Wisconsin Electric Power Company PFD 6% (WELPM) 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.    )

Check the appropriate box:
¨	Preliminary Information Statement
¨	Confidential, for Use of the Commission Only (as permitted by Rule 14c-5(d)(2))
x	Definitive Information Statement
Wisconsin Electric Power Company
(Name of Registrant As Specified In Charter)
Payment of Filing Fee (Check the appropriate box):
x	No fee required
¨	Fee computed on table below per Exchange Act Rules 14c-5(g) and 0-11.
	(1)	Title of each class of securities to which transaction applies:
	(2)	Aggregate number of securities to which transaction applies:
	(3)	Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (Set forth the amount on which the filing fee is calculated and state how it was determined):
	(4)	Proposed maximum aggregate value of transaction:
	(5)	Total fee paid:
¨	Fee paid previously with preliminary materials.
¨	Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration statement number, or the Form or Schedule and the date of its filing
	(1)	Amount Previously Paid:
	(2)	Form, Schedule or Registration Statement No.:
	(3)	Filing Party:
	(4)	Date Filed:

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

March 30, 2012

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 26, 2012, 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 3, 2012, 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 30, 2012

To the Stockholders of Wisconsin Electric Power Company:

The 2012 Annual Meeting of Stockholders of Wisconsin Electric Power Company will be held on Thursday, April 26, 2012, 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 2013 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 23, 2012, 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 26, 2012 – The Information Statement and 2011 Annual Report to Stockholders are available at:

http://www.wisconsinelectric.com

By Order of the Board of Directors,

Susan H. Martin

Executive Vice President, General Counsel and Corporate Secretary

We Energies
231 West Michigan  Street Milwaukee, Wisconsin  53203

INFORMATION STATEMENT

This information statement is being furnished to stockholders beginning on or about March 30, 2012, in connection with the annual meeting of stockholders of Wisconsin Electric Power Company (“WE” or the “Company”) to be held on Thursday, April 26, 2012 (“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 23, 2012, 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 23, 2012 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

• 2011 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 2013 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.

Because Frederick P. Stratton, Jr. exceeds the Company’s age guidelines for non-employee directors, he is not standing for re-election at the Meeting. As a result, the Board has determined to reduce the number of directors constituting the whole Board from ten to nine.

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

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

1

Information About Nominees for Election to the Board of Directors.

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 as described below under “What are the criteria and processes used to evaluate director nominees?”.

Biographical information regarding each nominee is shown below. WE and Wisconsin Gas LLC (WG) do business as We Energies and are subsidiaries of WEC. Ages and biographical information are as of March 1, 2012.

John F. Bergstrom. Age 65.

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

• Director of Advance Auto Parts Inc. since 2008; Director of Associated Banc-Corp since 2010; and Director of Kimberly-Clark Corporation since 1987.

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

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

Mr. Bergstrom has over 26 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, as well as a unique perspective on customer focus and satisfaction which continues to be a primary focus of the Company. Mr. Bergstrom also provides the Board with insight gained from his over 26 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 64.

• 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 2006 when The Kenwood Group, Inc. merged into Profit Investment Management. Chief Executive Officer from 1989 to 2005.

• Director of Hospira, Inc. since 2008.

• Director of Black & Decker Corporation from 1993 to 2010; and Director of Dollar General Corporation from 2000 to 2007.

• 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 for the mid-cap portfolios following the Kenwood Group’s 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’ past and present 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 the Company.

2

Patricia W. Chadwick.Age 63.

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

• Director of AMICA Mutual Insurance Company since 1992; Director of ING Mutual Funds since 2006; and Director of The Royce Funds since 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 Committee and Nominating and Governance Committee (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 AMICA Mutual Insurance Company and The Royce Funds, as well as 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 71.

• 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 Committee on which he serves. Mr. Cornog also has more than 18 years of service as a director on WE’s Board and 19 years of service on WEC’s Board, including over 14 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, including Johnson Controls, Inc. where Mr. Cornog presently serves as lead director.

Curt S. Culver. Age 59.

• MGIC Investment Corporation – Chairman since 2005, Chief Executive Officer since 2000, and President from 1999 to 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 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 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.

3

Thomas J. Fischer. Age 64.

• 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 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, which was 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 several public utility audits. Combined with Mr. Fischer’s 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 61.

• Wisconsin Energy Corporation – Chairman of the Board and Chief Executive Officer since 2004. President since 2003.

• Wisconsin Electric Power Company – Chairman of the Board since 2004. President and Chief Executive Officer since 2003.

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

• Director of Badger Meter, Inc. since 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 37 years of experience working in the public utility industry, the last 19 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 56.

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

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

• Director of Badger Meter, Inc. from 2000 to 2010; and Director of Midwest Air Group, Inc. from 1998 to 2008.

• 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 on the Boards of several public corporations includes service as a member of either the audit or finance committee at each of these companies, which is beneficial to the Board.

4

Mary Ellen Stanek.Age 55.

• Robert W. Baird & Co. Incorporated – Managing Director and Director of Asset Management since 2000; Baird Advisors – Chief Investment Officer since 2000; Baird Funds, Inc. – President since 2000. Robert W. Baird & Co. provides wealth management, capital markets, private equity and asset management services to clients worldwide. Baird Advisors is an institutional fixed income investment advisor. Baird Funds, Inc. is a publicly registered investment company.

• Director of Journal Communications Inc. (and its predecessor company) since 2002; and Trustee of The Northwestern Mutual Life Insurance Company since 2009.

• Director of Wisconsin Energy Corporation, Wisconsin Electric Power Company, and Wisconsin Gas LLC since January 2012.

Ms. Stanek, who is a Chartered Financial Analyst, has over 30 years of investment management experience and is currently responsible for the development and portfolio management of all proprietary asset management services for Robert W. Baird & Co. Ms. Stanek also co-manages several fixed income mutual funds as well as a number of taxable and tax-exempt portfolios. In addition to her positions with Robert W. Baird & Co. set forth above, Ms. Stanek is also a director of Robert W. Baird, Baird Holding Company and Baird Financial Corp. Because of her career and experience, Ms. Stanek brings significant knowledge of, and financial expertise in, the financial markets to the Board and Finance Committee. In particular, Ms. Stanek’s focus on fixed income investments is valuable as the Company and its affiliates customarily issue debt securities as a means of raising capital. In addition, Ms. Stanek brings experience in dealing with insurance risk management issues through her service as a director of West Bend Mutual Insurance Company since 1999. Ms. Stanek’s past and present experience serving on the boards of numerous Milwaukee-area non-profit institutions provides her with a good understanding of the issues and challenges that impact the Milwaukee community.

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 at www.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

5

	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. 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, Stanek and Stratton have no relationships described in the Board’s standards of independence noted above and otherwise have no material relationships with WE or WEC and are independent. This represents 90% of the Board. Director Klappa is not independent due to his present employment with WEC and its affiliates. Since 2005, WEC has engaged Robert W. Baird & Co. primarily to provide consulting services for investments held in its various benefit plan trusts. The Board reviewed the terms of this engagement, including the approximately $379,000 in fees paid to Baird in 2011 (which are less than one-tenth of 1% of Baird’s total revenue), and Ms. Stanek’s position at Baird, and concluded that such engagement is not material and did not impact Ms. Stanek’s independence.
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?	Yes, the office of CEO is 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

6

	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 Board does not believe that the appointment of a designated lead independent director is necessary.
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 Board’s role in risk oversight had no effect on the Board’s decision to keep the roles of Chairman and CEO combined. 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. As part of this process, the business unit leaders identify existing, new or emerging issues or changes within their business area that could have enterprise implications and report them to senior management. Management 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 and anonymously report suspected violations of WEC’s Code of Business Conduct or other concerns, including those regarding accounting, internal accounting controls or auditing matters.

7

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.

8

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; (4) establishing and administering the Chief Executive Officer compensation package; and (5) reviewing the results of WEC’s most recent stockholder advisory vote on compensation of the named executive officers. The Compensation Committee is also charged with administering the compensation package of the non-employee directors. The Compensation Committee meets with WEC’s Corporate Governance Committee annually to review the compensation package of WEC’s non-employee directors and to determine the appropriate amount of such compensation. 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, 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 2013 Annual Meeting of Stockholders must submit the candidates’ names and qualifications to WEC’s Corporate Governance Committee no later than November 1, 2012, 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.

9

The Committee does not have a specific policy with regards to the consideration of diversity in identifying director nominees. However, 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. As part of its process in connection with the nomination of new directors to the Board, the Committee considers several factors 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 that 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 additional 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 challenging business and regulatory environments.

What is WE’s policy regarding director attendance at annual meetings?

Directors are not expected to attend the Company’s annual meetings of stockholders, as they are only short business meetings. Generally all directors are expected to attend WEC’s annual meetings of stockholders. All directors attended WEC’s 2011 Annual Meeting, except for Mr. Culver and Ms. Stanek who was not a member of the Board at the time.

10

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 2011.
Compensation John F. Bergstrom, Chair Ulice Payne, Jr. Frederick P. Stratton, Jr.	•   Identify through succession planning potential executive officers. •   Provide a competitive, performance-based executive and director compensation program. •   Set goals for the CEO, annually evaluate the CEO’s performance against such goals and determine compensation adjustments based on whether these goals have been achieved. •   The Committee conducted six meetings in 2011, including one joint meeting with WEC’s Corporate Governance Committee, and executed one signed, written unanimous consent.
Finance Curt S. Culver, Chair Patricia W. Chadwick Ulice Payne, Jr. Mary Ellen Stanek 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 2011.

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 2011, including one joint meeting with the Company’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 2011.

In addition to the number of committee meetings listed in the preceding table, the Board met six times in 2011 and executed two signed, written unanimous consents. The average meeting attendance during the year was 93.9%. No director attended fewer than 86.7% of the total number of meetings of the Board and Board committees on which he or she served.

11

INDEPENDENT AUDITORS’ FEES AND SERVICES

Deloitte & Touche LLP served as the independent auditors for the Company for the last ten 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, 2012, subject to ratification by the stockholders of Wisconsin Energy Corporation at WEC’s Annual Meeting of Stockholders on May 3, 2012.

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 3, 2012. 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 is required to report any pre-approval decisions at the next scheduled Committee meeting. Under the pre-approval policy, the Committee may 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 to 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 the Company’s annual financial statements for fiscal years 2011 and 2010 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.

	2011		2010
Audit Fees(1)	$	1,313,595	$	1,204,645
Audit-Related Fees(2)		—		—
Tax Fees(3)		7,540		48,616
All Other Fees(4)		4,668		10,085
Total	$	1,325,803	$	1,263,346

⁽¹⁾  Audit Fees consist of fees for professional services rendered in connection with the audit of the Company’s annual financial statements, reviews of financial statements included in Form 10-Q filings of WE 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 normally 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.

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

12

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 2012, 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 2011. 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, 2011 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

13

COMPENSATION DISCUSSION AND ANALYSIS

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 named executive officers for fiscal year 2011.

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.

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.

Executive Summary. 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 reward them for achieving 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 short-term and long-term goals that are aligned with the interests of WEC’s stockholders and our customers. To that end, a substantial portion of pay is at risk and generally, the value will only be realized upon strong corporate performance.

Economic conditions and the operating and regulatory environments in which we do business once again proved challenging in 2011. Despite these challenges, the Company achieved strong financial results which contributed to WEC’s outstanding stockholder returns. Accounting for the two-for-one split of WEC’s common stock in March 2011, WEC achieved record earnings of $2.18 per share for 2011 and its common stock traded at an all-time high of $35.38 on December 30, 2011. In addition to the two-for-one split of its common stock, WEC increased its quarterly dividend rate to $0.30 per share from $0.26 per share effective with the first quarter 2012 dividend payment. WEC has consistently outperformed the peer group used in connection with the WEC performance units, described below, and the S&P 500, and 2011 was no exception. For 2011, WEC’s total stockholder return outperformed all of the major indices including the S&P 500 Electric Utility Index, Dow Jones Utility Index, Philadelphia Utility Index, Dow Jones Industrial Index, S&P 500 and NASDAQ.

We generally compensate our named executive officers through a mix of compensation elements, which primarily include:

• annual base salary;

• annual cash incentive compensation (based principally on WEC earnings per share) and short-term dividend equivalents;

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

• retirement programs.

With respect to each of these elements, we analyze market data provided by Towers Watson, a compensation consulting firm retained by management, to help determine the appropriate levels of compensation for each named executive officer. This Compensation Discussion and Analysis contains a more detailed discussion of each of these elements and the extent to which we analyzed market data in establishing each individual element in 2011.

Specifically, for 2011:

• after being frozen for two consecutive years at 2008 levels due to general economic conditions, and in light of the Company’s and WEC’s financial and operational performance over the past several years, base salaries were increased;

• the annual cash incentive award represented 210% of the target award as a result of strong achievement against all performance measures;

• the short-term dividend equivalents vested because WEC achieved the 2011 performance target for earnings from continuing operations;

• the long-term incentive awards consisted of 80% WEC performance units, 10% WEC stock options and 10% WEC restricted stock, resulting in a significant part of the long-term award being tied to WEC performance and shareholder value over a multi-year period;

• total WEC stockholder return for the three-year performance period ended December 31, 2011 was at the 76^th percentile of the peer group established by the Compensation Committee, resulting in the performance units granted in 2009 vesting at a level of 128.3%; and

14

• the stock ownership guidelines were revised to increase the minimum amount of WEC common stock executive officers are required to hold, and to eliminate the recognition of vested and unexercised stock options when evaluating stock ownership levels.

With the changes to the stock ownership guidelines, which we believe further align management’s interests with those of WEC’s stockholders, our policies regarding stock ownership now include:

• stock ownership guidelines that require executive officers to acquire, generally within five years of appointment as an executive officer, and hold WEC common stock having a minimum fair market value ranging from 250% to 400%, rather than 150% to 300%, of base salary; and

• a no-hedging policy that prohibits directors, officers and employees from hedging the economic interest in the WEC shares they hold.

To the extent feasible, we believe it is important that the compensation program not dilute the interests of WEC’s current stockholders. Therefore, WEC currently uses open market purchases rather than new issue or treasury shares to satisfy its benefit plan obligations, including the exercise and vesting of WEC stock options and WEC restricted stock, respectively.

At the 2011 Annual Meeting of WEC Stockholders, WEC’s stockholders approved the compensation of the named executive officers with 92.3% of the votes cast. After considering this substantial level of approval as well as the strong financial and operational performance of the Company and WEC over the past several years, the Compensation Committee determined that the executive compensation program was working as intended and did not make any other significant changes to the program for 2011.

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 the WEC Corporate Governance Committee, for approval by the Board. In addition, the Compensation Committee administers the long-term incentive compensation programs, including the WEC 1993 Omnibus Stock Incentive Plan, amended and restated effective May 5, 2011, and the Wisconsin Energy Corporation 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.

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.

To confirm that our annual executive compensation is competitive with the market, we consider the market data obtained from Towers Watson. For 2011, Towers Watson provided us with compensation data from its 2011 Executive Compensation Data Bank, which contains information obtained from 411 companies of varying sizes in a wide range of businesses throughout general industry, including information from 108 companies within the “energy services” industry (i.e., companies with regulated and/or unregulated utility operations and independent power producers).

For purposes of determining the 2011 compensation of 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 at the time as principal executive officer of WEC’s electric utility generation operations, we considered 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 considered 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.

When the Compensation Committee made its initial decisions regarding executive compensation for 2011, Mr. Leverett was Chief Financial Officer of WEC and the Company and Mr. Kuester was the principal executive officer of WEC’s electric utility generation operations. Subsequently, on March 1, 2011, Messrs. Leverett and Kuester exchanged roles. The market median for Mr. Leverett was

15

based upon his position as Chief Financial Officer, and the market median for Mr. Kuester was based upon his role as the principal executive officer of WEC’s generation operations.

Our comparison of each element of compensation with the appropriate market data when setting the compensation levels of our named executive officers drives the allocation of cash versus non-cash compensation and short-term versus long-term incentive compensation.

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. However, the Compensation Committee may, in its discretion, adjust base salaries outside of this 10% band when the Committee deems it appropriate. The extent to which the Committee exercised discretion in establishing 2011 base salaries is set forth below.

Actual salary determinations are made taking into consideration factors such as the relative levels of individual experience, performance, responsibility and contribution to the results of the Company’s operations. At the beginning of each year, Mr. Klappa develops a list of goals for WEC and its subsidiaries, including the Company, and its employees to achieve during the upcoming year. At the end of the year, Mr. Klappa measures the performance of WEC and the Company against each stated goal and provides a report to the Board of Directors. The Compensation Committee then takes WEC’s performance into consideration when establishing Mr. Klappa’s compensation for the upcoming year. Mr. Klappa undertakes a similar process with the named executive officers of WEC and its subsidiaries, who develop individual goals related to the achievement of WEC’s goals developed by Mr. Klappa. At the end of the year, each officer’s performance is measured against these goals. Compensation recommendations and determinations for the upcoming year for each executive officer take into consideration the level of such performance.

After freezing the base salaries of all officers of WEC and its subsidiaries, including the named executive officers, for two consecutive years at 2008 levels, and in light of the Company’s and WEC’s strong financial and operational performance over the past several years, the Compensation Committee increased base salaries in 2011.

With respect to Mr. Klappa, based on the factors described above and the results of the Board’s annual CEO evaluation, the Compensation Committee approved an annual base salary of $1,174,168, which represented an increase of approximately 4%. The Compensation Committee recognized that Mr. Klappa’s eight years of service as WEC’s CEO were longer than many of those in the traditional market median used. Therefore, in order to calibrate the effect on base salaries of longer service in the CEO position, the Compensation Committee also reviewed data from utility companies in the Fortune 500 with a particular focus on the 20 most valuable electric utility companies by market capitalization, including WEC. The data indicated a distinction in the median salary for those CEOs who had served in their positions for more than 5 years. In order to appropriately recognize this differential, the Compensation Committee increased the market median for Mr. Klappa by 5% and adjusted the target range accordingly. Mr. Klappa’s 2011 annual base salary was less than 1% above this range.

The 20 most valuable electric utility companies by market capitalization⁽¹⁾ were:

Ÿ       AES Corp. Ÿ       Ameren Corporation⁽²⁾ Ÿ       American Electric Power Co. Ÿ       Consolidated Edison Ÿ       Dominion Resources Ÿ       DTE Energy Co. Ÿ       Duke Energy  Corp. Ÿ       Edison International Ÿ       Entergy Corp. Ÿ       Exelon Corp. Ÿ       FirstEnergy Corp. Ÿ       NextEra Energy Ÿ       PG&E Corp. Ÿ       PPL Corp. Ÿ       Progress Energy Ÿ       Public Service Enterprise Group Ÿ       Sempra Energy Ÿ       Southern Co. Ÿ       Wisconsin Energy Corp. Ÿ       Xcel Energy

(1) As determined by publicly available data.

(2) Although Ameren Corporation is in the list of the top 20 utilities, it was excluded from the analysis of such utilities as its CEO had been in the position for less than 18 months, which the Committee did not believe was sufficient tenure.

With respect to each other named executive officer, Mr. Klappa recommended an annual base salary to the Compensation Committee based upon a review of the market compensation data provided by Towers Watson and the factors described above. The Compensation Committee approved Mr. Klappa’s recommendations, which represented an increase in base salary of approximately 4% for Messrs. Kuester, Leverett and Fleming, and Ms. Rappé. The annual base salaries of Mr. Fleming and Ms. Rappé were within 10% of the appropriate market median.

The Compensation Committee recognized that Mr. Kuester had eight years of service with the Company and WEC. Therefore, because the median range for Mr. Kuester is based, in part, on CEO compensation in general industry, the Compensation Committee undertook an analysis for Mr. Kuester similar to the one they performed for Mr. Klappa. In order to appropriately recognize the

16

differential in median salaries of CEOs with more than 5 years of tenure, the Compensation Committee also increased the market median for Mr. Kuester by 5% and adjusted the target range accordingly. Mr. Kuester’s 2011 annual base salary fell within this range. Mr. Kuester’s 2011 base salary was not adjusted when he assumed the role of Chief Financial Officer of WEC and the Company. We requested Mr. Kuester to exchange roles with Mr. Leverett as part of our management succession planning, and the Compensation Committee determined it would not be appropriate to reduce his salary or change the method by which it is adjusted in future years.

The annual base salary of Mr. Leverett, approved when he was Chief Financial Officer of WEC and the Company, was 11.3% above the target range for that position. We believe that Mr. Leverett’s responsibilities and contributions as Chief Financial Officer varied widely from those of his counterparts within general industry, and thus, additional compensation was warranted. In addition to the normal responsibilities of a principal financial officer, as Chief Financial Officer Mr. Leverett assisted in the development of a comprehensive corporate strategy (with a focus on all Company and WEC operations and affairs, not just finance), executed corporate divestitures and oversaw the investment in the American Transmission Company, which currently represents nearly 7.5% of WEC’s consolidated earnings. In recognition of his significant responsibilities and contributions to the strategic direction of the Company and WEC beyond those of a typical principal financial officer, the Compensation Committee approved a higher level of base salary. Mr. Leverett’s 2011 base salary was not adjusted when he assumed the role of principal executive officer of WEC’s generation operations.

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 and customer (including our customers) value, as well as individual contributions to successful operations.

2011 Target Awards.Each year, the Compensation Committee approves a target level of compensation under the STPP for each of the named executive officers. This target level of compensation is expressed as a percentage of base salary. Each of Messrs. Klappa, Kuester and Leverett, 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. 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. Market data continues to support these target levels and indicates that such levels reflect median incentive compensation practices for similar officers in companies similar in size to WEC in general industry.

For 2011, the Compensation Committee approved the target awards under the STPP for each named executive officer set forth below. The targets are unchanged from previous years and are the same as those set forth in their employment agreements.

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

For 2011, 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.

2011 Performance Goals.The Compensation Committee adopted the 2011 STPP with a continued principal focus on financial results. In December 2010, the Compensation Committee approved WEC earnings per share from continuing operations as the primary performance measure to be used in 2011. We believe WEC’s earnings per share from continuing operations is a key indicator of financial strength and performance and is recognized as such by the investment community. Prior to 2011, we also included WEC cash flow as a primary performance measure for the STPP. However, as we indicated in our discussion last year, with WEC’s approximately $2.6 billionPower the Futureplan coming to conclusion in January 2011, the Compensation Committee determined that WEC cash flow was no longer as relevant a performance measure going forward as it had been during construction of the four new generating units. In January 2011, the Compensation Committee approved threshold level, target level, above target level and maximum payout level performance goals under the STPP for WEC’s earnings per share from continuing operations. If the threshold level, target level, above target level or maximum payout level performance goal was achieved, officers participating in the STPP

17

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.

After accounting for the 2-for-1 split of WEC’s common stock on March 1, 2011, the Compensation Committee established the WEC earnings per share from continuing operations goals for 2011 at a threshold level goal of $2.05 per share, a target level goal of $2.08 per share, an above target level goal of $2.09 per share and a maximum payout level goal of $2.10 per share. In addition, the Compensation Committee determined that if WEC earnings per share from continuing operations were either $2.03 or $2.04, officers would receive an award determined by interpolating on a straight line basis the appropriate vesting percentage. WEC earnings per share of $2.02 or below would result in no payout. Similar to 2010, the Compensation Committee felt that even if WEC did not achieve what would normally be the threshold level goal for earnings per share, WEC stockholders would still be provided with significant value if WEC earned at least $2.03 per share from continuing operations, and therefore, the officers should earn some incentive award.

To arrive at the 2011 WEC earnings per share performance levels, the Compensation Committee evaluated the estimated earnings per share five-year compound annual growth rates for the year ended 2011 for the companies included in WEC’s peer group established for purposes of the WEC performance units, discussed below under “2011 Performance Units”. The estimated growth rates were obtained from Thomson Reuters First Call. The survey data indicated that WEC’s earnings per share from continuing operations would need to grow by 6.0% to 6.5% in 2011 to obtain top quartile earnings growth. The Committee then considered WEC’s guidance range at that time for WEC earnings per share growth in 2011, which was 6.8% to 9.4% over WEC’s earnings per share in 2010 of $1.92. WEC’s earnings per share in 2010 were actually $3.84 which, adjusting for the two-for-one split of WEC’s common stock, was restated as $1.92. This expected growth was being driven primarily by the commencement of commercial operation of Unit 2 at the Oak Creek expansion in January 2011. After evaluating the data, the Compensation Committee determined that using WEC’s 2011 guidance range to set performance level goals would be most appropriate, as using the survey data would have set performance targets unreasonably low and would not account for the earnings growth expected from the commercial operation of Unit 2. As a result, the Compensation Committee set the lower level of the guidance range ($2.05 per share) as the threshold level goal, the mid-point of the range (rounded up to $2.08 per share) as the target level goal and $2.09 per share as the above target level goal. The Compensation Committee set the maximum payout level goal at $2.10 per share, the high end of the guidance range.

