non-profit entities, including the Green Bay Packers, Inc.

Barbara L. Bowles.Age 62.

• 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 since 1993; and Director of Hospira, Inc. since 2008.

• Director of Dollar General Corporation from 2000 to 2007; and Director of Georgia Pacific Corporation from 2000 to 2005.

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

As founder, president and CEO of The Kenwood Group, Inc., a Chicago-based investment advisory firm that managed pension funds for corporations, public institutions and endowments, Ms. Bowles has over 19 years of investment advisory experience. Before founding The Kenwood Group, Ms. Bowles, who is a Chartered Financial Analyst, was a chief investor relations officer for two Fortune 50 companies. Prior to that, she served as a portfolio manager and utility analyst for more than 10 years. With this combined experience, Ms. Bowles is uniquely qualified to provide perspective to the Board as to what issues are important to large investors, particularly what is important to analysts covering the Company’s industry. Ms. Bowles also served as chief compliance officer with The Kenwood Group prior to its merger with Profit Investment Management, through which she gained a deep understanding of corporate governance issues and concerns. This experience is invaluable for Ms. Bowles’ positions as chair of the WEC Corporate Governance Committee and presiding independent director. Ms. Bowles’ service as a director of other public companies, including service on several audit and finance committees, provides a resource to the Board in discussions of issues facing WEC and the Company.

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Patricia W, Chadwick.Age 61.

• 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 since 1992; Director of ING Mutual Funds since 2006; and Director of The Royce Funds since December 2009.

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

Ms. Chadwick, who is a Chartered Financial Analyst, was an investment professional/portfolio manager or principal for 30 years, and served as a director of research for four of those years. Since 1999, Ms. Chadwick has been president of Ravengate Partners, LLC, a firm that provides businesses and not-for-profit institutions with advice about the economy and the financial markets. As indicated above, Ms. Chadwick currently serves as a director on the boards of two registered investment companies. She has served as the Chair of multiple committees at AMICA Mutual Insurance Company, including the Audit and Nominating and Governance Committees (which she currently chairs). She is also the Chair of the Domestic Investment Review Committee at ING Mutual Funds and serves on the Audit Committees for ING and Royce Funds and the Finance Committee for AMICA. Ms. Chadwick’s career and experience allow her to provide needed advice and insight to the Board on the capital markets. This perspective is valuable to the Company and its affiliates, which operate in a capital-intensive industry and must consistently access the capital markets. In addition, Ms. Chadwick’s service on the Board of AMICA has provided her with experience in dealing with insurance risk management issues.

Robert A. Cornog.Age 69.

• Snap-on Incorporated – Retired Chairman of the Board, President and Chief Executive Officer. Served as President and Chief Executive Officer from 1991 until 2001 and 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. since 1992.

• Director of Oshkosh Corporation from 2005 to 2009.

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

Mr. Cornog served as president and CEO of Snap-on Incorporated for 10 years. Snap-on is a Wisconsin-based manufacturer with significant operations in We Energies’ utility service territories. Therefore, Mr. Cornog provides perspective as to the issues facing the Company’s large commercial and industrial retail customers, as well as experience in navigating Wisconsin’s regulatory and political environment. Mr. Cornog served for five years as a member of the Risk Committee while at Snap-on Incorporated where he identified, assessed and managed company risk. Mr. Cornog brings this experience to the Board and the Audit and Oversight Committees of WEC and the Company on which he serves. Mr. Cornog also has more than 16 years of service as a director on WE’s Board and 17 years of service on WEC’s Board, including over 12 years of service on each Board’s Audit and Oversight Committee, and over 20 years of combined experience as a director on the boards of two other publicly traded U.S. corporations headquartered in Wisconsin.

Curt S. Culver.Age 57.

• 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 since 1999.

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

Mr. Culver’s experience as Chairman and CEO of MGIC, which is headquartered in Milwaukee, Wisconsin, not only provides the Board with expertise in the financial markets and risk assessment and management, but also knowledge of the challenges and issues facing a public company headquartered in the same city as the Company. In addition, with his experience in the insurance industry, Mr. Culver is in a position to advise the Company’s Finance Committee on the Company’s insurance program and its effect on overall risk management. Mr. Culver also has past and present experience serving on the boards of numerous Milwaukee-area non-profit and two private, regional for-profit entities.

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Thomas J. Fischer.Age 62.

• 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 and Deputy Managing Partner for the Great Plains Region 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 since 2003; Director of Badger Meter, Inc. since 2003; and Director of Regal-Beloit Corporation since 2004.

• Director of Wisconsin Energy Corporation, Wisconsin Electric Power Company, and Wisconsin Gas LLC since 2005.

As Principal of Fischer Financial Consulting LLC, Mr. Fischer has provided consulting services to publicly traded companies in the areas of corporate financial, accounting and governance matters since 2002. Prior to this, Mr. Fischer, who is a Certified Public Accountant, worked for Arthur Andersen, a large, international independent public accounting firm, for 33 years, the last 20 as a partner responsible for services provided to large, complex public and private companies and for several public utility audits. Combined with his service as a director and member of the audit committee of three other Wisconsin-based public companies, Mr. Fischer provides the Board with a deep understanding of corporate governance issues, accounting and auditing matters, including financial reporting and regulatory compliance, and risk assessment and management. In light of this extensive experience, he is chair of the Audit and Oversight Committee for each of WEC and the Company.

Gale E. Klappa.Age 59.

• 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 Badger Meter, Inc. since February 2010; and Director of Joy Global Inc. since 2006.

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

As Chief Executive Officer and President of WEC, WE and WG, Mr. Klappa represents and communicates management’s perspective to the Board. Mr. Klappa provides the Board with an understanding of the day-to-day operations of the Company, and, in turn, communicates the Board’s vision and direction for the Company to the other officers and management. Mr. Klappa has more than 35 years of experience working in the public utility industry, the last 17 at a senior executive level. Immediately prior to joining WEC in 2003, Mr. Klappa served as Executive Vice President and Chief Financial Officer at The Southern Company, a public utility holding company serving the southeastern United States. Mr. Klappa also served in various other positions during his tenure at Southern, including Treasurer and Chief Strategic Officer. Mr. Klappa currently serves on the boards of Edison Electric Institute, an association of U.S. shareholder-owned electric companies, and Electric Power Research Institute, an independent, non-profit research company performing research, development and demonstration in the electricity sector.

Ulice Payne, Jr.Age 54.

• Addison-Clifton, LLC – Managing Member since 2004. Addison-Clifton, LLC provides global trade compliance advisory services.

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

• Director of Badger Meter, Inc. since 2000; Director of Manpower Inc. since 2007; and Trustee of The Northwestern Mutual Life Insurance Company since 2005.

• Director of Midwest Air Group, Inc. from 1998 to 2008; and Director of State Financial Services Corporation from 1998 to 2005.

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

Mr. Payne has extensive leadership experience within the local community and the state of Wisconsin, previously serving as president and CEO of the Milwaukee Brewers Baseball Club, Inc., as managing partner of the Milwaukee office of Foley & Lardner, a Milwaukee-based law firm, and as Securities Commissioner for the state of Wisconsin. In addition, Mr. Payne is and has been involved in numerous Milwaukee-area non-profit entities, including serving as past chair of the Bradley Center Sports and Entertainment Corporation. Therefore, Mr. Payne is able to provide the Board with a unique perspective on the issues and challenges affecting the local Milwaukee community as a whole as well as a broad spectrum of the Company’s customers. As a result of these positions, Mr. Payne also has experience in operating in the same regulatory and political environment as the Company. Mr. Payne presently advises on global trade compliance as Managing Member of Addison-Clifton, LLC, where Mr. Payne consistently deals with public policy and compliance matters, experience he brings to the Board. In addition, Mr. Payne’s past and present directorship experience includes service as a member of either the audit or finance committee at each of these companies, which is beneficial to the Board.

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Frederick P. Stratton, Jr.Age 70.

• Briggs & Stratton Corporation – Chairman Emeritus since 2003. Chairman of the Board from 2001 to 2003. Chairman and Chief Executive Officer from 1986 until 2001. Chief Executive Officer from 1977 until 1986. Briggs & Stratton Corporation is a manufacturer of small gasoline engines.

• Director of Baird Funds, Inc. since 2004; and Director of Weyco Group, Inc. since 1976.

• Director of Midwest Air Group, Inc. from 1986 to 2007.

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

Mr. Stratton has held leadership positions, including 24 years as CEO, in Briggs & Stratton Corporation, a manufacturer headquartered in Milwaukee, Wisconsin, and with significant operations in We Energies’ utility service territories. As a result, Mr. Stratton provides the Board with perspective as to the issues facing the Company’s large commercial and industrial retail customers, as well as experience working in Wisconsin’s regulatory and political environment. As the former CEO of a large public corporation, Mr. Stratton has a deep understanding of the executive compensation issues and challenges WEC and the Company face, as well as the challenges a public corporation can face raising capital. Mr. Stratton also brings to the Board his 24 years of service as a director on the Company’s and its affiliates’ Boards, and over 60 years of combined experience as a director on the boards of three other publicly traded U.S. corporations headquartered in Wisconsin, including service on the audit committee for two of those companies.

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. WEC’s Corporate Governance Committee reviews the Guidelines annually to ensure that the Board is providing effective governance over the affairs of the Company. 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, the 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

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	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;
	•       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.
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 is 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.
Is the office of CEO combined with the office of Chairman of the Board?	Consistent with WE’s Bylaws and WEC’s Corporate Governance Guidelines, the Board retains the right to exercise its discretion in combining or separating the offices of Chief Executive Officer and Chairman of the Board. Given the uniqueness and complexity of the Company’s industry, operations and regulatory environment, the Board believes that having a combined CEO and Chairman is the appropriate structure for the Company. This combined structure provides the Company with clear leadership and a single voice in implementation of its strategy and in leading discussions at the Board level. The Board currently does not appoint a lead independent director; however, Director Bowles, the chair of WEC’s Corporate Governance Committee, acts as presiding director whenever the independent directors meet in executive session without any management present. The Board believes that such leadership evolves naturally and may vary depending upon the issue under consideration. Therefore, the appointment of a lead independent director is not necessary.

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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. Director Bowles currently presides at these sessions.
What is the Board’s role in risk oversight?	The Board oversees our risk environment and has delegated specific risk monitoring responsibilities to the Audit and Oversight Committee and the Finance Committee as described in each committee’s charter. Both of these committees routinely report back to the Board. The Board and its committees also periodically receive briefings from management on specific areas of risk as well as emerging risks to the enterprise. The Audit and Oversight Committee periodically hears reports from management on the Company’s major risk exposures in such areas as compliance, environmental, legal/litigation and ethical conduct and steps taken to monitor and control such exposures. This committee also devotes at least one meeting annually to risk oversight. The Finance Committee discusses the Company’s risk assessment and risk management policies, and provides oversight of insurance matters to ensure that its risk management program is functioning properly. Both committees have direct access to, and meet as needed with, Company representatives without other management present to discuss matters related to risk management. The CEO, who is ultimately responsible for managing risk, routinely reports to the Board on risk-related matters. The Company, along with WEC, has implemented a quarterly process in which business unit leaders are to identify existing, new or emerging issues or changes within their business area that could have enterprise implications and report them to the Enterprise Risk Management Committee. This committee is comprised of management employees who are responsible for his or her business unit and is tasked with ensuring that these risks and opportunities are appropriately addressed. In addition, the Company, along with WEC, has established a Compliance Risk Steering Committee, comprised of senior level management employees, whose purpose is to foster an enterprise-wide approach to managing compliance. The results of each of these risk-management efforts are reported to the CEO and to the Board or its appropriate committee.
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. Pursuant to instructions from the Board of 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 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 several ways employees can raise questions concerning WEC’s Code of Business Conduct and other Company policies. As one reporting mechanism, the Company has contracted with an independent call center for employees to confidentially report suspected violations of WEC’s Code of Business Conduct or other concerns, including those regarding accounting, internal accounting controls or auditing matters.

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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 the board of a substantial non-profit organization, but do not need to obtain prior approval.
	In addition, WEC’s Code of Business Conduct requires employees and directors 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 obtains from each non-employee director his or her opinion and input 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 evaluation results 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, risks to the enterprise and customer satisfaction initiatives); communicating the Board’s expectations and concerns to the CEO; 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.
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.

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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) overseeing 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 Company engaged (outside of the Compensation Committee) Towers Watson (f/k/a Towers Perrin), a compensation consulting firm, to provide the Compensation Committee and Chief Executive Officer with compensation data regarding general industry and the energy services industry. Although the Compensation Committee relies on this compensation data, Towers Watson does not recommend the amount or form of executive or director compensation. While Towers Watson was not engaged directly by the Compensation Committee, the Committee has unrestricted access to Towers Watson and may retain its own compensation consultant at its discretion.
	The Chief Executive Officer, after reviewing the compensation data compiled by Towers Watson 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. 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. It is also available in print to any stockholder upon request in writing to the Corporate Secretary.
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 2011 Annual Meeting of Stockholders must submit the candidates’ names and qualifications to WEC’s Corporate Governance Committee no later than November 1, 2010, via the Corporate Secretary, Susan H. Martin, at WEC’s principal business office, 231 West Michigan Street, P.O. Box 1331, Milwaukee, Wisconsin 53201.
What are the criteria and processes used to evaluate director nominees?	WE relies on WEC’s Corporate Governance Committee to identify and evaluate director nominees. WEC’s Corporate Governance Committee has established criteria for evaluating all director candidates, which are reviewed annually. As set forth in WEC’s Corporate Governance Guidelines, these include: 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’s 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.
	WEC’s Corporate Governance Committee strives to recommend candidates who each bring a unique perspective to the Board in order to contribute to the collective diversity of the Board. Although there is no specific diversity policy, the Board believes that a diverse board contributes to

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	effective governance over the affairs of WEC and the Company for the benefit of their stockholders. Several factors are considered by the Committee to ensure the entire Board collectively embraces a wide variety of characteristics, including professional background, experience, skills and knowledge as well as the criteria listed above. Each candidate will generally exhibit different and varying degrees of these characteristics.
	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. WEC’s Corporate Governance 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 directors attended WEC’s 2009 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 Patricia W. Chadwick 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. •       Review the Company’s risk exposure in such areas as compliance, environmental, legal/litigation and ethical conduct. •       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 2009.
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 five meetings in 2009, including one joint meeting with WEC’s Corporate Governance Committee.
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 three meetings in 2009.

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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 three meetings in 2009, 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 2009.

In addition to the number of committee meetings listed in the preceding table, the Board met seven times in 2009 and executed three signed, written unanimous consents. The average meeting attendance during the year was 94.9%. No director attended fewer than 80% 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 eight 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, 2010, subject to ratification by the stockholders of Wisconsin Energy Corporation at WEC’s Annual Meeting of Stockholders on May 6, 2010.

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 6, 2010. They will have an opportunity to make a statement at WEC’s Annual Meeting, if they so desire, and are expected to respond to appropriate questions that may be directed to them.

Pre-Approval Policy. 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 or other employee of the Company who serves in a financial reporting oversight role or to the chair 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 2009 and 2008 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.

	2009		2008
Audit Fees(1)	$	1,204,681	$	1,253,390
Audit-Related Fees(2)		23,040		—
Tax Fees(3)		26,956		697,860
All Other Fees(4)		1,260		3,675
Total	$	1,255,937	$	1,954,925

⁽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, 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.

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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 2010, 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 2009. 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. 61, as amended (AICPA, Professional Standards, Vol. 1. AU Section 380), as adopted by the Public Company Accounting Oversight Board in Rule 3200T.

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, 2009 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

Patricia W. Chadwick

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 2009.

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, in 2009 we compensated executives through a mix of compensation elements that included:

• 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 Watson (f/k/a Towers Perrin), a compensation consulting firm retained by management, to help 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 analyzed market data in establishing each individual element in 2009 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 a 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 Watson. For 2009, Towers Watson provided us with compensation data from its 2009 Executive Compensation Data Bank, which contains information obtained from 428 companies of varying sizes in a wide range of businesses throughout general industry, including information from 98 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 Watson 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 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. The Compensation Committee may also, in its discretion, adjust base salaries outside of this 10% band when the Committee deems it appropriate. However, in light of the economic conditions in our service territories at the end of 2008 and the forecasted decline in 2009, the Compensation Committee agreed with Mr. Klappa’s recommendation to freeze 2009 salaries at 2008 levels for all officers of WEC and its subsidiaries, including the named executive officers. Despite the freeze in base salaries, the Compensation Committee reviewed whether the named executive officers’ 2009 base salaries were within 10% of the market median as it wanted to ensure the compensation program remained competitive.

Other than for Mr. Leverett, the annual base salaries of the named executive officers were within 10% of the appropriate market median. The annual base salary for Mr. Leverett was 6.7% 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 addition to the normal responsibilities of a chief financial officer, Mr. Leverett’s responsibilities include assisting in the development of a comprehensive corporate strategy (with a focus on all of WEC’s operations and affairs, not just finance), executing corporate divestitures and overseeing our investment in the American Transmission Company (which currently represents nearly ten percent of WEC’s consolidated earnings).

In light of the continued deterioration in economic conditions in our service territories during 2009, the Compensation Committee agreed with Mr. Klappa’s recommendation to freeze base salaries in 2010 for all officers of WEC and its subsidiaries, including the named executive officers. Therefore, the named executive officers’ 2010 base salaries will remain frozen for the second consecutive year. Salaries for all management employees (other than officers) were frozen at 2009 levels.

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 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.

2009 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 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. These target levels continue to be supported by market data.

For 2009, 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:

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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 2009, 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.

2009 Performance Goals.The Compensation Committee adopted the 2009 STPP with a continued principal focus on financial results. In December 2008, the Compensation Committee approved the two primary performance measures to be used in 2009: (1) WEC’s earnings per share from continuing 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 addition, because of the significant capital expenditures necessary for WEC’s continuing construction program, we feel cash flow is an important financial measurement for WEC. In January 2009, 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. If WEC’s performance falls between these payout levels, the vesting percentage is determined by interpolating on a straight line basis the appropriate vesting percentage.

WEC’s earnings per share from continuing operations goals for 2009 were a threshold level goal of $3.05 per share, a target level goal of $3.09 per share, an above target level goal of $3.11 per share and a maximum payout level goal of $3.16 per share. The performance goals for WEC’s cash flow were set at a threshold level goal of ($626.6) million, a target level goal of ($602.0) million, an above target level goal of ($589.7) million and a maximum payout level goal of ($552.9) million.

The Compensation Committee evaluated five-year growth rates projected for the period from 2004 to 2009 for the companies included in the peer group used for purposes of performance units, discussed below. Based on these projected growth rates, the Compensation Committee believed that if WEC achieved earnings per share from continuing operations of $3.16 in 2009, or a 4.3% annual growth rate versus 2008 earnings per share from continuing operations of $3.03, WEC’s five-year growth rate for the period from 2004 to 2009 would be in the top quartile of the peer group companies. As a result, the Compensation Committee set 4.3% growth, or $3.16 per share from continuing operations, as the level required to achieve the maximum payout on this goal. Based upon the level of growth needed to achieve maximum payout, the Compensation Committee then established the earnings per share from continuing operations goals for each remaining payout level using the following rates of growth: 0.5% to achieve the threshold level goal; 2.0% to achieve the target level goal; and 2.5% to achieve the above target level goal.

Once the Compensation Committee established the WEC earnings per share performance levels (i.e., threshold level, target level, above target level and maximum payout level), it set the 100% (target level) WEC cash flow target at the amount of cash flow estimated to be necessary to achieve WEC earnings per share at the target level, which amount was approved by the Finance Committee of the WEC Board of Directors. The Committee then set the above target level and maximum payout level for cash flow at approximately 2% and 8%, respectively, above the amount of cash flow required to achieve a WEC target level payout; the threshold level for cash flow was set at approximately 4% below the target level of cash flow. Cash flow results of less than 4% below target would result in no payout for the cash flow goal. In the judgment of the Compensation Committee, these three WEC cash flow targets reasonably represented the amount of cash flow necessary to achieve a combination of WEC earnings per share performance and appropriate capital spending levels given WEC’s construction program.

In December 2008 and January 2009, 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.

2009 Performance Under the STPP.In January 2010, the Compensation Committee reviewed WEC’s actual performance for 2009 against the financial and operational performance goals established under the STPP, subject to final audit. In 2009, WEC’s financial performance satisfied the maximum payout level goals established for both earnings per share from continuing operations and cash

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flow. In 2009, WEC’s earnings per share from continuing operations were $3.20 per share and WEC’s cash flow was ($98.2) million. WEC’s cash flow is measured by subtracting cash used in investing activities, excluding an investment in its (and our) transmission affiliate and net proceeds from asset sales, from cash provided by operations. WEC’s cash flow measure is not a measure of financial performance under generally accepted accounting principles.

