UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

SCHEDULE 14A

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

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Wisconsin Power and Light Company

(Name of Registrant as Specified In Its Charter)

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SEC 1913 (3-99)

WISCONSIN POWER AND LIGHT COMPANY

ANNUAL MEETING OF SHAREOWNERS

DATE:	Monday, May 21, 2012
TIME:	2:30 p.m. (Central Daylight Time)
LOCATION:	Wisconsin Power and Light Company Alliant Energy Corporation Headquarters Sandy River Conference Room 4902 North Biltmore Lane Madison, Wisconsin 53718

SHAREOWNER INFORMATION

Wells Fargo Shareowner Services

161 North Concord Exchange

P. O. Box 64854

St. Paul, MN 55164-0854

1 (800) 356-5343

www.shareowneronline.com

Wisconsin Power and Light Company

4902 North Biltmore Lane

P.O. Box 14720

Madison, WI 53708-0720

Phone: (608) 458-3110

NOTICE OF ANNUAL MEETING OF SHAREOWNERS AND PROXY STATEMENT

On Monday, May 21, 2012, Wisconsin Power and Light Company will hold its 2012 Annual Meeting of Shareowners at the offices of Alliant Energy Corporation, 4902 North Biltmore Lane, Sandy River Conference Room, Madison, Wisconsin 53718. The meeting will begin at 2:30 p.m. (Central Daylight Time).

Only our sole common shareowner, Alliant Energy Corporation and preferred shareowners of record at the close of business on April 3, 2012, may vote at this meeting. All shareowners are requested to be present at the meeting in person or by proxy so that a quorum may be ensured. At the meeting, our shareowners will be asked to:

1. elect five (5) Directors of the Company, two (2) to serve for a term expiring at the 2014 Annual Meeting and three (3) to serve for terms expiring at the 2015 Annual Meeting;

2. conduct an advisory vote on the compensation of our named executive officers;

3. ratify the appointment of Deloitte & Touche LLP as our independent registered public accounting firm for 2012; and

4. attend to any other business properly presented at the meeting.

Please sign and return the enclosed proxy card as soon as possible.

A copy of our 2011 Annual Report is included as Appendix A to this proxy statement. The proxy statement and Annual Report have been combined into a single document to improve the effectiveness of our financial communication and to reduce costs, although the Annual Report does not constitute a part of the proxy statement.

Important Notice Regarding the Availability of Proxy Materials for the Shareowner Meeting to be held on May 21, 2012. Our 2012 Notice of Meeting, Proxy Statement and the 2011 Annual Report to Shareowners are available at http://www.alliantenergy.com/WPLproxy.

Any Wisconsin Power and Light Company preferred shareowner who desires to receive a copy of the Alliant Energy Corporation 2011 Annual Report, 2012 Notice of Annual Meeting and Proxy Statement at no cost may do so by calling our Shareowner Services Department at (800) 353-1089 or writing to us at the address shown above. The Alliant Energy Corporation proxy statement for the 2012 Annual Meeting of Shareowners and the 2011 Annual Report to Shareowners are available at http://www.alliantenergy.com/eproxy.

By Order of the Board of Directors,

F. J. Buri

Corporate Secretary and

Assistant General Counsel

Dated, mailed and made available on the

Internet on or about April 17, 2012.

TABLE OF CONTENTS

General Information	1
Information About the Annual Meeting and Voting	1
Proposal One — Election of Directors	5
Meetings and Committees of the Board	8
Corporate Governance	12
Ownership of Voting Securities	15
Compensation Discussion and Analysis	17
Compensation and Personnel Committee Report	30
Summary Compensation Table	31
Grants of Plan-Based Awards	33
Outstanding Equity Awards at Fiscal Year-End	34
Option Exercises and Stock Vested	36
Pension Benefits	37
Nonqualified Deferred Compensation	41
Potential Payments Upon Termination or Change in Control	42
Proposal Two — Advisory Vote on Compensation of Our Named Executive Officers	48
Director Compensation	50
Report of the Audit Committee	52
Proposal Three — Ratification of the Appointment of Deloitte  & Touche LLP as the Company’s Independent Registered Public Accounting Firm for 2012	53
Section 16(a) Beneficial Ownership Reporting Compliance	54
Appendix A — Wisconsin Power and Light Company Annual Report

PROXY STATEMENT FOR 2012 ANNUAL MEETING OF SHAREOWNERS

GENERAL INFORMATION

Your Board of Directors is soliciting proxies to be voted at the 2012 Annual Meeting of Shareowners to be held on May 21, 2012, at 2:30 p.m. (Central Daylight Time), at the offices of Alliant Energy Corporation, Sandy River Conference Room, 4902 North Biltmore Lane, Madison, Wisconsin 53718. Your vote is very important. For this reason, the Board of Directors is requesting that you allow your stock to be represented at the meeting by the proxies named on the enclosed proxy card. We began mailing this proxy statement and the form of proxy on or about April  17, 2012.

INFORMATION ABOUT THE ANNUAL MEETING AND VOTING

  1. Why am I receiving these materials?

Our Board of Directors is providing these proxy materials to you in connection with our Annual Meeting of Shareowners (the “Annual Meeting”), which will take place on May 21, 2012. As a shareowner, you are invited to attend the Annual Meeting and are entitled to and requested to vote on the proposals described in this proxy statement.

  2. What is Wisconsin Power and Light Company and how does it relate to Alliant Energy Corporation?

We are a subsidiary of Alliant Energy Corporation (“Alliant Energy” or “AEC”), which is a public utility holding company whose regulated utilities are Interstate Power and Light Company (“IPL”) and Wisconsin Power and Light Company (“WPL”).

  3. Who is entitled to vote at the Annual Meeting?

Only shareowners of record at the close of business on April 3, 2012, are entitled to vote at the Annual Meeting. As of the record date, 13,236,601 shares of our common stock (owned solely by AEC) and 1,049,225 shares of preferred stock, in seven series (representing 599,630 votes), were issued and outstanding. Each share of our common stock and our preferred stock, with the exception of the 6.50% Series, is entitled to one vote per share. The 6.50% Series of Company preferred stock is entitled to 1/4 vote per share.

  4. What items are to be voted upon at the Annual Meeting?

You may vote on the following proposals:

• to elect as Directors of the Company the five (5) nominees named in this proxy statement, two (2) to serve for terms expiring at the 2014 Annual Meeting and three (3) to serve for terms expiring at the 2015 Annual Meeting;

• to conduct a non-binding, advisory vote on the compensation of our named executive officers; and

• to ratify the appointment of Deloitte & Touche LLP as our independent registered public accounting firm for 2012.

  5. How does the Board of Directors recommend I vote?

Our Board of Directors recommends that you vote your shares “FOR” each of the listed director nominees; “FOR” approval of the compensation of our named executive officers as disclosed in the Compensation Discussion and Analysis section and accompanying compensation tables and narrative discussion contained in this proxy statement; and “FOR” the ratification of the appointment of Deloitte & Touche LLP as our independent registered public accounting firm for 2012.

  6. How can I vote my shares?

You may vote either in person at the Annual Meeting or by appointing a proxy. If you desire to appoint a proxy, then sign and date each proxy card you receive and return it in the envelope provided. Appointing a proxy will not affect your right to vote your shares if you attend the Annual Meeting and desire to vote in person.

  7. How are votes counted?

• Election of directors — You may vote “FOR” all of the director nominees or you may “WITHHOLD” your vote with respect to one or more nominees.

• Advisory vote on compensation of our named executive officers — You may vote “FOR” or “AGAINST” approval of the compensation of our named executive officers, or you may “ABSTAIN.”

• Ratification of independent registered public accounting firm — You may vote “FOR” or “AGAINST” ratifying the appointment of Deloitte & Touche LLP as our independent registered public accounting firm for 2012, or you may “ABSTAIN.”

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• If you return your signed proxy card but do not mark the boxes showing how you wish to vote, your shares will be voted “FOR” all listed director nominees, “FOR” approval of the compensation of our named executive officers and “FOR” ratification of the appointment of Deloitte & Touche LLP as our independent registered public accounting firm for 2012. If your proxy card is not signed, your votes will not be counted.

If you hold your shares through a bank, broker or other record holder and you do not provide such bank, broker or other record holder with specific voting instructions on a timely basis, your shares will not be voted with respect to the election of directors or the advisory vote on compensation of our named executive officers. We urge you to carefully consider all of the proposals and direct your bank, broker or other record holder to vote your shares as you desire.

  8. Can I change my vote?

You have the right to revoke your proxy at any time before the Annual Meeting by:

• providing written notice to our Corporate Secretary at 4902 North Biltmore Lane, Madison, Wisconsin 53718 and voting in person at the Annual Meeting; or

• appointing a new proxy prior to the start of the Annual Meeting.

Attendance at the Annual Meeting will not cause your previously appointed proxy to be revoked unless you specifically so request in writing. If you want to revoke your proxy by mailing a new proxy card to the Company or by sending a written notice of revocation, you should ensure that you mail it in sufficient time for it to be received by the Company before the day of the Annual Meeting. If your shares are held by a bank, broker or other record holder on your behalf, you may submit voting instructions in accordance with the process provided by such record holder.

  9. What is the required vote for each item on the proxy card?

Election of Directors. Directors will be elected by a plurality of the votes cast at the meeting (assuming a quorum is present). Consequently, any shares not voted at the meeting, including as a result of broker non-votes, will not be counted as votes cast. The proxies solicited may be voted for a substitute nominee or nominees if any of the nominees are unable to serve, or for good reason will not serve, a contingency the Board of Directors does not currently anticipate. See “What happens if a Director nominee does not receive a majority of votes cast?” below for information concerning our director resignation policy.

Advisory Vote on Compensation of Our Named Executive Officers. Approval of the advisory vote on executive compensation requires that the votes cast “FOR” the approval of our executive compensation exceed the votes cast “AGAINST” the proposal at the Annual Meeting (assuming a quorum is present). For purposes of determining the vote required for this proposal, abstentions and broker non-votes will have no impact on the vote.

Ratification of Appointment of Independent Auditor. Approval of the ratification of the appointment of our independent registered public accounting firm requires that the votes cast “FOR” the approval exceed the votes cast “AGAINST” the proposal at the Annual Meeting (assuming a quorum is present). For purposes of determining the vote required for this proposal, abstentions and broker non-votes will have no impact on the vote.

10. What happens if a Director nominee does not receive a majority of votes cast?

Pursuant to our Corporate Governance Principles, any nominee for director in an uncontested election who receives a greater number of votes “withheld” from his or her election than votes “for” such election will promptly tender his or her resignation to the Chairperson of the Board of Directors. A Resignation Committee will promptly consider that resignation and recommend to the Board of Directors, based on all relevant factors, whether to accept the tendered resignation or reject it. The Board of Directors will then act on that recommendation no later than 90 days following the date of the shareowners’ meeting at which the election occurred. We will promptly publicly disclose the Board of Directors’ decision, including a full explanation of the process by which the decision was reached and, if applicable, the reasons for rejecting the resignation. The full details of our majority voting policy are set forth on Alliant Energy’s website at www.alliantenergy.com/investors under the “Corporate Governance” caption.

11. Who may attend the Annual Meeting?

All shareowners who owned shares of our common stock and preferred stock on April 3, 2012, may attend the Annual Meeting.

12. How does the proxy voting process work?

If the proxy card is voted properly as described under “How do I vote?” the proxy will be voted in accordance with the instructions indicated by it. If a proxy is given, the persons named in the proxy will have authority to vote in accordance

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with their best judgment on any other matter that is properly presented at the meeting for action, including any proposal to adjourn or concerning the conduct of the meeting.

The presence in person or by proxy of at least a majority of the shares of our common stock entitled to vote at the meeting constitutes a quorum. Abstentions and broker “non-votes” count as present for establishing a quorum. If you have returned valid proxy instructions or vote in person, your shares will be counted for the purpose of determining whether there is a quorum, even if you abstain from any matter introduced at the meeting.

13. Who tabulates the votes?

All votes will be tabulated by the inspector of election appointed for the Annual Meeting, who will separately tabulate affirmative and negative votes (or withheld votes in the case of the election of directors), abstentions and broker non-votes. Shares held by persons attending the Annual Meeting but not voting, shares represented by proxies that reflect abstentions as to one or more proposals and broker non-votes will be counted as present for purposes of determining a quorum.

14. What does it mean if I get more than one proxy card?

If your shares are registered differently and are in more than one account, then you will receive more than one proxy card. Be sure to vote all of your accounts to ensure that all of your shares are voted. We encourage you to have all accounts registered in the same name and address (whenever possible). You can accomplish this by contacting Wells Fargo Shareowner Services at the address below:

Wells Fargo Shareowner Services

161 North Concord Exchange; P.O. Box 64854

St. Paul, MN 55164-0854

1-800-356-5343

www.shareowneronline.com

15. How do I attend the Annual Meeting?

If you are a registered shareowner, simply bring your photo identification to the Annual Meeting. If you are a beneficial owner of stock held by a bank, broker or other record holder (with your stock held in “street name”), an admission card with the form of a proxy will be sent to you by your bank, broker or such other record holder. If you do not receive the admission card with the form of a proxy in time, you may be admitted to the meeting by showing your most recent brokerage statement or other proof of ownership verifying your beneficial ownership of our common stock or preferred stock on April 3, 2012, the record date for voting. You should also bring your photo identification. Because seating is limited, admission will be limited to shareowners or their proxy holders who have an admission card or other proof of ownership.

16. How will voting on any other business be conducted?

Our Board of Directors does not know of any business to be considered at the Annual Meeting other than the three proposals set forth in this proxy statement. These consist of the election of directors, the advisory vote on compensation of our named executive officers, and the ratification of the appointment of Deloitte & Touche LLP as our independent registered public accounting firm for 2012. If any other business is properly presented at the Annual Meeting, your proxy gives John O. Larsen, our President, and F. J. Buri, our Corporate Secretary, authority to vote on such matters at their discretion.

17. Where and when will I be able to find the results of the voting?

The results of the voting will be announced at the Annual Meeting. You may also call us at the information number shown on the Notice of Annual Meeting for the results. We will also file the voting results on a Current Report on Form 8-K with the Securities and Exchange Commission (“SEC”) within four business days following the Annual Meeting.

18. Are the 2011 Annual Report and these proxy materials available on the Internet?

Yes. As required by rules adopted by the SEC, we are making our proxy statement and our annual report available to our shareowners electronically via the Internet. You can access these materials at http://www.alliantenergy.com/WPLproxy.

19. When are shareowner proposals for the 2013 Annual Meeting due?

All shareowner proposals to be considered for inclusion in our proxy statement for the 2013 Annual Meeting, pursuant to Rule 14a-8 under the Securities Exchange Act of 1934 (“Rule 14a-8”), must be received at our principal office by

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December 18, 2012. In addition, any shareowner who intends to present a proposal from the floor at the 2013 Annual Meeting must submit the proposal to our Corporate Secretary no later than March 4, 2013.

20. Who is our independent registered public accounting firm and how is it appointed?

Deloitte & Touche LLP audited our financial statements for 2011. Representatives of Deloitte & Touche LLP are not expected to be present at the Annual Meeting. The Audit Committee of the Board of Directors has appointed, and is recommending for ratification by shareowners its appointment of, Deloitte & Touche LLP as our independent registered public accounting firm for 2012.

21. Who will bear the cost of soliciting proxies for the Annual Meeting and how will these proxies be solicited?

We will pay the cost of preparing, assembling, printing, mailing and distributing these proxy materials. In addition to the mailing of these proxy materials, the solicitation of proxies or votes may be made in person, by telephone or by electronic communication by our officers and employees who will not receive any additional compensation for these solicitation activities. We will pay banks, brokers, nominees and other fiduciaries reasonable charges and expenses incurred in forwarding the proxy materials to their principals.

22. If more than one shareowner lives in my household, how can I obtain an extra copy of the proxy statement and the 2011 Annual Report?

Pursuant to SEC rules, services that deliver our communications to shareowners that hold their shares through a bank, broker or other holder of record may deliver to multiple shareowners sharing the same address a single copy of our Annual Report and proxy statement. Upon written or oral request, we will mail a copy of the proxy statement and the 2011 Annual Report to any shareowner at a shared address to which a single copy of the document was previously delivered. You may notify us of your request by calling or writing to us at the information address or number shown on the Notice of Annual Meeting. You may also access these materials at http://www.alliantenergy.com/WPLproxy.

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PROPOSAL ONE

ELECTION OF DIRECTORS

Annual Election

At the Annual Meeting, two directors will be elected with terms expiring in 2014 and three directors will be elected with terms expiring in 2015. The nominees for election as recommended by the Nominating and Governance Committee and selected by the Board of Directors are Patrick E. Allen, Patricia L. Kampling, Ann K. Newhall, Dean C. Oestreich and Carol P. Sanders. Each of the nominees is currently serving on our Board of Directors. Mr. Allen and Ms. Kampling, if elected as a director, will serve until our Annual Meeting of Shareowners in 2014 or until his or her successor has been duly qualified and elected. Ms. Newhall, Mr. Oestreich and Ms. Sanders, if elected as directors, will serve until our Annual Meeting of Shareowners in 2015 or until his or her successor has been duly qualified and elected.

Directors will be elected by a plurality of the votes cast at the meeting (assuming a quorum is present). Consequently, any shares not voted at the meeting, including as a result of broker non-votes, will have no effect on the election of directors. The proxies solicited may be voted for a substitute nominee or nominees if any of the nominees are unable to serve, or for good reason will not serve, a contingency the Board of Directors does not currently anticipate.

Brief biographies of the director nominees and continuing directors follow. These biographies include their ages (as of December 31, 2011); an account of their specific business experience; the names of publicly held and certain other corporations of which they also are, or have been within the past five years, directors; and a brief discussion of their specific experience, qualifications, attributes or skills that led to the conclusion that they should serve as directors. Except as otherwise indicated, each nominee and continuing director has been engaged in his or her present occupation for at least the past five years.

NOMINEES FOR DIRECTOR

	PATRICK E. ALLEN Age 47	Director since 2011 Nominated Term expires in 2014
	Mr. Allen has served as Senior Vice President and Chief Financial Officer at Rockwell Collins, Inc., in Cedar Rapids, Iowa, since 2005. Mr. Allen previously served in various financial officer positions at Rockwell Collins and its subsidiaries since 2001. He has passed the certified public accounting exam and is an audit committee financial expert. Mr. Allen has been a director of AEC and IPL since 2011. He was originally recommended as a nominee in 2011 by a third-party search firm acting on behalf of the Nominating and Governance Committee. Mr. Allen’s experience with a publicly traded company, international financial reporting standards, operations, customer perspectives and technology matters led to the conclusion that he should serve on our Board of Directors.
	PATRICIA L. KAMPLING Age 52	Director since 2012 Nominated Term expires in 2014
	Ms. Kampling serves as our Chairman of the Board and Chief Executive Officer effective April 1, 2012. She previously served as Chief Operating Officer, from February 2011 through March 2012, as Vice President and Chief Financial Officer from January 2009 to February 2011, as Vice President and Treasurer from January 2007 to January 2009 and as Vice President of Finance from August 2005 to January 2007. She has prior industry experience in various executive positions at Commonwealth Edison Company and other subsidiaries of Exelon Corporation. Ms. Kampling has been a director of AEC and IPL since 2012. She currently serves on the board of directors of Briggs & Stratton Corporation, American Transmission Company and Wisconsin Manufacturers and Commerce. Ms. Kampling’s leadership positions in publicly traded companies and her experience in finance, operations, customer perspectives, regulatory, technology, environmental and diversity matters led to the conclusion that she should serve as the Chairman of our Board of Directors.
	ANN K. NEWHALL Age 60	Director since 2003 Nominated Term expires in 2015
	Ms. Newhall retired in August 2008 from her position as Executive Vice President, Chief Operating Officer and Secretary and as a director of Rural Cellular Corporation (“RCC”), a cellular communications corporation located in Alexandria, Minnesota, following RCC’s sale to Verizon. Ms. Newhall held this position from 2000 to 2008. Ms. Newhall has served as a Director of AEC and IPL since 2003. Ms. Newhall is Chairperson of the Compensation and Personnel Committee. Ms. Newhall’s leadership positions within a publicly traded company and her experience in operations, customer perspectives, legal, regulatory, human resources and technology matters led to the conclusion that she should serve on our Board of Directors.