Similar to prior years, in December 2010 and January 2011, 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.

2011 Performance Under the STPP.In January 2012, the Compensation Committee reviewed WEC’s actual performance for 2011 against the financial and operational performance goals established under the STPP, subject to final audit. In 2011, WEC’s financial performance satisfied the maximum payout level established for WEC earnings per share from continuing operations. In 2011, WEC earnings per share from continuing operations were $2.18.

By satisfying the maximum payout level with respect to WEC earnings per share from continuing operations, the named executive officers earned 200% of the target award from the financial goal component of the STPP.

With respect to operational goals in 2011, the performance at WEC and its subsidiaries, including the Company, generated a 10% 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 the Company and WG during the year, which measured (1) customers’ satisfaction with the Company and WG in general and (2) customers’ satisfaction with respect to their particular interactions with the Company and WG. In 2011, the Company and WG exceeded target levels related to both measures leading to a 5.0% increase in the award. With respect to safety measures, WEC and its subsidiaries, including the Company, exceeded the target levels for both Occupational Safety and Health Administration (OSHA) recordable injuries and lost-time injuries leading to a 2.5% increase in the STPP award. WEC and its subsidiaries exceeded target level performance with respect to both supplier and workforce diversity, resulting in an increase in the STPP award of 2.5% for 2011.

The Compensation Committee did not factor individual contributions into determining the amount of the awards for the named executive officers. Because performance measured against the financial and operational goals resulted in significant STPP awards in 2011, the Compensation Committee determined that no further adjustments based upon individual contributions were appropriate.

Based on performance measured against the financial and operational goals established by the Compensation Committee, Mr. Klappa received annual incentive cash compensation under the STPP of $2,465,753 for 2011. This represented 210% of his annual base

18

salary. Messrs. Kuester, Leverett and Fleming, and Ms. Rappé, received annual cash incentive compensation for 2011 under the STPP equal to 168%, 168%, 147% and 126% of their respective annual base salaries, representing 210% of the target award for each officer.

The Compensation Committee also considered other significant accomplishments of WEC and its subsidiaries, including the Company, in 2011. These included:

• Financial performance

• Declared a two-for-one split of WEC’s common stock effective March 1, 2011.

• Increased WEC’s dividend by almost 30% effective with the first quarter payment in 2011.

• Reported the highest WEC earnings per share in WEC’s history.

• Maintained strong, investment grade credit ratings.

• WEC common stock share price increased by 18.8% during 2011.

• Adjusting for the two-for-one stock split, WEC common stock traded at an all-time high of $35.38 per share on December 30, 2011.

• Operational excellence

• Named the most reliable utility in the Midwest for the seventh time in the past 10 years.

• Completed WEC’sPower the Future plan with the commercial operation of Unit 2 at the Oak Creek expansion in January 2011.

• Completed Glacier Hills Wind Park, Wisconsin’s largest wind farm, in December 2011.

• Continued improvements in customer satisfaction based on customer surveys. Data from 2011 indicated that the Company and WG achieved their best customer satisfaction ratings since their merger in 2000.

• Achieved the best overall safety results in WEC’s history.

• WEC was named one of the 100 best corporate citizens in the United States by Corporate Responsibility magazine for the fourth consecutive year.

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 2011 performance without any further adjustment.

Short-Term Dividend Equivalents. Under the STPP, certain officers, including the named executive officers, and employees 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 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 performance targets are established under the STPP for the annual incentive awards. For 2011, the Compensation Committee determined that the short-term dividend equivalents would be dependent upon WEC’s performance against a target for earnings from continuing operations. The Compensation Committee established $2.08 per share from continuing operations, approximately the mid-point of WEC’s earnings guidance, as the target, and WEC achieved $2.18 per share.

Long-Term Incentive Compensation.The Compensation Committee administers WEC’s 1993 Omnibus Stock Incentive Plan, amended and restated effective May 5, 2011, 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. The Compensation Committee also administers the Wisconsin Energy Corporation Performance Unit Plan, under which the Committee may award WEC performance units. The Compensation Committee primarily uses (1) WEC performance units, (2) WEC stock options and (3) WEC restricted stock to deliver long-term incentive opportunities.

Each year, the Compensation Committee makes annual grants of WEC performance units under the Performance Unit Plan. The WEC performance units are designed to provide a form of long-term incentive compensation that aligns the interests of management with those of a typical utility stockholder who is focused not only on stock price appreciation but also on dividends. 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. The performance units are settled in cash.

Each year, the Compensation Committee also makes annual WEC stock option grants as part of the 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

19

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 awards WEC restricted stock as part of the long-term incentive plan, consistent with the market data. Similar to performance units, restricted stock aligns the interests of management with a typical utility stockholder who is focused on stock price appreciation and dividends.

Aggregate 2011 Long-Term Incentive Awards.In establishing the target value of long-term incentive awards for each named executive officer in 2011, 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. Kuester and Leverett, 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 2011, the Compensation Committee approved a long-term incentive award consisting of 80% WEC performance units, 10% WEC stock options and 10% WEC restricted stock. This allocation is the same as in 2010. The Compensation Committee believes that the long-term award must be tied to WEC performance and shareholder value, and that WEC performance units are an effective tool to achieve this goal. Performance Units also better reflect the value to WEC’s stockholders of the continued increase in WEC’s annual dividend.

2011 Stock Option Grants.In December 2010, 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 120 other employees. These option grants were made effective January 3, 2011, the first trading day of 2011. 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 grant date. The options were granted in accordance with our standard practice of making annual stock option grants effective on the first trading day of each year, and the timing of the grants was not tied to the timing of any release of material 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 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 2011, adjusted to account for the two-for-one split of WEC’s common stock.

Executive Officer	Options Granted
Mr. Klappa	122,610
Mr. Kuester	56,540
Mr. Leverett	56,540
Mr. Fleming	19,870
Ms. Rappé	16,520

For financial reporting purposes, the WEC stock options granted in 2011 had a grant date fair value of $2.79 per option for Messrs. Klappa, Kuester and Fleming, and Ms. Rappé, and a grant date fair value of $3.91 for Mr. Leverett. Messrs. Klappa, Kuester and Fleming, and Ms. Rappé, are considered to be “retirement eligible.” Therefore, their options are presumed to have a shorter expected life, which results in a lower option value.

2011 Restricted Stock Awards.In December 2010, the Compensation Committee also approved the grant of WEC restricted stock to each of the named executive officers and established an overall pool of WEC restricted stock that was granted to approximately 120 other employees. These grants were also made effective January 3, 2011. The WEC restricted stock vests in three equal annual installments beginning on January 3, 2012. The vesting of the WEC restricted stock may be accelerated in connection with a termination of employment due to a change in control of WEC, death or disability or by action of the Compensation Committee. See “Potential Payments upon Termination or Change in Control” under “Executive Officers’ Compensation” for additional information. Tax withholding obligations related to vesting may be satisfied, at the option of the executive officer, by withholding shares otherwise

20

deliverable upon vesting or by cash. The named executive officers have the right to vote the restricted stock and to receive cash dividends at the same time that WEC declares and pays a dividend to its stockholders.

For purposes of determining the appropriate number of shares of WEC restricted stock to grant to a particular named executive officer, the Compensation Committee used a value of $29.489 per share, adjusted to account for the two-for-one stock split. This value was based on the volume weighted stock price of WEC’s common stock for the ten trading days beginning on December 6, 2010 and ending on December 17, 2010. The Compensation Committee uses the volume weighted stock price in order to minimize the impact of day to day volatility in the stock market. The measurement period is customarily mid- to late December to shorten the timeframe between the time the calculation of the awards is made and the actual grant date. The following table provides the number of shares of WEC restricted stock granted to each named executive officer in 2011, adjusted to account for the two-for-one split of WEC’s common stock.

Executive Officer	Restricted Stock Granted
Mr. Klappa	14,574
Mr. Kuester	6,720
Mr. Leverett	6,720
Mr. Fleming	2,364
Ms. Rappé	1,968

2011 Performance Units.In 2011, 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 120 other employees. With respect to the 2011 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, 2013, as compared to the total stockholder return of the custom peer group of companies described below. Total stockholder return is the calculation of total return (stock price appreciation plus reinvestment of dividends) based upon an initial investment of $100 and subsequent $100 investments at the end of each quarter during the three-year performance period.

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.

In addition to Wisconsin Energy Corporation, the peer group used for purposes of the performance units was 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.; 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, with a focus on regulated utility operations rather than a non-regulated business model.

Beginning in 2012 with the grant of WEC performance units on January 3, 2012, Allegheny Energy was replaced with CMS Energy Corporation in the custom peer group as FirstEnergy acquired Allegheny Energy effective February 25, 2011, and FirstEnergy is already part of the peer group. We believe CMS Energy is similar to WEC in terms of business model and long-term strategy, and therefore, is an appropriate addition to the custom peer group.

The required percentile ranking for total stockholder return 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

21

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 WEC performance units to grant to a particular named executive officer, the Compensation Committee used a value of $29.489 per unit, the same value used for the restricted stock. The following table provides the number of units granted to each named executive officer at the 100% target level, adjusted to account for the two-for-one split of WEC’s common stock.

Executive Officer	Performance Units Granted
Mr. Klappa		116,580
Mr. Kuester		53,760
Mr. Leverett		53,760
Mr. Fleming		18,890
Ms. Rappé		15,710

2011 Payouts Under Previously Granted Long-Term Incentive Awards. In 2009, 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 2009 were substantially similar to those of the WEC performance units granted in 2011 described above, and the required performance percentile ranks and related vesting schedule were identical to that of the 2011 units.

Payouts under the 2009 WEC performance units were based on WEC’s total stockholder return for the three-year performance period ended December 31, 2011 against the same group of peer companies used for the 2011 WEC performance unit awards.

For the three-year performance period ended December 31, 2011, WEC’s total stockholder return was at the 76^th percentile of the peer group, resulting in the performance units vesting at a level of 128.3%. The actual payouts were determined by multiplying the number of vested performance units by the closing price of WEC’s common stock ($34.96) on December 30, 2011, 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 2011” table. This table also reflects amounts realized by the named executive officers in connection with the exercise in 2011 of any vested WEC stock options and the amounts realized by the named executive officers 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, 2011, please refer to the table entitled “Outstanding Equity Awards at Fiscal Year-End 2011”.

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 which, as discussed under the Executive Summary above, were revised in July 2011. These guidelines, as amended, provide that each executive officer, including the named executive officers, 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 250% to 400% of base salary. In addition to shares owned outright, 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; and WEC shares held by a brokerage account, jointly with an immediate family member or in a trust. Prior to the July 2011 revisions to the stock ownership guidelines, vested WEC stock options were also included when evaluating progress towards compliance with the guidelines. Market data indicated that including vested and unexercised options in this calculation was no longer a common market practice. Therefore, the Compensation Committee revised the guidelines to eliminate recognition of such holdings when evaluating WEC stock ownership.

The Compensation Committee periodically reviews whether executive officers are in compliance with these guidelines. The last review was completed in July 2011 under the old ownership guidelines, which required executive officers to own WEC common stock having a minimum fair market value ranging from 150% to 300% of base salary. The Compensation Committee determined that all of the named executive officers satisfied these guidelines. The Compensation Committee intends to conduct a review of executive officers’ compliance with the revised stock ownership guidelines in 2012.

22

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, including the named executive officers, are prohibited from engaging in any such transactions.

Retirement Programs.WEC also maintains 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 the named 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 2011” and “Retirement Plans” later in this information statement.

Other Benefits, Including Perquisites.The Company provides its executive officers, including the named 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 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 financial planning, membership in a service that provides health care and safety management when traveling outside the United States, payment of the cost of a mandatory physical exam that the Board requires annually, limited spousal travel for business purposes and the cost of a residential security system. 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 related to perquisites. For a more detailed discussion of perquisites made available to our named executive officers, please refer to the notes following the Summary Compensation Table.

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 2011 of 349 companies throughout general industry. Based upon this review, we believe that the perquisites we provide to our executive officers are generally market competitive. As part of this review in July 2011, the Compensation Committee reviewed the Company’s practice of providing its executive officers with tax gross-ups on perquisites. The Committee agreed that those officers who were employed by the Company as of July 2011 would continue to receive tax gross-ups, but determined that the Company would not provide tax gross-ups to new executives.

We reimburse those executives who are still eligible for gross-ups 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.

In addition, each of our executive officers participates in WEC’s death benefit only plan. Under the terms of the plan, upon an executive officer’s death while employed by WEC or its subsidiaries, including the Company, 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 at the time of death.

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 the named 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 the named 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.

23

Each of Messrs. Klappa, Kuester, Leverett, 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, in either case, the highest bonus amount (except for Ms. Rappé, whose benefits were frozen as of December 31, 2010);

• 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 of WEC, if WEC terminates the employment of the applicable named executive officer for any reason other than cause, death or disability, or the applicable named 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. Kuester and Leverett, 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 (other than Ms. Rappé), (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 under his agreement upon termination of employment for good reason or without cause in the absence of a change in control of WEC.

We believe the amounts payable under these agreements are consistent with market standards as confirmed by our review in 2011 of a study of the competitive practices with regard to change in control severance benefits at the 100 largest companies in the S&P 500, which was the data available to us at the time of this review. As it relates to tax gross-up payments for any federal excise taxes that may be owed by an executive, this analysis indicated that most companies, similar to WEC, are “grandfathering” existing employment agreements.

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 does not believe it is appropriate to consider the amounts realized or realizable from prior incentive compensation awards when establishing future levels of short-term and long-term incentive compensation.

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 may take into consideration the provisions of Section 162(m), it believes that maintaining tax deductibility is only one consideration among many in the design of an effective executive compensation program.

With respect to 2011 compensation for the named executive officers, the stock option grants under WEC’s 1993 Omnibus Stock Incentive Plan have been structured to qualify as performance based compensation under Section 162(m). The remaining components of the 2011 compensation program do not qualify for tax deductibility under Section 162(m).

24

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.

25

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 2011, 2010 and 2009. 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,		2011		1,174,168		—		3,849,042		341,469		2,724,879		3,041,481		215,408		11,346,447
President and Chief		2010		1,129,008		—		3,716,818		393,835		2,462,868		2,399,257		214,033		10,315,819
Executive Officer of		2009		1,129,008		—		3,191,032		2,309,953		2,286,241		2,450,367		212,627		11,579,228
WEC, WE and WG
Frederick D. Kuester
Executive Vice President		2011		683,280		—		1,774,937		157,464		1,275,580		776,443		101,200		4,768,904
and Chief Financial		2010		657,000		—		1,934,290		204,971		1,152,390		1,117,215		91,782		5,157,648
Officer of WEC, WE		2009		657,000		—		1,688,178		1,222,020		1,064,340		1,463,700		92,546		6,187,784
and WG
Allen L. Leverett
Executive Vice President		2011		632,000		—		1,774,937		221,071		1,189,430		648,802		98,770		4,565,010
of WEC, WE and WG		2010		607,680		—		1,934,290		269,771		1,070,026		387,507		106,512		4,375,786
		2009		607,680		—		1,688,178		1,222,020		984,442		314,667		93,366		4,910,353
James C. Fleming
Executive Vice President		2011		458,200		—		623,751		55,338		718,742		270,310		68,829		2,195,170
and General Counsel of		2010		441,000		—		688,539		72,961		664,059		219,747		76,425		2,162,731
WEC, WE and WG		2009		441,000		—		615,073		372,400		625,118		233,114		69,838		2,356,543
Kristine A. Rappé
Senior Vice President		2011		407,881		—		518,805		46,008		551,568		567,937		73,506		2,165,705
and Chief Administrative		2010		393,708		—		574,157		80,049		509,504		555,288		110,660		2,223,366
Officer of WEC, WE		2009		393,708		—		514,390		372,423		478,356		463,564		91,670		2,314,111
and WG

⁽¹⁾  The amounts reported reflect the aggregate grant date fair value, as computed in accordance with FASB ASC Topic 718 excluding estimated forfeitures, of (i) WEC performance units awarded to each named executive officer in the respective year for which such amounts are reported and (ii) shares of WEC restricted stock awarded to each named executive officer in 2011 and 2010 (no restricted stock was granted in 2009). The amounts reported for the performance units 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. The actual value received by the executives from these awards may range from $0 to greater than the reported amounts, depending upon (i) in the case of the performance units, WEC’s performance over the three-year performance period, and (ii) in the case of the shares of WEC restricted stock, WEC’s performance and the executive’s number of additional years of service with the Company. The value of the WEC performance unit awards as of the grant date, assuming achievement of the highest level of performance, for each of Messrs. Klappa, Kuester, Leverett and Fleming, and Ms. Rappé, is $5,987,330, $2,761,013, $2,761,013, $970,170, and $806,851 for the 2011 awards, respectively; $5,781,839, $3,009,090, $3,009,090, $1,071,062 and $893,133 for the 2010 awards, respectively; and $5,584,327, $2,954,332, $2,954,332, $1,076,398 and $900,193 for the 2009 awards, respectively.

⁽²⁾  The amounts reported reflect the aggregate grant date fair value, as computed in accordance with FASB ASC Topic 718 excluding estimated forfeitures, 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 performance. In accordance with FASB ASC Topic 718, we made certain assumptions in our calculation of the grant date fair value of WEC stock options. See “Stock Options” in Note A — Summary of Significant Accounting Policies and Note H — Common Equity in the Notes to Consolidated Financial Statements in our 2011 Annual Report on Form 10-K for a description of these assumptions. For 2011, the assumptions made in connection with the valuation of WEC stock options are the same as described in Note A, except that the expected life of the options is 4.3 years for Messrs.

26

Klappa, Kuester and Fleming, and Ms. Rappé, and 7.7 years for Mr. Leverett, and the expected forfeiture rate is 0%. The change in the expected life of the options as set forth in Note A resulted from the fact that Messrs. Klappa, Kuester and Fleming, and Ms. Rappé, were “retirement eligible” as of December 31, 2011, and Mr. Leverett was not, whereas the assumption described in Note A is a weighted average of all option holders.

For 2010, the assumptions made in connection with the valuation of WEC stock options are the same as described in Note A, except that the expected life of the options is 4.9 years for Messrs. Klappa, Kuester and Fleming and 7.6 years for Mr. Leverett and Ms. Rappé, and the expected forfeiture rate is 0%. Only Messrs. Klappa, Kuester and Fleming were “retirement eligible” as of December 31, 2010.

For 2009, the assumptions made in connection with the valuation of WEC stock options are the same as described in Note A, 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%. Only Mr. Fleming was “retirement eligible” as of December 31, 2009.

For 2011, 2010 and 2009, 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.

⁽³⁾  Consists of the annual incentive compensation earned under WEC’s Short-Term Performance Plan for 2011, 2010 and 2009, as well as the short-term dividend equivalents earned for 2011 and 2010.

⁽⁴⁾  The amounts reported for 2011, 2010 and 2009 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, 2010 to December 31, 2011, December 31, 2009 to December 31, 2010 and December 31, 2008 to December 31, 2009, respectively. The Company’s 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 2011 and 2010, the applicable discount rate used to value pension plan liabilities was reduced from 5.60% to 5.05% and from 6.05% to 5.60%, respectively, consistent with the overall decline in interest rates over the last few years. As the discount rate decreases, the Company’s pension funding obligation increases.

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 amounts reported represent only WEC’s obligation of the aggregate change in the actuarial present value of each named executive officer’s accumulated benefit under all defined benefit plans. Messrs. Klappa, Kuester and Leverett are entitled to receive pension benefits from prior employers. To the extent such prior employers are unable to pay their pension obligations, WEC may be obligated to pay the total amount.

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 $172,118 for 2011, $150,038 for 2010 and $145,822 for 2009, which will be paid upon termination of employment. See “Pension Benefits at Fiscal Year-End 2011” and “Retirement Plans” later in this information statement for additional details.

The named executive officers did not receive any above-market or preferential earnings on deferred compensation in 2011, 2010 or 2009.

⁽⁵⁾  During 2011, 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; Messrs. Klappa, Kuester and Leverett were provided with membership in a service that provides healthcare and safety management when traveling outside the United States; and Mr. Klappa received reimbursement for the cost of a home security system. 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. During 2011, Mr. Klappa utilized the benefit of spousal travel for business purposes with the associated tax reimbursement. These tax reimbursements are reflected 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⁾  For Mr. Klappa, the amount reported in All Other Compensation for 2011 includes $17,371 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.

27

In addition to the perquisites and Directors’ Charitable Awards Program identified above, All Other Compensation for Messrs. Klappa, Kuester, Leverett and Fleming, and Ms. Rappé, for 2011 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 $131,764, $61,744, $56,398, $34,629 and $26,565, respectively; and

• Tax reimbursements or “gross-ups” for all applicable perquisites in the amounts of $27,505, $10,286, $14,245, $10,302 and $14,367, respectively.

Percentages of Total Compensation.

For Messrs. Klappa, Kuester, Leverett, and Fleming, and Ms. Rappé, (1) salary (as reflected in column (c) above) represented approximately 10%, 14%, 14%, 21% and 19%, respectively, of total compensation (as shown in column (j) above) in 2011, (2) annual incentive compensation and short-term dividend equivalents (as reflected in column (g) above) represented approximately 24%, 27%, 26%, 33% and 25%, respectively, of total compensation in 2011, and (3) salary and annual incentive compensation and short-term dividend equivalents together represented approximately 34%, 41%, 40%, 54% and 44%, respectively, of total compensation in 2011.

For Messrs. Klappa, Kuester, Leverett, and Fleming, and Ms. Rappé, (1) salary represented approximately 11%, 13%, 14%, 20% and 18%, respectively, of total compensation in 2010, (2) annual incentive compensation and short-term dividend equivalents represented approximately 24%, 22%, 24%, 31% and 23%, respectively, of total compensation in 2010, and (3) salary and annual incentive compensation together represented approximately 35%, 35%, 38%, 51% and 41%, respectively, of total compensation in 2010.

For Messrs. Klappa, Kuester, Leverett, and Fleming, and Ms. Rappé, (1) salary represented approximately 10%, 11%, 12%, 19% and 17%, respectively, of total compensation in 2009, (2) annual incentive compensation represented approximately 20%, 17%, 20%, 27% and 21%, respectively, of total compensation in 2009, and (3) salary and annual incentive compensation together represented approximately 29%, 28%, 32%, 45% and 38%, respectively, of total compensation in 2009.

28

All share amounts and the corresponding exercise prices provided in this information statement have been adjusted to reflect the March 1, 2011 two-for-one split of WEC’s common stock. These adjustments did not impact the value of the share-based compensation reported herein.

Grants of Plan-Based Awards for Fiscal Year 2011

The following table shows additional data regarding incentive plan awards to the named executive officers in 2011.

(a)	(b)			(c)		(d)		(e)		(f)		(g)		(h)		(i)		(j)		(k)				(l)
Name				Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (2)						Estimated Future Payouts Under Equity Incentive Plan Awards (3)						All Other Stock Awards: Number of Shares of Stock or Units(4)		All Other Option Awards (5)						Grant Date Fair Value of Stock and Option Awards (8)
	Grant Date		Action Date (1)	Threshold		Target		Maximum		Threshold		Target		Maximum				Number of Securities Underlying Options		Exercise or Base Price (6)		Closing Market Price (7)
				($)		($)		($)		(#)		(#)		(#)		(#)		(#)		($/Sh)		($/Sh)		($)
Gale E.		1/20/11	—		195,734		1,174,168		2,465,753		—		—		—		—		—		—		—		—
Klappa		1/20/11	—		—		259,126		—		—		—		—		—		—		—		—		—
		1/03/11	12/1/10		—		—		—		29,145		116,580		204,015		—		—		—		—		3,421,332
		1/03/11	12/1/10		—		—		—		—		—		—		14,574		—		—		—		427,710
		1/03/11	12/1/10		—		—		—		—		—		—		—		122,610		29.3475		29.40		341,469
Frederick D.		1/20/11	—		91,122		546,624		1,147,910		—		—		—		—		—		—		—		—
Kuester		1/20/11	—		—		127,670		—		—		—		—		—		—		—		—		—
		1/03/11	12/1/10		—		—		—		13,440		53,760		94,080		—		—		—		—		1,577,722
		1/03/11	12/1/10		—		—		—		—		—		—		6,720		—		—		—		197,215
		1/03/11	12/1/10		—		—		—		—		—		—		—		56,540		29.3475		29.40		157,464
Allen L.		1/20/11	—		84,284		505,600		1,061,760		—		—		—		—		—		—		—		—
Leverett		1/20/11	—		—		127,670		—		—		—		—		—		—		—		—		—
		1/03/11	12/1/10		—		—		—		13,440		53,760		94,080		—		—		—		—		1,577,722
		1/03/11	12/1/10		—		—		—		—		—		—		6,720		—		—		—		197,215
		1/03/11	12/1/10		—		—		—		—		—		—		—		56,540		29.3475		29.40		221,071
James C.		1/20/11	—		53,467		320,740		673,554		—		—		—		—		—		—		—		—
Fleming		1/20/11	—		—		45,188		—		—		—		—		—		—		—		—		—
		1/03/11	12/1/10		—		—		—		4,723		18,890		33,058		—		—		—		—		554,374
		1/03/11	12/1/10		—		—		—		—		—		—		2,364		—		—		—		69,377
		1/03/11	12/1/10		—		—		—		—		—		—		—		19,870		29.3475		29.40		55,338
Kristine A.		1/20/11	—		40,796		244,729		513,931		—		—		—		—		—		—		—		—
Rappé		1/20/11	—		—		37,637		—		—		—		—		—		—		—		—		—
		1/03/11	12/1/10		—		—		—		3,928		15,710		27,493		—		—		—		—		461,049
		1/03/11	12/1/10		—		—		—		—		—		—		1,968		—		—		—		57,756
		1/03/11	12/1/10		—		—		—		—		—		—		—		16,520		29.3475		29.40		46,008

⁽¹⁾  On December 1, 2010, the Compensation Committee awarded the 2011 option, restricted stock and performance unit grants effective the first trading day of 2011 (January 3, 2011).