By satisfying the maximum payout level with respect to both WEC’s earnings per share from continuing 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 2009, the performance at WEC and its subsidiaries, including the Company, generated a net 2.5% increase to the compensation awarded under the STPP, as detailed below. 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 WE and WG during the year, which measured (1) customers’ satisfaction with WE and WG in general and (2) customers’ satisfaction with respect to their particular interactions with WE and WG. In 2009, WE and WG exceeded target levels related to customers’ satisfaction with respect to their transactions with WE and WG leading to a 2.5% increase in the award, and achieved target level performance with respect to customers’ general satisfaction. With respect to safety measures, WEC and its subsidiaries, including the Company, satisfied the target level for Occupational Safety and Health Administration (OSHA) recordable injuries, but did not meet the target level for lost-time injuries which caused a 1.25% decrease in the STPP award. WEC and its subsidiaries exceeded target level performance with respect to workforce diversity and achieved target level performance with respect to supplier diversity, resulting in an increase in the STPP award of 1.25% for 2009.

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 $2,286,241 for 2009. This represented 202.5% of his annual base salary. Messrs. Leverett, Kuester and Fleming, and Ms. Rappé, received annual cash incentive compensation for 2009 under the STPP equal to 162%, 162%, 141.75% and 121.5% of their respective annual base salaries, representing 202.5% 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 2009. These included:

• Strong financial performance

• Record WEC earnings from continuing operations of $3.20 per share.

• A 25% increase in WEC’s dividend effective with the first quarter payment in 2009, and another approximately 18.5% increase effective with the first quarter payment in 2010.

• WEC’s debt to total capital ratio of 55.2% at year-end 2009, 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. WEC’s year-end debt to total capital ratio was significantly better than WEC’s target of 60.0%.

• The share price of WEC common stock increased by 18.7% during 2009.

• WEC common stock traded at $50.62 per share on December 30, 2009, which, at that time, was an all-time high.

• Operational excellence

• Significant progress on WEC’sPower the Future strategic plan.

• Achieved a favorable settlement with Bechtel Power Corporation of its $517.5 million claim for $72 million.

• Continued improvements in customer satisfaction based on customer surveys. Data from 2009 indicated that WE and WG consistently performed in the top quartile of the industry, achieving their best customer satisfaction ratings since the merger of the Company and Wisconsin Gas.

• Lowest OSHA recordable incidence rate in WEC’s history.

• An 18% reduction in customer outages, the Company’s best reliability in the modern era. The Company was named the most reliable utility in the Midwest for the sixth time in the past eight years.

• Continued leadership and excellence in corporate governance as evidenced by continued receipt by WEC during 2009 of a rating of “10,” the highest possible score, from GovernanceMetrics International (only one of two companies worldwide to consistently earn this distinction).

• Ended 2009 with the most diverse leadership team in WEC’s history.

• Completed 2009 with the Company’s retail electric rates ranking approximately 4.8% 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 2009 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 and restricted stock. 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 reinvested dividends) in comparison to a peer group of companies over a three-year performance period. In addition, for all performance unit awards through 2009, each holder of WEC 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.

In December 2009, the Compensation Committee amended and restated WEC’s Performance Unit Plan to eliminate the dividend equivalent on all performance units awarded after January 1, 2010. The Compensation Committee also amended the STPP effective January 1, 2010 to provide for short-term dividend equivalents. Under the STPP as amended, beginning with the 2010 performance unit grant under WEC’s Performance Unit Plan, certain officers, including the named executive officers, and employees of WEC and its subsidiaries are eligible to receive dividend equivalents in an amount equal to the number of WEC performance units at the target 100% rate held by each such officer and employee on the dividend declaration date multiplied by the amount of cash dividends paid by WEC on a share of its common stock on such date. The short-term dividend equivalents will vest at the end of each year only if WEC achieves the performance target or targets for that year established by the Compensation Committee in the same manner as the WEC performance targets are established under the STPP for the annual incentive award. For 2010, the Compensation Committee determined that the short-term dividend equivalents will be dependent upon WEC’s performance against a target for earnings from continuing operations.

Prior to the amendment to WEC’s Performance Unit Plan discussed above, dividends paid on outstanding WEC performance units were earned and paid regardless of WEC’s performance. The Compensation Committee made these amendments beginning with the 2010 compensation package because it felt that a plan designed to reward WEC performance over a three-year period should not provide for guaranteed dividends regardless of performance. Under the STPP as amended, the short-term dividend equivalents only vest upon achieving the performance target.

Aggregate 2009 Long-Term Incentive Awards.In establishing the target value of long-term incentive awards for each named executive officer in 2009, we analyzed the market compensation data included in the Towers Watson 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 both Messrs. Leverett and Kuester, we established the same target level of long-term incentive compensation using the average of the results obtained for each officer. We wanted to establish parity in long-term incentive opportunity between the heads of the financial and key operational areas of WEC and its subsidiaries, including 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.

For 2009, the Compensation Committee approved a WEC performance unit grant designed to represent approximately 72% of the long-term incentive target award and a WEC stock option grant designed to represent approximately 28% of the long-term incentive target award. Although the market data provided by Towers Watson indicated that long-term incentive awards were 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, we would have needed to issue more WEC stock options to meet the 40% level of the long-term incentive award than the Compensation Committee thought was prudent.

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For 2010, the Compensation Committee approved a long-term incentive award consisting of 80% WEC performance units, 10% WEC stock options and 10% WEC restricted stock. The Towers Watson market data indicated that companies were reducing the number of options awarded and beginning to grant time-vesting restricted stock. Because the Compensation Committee wanted a significant part of the long-term award to be tied to WEC performance and shareholder value, it increased the performance unit award to represent approximately 80% of the long-term target award. Due to the increase in the market value of WEC’s common stock between the 2009 and 2010 awards, the number of WEC performance units granted in 2010 actually decreased even though performance units made up a larger percentage of the total long-term target award. This was another factor that led the Committee to increase the performance unit portion of the long-term award.

In addition, based upon our review of the market data, the Compensation Committee decreased the target value of WEC’s 2010 long-term incentive compensation grant. The target value of the 2010 grant represents between a 9% and 12% decrease from the target value of the 2009 long-term incentive compensation grant. The Compensation Committee believes the decrease in the target value of long-term incentive compensation reflected in the market data is indicative of the decline in compensation trends during 2009.

2009 Stock Option Grants.In December 2008, the Compensation Committee approved the grant of WEC stock options to each of the 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, 2009, the first trading day of 2009. 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, 2009 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.

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 Watson 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 in 2009.

Executive Officer	Options Granted
Mr. Klappa	275,980
Mr. Leverett	146,000
Mr. Kuester	146,000
Mr. Fleming	53,200
Ms. Rappé	44,495

For financial reporting purposes under FASB ASC Topic 718, the WEC stock options granted in 2009 had a grant date fair value of $8.37 per option for Messrs. Klappa, Leverett and Kuester, and Ms. Rappé, and a grant date fair value of $7.00 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.

2009 Performance Units.In 2009, the Compensation Committee granted WEC performance units to each of the named executive officers and approved a pool of WEC performance units that were granted to approximately 135 other employees. With respect to the 2009 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, 2011, as compared to the total stockholder return of the 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; NV Energy, Inc.; OGE Energy Corp.; Pepco Holdings, Inc.; PG&E Corporation ; Pinnacle West Capital Corporation; Portland General; Progress Energy Inc.; SCANA Corporation; Sempra Energy; 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.

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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 on a straight line basis 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.

For purposes of determining the appropriate number of performance units to grant to a particular named executive officer, the Compensation Committee used a value of $41.40 per unit. This value was based on the volume weighted stock price of WEC’s common stock for the ten trading days beginning on December 8, 2008 and ending on December 19, 2008. To minimize the impact of the very volatile stock market conditions at the end of 2008 and to shorten the timeframe between the time the calculation of the award levels is made and the actual grant date, we determined not to calculate awards based on data available on October 31, which is what we historically used. 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	75,590
Mr. Leverett	39,990
Mr. Kuester	39,990
Mr. Fleming	14,570
Ms. Rappé	12,185

For financial reporting purposes under FASB ASC Topic 718, the WEC performance units granted to the above named executive officers in 2009 had a grant date fair value of $42.215 per unit.

2009 Payouts Under Previously Granted Long-Term Incentive Awards. In 2007, 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 2007 were substantially similar to those of the WEC performance units granted in 2009 described above, and the required performance percentile ranks and related vesting schedule were identical to that of the 2009 units.

Payouts under the 2007 WEC performance units were based on WEC’s total stockholder return for the three-year performance period ended December 31, 2009 against substantially the same group of peer companies used for the 2009 WEC performance unit awards, except that the peer group of companies for the 2007 awards (i) included Energy East Corporation, 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. Although part of the peer group for the 2007 WEC performance units, we were unable to measure the total stockholder return of Energy East Corporation and Puget Energy, Inc. for purposes of determining WEC’s ranking among the peer group. Energy East was purchased by a foreign utility holding company and is no longer a public company. In addition, in February 2009, Puget Energy completed its merger, first announced in October 2007, and was acquired by a group of long-term infrastructure investors. Upon consummation of the merger, Puget Energy was no longer a public company.

For the three-year performance period ended December 31, 2009, WEC’s total stockholder return was at the 88.9^th percentile of the peer group, resulting in the performance units vesting at a level of 171.3%. The actual payouts were determined by multiplying the number of vested performance units by the closing price of WEC’s common stock ($49.83) on December 31, 2009, 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 2009” table below. This table also reflects amounts realized by any named executive officer in connection with

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the exercise in 2009 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, 2009, please refer to the table entitled “Outstanding Equity Awards at Fiscal Year-End 2009” 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 the stock ownership guidelines: WEC restricted stock; WEC phantom stock units held in the WEC 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.

The Compensation Committee periodically reviews whether the officers are in compliance with these guidelines. The last review was completed in July 2009, and the Compensation Committee determined that all officers either satisfied, or were making appropriate progress to satisfy, the established guidelines.

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 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.

Retirement Programs.WEC also maintains four different retirement plans in which the 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 2009” 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 health care 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 club memberships for certain of 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 2009 of 319 companies throughout general industry. Based upon this review, we believe that the perquisites we provide to our executive officers are generally market competitive. 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 that 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.

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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 WEC or its subsidiaries, including the Company, at the time of death. In December 2009, the Compensation Committee amended the terms of the death benefit only plan to eliminate the payment of any benefit once participants in the plan have retired. Prior to this amendment, if a participant’s death occurred post-retirement a benefit was paid to his or her designated beneficiary in an amount equal to the after-tax value of one times final base salary. The Compensation Committee determined that this benefit was no longer supported by the market data.

Severance Benefits and Change in Control.Competitive practices dictate that companies 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, any 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) in anticipation of or following a change in control by WEC for any reason, other than cause, death or disability, (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 and Kuester, 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. Mr. Fleming is not entitled to receive any severance benefits upon termination of employment for good reason or without cause in the absence of a change in control.

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

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 2009.

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

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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 2009 compensation for the named executive officers, the annual stock option grants under WEC’s 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).

Changes for 2010. For 2010, the Compensation Committee made the following changes to the named executive officers’ compensation program:

• froze salaries for the second consecutive year;

• decreased the target value of long-term incentive compensation between 9% and 12%; and

• amended the terms of the death benefit only plan to eliminate the payment of any benefit once participants in the plan have retired.

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 2009, 2008 and 2007. 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 (1) ($)	Option Awards (2) ($)	Non-Equity Incentive Plan Compensation (3) ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings (4) ($)	All Other Compensation (5) (6) ($)	Total ($)
Gale E. Klappa
Chairman of the Board,	2009	1,129,008	—	3,191,032	2,309,953	2,286,241	2,450,367	212,627	11,579,228
President and Chief	2008	1,129,008	—	1,441,050	2,946,000	2,328,579	1,328,616	261,040	9,434,293
Executive Officer of	2007	1,075,356	—	1,289,385	2,471,520	2,177,596	4,700,118	223,749	11,937,724
WEC, WE and WG
Allen L. Leverett
Executive Vice President	2009	607,680	—	1,688,178	1,222,020	984,442	314,667	93,366	4,910,353
and Chief Financial	2008	607,680	—	761,355	1,612,935	1,002,672	88,151	101,049	4,173,842
Officer of WEC, WE	2007	576,000	—	608,876	1,176,480	933,120	197,018	84,733	3,576,227
and WG
Frederick D. Kuester
Executive Vice President	2009	657,000	—	1,688,178	1,222,020	1,064,340	1,463,700	92,546	6,187,784
of WEC and WG;	2008	657,000	—	761,355	1,612,935	1,084,050	927,165	136,983	5,179,488
Executive Vice	2007	622,752	—	608,876	1,176,480	1,008,859	2,650,828	110,334	6,178,129
President and Chief
Operating Officer of WE
James C. Fleming
Executive Vice President	2009	441,000	—	615,073	372,400	625,118	233,114	69,838	2,356,543
and General Counsel of	2008	441,000	—	293,014	497,535	636,694	219,296	76,298	2,163,837
WEC, WE and WG	2007	420,000	—	291,306	560,880	595,350	177,938	66,315	2,111,789
Kristine A. Rappé
Senior Vice President and	2009	393,708	—	514,390	372,423	478,356	463,564	91,670	2,314,111
Chief Administrative	2008	393,708	—	232,970	492,964	487,214	252,329	119,066	1,978,251
Officer of WEC, WE	2007	376,752	—	229,224	442,320	457,753	438,017	61,188	2,005,254
and WG

⁽¹⁾ The amounts reported reflect the aggregate grant date fair value, as computed in accordance with FASB ASC Topic 718, of WEC performance units awarded to each named executive officer in the respective year for which such amounts are reported, which includes the value of the right to receive WEC dividends. These amounts are based upon the probable outcome as of the grant date of associated performance and market conditions, and are consistent with our estimate, as of the grant date, of aggregate compensation cost to be recognized over the three-year performance period, excluding the effect of estimated forfeitures. The actual value received by the executives from these awards may range from $0 to greater than the reported amounts, depending upon WEC’s performance over the three-year performance period. The value of these awards as of the grant date, assuming achievement of the highest level of performance, for each of Messrs. Klappa, Leverett, Kuester and Fleming, and Ms. Rappé is $5,584,327, $2,954,332, $2,954,332, $1,076,398 and $900,193 for the 2009 awards, respectively; $2,521,838, $1,332,395, $1,332,395, $512,774 and $407,721 for the 2008 awards, respectively; and $2,256,424, $1,065,557, $1,065,557, $509,785 and $401,142 for the 2007 awards, respectively.

⁽²⁾ The amounts reported reflect the aggregate grant date fair value, as computed in accordance with FASB ASC Topic 718, of WEC stock options awarded to each named executive officer in the respective year for which such amounts are reported. The actual value received by the executives from these awards may range from $0 to greater than the reported amounts, depending upon WEC’s performance and the executive’s number of additional years of service with WEC or its subsidiaries. In accordance with FASB ASC Topic 718, we made certain assumptions in our calculation of the grant date fair value of the WEC stock options. See “Stock Options” in Note A — Summary of Significant Accounting Policies and Note I — Common Equity in the Notes to Consolidated Financial Statements in our 2009 Annual Report on Form 10-K for a description of these assumptions. For 2009, the assumptions made in connection with the valuation of the WEC stock options are the same as described in Note A in our

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2009 Annual Report, except that the expected life of the options is 4.4 years for Mr. Fleming and 6.8 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 4.4 years for Mr. Fleming and 6.8 years for the rest of the named executive officers from 6.2 years, as set forth in Note A, resulted from the fact that Mr. Fleming was “retirement eligible” as of December 31, 2009, 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 WEC stock options.

For 2008, the assumptions made in connection with the valuation of the WEC stock options are the same as described in Note A in our 2009 Annual Report, except that the expected life of the options is 4.6 years for Mr. Fleming and 6.8 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 4.6 years for Mr. Fleming and 6.8 years for the rest of the named executive officers from 6.2 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 WEC 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 2009 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.”

⁽³⁾ Consists of amounts earned under WEC’s Short-Term Performance Plan for 2009, 2008 and 2007. See Note (2) under “Grants of Plan-Based Awards for Fiscal Year 2009” for a description of the terms of the 2009 awards.

⁽⁴⁾ The amounts reported for 2009, 2008 and 2007 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, 2008 to December 31, 2009, December 31, 2007 to December 31, 2008 and December 31, 2006 to December 31, 2007, respectively. Our employees, including the named executive officers, are eligible to participate in WEC’s defined benefit plans. The terms of the pension plan did not change, and no changes were made in the method of calculating benefits thereunder. However, for 2009, the applicable discount rate used to value pension plan liabilities was reduced from 6.5% to 6.05%, consistent with the overall decline in interest rates. The changes in pension values reported for Messrs. Klappa, Leverett, Kuester and Fleming, and Ms. Rappé, were approximately 33%, 93%, 27%, 1% and 43% higher, respectively, as a result of this change in the discount rate than they would have been if the discount rate had remained the same.

The changes in the actuarial present values of the named executive officers’ pension benefits do not constitute cash payments to the named executive officers.

The named executive officers did not receive any above-market or preferential earnings on deferred compensation in 2009, 2008 or 2007.

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.

The total aggregate change in the actuarial present value of Mr. Klappa’s accumulated benefit for 2009, 2008 and 2007 was $2,783,138, $1,347,101 and $5,080,365, respectively—$332,771, $18,485 and $380,247 of which we estimate the prior employer is obligated to pay.

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.

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The total aggregate change in the actuarial present value of Mr. Leverett’s accumulated benefit for 2009, 2008 and 2007 was $350,877, $75,252 and $190,462. For 2009, we estimate that Mr. Leverett’s prior employer is obligated to pay $36,210 of this change. However, because the estimated change in the actuarial present value of his prior employer’s obligation decreased by ($12,899) and ($6,556) in 2008 and 2007, respectively, WEC’s obligation for the aggregate change in the actuarial present value of Mr. Leverett’s total accumulated pension benefit was actually $88,151 and $197,018 for 2008 and 2007, respectively.

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.

The total aggregate change in the actuarial present value of Mr. Kuester’s accumulated benefit for 2009, 2008 and 2007 was $1,730,478, $958,973 and $2,865,319, respectively—$266,778, $31,808 and $214,491 of which we estimate the prior employer is obligated to pay.

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 $145,822 for 2009, $125,177 for 2008 and $122,305 for 2007, which will be paid upon termination of employment after age 65. See “Pension Benefits at Fiscal Year-End 2009” and “Retirement Plans” later in this information statement for additional details.

⁽⁵⁾ During 2009, 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 2009. These tax reimbursements are reflected separately in the Summary Compensation Table (see the third bullet point in Note 6 below). Other than the tax reimbursement, there is no incremental cost to the Company related to this spousal travel.

⁽⁶⁾ 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. As discussed in the Compensation Discussion and Analysis, the Compensation Committee amended the terms of this plan in December 2009 to eliminate the payment of any benefit once participants in the plan have retired. In connection with this amendment, we reversed certain expenses in 2009 that were previously recognized as follows: Mr. Klappa ($369,538), Mr. Leverett ($82,540), Mr. Kuester ($206,436), Mr. Fleming ($197,390) and Ms. Rappé ($74,480). These reversals are not reflected in the reported amounts.

For Mr. Klappa, the amount reported in All Other Compensation for 2009 includes $16,072 attributable to the WEC 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 WEC’s 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 2009 consists of:

• Employer matching of contributions into WEC’s 401(k) plan in the amount of $9,800 for Messrs. Klappa, Kuester and Fleming, and Ms. Rappé, and $9,475 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 $128,828, $54,939, $60,167, $33,633 and $25,762, respectively; and

• Tax reimbursements or “gross-ups” for all applicable perquisites in the amounts of $25,250, $10,021, $6,174, $9,184 and $18,055, 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 10%, 12%, 11%, 19% and 17%, respectively, of total compensation (as shown in column (j) above) for 2009,

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(2) annual incentive compensation (as reflected in column (g) above) represented approximately 20%, 20%, 17%, 27% and 21%, respectively, of total compensation in 2009, and (3) salary and annual incentive compensation together represented approximately 29%, 32%, 28%, 45% and 38%, respectively, of total compensation in 2009.

For Messrs. Klappa, Leverett, Kuester, and Fleming, and Ms. Rappé, (1) salary (as reflected in column (c) above) represented approximately 12%, 15%, 13%, 20% and 20%, respectively, of total compensation (as shown in column (j) above) for 2008, (2) annual incentive compensation (as reflected in column (g) above) represented approximately 25%, 24%, 21%, 29% and 25%, respectively, of total compensation in 2008, and (3) salary and annual incentive compensation together represented approximately 37%, 39%, 34%, 50% and 45%, 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%, 16%, 10%, 20% and 19%, respectively, of total compensation (as shown in column (j) above) for 2007, (2) annual incentive compensation (as reflected in column (g) above) represented approximately 18%, 26%, 16%, 28% and 23%, respectively, of total compensation in 2007, and (3) salary and annual incentive compensation together represented approximately 27%, 42%, 26%, 48% and 42%, respectively, of total compensation in 2007.