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	DEAN C. OESTREICH Age 59	Director since 2005 Nominated Term expires in 2015
	Mr. Oestreich has been a consultant to Pioneer Hi-Bred International, Inc., a developer and supplier of advanced plant genetics, and a wholly-owned subsidiary of DuPont Corporation, located in Johnston, Iowa, since January 2010. He previously served as Chairman of Pioneer Hi-Bred International, Inc., from November 2007 until his retirement in December 2009. Mr. Oestreich also served as Vice President of DuPont Corporation from 2004 through 2009. He previously served as President of Pioneer Hi-Bred International, Inc. from 2004 to 2007. He serves as a director of Nexsteppe, a feedstock solutions business for biofuels, biopower and biobased product industries. Mr. Oestreich has served as a Director of AEC and IPL since 2005. Mr. Oestreich is Chairperson of the Environmental, Nuclear, Health and Safety Committee. Mr. Oestreich’s experience with publicly traded companies, operations, customer perspectives, regulatory and public affairs, human resources, technology, environmental matters and safety led to the conclusion that he should serve on our Board of Directors.
	CAROL P. SANDERS Age 44	Director since 2005 Nominated Term expires in 2015
	Ms. Sanders has been the Senior Vice President, Chief Financial Officer and Treasurer of Jewelers Mutual Insurance Company of Neenah, Wisconsin, a nationwide insurer that specializes in protecting jewelers and personal jewelry, since May 2011. She previously served as the Chief Financial Officer since 2004. Before that, Ms. Sanders served as Controller and Assistant Treasurer of Sentry Insurance located in Stevens Point, Wisconsin, from 2001 to 2004. Ms. Sanders has served as a Director of AEC and IPL since 2005. She is Chairperson of the Audit Committee and an audit committee financial expert. Ms. Sanders’ experience with publicly traded companies, operations, customer perspectives, regulatory matters, human resources and technology matters led to the conclusion that she should serve on our Board of Directors.

The Board of Directors unanimously recommends a vote “FOR” all nominees for election of directors.

CONTINUING DIRECTORS

	MICHAEL L. BENNETT Age 58	Director since 2003 Term expires in 2013
	Mr. Bennett has been a private investor in Sioux City, Iowa, since May 2010. He previously served as President and Chief Executive Officer of Terra Industries Inc., an international producer of nitrogen products headquartered in Sioux City, Iowa, since April 2001. He also served as Chairman of the Board and President for Terra Nitrogen Company, L.P., a subsidiary of Terra Industries Inc. He has served on the board of directors of Arclin, Inc., a privately held company located in Canada since 2010. Mr. Bennett has served as a Director of AEC and IPL since 2003. Mr. Bennett is Chairperson of the Nominating and Governance Committee, our Lead Independent Director and an audit committee financial expert. Mr. Bennett’s leadership of a publicly traded company and his experience in operations, customer perspectives, legal matters, and human resource matters led to the conclusion that he should serve on our Board of Directors.
	DARRYL B. HAZEL Age 63	Director since 2006 Term expires in 2013
	Mr. Hazel has been the principal of Darryl B. Hazel Consulting LLC, a business consulting firm in Detroit, Michigan, since January 2010. He retired in January 2010 from his position as Senior Vice President, Global Services Initiatives of Ford Motor Company, an automobile manufacturer. He also served as President of the Customer Service Division and Senior Vice President of Ford Motor Company from March 2006 to September 2009. He previously served as President of Marketing of Ford Motor Company from September 2005 to March 2006; President of the Ford Division from April 2005 to September 2005; and President of the Lincoln Mercury Division from August 2002 to April 2005. Mr. Hazel has served as a Director of AEC and IPL since 2006. Mr. Hazel is an audit committee financial expert. Mr. Hazel’s long-term experience as an executive of a publicly traded company and its subsidiaries along with his experience in operations, customer perspectives, human resources, technology matters and diversity initiatives led to the conclusion that he should serve on our Board of Directors.

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	SINGLETON B. MCALLISTER Age 59	Director since 2001 Term expires in 2014
	Ms. McAllister has been a partner in the Washington, D.C. office of the law firm of Blank Rome LLP since June 2010. She previously served as a partner in the law firm of LeClair & Ryan LLP from October 2007 to June 2010 and as a partner in the law firm of Mintz, Levin, Cohn, Ferris, Glovsky and Popeo P.C. from July 2005 to October 2007. She served as the Corporate Diversity Counsel practice group chair and in the public law and policy strategies group of the Washington, D.C. law firm office of Sonnenschein, Nath & Rosenthal, LLP from 2003 to July 2005. Ms. McAllister has served on the board of directors of United Rentals, Inc., since 2004. Ms. McAllister has served as a Director of AEC and IPL since 2001. Ms. McAllister’s experience in legal, legislative, regulatory, public affairs, human resources and diversity initiatives led to the conclusion that she should serve on our Board of Directors.
	DAVID A. PERDUE Age 62	Director since 2001 Term expires in 2013
	Mr. Perdue has been the Chief Executive Officer of Aquila Group LLC, a private investment firm based in Sea Island, Georgia, since 2007. He retired in July 2007 from his position as Chairman of the Board of Directors and Chief Executive Officer of Dollar General Corporation, a retail organization headquartered in Goodlettsville, Tennessee. He was named Chief Executive Officer and a Director in April 2003 and elected Chairman of the Board of Directors in June 2003. From July 2002 to March 2003, he was Chairman and Chief Executive Officer of Pillowtex Corporation, a textile manufacturing company. Pillowtex emerged from bankruptcy in May 2002 and reentered bankruptcy in July 2003. Mr. Perdue has served on the board of directors of Jo-Anne Stores, Inc. from 2008 to 2011, Liquidity Services, Inc., since 2009, and Graphic Package Holding Company, since 2011. Mr. Perdue has served as a Director of AEC and IPL since 2001. Mr. Perdue is an audit committee financial expert. Mr. Perdue’s leadership of publicly traded companies and his experience in operations, marketing, human resources and technology matters led to the conclusion that he should serve on our Board of Directors.
	JUDITH D. PYLE Age 68	Director since 1994 Term expires in 2013
	Ms. Pyle is President and Chief Executive Officer of Judith Dion Pyle and Associates, a financial services company located in Middleton, Wisconsin. Prior to assuming her current position in 2003, she served as Vice Chair of The Pyle Group, a financial services company located in Madison, Wisconsin. She previously served as Vice Chair and Senior Vice President of Corporate Marketing of Rayovac Corporation, a battery and lighting products manufacturer located in Madison, Wisconsin. In addition, Ms. Pyle is a director of Uniek, Inc. Ms. Pyle has served as a Director of AEC since 1992 and of IPL since 1998. Ms. Pyle’s experience in operations, marketing, human resources and diversity initiatives led to the conclusion that she should serve on our Board of Directors.

RETIRING DIRECTOR

	WILLIAM D. HARVEY Age 62	Director since 2005 Retired
	Mr. Harvey retired as Chairman of the Board of Directors and Chief Executive Officer of the Company, AEC and IPL, effective March 31, 2012. He served in those positions since February 2006. He served as Chief Executive Officer of the Company, AEC and IPL since July 2005. He served as President of AEC from January 2004 until February 2011. He previously served as President and Chief Operating Officer of AEC and Chief Operating Officer of the Company and IPL from January 2004 to July 2005. Mr. Harvey serves on the board of directors of Sentry Insurance Company. Mr. Harvey’s long-term experience with our operations, customer perspectives, utility and environmental regulation, legal matters, safety and diversity initiatives led to the conclusion that he should serve as Chairman of the Board of Directors during 2011.

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MEETINGS AND COMMITTEES OF THE BOARD

The Board of Directors has standing Audit; Compensation and Personnel; Nominating and Governance; Environmental, Nuclear, Health and Safety; Capital Approval; and Executive Committees. The Board of Directors has adopted formal written charters for each of the Audit, Compensation and Personnel, and Nominating and Governance Committees, which are available on the Alliant Energy website at www.alliantenergy.com/investors under the “Corporate Governance” caption. Joint meetings in the descriptions below refer to meetings of the committees of the Company, Alliant Energy and IPL. Directors serve on the following committees as indicated below:

	Audit	Compensation   and Personnel	Nominating         and     Governance	Environmental,     Nuclear, Health   and Safety	Capital      Approval	Executive
Patrick E. Allen	·			·
Michael L. Bennett	·		·*		·	·
Darryl B. Hazel	·		·
Patricia L. Kampling					**	**
Singleton B. McAllister			·	·
Ann K. Newhall		·*		·	·	·
Dean C. Oestreich			·	·*	·	·
David A. Perdue		·	·
Judith D. Pyle		·		·
Carol P. Sanders	·*	·				·

* Committee Chairperson

** Non-voting Committee Chairperson

The following is a description of each of these committees:

Audit Committee

The Audit Committee held six joint meetings in 2011. The committee currently consists of C. P. Sanders (Chair), P. E. Allen, M. L. Bennett, and D. B. Hazel. Each of the members of the committee is independent as defined by the New York Stock Exchange (“NYSE”) corporate governance listing standards and applicable SEC rules. The Board of Directors has determined that Ms. Sanders and the other three Audit Committee members each qualify as an “audit committee financial expert” as defined by SEC rules.

The Audit Committee is responsible for assisting the Board of Directors in oversight of: (1) the integrity of our financial statements; (2) our compliance with legal and regulatory requirements; (3) the independent registered public accounting firm’s qualifications and independence; and (4) the performance of our internal audit function and independent registered public accounting firm. The Audit Committee is also directly responsible for the appointment, retention, termination, compensation and oversight of our independent registered public accounting firm.

Compensation and Personnel Committee

The Compensation and Personnel Committee held six joint meetings in 2011. The committee currently consists of A. K. Newhall (Chair), D. A. Perdue, J. D. Pyle and C. P. Sanders. The Board of Directors has determined that each of the four members of the committee is independent as defined by the NYSE corporate governance listing standards and applicable SEC rules.

The Compensation and Personnel Committee reviews and approves corporate goals and objectives relevant to Chief Executive Officer compensation and the compensation of the other executive officers, evaluates the Chief Executive Officer’s performance and determines and approves, either as a committee or together with the other independent directors, the Chief Executive Officer’s compensation level based on its evaluation of the Chief Executive Officer’s performance in addition to reviewing and approving the recommendations of the Chief Executive Officer with regard to the other executive officers. The committee has responsibilities with respect to our executive compensation and incentive programs and management development programs. It also makes recommendations to the Nominating and Governance Committee regarding compensation for the non-management directors.

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To support the Compensation and Personnel Committee in carrying out its mission, the committee has the authority to retain and terminate the services of outside advisors, experts and others to assist the committee. The expenses associated with such outside advisors, experts and others are paid by Alliant Energy. For 2011, the Committee engaged Pay Governance LLC, or Pay Governance, as an outside compensation consultant to serve as an advisor in evaluating the compensation of the Chief Executive Officer, other named executive officers and our outside non-management directors. Pay Governance also provides assistance and serves as an advisor and provides market information and trends regarding executive compensation programs; provides benchmarking and competitive market reviews of our executive officer total compensation; assists with the design of our short- and long-term incentive programs and executive retirement programs as well as assisting management with the implementation of these programs; and other consulting services at the request of the Committee. Aliant Energy will pay to Pay Governance its fees as determined by the Committee upon the Committee’s request as well as related out-of-pocket expenses of Pay Governance.

The Compensation and Personnel Committee reviews and approves all elements of our executive compensation programs. Our Chief Executive Officer provides input to the committee in the assessment, design and recommendation of executive compensation programs, plans and awards. Annually, the Chief Executive Officer reviews with the committee market data provided by Towers Watson about the comparable companies that are identified as our peer group to help verify survey job information adequately captures officers’ duties. Based on that data, the Chief Executive Officer recommends to the committee base salary adjustments and short- and long-term incentive targets in relation to external market data while also considering internal equity considerations and executive officers’ individual performance. The Chief Executive Officer provides recommendations to the committee for total annual compensation of executive officers. The Chief Executive Officer does not, however, make any recommendation to the committee regarding his or her own compensation. Further, the Chief Executive Officer and other executive officers assess the performance of those executive officers reporting to them. The Chief Executive Officer is invited to attend all committee meetings to provide an update of progress made toward achievement of annual performance goals and to provide management’s views on compensation program design features and components.

The Compensation and Personnel Committee has reviewed and approved the charter for our internal Total Compensation Committee made up of vice presidents of our energy delivery, new energy resources, generation, finance, legal and human resources business units. The Compensation and Personnel Committee has delegated to the Total Compensation Committee various powers of design and administration associated with our employee benefit plans for salaried and hourly employees. The Compensation and Personnel Committee reviews the minutes and actions of the Total Compensation Committee. The Compensation and Personnel Committee has also reviewed and approved the charter for our internal Investment Committee. The Investment Committee is made up of voting members and non-voting members. The voting members include officers in our finance, treasury, human resources, and accounting business units. The Compensation and Personnel Committee has delegated to the Investment Committee various powers regarding managing investment assets of our benefit and compensation plans and programs. The Compensation and Personnel Committee reviews the investment policies related to these benefit and compensation plans on an annual basis.

Nominating and Governance Committee

The Nominating and Governance Committee held five joint meetings in 2011. The committee currently consists of M. L. Bennett (Chair), D. B. Hazel, S. B. McAllister, D. C. Oestreich and D. A. Perdue. Each of the members of the committee is independent as defined by the NYSE corporate governance listing standards and applicable SEC rules.

The Nominating and Governance Committee’s responsibilities are to: (1) identify individuals qualified to become members of the Board of Directors, consistent with the criteria approved by the Board, and to recommend nominees for directorships to be filled by the Board or shareowners; (2) identify and recommend members of the Board of Directors qualified to serve on Board committees; (3) develop and recommend to the Board of Directors a set of corporate governance principles; (4) oversee the evaluation of the Board of Directors and our management; (5) oversee our related person transaction policy; and (6) advise the Board of Directors with respect to other matters relating to our corporate governance. The committee is responsible for evaluating nominees for director and director candidates based on such criteria and for seeking to assure that the specific talents, skills and other characteristics that are needed to increase the effectiveness of the Board of Directors are possessed by an appropriate combination of directors. Our Corporate Governance Principles, as adopted by the Board of Directors, provide insight for the committee on the consideration of appropriate criteria for director nominees.

In making recommendations of nominees to serve as directors to the Board of Directors, the committee will examine each director nominee on a case-by-case basis regardless of the source of the recommendation and take into account all factors it

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considers appropriate, which may include strength of character, mature judgment, career specialization, relevant technical skills or financial acumen, diversity of viewpoint and industry knowledge. However, the committee believes that, to be recommended as a director nominee, each candidate must:

• display the highest personal and professional ethics, integrity and values;

• have the ability to exercise sound business judgment;

• be highly accomplished in his or her respective field, with superior credentials and recognition and broad experience at the administrative and/or policy-making level in business, government, education, technology or public interest;

• have relevant expertise and experience, and be able to offer advice and guidance to the Chief Executive Officer based on that expertise and experience;

• be independent of any particular constituency, be able to represent all of our shareowners and be committed to enhancing long-term shareowner value; and

• have sufficient time available to devote to activities of the Board of Directors and to enhance his or her knowledge of our business.

The Nominating and Governance Committee also believes the following qualities or skills are necessary for one or more directors to possess:

• At least one director should have the requisite experience and expertise to be designated as an “audit committee financial expert” as defined by the applicable rules of the SEC.

• Directors generally should be active or former senior executive officers of public companies or leaders of major and/or complex organizations, including commercial, governmental, educational and other non-profit institutions.

• Directors should be selected so that the Board of Directors is a diverse body, with diversity reflecting age, gender, race and professional experience.

The Nominating and Governance Committee has determined that each nominee for director, as well as each continuing member of the Board of Directors, satisfies the applicable criteria for directors outlined above. In addition, the committee annually reviews particular attributes, qualities and skills attendant to the members of our Board of Directors and documents this annual assessment through the use of a directors’ skills matrix that assesses directors’ experiences and expertise in areas such as public company environment, finance, operations, customer perspective, regulatory and public affairs, legal, human resources, technology, environment and safety, and diversity initiatives. Diversity is a component of our core value of respect. We strive to create a workplace where people of diverse backgrounds, talents and perspectives support our mission. Diversity is reflected in our directors’ skills matrix, in the criteria specified for use in the evaluation of our director nominees by the committee and in the Board of Directors’ responsibilities in advising and counseling management. Specifically, our Corporate Governance Principles provide that the Board of Directors is responsible for using the broad range of experiences and perspectives of directors to advise and counsel management, both in meetings and in informal consultations, on significant issues facing the Company. In its annual performance evaluation, the committee assesses whether it effectively identifies individuals qualified to be nominated to the Board of Directors for election by the shareowners consistent with the criteria approved by the Board of Directors. We believe that our Board of Directors has been effective in assembling a diverse body of individuals as measured by the criteria of age, gender, race and professional experience specified in our Corporate Governance Principles.

The Nominating and Governance Committee will consider nominees recommended by shareowners in accordance with our Nominating and Governance Committee Charter and our Corporate Governance Principles. Any shareowner wishing to make a recommendation should write to our Corporate Secretary and include appropriate biographical information concerning each proposed nominee. The Corporate Secretary will forward all recommendations to the committee. Our Bylaws also set forth certain requirements for shareowners wishing to nominate director candidates directly for consideration by shareowners. These provisions require such nominations to be made pursuant to timely notice (as specified in the Bylaws) in writing to our Corporate Secretary.

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We and the Nominating and Governance Committee maintain a file of recommended potential director nominees, which is reviewed at the time a search for a new director needs to be performed. To assist the committee in its identification of qualified director candidates, the committee may engage an outside search firm.

The Nominating and Governance Committee has the responsibility to periodically review and make recommendations to the Board of Directors regarding policies and procedures for selection of the Chief Executive Officer and succession planning in the event of an emergency or the retirement of the Chief Executive Officer. The committee, in conjunction with the full Board, discusses succession planning and other management development issues at least annually and more often, as necessary.

The Nominating and Governance Committee is responsible for ensuring that new members of our Board of Directors have an appropriate orientation to our company and their responsibilities as directors to permit them to become familiar with the industry, business units and corporate governance processes of our company. The committee is also responsible for ensuring that a process is in place to provide educational opportunities on an ongoing basis to help assure that each director has the necessary skills to perform his or her responsibilities as a director. The committee has established an aspirational continuing education guideline for approximately one half of the members of our Board of Directors to attend a continuing education program every year.

Environmental, Nuclear, Health and Safety Committee

The Environmental, Nuclear, Health and Safety Committee held one joint meeting in 2011. The committee currently consists of D. C. Oestreich (Chair), P. E. Allen, S. B. McAllister, A. K. Newhall and J. D. Pyle. Each of the members of the committee is independent as defined by the NYSE corporate governance listing standards and applicable SEC rules.