⁽²⁾  Non-equity incentive plan awards consist of annual incentive awards under WEC’s Short-Term Performance Plan (reported on the first line) and short-term dividend equivalents (reported on the second line). The short-term dividend equivalents only vest upon WEC’s achievement of the established performance target; otherwise, no dividend equivalents vest. For a more detailed description of the Short-Term Performance Plan and short-term dividend equivalents, see the Compensation Discussion and Analysis.

⁽³⁾ Consists of performance units awarded under the WEC Performance Unit Plan. For a more detailed description of the terms of the performance units, see the Compensation Discussion and Analysis.

⁽⁴⁾  Consists of restricted stock awarded under WEC’s 1993 Omnibus Stock Incentive Plan. For a more detailed description of the terms of the restricted stock, see the Compensation Discussion and Analysis.

⁽⁵⁾  Consists of non-qualified stock options to purchase shares of WEC common stock pursuant to WEC’s 1993 Omnibus Stock Incentive Plan. 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-

29

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).

⁽⁶⁾  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 3, 2011. Fair market value is the average of the high and low prices of WEC’s common stock reported in the New York Stock Exchange Composite Transaction Report on the grant date.

⁽⁷⁾  Reflects the closing market price of WEC’s common stock reported in the New York Stock Exchange Composite Transaction Report on the grant date, adjusted to reflect the two-for-one split of WEC’s common stock.

⁽⁸⁾  Grant date fair value of each award as determined in accordance with FASB ASC Topic 718, which 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’s performance and the executive’s number of additional years of service with WEC or its subsidiaries, including the Company.

Outstanding Equity Awards at Fiscal Year-End 2011

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 equity awards held by the named executive officers at fiscal year-end 2011.

(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.	560,000	—	—	17.100	1/18/15	—	—	—	—
Klappa	504,000	—	—	19.7375	1/03/16	—	—	—	—
	542,000	—	—	23.8775	1/03/17	—	—	—	—
	600,000	—	—	24.0175	1/02/18	—	—	—	—
	—	551,960	—	21.1075	1/02/19	—	—	—	—
	—	131,060	—	24.92	1/04/20	—	—	—	—
	—	122,610	—	29.3475	1/03/21	—	—	—	—
	—	—	—	—	—	44,225 (4)	1,546,106	—	—
	—	—	—	—	—	—	—	232,015 (9)	8,111,244  (9)
	—	—	—	—	—	—	—	204,015 (10)	7,132,364 (10)
Frederick D.	328,500	—	—	24.0175	1/02/18	—	—	—	—
Kuester	—	292,000	—	21.1075	1/02/19	—	—	—	—
	—	68,210	—	24.92	1/04/20	—	—	—	—
	—	56,540	—	29.3475	1/03/21	—	—	—	—
	—	—	—	—	—	23,572 (5)	824,077	—	—
	—	—	—	—	—	—	—	120,750 (9)	4,221,420 (9)
	—	—	—	—	—	—	—	94,080 (10)	3,289,037 (10)
Allen L.	140,000	—	—	17.100	1/18/15	—	—	—	—
Leverett	190,000	—	—	19.7375	1/03/16	—	—	—	—
	258,000	—	—	23.8775	1/03/17	—	—	—	—
	328,500	—	—	24.0175	1/02/18	—	—	—	—
	—	292,000	—	21.1075	1/02/19	—	—	—	—
	—	68,210	—	24.92	1/04/20	—	—	—	—
	—	56,540	—	29.3475	1/03/21	—	—	—	—
	—	—	—	—	—	12,468(6)	435,881	—	—
	—	—	—	—	—	—	—	120,750 (9)	4,221,420 (9)
	—	—	—	—	—	—	—	94,080 (10)	3,289,037  (10)

30

(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)
	(#)	(#)	(#)	($)		(#)	($)	(#)	($)
James C.	123,000	—	—	24.0175	1/02/18	—	—	—	—
Fleming	—	106,400	—	21.1075	1/02/19	—	—	—	—
	—	24,280	—	24.92	1/04/20	—	—	—	—
	—	19,870	—	29.3475	1/03/21	—	—	—	—
	—	—	—	—	—	4,412 (7)	154,244	—	—
	—	—	—	—	—	—	—	42,980 (9)	1,502,581 (9)
	—	—	—	—	—	—	—	33,058 (10)	1,155,708 (10)
Kristine A.	100,400	—	—	24.0175	1/02/18	—	—	—	—
Rappé	—	88,990	—	21.1075	1/02/19	—	—	—	—
	—	20,240	—	24.92	1/04/20	—	—	—	—
	—	16,520	—	29.3475	1/03/21	—	—	—	—
	—	—	—	—	—	3,676 (8)	128,513	—	—
	—	—	—	—	—	—	—	35,840 (9)	1,252,966 (9)
	—	—	—	—	—	—	—	27,493 (10)	961,155 (10)

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

⁽²⁾  All options reported in this column with an exercise price of $21.1075 and an expiration date of January 2, 2019, fully vest and become exercisable on January 2, 2012. All options reported in this column with an exercise price of $24.92 and an expiration date of January 4, 2020, fully vest and become exercisable on January 4, 2013. All options reported in this column with an exercise price of $29.3475 and an expiration date of January 3, 2021, fully vest and become exercisable on January 3, 2014.

⁽³⁾  Based on the closing price of WEC common stock reported in the New York Stock Exchange Composite Transaction Report on December 30, 2011, the last trading day of the year.

⁽⁴⁾  Effective April 14, 2003, Mr. Klappa was granted a WEC restricted stock award of 79,020 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 this award of restricted stock.

Effective January 4, 2010 and January 3, 2011, Mr. Klappa was granted a WEC restricted stock award of 16,570 shares and 14,574 shares, respectively, which began vesting in three equal annual installments on January 4, 2011 and January 3, 2012, respectively. The vesting of the restricted stock may be accelerated in connection with a termination of employment due to a change in control of WEC, death or disability or by action of the Compensation Committee.

⁽⁵⁾  Effective October 13, 2003, Mr. Kuester was granted a WEC restricted stock award of 48,280 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 this award of restricted stock.

Effective January 4, 2010 and January 3, 2011, Mr. Kuester was granted a WEC restricted stock award of 8,620 shares and 6,720 shares, respectively, which began vesting in three equal annual installments on January 4, 2011 and January 3, 2012, respectively. The vesting of the restricted stock may be accelerated in connection with a termination of employment due to a change in control of WEC, death or disability or by action of the Compensation Committee.

⁽⁶⁾  Effective January 4, 2010 and January 3, 2011, Mr. Leverett was granted a WEC restricted stock award of 8,620 shares and 6,720 shares, respectively, which began vesting in three equal annual installments on January 4, 2011 and January 3, 2012, respectively.

31

The vesting of the restricted stock may be accelerated in connection with a termination of employment due to a change in control of WEC, death or disability or by action of the Compensation Committee.

⁽⁷⁾  Effective January 4, 2010 and January 3, 2011, Mr. Fleming was granted a WEC restricted stock award of 3,070 shares and 2,364 shares, respectively, which began vesting in three equal annual installments on January 4, 2011 and January 3, 2012, respectively. The vesting of the restricted stock may be accelerated in connection with a termination of employment due to a change in control of WEC, death or disability or by action of the Compensation Committee.

⁽⁸⁾  Effective January 4, 2010 and January 3, 2011, Ms. Rappé was granted a WEC restricted stock award of 2,560 shares and 1,968 shares, respectively, which began vesting in three equal annual installments on January 4, 2011 and January 3, 2012, respectively. The vesting of the restricted stock may be accelerated in connection with a termination of employment due to a change in control of WEC, death or disability or by action of the Compensation Committee.

⁽⁹⁾  The number of WEC performance units reported were awarded in 2010 and vest at the end of the three-year performance period ending December 31, 2012. 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 2011 and vest at the end of the three-year performance period ending December 31, 2013. The number of performance units reported and their corresponding value are based upon a payout at the maximum amount.

Option Exercises and Stock Vested for Fiscal Year 2011

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 2011.

(a)	(b)	(c)	(d)		(e)
	Option Awards		Stock Awards
Name	Number of Shares Acquired on Exercise                   (#)	Value Realized on Exercise (1)               ($)	Number of Shares Acquired on Vesting (2) (#)		Value Realized on Vesting (3) (4) ($)
Gale E. Klappa	394,020	5,926,381		15,188		446,679
	—	—		193,964		6,780,979
Frederick D. Kuester	648,000	7,378,682		8,750		268,524
	—	—		102,614		3,587,397
Allen L. Leverett	304,020	4,500,364		2,872		83,661
	—	—		102,614		3,587,397
James C. Fleming	123,000	949,868		2,122 (5)		61,660 (5)
	—	—		37,387		1,307,036
Kristine A. Rappé	—	—		3,792 (5)		111,650 (5)
	—	—		31,267		1,093,084

⁽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 2011 (first line) and the number of WEC performance units that vested as of December 31, 2011, the end of the applicable three-year performance period (second line). The performance units were settled in cash.

⁽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⁾  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, 2011.

⁽⁵⁾  Mr. Fleming and Ms. Rappé deferred $31,889 and $85,591, 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.

32

Pension Benefits at Fiscal Year-End 2011

The following table sets forth information for each named executive officer regarding their pension benefits at fiscal year-end 2011 under WEC’s four different retirement plans discussed below.

(a)	(b)	(c)	(d)	(e)
		Number of Years     Credited Service (1)	Present Value of     Accumulated Benefit (2)(3)	Payments During     Last Fiscal Year
Name	Plan Name	(#)	($)	($)
Gale E. Klappa	WEC Plan	8.67	162,016	—
	SERP A	8.67	1,797,271	—
	Individual Letter Agreement	34.33	17,694,733	—
Frederick D. Kuester	WEC Plan	8.17	149,293	—
	SERP A	8.17	811,719	—
	Individual Letter Agreement	39.33	9,354,637	—
Allen L. Leverett	WEC Plan	8.50	156,676	—
	SERP A	8.50	926,326	—
	Individual Letter Agreement	23.00	1,430,270	—
James C. Fleming	WEC Plan	6.00	106,895	—
	SERP A	6.00	319,120	—
	Individual Letter Agreement	6.00	814,878	—
Kristine A. Rappé	WEC Plan	29.33	813,648	—
	SERP A	29.33	2,322,604	—
	SERP B	—  (4)	669,273	—
	Individual Letter Agreement	—	—	—

⁽¹⁾  Years of service are computed as of December 31, 2011, the pension plan measurement date used for financial statement reporting purposes. Messrs. Klappa, Kuester and Leverett have been credited with 25.66, 31.16 and 14.5 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, Kuester’s and Leverett’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 Mr. Leverett and Ms. Rappé, age 65.

– For Mr. Kuester, age 60.

– For Mr. Fleming, age 66 (current age)

• Discount rate of 5.05%.

• Cash balance interest crediting rate of 5.80%.

• 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, Kuester and Leverett – RP2000 with projection to 2015 – Male.

– Mr. Fleming – N/A.

– Ms. Rappé – RP2000 with projection to 2015 – Female.

⁽³⁾  WEC’s pension benefit obligations to Messrs. Klappa, Kuester and Leverett will be partially offset by pension benefits Messrs. Klappa, Kuester and Leverett are entitled to receive from their former employers. The amounts reported for Messrs. Klappa, Kuester and Leverett 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, Kuester’s and Leverett’s accumulated benefit under all of the plans is $23,609,952, $13,500,041 and $2,826,223, respectively, $3,955,933, $3,184,392 and $312,951 of which we estimate the prior employer is obligated to pay. If Mr. Klappa’s, Mr. Kuester’s or Mr. Leverett’s former employer becomes unable to pay its portion of his respective accumulated pension benefit, WEC may be obligated to pay the total amount.

33

⁽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, Kuester and Leverett is $3,467,936, $1,747,620 and $1,616,433, 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 $1,102,611. This amount represents Mr. Fleming’s 2011 base salary, plus his 2010 STPP award paid in 2011. Because Ms. Rappé’s WEC Plan and SERP A benefits were frozen as of December 31, 2010, the compensation considered for purposes of SERP A is $868,149. The compensation currently considered for purposes of SERP B for Ms. Rappé is $884,662, which represents her average compensation for the 36 highest consecutive months. As of December 31, 2011, Messrs. Klappa, Kuester, Leverett and Fleming, and Ms. Rappé, currently have or are considered to have 34.33, 39.33, 23.00, 6.00 and 29.33 credited years of service, respectively, under the various supplemental plans described below. Mr. Leverett 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 continued to increase until December 31, 2010, at which time it was 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, Kuester’s and Leverett’s total retirement benefits would be determined by the prior plan benefit formula if they were to retire at or after age 60. Both Messrs. Klappa and Kuester turned 60 in 2010. These benefits are payable under the Individual Letter Agreements, not the WEC Plan. These agreements also provide that the prior plan benefit formula will continue to be applied until retirement, with no amounts frozen as of December 31, 2010. 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

34

of 60. Ms. Rappé would receive benefits under either the grandfathered formula or the cash balance plan formula, whichever is higher, if she were to terminate employment prior to attaining the age of 60.

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

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

Messrs. Klappa’s, Kuester’s and Leverett’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, Kuester’s and Leverett’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 vested when Mr. Fleming reached the age of 65 in 2010. The account balance 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, Kuester, Leverett and Fleming did not lose pension earnings by joining the executive management team at WEC and the Company they otherwise would have received from their former employers. Since retirement plans operate in a manner where accrued amounts increase substantially as a participant increases in age and years of service, these officers forfeited substantial pension benefits by coming to work for us. Without providing a means to retain these pension benefits, it would have been difficult for us to attract these officers.

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

The SPP provides for a mandatory lump sum payment upon a change in control 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 the WEC Executive Deferred Compensation Plan and the WEC 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.

35

Nonqualified Deferred Compensation for Fiscal Year 2011

The following table reflects activity by the named executive officers during 2011 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	464,976		131,764		125,712		—		4,241,245
Frederick D. Kuester	596,425		61,744		118,241		—		2,857,780
Allen L. Leverett	115,278		56,398		9,833		—		2,446,457
James C. Fleming	139,378		34,629		53,763		—		1,351,228
Kristine A. Rappé	143,903		26,565		242,008		—		2,709,755

⁽¹⁾  Other than $62,195 and $85,592 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 2011 and/or dividends paid in 2011 on the WEC performance units granted in 2009. The grant date fair value of the WEC performance units granted in 2009 is included in the Summary Compensation Table.

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

⁽³⁾  $3,005,181, $1,506,179, $1,666,314, $824,507 and $380,065 of the reported amounts were reported as compensation in the Summary Compensation Tables in prior information statements for Messrs. Klappa, Kuester, Leverett and Fleming, and Ms. Rappé, respectively.

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 WEC stock option gains, vested awards of WEC 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 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

36

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, 2011:

Name of Fund	Rate of Return (%)	Name of Fund	Rate of Return (%)
Fidelity Balanced Fund	1.68%	Prime Rate	3.25%
Fidelity Diversified International Fund	-13.78%	S&P 500 Fund	2.11%
Fidelity Growth Company Fund	0.67%	Vanguard Intermediate Bond Index	10.74%
Fidelity Low-Priced Stock Fund	-0.06%	Vanguard Mid-Cap Index	-2.11%
MFS Value R4	0.05%	WEC Common Stock Fund	22.93%

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 WEC restricted stock and 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 five years beyond the originally designated payout date. Payout amounts may not be limited in order to deduct such amounts under Section 162(m) of the Internal Revenue Code.

37

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 officer’s aggregate balance in WEC’s Executive Deferred Compensation Plan at fiscal year-end 2011, as reported in column (f) under “Nonqualified Deferred Compensation for Fiscal Year 2011.” 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, 2011 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, 2011, which was within 18 months of a change in control of WEC. The amounts reported in the row titled “Retirement Plans” in each table below are not in addition to the amounts reflected under “Pension Benefits at Fiscal Year-End 2011.” 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, WEC restricted stock and WEC performance units (otherwise, the ability to exercise already vested options within three months of termination) as well as vesting in the SERP and Individual Letter Agreements; and

• if voluntary termination occurs after age 60, such termination is treated as a normal retirement.

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.

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 the named executive officers, 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;

• 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.

38

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 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 of WEC, 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. Kuester’s and Mr. Leverett’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. Kuester’s and Mr. Leverett’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 under his agreement upon the termination of employment for good reason or without cause in the absence of a change in control of WEC.

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, 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. In addition, Ms. Rappé is not entitled to any payment related to additional years of participation in the retirement plans as her benefits under the WEC Plan and SERP A were frozen as of December 31, 2010. 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 in 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; 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 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.

39

Generally, pursuant to the agreements, a change in control of WEC 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		—		—		—		10,592,916		10,592,916		—		—
Additional Pension Credited Service		—		—		—		2,162,995		2,162,995		—		—
Additional 401(k) and EDCP Match		—		—		—		423,717		423,717		—		—
Long-Term Incentive Compensation:
Performance Units		4,448,543		4,448,543		—		8,710,634		8,710,634		8,710,634		8,710,634
Restricted Stock		—		—		—		1,546,138		1,546,138		1,546,138		1,546,138
Options		9,648,331		9,648,331		—		9,648,331		9,648,331		9,648,331		9,648,331
Benefits & Perquisites:
Retirement Plans		19,654,019		19,654,019		19,654,019		16,224,414		16,224,414		19,654,019		8,783,204
Health and Welfare Benefits		—		—		—		45,882		45,882		—		—
Excise Tax Gross-Up		—		—		—		—		9,135,720		—		—
Financial Planning		—		—		—		45,000		45,000		—		—
Outplacement		—		—		—		30,000		30,000		—		—
Death Benefit Only Plan		—		—		—		—		—		—		3,522,504
Total		33,750,893		33,750,893		19,654,019		49,430,027		58,565,747		39,559,122		32,210,811

40

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		—		—		—		3,560,940		5,341,410		—		—
Additional Pension Credited Service		—		—		—		518,835		492,728		—		—
Additional 401(k) and EDCP Match		—		—		—		142,438		213,656		—		—
Long-Term Incentive Compensation:
Performance Units		2,234,643		2,234,643		—		4,291,690		4,291,690		4,291,690		4,291,690
Restricted Stock		—		—		—		824,064		824,064		824,064		824,064
Options		5,046,218		5,046,218		—		5,046,218		5,046,218		5,046,218		5,046,218
Benefits & Perquisites:
Retirement Plans		10,315,649		10,315,649		10,315,649		8,676,488		7,944,095		10,315,649		5,582,897
Health and Welfare Benefits		—		—		—		30,588		45,882		—		—
Excise Tax Gross-Up		—		—		—		—		—		—		—
Financial Planning		—		—		—		30,000		30,000		—		—
Outplacement		—		—		—		30,000		45,000		—		—
Death Benefit Only Plan		—		—		—		—		—		—		2,049,840
Total		17,596,510		17,596,510		10,315,649		23,151,261		24,274,743		20,477,621		17,794,709

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		—		—		—		3,293,652		4,940,478		—		—
Additional Pension Credited Service		—		—		—		629,511		888,422		—		—
Additional 401(k) and EDCP Match		—		—		—		131,746		197,619		—		—
Long-Term Incentive Compensation:
Performance Units		—		2,234,643		—		4,291,690		4,291,690		4,291,690		4,291,690
Restricted Stock		—		—		—		435,881		435,881		435,881		435,881
Options		—		5,046,218		—		5,046,218		5,046,218		5,046,218		5,046,218
Benefits & Perquisites:
Retirement Plans		156,676		2,513,272		156,676		2,478,532		2,484,361		2,513,272		1,756,144
Health and Welfare Benefits		—		—		—		30,588		45,882		—		—
Excise Tax Gross-Up		—		—		—		—		6,347,936		—		—
Financial Planning		—		—		—		30,000		45,000		—		—
Outplacement		—		—		—		30,000		30,000		—		—
Death Benefit Only Plan		—		—		—		—		—		—		1,896,000
Total		156,676		9,794,133		156,676		16,397,818		24,753,487		12,287,061		13,425,933

41

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		—		—		—		—		3,307,833		—		—
Additional Pension
Credited Service		—		—		—		—		587,317		—		—
Additional 401(k) and EDCP Match		—		—		—		—		132,313		—		—
Long-Term Incentive Compensation:
Performance Units		792,543		792,543		—		792,543		1,519,012		1,519,012		1,519,012
Restricted Stock*		—		—		—		—		154,244		154,244		154,244
Options		1,828,882		1,828,882		—		1,828,882		1,828,882		1,828,882		1,828,882
Benefits & Perquisites:
Retirement Plans		1,267,893		1,267,893		1,267,893		1,286,062		1,307,719		1,267,893		1,267,893
Health and Welfare Benefits		—		—		—		—		45,882		—		—
Excise Tax Gross-Up		—		—		—		—		2,434,122		—		—
Financial Planning		—		—		—		—		45,000		—		—
Outplacement		—		—		—		—		30,000		—		—
Death Benefit Only Plan		—		—		—		—		—		—		1,374,600
Total		3,889,318		3,889,318		1,267,893		3,907,487		11,392,324		4,770,031		6,144,631

* Mr. Fleming is retiring effective April 1, 2012. In connection with his retirement and in light of his many contributions to the success of the Company and WEC, on February 24, 2012, the Compensation Committee accelerated the vesting of all unvested shares of WEC restricted stock awarded to Mr. Fleming, consisting of 5,825 shares, effective March 30, 2012. This amount is not included in the table.

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		—		—		—		1,305,219		1,957,829		—		—
Additional Pension
Credited Service		—		—		—		—		—		—		—
Additional 401(k) and EDCP Match		—		—		—		52,209		78,313		—		—
Long-Term Incentive Compensation:
Performance Units		—		660,394		—		1,265,202		1,265,202		1,265,202		1,265,202
Restricted Stock		—		—		—		128,513		128,513		128,513		128,513
Options		1,528,398		1,528,398		—		1,528,398		1,528,398		1,528,398		1,528,398
Benefits & Perquisites:
Retirement Plans		813,648		3,805,524		813,648		4,650,473		4,650,118		3,805,524		2,240,718
Health and Welfare Benefits		—		—		—		30,588		45,882		—		—
Excise Tax Gross-Up		—		—		—		—		2,703,708		—		—
Financial Planning		—		—		—		30,000		30,000		—		—
Outplacement		—		—		—		30,000		30,000		—		—
Death Benefit Only Plan		—		—		—		—		—		—		1,223,643
Total		2,342,046		5,994,316		813,648		9,020,602		12,417,963		6,727,637		6,386,474

42

DIRECTOR COMPENSATION

The following table summarizes total compensation awarded to, earned by or paid to each of the Company’s non-employee directors during 2011. The amounts 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 (2)(3)	Option Awards (4)		Non-Equity Incentive Plan Compensation		Change in Pension Value and Nonqualified Deferred Compensation Earnings		All Other Compensation (5)	Total
	($)	($)	($)		($)		($)		($)	($)
John F. Bergstrom	87,000	75,000		—		—		—	22,348	184,348
Barbara L. Bowles	85,000	75,000		—		—		—	20,555	180,555
Patricia W. Chadwick	75,000	75,000		—		—		—	23,207	173,207
Robert A. Cornog	75,000	75,000		—		—		—	21,947	171,947
Curt S. Culver	85,000	75,000		—		—		—	15,978	175,978
Thomas J. Fischer	90,000	75,000		—		—		—	26,532	191,532
Ulice Payne, Jr.	75,000	75,000		—		—		—	11,462	161,462
Mary Ellen Stanek(1)	—	—		—		—		—	—	—
Frederick P. Stratton, Jr.	75,000	75,000		—		—		—	23,374	173,374

⁽¹⁾  Ms. Stanek was elected to the Board of Directors effective January 19, 2012, and therefore, did not receive any director compensation in 2011.

⁽²⁾  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 2011. Each restricted stock award vests in full on the third anniversary of the grant date.