Grants of Plan-Based Awards for Fiscal Year 2009

The following table shows additional data regarding incentive plan awards to the named executive officers in 2009.

(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	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 (#)	Awards: Number of Shares of Stock or Units (#)	Number of Securities Underlying Options (#)	Exercise or Base Price (5) ($/Sh)	Closing Market Price (6) ($/Sh)
Gale E.	1/29/09	—	564,504	1,129,008	2,370,917	—	—	—	—	—	—	—	—
Klappa	1/02/09	12/4/08	—	—	—	18,898	75,590	132,283	—	—	—	—	3,191,032
	1/02/09	12/4/08	—	—	—	—	—	—	—	275,980	42.215	42.54	2,309,953
Allen L.	1/29/09	—	243,072	486,144	1,020,902	—	—	—	—	—	—	—	—
Leverett	1/02/09	12/4/08	—	—	—	9,998	39,990	69,983	—	—	—	—	1,688,178
	1/02/09	12/4/08	—	—	—	—	—	—	—	146,000	42.215	42.54	1,222,020
Frederick D.	1/29/09	—	262,800	525,600	1,103,760	—	—	—	—	—	—	—	—
Kuester	1/02/09	12/4/08	—	—	—	9,998	39,990	69,983	—	—	—	—	1,688,178
	1/02/09	12/4/08	—	—	—	—	—	—	—	146,000	42.215	42.54	1,222,020
James C.	1/29/09	—	154,350	308,700	648,270	—	—	—	—	—	—	—	—
Fleming	1/02/09	12/4/08	—	—	—	3,643	14,570	25,498	—	—	—	—	615,073
	1/02/09	12/4/08	—	—	—	—	—	—	—	53,200	42.215	42.54	372,400
Kristine A.	1/29/09	—	118,113	236,225	496,073	—	—	—	—	—	—	—	—
Rappé	1/02/09	12/4/08	—	—	—	3,046	12,185	21,324	—	—	—	—	514,390
	1/02/09	12/4/08	—	—	—	—	—	—	—	44,495	42.215	42.54	372,423

⁽¹⁾ On December 4, 2008, the Compensation Committee awarded the 2009 option and performance unit grants effective the first trading day of 2009 (January 2, 2009).

⁽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 2009 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 2009, each named executive officer earned 202.5% 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 WEC 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

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units that ultimately will vest is dependent upon WEC’s total stockholder return over a three-year period ending December 31, 2011 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; NV Energy, Inc.; OGE Energy Corp.; Pepco Holdings, Inc.; PG&E Corporation; Pinnacle West Capital Corporation; Portland General; Progress Energy Inc.; SCANA Corporation; Sempra Energy; 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:

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 on a straight line basis 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 WEC 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. Ending with these 2009 awards, participants, including the named executive officers, will receive a cash dividend pursuant to the terms of the WEC Performance Unit Plan 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, 2009. 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 FASB ASC Topic 718, which includes the value of the right to receive dividends and excludes the amount of estimated forfeitures as required by Item 402 of Regulation S-K. 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.

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Outstanding Equity Awards at Fiscal Year-End 2009

The following table reflects the number and value of exercisable and unexercisable WEC stock options as well as the number and value of other WEC stock awards held by the named executive officers at fiscal year-end 2009.

(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	—		—	—		—
	—	275,980	—	42.215	1/02/19	—		—	—		—
	—	—	—	—	—	18,144	(4)	904,116	—		—
	—	—	—	—	—	—		—	52,500	(9)	2,616,075	(9)
	—	—	—	—	—	—		—	132,283	(10)	6,591,662	(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	—		—	—		—
	—	146,000	—	42.215	1/02/19	—		—	—		—
	—	—	—	—	—	2,221	(5)	110,672	—		—
	—	—	—	—	—	—		—	27,738	(9)	1,382,185	(9)
	—	—	—	—	—	—		—	69,983	(10)	3,487,253	(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	—		—	—		—
	—	146,000	—	42.215	1/02/19	—		—	—		—
	—	—	—	—	—	10,849	(6)	540,606	—		—
	—	—	—	—	—	—		—	27,738	(9)	1,382,185	(9)
	—	—	—	—	—	—		—	69,983	(10)	3,487,253	(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	—		—	—		—
	—	53,200	—	42.215	1/02/19	—		—	—		—
	—	—	—	—	—	1,088	(7)	54,215	—		—
	—	—	—	—	—	—		—	10,675	(9)	531,935	(9)
	—	—	—	—	—	—		—	25,498	(10)	1,270,565	(10)
Kristine A.	20,925	—	—	33.435	1/02/14	—		—	—		—
Rappé	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	—		—	—		—
	—	44,495	—	42.215	1/02/19	—		—	—		—
	—	—	—	—	—	4,000	(8)	199,320	—		—
	—	—	—	—	—	—		—	8,488	(9)	422,957	(9)
	—	—	—	—	—	—		—	21,324	(10)	1,062,575	(10)

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

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⁽²⁾ All options reported in this column with an exercise price of $47.755 and an expiration 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. All options reported in this column with an exercise price of $42.215 and an expiration date of January 2, 2019, fully vest and become exercisable on January 2, 2012.

⁽³⁾ Based on the closing price of WEC common stock reported in the New York Stock Exchange Composite Transaction Report on December 31, 2009, 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 the 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 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 cumulative WEC 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 WEC 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 the WEC restricted stock.

⁽⁹⁾ The number of WEC performance units reported were awarded in 2008 and 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.

⁽¹⁰⁾ The number of WEC performance units reported were awarded in 2009 and vest at the end of the three-year performance period ending December 31, 2011. The number of performance units reported and their corresponding value are based upon a payout at the maximum amount.

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Option Exercises and Stock Vested for Fiscal Year 2009

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 2009.

(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	—	—		4,695	(2)	186,884	(3)
	—	—		46,251	(4)	2,304,687	(5)
Allen L. Leverett	—	—		2,232	(2)	92,103	(3)
	—	—		21,840	(4)	1,088,325	(5)
Frederick D. Kuester	—	—		2,892	(2)	128,000	(3)
	—	—		21,840	(4)	1,088,325	(5)
James C. Fleming	—	—		542	(2)(6)	22,731	(3)(6)
	—	—		10,449	(4)	520,689	(5)
Kristine A. Rappé	10,000	142,470	(1)	273	(2)(6)	12,378	(3)(6)
	—	—		8,222	(4)	409,722	(5)

⁽¹⁾ Value realized upon the exercise of WEC stock options is determined by multiplying the number of shares received upon exercise by the difference between the market price of WEC common stock at the time of exercise and the exercise price.

⁽²⁾ Reflects the number of shares of WEC restricted stock that vested in 2009.

⁽³⁾ 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.

⁽⁴⁾ Reflects the number of WEC performance units that vested as of December 31, 2009, the end of the applicable three-year performance period. The performance units were settled in cash.

⁽⁵⁾ Performance units value realized is determined by multiplying the number of WEC performance units that vested by the closing market price of WEC common stock on December 31, 2009.

⁽⁶⁾ Mr. Fleming and Ms. Rappé deferred $22,731 and $12,243, 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.

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Pension Benefits at Fiscal Year-End 2009

The following table sets forth information for each named executive officer regarding their pension benefits at fiscal year-end 2009 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	6.67		117,997	—
	SERP A	6.67		1,250,917	—
	Individual Letter Agreement	32.33		12,844,366	—
Allen L. Leverett	WEC Plan	6.50		108,020	—
	SERP A	6.50		648,257	—
	Individual Letter Agreement	21.00		720,685	—
Frederick D. Kuester	WEC Plan	6.17		105,777	—
	SERP A	6.17		555,606	—
	Individual Letter Agreement	37.33		7,760,608	—
James C. Fleming	WEC Plan	4.00		67,802	—
	SERP A	4.00		190,313	—
	Individual Letter Agreement	4.00		519,722	—
Kristine A. Rappé	WEC Plan	27.33		587,865	—
	SERP A	27.33		1,628,165	—
	SERP B	—	(4)	475,794	—
	Individual Letter Agreement	—		—	—

⁽¹⁾ Years of service are computed as of December 31, 2009, 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 6.05%.

• 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 $17,382,252, $1,687,275 and $11,115,772, respectively, $3,168,971, $210,313 and $2,693,781 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 $3,299,932, $1,536,600, $1,661,380 and $850,862, 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 $1,077,694. This amount represents Mr. Fleming’s 2009 base salary, which was the same as his 2008 base salary, plus his 2008 STPP award paid in 2009. As of December 31, 2009, Messrs. Klappa, Leverett, Kuester and Fleming, and Ms. Rappé, currently have or are considered to have 32.33, 21.00, 37.33, 4.00 and 27.33 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 WEC 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.

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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.

Pursuant to the Internal Revenue Code, only $245,000 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 the Company, 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 or its subsidiaries until retirement or death. The Compensation Committee eliminated 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 or its subsidiaries. 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 did not lose pension earnings by joining the executive management teams 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 of WEC if the executive’s employment is terminated within 18 months after the change in control. 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 2009

The following table reflects activity by the named executive officers during 2009 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	463,001	128,828	81,292	—	2,828,562
Allen L. Leverett	112,725	54,939	141,380	—	1,970,000
Frederick D. Kuester	114,209	60,167	125,538	—	1,820,280
James C. Fleming	394,375	33,633	102,393	—	812,391
Kristine A. Rappé	69,314	25,762	248,976	—	1,809,691

⁽¹⁾ Other than $58,871 and $12,243 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 2009 and/or dividends paid on WEC performance units during 2009. The grant date fair value of the WEC performance units granted in 2007, 2008 and 2009 (which includes the value of the right to receive dividends) are included in the Summary Compensation Table.

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

⁽³⁾ $1,826,179, $1,332,992, $1,159,595, $297,562 and $210,780 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 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. Since January 1, 2005, all deferrals have been 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 loss on deferred amounts for the duration of the deferral period. Each participant may select the amount of deferred compensation to

35

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 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 Legacy EDCP and their annual rate of return for the calendar year ended December 31, 2009:

Name of Fund	Rate of Return (%)	Name of Fund	Rate of Return (%)
Fidelity Balanced Fund	28.05	Fidelity U.S. Bond Index Fund	6.45
Fidelity Diversified International Fund	31.78	Prime Rate	3.30
Fidelity Equity – Income Fund	29.54	S&P 500 Fund	26.46
Fidelity Growth Company Fund	41.15	Vanguard Mid-Cap Index	40.22
Fidelity Low-Priced Stock Fund	39.08	WEC Common Stock Fund	22.50

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 or her 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.

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 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 WEC restricted stock are always deemed invested in 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 EDCP may not be withdrawn at the discretion of the participant and a change to the designated payout date delays the initial payment

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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 or her 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 WEC Executive Deferred Compensation Plan at fiscal year-end 2009, as reported in column (f) under “Nonqualified Deferred Compensation for Fiscal Year 2009.” 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, 2009 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, 2009, 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 2009.” 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 Executive Deferred Compensation Plan 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 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 Executive Deferred Compensation Plan account balances.

In addition, Ms. Rappé is entitled to full vesting of her restricted stock upon retirement at or after attainment of age 60. 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 of WEC;

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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 WEC Executive Deferred Compensation Plan;

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

• 401(k) plan and Executive Deferred Compensation Plan 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 and Mr. Kuester’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 Executive Deferred Compensation Plan 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.

Mr. Fleming is entitled to the same benefits as Mr. Klappa upon termination of employment in connection with a change in control of WEC. However, Mr. Fleming is not entitled to receive any severance payments upon termination of employment for good reason or without cause in the absence of a change in control.

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 Executive Deferred Compensation Plan 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

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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.

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	—	—	—	10,372,761	10,372,761	—	—
Additional Pension Credited Service	—	—	—	2,602,135	2,602,135	—	—
Additional 401(k) and EDCP Match	—	—	—	414,910	414,910	—	—
Long-Term Incentive Compensation:
Performance Units	—	2,252,149	—	5,261,550	5,261,550	5,261,550	5,261,550
Restricted Stock	—	—	—	904,147	904,147	904,147	904,147
Options	—	3,202,413	—	3,202,413	3,202,413	3,202,413	3,202,413
Benefits & Perquisites:
Retirement Plans	117,997	14,213,281	117,997	13,801,747	13,801,747	14,213,281	6,515,689
Health and Welfare Benefits	—	—	—	38,321	38,321	—	—
Excise Tax Gross-Up	—	—	—	—	9,900,732	—	—
Financial Planning	—	—	—	45,000	45,000	—	—
Outplacement	—	—	—	30,000	30,000	—	—
Death Benefit Only Plan	—	—	—	—	—	—	3,387,024
Total	117,997	19,667,843	117,997	36,672,984	46,573,716	23,581,391	19,270,823

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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	—	—	—	3,220,704	4,831,056	—	—
Additional Pension Credited Service	—	—	—	530,888	709,170	—	—
Additional 401(k) and EDCP Match	—	—	—	128,828	193,242	—	—
Long-Term Incentive Compensation:
Performance Units	—	1,190,771	—	2,782,507	2,782,507	2,782,507	2,782,507
Restricted Stock	—	—	—	110,685	110,685	110,685	110,685
Options	—	1,674,294	—	1,674,294	1,674,294	1,674,294	1,674,294
Benefits & Perquisites:
Retirement Plans	108,020	1,476,963	108,020	1,546,254	1,583,967	1,476,963	1,147,465
Health and Welfare Benefits	—	—	—	25,548	38,321	—	—
Excise Tax Gross-Up	—	—	—	—	4,872,112	—	—
Financial Planning	—	—	—	30,000	45,000	—	—
Outplacement	—	—	—	30,000	30,000	—	—
Death Benefit Only Plan	—	—	—	—	—	—	1,823,040
Total	108,020	4,342,028	108,020	10,079,708	16,870,354	6,044,449	7,537,991

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	—	—	—	3,482,100	5,223,150	—	—
Additional Pension Credited Service	—	—	—	1,195,612	1,284,893	—	—
Additional 401(k) and EDCP Match	—	—	—	139,284	208,926	—	—
Long-Term Incentive Compensation:
Performance Units	—	1,190,771	—	2,782,507	2,782,507	2,782,507	2,782,507
Restricted Stock	—	—	—	540,627	540,627	540,627	540,627
Options	—	1,674,294	—	1,674,294	1,674,294	1,674,294	1,674,294
Benefits & Perquisites:
Retirement Plans	105,777	8,421,990	105,777	7,436,942	6,764,370	8,421,990	3,421,274
Health and Welfare Benefits	—	—	—	25,548	38,321	—	—
Excise Tax Gross-Up	—	—	—	—	5,191,861	—	—
Financial Planning	—	—	—	30,000	45,000	—	—
Outplacement	—	—	—	30,000	30,000	—	—
Death Benefit Only Plan	—	—	—	—	—	—	1,971,000
Total	105,777	11,287,055	105,777	17,336,914	23,783,949	13,419,418	10,389,702

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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	—	—	—	—	3,233,082	—	—
Additional Pension Credited Service	—	—	—	—	586,316	—	—
Additional 401(k) and EDCP Match	—	—	—	—	129,323	—	—
Long-Term Incentive Compensation:
Performance Units	—	444,650	—	444,650	1,029,986	1,029,986	1,029,986
Restricted Stock	—	—	—	—	54,224	54,224	54,224
Options	—	643,123	—	643,123	643,123	643,123	643,123
Benefits & Perquisites:
Retirement Plans	258,115	777,837	258,115	258,115	802,856	777,837	775,707
Health and Welfare Benefits	—	—	—	—	38,321	—	—
Excise Tax Gross-Up	—	—	—	—	2,413,005	—	—
Financial Planning	—	—	—	—	45,000	—	—
Outplacement	—	—	—	—	30,000	—	—
Death Benefit Only Plan	—	—	—	—	—	—	1,323,000
Total	258,115	1,865,610	258,115	1,345,888	9,005,236	2,505,170	3,826,040

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	—	—	—	1,259,866	1,889,798	—	—
Additional Pension Credited Service	—	—	—	255,980	386,672	—	—
Additional 401(k) and EDCP Match	—	—	—	50,395	75,592	—	—
Long-Term Incentive Compensation:
Performance Units	—	363,510	—	848,854	848,854	848,854	848,854
Restricted Stock	—	199,349	—	199,349	199,349	199,349	199,349
Options	—	529,576	—	529,576	529,576	529,576	529,576
Benefits & Perquisites:
Retirement Plans	578,865	2,682,824	578,865	3,725,685	3,769,091	2,682,824	1,783,785
Health and Welfare Benefits	—	—	—	25,548	38,321	—	—
Excise Tax Gross-Up	—	—	—	—	4,741,068	—	—
Financial Planning	—	—	—	30,000	30,000	—	—
Outplacement	—	—	—	30,000	30,000	—	—
Death Benefit Only Plan	—	—	—	—	—	—	1,181,124
Total	578,865	3,775,259	578,865	6,955,253	12,538,321	4,260,603	4,542,688

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DIRECTOR COMPENSATION

The following table summarizes total compensation awarded to, earned by or paid to each of the Company’s non-employee directors during 2009. The amounts shown in the table are WEC consolidated compensation data.

(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)
Name	Fees Earned or Paid In Cash ($)	Stock Awards (1)(2) ($)	Option Awards (3) ($)	Non-Equity Incentive Plan Compensation ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)	All Other Compensation (4) ($)	Total ($)
John F. Bergstrom	80,000	75,000	—	—	—	20,677	175,677
Barbara L. Bowles	80,000	75,000	—	—	—	18,986	173,986
Patricia W. Chadwick	75,000	75,000	—	—	—	19,843	169,843
Robert A. Cornog	75,000	75,000	—	—	—	41,077	191,077
Curt S. Culver	80,000	75,000	—	—	—	14,758	169,758
Thomas J. Fischer	82,500	75,000	—	—	—	24,861	182,361
Ulice Payne, Jr.	75,000	75,000	—	—	—	10,513	160,513
Frederick P. Stratton, Jr.	75,000	75,000	—	—	—	20,608	170,608

⁽¹⁾ The amounts reported reflect the aggregate grant date fair value, as computed in accordance with FASB ASC Topic 718, of WEC restricted stock awards made to the directors in 2009. 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 I — Common Equity in the Notes to Consolidated Financial Statements in our 2009 Annual Report on Form 10-K for a description of these assumptions.

⁽²⁾ Directors held the following number of shares of WEC restricted stock as of December 31, 2009: Mr. Bergstrom (5,180), Ms. Bowles (5,180), Ms. Chadwick (5,180), Mr. Cornog (5,180), Mr. Culver (5,180), Mr. Fischer (5,180), Mr. Payne (5,180) and Mr. Stratton (5,180).

⁽³⁾ Directors held the following number of options to purchase WEC common stock as of December 31, 2009, all of which are exercisable: Ms. Bowles (5,000), Mr. Cornog (15,000) and Mr. Payne (10,000).

⁽⁴⁾ 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 2009, 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. 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, 2009, the 2009 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.

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 the provisions of Section 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 the Company. The deferred amounts will be paid out of general corporate assets or the assets of the WEC Amended Non-Qualified Trust.

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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.

WEC has a Directors’ Charitable Awards Program to help further its 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, following the director’s death. Directors are provided with one charitable award benefit for serving on the boards of WEC and its subsidiaries, including the Company. 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 2009, the Compensation Committee reviewed director compensation and determined that no changes should be made for 2010.

RISK ANALYSIS OF WE’s COMPENSATION POLICIES AND PRACTICES

As part of its process to determine the 2010 compensation of the named executive officers, the Compensation Committee analyzed whether the compensation program of WEC and its subsidiaries, including the Company, taken as a whole creates risks that are reasonably likely to have a material adverse effect on WEC and its subsidiaries. The Committee concluded it does not. This analysis applies generally to the compensation program for WEC’s and the Company’s employees since all management employees (both officers and non-officers) above a certain level are provided with substantially the same mix of compensation as the named executive officers. The compensation package provided to employees below this level is not applicable to this analysis as such compensation package does not provide sufficient incentive to take risks that could materially affect WEC or the Company.

There is no objective way to measure risk resulting from a corporation’s compensation program; therefore, this analysis is subjective in nature. We believe that the only elements of our compensation program that could incentivize risk taking by WEC’s or the Company’s employees, and therefore have a reasonable likelihood of materially adversely affecting WEC or the Company, are the annual cash incentive compensation and the long-term incentive compensation, the payout of which is dependent on the achievement of certain performance levels by WEC and its subsidiaries, including the Company. Based upon the value of each of these elements to the overall compensation mix and the relative value each has to the other, we believe our compensation program is appropriately balanced. We believe that the mix of short- and long-term awards minimizes risks that may be taken, as any risks taken for short-term gains could ultimately jeopardize WEC’s or the Company’s ability to meet the long-term performance objectives. Given the current balance of compensation elements, we do not believe our compensation program incentivizes unreasonable risk taking by management. In addition, we believe the Compensation Committee’s stock ownership guidelines, which require officers who participate in the long-term incentive compensation program to hold WEC common stock and other equity-related WEC securities having a minimum fair market value ranging from 150% to 300% of base salary, further discourage unreasonable risk taking by WEC or Company officers.