The Environmental, Nuclear, Health and Safety Committee’s responsibilities are to review environmental policy and planning issues of interest to us, including matters involving the Company before environmental regulatory agencies and compliance with air, water and waste regulations. The committee also reviews health- and safety-related policies, activities and operational issues as they affect employees, customers and the general public. In addition, the committee reviews issues related to nuclear generating facilities from which we and IPL purchase power.

Capital Approval Committee

The Capital Approval Committee held no meetings in 2011. The committee currently consists of M. L. Bennett, A. K. Newhall and D. C. Oestreich. Ms. Kampling is the Chair and a non-voting member of this committee.

The purpose of the Capital Approval Committee is to evaluate certain investment proposals where (1) an iterative bidding process is required, and/or (2) the required timelines for a proposal would not permit the proposal to be brought before a regular meeting of the Board of Directors and/or a special meeting of the full Board of Directors is not practical or merited.

Executive Committee

The Executive Committee held no meetings in 2011. The committee currently consists of M. L. Bennett, A. K. Newhall, D. C. Oestreich and C. P. Sanders, each the Chairperson of a committee. Ms. Kampling is the Chair and a non-voting member of this committee.

The purpose of the Executive Committee is to possess all the powers and authorities of the Board of Directors when the Board is not in session, except for the powers and authorities excluded for such a committee under the Wisconsin Business Corporation Law. The committee meets only when a regular, or special, Board of Directors meeting, or a meeting of the Capital Approval Committee, would be impractical and an important need exists that requires action.

Attendance and Performance Evaluations

The Board of Directors held six joint meetings in 2011. Each director attended at least 75% of the aggregate number of meetings of the Board and Board committees on which he or she served.

The Board of Directors and each Board committee conduct performance evaluations annually to determine their effectiveness and suggest improvements for consideration and implementation. In addition, the Compensation and Personnel Committee evaluates the performance of the Chief Executive Officer on an annual basis.

Members of our Board of Directors are not expected to attend our annual meeting of shareowners. None of the Board of Directors were present for our 2011 Annual Meeting.

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CORPORATE GOVERNANCE

Corporate Governance Principles

Our Board of Directors has adopted Corporate Governance Principles that, in conjunction with the Board committee charters, establish processes and procedures to help ensure effective and responsive governance by the Board. The Corporate Governance Principles are available on the Aliant Energy website at www.alliantenergy.com/investors under the “Corporate Governance” caption.

The Board of Directors has adopted certain categorical standards of independence to assist it in making determinations of director independence under the NYSE corporate governance listing standards. The categorical standards are available in Appendix A to our Corporate Governance Principles available on the Alliant Energy website at www.alliantenergy.com/investors under the “Corporate Governance” caption.

The Board of Directors also gave consideration to certain other factors in relation to an independence determination. Messrs. Allen, Hazel, Oestreich and Ms. Pyle serve as consultants, executive officers and/or directors of companies that are customers of our Company or IPL. These customer relationships do not constitute a material relationship under the NYSE corporate governance listing standards cited above or the SEC rules governing related person transactions. However, each of these circumstances was evaluated under the applicable NYSE corporate governance listing standards and applicable SEC rules. The Board determined that these factors did not impair the independence of these directors.

Based on these standards and this evaluation, the Board of Directors has affirmatively determined by resolution that each of Messrs. Allen, Bennett, Hazel, Oestreich, and Perdue and Mses. McAllister, Newhall, Pyle and Sanders has no material relationship with us and, therefore, is independent in accordance with the NYSE corporate governance listing standards. The Board of Directors will regularly review the continuing independence of the directors.

The Corporate Governance Principles provide that at least 75% of the members of the Board of Directors must be independent directors under the NYSE corporate governance listing standards. The Audit, Compensation and Personnel, and Nominating and Governance Committees must consist of all independent directors.

Related Person Transactions

We have adopted a written policy that we will annually disclose information regarding related person transactions that is required by regulations of the SEC to be disclosed, or incorporated by reference, in our Annual Report on Form 10-K. For purposes of the policy:

The term “related person” means any of our directors or executive officers, or nominee for director, and any member of the immediate family of such person.

A related person transaction is generally a consummated or currently proposed transaction in which we were or are to be a participant and the amount involved exceeds $120,000, and in which the related person had or will have a direct or indirect material interest. A related person transaction does not include:

• the payment of compensation by us to our executive officers, directors or nominee for director;

• a transaction if the interest of the related person arises solely from the ownership of our shares and all shareowners receive the same benefit on a pro rata basis;

• a transaction in which the rates or charges involved are determined by competitive bids, or that involves the rendering of services as a common or contract carrier, or public utility, at rates or charges fixed and in conformity with law or governmental authority; or

• a transaction that involves our services as a bank, transfer agent, registrar, trustee under a trust indenture, or similar services.

Furthermore, a related person is not deemed to have a material interest in a transaction if the person’s interest arises only (i) from the person’s position as a director of another party to the transaction; (ii) from the ownership by such person and all other related persons, in the aggregate, of less than a 10% equity interest in another person (other than a partnership) that is a

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party to the transaction; (iii) from such person’s position as a limited partner in a partnership and all other related persons have an interest of less than 10% of, and the person is not a general partner of or holds another position in, the partnership; and (iv) from both such director position and ownership interest. Pursuant to the policy, each of our executive officers, directors and nominees for director is required to disclose to the Nominating and Governance Committee of the Board of Directors certain information regarding the related person transaction for review, approval or ratification by the Nominating and Governance Committee. Such disclosure to the Nominating and Governance Committee should occur before, if possible, or as soon as practicable after the related person transaction is effected, but in any event as soon as practicable after the executive officer, director or nominee for director becomes aware of the related person transaction.

The Nominating and Governance Committee’s decision whether or not to approve or ratify the related person transaction should be made in light of the Committee’s determination as to whether consummation of the transaction is believed by the Committee to not be, or to have been contrary to, the best interests of our company. The Committee may take into account the effect of a director’s related person transaction on such person’s status as an independent member of our Board of Directors and eligibility to serve on Board committees under SEC and NYSE rules.

Based on these standards, we had no related person transactions in 2011, and no related person transactions are currently proposed.

Board Leadership Structure; Executive Sessions

Our Bylaws and our Corporate Governance Principles provide that the Board of Directors is responsible to select a Chairperson and a Chief Executive Officer. Our Corporate Governance Principles also provide that the Board of Directors should have the flexibility to decide whether it is best for our company that the two positions be filled by the same individual and that, if the Chairperson of the Board is not an independent director, the chairperson of the Nominating and Governance Committee will be designated the Lead Independent Director. The Board of Directors has determined that the positions of Chairperson of the Board and Chief Executive Officer should be held by one individual with the use of a Lead Independent Director. In choosing to combine the roles of Chairperson of the Board and Chief Executive Officer, the Board of Directors has expressed its belief that our management, through the Chairperson and Chief Executive Officer, should have the primary accountability, and the responsibility to act as the spokesperson, for us. The Board of Directors believes that maintaining the positions of Chairperson and Chief Executive Officer in a single individual will promote a consistent and accurate message to our investors, employees, customers and other constituencies.

While our Corporate Governance Principles do not grant the Lead Independent Director any special authority over management, both the Board of Directors and management recognize the Lead Independent Director as a key position of leadership within the Board of Directors. Our Corporate Governance Principles do provide that the Lead Independent Director will preside at regular executive sessions of the Board of Directors without management participation. We believe that the use of a Lead Independent Director has proven effective for us and has greatly facilitated communication of important issues between the Board of Directors and the Chief Executive Officer. Subsequent to the adoption of our Corporate Governance Principles formally establishing the Lead Independent Director position, our Lead Independent Director’s role has developed to include additional board governance activities, including the following examples:

• communicating applicable information arising out of the deliberations in executive sessions to the Chairperson and Chief Executive Officer;

• reviewing with the Chairperson and Chief Executive Officer items of importance for consideration by the Board of Directors;

• acting as principal liaison between the independent directors and the Chairperson and Chief Executive Officer on sensitive issues;

• discussing with the Chairperson and Chief Executive Officer important issues to assess and evaluate the view of the Board of Directors;

• consulting and meeting with any or all of our independent directors, at the discretion of either party and with or without the attendance of the Chairperson and Chief Executive Officer;

• in conjunction with the Nominating and Governance Committee, recommending to the Chairperson the membership of the various board committees and selection of the board committee chairs;

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• in conjunction with the Nominating and Governance Committee, interviewing all board candidates and making recommendations to the Board of Directors on director nominees;

• mentoring and counseling new members of the Board of Directors to assist them in becoming active and effective directors;

• in conjunction with the Nominating and Governance and Compensation and Personnel Committees, reviewing and approving the philosophy of, and program for, compensation of the independent directors; and

• evaluating, along with the other members of the Board of Directors, the Chief Executive Officer’s performance and meeting with the Chief Executive Officer to discuss the Board of Directors’ evaluation.

As the Chairperson of the Nominating and Governance Committee, Mr. Bennett is currently designated as the Lead Independent Director. At every regular in-person meeting of the Board of Directors, the independent directors meet in executive session with no member of our management present.

Risk Oversight

Our Corporate Governance Principles provide that the Board of Directors is responsible for overseeing and understanding our vision and mission, strategic plan, overall corporate risk profile, risk parameters, annual operating plan and annual budget and for monitoring whether these plans are being implemented effectively. The Board of Directors annually conducts a broad based risk assessment. For 2011, this risk assessment was conducted in association with reviews by the president and chief operating officer and the vice president and chief financial officer. The methodology of the risk assessment identifies key themes and trends, quantifies our key risks and develops mitigation plans and strategies. This assessment provides the platform to develop appropriate audit plans and to ensure resources are devoted to areas having the highest risk. This assessment culminates in the Annual Risk Management Report to the Board of Directors. On an on-going basis, the Audit Committee regularly discusses our policies with respect to risk assessment and risk management, our financial risk exposures and the steps we have taken to monitor and control such exposures. The Board of Directors relies on the Compensation and Personnel Committee to address potential risks arising from our general compensation programs and policies for all employees, and the Compensation and Personnel Committee conducted an assessment in 2011 of these policies and practices to determine whether risks arising from them were reasonably likely to have a material adverse effect on us as described in further detail under “Compensation Committee Risk Assessment” below.

Communication with Directors

Shareowners and other interested parties may communicate with the full Board, non-management directors as a group or individual directors, including the Lead Independent Director, by providing such communication in writing to our Corporate Secretary, who will post such communications directly to our Board of Directors’ website.

Ethical and Legal Compliance Policy

We have adopted a Code of Conduct, that serves as our code of ethics, and that applies to all employees, including our Chief Executive Officer, chief financial officer and chief accounting officer, as well as our Board of Directors. We make our Code of Conduct available on the Alliant Energy website at www.alliantenergy.com/investors under the “Corporate Governance” caption. We intend to satisfy the disclosure requirements under Item 5.05 of Form 8-K regarding amendments to, or waivers from, the Code of Conduct by posting such information on the Alliant Energy website.

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OWNERSHIP OF VOTING SECURITIES

All of our common stock is held by Alliant Energy. Listed in the following table are the number of shares of Alliant Energy’s common stock beneficially owned as of February 29, 2012, by (1) the executive officers listed in the Summary Compensation Table, (2) all of our director nominees and directors and (3) all director nominees, directors, and the executive officers as a group. The directors, and executive officers as a group owned less than 1% of the outstanding shares of Alliant Energy’s common stock on that date. No individual director or officer owned more than 1% of the outstanding shares of Alliant Energy’s common stock on that date. No director or officer owns any other equity of Alliant Energy Corporation or any of its subsidiaries.

NAME OF BENEFICIAL OWNER	SHARES BENEFICIALLY OWNED(1)
EXECUTIVE OFFICERS(2)
Thomas L. Aller		60,395	(3)
Thomas L. Hanson		32,979	(3)
John O. Larsen		28,071	(3)
James H. Gallegos		8,575
Dundeana K. Doyle		29,380	(3)(4)
DIRECTOR NOMINEES
Patrick E. Allen		100
Patricia L. Kampling		57,370	(3)
Ann K. Newhall		17,083	(3)
Dean C. Oestreich		18,486	(3)
Carol P. Sanders		14,819	(3)
DIRECTORS
Michael L. Bennett		26,536	(3)
William D. Harvey		305,316	(3)(5)
Darryl B. Hazel		10,819	(3)
Singleton B. McAllister		13,687	(3)
David A. Perdue		21,774	(3)
Judith D. Pyle		18,541
All Executive Officers and Directors as a Group (17 people)		666,931	(3)

⁽¹⁾  Total shares of Alliant Energy’s common stock outstanding as of February 29, 2012, were 110,959,728.

⁽²⁾  Stock ownership of Mr. Harvey and Ms. Kampling is shown with the directors.

⁽³⁾  Included in the beneficially owned shares shown are indirect ownership interests with shared voting and investment powers: Mr. Harvey — 3,769 and Mr. Aller — 1,000; shares of common stock held in deferred compensation plans: Mr. Bennett — 26,036, Mr. Harvey — 49,657, Mr. Hazel — 10,143, Ms. McAllister — 8,038, Ms. Newhall — 15,914, Mr. Oestreich — 17,486, Mr. Perdue — 21,774, Ms. Sanders — 14,819, Mr. Aller — 8,937, Ms. Doyle — 9,425, Mr. Hanson — 4,157, Ms. Kampling — 1,626, Mr. Larsen — 6,772, (all executive officers and directors as a group —194,784); and stock options exercisable on or within 60 days of February 29, 2012: Mr. Harvey — 11,258 and Mr. Aller — 21,654 (all executive officers and directors as a group — 32,912).

⁽⁴⁾  Ms. Doyle retired effective August 31, 2011, and her beneficial ownership is shown as of August 17, 2011, the last date on which we were able to obtain information from Ms. Doyle.

⁽⁵⁾  Mr. Harvey retired effective March 31, 2012.

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The following table sets forth information, as of December 31, 2011, regarding beneficial ownership by the only persons known to us to own more than 5% of Alliant Energy’s common stock. The beneficial ownership set forth below has been reported on Schedule 13G filings with the SEC by the beneficial owners.

Amount and Nature of Beneficial Ownership

	Voting Power				Investment Power
Name and Address of Beneficial Owner	Sole		Shared		Sole		Shared		Aggregate		Percent of Class
BlackRock, Inc. (and certain affiliates) 40 East 52nd Street New York, NY 10022		10,243,616		0		10,243,616		0		10,243,616		9.23	%

None of our directors or officers own any shares of preferred stock. To our knowledge, no shareowner beneficially owned 5% or more of any class of our preferred stock as of December 31, 2011 other than the 4.96% series of preferred stock. The following table sets forth information, as of December 31, 2011, regarding beneficial ownership by the only persons known to us to own more than 5% of the 4.96% series of preferred stock. The beneficial ownership set forth below has been reported on Scheduled 13G filings with the SEC by the beneficial owners.

Amount and Nature of Beneficial Ownership

	Voting Power				Investment Power
Name and Address of Beneficial Owner	Sole		Shared		Sole		Shared		Aggregate		Percent of Class
Wells Fargo and Company 420 Montgomery Street San Francisco, CA 94104		10,283		0		10,283		0		10,283		15.83	%

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COMPENSATION DISCUSSION AND ANALYSIS

The following is a discussion and analysis of the compensation paid by Alliant Energy to our executive officers listed in the Summary Compensation Table for services performed for us, Alliant Energy and Alliant Energy’s other subsidiaries. References to “we,” “us,” “our,” and similar references in the following discussion and analysis include us, Alliant Energy and Alliant Energy’s other subsidiaries together unless the context indicates otherwise.

Executive Summary

This compensation discussion and analysis explains our compensation philosophy, policies and practices with respect to our named executive officers. For calendar year 2011, our named executive officers were:

Named Executive Officer	Title
William D. Harvey	Chief Executive Officer and  Chairman of the Board of Directors
Patricia L. Kampling	Chief Operating Officer and Former Chief Financial Officer
Thomas L. Hanson	Vice President and Chief Financial Officer
Thomas L. Aller	Senior Vice President — Energy Resource Development
John O. Larsen	President
James H. Gallegos	Vice President and General Counsel
Dundeana K. Doyle	Former Senior Vice President — Energy Delivery

Ms. Doyle retired from the Company effective August 31, 2011; however, because Ms. Doyle would have qualified as a named executive officer but for the fact that she was not an executive officer at the end of 2011, we have considered her a named executive officer for purposes of this compensation discussion and analysis.

Effective March 31, 2012, Mr. Harvey retired as a Director, Chairman of the Board of Directors and Chief Executive Officer of the Company, Alliant Energy Corporation and Interstate Power and Light Company. Effective April 1, 2012, Ms. Kampling succeeded Mr. Harvey as Chairman of the Board and Chief Executive Officer of the Company, Alliant Energy Corporation and Interstate Power and Light Company.

As a result of Ms. Kampling becoming Chief Executive Officer, effective as of April 1, 2012, her base salary increased to $740,000, her target percentage under Alliant Energy’s 2012 Management Incentive Award Plan increased to 105% of base salary, and her long-term incentive target percentage for awards made in 2012 increased to 265% of her base salary. No other changes have been made to Ms. Kampling’s compensation arrangements; Alliant Energy and Ms. Kampling have not entered into an employment agreement.

Linkages Between Company Performance and Executive Compensation

Alliant Energy’s strategic plan focuses on its core business of delivering regulated electric and natural gas service in its Iowa, Wisconsin and Minnesota service territories. The strategic plan is built upon three key elements: competitive costs, safe and reliable service, and balanced generation.

In 2011, we delivered strong performance both to Alliant Energy’s shareowners and our customers despite the continued challenging macroeconomic and competitive environment.

We note the following Alliant Energy performance achievements in 2011:

• Adjusted 2011 utility earnings per share of $2.72 exceeded the target of $2.70 and represented a slight increase over 2010 results.

• At the end of 2011, the relative total shareowner return compared to the Edison Electric Institute (EEI) Stock Index (a peer group stock index selected by our Compensation Committee as described below) performed at the 68^th percentile for the last year, the 74^th percentile over the last three years and the 70^th percentile over the last five years.

• At the end of 2011, the relative total shareowner return compared to the S&P Midcap Utility Index performed at the 76^th percentile for the last year, the 75^th percentile over the last three years and the 65^th percentile over the last five years.

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• For the one-, three- and five-year periods ending on December 31, 2011, Alliant Energy’s total shareowner returns were approximately 25%, 75% and 45%, respectively.

• 2011 adjusted cash flows from the utilities and service company of $782 million significantly exceeded the 2011 target of $700 million.

• Cumulative, operational goal performance in 2011 was slightly above target.

The following table demonstrates our pay for performance linkage by displaying the results of Alliant Energy financial performance goals used in our incentive programs and incentive compensation payouts over the past three years.

Year	Adjusted Utility Earnings Per Share From Continuing Operations	Annual Incentive Payout as % of Target			Relative Total Shareowner Return (Three Years)*	Performance Share Payout as % of Target			Performance Contingent    Restricted Stock Vesting
2009	$1.86		0	%	31st percentile		0	%	No
2010	$2.68		130	%	45th percentile		75	%	Yes
2011	$2.72		101	%	75th percentile		162.5	%	Yes

* Total Shareowner Return as compared to the S&P Utility Midcap Index in 2009 and 2010 and compared to the EEI Stock Index in 2011.

Recent Developments in Alliant Energy’s Executive Compensation Program

The following are the key executive compensation program changes recently implemented to improve our corporate governance and ensure appropriate compensation and benefits to our executive officers:

• None of our existing executive separation arrangements have Section 280G gross-up provisions.