⁽³⁾  Other than Ms. Stanek, each director held 9,752 shares of WEC restricted stock as of December 31, 2011.

⁽⁴⁾  Directors held the following number of options to purchase WEC common stock as of December 31, 2011, all of which are exercisable: Mr. Cornog (10,000) and Mr. Payne (20,000).

⁽⁵⁾  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 2011, each non-employee director received an annual retainer fee of $75,000. Non-employee chairs of the Finance Committee and the WEC Corporate Governance Committee received a quarterly retainer of $2,500, the chair of the Compensation Committee received a quarterly retainer of $3,000 and the chair of the Audit and Oversight Committee received a quarterly retainer of $3,750. 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 3, 2011, the 2011 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 the WEC 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

43

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.

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 Energy, Wisconsin Electric 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 except Ms. Stanek, were grandfathered.

In December 2011, the Compensation Committee conducted its annual review of non-employee director compensation and determined that the total directors’ compensation package was slightly below the market median. With other companies placing more emphasis on the stock component of the directors’ pay package than they do on the cash retainer, the Committee determined it was appropriate to increase the annual WEC restricted stock award by $5,000. As a result, effective January 1, 2012, the Committee increased the annual WEC restricted stock award from $75,000 to $80,000.

RISK ANALYSIS OF COMPENSATION POLICIES AND PRACTICES

As part of its process to determine the 2011 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 the 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 the 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 the compensation program incentivizes unreasonable risk taking by management.

The Compensation Committee’s stock ownership guidelines require officers who participate in the long-term incentive compensation program to hold an amount of WEC common stock and other equity-related WEC securities that varies depending upon such officers’ level. The guidelines require executive officers to hold common stock and other equity-related securities of WEC having a minimum fair market value ranging from 250% to 400% of base salary. The Committee believes these stock ownership guidelines 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, or relate to, 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.

44

STOCK OWNERSHIP OF DIRECTORS, NOMINEES AND EXECUTIVE OFFICERS

None of the Company’s directors, nominees or executive officers own any 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 March 2, 2012. 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 March 2, 2012. 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.

	Shares Beneficially Owned (1)
Name	Shares Owned (2) (3) (4)(5)		Option Shares         Exercisable Within         60 Days	Total
John F. Bergstrom		19,729	—		19,729
Barbara L. Bowles		30,519	—		30,519
Patricia W. Chadwick		21,126	—		21,126
Robert A. Cornog		29,515	5,000		34,515
Curt S. Culver		8,212	—		8,212
Thomas J. Fischer		30,045	—		30,045
James C. Fleming		9,645	229,400		239,045
Gale E. Klappa		119,689	2,682,960		2,802,649	(6)
Frederick D. Kuester		60,962	620,500		681,462
Allen L. Leverett		38,308	1,208,500		1,246,808
Ulice Payne, Jr.		28,839	20,000		48,839
Kristine A. Rappé		23,202	189,390		212,592
Mary Ellen Stanek		2,371	—		2,371
Frederick P. Stratton, Jr.		37,411	—		37,411
All directors and executive officers as a group (18 persons)		542,622	5,099,628		5,642,250	(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 (37,980), Ms. Bowles (77), Mr. Cornog (51,360), Mr. Culver (50,340), Mr. Fleming (5,925), Mr. Kuester (6,044), Ms. Rappé (36,254), Mr. Stratton (42,305) and all directors and executive officers as a group (230,614). 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 (6,000), Mr. Cornog (15,847), Mr. Klappa (5,000), Mr. Kuester (30,934), Mr. Leverett (19,526), Mr. Stratton (9,200) and all directors and executive officers as a group (86,507).

⁽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 (8,211), Ms. Bowles (8,211), Ms. Chadwick (8,212), Mr. Cornog (8,211), Mr. Culver (8,212), Mr. Fischer (8,212), Mr. Fleming (5,825), Mr. Klappa (54,200), Mr. Kuester (27,436), Mr. Leverett (16,234), Mr. Payne (8,211), Ms. Rappé (4,803), Ms. Stanek (2,371), Mr. Stratton (8,211) and all directors and executive officers as a group (181,966).

⁽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.

45

⁽⁶⁾  Represents approximately 1.2% of total WEC common stock outstanding on March 2, 2012.

⁽⁷⁾  Represents approximately 2.4% of total WEC common stock outstanding on March 2, 2012.

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 2011 fiscal year. To the Company’s knowledge, based on information provided by the reporting persons, all applicable reporting requirements for fiscal year 2011 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 2011 was an officer or employee of the Company during 2011 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, 2011, 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 2011 Annual Financial Statements and Review of Operations, attached hereto as Appendix A.

46

APPENDIX A

WISCONSIN ELECTRIC POWER COMPANY

2011 ANNUAL REPORT TO STOCKHOLDERS

2011 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:

Primary Subsidiary and Affiliates

Bostco Bostco LLC

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

VAPP Valley Power Plant

Other Affiliates

ATC American Transmission Company LLC

ERGSS Elm Road Generating Station Supercritical, LLC

Federal and State Regulatory Agencies

DOE United States Department of Energy

EPA United States Environmental Protection Agency

FERC Federal Energy Regulatory Commission

IRS Internal Revenue Service

MPSC Michigan Public Service 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

CAVR Clean Air Visibility Rule

CO₂ Carbon Dioxide

CSAPR Cross-State Air Pollution Rule

FIP Federal Implementation Plan

MACT Maximum Achievable Control Technology

MATS Mercury and Air Toxics Standards

NODA Notice of Data Availability

NOV Notice of Violation

NO_x Nitrogen Oxide

PM_2.5 Fine Particulate Matter

SIP State Implementation Plan

SO₂ Sulfur Dioxide

A-2

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:

Other Terms and Abbreviations

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

Dodd-Frank Act Dodd-Frank Wall Street Reform and Consumer Protection Act

ERISA Employee Retirement Income Security Act of 1974

Exchange Act Securities Exchange Act of 1934, as amended

Fitch Fitch Ratings

FTRs Financial Transmission Rights

GCRM Gas Cost Recovery Mechanism

GDP Gross Domestic Product

LLC Limited Liability Company

LMP Locational Marginal Price

MISO Midwest Independent Transmission System Operator, Inc.

MISO Energy Markets MISO Energy and Operating Reserves Market

Moody’s Moody’s Investor Service

NYMEX New York Mercantile Exchange

OTC Over-the-Counter

Plan The Wisconsin Energy Corporation Retirement Account Plan

Point Beach Point Beach Nuclear Power Plant

PTF Power the Future

RSG Revenue Sufficiency Guarantee

RTO Regional Transmission Organization

Settlement Agreement Settlement Agreement and Release between Elm Road Services, LLC 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

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

A-3

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 (Exchange Act). 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, on-going legal proceedings, 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,” “goals,” “guidance,” “intends,” “may,” “objectives,” “plans,” “possible,” “potential,” “projects,” “seeks,” “should,” “targets” 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 catastrophic weather-related or terrorism-related damage; cyber-security threats and disruptions to our technology network; 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; unanticipated changes in the cost or availability of materials needed to operate new environmental controls at our electric generating facilities or replace and/or repair our electric and gas distribution systems; 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 demand for electricity and natural gas, including weather and other natural phenomena; the economic climate in our service territories; customer growth and declines; customer business conditions, including demand for their products and services; and energy conservation efforts.

• Timing, resolution and impact of pending and future rate cases and negotiations, including recovery of all costs associated with Wisconsin Energy Corporation’s (Wisconsin Energy)Power the Future (PTF) strategy, as well as costs associated with environmental compliance, renewable generation, transmission service, distribution system upgrades, fuel and the Midwest Independent Transmission System Operator, Inc. (MISO) Energy Markets.

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

• The ability to control costs and avoid construction delays during the development and construction of new environmental controls and renewable generation.

• The impact of recent and future federal, state and local legislative and regulatory changes, including any changes in rate-setting policies or procedures; electric and gas industry restructuring initiatives; transmission or distribution system operation and/or administration initiatives; any required changes in facilities or operations to reduce the risks or impacts of potential terrorist activities or cybersecurity threats; required approvals for new construction, and the siting approval process for new generation and transmission facilities and new pipeline construction; changes to the Federal Power Act and related regulations and enforcement thereof by the Federal Energy Regulatory Commission (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; changes in the application of existing laws and regulations; and changes in the interpretation or enforcement of permit conditions by the permitting agencies.

• Internal restructuring options that may be pursued by Wisconsin Energy.

• Current and future litigation, regulatory investigations, proceedings or inquiries, including FERC matters and IRS audits and other tax matters.

A-4

• Failure of the court to approve the settlement agreement reached in the lawsuit against the Wisconsin Energy Corporation Retirement Account Plan (Plan).

• 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 or us; and our credit ratings.

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

• The financial performance of American Transmission Company LLC (ATC) and its corresponding contribution to our earnings.

• The impact of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) and any regulations promulgated thereunder.

• The impact of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 and any related regulations.

• The effect of accounting pronouncements issued periodically by standard setting bodies, including any changes in regulatory accounting policies and practices and any requirement for U.S. registrants to follow International Financial Reporting Standards (IFRS) instead of Generally Accepted Accounting Principles (GAAP).

• 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.

• The ability to obtain and retain short- and long-term contracts with wholesale customers.

• Foreign governmental, economic, political and currency risks.

• Other business or investment considerations that may be disclosed from time to time in our Securities and Exchange Commission (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	2011		2010		2009		2008		2007
Year Ended December 31
Earnings available for common stockholder (Millions)	$	338.4	$	314.2	$	287.4	$	280.1	$	287.7
Operating Revenues (Millions)
Electric	$	3,211.3	$	2,936.3	$	2,685.0	$	2,660.6	$	2,674.6
Gas		477.3		481.6		564.2		709.2		611.9
Steam		39.0		38.8		39.1		40.3		35.1
Total operating revenues	$	3,727.6	$	3,456.7	$	3,288.3	$	3,410.1	$	3,321.6
At December 31 (Millions)
Total assets	$	11,661.3	$	10,170.7	$	8,871.2	$	8,775.4	$	8,312.8
Long-term debt and capital lease obligations (including current maturities)	$	5,022.0	$	4,053.5	$	3,092.8	$	2,886.4	$	1,990.4

CONSOLIDATED SELECTED QUARTERLY FINANCIAL DATA (Unaudited)

	(Millions of Dollars) (a)
	March				June
Three Months Ended	2011		2010		2011		2010
Total operating revenues	$	1,006.2	$	933.9	$	853.3	$	777.6
Operating income	$	155.3	$	130.8	$	81.2	$	96.2
Earnings available for common stockholder	$	107.2	$	79.1	$	57.8	$	61.1
	September				December
Three Months Ended	2011		2010		2011		2010
Total operating revenues	$	958.3	$	883.2	$	909.8	$	862.0
Operating income	$	143.1	$	139.6	$	94.0	$	122.6
Earnings available for common stockholder	$	100.8	$	89.3	$	72.6	$	84.7

(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 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 LLC (Wisconsin Gas), a natural gas distribution utility, which serves customers throughout Wisconsin; and W.E. Power, LLC (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

We have two primary investment opportunities and earnings streams: our regulated utility business and our investment in ATC.

Our regulated utility business primarily consists of electric generation assets and the electric and gas distribution assets that serve our electric and gas customers. During 2011, our regulated utility earned $473.6 million of operating income. Over the next three years, we expect to invest approximately $1.7 billion in this business to construct renewable generation and environmental projects at our electric generation assets, to update the electric and gas distribution infrastructure, and for other utility projects.

We have a $307.5 million investment in ATC, which represents a 23.0% ownership interest. Our 2011 pre-tax earnings from ATC totaled $54.9 million and we received $43.7 million in dividends from ATC. Over the next three years, we expect to invest approximately $25.8 million in ATC as it continues to upgrade the transmission infrastructure within Wisconsin.

RESULTS OF OPERATIONS

EARNINGS

2011 vs. 2010:  Earnings increased to $338.4 million in 2011 compared with $314.2 million in 2010. Operating income decreased $15.6 million between the comparative periods. The decrease in operating income was primarily caused by increased other operation and maintenance expense and unfavorable weather during 2011 as compared to the prior year, partially offset by wholesale electric pricing increases and electric sales growth.

2010 vs. 2009:  Earnings increased to $314.2 million in 2010 compared with $287.4 million in 2009. Operating income increased $20.3 million between the comparative periods. The increase in operating income was primarily caused by favorable weather during 2010, partially offset by unfavorable recoveries of revenues associated with fuel and purchased power in 2010.

A-7

The following table summarizes our consolidated earnings during 2011, 2010 and 2009:

	2011		2010			2009
	(Millions of Dollars)
Utility Gross Margin
Electric (See below)	$	2,052.1	$	1,844.8		$	1,632.9
Gas (See below)		171.1		165.6			174.5
Steam		23.7		25.6			26.7
Total Gross Margin		2,246.9		2,036.0			1,834.1
Other Operating Expenses
Other operation and maintenance		1,447.6		1,432.5			1,231.7
Depreciation and amortization		220.3		216.2			265.1
Property and revenue taxes		105.4		96.5			99.1
Amortization of gain		—		(198.4	)		(230.7	)
Operating Income		473.6		489.2			468.9
Equity in Earnings of Transmission Affiliate		54.9		52.7			51.9
Other Income and Deductions, net		62.1		39.8			25.8
Interest Expense, net		94.2		101.5			100.3
Income Before Income Taxes		496.4		480.2			446.3
Income Tax Expense		156.8		164.8			157.7
Preferred Stock Dividend Requirement		1.2		1.2			1.2
Earnings Available for Common Stockholder	$	338.4	$	314.2		$	287.4

Electric Utility Gross Margin

The following table compares our electric utility gross margin during 2011 with similar information for 2010 and 2009, including a summary of electric operating revenues and electric sales by customer class:

	Electric Revenues and Gross Margin						MWh Sales
Electric Utility Operations	2011		2010		2009		2011		2010		2009
	(Millions of Dollars)						(Thousands, Except Degree Days)
Customer Class
Residential	$	1,159.2	$	1,114.3	$	977.6		8,278.5		8,426.3		7,949.3
Small Commercial/Industrial		1,006.9		922.2		860.3		8,795.8		8,823.3		8,571.6
Large Commercial/Industrial		763.7		677.1		599.4		9,992.2		9,961.5		9,140.3
Other - Retail		22.9		21.9		21.2		153.6		155.3		156.5
Total Retail		2,952.7		2,735.5		2,458.5		27,220.1		27,366.4		25,817.7
Wholesale - Other		154.0		134.6		116.7		2,024.8		2,004.6		1,529.4
Resale - Utilities		69.5		40.4		47.5		2,065.7		1,103.8		1,548.9
Other Operating Revenues		35.1		25.8		62.3		—		—		—
Total		3,211.3		2,936.3		2,685.0		31,310.6		30,474.8		28,896.0
Fuel and Purchased Power
Fuel		644.4		570.5		518.3
Purchased Power		514.8		521.0		533.8
Total Fuel and Purchased Power		1,159.2		1,091.5		1,052.1
Total Electric Gross Margin	$	2,052.1	$	1,844.8	$	1,632.9
Weather – Degree Days (a)
Heating (6,615 Normal)								6,633		6,183		6,825
Cooling (709 Normal)								793		944		475

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

A-8

Electric Utility Revenues and Sales

2011 vs. 2010:  Our electric utility operating revenues increased by $275.0 million, or 9.4%, when compared to 2010. The most significant factors that caused a change in revenues were:

• 2011 increase of approximately $198.4 million, reflecting the reduction of Point Beach bill credits to retail customers. For information on the bill credits, see Amortization of Gain below.

• Net pricing increases totaling $48.8 million, which includes rates related to our 2010 fuel recovery request that became effective March 25, 2010, and our request to review 2011 fuel costs that became effective April 29, 2011. For information on these rate orders, see Factors Affecting Results, Liquidity and Capital Resources – Rates and Regulatory Matters.

• Unfavorable weather as compared to the prior year that decreased electric revenues by an estimated $40.5 million.

• A $20.4 million increase in revenue from energy sold into the MISO Energy Markets, which was driven by increased MWh generation from the Oak Creek expansion units.

• Net economic growth that increased electric revenues by an estimated $16.2 million as compared to 2010.

• Higher MWh sales to our wholesale customers, which increased revenue by an estimated $10.4 million as compared to 2010.

As measured by cooling degree days, 2011 was 11.8% warmer than normal, but 16.0% cooler than 2010. The 1.8% decrease in residential sales volumes in 2011 is primarily attributable to weather. The estimated 1.8% impact of cooler summer weather on our small commercial/industrial sales volumes was almost entirely offset by an estimated 1.5% increase in sales due to modest economic growth. Increased sales to our largest customers, two iron ore mines, accounted for the increase in sales to our large commercial/industrial customers. If these sales are excluded, sales to our large commercial/industrial customers decreased by approximately 1.2% for 2011 as compared to 2010 primarily because of previously announced plant closings.

2010 vs. 2009:  Our electric utility operating revenues increased by $251.3 million, or 9.4%, when compared to 2009. The most significant factors that caused a change in revenues were:

• Net pricing increases totaling $121.0 million related to Wisconsin and Michigan rate orders that became effective in 2010. For information on these rate orders, see Factors Affecting Results, Liquidity and Capital Resources – Rates and Regulatory Matters.

• Favorable weather that increased electric revenues by an estimated $103.4 million as compared to 2009.

• Net economic growth that increased electric revenues by an estimated $43.0 million as compared to 2009.

• 2010 pricing increases totaling approximately $32.3 million, reflecting the reduction of Point Beach bill credits to retail customers.

As measured by cooling degree days, 2010 was 98.7% warmer than 2009 and 35.2% warmer than normal. Collectively, retail sales to our residential and small commercial/industrial customers, who are more weather sensitive, increased by 4.4%. Sales to our large commercial/industrial customers increased by 9.0% during 2010 as compared to 2009, primarily because of an improving economy. Electric sales to our largest customers, two iron ore mines, which represented approximately 6.9% of our annual sales in 2010, increased significantly for the year. If these sales are excluded, sales to our large commercial/industrial customers increased by 3.2% for 2010 as compared to 2009. The $36.5 million decline in Other Operating Revenues primarily relates to regulatory amortizations during 2010 as compared to 2009.

Electric Fuel and Purchased Power Expenses

2011 vs. 2010:  Our electric fuel and purchased power costs increased by $67.7 million, or approximately 6.2%, when compared to 2010. This increase was primarily caused by a 2.7% increase in total MWh sales as well as increased coal and related transportation costs, partially offset by lower natural gas prices.

2010 vs. 2009:  Our electric fuel and purchased power costs increased by $39.4 million, or approximately 3.7%, when compared to 2009. This increase was primarily caused by a 5.5% increase in total MWh sales, partially offset by a 1.6% decrease in the average cost/MWh between periods. The average cost/MWh was comparable between periods because of a 7.7% increase in generation from our lower cost coal units and a 16.5% decrease in the cost of natural gas used at the Port Washington Generating Station (PWGS), which was sufficient to offset the impact of a 5.7% increase in coal and related transportation costs and the increase in gas generation and purchased power utilized as a result of the increased sales.

A-9

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 2011, 2010 and 2009. Operating revenues and cost of gas sold has declined over the last three years due to the decline in the commodity cost of natural gas during this three year period.

Gas Utility Operations	2011		2010		2009
	(Millions of Dollars)
Operating Revenues	$	477.3	$	481.6	$	564.2
Cost of Gas Sold		306.2		316.0		389.7
Gross Margin	$	171.1	$	165.6	$	174.5

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 Gas Cost Recovery Mechanism (GCRM). The following table compares our gas utility gross margin and therm deliveries by customer class during 2011, 2010 and 2009:

	Gross Margin						Therm Deliveries
Gas Utility Operations	2011		2010		2009		2011		2010		2009
	(Millions of Dollars)						(Millions, Except Degree Days)
Customer Class
Residential	$	114.7	$	111.2	$	117.3		339.4		321.8		349.4
Commercial/Industrial		38.1		35.8		40.2		198.7		184.5		208.8
Interruptible		0.5		0.6		0.6		5.3		5.5		5.9
Total Retail		153.3		147.6		158.1		543.4		511.8		564.1
Transported Gas		16.3		15.5		14.3		294.4		300.8		298.4
Other		1.5		2.5		2.1		—		—		—
Total	$	171.1	$	165.6	$	174.5		837.8		812.6		862.5
Weather – Degree Days (a)
Heating (6,615 Normal)								6,633		6,183		6,825

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

2011 vs. 2010:  Our gas margin increased by $5.5 million, or approximately 3.3%, when compared to 2010 primarily because of an increase in sales volumes as a result of colder winter weather in 2011 as compared to 2010. As measured by heating degree days, 2011 was 7.3% colder than 2010 and 0.3% colder than normal.

Winter weather is the most significant variable for our gas margin.

2010 vs. 2009:  Our gas margin decreased by $8.9 million, or approximately 5.1%, when compared to 2009 primarily because of a decline in sales volumes as a result of warmer winter weather in 2010 as compared to 2009. As measured by heating degree days, 2010 was 9.4% warmer than 2009 and 6.5% warmer than normal.

Other Operation and Maintenance Expense

2011 vs. 2010:  Our other operation and maintenance expense increased by $15.1 million, or approximately 1.1%, when compared to 2010. Higher maintenance costs at one of our natural gas peaking plants, increased spending on forestry work for our electric distribution system and increased costs associated with the amortization of deferred PTF costs related to wholesale and Michigan customers were the primary drivers of the increase.

A-10

Our utility operation and maintenance expenses are influenced by, among other things, labor costs, employee benefit costs, plant outages and amortization of regulatory assets. We expect our 2012 other operation and maintenance expense to decrease by $148 million because of the one year elimination of amortization expense on certain regulatory assets as authorized under our 2012 Wisconsin Rate Case. For additional information on the 2012 rate case, see Factors Affecting Results, Liquidity and Capital Resources – Rates and Regulatory Matters.

2010 vs. 2009:  Our other operation and maintenance expense increased by $200.8 million, or approximately 16.3%, when compared to 2009. The 2010 Public Service Commission of Wisconsin (PSCW) rate case order allowed for pricing increases related to regulatory items including PTF lease costs, bad debt expense and amortization of other deferred costs. We estimate that these items were approximately $72.6 million higher in 2010 as compared to 2009. In addition, operation and maintenance expenses at our power plants increased approximately $63.7 million primarily because of the operation of Oak Creek expansion Unit 1 (OC 1), which was placed in service in February 2010, and higher maintenance costs at our other power plants. We also had increased operation and maintenance expenses of approximately $20.7 million related to increased reliability maintenance in our distribution system in 2010 and responding to damage caused by a larger number of summer storms compared to 2009.

Depreciation and Amortization Expense

2011 vs. 2010:  Depreciation and Amortization expense increased by $4.1 million, or approximately 1.9%, when compared to 2010. This increase was primarily because of an overall increase in utility plant in service.

We expect depreciation and amortization expense to increase in 2012 as a result of an increase in utility plant in service related to the Glacier Hills Wind Park, which went in service in December 2011, and the Oak Creek Air Quality Control System (AQCS) project, which is scheduled to go in service in 2012.

2010 vs. 2009:  Depreciation and Amortization expense decreased by $48.9 million, or approximately 18.4%, when compared to 2009. This decrease was primarily because of new depreciation rates that were implemented in connection with the 2010 PSCW rate case order. The new depreciation rates generally reflect longer lives for our utility assets.

Amortization of Gain

In connection with the September 2007 sale of Point Beach, we reached an agreement 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 were returned to customers in the form of bill credits. The net gain was originally recorded as a regulatory liability, and it was amortized to the income statement as we issued bill credits to customers. When the bill credits were issued to customers, we transferred cash from the restricted accounts to the unrestricted accounts, adjusted for taxes. All bill credits associated with the sale of Point Beach were applied to customers as of December 31, 2010, and as a result, the Amortization of Gain was zero during 2011 as compared to $198.4 million during 2010 and $230.7 million during 2009.

Other Income and Deductions, net

Other Income and Deductions, net	2011		2010		2009
	(Millions of Dollars)
AFUDC - Equity	$	59.2	$	32.4	$	15.9
Gain on Property Sales		2.4		4.5		1.7
Other, net		0.5		2.9		8.2
Total Other Income and Deductions, net	$	62.1	$	39.8	$	25.8

2011 vs. 2010:  Other income and deductions, net increased by approximately $22.3 million, or 56.0%, when compared to 2010. This increase primarily relates to increased AFUDC - Equity related to the construction of the Oak Creek AQCS project and the Glacier Hills Wind Park.

During 2012, we expect to see a reduction in AFUDC - Equity with the completion of the Glacier Hills Wind Park in December 2011 and the expected completion of the Oak Creek AQCS project by the end of 2012.

2010 vs. 2009:  Other income and deductions, net increased by approximately $14.0 million, or 54.3%, when compared to 2009. This increase primarily relates to increased AFUDC - Equity related to the construction of the Oak Creek AQCS project.