As part of this analysis, we also considered the nature of WEC’s business as a public utility holding company and the fact that substantially all of its earnings and other financial results are generated by regulated public utilities, including the Company. The highly regulated nature of WEC’s business, including limits on the amount of profit the Company (and therefore, WEC) may earn, significantly reduces any incentive to engage in conduct that would be reasonably likely to have a material adverse effect on WEC or the Company.

43

STOCK OWNERSHIP OF DIRECTORS, NOMINEES AND EXECUTIVE OFFICERS

None of the Company’s directors, nominees or executive officers own any of WE 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 its directors and executive officers as a group as of February 12, 2010. 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, 2010. 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. Other than as indicated in Note 6 below, 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	10,748	—	10,748
Barbara L. Bowles	15,633	5,000	20,633
Patricia W. Chadwick	7,575	—	7,575
Robert A. Cornog	14,484	15,000	29,484
Curt S. Culver	4,990	—	4,990
Thomas J. Fischer	12,253	—	12,253
James C. Fleming	2,854	136,500	139,354
Gale E. Klappa	45,624	1,253,000	1,298,624	(6)
Frederick D. Kuester	23,075	674,000	697,075
Allen L. Leverett	10,732	674,000	684,732
Ulice Payne, Jr.	11,649	10,000	21,649
Kristine A. Rappé	13,189	192,425	205,614
Frederick P. Stratton, Jr.	19,589	—	19,589
All directors and executive officers as a group (15 persons)	231,245	3,171,885	3,403,130	(7)

⁽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.

⁽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 (14,190), Ms. Bowles (36), Mr. Cornog (20,418), Mr. Culver (17,448), Mr. Fleming (2,223), Mr. Kuester (2,812), Ms. Rappé (12,889), Mr. Stratton (16,203) and all directors and executive officers as a group (86,518). 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. Kuester (6,706), Mr. Leverett (3,012), Mr. Stratton (4,600) and all directors and executive officers as a group (24,825).

⁽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 (4,989), Ms. Bowles (4,989), Ms. Chadwick (4,990), Mr. Cornog (4,989), Mr. Culver (4,990), Mr. Fischer (4,990), Mr. Fleming (2,069), Mr. Klappa (26,429), Mr. Kuester (15,159), Mr. Leverett (6,531), Mr. Payne (4,989), Ms. Rappé (5,280), Mr. Stratton (4,989) and all directors and executive officers as a group (104,593).

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

⁽⁶⁾ Represents 1.1% of total WEC common stock outstanding on February 12, 2010.

⁽⁷⁾ Represents 2.9% of total WEC common stock outstanding on February 12, 2010.

44

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 2009 fiscal year. To the Company’s knowledge, based on information provided by the reporting persons, all applicable reporting requirements for fiscal year 2009 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.

Compensation Committee Interlocks and Insider Participation – None of the persons who served as members of the Compensation Committee during 2009 was an officer or employee of the Company during 2009 or at any time in the past nor had reportable transactions with the Company.

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, 2009, 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 2009 Annual Financial Statements and Review of Operations, attached hereto as Appendix A.

45

APPENDIX A

WISCONSIN ELECTRIC POWER COMPANY

2009 ANNUAL REPORT TO STOCKHOLDERS

2009 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
MACT	Maximum Achievable Control Technology
NOV	Notice of Violation
NOx	Nitrogen Oxide
PM 2.5	Fine Particulate Matter
RACT	Reasonably Available Control Technology
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
ANPR	Advanced Notice of Proposed Rulemaking
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
Energy Policy Act	Energy Policy Act of 2005
ERISA	Employee Retirement Income Security Act of 1974
Fitch	Fitch Ratings
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.
Plan	The Wisconsin Energy Corporation Retirement Account Plan
Point Beach	Point Beach Nuclear Power Plant
PRSG	Planning Reserve Sharing Groups
PTF	Power the Future
PUHCA 2005	Public Utility Holding Company Act of 2005
RFC	Reliability First Corporation
RSG	Revenue Sufficiency Guarantee
RTO	Regional Transmission Organizations
Settlement Agreement	Settlement Agreement and Release between ERS and Bechtel effective as of December 16, 2009
S&P	Standard & Poor’s Ratings Services
WPL	Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corp.
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

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:

Accounting Terms
AFUDC	Allowance for Funds Used During Construction
ARO	Asset Retirement Obligation
CWIP	Construction Work in Progress
FASB	Financial Accounting Standards Board
GAAP	Generally Accepted Accounting Principles
IFRS	International Financial Reporting Standards
OPEB	Other Post-Retirement Employee Benefits

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,” “should” 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.

• Timing, resolution and impact of pending and 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 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.

A-4

• 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.

• Events in the global credit markets that may affect 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.

We expressly disclaim any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

A-5

WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED SELECTED FINANCIAL AND STATISTICAL DATA

Financial	2009		2008		2007		2006		2005
Year Ended December 31
Earnings available forcommon stockholder (Millions)	$	287.4	$	280.1	$	287.7	$	275.6	$	283.6
Operating revenues (Millions)
Electric	$	2,685.0	$	2,660.6	$	2,674.6	$	2,499.5	$	2,320.9
Gas		564.2		709.2		611.9		590.0		593.6
Steam		39.1		40.3		35.1		27.2		23.5
Total operating revenues	$	3,288.3	$	3,410.1	$	3,321.6	$	3,116.7	$	2,938.0
At December 31 (Millions)
Total assets	$	8,871.2	$	8,775.4	$	8,312.8	$	8,257.8	$	7,909.2
Long-term debt and capital lease obligations (including current maturities)	$	3,092.8	$	2,886.4	$	1,990.4	$	2,152.1	$	2,058.5

CONSOLIDATED SELECTED QUARTERLY FINANCIAL DATA (Unaudited)

	(Millions of Dollars) (a)
	March				June
Three Months Ended	2009		2008		2009		2008
Total operating revenues	$	988.4	$	985.9	$	723.7	$	782.0
Operating income	$	158.1	$	141.1	$	87.2	$	86.8
Earnings available for common stockholder	$	98.5	$	83.6	$	51.2	$	51.9
	September				December
Three Months Ended	2009		2008		2009		2008
Total operating revenues	$	738.3	$	750.9	$	837.9	$	891.3
Operating income	$	83.4	$	119.4	$	140.2	$	134.6
Earnings available for common stockholder	$	52.4	$	73.7	$	85.3	$	70.9

(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.

A-6

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 and distributing electricity in Wisconsin and the Upper Peninsula of Michigan, and distributing natural gas in Wisconsin. 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, Bostco.

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, an unregulated company that was formed in 2001 to design, construct, own and lease to us the new generating capacity included in Wisconsin Energy’s PTF strategy, which is described further in this report. We have combined common functions with Wisconsin Gas 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. PWGS 1 and PWGS 2, two 545 MW natural gas electric generating units, were placed in service in July 2005 and May 2008, respectively, and OC 1, a 615 MW coal-fired generating unit, was placed in service on February 2, 2010. Although the new guaranteed in-service date is November 28, 2010, the contractor, Bechtel, is currently targeting commercial operation of OC 2, another 615 MW coal-fired generating unit, by the end of August 2010. We are entitled to 515 MW of each unit.

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 the demand for electricity and ensure a diverse fuel mix while keeping electricity prices reasonable. Under PTF, Wisconsin Energy is (1) investing approximately $2.7 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.

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.

The primary risks that remain under PTF are construction risks associated with the schedule and costs for OC 2; 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, see Factors Affecting Results, Liquidity and Capital Resources below.

A-7

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. 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. At the direction of our regulators, 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. For further information on the 2008 and 2010 rate cases, 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.

RESULTS OF OPERATIONS

EARNINGS

2009 vs. 2008: Earnings increased to $287.4 million in 2009 compared with $280.1 million in 2008. Operating income decreased $13.0 million between the comparative periods. The most significant factors that impacted operating income during 2009 were less favorable weather during the spring and summer months and a decline in economic conditions throughout 2009, both of which decreased electric sales. However, we experienced a decrease in fuel and purchased power costs largely due to lower MWh sales and a decrease in operating and maintenance expense during 2009 as compared to 2008.

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.

The following table summarizes our consolidated earnings during 2009, 2008 and 2007:

	2009			2008			2007
	(Millions of Dollars)
Utility Gross Margin
Electric (See below)	$	1,632.9		$	1,431.5		$	1,693.3
Gas (See below)		174.5			182.8			170.0
Steam		26.7			27.1			24.3
Total Gross Margin		1,834.1			1,641.4			1,887.6
Other Operating Expenses
Other operation and maintenance		1,231.7			1,295.2			1,041.9
Depreciation, decommissioning and amortization		265.1			256.0			269.7
Property and revenue taxes		99.1			96.4			91.7
Amortization of gain		(230.7	)		(488.1	)		(6.5	)
Operating Income		468.9			481.9			490.8
Equity in Earnings of Transmission Affiliate		51.9			45.4			37.9
Other Income and Deductions, net		25.8			9.9			41.7
Interest Expense, net		100.3			86.6			93.0
Income Before Income Taxes		446.3			450.6			477.4
Income Taxes		157.7			169.3			188.5
Preferred Stock Dividend Requirement		1.2			1.2			1.2
Earnings Available for Common Stockholder	$	287.4		$	280.1		$	287.7

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 2009 and 2008 earnings reflect higher fuel and purchased power costs as compared to 2007. In addition, as it relates to nuclear operating costs, our 2009 and 2008 operating income reflects lower other operation and maintenance costs and lower depreciation, decommissioning and amortization costs as we no longer own Point Beach.

A-8

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. The PSCW also determined that $85.0 million of Point Beach proceeds should be immediately applied during the first quarter of 2008 to offset certain regulatory assets. 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 resulted 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.

Electric Utility Gross Margin

The following table compares our electric utility gross margin during 2009 with similar information for 2008 and 2007, including a summary of electric operating revenues and electric sales by customer class:

	Electric Revenues and Gross Margin						Electric MWh Sales
Electric Utility Operations	2009		2008		2007		2009	2008	2007
	(Millions of Dollars)						(Thousands, Except Degree Days)
Customer Class
Residential	$	977.6	$	962.5	$	915.5	7,949.3	8,277.1	8,416.1
Small Commercial/Industrial		860.3		869.7		840.6	8,571.6	9,023.7	9,185.4
Large Commercial/Industrial		599.4		646.3		664.2	9,140.3	10,691.7	11,036.7
Other - Retail		21.2		20.8		19.2	156.5	161.5	162.4
Total Retail		2,458.5		2,499.3		2,439.5	25,817.7	28,154.0	28,800.6
Wholesale - Other		116.7		77.7		83.5	1,529.4	2,620.7	1,939.6
Resale - Utilities		47.5		37.7		110.7	1,548.9	881.0	1,920.7
Other Operating		62.3		45.9		40.9	—	—	—
Total	$	2,685.0	$	2,660.6	$	2,674.6	28,896.0	31,655.7	32,660.9
Fuel and Purchased Power
Fuel		518.3		570.6		570.0
Purchased Power		533.8		658.5		411.3
Total Fuel and Purchased Power		1,052.1		1,229.1		981.3
Total Electric Gross Margin	$	1,632.9	$	1,431.5	$	1,693.3
Weather - Degree Days (a)
Heating (6,640 Normal)							6,825	7,073	6,508
Cooling (698 Normal)							475	593	800

(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

2009 vs. 2008: Our electric utility operating revenues increased by $24.4 million, or 0.9%, when compared to 2008. The most significant factors that caused a change in revenues were:

• 2009 pricing increases totaling approximately $109.9 million reflecting the reduction of Point Beach credits to retail customers.

• A one-time FERC-approved refund to our wholesale customers in 2008 associated with their share of the gain on the sale of Point Beach that reduced 2008 wholesale revenues by $62.5 million.

• Net pricing increases totaling approximately $20.4 million related to Wisconsin and Michigan rate orders.

• Unfavorable weather that reduced electric revenues by an estimated $35.3 million as compared to 2008.

• A slowdown in the economy that reduced commercial and industrial sales by an estimated $129.0 million and wholesale sales by an estimated $30.9 million.

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Our total electric sales volumes decreased by approximately 8.7% as compared to 2008 due almost exclusively to a continued decline in economic conditions, which primarily affected our commercial and industrial sales, and milder weather, which primarily affected our residential sales. Total retail sales volumes declined approximately 8.3%. Of the 8.3% decline in retail sales volumes, approximately 7.1% relates to sales volumes at our small and large commercial and industrial customers. As measured by cooling degree days, 2009 was 19.9% cooler than 2008 and 31.9% cooler than normal.

We currently estimate that 2010 electric revenues will increase because of the impact of the 2010 PSCW rate increase, the reduction in the Point Beach bill credits and a slight increase in sales to large commercial and industrial customers as current economic conditions have improved slightly in our service territory. We would also expect residential sales to increase if we experience normal summer weather. However, we expect sales to small commercial and industrial customers to decrease slightly from 2009. For further information regarding the January 2010 PSCW rate order, see Factors Affecting Results, Liquidity and Capital Resources — Rates and Regulatory Matters - 2010 Rate Case.

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. Resale 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.

Electric Fuel and Purchased Power Expenses

2009 vs. 2008: Our electric fuel and purchased power costs decreased by $177.0 million, or 14.4%, when compared to 2008. This decline was primarily caused by lower MWh sales and lower natural gas and purchased power prices, partially offset by higher coal and related transportation costs. Approximately $41.2 million of this decrease related to the one-time amortization of deferred fuel costs recorded in the first quarter of 2008 pursuant to the January 2008 PSCW rate order. Adjusted for the one-time amortization, our electric fuel and purchased power costs decreased by $135.8 million, or 11.0%.

We expect that electric fuel and purchased power expenses in 2010 will be impacted by the price of natural gas, changes in the cost of coal and related transportation prices, and changes in electric sales.

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 2008. 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.

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 2009, 2008 and 2007:

Gas Utility Operations	2009		2008		2007
	(Millions of Dollars)
Operating Revenues	$	564.2	$	709.2	$	611.9
Cost of Gas Sold		389.7		526.4		441.9
Gross Margin	$	174.5	$	182.8	$	170.0

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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 2009, 2008 and 2007:

	Gross Margin						Therm Deliveries
Gas Utility Operations	2009		2008		2007		2009	2008	2007
	(Millions of Dollars)						(Millions, Except Degree Days)
Customer Class
Residential	$	117.3	$	120.5	$	113.1	349.4	364.7	342.6
Commercial/Industrial		40.2		41.9		38.7	208.8	216.2	199.6
Interruptible		0.6		0.7		0.7	5.9	6.9	7.1
Total Retail Gas Sales		158.1		163.1		152.5	564.1	587.8	549.3
Transported Gas		14.3		15.8		15.6	298.4	313.3	333.7
Other		2.1		3.9		1.9	—	—	—
Total	$	174.5	$	182.8	$	170.0	862.5	901.1	883.0
Weather — Degree Days (a)
Heating (6,640 Normal)							6,825	7,073	6,508

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

2009 vs. 2008: Our gas margin decreased by $8.3 million, or approximately 4.5%, when compared to 2008. We estimate that milder winter weather and a decline in economic conditions caused our margin to decrease by approximately $5.4 million during 2009 as compared to 2008. As measured by heating degree days, 2009 was 3.5% warmer than 2008, but 2.8% colder than normal.

We expect our 2010 gas margin will be impacted by weather; however, as noted above, 2009 was colder than normal.

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.

Other Operation and Maintenance Expense

2009 vs. 2008: Our other operation and maintenance expense decreased by $63.5 million, or approximately 4.9%, when compared to 2008. The largest factor for this decrease relates to a $43.8 million one-time amortization of deferred bad debt costs in 2008 pursuant to the January 2008 PSCW rate order. The January 2008 PSCW rate order, which was in effect for all of 2009, allowed for pricing increases related to transmission costs, PTF lease costs and the amortization of other deferred costs. We estimate that these items were approximately $16.4 million higher in 2009 as compared to 2008. The remaining decrease is primarily related to reduced operating and maintenance expenses at our power plants and electric distribution system.

Our operation and maintenance expense is influenced by wage inflation, employee benefit costs, plant outages and the amortization of regulatory assets. We expect our 2010 other operation and maintenance expense to increase because of costs associated with the new Oak Creek units and regulatory amortizations.

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 sold the plant in September 2007.

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Depreciation, Decommissioning and Amortization Expense

2009 vs. 2008: Depreciation, decommissioning and amortization expense increased by $9.1 million, or approximately 3.6%, when compared to 2008. This increase was primarily the result of higher depreciation related to new capital projects placed in service, including the Blue Sky Green Field wind project which was placed into service in May 2008.

We expect depreciation, decommissioning and amortization expense to decrease by approximately $40 million in 2010 because of new depreciation rates that were implemented in connection with the January 2010 PSCW rate order. The new depreciation rates generally reflect longer lives for our utility assets.

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. Partially offsetting this decline was higher depreciation related to new projects including the Blue Sky Green Field wind project.

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 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 2009, 2008 and 2007, the Amortization of Gain was as follows:

Amortization of Gain	2009		2008			2007
	(Millions of Dollars)
Bill Credits - Retail	$	230.7	$	340.6		$	6.5
One-Time FERC Refund		—		62.5			—
One-Time Amortization to Offset Regulatory Asset		—		85.0			—
Total Amortization of Gain	$	230.7	$	488.1		$	6.5
					��

During 2010, we expect to see a reduction in the Amortization of Gain of approximately $36.0 million related to the scheduled decrease in bill credits to retail customers compared to 2009. We expect that all remaining bill credits will be issued by the end of 2010.

Other Income and Deductions, net

The following table identifies the components of consolidated other income and deductions, net during 2009, 2008 and 2007:

Other Income and Deductions, net	2009			2008			2007
	(Millions of Dollars)
Carrying Costs	$	—		$	0.8		$	28.8
Gain on Property Sales		1.7			2.3			12.9
AFUDC - Equity		15.9			7.5			5.1
Donations and Contributions		(5.5	)		(12.0	)		(10.3	)
Other, net		13.7			11.3			5.2
Total Other Income and Deductions, net	$	25.8		$	9.9		$	41.7

2009 vs. 2008: Other income and deductions, net increased by $15.9 million when compared to 2008 primarily due to higher interest income and an increase in AFUDC - Equity related to the construction of our Oak Creek AQCS project. We expect to see an increase in AFUDC - Equity during 2010 with the continued construction of the Oak Creek AQCS project.

2008 vs. 2007: Other income and deductions, net decreased by $31.8 million when compared to 2007. We stopped accruing carrying charges on regulatory assets as the January 2008 PSCW rate order 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.

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Interest Expense, net

Interest Expense, net	2009		2008		2007
	(Millions of Dollars)
Gross Interest Costs	$	106.9	$	89.6	$	94.8
Less: Capitalized Interest		6.6		3.0		1.8
Interest Expense, net	$	100.3	$	86.6	$	93.0

2009 vs. 2008: Our gross interest costs increased by $17.3 million, or 19.3%, when compared to 2008, primarily due to higher debt balances to fund our planned construction activity, partially offset by lower short-term interest rates. Our capitalized interest increased by $3.6 million due to increased capital expenditures in 2009 related to our Oak Creek AQCS project. As a result, our net interest expense increased by $13.7 million, or 15.8%, as compared to 2008.

During 2010, we expect gross interest expense to increase due to increased debt levels to fund our planned construction activity. We expect our capitalized interest to increase slightly due to increased capital expenditures related to our Oak Creek AQCS project. As a result, we expect our net interest expense to increase in 2010.

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.

Income Taxes

2009 vs. 2008: Our effective income tax rate was 35.3% in 2009 compared with 37.6% in 2008. This reduction in our effective tax rate was primarily the result of tax credits associated with wind production. For further information regarding income taxes, see Note G — Income Taxes in the Notes to Consolidated Financial Statements. We expect our 2010 annual effective tax rate to range between 33.0% and 35.0%.

2008 vs. 2007: Our effective income tax rate was 37.6% in 2008 compared with 39.5% in 2007.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

The following table summarizes our cash flows during 2009, 2008 and 2007:

	2009			2008			2007
	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$	226.6		$	362.9		$	213.8
Investing Activities	($	333.6	)	($	212.7	)	$	236.2
Financing Activities	$	96.9		($	143.8	)	($	446.2	)

Operating Activities

2009 vs. 2008: Cash provided by operating activities was $226.6 million during 2009, which was $136.3 million lower than 2008. Although we experienced an increase in net income and depreciation during 2009, our operating cash flows declined because of large contributions to Wisconsin Energy’s pension and post-retirement benefit plans. During 2009, we contributed $283.8 million to Wisconsin Energy’s benefit plans compared to $37.9 million during 2008.