• We have made continued progress on our policy to reduce and substantially eliminate the amount of perquisites paid to our executive officers by eliminating a health care benefit received by executive officers that was more generous than that paid to other employees of Alliant Energy.

• In 2011, Alliant Energy adopted a new peer group for measuring performance for purposes of our long-term incentive performance share grants. The new peer group more appropriately reflects Alliant Energy’s market capitalization.

• In 2011, Alliant Energy discontinued the use of personal performance “modifiers” under Alliant Energy’s Management Incentive Compensation Plan with respect to our named executive officers in order to ensure that all annual bonus payouts to our named executive officers are contingent on Company performance.

• In 2011, Alliant Energy undertook a review of our compensation programs, which resulted in the amendment of many such programs to better reflect market practices and to enact several technical and legal changes to its plans, such as tightening the definition of change in control and clarifying certain provisions to ensure compliance with the Internal Revenue Code of 1986, amended, which we refer to as the tax code.

Executive Compensation Objectives and Principles

We believe that Alliant Energy’s strategic plan is best implemented if the executive compensation program is designed to achieve the following key compensation objectives:

• Reward Strong Performance: motivate and reward executives to contribute to the achievement of our business objectives by strengthening the relationship between pay and performance and emphasizing variable at-risk compensation.

• Align Executives’ and Shareowners’ Interests: align executive officers’ interests with those of Alliant Energy shareowners by delivering a significant proportion of total compensation that is dependent upon Alliant Energy total shareowner return.

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• Attract and Retain Valuable Officers: attract and retain the best possible personnel through competitive compensation that is comparable to that of similar companies.

We believe these objectives attract, retain and motivate a highly proficient executive management team that is actively engaged in producing results for our shareowners and customers. Based on these objectives, the Company’s Compensation and Personnel Committee (the “Compensation Committee”) considered the principles and the other factors described below when making compensation decisions.

We adhere to the following compensation principles, which are intended to facilitate the achievement of our compensation objectives:

• Target Base Pay to Market Median: base salary levels should be targeted at the median (50^th percentile) of base salaries paid in the market for comparable positions.

• At-Risk Compensation: a substantial portion of our executive officers’ compensation should be based on achievement of performance goals, with long-term incentives comprising a majority of the performance-based pay.

• Equity-Ownership: executive officers should have significant holdings of Alliant Energy common stock.

• Minimized Systemic Risk-Taking: compensation programs should be developed to properly manage risk-taking incentives, including providing a mix of long-term and short-term compensation and multiple performance criteria.

• Access to Retirement Programs: executive officers should have access to retirement plans commonly in use among comparable companies, including deferred compensation plans, pension plans, supplemental retirement programs and 401(k) savings plans.

Components of Executive Compensation Program

The major elements of the executive compensation program are base salary, annual incentives, long-term (equity) incentives, retirement and other benefits. In setting the level for each major component of compensation, we consider an executive officer’s total compensation (which consists of all elements of compensation including employee benefit programs), the target market reference point, the current market for talent, our historic levels of compensation, company culture, individual and company performance, the executive’s length of tenure, and internal pay equity. The table below summarizes the function of each component of compensation, each of which is described in more detail below.

Component	Description	Objective within Compensation Program
Base Salary	Fixed compensation, subject to annual review and increased or decreased in response to changes in responsibility, performance, length of service or competitive practice.	•    Provides base compensation at a level consistent with competitive practices. •    Reflects roles, responsibilities, skills, experience and performance. •    Adheres to market practice.
Annual Incentives	Annual cash incentive plan based on achievement of objective utility and service company financial and non-financial performance measures.	•    Motivates and rewards for achievement of annual utility and service company goals. •    Aligns management and key stakeholder interests by linking pay and performance.

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Component	Description	Objective within Compensation Program
Long-Term Equity Incentives	Allows grant of a variety of types of awards, including performance contingent restricted stock, performance shares and time-based restricted stock.	•    Motivates and rewards financial performance over a sustained period. •    Aligns management and shareowner interests by encouraging management ownership. •    Enhances retention of management personnel. •    Rewards strong total shareowner return and earnings growth. •    Measures performance relative to peers. •    Promotes achievement of strategic plan by linking pay to achievement of strategic goals.
Other Benefits	Deferred compensation and other retirement benefits.	•    Provides for current and future needs of the executives and their families. •    Enhances recruitment and retention. •    Adheres to competitive market practice.
Contractual and Severance Arrangements	Key Executive Employment and Severance Agreements (KEESAs) and Executive Severance Plan: Contingent amounts payable only if employment is terminated under certain conditions.	•    Enhances retention of management personnel by providing employment continuity. •    Encourages the objective evaluation and execution of potential changes to the Company’s strategy and structure.

In order to properly reward strong performance, we weigh performance-based incentive pay more heavily than other elements of our named executive officers’ total direct compensation. In 2011, incentive pay accounted for 54% to 78% of target total direct compensation for our named executive officers. The following table shows the breakdown of the total direct compensation pay mix for each of our named executive officers in 2011. The figures in this table were calculated using targeted compensation for 2011 and therefore may differ from the actual payments for 2011 as reported in the Summary Compensation Table below.

Named Executive Officer	Title	Salary as a %   of Total	All Incentives as   a % of Total	Annual Incentive   as a % of Total	Long-Term     Incentive as a   % of Total
William D. Harvey	Chief Executive Officer and Chairman of the Board of Directors	22%	78%	22%	56%
Patricia L. Kampling	Chief Operating Officer, Former Chief Financial Officer	32%	68%	20%	48%
Thomas L. Hanson	Vice President and Chief Financial Officer	33%	67%	22%	45%
Thomas L. Aller	Senior Vice President — Energy Resource Development	46%	54%	21%	33%
John O. Larsen	President	46%	54%	21%	33%
James H. Gallegos	Vice President and General Counsel	40%	60%	22%	38%
Dundeana K. Doyle	Former Senior Vice President — Energy Delivery	46%	54%	21%	33%

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Process for Setting Executive Compensation

Our compensation programs are subject to a thorough review process that includes Compensation Committee review and approval of all elements of our executive compensation program; the advice of an independent, third-party compensation consultant; and a Compensation Committee of independent directors that meets in executive session without management at every meeting.

Role of Compensation Committee

The Compensation Committee sets each component and level of compensation for the Company’s named executive officers and other executive officers. In order to set each component throughout the year, the Compensation Committee regularly reviews compensation reports prepared by the Compensation Committee’s outside compensation consultant, including reports on competitive pay practices, alternative mixes of compensation components and potential payouts under various termination scenarios.

Role of Chief Executive Officer

The Chief Executive Officer recommends the level of compensation for the Company’s named executive officers and other senior Company executives, other than himself or herself. He or she is present and available to the Compensation Committee during their meeting with respect to the compensation of the Company’s named executive officers and other senior Company executives, except when his or her own compensation is considered in executive session. The Chief Executive Officer, with the assistance of Alliant Energy’s human resources staff, compiles data and provides reports to the Compensation Committee to assist in their deliberations. The Chief Executive Officer’s compensation package is determined by the Compensation Committee in executive session.

Role of Independent Compensation Consultants

The Compensation Committee receives data, analysis and support from Pay Governance, a nationally recognized executive compensation consulting firm. During 2011, Pay Governance met with management and participated in Compensation Committee meetings, analyzed the competitive level of each element of compensation for each of the named executive officers, and provided information regarding executive compensation trends. Pay Governance was engaged by and reports solely to the Compensation Committee, and meets with the Compensation Committee at each meeting in executive session.

Role of Benchmarking

We utilize compensation data from general industry and the energy services sector in determining the appropriate levels of compensation for our executive officers. Although our business is focused in the energy services sector, we believe that the competitive labor market for our company includes both general industry and the energy services industry, particularly for those executives who serve in a general management capacity.

The benchmark data from the energy services sector used in 2011 were drawn from Towers Watson’s 2011 Energy Services Industry Executive Compensation Database (the “2011 Energy Services database”), a survey of over 60 companies, which comprises nearly all U.S. utilities. The general industry data were obtained from Towers Watson’s 2011 General Industry Executive Compensation Database, a survey of over 400 companies, the majority of which are Fortune 1000 companies (the “2011 General Industry database”), which we considered to be a fair gauge of compensation practices among leading companies. In using these broad-based surveys, we considered only aggregate data and did not select any individual companies for comparison. By focusing on the data in the aggregate, we can avoid the undue impact of statistically outlying companies and obtain a general understanding of compensation practices in the market. All of the survey data were updated to January 2012 using a 3% annual update factor, as 3% was the anticipated average annual increase for the survey companies. The data from each of the companies in both databases were size-adjusted based on gross revenue. We refer to the median in these surveys as our “market reference point” throughout the following discussion.

For general management positions, including with respect to Messrs. Harvey, Hanson and Gallegos and Ms. Kampling, equally blended energy industry and general industry data from these databases are used as our primary market reference point for compensation, reflecting the broader talent market for these jobs. For utility-specific operating positions, including with respect to Messrs. Aller and Larsen and Ms. Doyle, energy industry data are used as our market reference point. See “Meetings and Committees of the Board — Compensation and Personnel Committee” for more details.

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Components of Executive Compensation Program — Base Salary

We pay base salaries to provide management with a level of fixed compensation at competitive levels to reflect their professional skills, responsibilities and performance, and to attract and retain key executives. Because the Company is not contractually bound to pay particular levels of base salary to our executive officers, we have the flexibility to make adjustments to take into consideration changes in the market, responsibilities and performance against job expectations. We also consider the nature of the position, the responsibilities, skills, experience and tenure of the officer, and his or her past performance.

The Compensation Committee considers salaries that fall within 15% of our market reference point to be competitive. Base salaries may fall outside the competitive market range due to tenure in job position, increased responsibilities or outstanding job performance. We may adjust base salaries to keep current with our market reference point, to recognize outstanding individual performance or to recognize an increase in responsibility. In 2011, aggregate base salaries of our named executive officers were, on average, approximately 8% below our market reference point, which is within our target.

The following table sets forth the base salaries of each named executive officer as of the end of the 2011 and 2010 calendar years, as well as the percentage change from the prior year.

Named Executive Officer	2011 Base Salary			2010 Base Salary		Percentage Increase
William D. Harvey	$	900,000		$	875,000		3	%
Patricia L. Kampling	$	500,000		$	500,000		0	%
Thomas L. Hanson	$	329,800		$	270,000		22	%
Thomas L. Aller	$	290,000		$	282,000		3	%
John O. Larsen	$	301,500		$	301,500		0	%
James H. Gallegos	$	310,000		$	310,000		0	%
Dundeana K. Doyle	$	291,400	*	$	281,400		4	%

* As of August 31, 2011, Ms. Doyle’s retirement date.

Mr. Harvey’s salary for 2011 was slightly below the median of the blended energy industry and general industry market reference point, but within the competitive market median range. Base salaries with respect to Messrs. Hanson and Gallegos and Ms. Kampling were below the competitive market median range, reflecting the fact that these executives are new to their respective roles within the Company. Base salary for Mr. Hanson was significantly increased due to his promotion to chief financial officer during 2011. Other executive officers were within the competitive market median range. As a result of Ms. Kampling becoming Chief Executive Officer, effective as of April 1, 2012, her base salary increased to $740,000.

Components of Executive Compensation Program — MICP Annual Incentives

Our executive officers, including our named executive officers, are eligible to participate in the Alliant Energy Management Incentive Compensation Plan, or MICP, which is our annual incentive plan and was adopted under Alliant Energy 2010 Omnibus Incentive Plan. The MICP provides executive officers with the opportunity for annual cash bonuses tied directly to the achievement of Alliant Energy’s performance goals. The MICP encourages executive officers to achieve superior annual performance on key financial and operational goals. The Compensation Committee sets goals designed to drive annual performance and align the interests of management with the interests of our shareowners and customers.

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The Compensation Committee seeks to set MICP opportunities at the median annual incentive target levels compared to our benchmark data, measured as a percentage of base salary. The Compensation Committee considers targeted payouts that fall within 15% of the market median to be competitive. Participants may earn no payment or may earn up to 150% of their target payment based on achievement of the performance goals. The following table sets forth the target payout levels under the MICP with respect to each named executive officer for 2011.

Named Executive Officer	MICP Target Payout  as a Percentage of Base Salary
William D. Harvey	100%
Patricia L. Kampling	65%
Thomas L. Hanson	65%
Thomas L. Aller	45%
John O. Larsen	45%
James H. Gallegos	55%
Dundeana K. Doyle	45%

Target annual incentive compensation with respect to Messrs. Hanson and Gallegos and Ms. Kampling were below the competitive market median range, reflecting the fact that these executives are new to their respective roles within the Company. Target annual incentive compensation for Mr. Aller was slightly above the competitive market median range, due to his long tenure with Alliant Energy and his current role as President of Interstate Power and Light Company. All other executive officers’ target payouts were within the competitive market median range. As a result of Ms. Kampling becoming Chief Executive Officer, effective as of April 1, 2012, her target percentage under the MICP increased to 105% of base salary.

Alliant Energy pays incentives from a pool of funds that Alliant Energy establishes for MICP payments. The Compensation Committee establishes goals based primarily on utility performance, which it derives from Alliant Energy’s strategic plan and from operational benchmarks intended to benefit our shareowners, customers and employees. These performance goals apply to all named executive officers and determine the funding level of an incentive pool. Adjusted utility earnings per share from continuing operations determine whether or not the incentive pool will be funded. If the adjusted utility earnings per share threshold (shown in the table below) is not met, then the incentive pool is not funded and no incentives are paid under the MICP. After the adjusted utility earnings per share threshold is met, then a percent of the incentive pool is funded based on the achievement of the goals described below. If all such goals are met at target level, the incentive pool is funded at 100% of target. The size of the incentive pool will vary, from 0% to 150% of target, based on goal performance.

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The performance goals, targets and actual 2011 performance were:

Goal	Percent of Incentive Pool			Target	Actual	Percent Payment Toward Incentive Pool
Adjusted earnings per share from continuing operations of the utilities (“EPS”)		60%		EPS: Threshold: $2.43 Target: $2.70 Maximum: $3.04	$2.72*		60%
Adjusted cash flows from utilities and service company		10%		$700 million	$782 million**		10%
Customer satisfaction		10%		Complaints to Regulators: Threshold: 927 Target: 843 Maximum: 717	577		15%
Power supply availability		5%		Availability of Tier One Plants: Threshold: 85.5% Target: 86.5% Maximum: 88.5%	86.2%		4%
Power supply reliability		5%		SAIDI/SAIFI Reliability Index: Threshold: 90% Target: 100% Maximum: 115%	108%		6%
Safety		5%		OSHA Recordable Incident Rate: Threshold: 3.64 Target: 3.31 Maximum: 2.81	4.02		0%
Diversity (goal achieved if two of the three goals are met)		5%		Minority Employees: Threshold: 4.9% Target: 5.4% Maximum: 6.1%	5.2%		6%
				Women in Non-Traditional Jobs: Threshold: 9.0% Target: 9.4% Maximum: 10.0%	9.4%
				Spending to Minority and Women-Owned Businesses: Threshold: $44 million Target: $49 million Maximum: $56 million	$77 million
TOTAL		100	%				101	%

* This non-GAAP number is intended to represent ongoing operations of the utilities by excluding the effects of certain charges for asset write-downs and impairments, regulatory-related charges and credits, benefits related to tax changes, pension plan charges and emission allowance charges. These excluded items are not reflective of ongoing operations of the utilities and are therefore excluded when determining executive compensation.

** This non-GAAP number excludes the effects of sales of customer accounts receivable, net of tax pension contributions and net collateral held or paid by the utilities.

The performance goals are combined to determine the annual incentive payment for each executive officer. The performance goal achievement of 101% was multiplied by each named executive officer’s target payout percentage to set their final annual incentive payments. The individual annual incentive payments made for 2011 are reported below in the Summary Compensation Table. We have discontinued the use of any personal modifier with respect to our named executive officers, which would allow Alliant Energy to pay an executive more under the MICP than otherwise provided by the MICP’s formula.

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Components of Executive Compensation Program — Long-Term Incentives

We award long-term incentive compensation based on the achievement of longer-term, multi-year financial goals. Long-term, at-risk incentive payments account for 33%-56% of our named executive officers’ total targeted compensation, appropriately reflecting our compensation program’s emphasis on the long-term financial strength of the company.

In 2011, we granted long-term incentive compensation to executive officers in the form of (a) performance-contingent restricted stock, (b) performance shares and (c) solely with respect to Mr. Aller, time-based restricted stock, in each case granted under Alliant Energy’s 2010 Omnibus Incentive Plan. All of the equity awards granted to executive officers in 2011, with the exception of Mr. Aller’s time-based restricted stock described below, were performance based and will be forfeited if performance results are not achieved in future years.

We determine the value of each executive officer’s long-term incentive opportunity by targeting the median value of long-term opportunities of our market reference point. The Compensation Committee considers targeted payouts that fall within 15% of our market reference point to be competitive. The targets are set by assessing the individual performance of the executive officer and internal equity among our executives, and considering the competitiveness of the total direct compensation package. Targeted payouts may fall outside the competitive market range due to tenure in a job position, competitiveness of the total direct compensation package and individual performance. Based on these factors, the Compensation Committee approved grants of long-term incentives to our named executive officers with targeted grant values determined according to the percentages of base salary set forth in the table below. The Compensation Committee approves the dollar value of the long-term equity awards to be granted prior to the actual grant date and we grant the number of shares necessary to approximate that dollar value based on the fair market value of Alliant Energy’s share price on the grant date.

Named Executive Officer	Long-Term Incentive Grants in 2011 as a Percentage of Base Salary
William D. Harvey	250%
Patricia L. Kampling	150%
Thomas L. Hanson	135%
Thomas L. Aller	70%
John O. Larsen	70%
James H. Gallegos	95%
Dundeana K. Doyle	70%

Target long-term payouts with respect to Messrs. Hanson and Gallegos and Ms. Kampling were below the competitive market range, reflecting the fact that these executives are new to their respective roles within the Company. As a result of Ms. Kampling becoming Chief Executive Officer, effective as of April 1, 2012, her long-term incentive target percentage for awards made in 2012 increased to 265% of her base salary.

The long-term incentive awards consist of performance contingent restricted stock and performance shares. We believe these two types of long-term equity awards provide incentives for our executive officers to produce value for shareowners over the long term on both an absolute basis and a relative basis. Performance contingent restricted stock vests if Alliant Energy’s consolidated income from continuing operations achieves specified growth objectives in two, three or four years. This rewards absolute long-term growth. We set the rate of growth required for the performance contingent restricted stock to vest based on the successful execution of our strategic plan. Performance shares vest and pay out at varying levels depending on Alliant Energy’s relative total shareowner return as compared to the companies comprising the EEI Stock Index. This rewards the outperformance of Alliant Energy’s peers and superior return to shareowners. The Compensation Committee granted long-term equity awards in 2011 consisting of 50% performance shares and 50% performance contingent restricted stock to equally emphasize absolute and relative long-term growth.

In addition to regular performance-based annual grants, in March 2011, Alliant Energy granted 5,000 shares of time-based restricted stock to Mr. Aller to increase the retentive value of his overall compensation package.

Alliant Energy has not issued stock options since 2004 because we believe that performance contingent restricted stock and performance shares provide appropriate incentive value.