A-11

Interest Expense, net

Interest Expense, net	2011		2010		2009
	(Millions of Dollars)
Gross Interest Costs	$	118.9	$	115.0	$	106.9
Less: Capitalized Interest		24.7		13.5		6.6
Interest Expense, net	$	94.2	$	101.5	$	100.3

2011 vs. 2010:  Our gross interest costs increased by $3.9 million, or 3.4%, during 2011, primarily because of higher average long-term debt balances compared to 2010. In September 2011, we issued $300 million of long-term debt and used the net proceeds to repay short-term debt and for other general corporate purposes. Our capitalized interest increased by $11.2 million primarily because of increased capital expenditures related to our Oak Creek AQCS project and the Glacier Hills Wind Park. As a result, our net interest expense decreased by $7.3 million, or 7.2%, as compared to 2010.

During 2012, we expect to see higher net interest expense because of a reduction in capitalized interest as a result of the Glacier Hills Wind Park project going in service in December 2011 and the expected completion of the Oak Creek AQCS project by the end of 2012.

2010 vs. 2009:  Our gross interest costs increased by $8.1 million, or 7.6%, during 2010, primarily because of higher long-term debt balances compared to 2009. Our capitalized interest increased by $6.9 million primarily because of increased capital expenditures related to our Oak Creek AQCS project. As a result, our net interest expense increased by $1.2 million, or 1.2%, as compared to 2009.

Income Tax Expense

2011 vs. 2010:  Our effective income tax rate was 31.6% in 2011 compared with 34.3% in 2010. This reduction in our effective tax rate was primarily the result of increased AFUDC - Equity. For further information regarding income taxes, see Note G – Income Taxes in the Notes to Consolidated Financial Statements. We expect our 2012 annual effective tax rate to be between 34% and 35%.

2010 vs. 2009:  Our effective income tax rate was 34.3% in 2010 compared with 35.3% in 2009. This reduction in our effective tax rate was primarily the result of increased AFUDC - Equity and increased production activities tax deductions.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

The following table summarizes our cash flows during 2011, 2010 and 2009:

	2011			2010			2009
	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$	543.9		$	425.2		$	226.6
Investing Activities	$	(762.1	)	$	(470.8	)	$	(333.6	)
Financing Activities	$	207.6		$	50.6		$	96.9

Operating Activities

2011 vs. 2010:  Cash provided by operating activities was $543.9 million during 2011, which was an increase of $118.7 million over 2010. The largest increases in cash provided by operating activities related to higher net income, higher deferred income tax benefits and the elimination of the amortization of the gain on the sale of Point Beach. Combined these items totaled $604.7 million during 2011 as compared to $186.6 million during 2010. The largest reduction in cash provided by operating activities related to our contributions to our qualified benefit plans. During 2011, we contributed $275.1 million to our qualified benefit plans. We made no contributions to our qualified plans during 2010.

A-12

2010 vs. 2009:  Cash provided by operating activities was $425.2 million during 2010, which was an increase of $198.6 million over 2009. This increase is primarily related to a $283.8 million contribution to our qualified benefit plans in 2009. No such contributions were made in 2010. This increase was partially offset by an increase in cash paid for taxes during 2010.

Investing Activities

2011 vs. 2010:  Cash used in investing activities was $762.1 million during 2011, which was $291.3 million higher than 2010. This increase in cash used primarily reflects changes in restricted cash and increased capital expenditures. During 2011, our restricted cash increased by $37.2 million primarily because of the nuclear fuel settlement we received from the United States Department of Energy (DOE). During 2010, our restricted cash decreased by $186.2 million due to the release of restricted cash related to the Point Beach bill credits. See Nuclear Operations in this report for additional information regarding the settlement with the DOE. In addition, capital expenditures increased by approximately $89.3 million during 2011 as compared to 2010 primarily due to increased spending related to the construction of the Oak Creek AQCS project and the Glacier Hills Wind Park in 2011 as compared to 2010.

2010 vs. 2009:  Cash used in investing activities was $470.8 million during 2010, which was $137.2 million higher than 2009. This increase in cash used in investing activities primarily reflects an increase in capital expenditures of $136.2 million related to our Glacier Hills Wind Park and continued construction of the Oak Creek AQCS project. The increase in investing activities also reflects a reduction in the release of restricted cash related to the Point Beach bill credits.

Financing Activities

The following table summarizes our cash flows from financing activities:

	2011			2010			2009
	(Millions of Dollars)
Dividends to Wisconsin Energy	$	(239.6	)	$	(179.6	)	$	(179.6	)
Capital Contribution from Wisconsin Energy		—			100.0			100.0
Net Increase in Debt		440.7			117.9			176.2
Other		6.5			12.3			0.3
Cash Provided by Financing	$	207.6		$	50.6		$	96.9

2011 vs. 2010:  Cash provided by financing activities was $207.6 million during 2011 compared to $50.6 million provided by financing activities during 2010. During 2011, we issued $300 million of long-term debt and used the net proceeds to repay short-term debt and for other general corporate purposes. For additional information on the debt issuance, see Note I – Long-Term Debt and Capital Lease Obligations in the Notes to Consolidated Financial Statements. Partially offsetting the increase in debt is the payment of a $60 million special dividend to Wisconsin Energy and not receiving a capital contribution from Wisconsin Energy in 2011 compared to a $100 million capital contribution in 2010.

2010 vs. 2009:  Cash provided by financing activities was $50.6 million during 2010 compared to $96.9 million provided by financing activities during 2009. The decrease in financing cash flows is primarily related to changes in our debt levels. In 2010, we increased our debt levels by $117.9 million compared to an increase of $176.2 million during 2009.

CAPITAL RESOURCES AND REQUIREMENTS

Liquidity

We anticipate meeting our capital requirements during 2012 and beyond 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 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.

A-13

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.

As of December 31, 2011, we had approximately $494.1 million of available, undrawn lines under our bank back-up credit facility that was entered into in December 2010 and approximately $352.0 million of commercial paper outstanding that was supported by the available lines of credit. During 2011, our maximum commercial paper outstanding was $370.5 million with a weighted-average interest rate of 0.21%. For additional information regarding our commercial paper balances during 2011, see Note J – Short-Term Debt in the Notes to Consolidated Financial Statements.

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, 2011:

Total Facility		Letters     of Credit		Credit Available		Facility Expiration
(Millions of Dollars)
	$            500.0	$	5.9	$	494.1		December 2013

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	2011				2010
	(Millions of Dollars)
Common Equity	$	3,177.1	36.9	%	$	3,065.1	41.5	%
Preferred Stock		30.4	0.4	%		30.4	0.4	%
Long-Term Debt (a)		2,267.6	26.3	%		1,970.9	26.7	%
Capital Lease Obligations (a)		2,754.4	32.0	%		2,082.6	28.2	%
Short-Term Debt (b)		378.8	4.4	%		238.1	3.2	%
Total	$	8,608.3	100.0	%	$	7,387.1	100.0	%

(a) Includes current maturities

(b) Includes subsidiary note payable to Wisconsin Energy

For a summary of the interest rate, maturity and amount outstanding of each series of our long-term debt on a consolidated basis, see the Consolidated Statements of Capitalization.

We recorded an increase of approximately $650 million to our capital lease obligations in connection with Oak Creek expansion Unit 2(OC 2) being placed in service in January 2011. For additional information, see Note I – Long-Term Debt and Capital Lease Obligations in the Notes to Consolidated Financial Statements.

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, 2011, 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.

Bonus Depreciation Provisions

In December 2010, the President of the United States signed tax legislation extending the bonus depreciation rules to certain projects placed in service in 2010, 2011 and 2012. As a result of this extension, we recognized increased federal tax depreciation in 2010 and 2011 relating to assets placed in service during those years, including the Glacier Hills Wind Park. In addition, we also anticipate an increase in tax depreciation in 2012 for assets placed in service during 2012, including the Oak Creek AQCS project. As a result of the increased tax depreciation in 2011 and 2012, we will not make federal income tax payments for 2011 and do not anticipate making federal income tax payments for 2012.

A-14

Credit Rating Risk

We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. We do have certain agreements in the form of commodity contracts and employee benefit plans that could require collateral or a termination payment in the event of a credit rating change to below BBB- at S&P and/or Baa3 at Moody’s. As of December 31, 2011, we estimate that the collateral or the termination payments required under these agreements totaled approximately $181.7 million. Generally, collateral may be provided by a guaranty, letter of credit or cash. We also have commodity contracts that in the event of a credit rating downgrade could result in a reduction of our unsecured credit granted by counterparties.

In addition, access to capital markets at a reasonable cost is determined in large part by credit quality. Any credit ratings downgrade could impact our ability to access capital markets.

In December 2011, Moody’s affirmed our ratings (commercial paper, P-1; senior unsecured, A2) and our stable ratings outlook.

In June 2011, S&P affirmed our ratings (commercial paper, A-2; senior unsecured, A-). S&P also revised our ratings outlook from positive to stable in June 2011, after revising our ratings outlook from stable to positive in March 2011.

In June 2011, Fitch affirmed our ratings (commercial paper, F1; senior unsecured, A+) and our stable ratings outlook.

Subject to other factors affecting the credit markets as a whole, we believe our current 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. Any rating can be revised upward or downward or withdrawn at any time by a rating agency.

Capital Requirements

Capital Expenditures:  Our estimated 2012, 2013 and 2014 capital expenditures are as follows:

Capital Expenditures	2012		2013		2014
	(Millions of Dollars)
Renewable	$	160.6	$	24.4	$	—
Environmental		71.0		43.3		38.8
Base Spending		366.1		494.5		466.3
Total	$	597.7	$	562.2	$	505.1

Base spending primarily consists of upgrading our electric and gas distribution systems. Our actual future long-term capital requirements may vary from these estimates because of changing environmental and other regulations such as air quality standards, renewable energy standards and electric reliability initiatives that impact us.

Investments in Outside Trusts:  We use outside trusts to fund our pension and certain other post-retirement obligations. These trusts had investments of approximately $1.2 billion as of December 31, 2011. These trusts hold investments that are subject to the volatility of the stock market and interest rates.

During 2011, we contributed $234.1 million to our qualified pension plans and $41.0 million to our qualified Other Post-Retirement Employee Benefit (OPEB) plans. We did not make contributions to the plans during 2010 as they were 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 M – Benefits in the Notes to Consolidated Financial Statements.

Off-Balance Sheet Arrangements:  We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support commodity contracts and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors. For further information, see Note F – Variable Interest Entities and Note N – Guarantees in the Notes to Consolidated Financial Statements in this

A-15

report.

Contractual Obligations/Commercial Commitments:  We have the following contractual obligations and other commercial commitments as of December 31, 2011:

	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)	$	4,168.1	$	119.9	$	810.5	$	478.0	$	2,759.7
Capital Lease Obligations (c)		10,684.7		406.7		817.9		874.0		8,586.1
Operating Lease Obligations (d)		63.3		16.3		10.4		7.6		29.0
Purchase Obligations (e)		12,866.8		863.6		1,291.9		942.8		9,768.5
Other Long-Term Liabilities (f)		98.1		97.0		0.8		0.3		—
Total Contractual Obligations	$	27,881.0	$	1,503.5	$	2,931.5	$	2,302.7	$	21,143.3

(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.

(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 construction, information technology and other services for utility operations. This includes the power purchase agreement for Point Beach.

(f) Other Long-Term Liabilities include our portion of the expected 2012 supplemental executive retirement plan obligation. For additional information on employer contributions to Wisconsin Energy’s benefit plans, see Note M – 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 because we are not able to make a reasonably reliable estimate as to the amount and period of related future payments at this time. 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 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. As of December 31, 2011, our regulatory assets totaled $1,256.1 million and our regulatory liabilities totaled $671.2 million.

A-16

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. Effective January 1, 2011, the PSCW implemented new fuel rules which allow for a deferral of prudently incurred fuel costs that fall outside of a symmetrical band (plus or minus 2%). Under the rules, any over or under-collection of fuel costs deferred at the end of the year would be incorporated into fuel cost recovery rates in future years. For information regarding the fuel rules, see Rates and Regulatory Matters – Wisconsin Fuel Rules.

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. Higher natural gas costs may also lead to increased energy efficiency investments by our customers to reduce utility usage and/or fuel substitution.

As part of its November 2011 rate order, the PSCW authorized continued use of the escrow method of accounting for bad debt costs through December 31, 2012. The escrow method of accounting for bad debt costs allows for deferral of Wisconsin residential bad debt expense that exceeds or is less than amounts allowed in rates.

As a result of our GCRM, our gas utility operations 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. For information concerning our natural gas utility’s GCRM, see Rates and Regulatory Matters.

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 2011, 2010 and 2009, 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, 2011. 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, 2011 of our outstanding portfolio of commercial paper and variable rate long-term debt. As of December 31, 2011, we had $352.0 million of commercial paper outstanding with a weighted-average interest rate of 0.24% 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 $5.0 million.

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, 2011 was approximately:

	Millions of Dollars
Pension trust funds	$	1,018.1
Other post-retirement benefits trust funds	$	173.9

For 2012, the expected long-term rate of return on plan assets is 7.25% and 7.5%, respectively, for the pension and OPEB plans.

A-17

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.

Wisconsin Energy consults with its investment advisors on an annual basis to help it 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.

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

All of the PTF units have been placed into service and are positioned to provide a significant portion of our future generation needs. The PTF units include Port Washington Generating Station Unit 1 (PWGS 1), Port Washington Generating Station Unit 2 (PWGS 2), OC 1 and OC 2. The following table identifies 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
OC 1	February 2010	$	1,354 million
OC 2	January 2011	$	662 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 We Power’s ownership percentage.

We are leasing the PTF units from We Power under long-term leases. We are recovering the lease payments associated with PWGS 1, PWGS 2 and OC 1 in our rates as authorized by the PSCW, the Michigan Public Service Commission (MPSC) and FERC. We are recovering the lease payment associated with OC 2 as authorized by the PSCW and FERC, and have requested authorization from the MPSC in the rate case filed in July 2011.

Background:  The PSCW issued orders granting Certificates of Public Convenience and Necessity (CPCN) for the construction of the PWGS and the Oak Creek expansion in 2002 and 2003, respectively.

PWGS consists of two natural gas-fired combined cycle generating units on the site of our former Port Washington Power Plant, 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.

The Oak Creek expansion consists of two coal-fired generating units located adjacent to the site of our existing Oak Creek Power Plant. OC 1 and OC 2 were placed into service on February 2, 2010 and January 12, 2011, respectively. The PSCW set the total cost for the two units at $2.191 billion. We Power estimates that the final cost of the Oak Creek expansion is approximately $181 million, or 8.3%, over the amount initially approved by the PSCW, of which its share is approximately $154 million. The additional amount includes the amounts payable to Bechtel Power Corporation (Bechtel) pursuant to the Settlement Agreement. The order approving the Oak Creek expansion provides 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

A-18

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 event of loss. In addition, the leases provided for a guaranteed in-service date of September 29, 2009 for OC 1 and September 29, 2010 for OC 2, and imposed liquidated damages of $250,000 per day, of which the amount payable to us by Elm Road Generating Station Supercritical, LLC (ERGSS) is approximately $208,350 per day, for failure to achieve the guaranteed in-service date unless the delays resulted from force majeure conditions or an excused event. In light of the weather delays incurred on the project and other factors, we, along with ERGSS, expect to request authorization from the PSCW to recover all costs associated with the units.

ERGSS was entitled to receive its share of $250,000 per day from Bechtel under the contract with Bechtel for each day Bechtel failed to achieve the guaranteed in-service dates of September 29, 2009 and September 29, 2010, unless the delays resulted from force majeure conditions or excused events. Pursuant to the terms of the Settlement Agreement and a change order signed concurrent with the turnover of OC 2, ERGSS granted Bechtel total schedule relief of 120 days for OC 1 and 81 days for OC 2. Subject to PSCW review, all liquidated damages collected by us from ERGSS are for the benefit of our customers.

Lease Terms:  The PSCW approved the lease agreements and related documents under which we will staff, operate and maintain PWGS 1, PWGS 2, OC 1 and OC 2. Key terms of the leased generation contracts are as follows:

PWGS 1 & PWGS 2

• 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 order, which do not include the key financial terms.

OC 1 & OC 2

• 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;

• 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 order, which do not include the key financial terms.

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 86% of our electric revenues are regulated by the PSCW, 7% are regulated by the MPSC and the balance of our electric revenues is regulated by FERC. In Wisconsin, a general rate case is typically filed every two years. 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/.

A-19

2012 Wisconsin Rate Case:  On May 26, 2011, we filed an application with the PSCW to initiate rate proceedings. In lieu of a traditional rate proceeding, we requested an alternative approach, which results in no increase in 2012 base rates for our customers. In 2012, we would seek base rate increases to be effective in 2013. In order for us to proceed under this alternative approach, we requested that the PSCW issue an order that:

• Authorizes us to suspend the amortization of $148 million of regulatory costs during 2012, with amortization to begin again in 2013.

• Authorizes $148 million of carrying costs and depreciation on previously authorized air quality and renewable energy projects, effective January 1, 2012.

• Authorizes the refund of $26 million of net proceeds from our settlement of the spent nuclear fuel litigation with the DOE.

• Authorizes us to reopen the rate proceeding in 2012 to address, for rates effective in 2013, all issues set aside during 2012, including the determination of the final approved construction costs for the Oak Creek expansion.

• Schedules a proceeding to establish a 2012 fuel cost plan.

On October 6, 2011, the PSCW approved our proposal as filed. We received a final written order from the PSCW on November 3, 2011. For information related to the proceeding to establish a 2012 fuel cost plan, see 2012 Fuel Recovery Request below. We expect to initiate a traditional rate case filing in early 2012 for new electric, gas and steam rates to be effective in January 2013.

2012 Michigan Rate Case: On July 5, 2011, we filed a $17.5 million rate increase request with the MPSC, primarily to recover the costs of environmental upgrades and OC 2. Michigan law allows utilities, upon the satisfaction of certain conditions, to self-implement a rate increase request, subject to refund with interest. Therefore, in January 2012, we implemented a $5.7 million interim electric base rate increase. This increase is offset by a refund of $2.7 million of net proceeds from our settlement of the spent nuclear fuel litigation with the DOE, resulting in a net $3.0 million rate increase. In addition, approximately $2.0 million of renewable costs were included in our Michigan fuel recovery rate effective January 1, 2012. Therefore, the total self-implementation was $7.7 million. A final decision from the MPSC is expected in July 2012.

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 Milwaukee Downtown (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, which was partially offset by bill credits in 2010 and included a decrease in base fuel revenues of approximately $111.0 million, or a fuel rate component decrease of 13.8%;

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

• A decrease of approximately $0.4 million (1.65%) for our 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 authorized return on equity from 10.75% to 10.4%.

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

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

• Certain regulatory assets that were scheduled to be fully amortized over four years are instead being amortized over eight years; and

• We will continue to receive AFUDC on 100% of Construction Work in Progress for the environmental control projects at our Oak Creek Power Plant and at Edgewater Generating Unit 5, and on the Glacier Hills Wind Park. We sold our interest in Edgewater Generating Unit 5 in March 2011 and completed construction of Glacier Hills in December 2011.

A-20

As part of its final decision in the 2010 rate case, the PSCW authorized us to reopen the docket in 2010 to review updated 2011 fuel costs. On September 3, 2010, we filed an application with the PSCW to reopen the docket to review updated 2011 fuel costs and to set rates for 2011 that reflect those costs. We requested an increase in 2011 Wisconsin retail electric rates of $38.4 million, or 1.4%, related to the increase in 2011 monitored fuel costs as compared to the level of monitored fuel costs then embedded in rates. In December 2010, we reduced our request by approximately $5.2 million. Adjustments by the PSCW reduced the request by an additional $7.8 million. The PSCW issued its final decision, which increased annual Wisconsin retail rates by $25.4 million effective April 29, 2011. The net increase was being driven primarily by an increase in the delivered cost of coal.

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. In December 2009, the MPSC approved our modified self-implementation plan to increase electric rates in Michigan by approximately $12 million effective upon commercial operation of OC 1, which occurred on February 2, 2010. On July 1, 2010, the MPSC issued the final order, approving an additional increase of $11.5 million effective July 2, 2010. The combined total increase is $23.5 million annually, or 14.2%. In August 2010, our largest customers, two iron ore mines, filed an appeal with the MPSC regarding this rate order. In October 2010, the MPSC ruled on the mines’ appeal and reduced the rate increase by approximately $0.3 million annually, effective November 1, 2010. In November 2010, the mines filed a Claim of Appeal of the October 2010 order with the Michigan Court of Appeals. In December 2010, the MPSC filed a Motion for Remand with the Court of Appeals. In March 2011, the Court of Appeals denied the Motion for Remand. All briefs have been filed and the case is awaiting scheduling of oral argument, which we expect to occur in the first quarter of 2012.

Limited Rate Adjustment Requests

2012 Fuel Recovery Request:  On August 3, 2011, we filed a $50 million rate increase request with the PSCW to recover forecasted increases in fuel and purchased power costs. The primary reasons for the increase are projected higher coal, coal transportation and purchased power costs. This filing was made under the new Wisconsin fuel rules which require annual fuel cost filings. On January 5, 2012, the PSCW issued an order which provided for an increase in fuel costs of approximately $26 million, offset by approximately $26 million from the settlement with the DOE regarding the storage of spent nuclear fuel, resulting in no change in customer rates.

2010 Fuel Recovery Request:  In February 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 was driven primarily by increases in the price of natural gas compared to the forecasted prices included in the 2010 PSCW rate case order, changes in the timing of plant outages and increased MISO costs. Effective March 25, 2010, the PSCW approved an annual increase of $60.5 million in Wisconsin retail electric rates on an interim basis. On April 28, 2011, the PSCW approved the final increase with no changes.

2009 Fuel Order:  Under the fuel rules in effect in 2008 and 2009, a Wisconsin utility could request an emergency rate increase if projected costs fell outside of a prescribed range of costs which was plus or minus 2% of the fuel rate approved in a general rate proceeding.

In March 2008, we filed a request for an emergency rate increase with the PSCW to recover forecasted increases in fuel and purchased power costs. The PSCW authorized a total increase of $118.9 million. In April 2009, we filed a request with the PSCW to decrease annual Wisconsin retail electric rates by $67.2 million because we forecasted that our monitored fuel cost for 2009 would fall outside the range prescribed by the PSCW and would be less than the fuel cost reflected in then authorized rates. The PSCW approved this request on an interim basis with rates effective May 1, 2009.

The PSCW staff audited the fuel costs for the year 2009 to determine whether we collected excess revenues as a result of the fuel surcharges that were in place in 2008 and 2009. Under the fuel rules, if a utility collects excess revenues in a year in which it implemented an emergency fuel surcharge, it is required to refund to customers the over-collected fuel surcharge revenue up to the amount of the excess revenues. In February 2011, the PSCW closed out its review of this matter and determined that we did not collect any excess revenues.

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 $750 million ($900 million including AFUDC). The cost of constructing these facilities is included in our estimates of the costs to implement the Consent Decree with the United States Environmental Protection Agency (EPA).

A-21

Wisconsin Fuel Rules:  Embedded within our base rates is an amount to recover fuel costs. New fuel rules adopted in December 2010 require the company to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel costs that are outside of the utility’s symmetrical fuel cost tolerance, which the PSCW set at plus or minus 2% of the utility’s approved fuel cost plan. Fuel cost plans approved by the PSCW after January 1, 2011 are subject to the new rules. The deferred fuel costs are subject to an excess revenues test.

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, 2011, we had $118.3 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. As part of its January 2010 rate order, the PSCW approved changes to the GCRM. The GCRM now uses a modified one for one method that 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.

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 estimate that the new depreciation rates did not 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%. As of December 31, 2011, we are in compliance with the Wisconsin renewable energy percentage 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. To comply with increasing requirements, we have constructed and contracted for several hundred megawatts of wind generation and are in the process of constructing approximately 50 MW of biomass fueled generation. With the commercial operation of the Glacier Hills Wind Park in December 2011 and assuming the biomass project is completed on schedule, we expect to be in compliance with Act 141 through the year 2016. To remain in compliance with Act 141, we would need to construct or contract for the equivalent of approximately 400 MW of additional wind generating capacity beyond 2016. See Renewable Energy Portfolio discussion below for additional information regarding the development of renewable energy generation.

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 Wisconsin Department of Administration back to the PSCW and/or contracted third parties. In addition, Act 141 required that 1.5% of utilities’ annual operating revenues be used to fund these programs in 2011. The funding required by Act 141 decreased to 1.2% of annual operating revenues in 2012.

A-22

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:  The Blue Sky Green Field wind farm project, which has 88 turbines with an installed capacity of 145 MW, commenced commercial operation in May 2008. The Glacier Hills Wind Park, which has 90 turbines with an installed capacity of 162 MW, commenced commercial operation in December 2011. We estimate that the final cost of the Glacier Hills Wind Park will be approximately $355 million.