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.

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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 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. Our January 2009 contribution to Wisconsin Energy’s qualified pension plan resulted in a tax deduction for 2008.

Investing Activities

2009 vs. 2008: Cash used in investing activities was $333.6 million during 2009, which was $120.9 million higher than 2008. This increase primarily reflects a reduction in the release of restricted cash related to the Point Beach bill credits, partially offset by lower capital expenditures during 2009.

During 2009, we released $153.1 million less from restricted cash as compared to 2008. In September 2007, we sold Point Beach and placed approximately $924 million of cash 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 $194.5 million of restricted cash during 2010 as we issue bill credits to our retail customers from the Point Beach proceeds.

During 2009, our capital expenditures decreased by $42.6 million as compared to 2008, primarily due to the completion of our Blue Sky Green Field wind project in 2008. During 2010, we expect our capital expenditures to increase because of the continued construction of the Oak Creek AQCS project and the start of construction of our recently approved Glacier Hills wind farm project. See Rates and Regulatory Matters - Oak Creek Air Quality Control System Approval and - Renewable Energy Portfolio under Factors Affecting Results, Liquidity and Capital Resources for additional information on the projects.

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 related to the Point Beach bill credits. In addition, our capital expenditures increased by $42.7 million in 2008 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.

Financing Activities

The following table summarizes our cash flows from financing activities:

	2009			2008			2007
	(Millions of Dollars)
Dividends to Wisconsin Energy	($	179.6	)	($	367.0	)	($	179.6	)
Capital Contribution from Wisconsin Energy		100.0			—			—
Increase (Reduction) in Total Debt		176.2			225.3			(271.9	)
Other		0.3			(2.1	)		5.3
Cash Provided by (Used in) Financing	$	96.9		($	143.8	)	($	446.2	)

2009 vs. 2008: Cash provided by financing activities was $96.9 million during 2009 compared to $143.8 million used in financing activities during 2008. During 2009, we issued $250 million of debentures. The net proceeds were used to repay short-term debt and for other general corporate purposes. In addition, we repurchased $147 million of outstanding tax-exempt bonds in August 2009. For additional information on the debt issue and repurchase, see Note J — Long Term Debt in the Notes to Consolidated Financial Statements.

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.

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CAPITAL RESOURCES AND REQUIREMENTS

Capital Resources

We anticipate meeting our capital requirements during 2010 primarily through internally generated funds and short-term borrowings, supplemented as necessary by the issuance of intermediate or long-term debt securities, depending on market conditions and other factors, and an equity contribution from our parent. Beyond 2010, 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.

We 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.

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, 2009, we had approximately $474.0 million of available, undrawn lines under our bank back-up credit facility. As of December 31, 2009, we had approximately $92.0 million of commercial paper outstanding that was supported by the available lines 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, 2009:

Total Facility *	Letters of Credit		Credit Available *		Facility Expiration
	(Millions of Dollars)
$476.4	$	2.4	$	474.0	March 2011

* Excludes Lehman's commitment

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

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

Capitalization Structure	2009				2008
	(Millions of Dollars)
Common Equity	$	2,804.2	46.4	%	$	2,582.8	46.7	%
Preferred Stock		30.4	0.5	%		30.4	0.6	%
Long-Term Debt (a)		1,969.5	32.5	%		1,885.3	34.1	%
Capital Lease Obligations (a)		1,123.3	18.6	%		1,001.1	18.1	%
Short-Term Debt (b)		120.2	2.0	%		29.6	0.5	%
Total	$	6,047.6	100.0	%	$	5,529.2	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. For additional information, see Note J — Long-Term Debt in the Notes to Consolidated Financial Statements.

We recorded an increase of approximately $1.0 billion to our capital lease obligation in connection with OC 1 being placed into service on February 2, 2010. See Note T — Subsequent Events for additional information.

We are the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amount of $147 million. In August 2009, we terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We issued commercial paper to fund the purchase of the bonds. As of December 31, 2009, the repurchased bonds were still outstanding, but were reported as a reduction in our consolidated long-term debt because they are held by us.

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Depending on market conditions and other factors, we may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.

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, 2009:

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

In July 2009, S&P affirmed our ratings and revised our ratings outlook from positive to stable.

In June 2009, Fitch affirmed our ratings and revised our ratings outlook from stable to negative.

Our 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

Our estimated 2010, 2011 and 2012 capital expenditures are as follows:

Capital Expenditures	2010		2011		2012
	(Millions of Dollars)
Renewable	$	96.6	$	392.8	$	289.6
Environmental		301.7		170.6		69.2
Base Spending		337.6		371.6		379.1
Total	$	735.9	$	935.0	$	737.9

Changing environmental and other regulations such as air quality and renewable energy standards and electric reliability initiatives that impact us may cause actual future long-term capital requirements to vary from these estimates.

The anticipated 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 use outside trusts to fund our pension and certain other post-retirement obligations. These trusts had investments of approximately $923 million as of December 31, 2009. These trusts hold investments that are subject to the volatility of the stock market and interest rates.

In January 2009, we contributed approximately $265 million to Wisconsin Energy’s qualified pension plans due to poor investment returns during 2008. We do not expect to make contributions to the plans during 2010 as they are adequately funded. Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates. For additional information, see Note N — 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 additional information, see Note O — Guarantees in the Notes to Consolidated Financial Statements.

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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. The requested information required to make this determination has not been supplied. As a result, we do not consolidate these entities. 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. For additional information, see Note F — 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, 2009:

	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)	$	4,001.8	$	111.1	$	222.1	$	792.8	$	2,875.8
Capital Lease Obligations (c)		4,163.2		177.6		359.2		365.1		3,261.3
Operating Lease Obligations (d)		76.0		21.3		36.6		8.4		9.7
Purchase Obligations (e)		13,040.5		1,103.8		1,338.1		822.5		9,776.1
Other Long-Term Liabilities (f)		75.0		74.3		0.7		—		—
Total Contractual Obligations	$	21,356.5	$	1,488.1	$	1,956.7	$	1,988.8	$	15,922.9

(a) The amounts included in the table are calculated using current market prices, forward curves and other estimates.

(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. For information regarding the capital lease obligation for OC 1, which was placed into service on February 2, 2010, see Note T — Subsequent Events.

(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 our portion of the expected 2010 supplemental executive retirement plan obligation. For additional information on employer contributions to Wisconsin Energy’s benefit plans, see Note N — Benefits in the Notes to Consolidated Financial Statements.

The table above does not include liabilities related to the accounting treatment for uncertainty in income taxes. For additional information regarding these liabilities, refer to Note G — 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:

Regulatory Recovery: We account for our regulated operations in accordance with accounting guidance for regulated entities. Our rates are determined by regulatory authorities. Our primary regulator is the PSCW. Regulated entities are allowed 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

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impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. 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 2010) 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: 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.

In March 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. As part of the January 2010 PSCW rate order, the PSCW authorized continued use of the escrow method of accounting for bad debt costs through December 31, 2011.

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 and sales 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 and sales are unfavorably sensitive to above normal temperatures during the winter heating season. A summary of actual weather information in our service territory during 2009, 2008 and 2007, 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, 2009. 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, 2009 of our outstanding portfolio of commercial paper and variable rate long-term debt. As of December 31, 2009, we had $92.0 million of commercial paper outstanding with a weighted average interest rate of 0.19% and $147.0 million of variable-rate long-term debt outstanding with a weighted average interest rate of 0.50%. A one-percentage point change in interest rates would cause our annual interest expense to increase or decrease by approximately $0.9 million before taxes from commercial paper and by $1.5 million before taxes from variable rate long-term debt outstanding.

Marketable Securities Return: We use various trusts to fund our pension and OPEB obligations. These trusts invest in debt and equity securities. Changes in the market prices of these assets can affect future pension and OPEB expenses. Additionally, future contributions can also be affected by the investment returns on trust fund assets. We believe that the financial risks associated with investment returns would be partially mitigated through future rate actions by our various utility regulators.

The fair value of our trust fund assets as of December 31, 2009 was approximately:

	Millions of Dollars
Pension trust funds	$	793.7
Other post-retirement benefits trust funds	$	129.3

The expected long-term rate of return on plan assets was 8.25% for both the pension and other post-retirement benefits for 2009. During 2009, we contributed $265 million to Wisconsin Energy’s pension plans, which brought the plans close to fully funded under the Pension Protection Act. As a result, we changed our asset mix to a higher weighting of fixed income securities and a lower weighting of equity securities. In 2010, our expected long-term rate of return on the pension plan assets is 7.25% reflecting the

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change in asset allocations. The lower expected return on plan assets will increase 2010 pension costs by approximately $10 million; however, increased pension expense was considered in the rate setting process by the PSCW.

Fiduciary oversight of the pension and OPEB trust fund investments is the responsibility of an Investment Trust Policy Committee. The Committee works with external actuaries and investment consultants on an ongoing basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target asset allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. The targeted asset allocations are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments. Investment strategies utilize a wide diversification of asset types and qualified external investment managers.

Subsequent to its last asset/liability study completed in 2005, Wisconsin Energy has consulted with its investment advisors on an annual basis and requested them to forecast expected long-term returns on plan assets by reviewing actual historical returns and calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund.

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, 2009, we estimate that the collateral or the termination payment required under these agreements totaled approximately $191.0 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: Our service territory is within the state of Wisconsin and the Upper Peninsula of Michigan. We are exposed to market risks in the regional Midwest economy.

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 leasing of the PWGS and the Oak Creek expansion. We are leasing the PWGS units and OC 1 from We Power under long-term leases, and we will recover the lease payments in our electric rates. When OC 2 goes into service, we expect to also recover those 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 tables identify certain key items related to the units:

Unit Name	In Service	Cash Costs (a)
PWGS 1	July 2005	$	333 million
PWGS 2	May 2008	$	331 million
Unit Name	Scheduled In Service	Approximate Cash Costs (a)
OC 1	February 2010 (Actual)	$	1,346 million
OC 2	August 2010	$	670 million

(a) Cash costs represent actual and current projected costs, excluding capitalized interest. Approximate costs for OC 1 and OC 2 include the cost of the settlement agreement with Bechtel adjusted for Wisconsin Energy’s ownership percentage.

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.

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 was placed into service on February 2, 2010. Bechtel is currently targeting commercial operation of OC 2 by the end of August 2010. The total cost for the two units, including the common facilities, 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 also be included in lease payments and recovered from customers if the PSCW finds that such costs were prudently incurred and were the result of force majeure conditions, an excused event and/or an event of loss.

In June 2005, construction commenced at the site. In November 2005, Wisconsin Energy completed the sale of approximately a 17% interest in the two units to two unaffiliated entities who share ratably in the construction costs. Although these two unaffiliated entities have a combined ownership interest in approximately 17% of the MWs generated by the two units, they only have a 15% ownership interest in the Oak Creek expansion as a whole, taking into account the common facilities being constructed, including the coal handling and water intake systems.

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 $199.1 million.

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 $132.6 million.

Lease Terms: In October 2004, the PSCW approved the leased generation contracts between us and We Power for OC 1 and OC 2. 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: Bechtel, the contractor of the Oak Creek expansion under a fixed price contract, submitted claims to We Power for schedule and cost relief on December 22, 2008 related to the delay of the in-service dates for OC 1 and OC 2. These claims were asserted against ERS, the project manager for the construction of the Oak Creek expansion and agent for the joint owners of OC 1 and OC 2. On October 30, 2009, Bechtel amended its claim to increase its request for cost and schedule relief. In its amended claim, Bechtel requested cost relief totaling approximately $517.5 million and schedule relief that would have resulted in approximately seven months of relief from liquidated damages beyond the guaranteed in-service date of September 29, 2009 for OC 1 and approximately four months of relief from liquidated damages beyond the guaranteed in-service date of September 29, 2010 for OC 2.

Bechtel’s claims were based on the alleged impact of severe 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 Full Notice to Proceed in July 2005. These

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claims, as well as claims submitted by ERS related to the rights of the parties under the construction contract and ERS counterclaims, had been submitted to binding arbitration.

Effective December 16, 2009, ERS and Bechtel entered into the Settlement Agreement that settled all claims between them regarding OC 1 and OC 2. Pursuant to the terms of this Settlement Agreement, ERS will pay to Bechtel $72 million to settle these claims, with $10 million already paid in 2009 and the remaining $62 million to be paid in six additional installments upon the achievement of specific project milestones. In addition, Bechtel will receive 120 days of schedule relief for OC 1 and 60 days for OC 2. Therefore, the guaranteed in-service date of September 29, 2009 for OC 1 was extended to January 27, 2010, and the guaranteed in-service date of September 29, 2010 for OC 2 was extended to November 28, 2010.

We Power is responsible for approximately 85% of amounts paid under the Settlement Agreement, consistent with its ownership share of the Oak Creek expansion. The other joint owners are responsible for the remainder.

OC 1 was placed into service on February 2, 2010. Bechtel is currently targeting commercial operation of OC 2 by the end of August 2010.

The Settlement Agreement also provides for Bechtel’s release of ERS from all matters related to Bechtel’s claims, among other things, and for ERS’ release of Bechtel from all matters related to ERS’ claims that were subject to arbitration, among other things.

WPDES Permit: In July 2008, in order to resolve all outstanding challenges to the WPDES permit issued by the WDNR in connection with the Oak Creek expansion, 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 issued in July 2008 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% by 2013 and 25% by 2025, and to retire 116 MW of coal-fired generation at our Presque Isle Power Plant.

In its December 2009 decision, based upon a proposal submitted by the parties to the settlement agreement, the PSCW authorized recovery of $2.0 million per year for 2010 and 2011 related to costs associated with projects to address Lake Michigan water quality and recovery of $2.0 million of the second $2.5 million payment related to projects to reduce greenhouse gas emissions. Based upon this decision, the parties are proceeding to implement the settlement agreement. We are responsible for our pro rata share of these payments.

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 89% 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/.

2010 Wisconsin Rate Case: In March 2009, we initiated rate proceedings with the PSCW. We initially asked the PSCW to approve a rate increase for our Wisconsin retail electric customers of approximately $76.5 million, or 2.8%, and a rate increase for our natural gas customers of approximately $22.1 million, or 3.6%. In addition, we requested increases of approximately $1.4 million, or 5.8%, and approximately $1.3 million, or 6.8%, for our Valley steam utility customers and Milwaukee County steam utility customers, respectively.

In July 2009, we filed supplemental testimony with the PSCW updating our rate increase request for retail electric customers to reflect the impact of lower sales as a result of the decline in the economy. The effect of the change resulted in us increasing our request from $76.5 million to $126.0 million.

In December 2009, the PSCW authorized rate adjustments related to our request to increase electric, natural gas and steam rates. The PSCW approved the following rate adjustments:

• An increase of approximately $85.8 million (3.35%) in our retail electric rates;

• A decrease of approximately $2.0 million (0.35%) for natural gas service; and

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• A decrease of approximately $0.4 million (1.65%) for our Downtown Milwaukee (Valley) steam utility customers and a decrease of approximately $0.1 million (0.47%) for our Milwaukee County steam utility customers.

These rate adjustments became effective January 1, 2010. In addition, the PSCW lowered our return on equity from 10.75% to 10.4%.

The PSCW also made, among others, the following determinations:

• New depreciation rates are incorporated into the new base rates approved in the rate case;

• Certain regulatory assets currently scheduled to be fully amortized over the next four years are to instead be amortized over the next eight years; and

• We will continue to receive AFUDC on 100% of CWIP for the environmental control projects at our Oak Creek Power Plant and at Edgewater Generating Unit 5, and on the Glacier Hills Wind Park.

2010 Michigan Rate Increase Request: In July 2009, we filed a $42 million rate increase request with the MPSC, primarily to recover the costs of PTF projects. Michigan law allows utilities, upon the satisfaction of certain conditions, to self-implement a rate increase request, subject to refund with interest. In December 2009, the MPSC approved our modified self-implementation plan to increase electric rates in Michigan by approximately $12 million (9.5%), effective upon commercial operation of OC 1, which occurred on February 2, 2010. This rate increase is subject to refund with interest, depending upon the MPSC’s final decision on our rate request, which is expected in July 2010.

2008 Wisconsin Rate Increase: During 2007, we initiated rate proceedings. On January 17, 2008, the PSCW approved pricing increases for us as follows:

• $389.1 million (17.2%) in electric rates - the pricing increase was offset by bill credits in 2008 and 2009;

• $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.

2008 Michigan Rate Increase: In January 2008, we filed a rate increase request with the MPSC. This request represented an increase in electric rates of 14.7%, or $22.0 million, to support the growing demand for electricity at that time, 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.

Limited Rate Adjustment Requests

2010 Fuel Recovery Request: On February 19, 2010, we filed a $60.5 million rate increase request with the PSCW to recover forecasted increases in fuel and purchased power costs. The increase in fuel and purchased power costs is being driven primarily by increases in the price of natural gas, changes in the timing of plant outages and increased MISO costs. We expect to implement this rate request by the end of the first quarter of 2010, subject to refund based upon the PSCW’s final decision. The ultimate rate increase will be subject to the review and approval of the PSCW, which we expect to receive by the end of 2010.

2009 Fuel Cost Decrease Filing: We operate under a fuel cost adjustment clause for fuel and purchased power costs associated with the generation and delivery of electricity to our retail customers in Wisconsin. In April 2009, based on three months of actual fuel cost data and nine months of projected data, we forecasted that our monitored fuel cost for 2009 would fall outside the range prescribed by the PSCW and would be less than the monitored fuel cost reflected in then authorized rates. Therefore, in April 2009, we filed a request with the PSCW to decrease annual Wisconsin retail electric rates by $67.2 million for calendar year 2009. On April 30, 2009, the PSCW approved the fuel cost decrease filing with rates effective May 1, 2009.

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%. In April 2009, the PSCW ordered that we should refund $8.8 million (including interest) of over-collected fuel surcharge revenue. The refund was issued during the second quarter of 2009.

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Other Rate Matters

Oak Creek Air Quality Control System Approval: 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 currently expect the cost of completing this project to be approximately $800 million ($950 million including AFUDC). The cost of constructing these facilities is included in our estimates of the costs to implement the Consent Decree with the EPA.

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 12-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). 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. Currently, draft legislation is under review. The earliest that we expect any possible action on the fuel rules is mid-2010.

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 deferred transmission costs that exceeded amounts embedded in our rates. We were allowed to earn a return on the unrecovered transmission costs we deferred at our weighted average cost of capital. As of December 31, 2009, we had deferred $157.8 million of unrecovered transmission costs. The escrow accounting treatment has been discontinued as our 2008 and 2010 PSCW rate orders have provided for recovery of these costs.

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. Prior to 2010, there was an incentive mechanism under the GCRM that allowed for increased revenues if we acquired gas at prices lower than benchmarks approved by the PSCW. However, as part of the January 2010 PSCW rate order, the PSCW approved changing from an incentive method to a modified one for one method. The new method does not have revenue sharing. The GCRM measures commodity purchase costs against a monthly benchmark which includes a 2% tolerance. Costs in excess of this monthly benchmark are subject to additional review by the PSCW before they can be passed through to our customers. The modified one for one is the same method used by most other utilities in Wisconsin.

Bad Debt Costs: 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 exceeds amounts allowed in rates. As part of the January 2010 PSCW rate order, the escrow accounting method for bad debt costs was extended through December 31, 2011.

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.

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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: In January 2009, we filed a depreciation study with the PSCW proposing new depreciation rates that would reduce annual depreciation expense by approximately $41 million. The PSCW approved the depreciation study and the new depreciation rates began on January 1, 2010. We do not expect the new depreciation rates to have a material impact on earnings because the new depreciation rates were considered when the PSCW set our 2010 electric and gas rates.

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%. Under Act 141, we could not decrease our renewable energy percentage for the years 2006-2009, 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 Renewable Energy Portfolio discussion below.

In 2007, the Governor of Wisconsin established the Governor’s Task Force on Global Warming. The Task Force issued its final report in July 2008 that included 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. Draft legislation regarding this recommendation, as well as other recommendations made by the Task Force, is pending in the Wisconsin legislature.

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. 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 the energy efficiency goal be based on achieving efficiency resulting in a 2% reduction in electric load annually starting in 2015 rather than a goal based on a percent of revenue.

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.

Renewable Energy Portfolio: In May 2008, the Blue Sky Green Field wind farm project, which has 88 turbines with an installed capacity of 145 MW, reached commercial operation. In July 2008, we completed the purchase of rights to a new wind farm site in Central Wisconsin, Glacier Hills Wind Park, and filed a request for a CPCN with the PSCW in October 2008. We entered into a conditional turbine agreement for the new wind facility and filed a revised, lower cost estimate with the PSCW in May 2009 of $335.2 million to $413.5 million, excluding AFUDC. The PSCW approved the CPCN in January 2010. We currently expect to install up to 90 wind turbines with generating capacity of up to approximately 207 MW, subject to turbine selection and the final site configuration. We expect 2012 to be the first full year of operation.