In 2011, Alliant Energy amended the Alliant Energy 2010 Omnibus Incentive Plan to clarify the definition of “Change of Control of the Company” with respect to awards granted on or after January 1, 2012. The amendment made technical

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changes to tighten the definition of Change of Control and clarify compliance with provisions of the tax code and did not enhance the compensation or benefits of our executive officers. The amended definition also better conforms to market standards.

Performance Contingent Restricted Stock

In 2011, the Compensation Committee granted performance contingent restricted stock to our executive officers that will vest in two, three or four years if Alliant Energy’s consolidated income from continuing operations grows 16% over 2010 consolidated income from continuing operations. The growth contingency represents 5% compounded growth over three years. Alliant Energy’s 2010 adjusted base income from continuing operations is $308.2 million. This non-GAAP amount excludes the effects of asset impairments, regulatory-related charges and credits, legislative changes and other non-recurring items which we believe are not reflective of ongoing operations. Thus, the performance contingent restricted stock will vest in two, three or four years if Alliant Energy’s consolidated income from continuing operations in any year is $356.9 million. Consolidated income from continuing operations will be calculated excluding the effects of the following, if the amount is over $4 million on a pre-tax basis and is not considered in the annual budget approved by Alliant Energy’s Board of Directors: (i) charges for reorganizing and restructuring; (ii) discontinued operations; (iii) asset write-downs; (iv) gains or losses on the disposition of an asset or business; (v) mergers, acquisitions or dispositions; and (vi) extraordinary, unusual and/or non-recurring items of gain or loss, that in all of the foregoing Alliant Energy identifies in its audited financial statements, including footnotes, or the Management’s Discussion and Analysis section of the Alliant Energy’s periodic reports.

Consistent with our pay for performance criteria, performance contingent restricted stock granted to our executive officers in 2008 were forfeited because the applicable performance criteria were not met, as of December 31, 2011, the end of the fourth year of the performance period.

Performance Shares

In 2011, the Compensation Committee granted performance shares to our executive officers. The vesting of the performance shares is based on Alliant Energy’s relative total shareowner return over a three-year period. Performance shares provide a 100% payout, or target payout, if Alliant Energy’s relative total shareowner return over three years is equal to the median performance of a specific peer group selected by the Compensation Committee. The Compensation Committee selected the Edison Electric Institute (EEI) Stock Index as the peer group for the 2011 grants of performance shares because the EEI Stock Index more accurately reflected Alliant Energy’s relative market capitalization compared to the S&P 400 Midcap Utility Index, which was used in previous years. Performance share payouts are capped at 200% of the target payout. The following table shows the level of performance share payouts based on Alliant Energy’s total shareowner return as compared to the EEI Stock Index.

Alliant Energy’s Percentile Rank	Percent of Target Value Payout
90th percentile or greater	200%
80th percentile	175%
70th percentile	150%
60th percentile	125%
50th percentile	100%
45th percentile	75%
40th percentile	50%
Below 40th percentile	0%

Performance shares allow the executive officer to receive a payment in shares of Alliant Energy’s common stock, cash, or a combination of Alliant Energy’s common stock and cash, the value of which is equal to the number of Alliant Energy shares awarded, adjusted by the performance multiplier. If the executive officer chooses to take the payment in cash, the amount of the payout is determined by multiplying the number of Alliant Energy shares earned by the stock value on a date chosen by the Compensation Committee. The Compensation Committee chooses this date in advance of issuing the Alliant Energy shares.

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Components of Executive Compensation Program — Other Benefits

Alliant Energy also offers benefit programs to our executive officers with a focus towards their retirement consistent with those of our peer group. We provide these benefits to remain competitive with the general market for executive officers. These programs include a 401(k) savings plan, a deferred compensation plan and various pension benefits. The benefit programs are designed to be competitive in attracting, retaining and motivating our executive officers by providing competitive retirement benefits and to incentivize our executive officers to promote the Company’s interests over a long time-horizon. The Compensation Committee reviews benefit programs on a periodic basis to determine effectiveness and identify any necessary changes. The retirement-related benefit plans are reviewed periodically by the Compensation Committee and certain changes to the plans were adopted in 2011. A brief description of the plans is set forth in the table below.

Benefit	Description
Alliant Energy Deferred Compensation Plan (the “AEDCP”)	Enables participants to defer up to 100% of base salary and annual incentive awards on a pre-tax basis and to receive earnings or incur losses on the deferrals until the date of distribution. The shares of Alliant Energy’s common stock identified as obligations under the AEDCP are held in a rabbi trust.
Cash Balance Pension Plan	Offers flexible payment options and steady growth of retirement funds. The Cash Balance Pension Plan was frozen for participants effective August 2, 2008. Employees hired after December 25, 2005 do not participate.
Enhanced 401(k) Savings Plan	Provides for a match of $0.50 on each dollar for the first 8% of compensation contributed to their 401(k) Savings Plan account by the employee up to the IRS maximum. In addition, we contribute a percentage of employees’ salaries to their 401(k) accounts in addition to the company match. The amount of the company contribution ranges from 4% to 6% of an employee’s salary, depending on the employee’s age and number of years of service at the company.
Excess Retirement Plan	Provides the benefit that the participants would have earned under the Cash Balance Pension Plan and the 401(k) Savings Plan but for statutory limitations on employer-provided benefits imposed on those tax-qualified plans, and accruals earned on their deferrals into the AEDCP.
Supplemental Retirement Plan (“SRP”)	Provides retirement compensation in addition to the benefits provided by the Cash Balance Pension Plan and 401(k) Savings Plan, which are limited by the tax code. Generally payable only if the executive remains with us until retirement, disability or death.
Split Dollar / Reverse Split Dollar Life Insurance Plan	We pay the premiums for this insurance and these payments are taxable to the individual officers. We reimburse these executive officers for taxes associated with certain of these policies. These specific policies were grandfathered in 1998 and we no longer offer the policies to other executive officers as part of total executive compensation.

In 2011, the Compensation Committee enacted amendments to the AEDCP to provide new investment options for participants and to permit participants to reallocate their account balances among investment options with the exception of not permitting participants to reallocate account balances out of the Alliant Energy stock investment account. The Compensation Committee also enacted certain technical amendments to the AEDCP, the Excess Retirement Plan and the SRP, which provide for continuity of administration of such plans in the event of a change in control of Alliant Energy, which did not enhance the compensation or benefits payable under such plans.

In 2011, in connection with the retirement of Ms. Doyle, the Compensation Committee approved an amendment to the Supplemental Retirement Plan Agreement between Ms. Doyle and Alliant Energy to vest payment of the supplemental benefit at age 53.5, which resulted in a payment of $1,534,513 from the SRP to Ms. Doyle, in addition to other severance benefits, as discussed further below.

See “Nonqualified Deferred Compensation” below for more information regarding the AEDCP. See “Pension Benefits” below for more information regarding the Alliant Energy Cash Balance Pension Plan, the Excess Retirement Plan and the SRP.

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Perquisites

In 2009, Alliant Energy eliminated its flexible perquisite program. For 2011, Alliant Energy eliminated a portion of the executive health care perquisite that had been historically provided. Our executive officers remain eligible for executive physicals and long-term disability insurance, which were in excess of the benefits provided to our other employees.

Post-Termination Compensation

KEESAs

Alliant Energy currently has in effect Key Executive Employment and Severance Agreements (KEESAs) with our executive officers, including our named executive officers, and certain of our key employees, which provide certain severance benefits on a “double trigger” following a change in control. We believe the security afforded the executives by the KEESA will help the executives to remain focused on business continuity and reduce the distraction of the executive’s reasonable personal concerns regarding future employment during the uncertainty of a proposed change in control transaction. We believe the executives will be able to better consider the best interests of Alliant Energy and its shareowners due to the economic security provided by the KEESA benefits.

The KEESAs are paid if, within a period of up to three years after a change in control for Mr. Harvey or Ms. Kampling and two years for Messrs. Hanson, Gallegos, Aller and Larsen and Ms. Doyle, there has occurred both a change in control of Alliant Energy and loss of employment other than for cause, causing KEESA benefits to be subject to a “double trigger.” The double trigger mechanism ensures that only those executives adversely affected by a change in control would receive benefits under the KEESA. The cash termination benefit under the KEESA is up to three times base salary and target bonus for Mr. Harvey and Ms. Kampling and two times base salary and target bonus for Messrs. Hanson, Gallegos, Aller and Larsen and Ms. Doyle.

The KEESAs are generally designed to avoid the adverse effects of Section 280G of the tax code. With respect to Messrs. Hanson, Gallegos, Aller and Larsen and Ms. Doyle, the KEESAs provide that if any portion of the benefits under the KEESA or under any other agreement for the officer would constitute an excess parachute payment for purposes of the tax code, benefits will be reduced so that the officer will be entitled to receive $1 less than the maximum amount that he or she could receive without becoming subject to the 20% excise tax imposed by the tax code on certain excess parachute payments, or which we may pay without loss of deduction under the tax code. With respect to Ms. Kampling, the KEESA provides that if any portion of the benefits under the KEESA or under any other agreement would constitute an excess parachute payment for purposes of the tax code, she may receive the better of either a payment $1 less than the maximum amount she may receive without becoming subject to the 20% excise tax or the fully calculated payment subject to applicable excise taxes, for which she would be personally responsible.

The KEESA for Mr. Harvey provides that if any payments constitute an excess parachute payment, Alliant Energy will pay to Mr. Harvey the amount necessary to offset the excise tax and any additional taxes on this additional payment. In light of Mr. Harvey’s unique role and tenure within the Alliant Energy’s management, Mr. Harvey is the only executive officer with a gross-up provision in his KEESA.

We believe that the level of the benefits provided by the KEESAs to each executive officer reflects the appropriate amount of compensation necessary for our executive officers to consider our shareowners’ interests without interference of their own personal situation.

In consideration of the KEESA benefits, the executive agrees not to compete with Alliant Energy for a period of one year after the executive’s employment is terminated and to keep in confidence any proprietary information or confidential information for a period of five years after the executive’s employment is terminated by Alliant Energy or us. Both of these conditions can be waived in writing by Alliant Energy’s board of directors.

In 2011, as part of an ongoing corporate governance review, Alliant Energy approved a series of technical changes to the KEESAs for the officers of Alliant Energy, including the named executive officers, which (i) conforms the definition of “Change in Control of the Company” in the KEESAs to the definition provided in the 2010 Omnibus Incentive Plan, (ii) alters the timing of severance payments in the event of a qualifying termination of employment and (iii) clarifies the order in which certain termination payments will be reduced to the extent that any termination payments are reduced in order to avoid the imposition of excise taxes under Section 280G of the tax code. These changes did not enhance the compensation or benefits payable to our executive officers under the KEESAs.

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In connection with their respective retirements in 2011 and 2012, Ms. Doyle and Mr. Harvey terminated their KEESAs and waived any rights thereunder.

See “Potential Payments upon Termination or Change in Control” for more information regarding the KEESAs.

Executive Severance Plan

Alliant Energy also maintains a general executive severance plan for executive officers in the event that an officer’s position has been eliminated or significantly altered by us. The executive severance plan is designed to provide economic protection to key executives following the elimination of their position so that executives can remain focused on our business without undue personal concern. We recognize that circumstances may arise in which we may consider eliminating certain key positions. We believe the security afforded the executives by the severance plan will keep the executives focused on their duties at our company rather than on their personal concerns of job security. The plan provides for severance pay equal to one times annual base salary, payment of prorated incentive compensation within the discretion of the Chief Executive Officer, up to 18 months of COBRA coverage, six months of which are paid by Alliant Energy, outplacement services and/or tuition reimbursement of up to $10,000, and access to our employee assistance program. All executive officer severance packages are approved by the Compensation Committee. We believe our executive severance plan is consistent with plans throughout the industry.

In 2011, as part of an ongoing corporate governance review, Alliant Energy approved a series of technical changes to the executive severance plan to (i) impose a 52-day time limit on the requirement that a severed employee sign a release of claims as a condition to the receipt of benefits under the executive severance plan and provide that payments and benefits commence on the 60th day following termination, (ii) conform the definition of “Cause” in the executive severance plan to the definition provided in the KEESAs and (iii) provide that retiree-eligible employees will be eligible for benefits under the Alliant Energy’s subsidized retiree medical insurance program in lieu of benefits under COBRA upon termination from employment. These changes did not enhance the compensation or benefits payable to our executive officers under the executive severance plan.

See “Potential Payments upon Termination or Change in Control” for more information regarding the Executive Severance Plan.

Employment Agreements and Separation Arrangements

We and Alliant Energy do not have any other employment agreements with our executive officers.

Ms. Doyle retired from the Company in August 2011. In connection with her retirement, Alliant Energy approved a retirement package that included an Executive Agreement, which provided a cash payment of $291,400 and up to $10,000 in outplacement services or tuition reimbursement. This separation payment was in recognition of her years of service and in consideration for a one-year covenant not to compete and to keep information regarding Alliant Energy confidential, and a general release.

Executive Stock Ownership Guidelines

Alliant Energy has had stock ownership guidelines for our executives for many years. The guidelines require officers to own a certain number of shares of Alliant Energy common stock to further align the officer’s interest with that of the shareowners. In 2010, Alliant Energy adopted a new guideline that determines the required number of shares by taking the following multiples of the officer’s base salary as of the latest of (i) January 3, 2011, (ii) the date of hire or (iii) the date of promotion to a higher level of ownership requirement, as set forth in the table below.

Level of Seniority	Percent of Target Value Payout
Chief Executive Officer	4 times base salary
President	3 times base salary
Executive Vice President	2.5 times base salary
Senior Vice President	2 times base salary
Vice President	1.5 times base salary

The multiple of salary was divided by the closing price of Alliant Energy stock on January 3, 2011, (or the date of hire or promotion, if later) to determine the number of shares that the officer is required to hold (rounded to the nearest 500-share increment). That number of shares will not change unless the officer is promoted. By setting the number of shares this way,

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we mitigate the effect of short-term volatility on compliance caused by changes in Alliant Energy’s stock price and by changes in salary. Officers have five years from their hire date or the date they were promoted into a new position with a higher multiple to achieve the goal. Shares held outright, vested restricted stock, earned performance shares, shares held in the AEDCP, and shares held in the 401(k) Savings Plan count toward the ownership guidelines; unvested restricted stock and unearned performance shares do not count for this purpose.

Officers who have not yet met their share ownership level after five years are required to retain 100% of the after-tax value of vested long-term equity awards until the share ownership requirement is met. Our Chief Executive Officer retains the right to grant special dispensation for hardship, promotions or new hires. All of our current named executive officers who have held their current positions for five years are in compliance with the share ownership guidelines. The Alliant Energy shares owned by our named executive officers are shown in the “Ownership of Voting Securities” table above.

Impact of Section 162(m) of the Tax Code

Section 162(m) of the tax code generally limits the corporate deduction for compensation paid to Alliant Energy’s Chief Executive Officer and the three other most highly compensated executive officers (excluding our chief financial officer) to $1 million, unless such compensation is based upon performance objectives meeting certain regulatory criteria or is otherwise excluded from the limitation. Based on the Compensation Committee’s commitment to link compensation with performance as described above, the Compensation Committee intends to qualify future compensation paid to our executive officers for deductibility by us under Section 162(m) except in limited appropriate circumstances. We expect that short-term and long-term incentive compensation awarded under Alliant Energy’s 2010 Omnibus Incentive Plan will qualify for deductibility under Section 162(m). All of our equity compensation plans are accounted for under Financial Accounting Standard’s Board Accounting Standards, Codification Topic 718.

Responses to Non-Binding 2010 Say-on-Pay Shareowner Vote

At the Company’s 2011 Annual Meeting of Shareowners, shareowners approved a non-binding advisory resolution relating to the compensation of our named executive officers, which is commonly referred to as a “say-on-pay” proposal. The say-on-pay proposal was approved with a supermajority of the votes cast in favor of the proposal. Notwithstanding this vote of confidence expressed by our shareowners, the Compensation Committee and management continue to review the Company’s executive compensation program and related disclosure with the assistance of outside compensation consultants and outside counsel to identify any potential changes that might augment shareowner value.

Conclusion

The Compensation Committee is provided with appropriate information and reviews all components of our Chief Executive Officer’s and other executive officers’ compensation. Based on this information, the Compensation Committee seeks to implement executive compensation that is appropriately tied to the performance of the executives on behalf of shareowners, employees and customers.

COMPENSATION AND PERSONNEL COMMITTEE REPORT

To Our Shareowners:

The Compensation and Personnel Committee (the “Committee”) of the Board of Directors of the Company has reviewed and discussed the Compensation Discussion and Analysis with our management. Based on the Committee’s review and discussion, the Committee recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this proxy statement and incorporated by reference in our Annual Report on Form 10-K for the year ended December 31, 2011, for filing with the SEC.

COMPENSATION AND PERSONNEL COMMITTEE

Ann K. Newhall (Chairperson)

David A. Perdue

Judith D. Pyle

Carol P. Sanders

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SUMMARY COMPENSATION TABLE

The table below summarizes the compensation paid to or earned by our Chief Executive Officer, our chief operating officer, our chief financial officer, and our next four highest paid executive officers for services rendered to us, Alliant Energy and Alliant Energy’s other subsidiaries for 2011, 2010 and 2009. We refer to such individuals in this proxy statement collectively as our named executive officers.

Name and Principal Position	Year		Salary ($)(1)		Bonus ($)		Stock Awards ($)(2)		Option Awards ($)		Non-Equity Incentive Plan Compensation ($)(3)		Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)(4)		All Other Compensation ($)(8)		Total ($)
William D. Harvey Chief Executive Officer and Chairman of the Board of Directors		2011	$	894,231	$	0	$	2,347,528	$	0	$	909,000	$	2,175,000	$	390,355	$	6,716,114
		2010	$	872,481	$	0	$	2,384,547	$	0	$	1,080,625	$	403,922	$	413,208	$	5,154,783
		2009	$	832,000	$	0	$	1,999,511	$	0	$	0	$	147,000	$	353,986	$	3,332,497
Patricia L. Kampling Chief Operating Officer and Former Chief Financial Officer		2011	$	500,000	$	0	$	782,482	$	0	$	328,250	$	846,000	$	74,152	$	2,530,884
		2010	$	403,212	$	0	$	630,329	$	0	$	422,500	$	529,000	$	70,236	$	2,055,277
		2009	$	294,769	$	0	$	425,945	$	0	$	0	$	93,000	$	42,368	$	856,082
Thomas L. Hanson Vice President and Chief Financial Officer		2011	$	322,900	$	0	$	464,541	$	0	$	216,514	$	716,000	$	50,055	$	1,770,010
Thomas L. Aller Senior Vice President — Energy Resource Development		2011	$	288,154	$	0	$	411,072	$	0	$	131,805	$	250,000	$	47,156	$	1,128,187
		2010	$	280,241	$	0	$	215,196	$	0	$	164,970	$	170,000	$	48,260	$	878,667
		2009	$	263,385	$	0	$	177,236	$	0	$	0	$	151,000	$	44,053	$	635,674
John O. Larsen — President(5)		2011	$	301,500	$	0	$	220,182	$	0	$	137,032	$	340,720	$	42,218	$	1,041,652
James H. Gallegos Vice President and General Counsel(6)		2011	$	310,000	$	0	$	307,268	$	0	$	172,205	$	4,000	$	83,595	$	877,068
Dundeana K. Doyle Former Senior Vice President — Energy Delivery(7)		2011	$	204,474	$	0	$	212,824	$	0	$	88,294	$	885,531	$	340,300	$	1,731,423
		2010	$	279,658	$	0	$	214,699	$	0	$	164,619	$	246,917	$	59,675	$	965,568
		2009	$	262,800	$	0	$	176,901	$	0	$	0	$	153,832	$	56,821	$	650,354

⁽¹⁾  The amounts shown in this column include amounts deferred by the named executive officers in the Alliant Energy Deferred Compensation Plan Stock Account. See “Nonqualified Deferred Compensation.”