We are constructing a biomass-fueled power plant at Domtar Corporation’s Rothschild, Wisconsin paper mill site. Wood waste and wood shavings will be used to produce approximately 50 MW of renewable electricity and will also support Domtar’s sustainable papermaking operations. Construction commenced on June 27, 2011. We currently expect to invest between $245 million and $255 million, excluding AFUDC, in the plant and we expect the plant to be completed during the fall of 2013.

Pursuant to the National Defense Authorization Act (NDAA), which was passed in December 2011, utilities are now able to elect to receive a cash grant for renewable energy projects without the effect of normalization for income tax purposes. We are currently evaluating the impact of the NDAA on whether we pursue federal production tax credits or grants for certain of our renewable generation projects.

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 2011 and 2010. 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 2012. However, extremely hot weather, unexpected equipment failure or unavailability could require us to call upon load management procedures.

ENVIRONMENTAL MATTERS

Overview

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 Sulfur Dioxide (SO₂), Nitrogen Oxide (NO_x), fine particulates, mercury and greenhouse gas emissions; (2) water discharges; (3) disposal of coal combustion by-products such as fly ash; and (4) remediation of impacted properties, including former manufactured gas plant sites.

We are continuing to pursue a proactive strategy to manage our environmental compliance obligations, including: (1) developing additional sources of renewable electric energy supply; (2) reviewing water quality matters such as discharge limits and cooling water requirements and implementing improvements to our cooling water intake systems as needed; (3) adding emission control equipment to existing facilities to comply with new ambient air quality standards and federal clean air rules; (4) implementing a Consent Decree with the EPA to reduce emissions of SO₂ and NO_x by more than 65% by 2013; (5) continuing the beneficial use of ash and other solid products from coal-fired generating units; and (6) conducting the clean-up of former manufactured gas plant sites.

Air Quality

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

A-23

Wisconsin approved the amended Consent Decree and entered it in October 2007. The Consent Decree was further amended in January 2012 to change the point of air monitoring at the Oak Creek Power Plant to accommodate the AQCS scheduled to begin service in 2012. For further information, see Note Q – Commitments and Contingencies in the Notes to Consolidated Financial Statements.

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. The EPA has since redesignated three of these counties - Kewaunee, Manitowoc and Door - in attainment with the standard, and has made a finding that the remaining seven counties have achieved attainment with the standard. The EPA has stated, however, that Wisconsin must revise a portion of its State Implementation Plan (SIP) relating to volatile organic compounds, which do not apply to our facilities, before these seven counties can be formally redesignated. Pending redesignation, we will continue to be subject to more stringent permitting standards for new or revised facilities in the affected seven counties.

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. However, in September 2011, President Obama requested the EPA to delay the reconsideration of the 8-hour ozone standard until 2013, and the EPA began implementing the 2008 standard. The EPA has stated that it plans to finalize the designations under the 2008 ozone standard by May 31, 2012. The EPA has preliminarily designated Waukesha, Washington, Milwaukee and Racine Counties as being in attainment with the standard. Currently, the only counties in Wisconsin that are proposed for non-attainment are Kenosha and Sheboygan Counties.

Fine Particulate Standard:  In December 2006, a more restrictive federal standard for fine particulate matter (PM_2.5) became effective; however, in February 2009, the U.S. Court of Appeals for the D.C. Circuit issued a decision on the revised standard and remanded it back to the EPA for revision. 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 has submitted a request to the EPA to redesignate these three counties as being in attainment with the 2006 standard. If the EPA denies this request, Wisconsin will be required 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 on our operations, if any, cannot be determined at this time, particularly given the EPA’s continued efforts to revise the 2006 standard in light of the D.C. Circuit Court’s decision.

In a related matter, in August 2010, the Wisconsin Natural Resources Board adopted rules to reflect changes made by the EPA in their regulations regarding the regulation of PM_2.5. The rule became effective on January 1, 2011. PM_2.5 is proposed to be included as a pollutant used to determine whether a facility is a major source of air pollution. Additionally, any modifications to an existing facility that would result in increases in PM_2.5 emissions could trigger pre-construction permitting requirements, including requirements to control emissions to levels which represent best available control technology or lowest achievable emission rate.

Sulfur Dioxide Standard:  In June 2010, the EPA issued new hourly SO₂ National Ambient Air Quality Standards that became effective in August 2010. These standards, as modified, represent a significant change from the previous SO₂ standards. The new standards, among other things, require attainment designations to be based on modeling rather than monitoring. Traditionally, attainment designations were based on monitored data.

Various parties have submitted judicial and administrative challenges to this rule, and litigation is pending in the U.S. Court of Appeals for the D.C. Circuit challenging, among other things, the stringency of the standards and the EPA’s plans to require attainment designations to be based on modeling.

If the new standards remain in place, we believe that we would not need to make significant capital expenditures at the majority of our generation units because of prior investments in pollution control equipment and technology. However, we believe that the new standards may require us to retire our Presque Isle Power Plant in the Upper Peninsula of Michigan early because the cost of installing new pollution control equipment at this plant may exceed other alternatives we are currently studying, which include investing in the transmission system in that region, adding new air quality controls and possible shared ownership of the Presque Isle Power Plant. The new standards may also require us to make modifications at some of our smaller generation units.

Nitrogen Dioxide Standard:  In January 2010, the EPA announced a new hourly Nitrogen Dioxide standard, which became effective in April 2010. We are unable to predict the impact on the operation of our coal-fired generation facilities until final attainment designations are made and until any potential additional rules are adopted.

Mercury and Other Hazardous Air Pollutants:  On December 16, 2011, the EPA issued the final utility Maximum Achievable Control Technology (MACT) rule (referred to as the Mercury and Air Toxics Standard (MATS) rule), which imposes stringent limitations on numerous hazardous air pollutants, including mercury, from coal and oil-fired electric

A-24

generating units. While we are continuing to evaluate the impact of the rule on the operation of our existing coal-fired generation facilities, as well as alternatives for complying with the rule, we currently estimate our cost to comply with this rule will be approximately $16 million. Based upon our review, the Valley Power Plant (VAPP) and Presque Isle Power Plant may require additional modifications. In addition, we believe that our clean air strategy, including the environmental upgrades that have already been constructed and that are currently under construction at our other plants, positions those plants well to meet the rule’s requirements.

Cross-State Air Pollution Rule:  On August 8, 2011, the EPA issued a final rule, the Cross-State Air Pollution Rule (CSAPR), formerly known as the Clean Air Transport Rule. This rule was proposed in 2010 to replace the Clean Air Interstate Rule (CAIR), which had been remanded to the EPA in 2008. The stated purpose of the CSAPR is to limit the interstate transport of emissions of NO_x and SO₂ that contribute to fine particulate matter and ozone non-attainment in downwind states through a proposed allocation scheme. On October 14, 2011, the EPA published proposed revisions to CSAPR, which if finalized, would delay the implementation date for certain penalty provisions that could potentially impact the Presque Isle Power Plant and increase the number of allowances issued to the states of Michigan and Wisconsin. Even with these proposed revisions, however, the Presque Isle Power Plant may not have been allocated sufficient allowances to meet its obligations to operate and provide stability to the transmission system in the Upper Peninsula of Michigan. This situation could then put the plant at risk for certain penalties under the rule.

The rule was scheduled to become effective January 1, 2012. However, we and a number of other parties sought judicial review of the rule, and on December 30, 2011, the U.S. Court of Appeals for the District of Columbia granted a motion to stay CSAPR pending judicial review of the rule. While the CSAPR is stayed, the CAIR will remain in effect. We are unable to predict the outcome of this review at this time.

Wisconsin and Michigan Mercury Rules:  Both Wisconsin and Michigan have mercury rules that 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 the Clean Air Visibility Rule (CAVR) in June 2005 to address Regional Haze, or regionally-impaired visibility caused by multiple sources over a wide area. The rule defines Best Available Retrofit Technology (BART) requirements for electric generating units and how BART will be addressed in the 28 states subject to EPA’s CAIR. 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.

Pursuant to the rule, in July 2011, Wisconsin proposed a draft SIP for public comment. Michigan submitted a complete SIP to the EPA, but on December 30, 2011, the EPA proposed to disapprove the portion of the Michigan SIP that related to utility reductions of NO_x and SO₂ that were expected to occur under CAIR because the EPA had replaced the CAIR program with CSAPR. In this same proposal, the EPA proposed a partial Federal Implementation Plan (FIP) for Michigan that would rely on CSAPR for utility reductions of NO_x and SO₂. Issuance of a final partial FIP to Michigan may not occur while judicial review of CSAPR is pending. The EPA did not take action on the other portions of the Michigan SIP submittal.

The BART rules completed by Wisconsin and Michigan, which cover one aspect of the CAVR regulations, are partially based on utility reductions of NO_x and SO₂ that were expected to occur under CAIR. While the EPA has expressed its intention to allow states to consider utility reductions of NO_x and SO₂ expected under CSAPR in its Regional Haze SIPs, we will not be able to determine final impacts of these rules until judicial review of CSAPR is completed and any subsequent rulemaking activities required as result of that review have been finalized.

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 an 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 are 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.

A-25

Federal, state, regional and international authorities have undertaken efforts to limit greenhouse gas emissions. The regulation of greenhouse gas emissions through legislation and regulation has been, and continues to be, a focus of the President and his administration. Although legislation that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards and/or energy efficiency standards failed to pass in the U.S. Congress, we expect such legislation to be considered in the future. Any mandatory restrictions on our Carbon Dioxide (CO₂) emissions that may be adopted by Congress or Wisconsin’s or Michigan’s legislature could result in significant compliance costs that could affect future results of operations, cash flows and financial condition. While climate legislation has yet to be adopted, the EPA is pursuing regulation of greenhouse gas emissions using its existing authority under the Clean Air Act (CAA). These regulations are expected to impact our ability to do maintenance or modify our existing facilities, and permit new facilities. Depending on the extent of rate recovery and other factors, these rules could have a material adverse impact on our financial condition.

Beginning with 2010, we are required to report our CO₂ equivalent emissions from our electric generating facilities to the EPA under its Mandatory Reporting of Greenhouse Gases rule. For 2010, we reported CO₂ equivalent emissions of approximately 20.9 million metric tonnes to the EPA. Based upon our preliminary analysis of the monitoring data, we estimate that we will report CO₂ equivalent emissions of approximately 22.6 million metric tonnes to the EPA for 2011. The level of CO₂ and other greenhouse gas emissions vary from year to year and are dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed and how our units are dispatched by MISO.

We are also required to report CO₂ amounts related to the natural gas our gas utility distributes and sells. For 2010, we reported approximately 3.6 million metric tonnes of CO₂ to the EPA related to our distribution and sale of natural gas. Based upon our preliminary analysis of the monitoring data, we estimate that we will report CO₂emissions of approximately 3.9 million metric tonnes to the EPA for 2011.

Valley Power Plant:  We are exploring various options at VAPP in connection with the new environmental regulations, including converting it from a coal-fired plant to a natural gas-fired plant. For further information, see Note Q – Commitments and Contingencies in the Notes to Consolidated Financial Statements.

Water Quality

Clean Water Act:  Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts. The EPA finalized rules for new facilities (Phase I) in 2001. Final rules for cooling water intake systems at existing facilities (Phase II) were promulgated in 2004. However, as a result of litigation, the EPA withdrew the Phase II rule in July 2007 and advised states to use their best professional judgment in making BTA decisions while the rule remains suspended.

The EPA proposed a new Phase II rule on March 28, 2011, which must be finalized by July 27, 2012 in accordance with a judicial settlement entered into by the EPA. Once the rule is final, it will apply to all of our existing generating facilities with cooling water intake structures other than the Oak Creek expansion, which was permitted under the Phase I rules.

The proposed rule would create an impingement mortality reduction standard for all existing facilities. One proposed approach would allow a facility owner to satisfy the BTA requirement with respect to impingement mortality reduction if it demonstrates that its cooling water intake system has a maximum intake velocity of no more than 0.5 feet per second. Oak Creek Power Plant Units 5-8, Pleasant Prairie and Port Washington Generating Station all employ technologies that have a cooling water intake withdrawal velocity of less than 0.5 feet per second. We are still evaluating impingement mortality reduction compliance options for the Presque Isle Power Plant and VAPP.

The EPA has proposed that the BTA for entrainment mortality reduction be determined on a case-by-case basis. Therefore, permitting agencies would be required to determine BTA with respect to entrainment on a site-specific basis taking into consideration several factors. Because the entrainment reduction standard is a site-specific determination, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet this proposed requirement.

Depending on the final requirements of the Phase II rule, we may need to modify the cooling water intake systems at some of our facilities. However, we are not able to make a determination until after the Phase II rule is final.

Steam Electric Effluent Guidelines:  The federal Steam Electric Effluent guidelines, which regulate waste water discharges, are under review by the EPA. These rules govern discharges of waste water from our power plant processes. The EPA rules are expected to be finalized in 2014. After the promulgation of final rules, it is expected that the Wisconsin Department of Natural Resources (WDNR) will need to modify Wisconsin’s rules. The existing Wisconsin state rules for waste water discharge are very stringent, and therefore, the systems that have been installed at the Pleasant Prairie

A-26

Power Plant and the Oak Creek Power Plant use advanced technology. We are unable to determine the impact, if any, of these rules on our facilities at this time.

Land Quality

Proposed New Coal Combustion Products Regulation:  We currently have a program of beneficial utilization for substantially all of our coal combustion products, including fly ash, bottom ash and gypsum, which minimizes the need for disposal in specially-designed landfills. Both Wisconsin and Michigan have regulations governing the use and disposal of these materials. In June 2010, the EPA issued draft rules for public comment proposing two alternative rules for regulating coal combustion products. One of the proposed rules classifies the materials as hazardous waste. We submitted comments on the proposed rules in November 2010. The EPA also issued a Notice of Data Availability (NODA) in October 2011, and we submitted comments on the NODA in November 2011. If coal combustion products are classified as hazardous waste, it could have a material adverse effect on our ability to continue our current program.

If coal combustion products are classified as hazardous waste and we terminate our coal combustion products utilization program, we could be required to dispose of the coal combustion products at a significant cost to the Company, which could adversely impact our results of operations and financial condition.

In addition, the EPA finalized the Commercial and Industrial Solid Waste Incineration Units rule under the CAA, and finalized a Non-Hazardous Secondary Materials Rule. Both of these rules have the potential to negatively affect our ability to reburn coal ash from power plants and landfills. Presently, we have a successful program for reburning coal ash to recover energy and produce a usable fly ash product for the concrete industry.

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

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

LEGAL MATTERS

Cash Balance Pension Plan:  In June 2009, a lawsuit was filed by Alan M. Downes, a former employee, against the Plan in the U.S. District Court for the Eastern District of Wisconsin. The complaint alleged 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 the Employee Retirement Income Security Act of 1974 (ERISA) and were 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. In September 2010, the plaintiff filed a First Amended Class Action Complaint alleging additional claims under ERISA and adding Wisconsin Energy as a defendant.

In November 2011, the Plan entered into a settlement agreement with the plaintiffs for $45.0 million, and the court promptly issued an order preliminarily approving the settlement. As part of the settlement agreement, the Plan agreed to class certification for all similarly situated plaintiffs. The resolution of this matter resulted in a cost of less than $13 million for 2011 after considering insurance and reserves established in the prior year. We do not anticipate further charges as a result of the settlement, other than certain process-related costs we expect to incur to implement the settlement. We expect the court to provide final approval of the settlement agreement in April 2012, and to pay additional benefits to class members promptly after receiving this approval.

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.

Dairy farmers continue to make 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

A-27

these rulings, 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. This lawsuit was settled in May 2011. This settlement did not have a material effect on our financial condition or results of operations. Another stray voltage lawsuit was filed against us in January 2011, but was dismissed without prejudice by the court on February 21, 2012. We continue to evaluate various options and strategies to mitigate this risk.

NUCLEAR OPERATIONS

Used Nuclear Fuel Storage and Disposal:  During our ownership of Point Beach, we were authorized by the PSCW to load and store sufficient dry fuel storage containers to allow Point Beach Units 1 and 2 to operate to the end of their original operating licenses, but not to exceed the original 48-canister capacity of the dry fuel storage facility. The original operating licenses were set to expire in October 2010 for Unit 1 and in March 2013 for Unit 2 before they were renewed by the United States Nuclear Regulatory Commission 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. In February 2010, the DOE filed an appeal. We negotiated a settlement with the DOE for $45.5 million, which we received in the first quarter of 2011. This amount, net of costs incurred, is being returned to customers as part of the PSCW’s approval of our 2012 fuel recovery request and the MPSC’s approval of our interim order for the 2012 Michigan rate case.

INDUSTRY RESTRUCTURING AND COMPETITION

Electric Utility Industry

The regulated energy industry continues to experience significant changes. FERC continues to support large Regional Transmission Organizations (RTO), 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 Locational Marginal Price (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.

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.

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 territories in Michigan. We believe that this lack of alternate supplier activity reflects our small market area in Michigan, our competitive regulated power

A-28

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 an 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 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 Load Serving Entities located in the service territories of each MISO transmission owner. FERC has previously confirmed the use of the current transmission cost allocation methodology. Certain additional costs for new transmission projects are allocated throughout the MISO footprint.

In April 2006, FERC issued an order determining that MISO had not applied its energy markets tariff correctly in the assessment of Revenue Sufficiency Guarantee (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 Auction Revenue Rights (ARRs) and Financial Transmission Rights (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, 2011 through May 31, 2012. The resulting ARR valuation and the secured FTRs should 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

A-29

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 in this report for information on new accounting pronouncements.

International Financial Reporting Standards:  During 2009, the SEC announced a “roadmap” for the potential use by U.S. registrants of IFRS instead of GAAP. The SEC issued a Work Plan to consider specific areas and factors relevant to a determination of whether, when and how the current financial reporting system for U.S. registrants should be transitioned to a system incorporating IFRS. Working under the assumption that the SEC would make a decision in 2011, the Work Plan anticipated that the first time U.S. registrants would report under IFRS would be approximately 2015 or 2016. Since the release of the Work Plan, the SEC has issued several papers discussing the incorporation of IFRS into the U.S. financial reporting system and held a roundtable discussion, but has yet to make a determination regarding IFRS. To the extent the SEC determines to adopt IFRS, if at all, we are currently unable to determine when we would be required to begin using IFRS.

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 and accrue liabilities that non-regulated companies would not. As of December 31, 2011, we had $1,256.1 million in regulatory assets and $671.2 million in regulatory liabilities. In the future, if we move to market based rates, or if the actions of our regulators change, we may conclude that we are unable to follow regulatory accounting. In this situation, we would record the regulatory assets related to unrecognized pension and OPEB costs as a reduction of equity, after tax. The balance of our regulatory assets net of 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 M – Benefits in the Notes to Consolidated Financial Statements) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. Pension costs are impacted by actual employee demographics (including age, compensation levels and employment periods), the level of contributions made to plans and earnings on plan assets. Changes made to the provisions of the plans may also impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs.

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.

A-30

The following table 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 M – 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 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 table 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	$	2.4
0.5% decrease in health care cost trend rate in all future years	$	(3.1	)
0.5% decrease in expected rate of return on plan assets	$	0.7

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 2011 of approximately $3.7 billion included accrued revenues of $200.5 million as of December 31, 2011.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity and Capital Resources – Market Risks and Other Significant Risks in this report, as well as Note K – Derivative Instruments and Note L – Fair Value Measurements in the Notes to Consolidated Financial Statements, for information concerning potential market risks to which we are exposed.

A-31

WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED INCOME STATEMENTS

Year Ended December 31

	2011		2010		2009
	(Millions of Dollars)
Operating Revenues	$	3,727.6	$	3,456.7	$	3,288.3
Operating Expenses
Fuel and purchased power		1,174.5		1,104.7		1,064.5
Cost of gas sold		306.2		316.0		389.7
Other operation and maintenance		1,447.6		1,432.5		1,231.7
Depreciation and amortization		220.3		216.2		265.1
Property and revenue taxes		105.4		96.5		99.1
Total Operating Expenses		3,254.0		3,165.9		3,050.1
Amortization of Gain		—		198.4		230.7
Operating Income		473.6		489.2		468.9
Equity in Earnings of Transmission Affiliate		54.9		52.7		51.9
Other Income and Deductions, net		62.1		39.8		25.8
Interest Expense, net		94.2		101.5		100.3
Income Before Income Taxes		496.4		480.2		446.3
Income Tax Expense		156.8		164.8		157.7
Net Income		339.6		315.4		288.6
Preferred Stock Dividend Requirement		1.2		1.2		1.2
Earnings Available for Common Stockholder	$	338.4	$	314.2	$	287.4

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

A-32

WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31

	2011			2010			2009
	(Millions of Dollars)
Operating Activities
Net income	$	339.6		$	315.4		$	288.6
Reconciliation to cash
Depreciation and amortization		223.6			224.2			272.5
Amortization of gain		—			(198.4	)		(230.7	)
Deferred income taxes and investment tax credits, net		265.1			69.6			132.3
Contributions to qualified benefit plans		(275.1	)		—			(283.8	)
Change in - Accounts receivable and accrued revenues		(9.0	)		(44.0	)		51.2
Inventories		2.6			(0.3	)		(25.0	)
Other current assets		(23.5	)		17.0			19.6
Accounts payable		41.4			23.0			(64.4	)
Accrued income taxes, net		(85.4	)		(65.5	)		51.1
Deferred costs, net		25.9			25.9			46.2
Other current liabilities		23.9			6.6			4.9
Other, net		14.8			51.7			(35.9	)
Cash Provided by Operating Activities		543.9			425.2			226.6
Investing Activities
Capital expenditures		(706.6	)		(617.3	)		(481.1	)
Investment in transmission affiliate		(5.8	)		(4.6	)		(22.7	)
Proceeds from asset sales		41.5			5.5			1.8
Change in restricted cash		(37.2	)		186.2			192.0
Other, net		(54.0	)		(40.6	)		(23.6	)
Cash Used in Investing Activities		(762.1	)		(470.8	)		(333.6	)
Financing Activities
Dividends paid on common stock		(239.6	)		(179.6	)		(179.6	)
Dividends paid on preferred stock		(1.2	)		(1.2	)		(1.2	)
Issuance of long-term debt		300.0			—			250.0
Retirement and repurchase of long-term debt		—			—			(164.4	)
Change in total short-term debt		140.7			117.9			90.6
Capital contribution from parent		—			100.0			100.0
Other, net		7.7			13.5			1.5
Cash Provided by Financing Activities		207.6			50.6			96.9
Change in Cash and Cash Equivalents		(10.6	)		5.0			(10.1	)
Cash and Cash Equivalents at Beginning of Year		23.3			18.3			28.4
Cash and Cash Equivalents at End of Year	$	12.7		$	23.3		$	18.3

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

A-33

WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

December 31

ASSETS

	2011			2010
	(Millions of Dollars)
Property, Plant and Equipment
Electric	$	7,088.7		$	6,612.1
Gas		910.0			882.4
Steam		93.4			91.4
Common		264.0			239.4
Other		60.1			60.1
		8,416.2			7,885.4
Accumulated depreciation		(2,964.7	)		(2,879.7	)
		5,451.5			5,005.7
Construction work in progress		902.4			803.3
Leased facilities, net		2,428.2			1,850.7
Net Property, Plant and Equipment		8,782.1			7,659.7
Investments
Equity investment in transmission affiliate		307.5			290.6
Other		0.2			0.5
Total Investments		307.7			291.1
Current Assets
Cash and cash equivalents		12.7			23.3
Restricted cash		45.5			8.3
Accounts receivable, net of allowance for doubtful accounts of $36.9 and $34.2		274.2			260.4
Accounts receivable from related parties		36.5			23.3
Income taxes receivable		99.4			16.0
Accrued revenues		200.5			208.7
Materials, supplies and inventories		319.2			321.8
Prepayments		130.7			115.0
Other		51.3			67.4
Total Current Assets		1,170.0			1,044.2
Deferred Charges and Other Assets
Regulatory assets		1,236.2			1,009.0
Other		165.3			166.7
Total Deferred Charges and Other Assets		1,401.5			1,175.7
Total Assets	$	11,661.3		$	10,170.7

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

A-34

WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED BALANCE SHEETS

December 31

CAPITALIZATION AND LIABILITIES

	2011		2010
	(Millions of Dollars)
Capitalization
Common equity	$	3,177.1	$	3,065.1
Preferred stock		30.4		30.4
Long-term debt		2,267.6		1,970.9
Capital lease obligations		2,716.5		2,060.8
Total Capitalization		8,191.6		7,127.2
Current Liabilities
Long-term debt and capital lease obligations due currently		37.9		21.8
Short-term debt		352.0		210.5
Subsidiary note payable to Wisconsin Energy		26.8		27.6
Accounts payable		265.2		234.8
Accounts payable to related parties		94.6		83.7
Accrued payroll and vacation		73.2		68.8
Other		173.4		139.6
Total Current Liabilities		1,023.1		786.8
Deferred Credits and Other Liabilities
Regulatory liabilities		658.1		658.1
Deferred income taxes - long-term		1,284.0		925.4
Pension and other benefit obligations		278.8		403.7
Other		225.7		269.5
Total Deferred Credits and Other Liabilities		2,446.6		2,256.7
Commitments and Contingencies (Note Q)
Total Capitalization and Liabilities	$	11,661.3	$	10,170.7

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

A-35

WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

December 31

	2011			2010
		(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		941.9			928.7
Retained earnings		1,902.3			1,803.5
Total Common Equity		3,177.1			3,065.1
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			250.0
2.95% due 2021		300.0			—
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)                          4.81% effective rate due 2030		2.0			2.0
Notes (unsecured)                                              0.504% variable rate due 2016 (a)		67.0			67.0
0.504% variable rate due 2030 (a)		80.0			80.0
Variable rate notes held by us (see Note I)		(147.0	)		(147.0	)
Unamortized discount, net		(19.4	)		(16.1	)
Total Long-Term Debt		2,267.6			1,970.9
Obligations Under Capital Leases (see Note I)		2,716.5			2,060.8
Total Capitalization	$	8,191.6		$	7,127.2

(a) Variable interest rate as of December 31, 2011.