In September 2009, we announced plans to construct a biomass-fueled power plant at Domtar Corporation’s Rothschild, Wisconsin paper mill site. Wood, waste and sawdust will be used to produce approximately 50 MW of electricity and will also support Domtar’s sustainable papermaking operations. We believe the biomass plant will be eligible for either the federal production tax credit or the federal 30% investment tax credit. We currently expect the plant to cost approximately $250 million and to be completed during the

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fall of 2013, subject to regulatory approvals. We expect to file a request for a Certificate of Authority for the project in the first quarter of 2010.

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.

We had adequate capacity to meet all of our firm electric load obligations during 2009 and 2008. 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 2010. However, extremely hot weather, unexpected equipment failure or unavailability could require us to call upon load management procedures.

ENVIRONMENTAL MATTERS

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

We are currently pursuing a proactive strategy to manage our environmental compliance obligations, 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) implementing a Consent Decree 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 cost of implementing the EPA Consent Decree is estimated to be approximately $1.2 billion over the 10 year period 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 $800 million, excluding AFUDC. Through December 31, 2009, we have spent approximately $686 million associated with the installation of air quality controls and have retired four coal units as part of our plan under the Consent Decree. For further information concerning the Consent Decree, see Note R — Commitments and Contingencies in the Notes to Consolidated Financial Statements in this report.

Air Quality

8-hour Ozone Standard: In April 2004, the EPA designated 10 counties in southeastern Wisconsin as non-attainment areas for the 8-hour ozone ambient air quality standard. 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 ambient air quality standard. Instead of submitting a SIP, Wisconsin submitted a request to redesignate all counties in southeastern Wisconsin as 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. Compliance with the NO_x emission reduction requirements under the Consent Decree has substantially mitigated 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. In July 2009, Wisconsin issued both a draft Attainment Demonstration and a Redesignation request. Based on our review of these drafts, we do not believe we would be subject to any further requirements to reduce emissions. The EPA must take final approval action once Wisconsin finalizes its submittals.

In March 2008, the EPA announced its decision to further lower the 8-hour ozone standard, and in January 2010, the EPA proposed to lower that standard further. Given this most recent revision, the EPA has delayed the deadline for new non-attainment area

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designations under the revised standard once it is finalized, from March 2010 to March 2011. Although it is likely that 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.

Fine Particulate Standard: In December 2004, the EPA designated fine particulate (PM_2.5) non-attainment areas. 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. In October 2009, the EPA designated three counties in southeast Wisconsin (Milwaukee, Waukesha and Racine) as not meeting the 2006 daily standard for PM_2.5. Wisconsin will now have three years to develop a SIP and submit it to the EPA for approval, and will need to implement actions to reach attainment in the 2014-2019 time period. The impact of future SIP requirements cannot be determined at this time. Similarly, until the EPA revises the 2006 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 that 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, PWGS 1 and PWGS 2.

In a related matter, on February 11, 2010, the EPA announced its intent to end the transitional policy which has allowed facilities to use in their air permits PM₁₀ (an earlier measure of particulate matter) as a surrogate when measuring PM_2.5 emissions. This policy had allowed both the agencies and permit holders to continue to use standards that were well established, until the EPA and the states developed the necessary tools for permitting PM_2.5 emissions. The discontinuation of this policy creates uncertainty as to how this parameter will be evaluated when we seek and maintain Title V air permits for our facilities. The EPA will be taking written comments on the rule, and until the rule is finalized, we are not able to predict the impact of this policy change on our operations.

Sulfur Dioxide Standard: The EPA is currently in the process of revising the ambient air quality standard for SO₂. In November 2009, the EPA proposed to strengthen the primary standard for SO₂ by revoking the current standards and replacing them with a more stringent one-hour SO₂ standard. If the revised standard ultimately selected results in the designation of new non-attainment areas, it could potentially have an adverse effect on our facilities in those areas.

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 required NO_x and SO₂ emission reductions in two phases from electric generating units located in a 28-state region within the eastern United States, including Wisconsin and Michigan. 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. In 2008, the U.S. Court of Appeals for the D.C. Circuit invalidated several aspects of CAIR and remanded the rule to the EPA to promulgate a replacement rule. We previously determined that compliance with the NO_x and SO₂ emission reduction requirements under the Consent Decree would substantially mitigate costs to comply with CAIR and would 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.

Mercury and Other Hazardous Air Pollutants: The EPA issued the final CAMR in March 2005, addressing mercury emissions from new and existing coal-fired power plants. 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 reconsideration.

In December 2008, a number of environmental groups filed a complaint with the D.C. Circuit asking that the court place the EPA on a schedule for promulgating MACT limits for fossil-fuel fired electric utilities to address hazardous air pollutants, including mercury. In October 2009, the EPA published notice of a proposed consent decree in connection with this litigation that would place the EPA on a schedule to set a MACT rule for coal and oil-fired electric generating units in 2011. The EPA is currently in the process of developing the proposed MACT rule, which is expected to reduce emissions of numerous hazardous air pollutants, including mercury.

Wisconsin and Michigan State Only Mercury Rules: Both Wisconsin and Michigan now have mercury rules in place. Both states require a 90% reduction of mercury. We have plans in place to comply with these requirements and the costs of these plans are incorporated into our capital and operation and maintenance costs.

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 the EPA’s CAIR. The pollutants from power plants that reduce visibility include PM_2.5 or compounds that contribute to fine particulate formation, NO_x, SO₂ and ammonia. States were required to submit SIPs to implement CAVR by December 2007. Wisconsin has not yet submitted a SIP. Michigan submitted a SIP, which was partially approved. In response to a citizen suit, in January 2009, the EPA issued a finding of failure to 37 states, including Wisconsin and Michigan,

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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.

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.

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 pursuant to a ruling by the U.S. Court of Appeals for the D.C. Circuit requiring it to do so.

EPA Consent Decree: In April 2003, we reached a Consent Decree with the EPA in which we agreed to significantly reduce air emissions from certain of our coal-fired generating facilities. 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 R — Commitments and Contingencies in the Notes to Consolidated Financial Statements.

Climate Change: 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.

• Adding 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 President and his administration have made it clear that they are focused on reducing CO₂ emissions, through legislation and/or regulation. 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.

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. In September 2004, the EPA adopted rules for existing facilities to minimize the potential adverse 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 found certain portions of the rule impermissible, including portions that permitted approval of water intake system technologies based on a cost-benefit analysis, and remanded several parts of the rule to the EPA for further consideration or potential additional rulemaking. In April 2009, the United States Supreme Court reversed the Second Circuit regarding the use of cost-benefit analysis and held that it was permissible for the EPA to rely on cost-benefit analysis in setting national performance standards and in providing variances from those standards. The Supreme Court remanded the case for further proceedings consistent with its opinion.

Until the EPA completes its reconsideration and rulemaking, we cannot predict what impact these changes may have on our facilities. The decision will not affect the new units at the Oak Creek expansion because those units were permitted based on a BTA decision under the Phase I rule for new facilities.

In addition, in December 2009, the EPA published its determination that revision of the current effluent guidelines for steam electric generating units was warranted, and proposed a rulemaking process to adopt such revisions by 2013. Revisions to the current effluent guidelines are expected to result in more stringent standards that may result in the installation of additional controls. Until the EPA completes its rulemaking process, however, we cannot predict what impact these new standards may have on our facilities.

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Other Environmental Matters

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 R — 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 R — Commitments and Contingencies in the Notes to Consolidated Financial Statements.

LEGAL MATTERS

Cash Balance Pension Plan: On June 30, 2009, a lawsuit was filed by a former employee against the Plan in the U.S. District Court for the Eastern District of Wisconsin. Counsel representing the plaintiff is attempting to seek class certification for other similarly situated plaintiffs. The complaint alleges that Plan participants who received a lump sum distribution under the Plan prior to their normal retirement age did not receive the full benefit to which they were entitled in violation of ERISA and are owed additional benefits, because the Plan failed to apply the correct interest crediting rate to project the cash balance account to their normal retirement age. We believe the Plan correctly calculated the lump-sum distributions. An adverse outcome of this lawsuit could affect Plan funding and expense. We are currently unable to predict the final outcome or impact of this litigation.

Settlement with the Mines: In May 2007, we entered into a settlement agreement with our largest customers, two iron ore mines, related to an arbitration proceeding over disputed billings arising from the special negotiated contracts the mines operated under until they expired in December 2007. 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 we were holding in escrow. 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 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 is not expected to have a material adverse effect on our financial statements. In June 2007, another stray voltage lawsuit 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. In September 2007, we sold Point Beach to an affiliate of FPL for approximately $924 million. For additional information on this sale, see Corporate Strategy at the beginning of Management’s Discussion and Analysis of Financial Condition and Results of Operations. 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 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

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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. In December 2009, the Court ruled in our favor, granting us more than $50 million in damages. We anticipate that the DOE will appeal this decision and that any recoveries will be included in future rate cases.

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, among other things, amended federal energy laws and provided FERC with new oversight responsibilities.

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 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 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.

Electric Transmission and Energy Markets

In connection with its status as a FERC approved RTO, MISO developed bid-based energy markets, which were implemented on April 1, 2005. In January 2009, MISO commenced the Energy and Operating Reserves Markets, which includes the bid-based energy markets and a relatively new ancillary services market. 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

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ancillary services market has been able to reduce overall ancillary services costs in the MISO footprint. The MISO ancillary services market has enabled MISO to assume significant balancing area responsibilities such as frequency control and disturbance control.

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 the use of the current transmission cost allocation methodology. In October 2009, FERC issued an order related to the allocation of costs for network transmission upgrades. As a condition of this order, MISO is expected to submit a filing by July 15, 2010 to replace the current cost allocation methodology.

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. In July 2007, MISO commenced with the resettlement of the market in response to the orders. 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 ordered 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. Although MISO requested a postponement of the resettlements until the matter is resolved, the resettlement commenced in March 2009.

In May 2009, FERC issued an order denying rehearing on substantive matters for the rate period beginning August 10, 2007. However, FERC modified the effective date of that rate to November 10, 2008, and ordered MISO to cease the ongoing resettlement and to reconcile all invoices and payments therein. Similarly, in June 2009, FERC dismissed rehearing requests, but waived refunds for the period April 25, 2006 through November 4, 2007. FERC also stated for the first time that it was waiving refunds for the period April 1, 2005 through April 24, 2006. We, along with others, have sought rehearing and/or appeal of the FERC’s May and June 2009 determinations pertaining to refunds. In addition, there are contested compliance matters pending FERC review. The net effects of FERC’s rulings are uncertain at this time.

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, 2009 through May 31, 2010. The resulting ARR valuation and the secured FTRs should adequately mitigate our transmission congestion risk for that period.

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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International Financial Reporting Standards: During 2009, the SEC announced a “roadmap” for U.S. registrants that, if adopted, would require U.S. companies to follow IFRS instead of GAAP. The SEC guidelines, in their current form, would require us to adopt IFRS in 2014.

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. 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, 2009, we had $1,063.1 million in regulatory assets and $812.1 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 regulatory accounting. In this situation, continued deferral of certain regulatory asset and liability amounts on our books, as allowed under regulatory accounting, 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 regulatory accounting and have determined that it is currently appropriate to continue following it. 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 N — 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.

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	$	4.2
0.5% decrease in expected rate of return on plan assets	$	4.4

In addition to pension plans, we maintain OPEB plans which provide health and life insurance benefits for retired employees (described in Note N — Benefits in the Notes to Consolidated Financial Statements). 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

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costs in future periods. Similar to accounting for pension plans, our regulators have adopted accounting guidance for compensation related to retirement benefits for rate-making purposes.

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	$	2.3
0.5% decrease in health care cost trend rate in all future years		($2.7	)
0.5% decrease in expected rate of return on plan assets	$	0.6

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 2009 of approximately $3.3 billion included accrued revenues of $212.8 million as of December 31, 2009.

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WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED INCOME STATEMENTS

Year Ended December 31

	2009		2008		2007
	(Millions of Dollars)
Operating Revenues	$	3,288.3	$	3,410.1	$	3,321.6
Operating Expenses
Fuel and purchased power		1,064.5		1,242.3		992.1
Cost of gas sold		389.7		526.4		441.9
Other operation and maintenance		1,231.7		1,295.2		1,041.9
Depreciation, decommissioning and amortization		265.1		256.0		269.7
Property and revenue taxes		99.1		96.4		91.7
Total Operating Expenses		3,050.1		3,416.3		2,837.3
Amortization of Gain		230.7		488.1		6.5
Operating Income		468.9		481.9		490.8
Equity in Earnings of Transmission Affiliate		51.9		45.4		37.9
Other Income and Deductions, net		25.8		9.9		41.7
Interest Expense, net		100.3		86.6		93.0
Income Before Income Taxes		446.3		450.6		477.4
Income Taxes		157.7		169.3		188.5
Net Income		288.6		281.3		288.9
Preferred Stock Dividend Requirement		1.2		1.2		1.2
Earnings Available for Common Stockholder	$	287.4	$	280.1	$	287.7

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

	2009			2008
	(Millions of Dollars)
Property, Plant and Equipment
Electric	$	6,477.5		$	6,348.3
Gas		850.0			830.3
Steam		89.9			83.6
Common		239.1			236.5
Other		61.5			61.6
		7,718.0			7,560.3
Accumulated depreciation		(2,822.6	)		(2,721.2	)
		4,895.4			4,839.1
Construction work in progress		382.6			188.4
Leased facilities, net		959.6			870.2
Net Property, Plant and Equipment		6,237.6			5,897.7
Investments
Restricted cash		—			172.4
Equity investment in transmission affiliate		276.7			243.1
Other		0.5			0.4
Total Investments		277.2			415.9
Current Assets
Cash and cash equivalents		18.3			28.4
Restricted cash		194.5			214.1
Accounts receivable, net of allowance for doubtful accounts of $31.5 and $27.2		218.3			213.4
Accounts receivable from related parties		27.5			64.7
Accrued revenues		212.8			233.1
Materials, supplies and inventories		321.5			296.5
Prepayments		122.2			122.3
Regulatory assets		48.5			69.9
Other		25.5			69.1
Total Current Assets		1,189.1			1,311.5
Deferred Charges and Other Assets
Regulatory assets		1,014.6			992.9
Other		152.7			157.4
Total Deferred Charges and Other Assets		1,167.3			1,150.3
Total Assets	$	8,871.2		$	8,775.4

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

	2009		2008
	(Millions of Dollars)
Capitalization
Common equity	$	2,804.2	$	2,582.8
Preferred stock		30.4		30.4
Long-term debt		1,969.5		1,885.3
Capital lease obligations		1,111.3		991.8
Total Capitalization		5,915.4		5,490.3
Current Liabilities
Long-term debt and capital lease obligations due currently		12.0		9.3
Short-term debt		92.0		—
Subsidiary note payable to Wisconsin Energy		28.2		29.6
Accounts payable		207.0		289.2
Accounts payable to related parties		79.9		76.2
Payroll and vacation accrued		64.9		65.4
Accrued taxes		50.5		9.6
Accrued interest		13.8		13.3
Regulatory liabilities		220.8		307.7
Other		100.3		124.0
Total Current Liabilities		869.4		924.3
Deferred Credits and Other Liabilities
Regulatory liabilities		591.3		786.5
Deferred income taxes - long-term		833.8		691.7
Accumulated deferred investment tax credits		35.6		39.1
Asset retirement obligations		52.6		52.3
Pension and other benefit obligations		374.2		614.3
Other		198.9		176.9
Total Deferred Credits and Other Liabilities		2,086.4		2,360.8
Commitments and Contingencies (Note R)
Total Capitalization and Liabilities	$	8,871.2	$	8,775.4

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

	2009			2008			2007
	(Millions of Dollars)
Operating Activities
Net income	$	288.6		$	281.3		$	288.9
Reconciliation to cash
Depreciation, decommissioning and amortization		272.5			263.4			279.3
Amortization of gain		(230.7	)		(488.1	)		(6.5	)
Equity in earnings of transmission affiliate		(51.9	)		(45.4	)		(37.9	)
Distributions from transmission affiliate		40.9			34.2			29.2
Deferred income taxes and investment tax credits, net		132.3			264.6			8.9
Contributions to benefit plans		(283.8	)		(37.9	)		(23.2	)
Change in - Accounts receivable and accrued revenues		51.2			(5.3	)		8.3
Inventories		(25.0	)		(10.9	)		2.8
Other current assets		19.6			(44.9	)		(2.9	)
Accounts payable		(64.4	)		45.2			19.7
Accrued income taxes, net		51.1			(61.5	)		(154.7	)
Deferred costs, net		46.2			81.5			(56.3	)
Other current liabilities		4.9			9.6			(8.9	)
Other, net		(24.9	)		77.1			(132.9	)
Cash Provided by Operating Activities		226.6			362.9			213.8
Investing Activities
Capital expenditures		(481.1	)		(523.7	)		(481.0	)
Investment in transmission affiliate		(22.7	)		(22.2	)		—
Proceeds from asset sales, net		1.8			7.1			938.8
Proceeds from liquidation of nuclear decommissioning trust		—			—			552.4
Change in restricted cash		192.0			345.1			(731.6	)
Proceeds from investments within nuclear decommissioning trust		—			—			1,528.7
Other activity within nuclear decommissioning trust		—			—			(1,528.7	)
Other, net		(23.6	)		(19.0	)		(42.4	)
Cash (Used in) Provided by Investing Activities		(333.6	)		(212.7	)		236.2
Financing Activities
Dividends paid on common stock		(179.6	)		(367.0	)		(179.6	)
Dividends paid on preferred stock		(1.2	)		(1.2	)		(1.2	)
Issuance of long-term debt		250.0			697.0			23.4
Retirement and repurchase of long-term debt		(164.4	)		(147.0	)		(345.4	)
Change in total short-term debt		90.6			(324.7	)		50.1
Capital contribution from parent		100.0			—			—
Other, net		1.5			(0.9	)		6.5
Cash Provided by (Used in) Financing Activities		96.9			(143.8	)		(446.2	)
Change in Cash and Cash Equivalents		(10.1	)		6.4			3.8
Cash and Cash Equivalents at Beginning of Year		28.4			22.0			18.2
Cash and Cash Equivalents at End of Year	$	18.3		$	28.4		$	22.0

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

	2009			2008
	(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		802.4			688.8
Retained earnings		1,668.9			1,561.1
Total Common Equity		2,804.2			2,582.8
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			300.0
6.25% due 2015		250.0			250.0
4.25% due 2019		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			0.1
4.81% effective rate due 2030		2.0			2.0
Notes (unsecured)                           1.92% variable rate due 2015 (a)		—			17.4
0.504% variable rate due 2016 (b)		67.0			67.0
0.504% variable rate due 2030 (b)		80.0			80.0
Variable rate notes held by us (see Note J)		(147.0	)		—
Unamortized discount, net		(17.6	)		(16.2	)
Total Long-Term Debt		1,969.5			1,885.3
Obligations Under Capital Leases (see Note J)		1,111.3			991.8
Total Capitalization	$	5,915.4		$	5,490.3

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

(b) Variable interest rate as of December 31, 2009.

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			Total
	(Millions of Dollars)
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
Net income						288.6			288.6
Other comprehensive income						—			—
Comprehensive Income		—		—		288.6			288.6
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				9.9					9.9
Tax benefit of exercised stock options allocated from Parent				3.7					3.7
Balance - December 31, 2009	$	332.9	$	802.4	$	1,668.9		$	2,804.2

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 metropolitan Milwaukee, Wisconsin. We consolidate our wholly-owned subsidiary, Bostco. Bostco had total assets of $35.9 million as of December 31, 2009.

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.

Subsequent Events: We have evaluated and determined that no material events took place after our balance sheet date of December 31, 2009 through our financial statement issuance date of February 26, 2010, except as disclosed in Note T.

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 purchased 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: 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	2009			2008			2007
	(Millions of Dollars)
Carrying Costs	$	—		$	0.8		$	28.8
Gain on Property Sales		1.7			2.3			12.9
AFUDC - Equity		15.9			7.5			5.1
Donations and Contributions		(5.5	)		(12.0	)		(10.3	)
Other, net		13.7			11.3			5.2
Total Other Income and Deductions, net	$	25.8		$	9.9		$	41.7

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 2009 and 2008, and 3.7% in 2007.

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

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have spent in removal activities. This regulatory liability was $497.5 million as of December 31, 2009 and $472.5 million as of December 31, 2008.

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 2009 and 2008, we accrued AFUDC at a rate of 9.09% as authorized by the PSCW. Consistent with the PSCW’s 2008 rate order, we accrued AFUDC on 50% of all utility CWIP projects except our Oak Creek AQCS project, which accrued AFUDC on 100% of CWIP. Our rates are set to provide a current return on CWIP that does not accrue AFUDC. During 2007, we accrued AFUDC at a rate of 8.94%, as authorized by the PSCW in a prior rate order.