⁽²⁾  The amounts in this column reflect the aggregate grant date fair value of performance shares, performance contingent restricted stock, and time-based restricted stock granted pursuant to Alliant Energy’s 2002 Equity Incentive Plan (for 2009 and 2010 amounts) and Alliant Energy’s 2010 Omnibus Incentive Plan (for 2011 amounts), computed in accordance with Financial Accounting Standard’s Board Accounting Standards Codification Topic 718, or FASB ASC Topic 718.

A discussion of the assumptions used in calculating the award values may be found in Note 6(b) to Alliant Energy’s 2011 audited financial statements contained in Alliant Energy’s Annual Report on Form 10-K. For the performance shares, the fair value at the grant date is based upon the probable outcome of the performance conditions, consistent with the estimate of aggregate compensation cost to be recognized over the service period determined as of the grant date under FASB ASC Topic 718, excluding the effect of estimated forfeitures.

The 2011 grant date fair value reflected in this column for performance shares was $1,222,538 for Mr. Harvey; $407,498 for Ms. Kampling; $241,922 for Mr. Hanson; $110,286 for Mr. Aller; $114,666 for Mr. Larsen; $160,018 for Mr. Gallegos; and $110,834 for Ms. Doyle. The 2011 grant date fair value for performance shares at maximum would have been: $2,249,980 for Mr. Harvey; $749,968 for Ms. Kampling; $445,238 for Mr. Hanson; $202,973 for Mr. Aller; $211,033 for Mr. Larsen; $294,500 for Mr. Gallegos; and $203,980 for Ms. Doyle.

⁽³⁾  The 2011 amounts in this column represent cash amounts received by the executive officers under Alliant Energy’s MICP for services performed in 2011 that were paid in 2012.

⁽⁴⁾  The 2011 amounts in this column reflect (a) the actuarial increase in the present value of the named executive officers, benefits under all pension plans established by Alliant Energy, determined using the assumptions and methods set forth in footnote (3) to the Pension Benefits table below, which may include amounts that the named executive officer may not currently be entitled to receive because such amounts are not vested, and (b) amounts representing above market

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interest on nonqualified deferred compensation. The following represents the breakdown for 2011 for each of the change in pension value and the above market interest on nonqualified deferred compensation, respectively, for each named executive officer: $2,175,000/$0 for Mr. Harvey; $846,000/$0 for Ms. Kampling; $716,000/$0 for Mr. Hanson; $250,000/$0 for Mr. Aller; $340,000/$720 for Mr. Larsen; $4,000/$0 for Mr. Gallegos; and $878,000/$7,531 for Ms. Doyle. The change in pension value for Ms. Doyle includes the increased value of her Supplemental Retirement Plan. The changes in the actuarial present values of the named executive officers’ pension benefits do not constitute cash payments to the named executive officers.

⁽⁵⁾  Mr. Larsen was hired in 1987, but was not a named executive officer in 2009 or 2010.

⁽⁶⁾  Mr. Gallegos was hired in November 2010, but was not a named executive officer in 2010.

⁽⁷⁾  Ms. Doyle retired effective August 31, 2011.

⁽⁸⁾  None of the named executive officers received perquisites and other personal benefits in the aggregate amount of $10,000 or more in 2011. The table below shows the components of the compensation reflected under this column for 2011.

Name	Registrant Contributions to Defined Contribution Plans (a)		Life Insurance Premiums (b)		Tax Reimbursements (c)		Dividends (d)		Payments in Regard to Termination of Employment (e)
William D. Harvey	$	55,115	$	83,762	$	22,965	$	228,513	$	0
Patricia L. Kampling	$	25,000	$	1,896	$	0	$	47,256	$	0
Thomas L. Hanson	$	24,688	$	2,208	$	0	$	23,159	$	0
Thomas L. Aller	$	17,271	$	3,032	$	0	$	26,853	$	0
John O. Larsen	$	23,197	$	683	$	0	$	18,338	$	0
James H. Gallegos	$	77,594	$	1,104	$	0	$	4,897	$	0
Dundeana K. Doyle	$	12,144	$	10,117	$	6,695	$	19,944	$	291,400

^(a)  Matching contributions to the Alliant Energy 401(k) Savings Plan and the Alliant Energy Deferred Compensation Plan, employer contributions based on age and service to the Alliant Energy 401(k) Savings Plan accounts, employer defined contributions to the Alliant Energy Excess Retirement Plan, and, in the case of Mr. Gallegos, employer contributions to the Defined Contribution Supplemental Retirement Plan.

^(b)  All life insurance premiums.

^(c)  Tax reimbursements for reverse split dollar life insurance.

^(d)  Dividends earned in 2011 on unvested restricted stock.

^(e)  Payments in connection with Ms. Doyle’s retirement from Alliant Energy. This amount does not include the lump sum payment made to Ms. Doyle in 2012 pursuant to her Supplemental Retirement Plan, as described in the Pension Benefit table.

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GRANTS OF PLAN-BASED AWARDS

The following table sets forth information regarding all incentive plan awards that Alliant Energy granted to our named executive officers in 2011.

						Estimated Possible Payouts Under Non-Equity Incentive Plan Awards(1)						Estimated Future Payouts Under Equity Incentive Plan Awards						Grant Date Fair Value of Stock Awards(5)
Name	Grant Date			Committee Approval Date		Threshold ($) 20%		Target ($) 100%		Maximum ($) 150%		Threshold (#) 50%		Target (#) 100%		Maximum (#) 200%
William D. Harvey		2/22/2011	(2)		2/8/2011								14,516		29,032		58,064	$	1,222,538
		2/22/2011	(3)		2/8/2011										29,032			$	1,124,990
					2/8/2011	$	180,000	$	900,000	$	1,350,000
Patricia L. Kampling		2/22/2011	(2)		2/8/2011								4,839		9,677		19,354	$	407,498
		2/22/2011	(3)		2/8/2011										9,677			$	374,984
					2/8/2011	$	65,000	$	325,000	$	487,500
Thomas L. Hanson		2/22/2011	(2)		2/8/2011								2,873		5,745		11,490	$	241,922
		2/22/2011	(3)		2/8/2011										5,745			$	222,619
					2/8/2011	$	42,874	$	214,370	$	321,555
Thomas L. Aller		2/22/2011	(2)		2/8/2011								1,310		2,619		5,238	$	110,286
		2/22/2011	(3)		2/8/2011										2,619			$	101,486
		3/10/2011	(4)		3/10/2011										5,000			$	199,300
					2/8/2011	$	26,100	$	130,500	$	195,750
John O. Larsen		2/22/2011	(2)		2/8/2011								1,362		2,723		5,446	$	114,666
		2/22/2011	(3)		2/8/2011										2,723			$	105,516
					2/8/2011	$	27,135	$	135,675	$	203,513
James H. Gallegos		2/22/2011	(2)		2/8/2011								1,900		3,800		7,600	$	160,018
		2/22/2011	(3)		2/8/2011										3,800			$	147,250
					2/8/2011	$	34,100	$	170,500	$	255,750
Dundeana K. Doyle		2/22/2011	(2)		2/8/2011								1,316		2,632		5,264	$	110,834
		2/22/2011	(3)		2/8/2011										2,632			$	101,990
					2/8/2011	$	26,226	$	131,130	$	196,695

⁽¹⁾  The amounts shown represent the threshold, target and maximum awards that could have been earned by each of our named executive officers under the MICP for 2011 as described more fully under “Compensation Discussion and Analysis — Components of Executive Compensation Program — MICP Annual Incentives.” The threshold payment level under the MICP was 20% of the target amount. The maximum payment level under the MICP was 150% of the target amount. Payments earned for 2011 under the MICP are shown in the “Non-Equity Incentive Plan Compensation” column of the Summary Compensation Table.

⁽²⁾  The amounts shown represent the threshold, target and maximum amounts of performance shares that were awarded in 2011 to the named executive officers under Alliant Energy’s 2010 Omnibus Incentive Plan as described more fully under “Compensation Discussion and Analysis — Components of Executive Compensation Program — Long-Term Incentives.” The threshold amount is 50% of the target amount. The maximum amount is 200% of the target amount.

⁽³⁾  The amounts shown represent the number of shares of performance contingent restricted stock that were awarded in 2011 to the named executive officers under Alliant Energy’s 2010 Omnibus Incentive Plan as described more fully under “Compensation Discussion and Analysis — Components of Executive Compensation Program — Long-Term Incentives.” Performance contingent restricted stock awards granted in 2011 accumulate dividends on the same basis as shares of Alliant Energy’s common stock.

⁽⁴⁾  The amount shown represents the number of shares of restricted stock that were awarded in 2011 to the named executive officer under Alliant Energy’s 2010 Omnibus Incentive Plan as described more fully under “Compensation Discussion and Analysis — Components of Executive Compensation Program — Long-Term Incentives.” Restricted stock awards granted in 2011 accumulate dividends on the same basis as shares of Alliant Energy’s common stock.

⁽⁵⁾  The grant date fair value of each equity award was computed in accordance with FASB ASC Topic 718. For the performance shares, the fair value at the grant date is based upon the probable outcome of the performance conditions, consistent with the estimate of aggregate compensation cost to be recognized over the service period determined as of the grant date pursuant to FASB ASC Topic 718, excluding the effect of estimated forfeitures. For the performance shares, the grant date fair value, as determined by FASB ASC Topic 718, is $42.11. For the performance contingent restricted stock, the grant date fair value, as determined by the closing price of Alliant Energy’s common stock pursuant to Alliant Energy’s 2010 Omnibus Incentive Plan on February 22, 2011, is $38.75.

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OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END

The following table sets forth information on outstanding Alliant Energy stock option awards and unvested stock awards held by our named executive officers on December 31, 2011.

Name	Option Awards							Stock Awards
	Number of Securities Underlying Unexercised Options Exercisable (#)		Number of Securities Underlying Unexercised Options Unexercisable (#)	Option Exercise Price ($)(1)		Option Expiration Date		Number of Shares or Units of Stock That Have Not Vested (#)		Market Value of Shares or Units of Stock That Have Not Vested ($)		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 ($)(2)
William D. Harvey		11,258		$	25.93		2/9/2014
													31,412	$	1,385,583	(3)
													107,098	$	4,724,093	(4)
													40,718	$	1,796,071	(5)
													67,194	$	2,963,927	(6)
													36,223	$	1,597,797	(7)
													58,064	$	2,561,203	(8)
													29,955	$	1,321,315	(9)
Patricia L. Kampling													2,290	$	101,012	(3)
													22,814	$	1,006,326	(4)
													8,674	$	382,610	(5)
													17,762	$	783,482	(6)
													9,575	$	422,353	(7)
													19,354	$	853,705	(8)
													9,985	$	440,438	(9)
Thomas L. Hanson													2,620	$	115,568	(3)
													8,936	$	394,167	(4)
													3,397	$	149,842	(5)
													5,760	$	254,074	(6)
													3,105	$	136,962	(7)
													11,490	$	506,824	(8)
													5,928	$	261,484	(9)
Thomas L. Aller		18,767		$	24.90		1/2/2014
		2,887		$	25.93		2/9/2014
													2,784	$	122,802	(3)
													9,494	$	418,780	(4)
													3,609	$	159,193	(5)
													6,064	$	267,483	(6)
													3,269	$	144,196	(7)
													5,238	$	231,048	(8)
													2,702	$	119,185	(9)
									5,159	$	227,563					(10)
John O. Larsen													2,052	$	90,514	(3)
													8,694	$	383,492	(4)
													3,305	$	145,784	(5)
													5,946	$	262,278	(6)
													3,205	$	141,373	(7)
													5,446	$	240,223	(8)
													2,810	$	123,949	(9)
James H. Gallegos													7,600	$	335,236	(8)
													3,921	$	172,955	(9)
Dundeana K. Doyle													2,654	$	117,068	(3)(a)
													9,476	$	417,986	(4)(b)
													3,602	$	158,884	(5)(c)
													6,050	$	266,866	(6)(d)
													3,261	$	143,843	(7)(e)
													5,264	$	232,195	(8)(f)
													2,716	$	119,803	(9)(g)

⁽¹⁾ The exercise price for all stock option grants is the fair market value of Alliant Energy common stock on the date of grant.

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⁽²⁾  The values in this column are calculated by using the closing price of Alliant Energy common stock of $44.11 on December 30, 2011.

⁽³⁾  Performance contingent restricted stock granted on January 2, 2008. Vesting would have occurred if the performance criterion was met within 4 years. The values in the table include credited dividend equivalents. These shares were forfeited because the performance criteria was not met within 4 years.

⁽⁴⁾  Performance shares granted on February 26, 2009. Vesting occurs if the performance criterion is met in 3 years. The values in the table assume maximum level performance. These shares vested at 162.5% and are also reported in the Options Exercised and Stock Vested Table.

⁽⁵⁾  Performance contingent restricted stock granted on February 26, 2009. Vesting occurs if the performance criterion is met in 4 years. The values in the table include credited dividend equivalents.

⁽⁶⁾  Performance shares granted on February 22, 2010. Vesting occurs if the performance criterion is met in 3 years. The values in the table assume maximum level performance.

⁽⁷⁾ Performance contingent restricted stock granted on February 22, 2010. Vesting occurs if the performance criterion is met in 2, 3 or 4 years. The values in the table include credited dividend equivalents. These shares vested in 2 years and are also reported in the Options Exercised and Stock Vested Table.

⁽⁸⁾  Performance shares granted on February 22, 2011. Vesting occurs if the performance criterion is met in 3 years. The values in the table assume maximum level performance.

⁽⁹⁾  Performance contingent restricted stock granted on February 22, 2011. Vesting occurs if the performance criterion is met in 2, 3 or 4 years. The values in the table include credited dividend equivalents.

⁽¹⁰⁾  Time-based restricted stock granted on March 10, 2011. One-third of these shares will vest on each of the following dates: March 10, 2012, March 10, 2013, and March 10, 2014. The values in the table include credited dividend equivalents.

As a result of Ms. Doyle’s retirement, the awards listed above will be prorated pursuant to the terms of her performance contingent restricted stock agreements and performance share agreements as follows:

^(a)  If the performance target would have been met, Ms. Doyle’s award would be prorated at 44/48 or 2,433 shares. The performance target was not met; therefore, these shares were forfeited.

^(b)  If the performance target is met, Ms. Doyle’s award will be prorated at 32/36 or 4,212 shares.

^(c)  If the performance target is met, Ms. Doyle’s award will be prorated at 32/48, or 2,401 shares.

^(d)  If the performance target is met, Ms. Doyle’s award will be prorated at 20/36 or 1,681 shares.

^(e)  Given the performance target was met, Ms. Doyle’s award will be prorated at 20/24 or 2,718 shares.

^(f)  If the performance target is met, Ms. Doyle’s award will be prorated at 8/36 or 585 shares.

^(g)  If the performance target is met, Ms. Doyle’s award will be prorated by a fraction, the numerator of which is 8 and the denominator of which is 24, 36, 48 depending on whether the performance target is met in 2, 3, or 4 years, respectively.

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OPTION EXERCISES AND STOCK VESTED

The following table shows a summary of the Alliant Energy stock options exercised by our named executive officers during 2011 and Alliant Energy stock awards vested for the named executive officers during 2011.

Name	Option Awards				Stock Awards
	Number of Shares Acquired on Exercise (#)		Value Realized on Exercise ($)(1)		Long-Term Incentive Plan	Number of Shares Acquired on Vesting (#)		Value Realized on Vesting ($)(2)(3)
William D. Harvey					Performance Shares		87,017	$	3,864,860
					Performance Contingent Restricted Stock		36,605	$	1,575,852
Patricia L. Kampling					Performance Shares		18,536	$	823,276
					Performance Contingent Restricted Stock		9,676	$	416,559
Thomas L. Hanson					Performance Shares		7,261	$	322,497
					Performance Contingent Restricted Stock		3,138	$	135,085
Thomas L. Aller		34,876	$	686,267	Performance Shares		7,714	$	342,617
					Performance Contingent Restricted Stock		3,303	$	142,215
John O. Larsen					Performance Shares		7,064	$	313,748
					Performance Contingent Restricted Stock		3,239	$	139,447
James H. Gallegos					Performance Shares		0	$	0
					Performance Contingent Restricted Stock		0	$	0
Dundeana K. Doyle					Performance Shares		6,844	$	303,976
					Performance Contingent Restricted Stock		2,747	$	118,239

⁽¹⁾  Reflects the amount calculated by multiplying the number of options exercised by the difference between the fair market value of Alliant Energy’s common stock on the exercise date and the exercise price of options.

⁽²⁾  Reflects an amount calculated by (i) multiplying the vested number of the performance shares by the fair market value of Alliant Energy’s common stock on January 3, 2012, (the date of the first business day following the completion of 2011) of $43.97, plus dividend equivalents on such shares, and (ii) by multiplying the number of vested shares of performance contingent restricted stock, plus accumulated dividends (including fractional amounts not shown), by the fair market value of Alliant Energy’s common stock on February 27, 2012, (the date of the Compensation Committee’s certification of the achievement of 2011 performance goals) of $43.05.

⁽³⁾  Executive officers receiving a payout of their performance shares for the performance period ending December 31, 2011 could elect to receive their award in cash, in shares of Alliant Energy’s common stock, or partially in cash and partially in Alliant Energy’s common stock. All of the named executive officers elected to receive their awards 100% in cash, except Ms. Kampling, who elected to receive her award 50% in cash and 50% in Alliant Energy’s common stock.

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PENSION BENEFITS

The table sets forth the number of years of credited service, the present value of accumulated benefits and payments during 2011 for each of our named executive officers under the Alliant Energy Cash Balance Pension Plan, the Excess Retirement Plan, and the defined benefit Supplemental Retirement Plan, or DB SRP, which are each described below. The disclosed amounts are estimates only and do not necessarily reflect the actual amounts that will be paid to our named executive officers, which will only be known at the time that they become eligible for payment.

Name	Plan Name	Number of Years Credited Service ( # )(2)		Present Value of Accumulated Benefit ( $ )(3)			Payments During 2011 ($)
William D. Harvey	Cash Balance Plan		21.0	$	906,000		$	0
	Excess Plan		24.4	$	2,704,000		$	0
	DB SRP		24.4	$	8,987,000		$	0
			Total	$	12,597,000		$	0
Patricia L. Kampling	Cash Balance Plan		2.9	$	47,000		$	0
	Excess Plan		6.3	$	34,000		$	0
	DB SRP		6.3	$	1,558,000		$	0
			Total	$	1,639,000		$	0
Thomas L. Hanson	Cash Balance Plan		27.1	$	803,000		$	0
	Excess Plan		30.5	$	110,000		$	0
	DB SRP		30.5	$	1,040,000		$	0
			Total	$	1,953,000		$	0
Thomas L. Aller	Cash Balance Plan		15.2	$	188,000		$	0
	Excess Plan		18.7	$	37,000		$	0
	DB SRP		18.7	$	1,925,000		$	0
			Total	$	2,150,000		$	0
John O. Larsen	Cash Balance Plan		20.5	$	287,000		$	0
	Excess Plan		23.9	$	45,000		$	0
	DB SRP		23.9	$	567,000		$	0
			Total	$	899,000		$	0
James H. Gallegos(1)	Cash Balance Plan		N/A		N/A		$	0
	Excess Plan		1.2	$	4,000		$	0
	DB SRP		N/A		N/A		$	0
			Total	$	4,000		$	0
Dundeana K. Doyle	Cash Balance Plan		23.7	$	524,000		$	0
	Excess Plan		26.7	$	39,000		$	0
	DB SRP		26.7	$	1,523,000	(4)	$	0
			Total	$	2,086,000		$	0

⁽¹⁾  Based on his hire date, Mr. Gallegos is not eligible for the Cash Balance Pension Plan or the DB SRP. He is eligible for a defined contribution SRP benefit (DC SRP) and Excess Retirement Plan. The employer contribution to the DC SRP is included in Summary Compensation Table under “All Other Compensation.”