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

A-36

WISCONSIN ELECTRIC POWER COMPANY

CONSOLIDATED STATEMENTS OF COMMON EQUITY

	Common     Stock		Other Paid     In Capital		Retained     Earnings			Total
		(Millions of Dollars)
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	)
Capital 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
Net income						315.4			315.4
Other comprehensive income						—			—
Comprehensive Income		—		—		315.4			315.4
Cash dividends
Common stock						(179.6	)		(179.6	)
Preferred stock						(1.2	)		(1.2	)
Capital contribution from parent				100.0					100.0
Stock-based compensation				7.0					7.0
Tax benefit of exercised stock options allocated from Parent				19.3					19.3
Balance - December 31, 2010		332.9		928.7		1,803.5			3,065.1
Net income						339.6			339.6
Other comprehensive income						—			—
Comprehensive Income		—		—		339.6			339.6
Cash dividends
Common stock						(239.6	)		(239.6	)
Preferred stock						(1.2	)		(1.2	)
Stock-based compensation				2.6					2.6
Tax benefit of exercised stock options allocated from Parent				10.6					10.6
Balance - December 31, 2011	$	332.9	$	941.9	$	1,902.3		$	3,177.1

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

A-37

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 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 $33.9 million as of December 31, 2011.

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.

Reclassifications:    Certain prior period amounts have been reclassified on a basis consistent with the current period financial statement presentation.

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. Beginning in January 2011, the electric fuel rules in Wisconsin allow us to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel costs that are outside of the symmetrical fuel cost tolerance, which the PSCW set at plus or minus 2% of the approved fuel cost plan. The deferred amounts are subject to an excess revenues test.

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	2011		2010		2009
	(Millions of Dollars)
AFUDC - Equity	$	59.2	$	32.4	$	15.9
Gain on Property Sales		2.4		4.5		1.7
Other, net		0.5		2.9		8.2
Total Other Income and Deductions, net	$	62.1	$	39.8	$	25.8

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 2.9% in 2011 and 2010, and 3.6% in 2009.

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.

A-38

We collect in our rates amounts representing future removal costs for many assets that do not have an associated Asset Retirement Obligation (ARO). We record a regulatory liability on our balance sheet for the estimated amounts we have collected in rates for future removal costs less amounts we have spent in removal activities. This regulatory liability was $566.2 million as of December 31, 2011 and $564.2 million as of December 31, 2010.

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, 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 Construction Work in Progress (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. Based on the 2010 PSCW rate order, effective January 1, 2010, we recorded 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 was 8.83%. This AFUDC accrual policy and rate continued through 2011 and will continue through 2012.

We are also accruing AFUDC on 100% of the biomass project.

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

	2011		2010		2009
	(Millions of Dollars)
AFUDC - Debt	$	24.7	$	13.5	$	6.6
AFUDC - Equity	$	59.2	$	32.4	$	15.9

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

Materials, Supplies and Inventories	2011		2010
	(Millions of Dollars)
Fossil Fuel	$	169.0	$	182.3
Materials and Supplies		110.0		101.0
Natural Gas in Storage		40.2		38.5
Total	$	319.2	$	321.8

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 regulatory assets on the balance sheet and expensed in the periods when they are reflected in rates. We defer regulatory assets pursuant to specific or generic orders issued by our regulators. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers. 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

A-39

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 K.

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

Restricted Cash:    For 2011, restricted cash consists of the settlement we received from the DOE during the first quarter of 2011, which is being returned, net of costs incurred, to customers. For 2010, restricted cash consisted of cash proceeds that we received from the sale of Point Beach that were used for the benefit of our customers. As of December 31, 2011, 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 H.

Investments:    We account for investments in other affiliated companies in which we do not maintain control using the equity method of accounting. We had a total ownership interest of approximately 23.0% in ATC as of December 31, 2011 and 2010. We are represented by one out of ten ATC board members, each of whom has one vote. Due to the voting requirements, no individual member has more than 10% of the voting control. For further information regarding such investments, see Note P.

Income Taxes:    We follow the liability method in accounting for income taxes. 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 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 H.

A-40

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

	2011	2010	2009
Risk-free interest rate	0.2% - 3.4%	0.2% - 3.9%	0.3% - 2.5%
Dividend yield	3.9%	3.7%	3.0%
Expected volatility	19.0%	20.3%	25.9%
Expected life (years)	5.5	5.9	6.2
Expected forfeiture rate	2.0%	2.0%	2.0%
Weighted-average fair value our stock options granted	$3.17	$3.36	$4.01

B — RECENT ACCOUNTING PRONOUNCEMENTS

Presentation of Comprehensive Income:    In June 2011, the Financial Accounting Standards Board (FASB) issued guidance on the presentation of comprehensive income. This guidance eliminates the option of presenting components of other comprehensive income as part of the statement of changes in stockholders’ equity. The guidance gives entities the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. In December 2011, the FASB issued an amendment to indefinitely defer one of the requirements contained in its June 2011 final standard. That requirement called for reclassification adjustments from accumulated other comprehensive income to be measured and presented by income statement line item in net income and also in other comprehensive income. This guidance, including the related deferral, is effective for fiscal years and interim periods beginning after December 15, 2011 and must be applied retrospectively. We are currently assessing the effects this guidance may have on our consolidated financial statements.

Fair Value Measurement:    In May 2011, the FASB issued guidance amending existing guidance for measuring fair value and for disclosing information about fair value measurements. Under the new guidance, required disclosures are expanded, particularly for fair value measurements that are categorized within Level 3 of the fair value hierarchy, for which quantitative information about the unobservable inputs, the valuation processes used by the entity, and the sensitivity of the measurement to the unobservable inputs will be required. Entities will also be required to disclose the categorization, by level of the fair value hierarchy, of items that are not measured at fair value in the balance sheets but for which the fair value is required to be disclosed. This guidance is effective for fiscal years and interim periods beginning after December 15, 2011 and must be applied prospectively. We are currently assessing the effects this guidance may have on our consolidated financial statements.

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, 2011 and 2010, we had approximately $8.0 million and $12.2 million, respectively, of net regulatory assets that were not earning a return. These regulatory assets are expected to be recovered from customers over a period of one to five years.

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 were issued by the end of 2010.

A-41

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

	2011		2010
	(Millions of Dollars)
Regulatory Assets
Deferred unrecognized pension costs	$	476.0	$	384.9
Deferred plant related – capital leases		326.3		231.7
Escrowed electric transmission costs		118.3		138.0
Deferred income tax related		118.0		86.7
Deferred unrecognized OPEB costs		68.0		50.6
Other, net		149.5		164.1
Total regulatory assets	$	1,256.1	$	1,056.0
Regulatory Liabilities
Deferred cost of removal obligations	$	566.2	$	564.2
Other, net		105.0		108.4
Total regulatory liabilities	$	671.2	$	672.6

Our rates allow us to recover and expense capital lease payments as they are due. We defer as a regulatory asset the difference between the capital lease expense recovered in rates and the expense that would result from the amortization of the leased asset and the imputed interest expense.

Regulatory assets and liabilities that are expected to be amortized within one year are recorded as current on the balance sheet.

D — DIVESTITURES

Edgewater Generating Unit 5:    On March 1, 2011, we sold our 25% interest in Edgewater Generating Unit 5 to Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corp. (WPL), for our net book value, including working capital, of approximately $38 million. This transaction was treated as a sale of an asset.

E — ASSET RETIREMENT OBLIGATIONS

The following table presents the change in our AROs during 2011 and 2010:

	2011			2010
	(Millions of Dollars)
Balance as of January 1	$	50.8		$	52.6
Liabilities Incurred		—			—
Liabilities Settled		(2.2	)		(2.5	)
Accretion		2.8			2.9
Cash Flow Revisions		1.5			(2.2	)
Balance as of December 31	$	52.9		$	50.8

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,

A-42

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 which represent variable interests. We account for one of these agreements, with an independent power producer, as an operating lease. The agreement has a remaining term of approximately one and a half years. We have examined the risks of the entity including the impact of operations and maintenance, dispatch, financing, fuel costs, remaining useful life and other factors, and have determined that we are not the primary beneficiary of this entity. We have concluded that we do not have the power to direct the activities that would most significantly affect the economic performance of the entity over its remaining life.

We also have a purchased power agreement for 236 MW of firm capacity from a gas-fired cogeneration facility, which we account for as a capital lease. The agreement includes no minimum energy requirements over the remaining term of 11 years. We have examined the risks of the entity including operations and maintenance, dispatch, financing, fuel costs and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity and there is no residual guarantee associated with the purchased power agreement.

We have approximately $309.5 million of required payments over the remaining term of these agreements. We believe that the required lease payments under these contracts will continue to be recoverable in rates. Total capacity and lease payments under these contracts in 2011, 2010 and 2009 were $65.9 million, $64.2 million and $62.2 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contracts.

G — INCOME TAXES

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

Income Taxes	2011			2010			2009
	(Millions of Dollars)
Current tax expense (benefit)	$	(108.3	)	$	95.2		$	25.4
Deferred income taxes, net		269.0			72.9			135.8
Investment tax credit, net		(3.9	)		(3.3	)		(3.5	)
Total Income Tax Expense	$	156.8		$	164.8		$	157.7

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

	2011						2010						2009
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	$	173.3			35.0	%	$	167.6			35.0	%	$	155.8			35.0	%
State income taxes net of federal tax benefit		25.9			5.2	%		24.5			5.1	%		22.5			5.0	%
AFUDC - Equity		(20.7	)		(4.2	)%		(11.3	)		(2.4	)%		(5.5	)		(1.2	)%
Domestic production activities deduction		(12.6	)		(2.5	)%		(12.6	)		(2.6	)%		(8.3	)		(1.9	)%
Production tax credits - wind		(8.7	)		(1.8	)%		(7.2	)		(1.5	)%		(7.1	)		(1.6	)%
Investment tax credit restored		(3.9	)		(0.8	)%		(3.3	)		(0.7	)%		(3.5	)		(0.8	)%
Other, net		3.5			0.7	%		7.1			1.4	%		3.8			0.8	%
Total Income Tax Expense	$	156.8			31.6	%	$	164.8			34.3	%	$	157.7			35.3	%

A-43

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:

Deferred Tax Assets	2011			2010
	(Millions of Dollars)
Current
Employee benefits and compensation	$	11.9		$	11.0
Recoverable gas costs		0.8			0.9
Other		(0.9	)		(0.3	)
Total Current Deferred Tax Assets		11.8			11.6
Non-current
Deferred revenues		279.7			305.9
Employee benefits and compensation		(47.2	)		7.9
Construction advances		22.9			115.5
Emission allowances		1.0			2.6
Future federal tax benefits		8.5			—
Other		9.6			4.6
Total Non-Current Deferred Tax Assets		274.5			436.5
Total Deferred Tax Assets	$	286.3		$	448.1
Deferred Tax Liabilities	2011			2010
	(Millions of Dollars)
Current
Prepaid items	$	48.2		$	45.4
Uncollectible account expense		(25.5	)		(15.8	)
Total Current Deferred Tax Liabilities		22.7			29.6
Non-current
Property-related		1,373.2			1,177.2
Investment in transmission affiliate		112.3			98.2
Deferred transmission costs		47.4			53.1
Employee benefits and compensation		(6.9	)		(6.5	)
Other		32.5			39.9
Total Non-current Deferred Tax Liabilities		1,558.5			1,361.9
Total Deferred Tax Liabilities	$	1,581.2		$	1,391.5
Consolidated Balance Sheet Presentation	2011			2010
Current Deferred Tax Asset (Liability)	$	(10.9	)	$	(18.0	)
Non-Current Deferred Tax Asset (Liability)	$	(1,284.0	)	$	(925.4	)

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

As of December 31, 2011, we had approximately $24.3 million of net operating loss carryforwards resulting in deferred tax assets of approximately $8.5 million. These net operating loss carryforwards begin to expire in 2030. We anticipate that we will have future taxable income sufficient to utilize these deferred tax assets.

A-44

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:

	2011			2010
	(Millions of Dollars)
Balance as of January 1	$	15.8		$	21.4
Additions based on tax positions related to the current year		—			0.8
Additions for tax positions of prior years		—			10.4
Reductions for tax positions of prior years		(3.2	)		(2.5	)
Reductions due to statute of limitations		—			—
Settlements during the period		(2.0	)		(14.3	)
Balance as of December 31	$	10.6		$	15.8

The amount of unrecognized tax benefits as of December 31, 2011 and 2010 excludes deferred tax assets related to uncertainty in income taxes of $10.6 million and $14.6 million, respectively. As of December 31, 2011 and 2010, the net amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was approximately zero and $1.3 million, respectively.

We recognize interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense. For the years ended December 31, 2011, 2010 and 2009, we recognized approximately $0.6 million, $3.6 million and $1.4 million, respectively, of accrued interest in the Consolidated Income Statements. For the years ended December 31, 2011, 2010 and 2009, we recognized no penalties in the Consolidated Income Statements. We had approximately $2.0 million and $3.8 million of interest accrued in the Consolidated Balance Sheets as of December 31, 2011 and 2010, 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 2007 through 2011 are subject to Federal and Wisconsin examination.

H — COMMON EQUITY

On January 20, 2011, Wisconsin Energy’s Board of Directors declared a two-for-one common stock split effected by a 100% stock dividend paid on March 1, 2011 to shareholders of record on February 14, 2011. All share and per share data related to Wisconsin Energy equity compensation awards in these financial statements have been restated to reflect the stock split.

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.

A-45

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:

	2011		2010		2009
	(Millions of Dollars)
Stock options	$	2.5	$	7.0	$	9.9
Performance units		20.3		24.6		12.9
Restricted stock		1.1		0.8		0.3
Share-based compensation expense	$	23.9	$	32.4	$	23.1
Related Tax Benefit	$	9.6	$	13.0	$	9.3

Stock Options:    The exercise price of a Wisconsin Energy stock option under the plan is to be no less than 100% of the common stock’s fair market value on the grant date and options may not be exercised within six months of the grant date except in the event of a change in control. Option grants consist of non-qualified stock options and vest on a cliff-basis after a three year period. Options expire no later than ten years from the date of grant. For further information regarding stock-based compensation and the valuation of Wisconsin Energy stock options, see Note A.

The following is a summary of Wisconsin Energy stock option activity by our employees during 2011:

Stock Options	Number of     Options			Weighted- Average     Exercise Price		Weighted-Average Remaining Contractual Life (Years)		Aggregate     Intrinsic Value      (Millions)
Outstanding as of January 1, 2011		12,034,614		$	20.95
Granted		435,370		$	29.35
Exercised		(2,562,458	)	$	19.22
Forfeited		—		$	—
Outstanding as of December 31, 2011		9,907,526		$	21.76		5.4	$	130.7
Exercisable as of December 31, 2011		6,953,946		$	21.29		4.6	$	95.1

We expect that substantially all of the outstanding options as of December 31, 2011 will be exercised.

In January 2012, the Compensation Committee awarded 850,480 Wisconsin Energy non-qualified stock options at an exercise price of $34.88 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, 2011, 2010 and 2009 was $31.8 million, $53.2 million and $5.9 million, respectively. Cash received by Wisconsin Energy from exercises of its options by our employees was $49.3 million, $81.1 million and $8.2 million during the years ended December 31, 2011, 2010 and 2009, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $9.7 million, $21.0 million and $2.5 million, respectively.

A-46

The following table summarizes information about Wisconsin Energy stock options held by our employees and outstanding as of December 31, 2011:

	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)
$11.52 to $17.10		1,735,456	$	16.30		2.5		1,735,456	$	16.30		2.5
$19.74 to $21.11		3,370,840	$	20.62		5.9		1,311,040	$	19.86		4.3
$23.88 to $29.35		4,801,230	$	24.54		6.2		3,907,450	$	23.98		5.6
		9,907,526	$	21.76		5.4		6,953,946	$	21.29		4.6

The following table summarizes information about non-vested Wisconsin Energy options held by our employees during 2011:

Non-Vested Stock Options	Number of Options			Weighted- Average Fair Value
Non-Vested as of January 1, 2011		4,996,650		$	4.27
Granted		435,370		$	3.17
Vested		(2,478,440	)	$	4.65
Forfeited		—		$	—
Non-Vested as of December 31, 2011		2,953,580		$	3.78

As of December 31, 2011, total compensation costs related to non-vested Wisconsin Energy stock options held by our employees and not yet recognized was approximately $0.6 million, which is expected to be recognized over the next 19 months on a weighted-average basis.

Restricted Shares:    The Compensation Committee has also approved grants of Wisconsin Energy restricted stock to certain of our key employees. The following restricted stock activity related to our employees occurred during 2011:

Restricted Shares	Number of Shares			Weighted- Average Market Price
Outstanding as of January 1, 2011		124,460
Granted		51,690		$	29.00
Released		(57,322	)	$	16.53
Forfeited		(2,882	)	$	26.59
Outstanding as of December 31, 2011		115,946

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 2012, the Compensation Committee awarded 67,272 restricted shares to our officers and other key employees under its normal schedule of awarding long-term incentive compensation. These awards have a three-year vesting period, and generally, one-third of the award vests 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 $1.7 million, $1.6 million and $0.4 million for the years ended December 31, 2011, 2010 and 2009, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the

A-47

same years was $0.6 million, $0.6 million and $0.2 million, respectively.

As of December 31, 2011, total compensation cost related to our share of Wisconsin Energy restricted stock not yet recognized was approximately $1.8 million, which is expected to be recognized over the next 20 months on a weighted-average basis.

Performance Units:    In January 2011, 2010 and 2009, the Compensation Committee awarded 413,990, 520,620 and 618,620 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, 2011, 2010 and 2009 had a total intrinsic value of $23.8 million, $12.1 million and $9.3 million, respectively. The awards were subsequently distributed to our officers and key employees in January 2012, 2011 and 2010. The actual tax benefit realized for the tax deductions from the distribution of performance units was approximately $9.6 million, $4.2 million and $3.2 million, respectively. As of December 31, 2011, total compensation cost related to performance units not yet recognized was approximately $15.5 million, which is expected to be recognized over the next 19 months on a weighted-average basis.

In January 2012, the Compensation Committee awarded 313,985 performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

Equity Contribution:    Our capitalization reflects the impact of $100.0 million equity contributions from Wisconsin Energy during 2010 and 2009.

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

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

I — LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

Debentures and Notes:    As of December 31, 2011, the maturities and sinking fund requirements of our long-term debt outstanding (excluding obligations under capital leases) were as follows:

	(Millions of Dollars)
2012	$	—
2013		300.0
2014		300.0
2015		250.0
2016		—
Thereafter		1,437.0
Total	$	2,287.0

A-48

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

In September 2011, we issued $300 million of 2.95% Debentures due September 15, 2021. The debentures were issued under an existing shelf registration statement filed with the SEC in February 2011. The net proceeds were used to repay short-term debt and for other general corporate purposes.

During 2009, we issued $250 million of debentures under an existing 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, 2011 and 2010, 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.

Obligations Under Capital Leases

We are the obligor under a power purchase contract with an unaffiliated third party 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.

PWGS:    We are leasing PWGS 1 and PWGS 2, two 545 MW natural gas-fired generation units which were placed in service in July 2005 and May 2008, respectively, from We Power under PSCW approved leases. We recorded the leased plants and corresponding obligations for the plants at the estimated fair value of $670.9 million. 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 $126.6 million in the year 2021 for PWGS 1 and to approximately $127.5 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 the plants was $648.3 million as of December 31, 2011 and will decrease to zero over the remaining lives of the contracts.

Oak Creek Expansion:    We are leasing OC 1, OC 2 and the common facilities, which are also utilized by our Oak Creek Units 5-8, from We Power under PSCW approved leases. We are amortizing the leased plants on a straight-line basis over the 30-year term of the leases. The common coal handling system was placed in service in November 2007 and the water intake system was placed in service in January 2009. OC 1 and the remaining common facilities were placed in service in February 2010. OC 2 was placed in service in January 2011. We have recorded the leased plants and corresponding capital lease obligations at the estimated fair value of $1,954.0 million. The lease payments are expected to be recovered through our rates, as supported by the 2001 leased generation law. The total obligation under the capital leases was $1,973.8 million as of December 31, 2011, and will decrease to zero over the remaining life of the contracts.

A-49

We paid the following lease payments during 2011, 2010 and 2009:

	2011		2010		2009
	(Millions of Dollars)
Long-term power purchase commitment	$	31.3	$	30.2	$	29.1
PWGS		97.5		97.4		97.4
Oak Creek Expansion		266.1		178.6		41.6
Total	$	394.9	$	306.2	$	168.1

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

Capital Lease Assets	2011			2010
	(Millions of Dollars)
Long-term Power Purchase Commitment
Under capital lease	$	140.3		$	140.3
Accumulated amortization		(81.1	)		(75.5	)
Total Long-term Power Purchase Commitment	$	59.2		$	64.8
PWGS
Under capital lease	$	670.9		$	670.3
Accumulated amortization		(135.1	)		(108.2	)
Total PWGS	$	535.8		$	562.1
Oak Creek Expansion
Under capital lease	$	1,954.0		$	1,279.8
Accumulated amortization		(120.8	)		(56.0	)
Total Oak Creek	$	1,833.2		$	1,223.8
Total Leased Facilities	$	2,428.2		$	1,850.7

A-50

Future minimum lease payments under our capital leases and the present value of our net minimum lease payments as of December 31, 2011 are as follows:

Capital Lease Obligations	Power Purchase Commitment			PWGS			Oak Creek Expansion			Total
	(Millions of Dollars)
2012	$	38.9		$	97.5		$	270.3		$	406.7
2013		40.4			97.5			270.3			408.2
2014		41.9			97.5			270.3			409.7
2015		43.5			97.5			289.3			430.3
2016		45.1			97.5			301.0			443.6
Thereafter		85.4			1,460.5			7,040.6			8,586.5
Total Minimum Lease Payments		295.2			1,948.0			8,441.8			10,685.0
Less: Estimated Executory Costs		(74.9	)		—			—			(74.9	)
Net Minimum Lease Payments		220.3			1,948.0			8,441.8			10,610.1
Less: Interest		(87.9	)		(1,299.7	)		(6,468.0	)		(7,855.6	)
Present Value of Net
Minimum Lease Payments		132.4			648.3			1,973.8			2,754.5
Less: Due Currently		(12.4	)		(6.5	)		(19.1	)		(38.0	)
Total Capital Lease Obligations	$	120.0		$	641.8		$	1,954.7		$	2,716.5

We recorded an increase of approximately $1.0 billion to our capital lease obligations in connection with OC 1 being placed in service in February 2010 and an increase of approximately $650 million in connection with OC 2 being placed in service in January 2011.

J — SHORT-TERM DEBT

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

	2011					2010
Short-Term Debt	Balance		Interest Rate			Balance		Interest Rate
	(Millions of Dollars, except for percentages)
Commercial paper	$	352.0		0.24	%	$	210.5		0.25	%

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

	2011			2010
	(Millions of Dollars, except for percentages)
Maximum Commercial Paper Outstanding	$	370.5		$	268.0
Average Commercial Paper Outstanding	$	217.4		$	93.2
Weighted-Average Interest Rate		0.21	%		0.26	%

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%.

As of December 31, 2011, we had approximately $494.1 million of available, undrawn lines under our bank back-up credit facility and approximately $352.0 million of commercial paper outstanding that was supported by the available lines of

A-51

credit. Our bank back-up credit facility expires in December 2013. As of December 31, 2011, our subsidiary had a $26.8 million note payable to Wisconsin Energy with a weighted-average interest rate of 5.77%.

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, 2011, we were in compliance with all financial covenants.