Based on the 2010 PSCW rate order, effective January 1, 2010, we are recording AFUDC on 100% of CWIP associated with the Oak Creek AQCS project, the Edgewater Unit 5 Selective Catalytic Reduction project, and the Glacier Hills Wind Park. We will record AFUDC on 50% of all other electric, gas and steam utility CWIP. Our AFUDC rate starting January 1, 2010 is 8.83%.

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

	2009		2008		2007
	(Millions of Dollars)
AFUDC - Debt	$	6.6	$	3.0	$	1.8
AFUDC - Equity	$	15.9	$	7.5	$	5.1

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

Materials, Supplies and Inventories	2009		2008
	(Millions of Dollars)
Fossil Fuel	$	181.0	$	132.2
Materials and Supplies		99.3		93.1
Natural Gas in Storage		41.2		71.2
Total	$	321.5	$	296.5

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

Regulatory Accounting: 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 regulatory assets pursuant to specific orders or by a generic order issued by our regulators. 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.

Asset Retirement Obligations: 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 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 regulatory accounting guidance 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. For further information, see Note E.

Derivative Financial Instruments: We have derivative physical and financial instruments which we report at fair value. For further information, see Note L.

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

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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. As of December 31, 2009, all restricted cash is classified as current.

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 I.

Investments: We account for investments in other affiliated companies in which we do not maintain control using the equity method. As of December 31, 2009 and 2008, we had a total ownership interest of approximately 23.0% 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 Q.

Income Taxes: We follow the liability method in accounting for income taxes. Accounting guidance for income taxes 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 G.

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.

Wisconsin Energy estimates the fair value of stock options using the binomial pricing model. 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 10 years from the grant date. Excess tax benefits are reported as a financing cash inflow. In addition, Wisconsin Energy reports 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 a discussion of the impacts to our Consolidated Financial Statements, see Note I.

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

	2009	2008	2007
Risk-free interest rate	0.3% - 2.5%	2.9% - 3.9%	4.7% - 5.1%
Dividend yield	3.0%	2.1%	2.2%
Expected volatility	25.9%	20.0%	13.0% - 20.0%
Expected life (years)	6.2	6.2	6.0
Expected forfeiture rate	2.0%	2.0%	2.0%
Pro forma weighted average fair value of stock options granted	$8.01	$9.39	$8.72

B – RECENT ACCOUNTING PRONOUNCEMENTS

Fair Value Measurements: In September 2006, the FASB issued new accounting guidance relating to fair value measurements and also issued updated accounting guidance in 2008 and 2009. This guidance defines fair value, provides guidance for using fair value to measure assets and liabilities as well as a framework for measuring fair value, expands disclosures related to fair value measurements

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and was effective for financial statements issued for fiscal years beginning after November 15, 2007. This adoption did not have a significant financial impact on our financial condition, results of operations or cash flows. See Note M — Fair Value Measurements for required disclosures.

Noncontrolling Interests in Consolidated Financial Statements: In December 2008, the FASB issued new accounting guidance relating to noncontrolling interests in consolidated financial statements. This guidance clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements and was effective for fiscal years beginning on or after December 15, 2008. We adopted these provisions effective January 1, 2009. This adoption did not have a material financial impact on our financial condition, results of operations or cash flows.

Disclosures about Derivative Instruments and Hedging Activities: In March 2008, the FASB issued new accounting guidance relating to derivative instruments and hedging activities. This guidance 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, and was effective for fiscal years beginning after November 15, 2008. We adopted these provisions effective January 1, 2009. This adoption did not have any financial impact on our financial condition, results of operations or cash flows. See Note L — Derivative Instruments for required disclosures.

Subsequent Events: In May 2009, the FASB issued new accounting guidance relating to management’s assessment of subsequent events. This guidance clarifies that management must evaluate, as of each reporting period, events or transactions that occur after the balance sheet date through the date the financial statements are issued or are available to be issued, and was effective for interim and annual periods ending after June 15, 2009. We adopted these provisions effective June 30, 2009. This adoption had no financial impact on our financial condition, results of operations or cash flows.

Recognition and Presentation of Other-Than-Temporary Impairments: In April 2009, the FASB issued new accounting guidance that amended the other-than-temporary impairment guidance for debt securities to be more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in financial statements. We adopted these provisions effective June 30, 2009. This adoption had no financial impact on our financial condition, results of operations or cash flows.

Amendments to Variable Interest Entity Consolidation Guidance: In June 2009, the FASB issued new accounting guidance related to variable interest entity consolidation. The purpose of this guidance is to improve financial reporting by enterprises with variable interest entities. The new guidance is effective for all new and existing variable interest entities for fiscal years beginning after November 15, 2009. We adopted these provisions on January 1, 2010. This adoption is not expected to have any impact on our financial condition, results of operations or cash flows.

Employers’ Disclosures about Post-retirement Benefit Plan Assets: In December 2008, the FASB issued new accounting guidance for employers’ disclosures about plan assets of defined benefit pension or other post-retirement plans. This new guidance resulted in expanded disclosures related to post-retirement benefit plan assets and was effective for fiscal years ending after December 15, 2009. We adopted these provisions on December 31, 2009. This adoption had no impact on our financial condition, results of operations or cash flows. See Note N — Benefits for required disclosures.

C – REGULATORY ASSETS AND LIABILITIES

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 regulators. These deferred costs will be considered in future rate setting proceedings. As of December 31, 2009 and 2008, we had approximately $12.4 million and $20.0 million, respectively, of net regulatory assets that were not earning a return.

In December 2009, the PSCW issued a rate order effective January 1, 2010 that, among other things, reaffirmed our accounting for the regulatory assets and liabilities identified below. The rate order provided for the recovery over an eight year period of specific regulatory assets, the largest of which is the balance of the remaining deferred transmission costs. The order also specified that the deferred Point Beach gain would be passed on to customers as authorized in the prior rate case such that the final credits should essentially be issued by the end of 2010.

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

	2009		2008
	(Millions of Dollars)
Regulatory Assets
Deferred unrecognized pension costs	$	378.6	$	392.0
Deferred plant related — capital leases		163.7		130.9
Escrowed electric transmission costs		157.8		199.0
Deferred unrecognized OPEB costs		77.9		48.7
Deferred income tax related		75.5		70.1
Deferred derivative amounts		11.6		57.0
Other, net		198.0		165.1
Total regulatory assets	$	1,063.1	$	1,062.8
Regulatory Liabilities
Deferred cost of removal obligations	$	497.5	$	472.5
Deferred Point Beach related		202.4		431.5
Deferred income tax related		49.7		83.8
Other, net		62.5		106.4
Total regulatory liabilities	$	812.1	$	1,094.2

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, 2009, we have recorded $44.8 million of environmental costs associated with manufactured gas plant sites as a regulatory asset, including $9.3 million of deferrals for actual remediation costs incurred and a $35.5 million accrual for estimated future site remediation (see Note R). In addition, we have deferred $4.9 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, 2009, we have $16.0 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 SALES, DIVESTITURES AND DISCONTINUED OPERATIONS

Edgewater Generating Unit 5: During the fourth quarter of 2009, we reached a contingent agreement to sell our 25% interest in Edgewater Generating Unit 5 to WPL, which will become binding if we are unable to reach an agreement with a third party to sell our interest. We are continuing to negotiate with a third party to sell our interest in this unit. The completion of any sale will be subject to approval by the PSCW.

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. 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 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, 2009, we have recorded a regulatory liability of approximately $202.4 million that represents deferred gains that will be used for the benefit of our customers.

As of December 31, 2009, we have given approximately $577.8 million in bill credits to our Wisconsin and Michigan retail customers and issued a refund of approximately $62.5 million to wholesale customers in a one-time FERC-approved settlement. In addition,

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pursuant to the January 2008 PSCW rate order, during the first quarter of 2008, we used $85.0 million of restricted cash proceeds to recover $85.0 million of regulatory assets.

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). For further information regarding our former nuclear operations, see Note H.

E – ASSET RETIREMENT OBLIGATIONS

The following table presents the change in our AROs during 2009:

	Balance at 12/31/08		Liabilities Incurred		Liabilities Settled			Accretion		Cash Flow Revisions		Balance at 12/31/09
	(Millions of Dollars)
AROs	$	52.3	$	—	($	2.6	)	$	2.9	$	—	$	52.6

F – VARIABLE INTEREST ENTITIES

The primary beneficiary of a variable interest entity must consolidate the related assets and liabilities. Certain disclosures are required by sponsors, significant interest holders in variable interest entities and potential variable interest entities.

We assess our relationships with 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. In making this assessment, 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. The requested information required to make this determination has not been supplied. As a result, we do not consolidate these entities. We account for one of these contracts as a capital lease and the other contract as an operating lease. We have approximately $417.9 million of required payments over the remaining terms of these two agreements, which expire over the next 13 years. We believe the required payments or any replacement power purchased will continue to be recoverable in rates. Total capacity and lease payments under these contracts in 2009, 2008 and 2007 were $62.2 million, $66.4 million and $70.4 million, respectively.

G – INCOME TAXES

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

Income Taxes	2009			2008			2007
	(Millions of Dollars)
Current tax expense (benefit)	$	25.4		($	95.3	)	$	284.2
Deferred income taxes, net		135.8			270.5			(91.9	)
Investment tax credit, net		(3.5	)		(5.9	)		(3.8	)
Total Income Tax Expense	$	157.7		$	169.3		$	188.5

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

	2009					2008					2007
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	$	155.8		35.0	%	$	157.3		35.0	%	$	166.7		35.0	%
State income taxes net of federal tax benefit		22.5		5.0	%		23.5		5.2	%		24.5		5.1	%
Domestic production activities deduction		(8.3	)	(1.9	%)		(7.9	)	(1.8	%)		—		—	%
Production tax credits - wind		(7.1	)	(1.6	%)		(4.8	)	(1.1	%)		(0.1	)	—	%
Investment tax credit restored		(3.5	)	(0.8	%)		(5.9	)	(1.3	%)		(3.8	)	(0.8	%)
Other, net		(1.7	)	(0.4	%)		7.1		1.6	%		1.2		0.2	%
Total Income Tax Expense	$	157.7		35.3	%	$	169.3		37.6	%	$	188.5		39.5	%

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

	2009			2008
	(Millions of Dollars)
Deferred Tax Assets
Current
Deferred gain	$	21.3		$	37.0
Employee benefits and compensation		10.7			11.0
Recoverable gas costs		0.6			0.2
Other		(1.2	)		5.5
Total Current Deferred Tax Assets	$	31.4		$	53.7
Non-current
Deferred revenues	$	270.8		$	204.5
Construction advances		111.9			105.7
Employee benefits and compensation		16.1			80.8
Deferred gain		—			27.2
Emission allowances		4.0			13.0
Other		(17.4	)		(9.6	)
Total Non-current Deferred Tax Assets	$	385.4		$	421.6
Total Deferred Tax Assets	$	416.8		$	475.3
Deferred Tax Liabilities
Current
Prepaid items	$	45.8		$	42.8
Uncollectible account expense		(4.0	)		—
Total Current Deferred Tax Liabilities	$	41.8		$	42.8
Non-current
Property-related	$	1,039.0		$	870.7
Employee benefits and compensation		—			80.4
Deferred transmission costs		63.2			76.4
Investment in transmission affiliate		80.1			52.2
Other		36.9			33.6
Total Non-current Deferred Tax Liabilities	$	1,219.2		$	1,113.3
Total Deferred Tax Liabilities	$	1,261.0		$	1,156.1
Consolidated Balance Sheet Presentation	2009			2008
Current Deferred Tax Asset (Liability)	($	10.4	)	$	10.9
Non-current Deferred Tax Asset (Liability)	($	833.8	)	($	691.7	)

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

On January 1, 2007, we adopted accounting guidance related to uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

	2009			2008
	(Millions of Dollars)
Balance as of January 1	$	17.2		$	12.1
Additions based on tax positions related to the current year		0.9			—
Additions for tax positions of prior years		4.5			5.4
Reductions for tax positions of prior years		(1.2	)		(0.3	)
Reductions due to statute of limitations		—			—
Settlements during the period		—			—
Balance as of December 31	$	21.4		$	17.2

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The amount of unrecognized tax benefits as of December 31, 2009 and 2008 excludes deferred tax assets related to uncertainty in income taxes of $13.4 million and $9.1 million, respectively. As of December 31, 2009 and 2008, 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, 2009, 2008 and 2007, we recognized approximately $1.4 million, $1.7 million and $1.1 million, respectively, of accrued interest in the Consolidated Income Statements. For the years ended December 31, 2009, 2008 and 2007, we recognized no penalties in the Consolidated Income Statements. We had approximately $5.1 million and $3.6 million of interest accrued in the Consolidated Balance Sheets as of December 31, 2009 and 2008, respectively.

We do not anticipate any significant increases or decreases in the total amounts of unrecognized tax benefits within the next 12 months.

Our primary tax jurisdictions include Federal and the state of Wisconsin. Currently, the tax years of 2004 through 2009 are subject to Federal and Wisconsin examination.

H – NUCLEAR OPERATIONS

The sale of Point Beach was completed on 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. We liquidated our decommissioning trust assets as part of the sale of Point Beach.

I – 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. We utilize the straight-line attribution method for recognizing share-based compensation expense. Accordingly, for employee awards, equity classified 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 held by our employees 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 during the years ended December 31:

	2009		2008		2007
	(Millions of Dollars)
Stock options	$	9.9	$	11.3	$	10.8
Performance units		12.9		8.7		5.0
Restricted stock		0.3		0.3		0.5
Share-based compensation expense	$	23.1	$	20.3	$	16.3
Related Tax Benefit	$	9.3	$	8.1	$	6.6

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.

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The following is a summary of Wisconsin Energy stock option activity by our employees during 2009:

Stock Options	Number of Options		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life (Years)	Aggregate Intrinsic Value (Millions)
Outstanding as of January 1, 2009	7,423,937		$	37.91
Granted	1,129,315		$	42.22
Exercised	(315,824	)	$	26.05
Forfeited	—
Outstanding as of December 31, 2009	8,237,428		$	38.95	6.0	$	89.6
Exercisable as of December 31, 2009	4,828,148		$	33.95	4.6	$	76.7

We expect that substantially all of the outstanding options as of December 31, 2009 will be exercised.

In January 2010, the Compensation Committee awarded 257,350 Wisconsin Energy non-qualified stock options at an exercise price of $49.84 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, 2009, 2008 and 2007 was $5.9 million, $6.9 million and $22.7 million, respectively. Cash received by Wisconsin Energy from exercises of its options by our employees was $8.2 million, $8.0 million and $27.5 million during the years ended December 31, 2009, 2008 and 2007, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $2.5 million, $2.3 million and $8.9 million, respectively.

The following table summarizes information about Wisconsin Energy stock options held by our employees and outstanding as of December 31, 2009:

	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)
$19.62 to $31.07	1,186,103	$	26.27	3.0	1,186,103	$	26.27	3.0
$33.44 to $39.48	3,395,010	$	35.66	5.0	3,395,010	$	35.66	5.0
$42.56 to $48.04	3,656,315	$	46.12	8.0	247,035	$	47.27	7.3
	8,237,428	$	38.95	6.0	4,828,148	$	33.95	4.6

The following table summarizes information about non-vested Wisconsin Energy options held by our employees during 2009:

Non-Vested Stock Options	Number of Options		Weighted- Average Fair Value
Non-vested as of January 1, 2009	3,339,669		$	8.81
Granted	1,129,315		$	8.01
Vested	(1,059,704	)	$	7.59
Forfeited	—
Non-Vested as of December 31, 2009	3,409,280		$	8.73

As of December 31, 2009, total compensation costs related to non-vested Wisconsin Energy stock options held by our employees and not yet recognized was approximately $6.8 million, which is expected to be recognized over the next 16 months on a weighted-average basis.

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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 2009:

Restricted Shares	Number of Shares		Weighted- Average Market Price
Outstanding as of January 1, 2009	67,328
Granted	—
Released / Forfeited	(9,329	)	$	28.47
Outstanding as of December 31, 2009	57,999

Recipients of previously issued Wisconsin Energy restricted shares have the right to vote the shares and receive dividends, and the shares have vesting periods ranging up to 10 years.

In January 2010, the Compensation Committee awarded 32,505 restricted shares to our officers and other key employees as part of the long-term incentive program. These awards have a three-year vesting period, with one-third of the award vesting on each anniversary of the grant date. During the vesting period, restricted share recipients also have voting rights and are entitled to dividends in the same manner as other shareholders.

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. The intrinsic value of Wisconsin Energy restricted stock vesting and held by our employees was $0.4 million, $1.1 million and $1.8 million for the years ended December 31, 2009, 2008 and 2007, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was $0.2 million, $0.3 million and $0.7 million, respectively.

As of December 31, 2009, total compensation cost related to our share of Wisconsin Energy restricted stock not yet recognized was approximately $0.6 million, which is expected to be recognized over the next 37 months on a weighted-average basis.

Performance Units: In January 2009, 2008 and 2007, the Compensation Committee awarded 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. Performance units earned as of December 31, 2009, 2008 and 2007 had a total intrinsic value of $9.3 million, $7.9 million and $4.7 million, respectively. The awards were subsequently distributed to our officers and key employees in January 2010, 2009 and 2008. The actual tax benefit realized for the tax deductions from the distribution of performance units was approximately $3.2 million, $2.9 million and $1.6 million, respectively. As of December 31, 2009, total compensation cost related to performance units not yet recognized was approximately $13.3 million, which is expected to be recognized over the next 22 months on a weighted-average basis.

In January 2010, the Compensation Committee awarded 260,310 performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

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 2010 PSCW rate order requires us to maintain a capital structure that 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 K 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.

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J — LONG-TERM DEBT

Debentures and Notes: As of December 31, 2009, the maturities and sinking fund requirements of our long-term debt outstanding (excluding obligations under capital leases) were as follows:

	(Millions of Dollars)
2010	$	0.1
2011		—
2012		—
2013		300.0
2014		300.0
Thereafter		1,387.0
Total	$	1,987.1

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

During 2009, we issued $250 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.

We are the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amount of $147 million. In August 2009, we terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We purchased the bonds at par plus accrued interest to the date of purchase. As of December 31, 2009, the repurchased bonds were still outstanding, but were reported as a reduction in our consolidated long-term debt because they are held by us. Depending on market conditions and other factors, we may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.

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.

Obligations Under Capital Leases

We are the obligor under a power purchase contract and we lease power plants from We Power under Wisconsin Energy’s PTF strategy. Under capital lease accounting, we have recorded the leased plants and corresponding obligations under the capital leases on our Consolidated Balance Sheets. We treat these agreements as operating leases for rate-making purposes. We record our minimum lease payments under the power purchase contract as purchased power expense on the Consolidated Income Statements. We record the lease payments under our PTF leases as rent expense in other operation and maintenance in the Consolidated Income Statements. 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).

Power Purchase Commitment: 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 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. Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to approximately $78.5 million during 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the capital lease was $149.0 million as of December 31, 2009 and will decrease to zero over the remaining life of the contract.

PWGS: We are leasing PWGS 1 and PWGS 2, two 545 MW natural gas-fired generation units which were placed into service in July 2005 and May 2008, respectively, from We Power under PSCW approved leases. We recorded the leased plants and corresponding obligations for PWGS 1 and PWGS 2 at the estimated fair value of $338.7 million and $331.1 million, respectively. We are amortizing the leased plants on a straight-line basis over the original 25-year term of the leases. The lease payments are expected to be recovered through our rates, as supported by the 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $127.2 million in the year 2021 for PWGS 1 and to approximately $127.1 million in the year 2024 for PWGS 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the capital leases for PWGS 1 and PWGS 2 was $329.3 million and $328.6 million, respectively, as of December 31, 2009 and will decrease to zero over the remaining lives of the contracts.

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Oak Creek Expansion: We are leasing the common facilities, including the coal handling system which was placed into service in November 2007 and the water intake system which was placed into service in January 2009, from We Power under a PSCW approved lease. We recorded the leased plant and corresponding obligation at the estimated fair value of $316.4 million. We are amortizing the leased plant on a straight-line basis over the 30-year term of the lease. The total obligation under the capital lease was $316.4 million as of December 31, 2009 and will decrease to zero over the remaining life of the contract.