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⁽²⁾  Years of credited service for the Cash Balance Plan are less than the actual years of service of the officer because the Cash Balance Plan was frozen in August 2008.

⁽³⁾  The following assumptions, among others, were used to calculate the present value of accumulated benefits: that the participant retires at age 62; that the benefit calculation date is December 31, 2011, consistent with our accounting measurement date for financial statement reporting purposes; that the discount rate is 4.70% (compared to 5.35% for 2010); that the post-retirement mortality assumption is based on the RP-2000 table with white collar adjustment and a 12-year projection using Scale AA; that the form of payment is 70% lump sum and 30% annuity; and, for participants who are not yet eligible to retire with a SRP benefit, that the target benefit has been prorated over an executive’s service career until benefit eligibility date.

⁽⁴⁾  In connection with her retirement, Alliant Energy amended the terms of the DB SRP in order to accelerate the vesting of Ms. Doyle’s supplemental benefits at age 53.5, instead of age 55. Ms. Doyle’s actual balance in the DB SRP was paid to her in lump sum on March 1, 2012, six months following her retirement date of August 31, 2011, in compliance with Section 409A of the tax code. The amount shown in the table above is the actuarial value of her DB SRP on December 31, 2011, which is different from the actual balance paid on March 1, 2012.

Alliant Energy Cash Balance Pension Plan — A portion of our salaried employees, including our named executive officers, are eligible to participate in the Alliant Energy Cash Balance Pension Plan, or Pension Plan, that Alliant Energy maintains. The Pension Plan bases a participant’s defined benefit pension on the value of a hypothetical account balance. For individuals participating in the Pension Plan as of August 1, 1998, a starting account balance was created equal to the present value of the benefit accrued as of December 31, 1997, under the applicable prior benefit formula. In addition, such individuals received a special one-time transition credit amount equal to a specified percentage varying with age multiplied by credited service and pay. For 1998 through August 2, 2008, a participant received annual credits to the account equal to 5% of base pay (including certain incentive payments, pre-tax deferrals and other items). For 1998 through 2008, a participant also received an interest credit on all prior accruals equal to 4%, plus a potential share of the gain on the investment return on Pension Plan assets for the year. Alliant Energy amended the Pension Plan’s interest crediting rate for 2009 and future years. The new interest crediting rate will be equal to the annual percentage change in the consumer price index, as of October each year, plus 3%.

All of our named executive officers, with the exception of Ms. Kampling and Mr. Gallegos, are “grandfathered” under the applicable prior plan benefit formula. Mr. Gallegos is not eligible for the Pension Plan. For Messrs. Harvey, Hanson, Larsen and Ms. Doyle, estimated benefits under the applicable prior plan benefit formula are expected to be higher than under the Pension Plan formula, utilizing current assumptions. Mr. Aller’s benefits under the applicable prior plan are less than the benefits under the Pension Plan. Therefore, the benefits for all of our named executive officers participating in the Pension Plan, with the exception of Ms. Kampling and Mr. Aller, would currently be determined under the applicable prior plan benefit formula. To the extent benefits under the Pension Plan are limited by tax law, any excess will be paid under the Excess Retirement Plan described below. Pension Plan accruals ceased as of August 2, 2008. This “freeze” applies to both the 5% of base pay annual credits to the hypothetical account balance and to the grandfathered prior plan formulas. Subsequent to August 2, 2008, active participants receive enhanced benefits under the Alliant Energy 401(k) Savings Plan.

WPL Plan A Prior Formula. One of the applicable prior plan formulas provided retirement income based on years of credited service and final average compensation for the 36 highest consecutive months, with a reduction for Social Security offset. Mr. Harvey and Mr. Hanson are covered by this prior formula.

For purposes of the Pension Plan, compensation means payment for services rendered, including vacation and sick pay, and is substantially equivalent to the salary amounts reported in the Summary Compensation Table. Pension Plan benefits depend upon length of Pension Plan service (up to a maximum of 30 years), age at retirement and amount of compensation (determined in accordance with the Pension Plan and subject to the limit in the tax code) and are reduced by up to 50% of Social Security benefits. The general formula is (i) 55% of final average compensation less 50% of Social Security benefits, the difference multiplied by (ii) a fraction not greater than 1, the numerator of which is the number of years of credit and the denominator of which is 30. This formula provides the basic benefit payable for the life of the participant. If the participant receives an alternative form of payment, then the monthly benefit would be reduced accordingly.

Mr. Harvey retired effective March 31, 2012. Mr. Harvey is eligible for an unreduced pension benefit because he is over age 62. Mr. Hanson is eligible for early retirement because he is over age 55. For each year Mr. Hanson would choose to retire and commence benefits prior to age 62, his benefits would be reduced by 5% per year. If benefits commence at or after age 62, there would be no reduction for early commencement prior to the normal retirement age of 65.

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IES Industries Pension Plan Prior Formula. Another applicable prior plan formula applies to Ms. Doyle and Mr. Larsen. This formula provides retirement income based on years of service, final average compensation and Social Security covered compensation. Technically, this formula also applies to Mr. Aller, but his prior plan formula benefit is frozen in the annual amount of $7,607 payable at age 65; therefore, the Cash Balance Pension Plan formula is expected to provide him with a greater benefit.

The benefit formula for Ms. Doyle and Mr. Larsen for service until the August 2, 2008, freeze date is generally the benefit they had accrued under an old formula in existence prior to 1988 plus (i) 1.05% of average monthly compensation for years of service not in excess of 35, plus (ii) 0.50% of average monthly compensation in excess of Social Security covered compensation for years of service not in excess of 35, plus (iii) 1.38% of average monthly compensation for years of service in excess of 35. Compensation generally is the salary amount reported in the Summary Compensation Table (subject to limit in the tax code), with the final average compensation being calculated based on the three highest calendar years of such pay. The formula provides the basic benefit payable for the life of the participant. If the participant receives an alternative form of payment, then the monthly benefit would be reduced accordingly. Ms. Doyle and Mr. Larsen are eligible for early retirement benefits because they have 15 years of service or more. Unreduced benefits are available at age 62. Benefits that commence prior to age 62 are reduced by a reduction factor of not less than 5% per year.

Excess Retirement Plan — Alliant Energy maintains an unfunded Excess Retirement Plan that provides funds for payment of retirement benefits above the limitations on payments from qualified pension plans in those cases where an employee’s retirement benefits exceed the qualified plan limits. The Excess Retirement Plan provides an amount equal to the difference between the actual pension benefit payable under the Pension Plan and Alliant Energy’s actual contributions based on age and service to the Alliant Energy 401(k) Savings Plan and what such benefits and contributions would be if calculated without regard to any limitation imposed by the Code on pension benefits or covered compensation.

Supplemental Retirement Plan — Alliant Energy maintains an unfunded Defined Benefit Supplemental Retirement Plan, or DB SRP, to provide incentive for key executives to remain in our service by providing additional compensation that is payable only if the executive remains with us until retirement, disability or death. While the DB SRP provides different levels of benefits depending on the executive covered, this summary reflects the terms applicable to all of our named executive officers. Participants in the DB SRP must be approved by the Compensation and Personnel Committee. The DB SRP was discontinued in 2008. Executives hired after 2008, such as Mr. Gallegos, participate in the DC SRP.

For Mr. Harvey, the DB SRP provides for payments of 60% of the participant’s average annual earnings (base salary and bonus) for the highest paid three consecutive years out of the last 10 years of the participant’s employment reduced by the sum of benefits payable to the officer from the officer’s defined benefit plan, the Alliant Energy contributions based on age and service to the Alliant Energy 401(k) Savings Plan, and the Excess Retirement Plan. Mr. Harvey qualifies for an unreduced benefit since he meets the normal retirement requirement of age 62 with at least 10 years of service. Payment of benefits under the DB SRP commences six months after the participant’s retirement. Mr. Harvey has elected to receive the benefit in the form of a lump sum.

For Ms. Kampling, Messrs. Hanson, Aller and Larsen, the DB SRP provides for payments of 50% of the participant’s average annual earnings (base salary and bonus) for the highest paid three consecutive years out of the last 10 years of the participant’s employment reduced by the sum of benefits payable to the officer from the officer’s defined benefit plan, the Alliant Energy contributions based on age and service to the Alliant Energy Corporation 401(k) Savings Plan, and the unfunded Excess Retirement Plan. The normal retirement date under the DB SRP is age 62 with at least 10 years of service and early retirement is at age 55 with at least 10 years of service and five or more years of continuous DB SRP employment, which age and service requirements Mr. Aller has already satisfied. If a participant retires prior to age 62, the 50% payment under the DB SRP is reduced by approximately 5% per year for each year the participant’s retirement date precedes his/her normal retirement date. Payment of benefits under the DB SRP commences six months after the participant’s retirement. At the timely election of the participant, benefits under the DB SRP will be made in a lump sum, in annual installments over a period of five years, or in monthly installments for 18 years. Participants made their elections in December 2008. Participants may change their form of payment once, provided that the new election is made at least 12 months prior to their retirement. If such an election is made, benefits under the DB SRP will not be paid for five years after they otherwise would have been.

For Messrs. Hanson, Aller, and Larsen and Ms. Kampling, if the monthly benefit is selected, and in either case the participant dies prior to receiving 12 years of payments, payments continue to any surviving spouse or dependent children, payable for the remainder of the 12 year period. In each case, if the five annual installments benefit is selected and the participant dies prior to receiving five annual payments, payments will continue to any surviving spouse or dependent children, payable for the remainder of the five-year period. If the participant dies while still employed by us, the designated beneficiary shall receive a lump sum equal to the discounted value of retirement benefits for 12 years.

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For Ms. Doyle, the DB SRP provided for payments of 60% of the participant’s average annual earnings (base salary and bonus) for the highest paid three consecutive years out of the last 10 years of the participant’s employment reduced by the sum of benefits payable to the officer from the officer’s defined benefit plan, the Alliant Energy contributions based on age and service to the Alliant Energy 401(k) Savings Plan, and the Excess Retirement Plan. The normal retirement date under the DB SRP is age 62. In 2011, Ms. Doyle’s DB SRP was amended to vest payment when Ms. Doyle reached age 53.5. As a result, Ms. Doyle was vested when she retired in August 2011 and received a payment of $1,534,513 on March 1, 2012, or six months after her retirement date. Since Ms. Doyle retired in 2011, prior to reaching age 62, the 60% payment under the DB SRP was reduced by 3% per year for each year that her retirement date preceded her normal retirement date. Payment of benefits under the DB SRP commences six months after the participant’s retirement. Ms. Doyle elected to receive her benefit in the form of a lump sum. For Mr. Harvey and Ms. Doyle, a post-retirement death benefit of one times the participant’s final average earnings at the time of retirement will be paid to the designated beneficiary in addition to the continuation of benefit payments as described above.

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NONQUALIFIED DEFERRED COMPENSATION

The table below sets forth certain information as of December 31, 2011, for each of our named executive officers with respect to the Alliant Energy Deferred Compensation Plan, which is described below.

Name	Executive Contributions in 2011 ($)(1)		Registrant Contributions in 2011 ($)(2)		Aggregate Earnings in 2011 ($)(3)		Aggregate Withdrawals/ Distributions in 2011 ($)(4)		Aggregate Balance as of December 31, 2011 ($)
William D. Harvey	$	0	$	27,952	$	593,146	$	0	$	5,849,607
Patricia L. Kampling	$	0	$	7,613	$	14,072	$	0	$	70,960
Thomas L. Hanson	$	9,618	$	2,705	$	43,200	$	0	$	357,804
Thomas L. Aller	$	0	$	0	$	79,579	$	0	$	460,777
John O. Larsen	$	33,165	$	4,337	$	66,194	$	0	$	508,630
James H. Gallegos	$	24,800	$	0	$	318	$	0	$	25,118
Dundeana K. Doyle	$	0	$	0	$	97,755	$	173,133	$	419,936

⁽¹⁾  The amounts reported are also reported under the “Salary” or “Non-Equity Incentive Plan Compensation” headings in the Summary Compensation Table.

⁽²⁾  The amounts reported in this column are also reported under the “All Other Compensation” heading in the Summary Compensation Table.

⁽³⁾  The following portion of the amount reported in this column, which represents above-market interest on deferred compensation, was reported in the “Change in Pension Value and Nonqualified Deferred Compensation Earnings” heading in the Summary Compensation Table, Mr. Larsen — $720; and Ms. Doyle — $7,531.

⁽⁴⁾  Ms. Doyle received a payment for the value of her frozen IES Deferred Compensation Plan benefit in November 2011.

Alliant Energy maintains the Alliant Energy Deferred Compensation Plan (AEDCP), under which participants, including our named executive officers, may defer up to 100% of base salary and annual incentive compensation. Participants who have made the maximum allowed contribution to the Alliant Energy 401(k) Savings Plan may receive an additional credit to the AEDCP. The credit made in January 2011 was equal to 50% of (a), minus (b), where:

(a) equals the lesser of (i) 8% of base salary for the Plan Year or (ii) the sum of the amounts (if any) contributed by the participant to the Alliant Energy Corporation 401(k) Savings Plan during the applicable year that were eligible for matching contributions under the Alliant Energy Corporation 401(k) Savings Plan, plus the amounts deferred by the participant during the applicable year under the AEDCP; and

(b) equals the amount of any matching contributions under the Alliant Energy Corporation 401(k) Savings Plan on behalf of the participant for the applicable year.

The participant may elect to have his or her deferrals credited to an Interest Account, Equity Account, Alliant Energy Stock Account or beginning in 2011, a Mutual Fund Account. Deferrals and matching contributions to the Interest Account receive an annual return based on the 10-year Treasury Bond Rate plus 1.50% as established by the Federal Reserve. Deferrals and matching contributions credited to the Equity Account are treated as invested in an S&P 500 index fund. Deferrals and matching contributions credited to the Mutual Fund Account are treated as invested in a mutual fund or other investment vehicle offered under the Alliant Energy 401(k) Savings Plan as selected by our Investment Committee. Deferrals and matching contributions credited to the Alliant Energy Stock Account are treated as though invested in Alliant Energy’s common stock and are credited with dividend equivalents, which are treated as if reinvested. The shares of Alliant Energy’s common stock identified as obligations under the AEDCP are held in a rabbi trust. Payments from the AEDCP due to death or retirement may be made in a lump sum or in annual installments for up to 10 years at the election of the participant. Payments from the AEDCP for any reason other than death or retirement are made in a lump sum. Participants are selected by our Chief Executive Officer. All of our named executive officers are participants in the AEDCP.

Alliant Energy maintains a frozen legacy deferred compensation plan, the IES Deferred Compensation Plan, in which Ms. Doyle and Mr. Larsen maintain a frozen account. An interest credit is provided for the balance in the account at a rate of

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11% for the balance in the account prior to July 1, 1993 and 9% on the remainder of the account. This plan was frozen on April 21, 1998 and no amounts have been deferred to the account since then. Ms. Doyle received a lump sum distribution of her frozen legacy IES Deferred Compensation Plan account because of her termination of employment in August 2011. Payment was made in November 2011.

POTENTIAL PAYMENTS UPON TERMINATION

OR CHANGE IN CONTROL

The following tables describe potential payments and benefits under Alliant Energy’s compensation and benefit plans, and arrangements to which our named executive officers would be entitled upon termination of employment or change in control of Alliant Energy. The estimated amount of compensation payable to each of our named executive officers in each situation is listed in the tables below assuming that the termination and/or change in control of Alliant Energy occurred at December 30, 2011, and Alliant Energy’s common stock is valued at $44.11, which was the closing market price for Alliant Energy’s common stock on December 30, 2011. The actual amount of payments and benefits can only be determined at the time of such a termination or change in control and therefore the actual amounts will vary from the estimated amounts in the tables below. Descriptions of the circumstances that would trigger payments or benefits to our named executive officers, how such payments and benefits are determined under the circumstances, material conditions and obligations applicable to the receipt of payments or benefits and other material factors regarding such agreements and plans, as well as other material assumptions that we have made in calculating the estimated compensation, follow these tables. Information regarding potential payments to Ms. Doyle is not provided due to her retirement in August 2011.