K — 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, 2011, we recognized $14.1 million in regulatory assets and $20.3 million in regulatory liabilities related to derivatives in comparison to $11.0 million in regulatory assets and $13.7 million in regulatory liabilities as of December 31, 2010.

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 $2.5 million is recorded in other deferred charges and other assets, and the long-term portion of our derivative liabilities of $0.4 million is recorded in other deferred credits and other liabilities. Our Consolidated Balance Sheets as of December 31, 2011 and 2010 include:

	December 31, 2011				December 31, 2010
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	0.7	$	4.6	$	0.9	$	6.3
Fuel Oil		0.3		0.1		4.4		—
FTRs		5.7		—		5.9		—
Coal		12.5		—		2.9		—
Total	$	19.2	$	4.7	$	14.1	$	6.3

Our Consolidated Income Statements include gains (losses) on derivative instruments used in our risk management strategies under fuel and purchased power for those commodities supporting our electric operations and under cost of gas sold for the natural gas sold to our customers. Our estimated notional volumes and gains (losses) for the years ended December 31, 2011 and 2010 were as follows:

	2011			2010
	Volume	Gains (Losses)		Volume	Gains (Losses)
		(Millions of Dollars)			(Millions of Dollars)
Natural Gas	32.2 million Dth	$	(15.5)	37.8 million Dth	$	(23.3)
Power	zero MWh		—	234,720 MWh		(0.5)
Fuel Oil	13.0 million gallons		6.9	8.1 million gallons		(0.5)
FTRs	23,718 MW		12.5	25,234 MW		19.2
Total		$	3.9		$	(5.1)
					��

As of December 31, 2011 and 2010, we posted collateral of $6.4 million and $4.2 million, respectively, in our margin accounts. These amounts are recorded on the balance sheet in other current assets.

A-52

L — 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 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 on-going 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 Over-the-Counter (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, 2011
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	45.5	$	—	$	—	$	45.5
Derivatives		0.3		13.2		5.7		19.2
Total	$	45.8	$	13.2	$	5.7	$	64.7
Liabilities:
Derivatives	$	4.3	$	0.4	$	—	$	4.7
Total	$	4.3	$	0.4	$	—	$	4.7

A-53

Recurring Fair Value Measures	As of December 31, 2010
	Level 1		Level 2		Level 3		Total
		(Millions of Dollars)
Assets:
Restricted Cash	$	8.3	$	—	$	—	$	8.3
Derivatives		4.5		3.7		5.9		14.1
Total	$	12.8	$	3.7	$	5.9	$	22.4
Liabilities:
Derivatives	$	3.0	$	3.3	$	—	$	6.3
Total	$	3.0	$	3.3	$	—	$	6.3

Restricted cash consists of certificates of deposit and government backed interest bearing securities and represents (i) for 2010, the remaining funds to be distributed to customers resulting from the net proceeds received from the sale of Point Beach, and (ii) for 2011, the settlement we received from the DOE during the first quarter of 2011, which is being returned, net of costs incurred, to customers. Derivatives reflect positions we hold in exchange-traded derivative contracts and OTC derivative contracts. Exchange-traded derivative contracts, which include futures and exchange-traded options, are generally based on unadjusted quoted prices in active markets and are classified within Level 1. Some OTC derivative contracts are valued using broker or dealer quotations, or market transactions in either the listed or OTC markets utilizing a mid-market pricing convention (the mid-point between bid and ask prices), as appropriate. In such cases, these derivatives are classified within Level 2. Certain OTC derivatives may utilize models to measure fair value. Generally, we use a similar model to value similar instruments. Valuation models utilize various inputs which include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs (i.e., inputs derived principally from or corroborated by observable market data by correlation or other means). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Certain OTC derivatives are in less active markets with a lower availability of pricing information which might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in Level 3.

The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy:

	2011			2010
		(Millions of Dollars)
Balance as of January 1	$	5.9		$	5.8
Realized and unrealized gains (losses)		—			—
Purchases and issuances		16.1			17.9
Settlements		(16.3	)		(17.8	)
Transfers in and/or out of Level 3		—			—
Balance as of December 31	$	5.7		$	5.9
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 K — Derivative Instruments for further information on the offset to regulatory assets and liabilities.

A-54

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

	2011				2010
Financial Instruments	Carrying         Amount		Fair         Value		Carrying         Amount		Fair         Value
		(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	25.1	$	30.4	$	23.5
Long-term debt including current portion	$	2,287.0	$	2,669.0	$	1,987.0	$	2,158.7

The carrying value of net accounts receivable, accounts payable and short-term borrowings approximates fair value due to the short-term nature of these instruments. The fair value of our preferred stock is estimated based upon the quoted market value for the same or similar issues. The fair value of our long-term debt, including the current portion of long-term debt, but excluding capitalized leases and 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.

M — BENEFITS

Pensions and Other Post-retirement Benefits:    We participate in Wisconsin Energy’s defined benefit pension plans that cover substantially all of our employees. The plans provide defined benefits based upon years of service and final average salary.

We also participate in Wisconsin Energy’s OPEB plans that cover substantially all of our employees. The health care plans are contributory with participants’ contributions adjusted annually; the life insurance plans are noncontributory. The accounting for the health care plans anticipates future cost-sharing changes to the written plans that are consistent with our expressed intent to maintain the current cost sharing levels. The post-retirement health care plans include a limit on our share of costs for recent and future retirees.

The assets, obligations and the components of our pension costs are allocated by Wisconsin Energy’s actuary to each of the participating companies as if each participating company had its own plan. The disclosures below are based on an allocation to us of the amounts for Wisconsin Energy’s pension plans.

Wisconsin Energy 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.

A-55

The following table presents details about the pension and OPEB plans:

	Pension						OPEB
	2011			2010			2011			2010
	(Millions of Dollars)
Change in Benefit Obligation
Benefit Obligation at January 1	$	1,056.0		$	992.6		$	297.1		$	304.1
Service cost		14.5			22.1			9.9			10.6
Interest cost		58.4			58.9			17.0			17.4
Participants’ contributions		—			—			10.8			6.1
Inter Plan transfer		1.9			—			—			—
Actuarial loss (gain)		84.2			52.7			6.5			(24.6	)
Gross benefits paid		(61.7	)		(70.3	)		(24.7	)		(17.3	)
Federal subsidy on benefits paid		N/A			N/A			0.7			0.8
Benefit Obligation at December 31	$	1,153.3		$	1,056.0		$	317.3		$	297.1
Change in Plan Assets
Fair Value at January 1	$	813.7		$	793.7		$	135.9		$	129.3
Actual earnings on plan assets		26.8			84.7			6.3			15.1
Employer contributions		239.3			5.6			45.6			2.7
Participants’ contributions		—			—			10.8			6.1
Gross benefits paid		(61.7	)		(70.3	)		(24.7	)		(17.3	)
Fair Value at December 31	$	1,018.1		$	813.7		$	173.9		$	135.9
Net Liability	$	135.2		$	242.3		$	143.4		$	161.2

As of December 31, 2011, our qualified and non-qualified pension plans were under-funded by $53.0 million and $82.2 million, respectively. As of December 31, 2010, our qualified and non-qualified pension plans were under funded by $162.6 million and $79.7 million, respectively.

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

	Pension				OPEB
	2011		2010		2011		2010
	(Millions of Dollars)
Other deferred charges	$	—	$	—	$	0.2	$	0.2
Other long-term liabilities		135.2		242.3		143.6		161.4
Net liability	$	135.2	$	242.3	$	143.4	$	161.2

The accumulated benefit obligation for all the defined benefit plans was $1,152.2 million and $1,055.7 million as of December 31, 2011 and 2010, respectively.

A-56

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
	2011		2010		2011			2010
	(Millions of Dollars)
Net actuarial loss	$	462.5	$	364.6	$	73.1		$	65.9
Prior service costs (credits)		13.5		15.7		(5.4	)		(7.4	)
Transition obligation		—		—		0.3			0.7
Total	$	476.0	$	380.3	$	68.0		$	59.2

We estimate that 2012 pension and OPEB costs will include the amortization of previously unrecognized benefit costs referred to above of $33.3 million and $3.2 million, respectively.

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

	Pension									OPEB
	2011			2010			2009			2011			2010			2009
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	14.5		$	22.1		$	21.4		$	9.9		$	10.6		$	8.2
Interest cost		58.4			59.0			61.9			17.0			17.4			16.5
Expected return on plan assets		(63.8	)		(59.5	)		(73.0	)		(11.2	)		(9.1	)		(8.9	)
Amortization of:
Transition obligation		—			—			—			0.3			0.3			0.3
Prior service cost (credit)		2.1			2.1			2.1			(1.9	)		(11.9	)		(12.6	)
Actuarial loss		24.3			18.8			12.8			4.2			8.2			5.5
Net Periodic Benefit Cost	$	35.5		$	42.5		$	25.2		$	18.3		$	15.5		$	9.0

In addition to the costs above, in 2011 we recorded net pension costs of less than $13 million relating to the settlement of pension litigation. The charges were after considering insurance and reserves established in the prior year. See Note Q —Commitments and Contingencies in this report.

	Pension						OPEB
	2011		2010		2009		2011		2010		2009
Weighted-Average assumptions used to determine benefit obligations as of Dec. 31
Discount rate		5.05%		5.60%		6.05%		5.20%		5.70%		5.75%
Rate of compensation increase		4.00%		4.00%		4.00%		N/A		N/A		N/A
Weighted-Average assumptions used to determine net cost for year ended Dec. 31
Discount rate		5.60%		6.05%		6.50%		5.70%		5.75%		6.50%
Expected return on plan assets		7.25%		7.25%		8.25%		7.50%		7.50%		8.25%
Rate of compensation increase		4.00%		4.00%		4.00%		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)								8.0%/12.0%		7.5%/16.0%		7.5%/20.0%
Rate that the cost trend rate gradually adjusts to								5.00%		5.00%		5.00%
Year that the rate reaches the rate it is assumed to remain at (Pre 65 / Post 65)								2017/2017		2015/2016		2015/2016

A-57

The expected long-term rate of return on pension and OPEB plan assets was 7.25% and 7.50%, respectively, in 2011 and 2010. The expected long-term rate of return for all plan assets was 8.25% in 2009. Wisconsin Energy consults with its investment advisors on an annual basis to help 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.

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	$	30.8	$	(25.8	)
Total of service and interest cost components	$	3.8	$	(3.1	)

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

Plan Assets:    Current pension trust assets and amounts which are expected to be contributed to the trusts in the future are expected to 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 on-going 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 target asset allocation is 45% equity investments and 55% fixed income investments. The current OPEB target 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 plan assets by asset category within the fair value hierarchy (for further level information, see Note L):

	As of December 31, 2011
Asset Category - Pension	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	6.9	$	—	$	—	$	6.9
Equities:
U.S. Equity		367.0		—		—		367.0
International Equity		81.0		27.3		—		108.3
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds		61.9		405.5		—		467.4
International Bonds		33.0		35.5		—		68.5
Total	$	549.8	$	468.3	$	—	$	1,018.1

A-58

	As of December 31, 2010
Asset Category - Pension	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	16.2	$	—	$	—	$	16.2
Equities:
U.S. Equity		166.8		190.1		—		356.9
International Equity		62.3		16.6		—		78.9
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds		38.2		277.6		—		315.8
International Bonds		24.4		21.5		—		45.9
Total	$	307.9	$	505.8		—	$	813.7

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

The following table summarizes the fair value of our share of OPEB plan assets by asset category within the fair value hierarchy:

	As of December 31, 2011
Asset Category - OPEB	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	1.6	$	—	$	—	$	1.6
Equities:
U.S. Equity		77.3		—		—		77.3
International Equity		21.9		1.6		—		23.5
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds		5.6		56.5		—		62.1
International Bonds		5.9		3.5		—		9.4
Total	$	112.3	$	61.6		—	$	173.9

	As of December 31, 2010
Asset Category - OPEB	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	0.9		—		—	$	0.9
Equities:
U.S. Equity		26.1		50.2		—		76.3
International Equity		3.3		0.9		—		4.2
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds		13.6		37.3		—		50.9
International Bonds		1.3		2.3		—		3.6
Total	$	45.2	$	90.7		—	$	135.9

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

A-59

Cash Flows:

	Pension
Employer Contributions	Qualified		Non-Qualified		OPEB
	(Millions of Dollars)
2009	$	264.6	$	4.6	$	21.8
2010	$	—	$	5.6	$	2.7
2011	$	234.1	$	5.2	$	45.6

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)
2012	$	96.7	$	14.6	$	(0.7	)
2013	$	90.2	$	15.1	$	—
2014	$	92.9	$	16.0	$	—
2015	$	90.0	$	17.1	$	—
2016	$	90.1	$	18.2	$	—
2017-2021	$	457.8	$	104.3	$	—

Savings Plans:    We sponsor savings plans which allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. Under these plans, we expensed matching contributions of $12.9 million during 2011 and $12.5 million during 2010 and 2009.

Postemployment Benefits:    Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $12.2 million as of December 31, 2011.

N — GUARANTEES

We enter into various guarantees to provide financial and performance assurance to third parties. As of December 31, 2011, we had the following guarantees:

	Maximum Potential       Future Payments		Outstanding		Liability Recorded
	(Millions of Dollars)
Guarantees	$	2.7	$	0.1	$	—
Letters of Credit	$	1.5	$	—	$	—

We are subject to the potential retrospective premiums that could be assessed under our insurance program.

O — SEGMENT REPORTING

We are a 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

A-60

produces, distributes and sells steam to space heating and processing customers in the Milwaukee, Wisconsin area.

Summarized financial information concerning our operating segments for the years ended December 31, 2011, 2010 and 2009 is shown in the following table:

	Operating Segments
Year Ended	Electric		Gas		Steam		Other (a)		Total
	(Millions of Dollars)
December 31, 2011
Operating Revenues (b)	$	3,211.3	$	477.3	$	39.0	$	—	$	3,727.6
Depreciation and Amortization	$	190.2	$	26.8	$	3.3	$	—	$	220.3
Operating Income (c)	$	425.6	$	46.7	$	1.3	$	—	$	473.6
Equity in Earnings of Transmission Affiliate	$	54.9	$	—	$	—	$	—	$	54.9
Capital Expenditures	$	665.0	$	39.0	$	2.6	$	—	$	706.6
Total Assets (d)	$	10,816.1	$	654.9	$	67.8	$	122.5	$	11,661.3
December 31, 2010
Operating Revenues (b)	$	2,936.3	$	481.6	$	38.8	$	—	$	3,456.7
Depreciation and Amortization	$	187.0	$	25.9	$	3.3	$	—	$	216.2
Operating Income (c)	$	448.1	$	38.9	$	2.2	$	—	$	489.2
Equity in Earnings of Transmission Affiliate	$	52.7	$	—	$	—	$	—	$	52.7
Capital Expenditures	$	574.9	$	38.8	$	2.5	$	1.1	$	617.3
Total Assets (d)	$	9,356.8	$	638.1	$	65.3	$	110.5	$	10,170.7
December 31, 2009
Operating Revenues (b)	$	2,685.0	$	564.2	$	39.1	$	—	$	3,288.3
Depreciation 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

(a) Other includes primarily non-utility property and investments, materials and supplies, deferred charges and other corporate items.

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

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

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

P — RELATED PARTIES

We provide to and receive from certain of our Wisconsin Energy affiliates managerial, financial, accounting, legal, data processing and other services in accordance with service agreements approved by the PSCW. In addition, we make lease payments to We Power for PWGS 1, PWGS 2, OC 1 and OC 2. 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, 2011, 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

A-61

transmission infrastructure upgrades for new generation projects while projects are under construction, including the new generating units constructed as part of Wisconsin Energy’s PTF strategy. ATC reimburses us for these costs when new generation is placed into service. As of December 31, 2011 and 2010, we had a receivable of $5.4 million and $3.8 million, respectively, for these items. During the years ended December 31, 2011, 2010 and 2009, our equity in earnings from ATC was $54.9 million, $52.7 million and $51.9 million, respectively. During the years ended December 31, 2011, 2010 and 2009, distributions received from ATC were $43.7 million, $43.3 million and $40.9 million, respectively.

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

	2011		2010		2009
	(Millions of Dollars)
Operating Revenues	$	567.2	$	556.7	$	521.5
Operating Income	$	305.6	$	305.6	$	291.2
Net Income	$	223.9	$	219.7	$	213.4
Current Assets	$	58.7	$	59.9	$	51.1
Non-Current Assets	$	3,053.7	$	2,888.4	$	2,767.3
Current Liabilities	$	298.5	$	428.4	$	285.5
Non-Current Liabilities	$	1,482.7	$	1,260.0	$	1,336.5

We provided and received services from the following associated companies during 2011, 2010 and 2009:

Company	2011		2010		2009
	(Millions of Dollars)
Affiliate
Net Services Provided
We Power (excluding lease payments)	$	5.3	$	0.6	$	1.2
Wisconsin Gas	$	67.4	$	64.8	$	58.2
Other	$	1.1	$	0.9	$	1.1
Net Services Received
We Power (lease payments)	$	370.5	$	367.8	$	347.0
Wisconsin Energy	$	23.7	$	26.5	$	15.8
Equity Investee
Services Provided
ATC	$	10.8	$	16.9	$	22.3
Services Received
ATC	$	219.2	$	220.8	$	196.0

As of December 31, 2011 and 2010, our Consolidated Balance Sheets included receivable and payable balances with ATC as follows:

Equity Investee	2011		2010
	(Millions of Dollars)
Services Provided
ATC	$	0.7	$	0.9
Services Received
ATC	$	18.1	$	18.5

A-62

Q — COMMITMENTS AND CONTINGENCIES

Capital Expenditures:    We have made certain commitments in connection with 2012 capital expenditures. During 2012, we estimate that total capital expenditures will be approximately $597.7 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 2018. Certain of these contracts were deemed to qualify as operating leases. In addition, we have various other operating leases, including leases for coal cars.

Future minimum payments for the next five years and thereafter for our operating lease contracts are as follows:

	(Millions of Dollars)
2012	$	16.3
2013		6.5
2014		3.9
2015		4.0
2016		3.7
Thereafter		29.0
Total	$	63.4

Divested Assets:    Pursuant to the sale of Point Beach, we have agreed to indemnification provisions customary to transactions involving the sale of nuclear assets. We also provided customary indemnifications to WPL in connection with the sale of our interest in Edgewater Generating Unit 5. We have established reserves as deemed appropriate for these indemnification provisions.

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-combustion product disposal sites. We perform ongoing assessments of our manufactured gas plant sites and related disposal sites, as well as our coal combustion product 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 on-going analysis, we estimate that the future costs for detailed site investigation and future remediation costs may range from $6 million to $19 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, 2011, we have established reserves of $6.4 million related to future remediation costs.

Historically, 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.

Coal Combustion Product Landfill Sites:    We aggressively seek environmentally acceptable, beneficial uses for our coal combustion products. However, some coal combustion 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. During 2011, 2010 and 2009, we incurred $0.2 million, $0.4 million and $0.3 million, respectively, in landfill remediation expenses. As of December 31, 2011, we have no reserves established related to coal combustion product landfill sites.

A-63

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 Consent Decree was further amended in January 2012 to change the point of air monitoring at the Oak Creek Power Plant to accommodate the AQCS scheduled to begin service in 2012. 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, 2011, we have spent approximately $1.0 billion 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 currently estimated to be approximately $1.1 billion over the ten year period ending 2013.

Valley Power Plant Title V Air Permit:    The WDNR issued a renewed Title V operating permit for VAPP on February 28, 2011. The term of the permit is five years. Sierra Club and Clean Wisconsin requested a contested case hearing on certain conditions of the permit, and that request was granted. The Sierra Club also filed a petition requesting that the EPA remand the permit to the WDNR to require lower emission limits for particulate matter, SO₂ and NO_x, and to revise certain record-keeping requirements. No timeline has been set by the EPA to respond to that petition. We believe that the permit was properly issued and that the plant is in compliance with all applicable regulations and standards.

The Company filed an application with the PSCW on December 9, 2011 for authority to replace and upgrade the Lincoln Arthur natural gas main, which would also have the capability to accommodate the increased natural gas required if VAPP were to convert from coal to natural gas in the future. We also submitted a letter to the EPA on December 8, 2011 with four voluntary goals, which included: (1) reduce annual SO₂ emissions from the plant to no more than 4,500 tons (a 65% decrease from 2001 emission levels); (2) install a dry sorbent injection system at VAPP that is needed to meet the utility MACT rules earlier than the rules require if the installation would provide a direct economic benefit to customers and is approved by the PSCW; (3) hold an open house and tour of VAPP in 2012 to help inform the community on the plant, the unique role that it plays in the community, and to share environmental successes and future plans; and (4) convert VAPP to natural gas fuel by the 2017/2018 timeframe, provided we can demonstrate a direct economic benefit to customers and obtain authorization from the PSCW.

Cash Balance Pension Plan:    In June 2009, a lawsuit was filed by Alan M. Downes, a former employee, against the Plan in the U.S. District Court for the Eastern District of Wisconsin. The complaint alleged 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 were 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. In September 2010, the plaintiff filed a First Amended Class Action Complaint alleging additional claims under ERISA and adding Wisconsin Energy as a defendant.

In November 2011, the Plan entered into a settlement agreement with the plaintiffs for $45.0 million, and the court promptly issued an order preliminarily approving the settlement. As part of the settlement agreement, the Plan agreed to class certification for all similarly situated plaintiffs. The resolution of this matter resulted in a cost of less than $13 million for 2011 after considering insurance and reserves established in the prior year. We do not anticipate further charges as a result of the settlement, other than certain process-related costs we expect to incur to implement the settlement. We expect the court to provide final approval of the settlement agreement in April 2012, and to pay additional benefits to class members promptly after receiving this approval.

R — SUPPLEMENTAL CASH FLOW INFORMATION

During the year ended December 31, 2011, we paid $89.5 million in interest, net of amounts capitalized, and $1.1 million in income taxes, net of refunds. During the year ended December 31, 2010, we paid $99.7 million in interest, net of amounts capitalized, and $112.0 million in income taxes, net of refunds. 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.

As of December 31, 2011, 2010 and 2009, the amount of accounts payable related to capital expenditures was $16.7 million, $16.8 million and $8.1 million, respectively.

A-64

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, 2011 and 2010, and the related consolidated statements of income, common equity, and cash flows for each of the three years in the period ended December 31, 2011. 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, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

February 28, 2012

A-65

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	2011		2010
	(Millions of Dollars)
First	$	44.9	$	44.9
Second		44.9		44.9
Third		44.9		44.9
Fourth		104.9		44.9
Total	$	239.6	$	179.6

Subject to any regulatory restriction or other limitations on the payment of dividends, future dividends will be at the discretion of the board of directors and will depend upon, among other factors, our earnings, financial condition and other requirements.

Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. Under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy. For additional information regarding restrictions on our ability to pay dividends, see Note H -- Common Equity in the Notes to Consolidated Financial Statements.

BUSINESS OF THE COMPANY

We are an electric, gas and steam utility which was incorporated in the State of Wisconsin in 1896. Our operations are conducted in the following three segments:

Electric Operations:    We are the largest electric utility in the state of Wisconsin. We generate and distribute electric energy to approximately 1,122,500 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 466,000 customers in three distinct service areas: west and south of the City of Milwaukee, the Appleton area and areas within Iron and Vilas Counties, Wisconsin. We began doing business with Wisconsin Gas, an affiliated gas utility, under the trade name “We Energies” in April 2002.

Steam Operations:    We generate, distribute and sell steam supplied by our Valley and Milwaukee County Power Plants. Steam is used by approximately 465 customers in the metropolitan Milwaukee area for processing, space heating, domestic hot water and humidification.

For additional financial information about our operating segments, see Results of Operations in Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note O — Segment Reporting in the Notes to Consolidated Financial Statements.

A-66

DIRECTORS AND EXECUTIVE OFFICERS

DIRECTORS

The information under “Information About Nominees for Election to the Board of Directors” in Wisconsin Electric Power Company’s definitive Information Statement dated March 30, 2012, attached hereto, is incorporated herein by reference.

EXECUTIVE OFFICERS

The names and positions as of December 31, 2011 of Wisconsin Electric’s executive officers are listed below.

Gale E. Klappa – Chairman of the Board, President and Chief Executive Officer.

James C. Fleming⁽¹⁾ – Executive Vice President and General Counsel.

Frederick D. Kuester – Executive Vice President and Chief Financial Officer.

Allen L. Leverett – Executive Vice President.

Charles R. Cole⁽²⁾ – Senior Vice President.

Kevin Fletcher – Senior Vice President – Customer Operations.

Robert M. Garvin – Senior Vice President – External Affairs.

Kristine A. Rappé – Senior Vice President and Chief Administrative Officer.

Stephen P. Dickson – Vice President and Controller.

⁽¹⁾ Mr. Fleming stepped down as General Counsel effective March 1, 2012, and is retiring effective April 1, 2012.

⁽²⁾ Mr. Cole retired effective March 1, 2012.

A-67