We paid the following lease payments during 2009, 2008 and 2007:

	2009		2008		2007
	(Millions of Dollars)
Long-term power purchase commitment	$	29.1	$	28.1	$	27.1
PWGS 1		48.5		48.3		48.1
PWGS 2		48.9		29.7		—
OC Common Facilities		41.6		24.2		3.8
Total	$	168.1	$	130.3	$	79.0

The following table summarizes our capitalized leased facilities as of December 31:

Capital Lease Assets	2009			2008
	(Millions of Dollars)
Long-term Power Purchase Commitment
Under capital lease	$	140.3		$	140.3
Accumulated amortization		(69.8	)		(64.1	)
Total Long-term Power Purchase Commitment	$	70.5		$	76.2
PWGS 1
Under capital lease	$	338.7		$	337.9
Accumulated amortization		(60.1	)		(46.6	)
Total PWGS 1	$	278.6		$	291.3
PWGS 2
Under capital lease	$	331.1		$	331.1
Accumulated amortization		(21.3	)		(8.1	)
Total PWGS 2	$	309.8		$	323.0
OC Common Facilities
Under capital lease	$	316.4		$	185.7
Accumulated amortization		(15.7	)		(6.0	)
Total OC Common Facilities	$	300.7		$	179.7
Total Leased Facilities	$	959.6		$	870.2

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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, 2009 are as follows:

Capital Lease Obligations	Power Purchase Commitment			PWGS 1			PWGS 2			OC Common Facilities			Total
2010	$	36.2		$	48.5		$	48.9		$	44.0		$	177.6
2011		37.5			48.5			48.9			44.0			178.9
2012		38.9			48.5			48.9			44.0			180.3
2013		40.4			48.5			48.9			44.0			181.8
2014		41.9			48.5			48.9			44.0			183.3
Thereafter		174.0			755.7			898.8			1,432.8			3,261.3
Total Minimum Lease Payments		368.9			998.2			1,143.3			1,652.8			4,163.2
Less: Estimated Executory Costs		(87.2	)		—			—			—			(87.2	)
Net Minimum Lease Payments		281.7			998.2			1,143.3			1,652.8			4,076.0
Less: Interest		(132.7	)		(668.9	)		(814.7	)		(1,336.4	)		(2,952.7	)
Present Value of Net
Minimum Lease Payments		149.0			329.3			328.6			316.4			1,123.3
Less: Due Currently		(7.1	)		(3.0	)		(1.9	)		—			(12.0	)
Total Capital Lease Obligations	$	141.9		$	326.3		$	326.7		$	316.4		$	1,111.3

We recorded an increase of approximately $1.0 billion to our capital lease obligation in connection with OC 1 being placed into service on February 2, 2010. See Note T — Subsequent Events for additional information.

K – SHORT-TERM DEBT

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

	2009				2008
	Balance		Interest Rate		Balance		Interest Rate
	(Millions of Dollars, except for percentages)
Commercial Paper	$	92.0	0.19	%	$	—	—	%

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

	2009			2008
	(Millions of Dollars, except for percentages)
Maximum Commercial Paper Outstanding	$	437.5		$	452.5
Average Commercial Paper Outstanding	$	248.8		$	283.3
Weighted-Average Interest Rate		0.27	%		2.71	%

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. We have no current plans to replace Lehman’s commitment. Excluding Lehman’s commitment, as of December 31, 2009, we had approximately $474.0 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, 2009, we had approximately $92.0 million of commercial paper outstanding that was supported by the available lines of credit, and our subsidiary had a $28.2 million note payable to Wisconsin Energy with a weighted average interest rate of 4.59%.

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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, 2009, we were in compliance with all covenants.

L – DERIVATIVE INSTRUMENTS

We utilize derivatives as part of our risk management program to manage the volatility and costs of purchased power, generation and natural gas purchases for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk and protect against price volatility. Regulated hedging programs require prior approval by the PSCW.

We record derivative instruments on the balance sheet as an asset or liability measured at its fair value, and changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, 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, 2009, we recognized $11.6 million in regulatory assets and $9.3 million in regulatory liabilities related to derivatives in comparison to $57.0 million in regulatory assets and $11.8 million in regulatory liabilities as of December 31, 2008.

We record our current derivative assets on the balance sheet in Other current assets and the current portion of the liabilities in Other current liabilities. The long-term portion of our derivative assets of $0.8 million is recorded in Other deferred charges and other assets, and the long-term portion of our derivative liabilities of $2.6 million is recorded in Other deferred credits and other liabilities. Our Consolidated Balance Sheet as of December 31, 2009 includes:

	Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	1.2	$	6.6
Fuel Oil		0.6		—
FTRs		5.8		—
Coal		2.1		—
Total	$	9.7	$	6.6

Our Consolidated Income Statements include gains (losses) on derivative instruments used in our risk management strategies for those commodities supporting our electric operations and natural gas sold to our customers. Our estimated notional volumes and gains (losses) for the year ended December 31, 2009 were as follows:

	Volume	Gains (Losses)
		(Millions of Dollars)
Natural Gas	45.2 million Dth	($	70.9	)
Energy	23,520 MWh		(0.5	)
Fuel Oil	6.8 million gallons		(2.5	)
FTRs	27,262 MW		12.9
Total		($	61.0	)

As of December 31, 2009, we have posted collateral of $6.6 million in our margin accounts.

M – FAIR VALUE MEASUREMENTS

Fair value measurements require enhanced disclosures about assets and liabilities that are measured and reported at fair value and establish a hierarchal disclosure framework which prioritizes and ranks the level of observable inputs used in measuring fair value.

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

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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 gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

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 fair value reporting 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 tables summarize our financial assets and liabilities by level within the fair value hierarchy:

Recurring Fair Value Measures	As of December 31, 2009
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	194.5	$	—	$	—	$	194.5
Derivatives		0.6		3.3		5.8		9.7
Total	$	195.1	$	3.3	$	5.8	$	204.2
Liabilities:
Derivatives	$	4.2	$	2.4	$	—	$	6.6
Total	$	4.2	$	2.4	$	—	$	6.6
Recurring Fair Value Measures	As of December 31, 2008
	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

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

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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:

	2009			2008
	(Millions of Dollars)
Balance as of January 1	$	8.8		$	13.0
Realized and unrealized gains (losses)		—			—
Purchases, issuances and settlements		(3.0	)		(4.2	)
Transfers in and/or out of Level 3		—			—
Balance as of December 31	$	5.8		$	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 MISO FTRs 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. See Note L — 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 are as follows:

	2009				2008
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	20.2	$	30.4	$	19.0
Long-term debt including current portion	$	1,987.1	$	2,088.2	$	1,901.5	$	1,896.3

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 unamortized discount on debt, 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.

N – 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 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.

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Wisconsin Energy 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
	2009			2008			2009			2008
	(Millions of Dollars)
Change in Benefit Obligation
Benefit Obligation at January 1	$	967.0		$	988.0		$	254.6		$	262.3
Service cost		21.4			17.0			8.2			9.8
Interest cost		61.9			60.4			16.5			15.9
Plan participants’ contributions		—			—			6.2			—
Plan amendments		0.2			5.1			(9.3	)		—
Actuarial loss (gain)		42.2			(28.4	)		43.5			(27.2	)
Gross benefits paid		(100.1	)		(75.1	)		(16.5	)		(7.3	)
Federal subsidy on benefits paid		N/A			N/A			0.9			1.1
Benefit Obligation at December 31	$	992.6		$	967.0		$	304.1		$	254.6
Change in Plan Assets
Fair Value at January 1	$	510.7		$	719.4		$	97.0		$	126.9
Actual earnings (loss) on plan assets		113.9			(177.2	)		20.8			(33.6	)
Employer contributions		269.2			43.6			21.8			11.0
Plan participants’ contributions		—			—			6.2			—
Gross benefits paid		(100.1	)		(75.1	)		(16.5	)		(7.3	)
Fair Value at December 31	$	793.7		$	510.7		$	129.3		$	97.0
Net Liability	$	198.9		$	456.3		$	174.8		$	157.6

Amounts recognized in our Consolidated Balance Sheets as of December 31 related to the funded status of the benefit plans consisted of:

	Pension				OPEB
	2009		2008		2009		2008
	(Millions of Dollars)
Other deferred charges	$	—	$	—	$	0.5	$	0.4
Other long-term liabilities		198.9		456.3		175.3		158.0
Net liability	$	198.9	$	456.3	$	174.8	$	157.6

The accumulated benefit obligation for all the defined benefit plans was $978.9 million and $947.6 million as of December 31, 2009 and 2008, 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
	2009		2008		2009			2008
	(Millions of Dollars)
Net actuarial loss	$	355.9	$	367.3	$	104.7		$	78.6
Prior service costs (credits)		17.8		19.8		(19.2	)		(22.6	)
Transition obligation		—		—		1.0			1.3
Total	$	373.7	$	387.1	$	86.5		$	57.3

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The following table shows the estimated amounts that will be amortized as a component of net periodic benefit costs during 2010:

	Pension		OPEB
	(Millions of Dollars)
Net actuarial loss	$	18.2	$	8.1
Prior service costs (credits)		2.1		(11.8	)
Transition obligation		—		0.3
Total	$	20.3	($	3.4	)

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:

	2009		2008
	(Millions of Dollars)
Projected benefit obligation	$	992.6	$	967.0
Accumulated benefit obligation	$	978.9	$	947.6
Fair value of plan assets	$	793.7	$	510.7

The components of net periodic pension and OPEB costs for the years ended December 31 are as follows:

	Pension									OPEB
	2009			2008			2007			2009			2008			2007
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	21.4		$	17.1		$	26.6		$	8.2		$	9.8		$	10.6
Interest cost		61.9			60.4			60.9			16.5			15.9			15.2
Expected return on plan assets		(73.0	)		(60.7	)		(61.0	)		(8.9	)		(10.9	)		(9.5	)
Amortization of:
Transition obligation		—			—			—			0.3			0.3			0.3
Prior service cost (credit)		2.1			2.4			5.4			(12.6	)		(12.6	)		(12.5	)
Actuarial loss		12.8			10.1			13.1			5.5			4.6			5.4
Net Periodic Benefit Cost	$	25.2		$	29.3		$	45.0		$	9.0		$	7.1		$	9.5

	Pension						OPEB
	2009		2008		2007		2009		2008		2007
Weighted-Average assumptions used to determine benefit obligations as of Dec. 31
Discount rate	6.05	%	6.50	%	6.05	%	5.75	%	6.50	%	6.10	%
Rate of compensation increase	4.0		4.0		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	6.50	%	6.05	%	5.75	%	6.50	%	6.10	%	5.75	%
Expected return on plan assets	8.25		8.5		8.5		8.25		8.5		8.5
Rate of compensation increase	4.0		4.5 to 5.0		4.5 to 5.0		N/A		N/A		N/A
Assumed health care cost trend rates as of Dec. 31
Health care cost trend rate assumed for next year (Pre 65 / Post 65)							7.5/20		7.5/9		8/11
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 (Pre 65 / Post 65)							2015/2016		2014		2014

The expected long-term rate of return on plan assets was 8.25% in 2009, and 8.5% in 2008 and 2007. Subsequent to its last asset/liability study in 2005, Wisconsin Energy has consulted with its investment advisors on an annual basis and requested them to forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund.

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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	$	26.7	($	22.4	)
Total of service and interest cost components	$	3.6	($	2.9	)

We use various Employees’ Benefit Trusts to fund a major portion of OPEB. The majority of the trusts’ assets are mutual funds or commingled funds.

Plan Assets: 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 Investment Trust Policy Committee oversees investment matters related to all of our funded benefit plans. The Committee works with external actuaries and investment consultants on an ongoing basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. They are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments.

Our current pension plan asset allocation is 45% equity investments and 55% fixed income investments. The current OPEB asset allocation is 60% equity investments and 40% fixed income investments. Equity securities include investments in large-cap, mid-cap and small-cap companies primarily located in the United States. Fixed income securities include corporate bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and U.S. Treasuries.

The following table summarizes the fair value of our share of Pension Trust assets as of December 31, 2009 by asset category within the fair value hierarchy (for further level information, see Note M):

Asset Category - Pension	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	8.3	$	—	$	—	$	8.3
Equities:
U.S. Equity		142.0		167.0		—		309.0
International Equity		45.3		26.1		—		71.4
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds		347.2		—		—		347.2
International Bonds		33.7		—		—		33.7
Commercial Paper (b)		24.1		—		—		24.1
Total	$	600.6	$	193.1	$	—	$	793.7

(a) This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries.

(b) This category represents investment in commercial paper issued by Wisconsin Energy.

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The following table summarizes the fair value of our share of OPEB plan assets as of December 31, 2009 by asset category within the fair value hierarchy:

Asset Category - OPEB	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	0.5	$	—	$	—	$	0.5
Equities:
U.S. Equity		23.9		46.5		—		70.4
International Equity		2.2		1.3		—		3.5
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds		52.1		—		—		52.1
International Bonds		1.7		—		—		1.7
Commercial Paper (b)		1.1		—		—		1.1
Total	$	81.5	$	47.8	$	—	$	129.3

(a) This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries.

(b) This category represents investment in commercial paper issued by Wisconsin Energy.

In January 2009, the committee that oversees the investment of the pension assets authorized the Trustee of Wisconsin Energy’s pension plan to invest in the commercial paper of Wisconsin Energy. As of December 31, 2009, the Pension Trust and OPEB plan assets included our share of approximately $25.2 million of commercial paper issued by Wisconsin Energy, which represents less than 10% of total assets of the plan.

Cash Flows:

Employer Contributions	Pension		OPEB
	(Millions of Dollars)
2007	$	24.6	$	11.5
2008	$	43.6	$	11.0
2009	$	269.2	$	21.8

Of the amounts listed above, we contributed approximately $265 million, $37.9 million and $19.1 million to the qualified pension plan during 2009, 2008 and 2007, respectively. We do not expect to make contributions to the plan in 2010.

Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates.

The entire contribution to the OPEB plans during 2009 was discretionary as the plans are not subject to any minimum regulatory funding requirements.

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

Year	Pension		Gross OPEB		Expected Medicare Part D Subsidy
	(Millions of Dollars)
2010	$	73.6	$	15.3	($	0.7	)
2011	$	88.5	$	16.5	($	0.5	)
2012	$	93.3	$	17.5		—
2013	$	94.4	$	19.7		—
2014	$	98.3	$	21.1		—
2015-2019	$	457.1	$	121.6		—

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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 $12.5 million, $13.3 million and $9.9 million during 2009, 2008 and 2007, respectively.

O – GUARANTEES

We enter into various guarantees to provide financial and performance assurance to third parties. As of December 31, 2009, we had the following guarantees:

Maximum Potential Future Payments	Outstanding	Liability Recorded
	(Millions of Dollars)
$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 for such benefits was $10.8 million as of December 31, 2009.

P – SEGMENT REPORTING

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

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

Summarized financial information concerning our reportable operating segments for the years ended December 31, 2009, 2008 and 2007 is shown in the following table:

	Reporting Operating Segments
Year Ended	Electric		Gas		Steam		Other (a)		Total
	(Millions of Dollars)
December 31, 2009
Operating Revenues (b)	$	2,685.0	$	564.2	$	39.1	$	—	$	3,288.3
Depreciation, Decommissioning and Amortization	$	225.7	$	35.5	$	3.9	$	—	$	265.1
Operating Income (c)	$	409.0	$	53.4	$	6.5	$	—	$	468.9
Equity in Earnings of Transmission Affiliate	$	51.9	$	—	$	—	$	—	$	51.9
Capital Expenditures	$	448.0	$	30.4	$	2.6	$	0.1	$	481.1
Total Assets (d)	$	8,019.4	$	668.7	$	65.8	$	117.3	$	8,871.2
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

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

(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.

Q – 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, the Oak Creek Water Intake 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.

American Transmission Company LLC: As of December 31, 2009, we had 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, 2009 and 2008, we had a receivable of $1.1 million and $32.6 million, respectively, for these items.

Summary financial information as of December 31 from the financial statements of ATC is as follows:

	2009		2008		2007
	(Millions of Dollars)
Operating Revenues	$	521.5	$	466.6	$	408.0
Operating Income	$	291.2	$	257.6	$	209.8
Net Income	$	213.4	$	188.0	$	154.1
Current Assets	$	51.1	$	50.8	$	48.3
Non-Current Assets	$	2,767.3	$	2,480.0	$	2,189.0
Current Liabilities	$	285.5	$	252.0	$	317.1
Non-Current Liabilities	$	1,336.5	$	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, which held the operating licenses of Point Beach. Upon the sale of Point Beach, the operating licenses were transferred to the buyer, the relationship with NMC was terminated and WEC Nuclear Corporation was dissolved.

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We provided and received services from the following associated companies during 2009, 2008 and 2007:

Company	2009		2008		2007
	(Millions of Dollars)
Affiliate
Net Services Provided
-We Power (excluding lease payments)	$	1.2	$	1.3	$	3.0
-Wisconsin Gas	$	58.2	$	51.3	$	50.8
-Edison Sault (including electric energy sold)	$	38.2	$	35.3	$	29.3
-Other	$	1.1	$	1.7	$	1.7
Net Services Received
-We Power (lease payments)	$	347.0	$	312.2	$	223.7
-Wisconsin Energy	$	15.8	$	12.6	$	8.3
Equity Investee
Services Provided
-ATC	$	22.3	$	20.0	$	17.1
Services Received
-ATC	$	196.0	$	194.4	$	172.1
-NMC	$	—	$	—	$	50.6

As of December 31, 2009 and 2008, our Consolidated Balance Sheets included receivable and payable balances with ATC as follows:

Equity Investee	2009		2008
	(Millions of Dollars)
Services Provided
-ATC	$	1.1	$	2.1
Services Received
-ATC	$	16.3	$	16.2

R – COMMITMENTS AND CONTINGENCIES

Capital Expenditures: We have made certain commitments in connection with 2010 capital expenditures. During 2010, we estimate that total capital expenditures will be approximately $736 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 2014. 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)
2010	$	21.3
2011		21.5
2012		15.1
2013		5.5
2014		2.9
Thereafter		9.7
Total	$	76.0

Divested Assets: Pursuant to the sale of Point Beach, we have agreed to indemnification provisions customary to transactions involving the sale of nuclear assets.

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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, as discussed below. 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 $25 to $45 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, 2009, we have established reserves of $35.5 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, some coal-ash by-products have been, and to a small degree, continue to be managed in company-owned licensed landfills. Some early designed and constructed landfills have at times required various levels of monitoring or remediation. 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 2009, 2008 and 2007, we incurred $0.3 million, $1.3 million and $0.8 million, respectively, in coal-ash remediation expenses. As of December 31, 2009, we have no reserves established related to ash landfill sites.

EPA - Consent Decree: In April 2003, we reached a Consent Decree with the EPA in which we agreed to significantly reduce air emissions from our coal-fired generating facilities. In July 2003, the Consent Decree was amended to include the state of Michigan, and in October 2007, the U.S. District Court for the Eastern District of Wisconsin approved and entered the amended Consent Decree. 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, 2009, we have spent approximately $686 million associated with the installation of air quality controls and have retired four coal units as part of our plan under the Consent Decree. The total cost of implementing this agreement is estimated to be $1.2 billion over the 10 year period ending 2013.

Cash Balance Pension Plan: On June 30, 2009, a lawsuit was filed by a former employee against the Plan in the U.S. District Court for the Eastern District of Wisconsin. Counsel representing the plaintiff is attempting to seek class certification for other similarly situated plaintiffs. The complaint alleges that Plan participants who received a lump sum distribution under the Plan prior to their normal retirement age did not receive the full benefit to which they were entitled in violation of ERISA and are owed additional benefits, because the Plan failed to apply the correct interest crediting rate to project the cash balance account to their normal retirement age. We believe the Plan correctly calculated the lump-sum distributions. An adverse outcome of this lawsuit could affect Plan funding and expense. We are currently unable to predict the final outcome or impact of this litigation.

S – SUPPLEMENTAL CASH FLOW INFORMATION

During the year ended December 31, 2009, we paid $98.5 million in interest, net of amounts capitalized, and $7.7 million in income taxes, net of refunds. 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.

As of December 31, 2009, 2008 and 2007, the amount of accounts payable related to capital expenditures was $8.1 million, $22.3 million and $73.0 million, respectively.

T – SUBSEQUENT EVENTS

On February 2, 2010, OC 1 was placed into service. Prior to December 31, 2009, certain common facilities associated with the Oak Creek facility were placed into service. We now have care, custody and control of OC 1 and will operate and maintain it over the 30 year life of the lease. As a result of the commercial operation of OC 1, in February 2010, we recorded an additional capital lease asset and capital lease obligation related to the Oak Creek expansion totaling approximately $1.0 billion. We also expect that the additional lease payments for the Oak Creek expansion will total approximately $4.5 billion over the next 30 years.

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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, 2009 and 2008, and the related consolidated statements of income, common equity, and cash flows for each of the three years in the period ended December 31, 2009. 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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

February 26, 2010

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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	2009		2008
	(Millions of Dollars)
First	$	44.9	$	54.3
Second		44.9		54.3
Third		44.9		204.1
Fourth		44.9		54.3
Total	$	179.6	$	367.0

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 I — 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 1,117,400 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 serve approximately 462,400 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 P — 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 2011” in Wisconsin Electric Power Company’s definitive Information Statement dated March 31, 2010, 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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