William D. Harvey	Death		Disability		Involuntary Termination Without Cause		Retirement		Change in Control and Termination Without Cause or for Good Reason		Change in Control Without Termination
Triggered Payouts
Cash Termination Payment	$	0	$	0	$	900,000	$	0	$	5,941,875	$	0
Life, Medical, Dental Insurance Continuation	$	0	$	0	$	5,958	$	0	$	287,037	$	0
Lump Sum SRP	$	0	$	0	$	0	$	0	$	0	$	0
Unvested Stock Options	$	0	$	0	$	0	$	0	$	0	$	0
Unvested Restricted Stock	$	0	$	0	$	0	$	0	$	0	$	0
Unearned Performance Contingent Restricted Stock	$	2,852,689	$	2,852,689	$	2,852,689	$	2,852,689	$	2,852,689	$	2,852,689
Unearned Performance Shares	$	1,414,843	$	1,414,843	$	1,414,843	$	1,414,843	$	1,414,843	$	1,414,843
Outplacement Services	$	0	$	0	$	10,000	$	0	$	90,000	$	0
Tax Preparation Assistance	$	0	$	0	$	0	$	0	$	0	$	0
Legal and Accounting Advisor Services	$	0	$	0	$	0	$	0	$	10,000	$	0
Excise Tax Gross Up		n/a		n/a		n/a		n/a	$	4,374,685		n/a
Life Insurance Proceeds	$	2,974,390	$	0	$	0	$	0	$	0	$	0
Total Pre-Tax Benefit	$	7,241,922	$	4,267,532	$	5,183,490	$	4,267,532	$	14,971,129	$	4,267,532

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Patricia L. Kampling	Death		Disability		Involuntary Termination Without Cause		Retirement		Change in Control and Termination Without Cause or for Good Reason		Change in Control Without Termination
Triggered Payouts
Cash Termination Payment	$	0	$	0	$	500,000	$	0	$	2,767,500	$	0
Life, Medical, Dental Insurance Continuation	$	0	$	0	$	9,220	$	0	$	61,005	$	0
Lump Sum SRP	$	0	$	0	$	0	$	0	$	1,324,000	$	0
Unvested Stock Options	$	0	$	0	$	0	$	0	$	0	$	0
Unvested Restricted Stock	$	0	$	0	$	0	$	0	$	0	$	0
Unearned Performance Contingent Restricted Stock	$	715,339	$	715,339	$	715,339	$	715,339	$	715,339	$	715,339
Unearned Performance Shares	$	403,445	$	403,445	$	403,445	$	403,445	$	403,445	$	403,445
Outplacement Services	$	0	$	0	$	10,000	$	0	$	50,000	$	0
Tax Preparation Assistance	$	0	$	0	$	0	$	0	$	0	$	0
Legal and Accounting Advisor Services	$	0	$	0	$	0	$	0	$	10,000	$	0
Excise Tax Cut Back		n/a		n/a		n/a		n/a		n/a		n/a
Life Insurance Proceeds	$	0	$	0	$	0	$	0	$	0	$	0
Total Pre-Tax Benefit	$	1,118,784	$	1,118,784	$	1,638,004	$	1,118,784	$	5,331,289	$	1,118,784

Thomas L. Hanson	Death		Disability		Involuntary Termination Without Cause		Retirement		Change in Control and Termination Without Cause or for Good Reason			Change in Control Without Termination
Triggered Payments
Cash Termination Payment	$	0	$	0	$	329,800	$	0	$	1,088,340		$	0
Life, Medical, Dental Insurance Continuation	$	0	$	0	$	5,958	$	0	$	28,250		$	0
Lump Sum SRP	$	0	$	0	$	0	$	0	$	0		$	0
Unvested Stock Options	$	0	$	0	$	0	$	0	$	0		$	0
Unvested Restricted Stock	$	0	$	0	$	0	$	0	$	0		$	0
Unearned Performance Contingent Restricted Stock	$	290,850	$	290,850	$	290,850	$	290,850	$	290,850		$	290,850
Unearned Performance Shares	$	169,162	$	169,162	$	169,162	$	169,162	$	169,162		$	169,162
Outplacement Services	$	0	$	0	$	10,000	$	0	$	32,980		$	0
Tax Preparation Assistance	$	0	$	0	$	0	$	0	$	0		$	0
Legal and Accounting Advisor Services	$	0	$	0	$	0	$	0	$	10,000		$	0
Excise Tax Cut Back		n/a		n/a		n/a		n/a	($	166,191	)		n/a
Life Insurance Proceeds	$	0	$	0	$	0	$	0	$	0		$	0
Total Pre-Tax Benefit	$	460,012	$	460,012	$	805,770	$	460,012	$	1,453,391		$	460,012

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Thomas L. Aller	Death		Disability		Involuntary Termination Without Cause		Retirement		Change in Control and Termination Without Cause or for Good Reason		Change in Control Without Termination
Triggered Payouts
Cash Termination Payment	$	0	$	0	$	290,000	$	0	$	909,940	$	0
Life, Medical, Dental Insurance Continuation	$	0	$	0	$	5,958	$	0	$	29,898	$	0
Lump Sum SRP	$	0	$	0	$	0	$	0	$	0	$	0
Unvested Stock Options	$	0	$	0	$	0	$	0	$	0	$	0
Unvested Restricted Stock	$	227,563	$	227,563	$	227,563	$	0	$	227,563	$	227,563
Unearned Performance Contingent Restricted Stock	$	255,254	$	255,254	$	255,254	$	255,254	$	255,254	$	255,254
Unearned Performance Shares	$	127,669	$	127,669	$	127,669	$	127,669	$	127,669	$	127,669
Outplacement Services	$	0	$	0	$	10,000	$	0	$	29,000	$	0
Tax Preparation Assistance	$	0	$	0	$	0	$	0	$	0	$	0
Legal and Accounting Advisor Services	$	0	$	0	$	0	$	0	$	10,000	$	0
Excise Tax Cut Back		n/a		n/a		n/a		n/a		n/a		n/a
Life Insurance Proceeds	$	0	$	0	$	0	$	0	$	0	$	0
Total Pre-Tax Benefit	$	610,486	$	610,486	$	916,444	$	382,923	$	1,589,324	$	610,486

John O. Larsen	Death		Disability		Involuntary Termination Without Cause		Retirement		Change in Control and Termination Without Cause or for Good Reason			Change in Control Without Termination
Triggered Payouts
Cash Termination Payment	$	0	$	0	$	301,500	$	0	$	955,756		$	0
Life, Medical, Dental Insurance Continuation	$	0	$	0	$	9,220	$	0	$	38,244		$	0
Lump Sum SRP	$	0	$	0	$	0	$	0	$	965,000		$	0
Unvested Stock Options	$	0	$	0	$	0	$	0	$	0		$	0
Unvested Restricted Stock	$	0	$	0	$	0	$	0	$	0		$	0
Unearned Performance Contingent Restricted Stock	$	244,902	$	244,902	$	244,902	$	244,902	$	244,902		$	244,902
Unearned Performance Shares	$	127,463	$	127,463	$	127,463	$	127,463	$	127,463		$	127,463
Outplacement Services	$	0	$	0	$	10,000	$	0	$	30,150		$	0
Tax Preparation Assistance	$	0	$	0	$	0	$	0	$	0		$	0
Legal and Accounting Advisor Services	$	0	$	0	$	0	$	0	$	10,000		$	0
Excise Tax Cut Back		n/a		n/a		n/a		n/a	($	1,065,378	)		n/a
Life Insurance Proceeds	$	0	$	0	$	0	$	0	$	0		$	0
Total Pre-Tax Benefit	$	372,365	$	372,365	$	693,085	$	372,365	$	1,306,137		$	372,365

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James H. Gallegos	Death		Disability		Involuntary Termination Without Cause		Retirement		Change in Control and Termination Without Cause or for Good Reason			Change in Control Without Termination
Triggered Payouts
Cash Termination Payment	$	0	$	0	$	310,000	$	0	$	961,000		$	0
Life, Medical, Dental Insurance Continuation	$	0	$	0	$	11,445	$	0	$	47,988		$	0
Lump Sum SRP	$	0	$	0	$	0	$	0	$	65,000		$	0
Unvested Stock Options	$	0	$	0	$	0	$	0	$	0		$	0
Unvested Restricted Stock	$	0	$	0	$	0	$	0	$	0		$	0
Unearned Performance Contingent Restricted Stock	$	57,652	$	57,652	$	57,652	$	57,652	$	57,652		$	57,652
Unearned Performance Shares	$	55,873	$	55,873	$	55,873	$	55,873	$	55,873		$	55,873
Outplacement Services	$	0	$	0	$	10,000	$	0	$	31,000		$	0
Tax Preparation Assistance	$	0	$	0	$	0	$	0	$	0		$	0
Legal and Accounting Advisor Services	$	0	$	0	$	0	$	0	$	10,000		$	0
Excise Tax Cut Back		n/a		n/a		n/a		n/a	($	199,630	)		n/a
Life Insurance Proceeds	$	0	$	0	$	0	$	0	$	0		$	0
Total Pre-Tax Benefit	$	113,525	$	113,525	$	444,970	$	113,525	$	1,028,883		$	113,525

Change in Control Agreements

Alliant Energy currently has in effect Key Executive Employment and Severance Agreements (KEESAs), with all our executive officers, including our named executive officers, and certain of our key employees, except Ms. Doyle, who retired on August 31, 2011. The KEESAs provide that each executive officer who is a party thereto is entitled to benefits if, within a period of up to three years (in the case of Mr. Harvey and Ms. Kampling), or two years (in the case of Messrs. Hanson, Aller, Larsen, and Gallegos) after a change in control of Alliant Energy (as defined below), the officer’s employment is ended through (a) termination by us, other than by reason of death or disability or for cause (as defined below), or (b) termination by the officer for good reason (as defined below).

The KEESAs provide the following benefits, each of which are reflected in the tables above assuming the maximum potential amounts payable pursuant to the terms of the KEESAs:

• reimbursement for up to 10% of the officer’s annual base salary for outplacement services;

• continuation of life, medical and dental insurance coverage for up to three years (in the case of Mr. Harvey and Ms. Kampling) or two years (in the case of Messrs. Hanson, Aller, Larsen, and Gallegos);

• full vesting of the officer’s accrued benefit under any SRP, and in any defined contribution retirement plan and deemed satisfaction of any minimum years of service requirement under the SRP (the amounts shown in the tables above assume a lump sum form of payment under the SRP using the 2011 lump sum interest rate of 2.79% and a single life annuity or lump sum payment under Alliant Energy’s qualified Cash Balance Pension Plan and nonqualified Excess Plan), provided that the SRP benefit will not be received until the executive officer reaches age 55;

• full vesting of any time-based restricted stock and stock options;

• payment at target of all performance plan awards pursuant to any long-term incentive plan on a pro rata basis unless the award cycle has been in effect less than six months;

• a cash termination payment of up to three times (in the case of Mr. Harvey and Ms. Kampling), or two times (in the case of Messrs. Hanson, Aller, Larsen, and Gallegos) the sum of the officer’s annual base salary and the greater of the officer’s target bonus for the year in which the termination date occurs, or the officer’s bonus in the year prior to the change in control; and

• reimbursement for up to $10,000 in legal or accounting advisor fees.

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In addition, the KEESA for Mr. Harvey provided that if the aggregate payments under the KEESA, or otherwise, are an “excess parachute payment” for purposes of the Internal Revenue Code, then Alliant Energy will pay the officer the amount necessary to offset the 20% excise tax imposed by the Internal Revenue Code and any additional taxes on this payment. In determining the amount of the excise tax gross-up included in the tables above, Alliant Energy made the following material assumptions: a Section 280G excise tax rate of 20%, a 35% federal income tax rate, a 1.45% Medicare tax rate and a 7.75% state income tax rate; the calculation also assumes that Alliant Energy would pay 18 months of COBRA coverage, the performance period for outstanding performance contingent restricted stock would be two years, and that Alliant Energy can prove that the awards of performance contingent restricted stock and performance shares in 2011 were not made in connection with or contemplation of a change of control of Alliant Energy. Furthermore, it is assumed that no value will be attributed to reasonable compensation under any non-competition agreement. At the time of any change in control, a value may be so attributed, which would result in a reduction of amounts subject to the excise tax. The KEESA for Ms. Kampling provides that if any portion of the benefits under the KEESA, or under any other agreement, would constitute an excess parachute payment for purposes of the Internal Revenue Code, she may either receive the better of either a payment $1 less than the maximum amount she may receive without becoming subject to the 20% excise tax, or receive the fully calculated payment subject to applicable excise taxes, for which she would be personally responsible. For Ms. Kampling, the potential payment and benefit amounts shown in the table above assume she receives the full payment under the KEESA without giving effect to the cutback provision. The KEESAs for Messrs. Hanson, Aller, Larsen, and Gallegos, provide that if the aggregate payments under the KEESA, or otherwise, are an “excess parachute payment,” then the payments will be reduced so that the officer will be entitled to receive $1 less than the maximum amount that the officer could receive without becoming subject to the 20% excise tax, or which we may pay without loss of deduction under the Internal Revenue Code. For Messrs. Hanson, Aller, Larsen, and Gallegos, the potential payment and benefit amounts shown in the tables above reflect this cutback provision from their KEESAs.

In consideration of the KEESA benefits, the executive officer agrees not to compete with Alliant Energy or us for a period of one year after the executive officer leaves Alliant Energy and to keep in confidence any proprietary information or confidential information for a period of five years after the executive officer leaves Alliant Energy. Both of these conditions can be waived in writing by Alliant Energy’s Board of Directors.

Under the KEESAs, a “change in control” is deemed to have occurred if:

• any person is or becomes the beneficial owner of securities representing 20% or more of Alliant Energy outstanding shares of common stock or combined voting power;

• there is a change in the composition of Alliant Energy’s Board of Directors that is not approved by at least two-thirds of the existing directors;

• Alliant Energy’s shareowners approve a merger, consolidation or share exchange with any other corporation (or the issuance of voting securities in connection with a merger, consolidation or share exchange) in which Alliant Energy’s shareowners control less than 50% of combined voting power after the merger, consolidation or share exchange; or

• Alliant Energy’s shareowners approve of a plan of complete liquidation or dissolution or an agreement for the sale or disposition by Alliant Energy of all or substantially all of its assets.

Under the KEESAs, the term “cause” means:

• engaging in intentional conduct that causes Alliant Energy demonstrable and serious financial injury;

• conviction of a felony that substantially impairs the officer’s ability to perform duties or responsibilities; or

• continuing willful and unreasonable refusal by an officer to perform duties or responsibilities.

Under the KEESAs, the term “good reason” means:

• a material breach of the agreement by Alliant Energy;

• a material diminution in the officer’s base compensation;

• a material diminution in the officer’s authority, duties, or responsibilities, including a material diminution in the budget over which he or she retains authority; or

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• a material diminution in the authority, duties, or responsibilities of the supervisor to whom the officer is required to report, including a requirement that he or she report to a corporate officer or employee instead of reporting directly to the board of directors.

Stock Option Agreements

The agreements under which Alliant Energy has awarded Alliant Energy stock options to our executive officers provide that:

• if the officer’s employment is terminated by reason of death or disability, then the options will remain exercisable for twelve months after such termination;

• if the officer’s employment is terminated by reason of retirement after satisfying the minimum requirements for early retirement under the Alliant Energy Cash Balance Pension Plan, then the options may be exercised for three years after such termination; and

• upon a change in control of Alliant Energy, which is defined in the same manner as under the KEESAs, the options will immediately vest and become exercisable, though all outstanding options have already vested.

The tables above include the amounts by which the closing price of Alliant Energy’s common stock on December 30, 2011, exceeds the exercise price for unvested options held by our named executive officers. As of December 30, 2011, all stock options held by our named executive officers were fully vested.

Restricted Stock Agreement

The agreement under which we have awarded restricted stock to Mr. Aller provides that the forfeiture restrictions on such restricted stock will immediately lapse upon:

• a change in control of Alliant Energy, which is defined in the same manner as under the KEESAs;

• the termination of the officer’s employment by reason of death or disability; and

• involuntary termination of the officer’s employment without cause (which means embezzlement of company funds, fraud, actions made in bad faith which cause harm to the company, or willful and unreasonable refusal to perform his duties).

The shares shall be forfeited if Mr. Aller retires prior to December 31, 2012. The tables above include the amounts attributable to unvested restricted stock held by Mr. Aller valued at the closing price of Alliant Energy’s common stock on December 30, 2011.

Performance Contingent Restricted Stock Agreements and Performance Share Agreements

The agreements under which Alliant Energy has awarded performance contingent restricted stock and performance shares to our executive officers provide that:

• if the performance contingency under the award is satisfied and if the officer’s employment is terminated by reason of death, disability, involuntary termination without cause (which means embezzlement of company funds, fraud, actions made in bad faith which cause harm to Alliant Energy, or willful and unreasonable refusal to perform assigned duties), or retirement (which means after the officer has reached age 55 with 10 years of service), then the officer will be entitled to a prorated number of shares based on the ratio of the number of months the officer was employed during the performance period to the total number of months in the performance period; and

• if there is a change in control of Alliant Energy, which is defined in the same manner as under the KEESAs, at least 180 days after the date of the award, then the officer will be entitled to a prorated number of shares based on the ratio of the number of months the officer was employed during the performance period up to the change in control, up to 48.

The tables above include the amounts attributable to the pro rata shares that would be received by our named executive officers valued at the closing price of Alliant Energy’s common stock on December 30, 2011, assuming, in the case of a termination by reason of death, disability, involuntary termination without cause, or retirement, that the applicable performance contingency was satisfied.

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Executive Severance Plan

Alliant Energy also maintains a general executive severance plan for our executive officers that applies when the officer’s position is eliminated or significantly altered by us. The plan provides for a minimum level of severance pay equal to one times base salary, payment of prorated incentive compensation as within the discretion of the Chief Executive Officer, up to 18 months of COBRA coverage, or to the extent eligible, retiree medical coverage, six months of either are paid by Alliant Energy, outplacement services and/or tuition reimbursement of up to $10,000, and access to Alliant Energy’s employee assistance program. Eligibility for benefits under this plan is conditioned upon the executive executing a severance agreement and release form. All executive severance packages are approved by the Compensation and Personnel Committee.

Life Insurance Proceeds

The amounts shown in the tables above reflect proceeds to be paid to the executive officer’s beneficiaries pursuant to life insurance policies Alliant Energy offers that are not otherwise available to all employees (i.e., split dollar and/or reverse split dollar policies, as applicable).

Pension Plans

The tables above do not include any amounts for the Alliant Energy Pension Plan or the Excess Retirement Plan because these plans are not impacted by the nature of the termination of employment nor whether or not there has been a change in control of Alliant Energy. The tables above also do not include any amounts for the SRP other than in the event of a termination after a change in control because that plan is not impacted by the nature of the termination of employment unless there has been a change in control of Alliant Energy, in which case the benefits under the SRP may be enhanced under the KEESA as described above under “Change in Control Agreements.”

Compensation Committee Risk Assessment

In December 2011, the Compensation and Personnel Committee undertook an assessment of our general compensation policies and practices for all employees, including Alliant Energy’s non-regulated businesses, to evaluate whether risks arising from these policies and practices were reasonably likely to have a material adverse effect on us. The Committee did not recommend or implement any material changes in 2011 as a result of its assessment, but has identified or implemented the following features of our policies and practices that it believes serve to mitigate any risks arising from Alliant Energy’s compensation policies and practices:

• use of a mix of short-term and long-term incentive awards to provide an appropriate balance of short and long-term risk and reward horizons;

• use of a variety of performance metrics for incentive awards to avoid excessive focus on a single measure of performance;

• caps on incentive awards to reduce incentives to take short-term or inappropriately risky measures to increase payouts in any given year;

• review of our compensation programs for reasonableness by state utility commissions to mitigate risk;

• claw-back policies that provide Alliant Energy with the ability to recoup short-term and long-term incentive awards under appropriate circumstances; and

• stock ownership requirements for certain executives, including our named executive officers, which we believe help to focus our executives on long-term stock price appreciation and sustainability.

PROPOSAL TWO

ADVISORY VOTE ON COMPENSATION OF OUR NAMED EXECUTIVE OFFICERS

We and Alliant Energy view executive compensation as an important matter both to us and to our shareowners. We are asking shareowners to vote, on a non-binding basis, on an advisory resolution approving the compensation of our named executive officers as disclosed in the Compensation Discussion and Analysis section and the accompanying compensation tables and narrative discussion contained in this proxy statement. We will hold this advisory vote on compensation of our named executive officers annually.

The Compensation and Personnel Committee of our Board of Directors oversees the development and implementation of the executive compensation programs. Alliant Energy has designed the compensation programs to align management interests with the interests of shareowners and customers by directly linking a significant portion of the compensation of our named

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executive officers to defined performance standards that promote balance between the drive for near-term growth and long-term increase in shareowner value. The Committee also designed our compensation programs to attract, retain and motivate key executives who are essential to the implementation of our strategic growth and development strategy. We are, therefore, as required by Section 14A of the Securities Exchange Act of 1934, asking shareowners to vote in favor of the resolution below.

The Committee bases its executive compensation decisions on our core compensation objectives as more fully described in the Compensation Discussion and Analysis, including the following:

• Reward Strong Performance: motivate and reward executives to contribute to the achievement of our business objectives by strengthening the relationship between pay and performance and emphasizing variable at-risk compensation.

• Align Executives’ and Shareowners’ Interests: align executive officers’ interests with those of our shareowners by delivering a significant proportion of total compensation that is dependent upon Alliant Energy total shareowner return.

• Attract and Retain Valuable Officers: attract and retain the best possible personnel through competitive compensation that is comparable to that of similar companies.

We believe these objectives attract, retain and motivate a highly proficient executive management team that is actively engaged in producing results for shareowners and customers.

To emphasize performance standards and variable at-risk compensation, all of our short-term (annual) and equity-based awards in 2011 were granted contingent upon the achievement of performance goals, with the exception of certain time-based restricted stock units granted on a non-recurring basis to Mr. Aller. As a result, on average in the aggregate, approximately 54% to 78% of our named executive officers’ target total compensation for 2011 was dependent on performance. Information demonstrating the link between our performance and executive compensation can be found in the Executive Summary of the Compensation Discussion and Analysis.

The Board of Directors would like the support of our shareowners for the compensation of our named executive officers as disclosed in this proxy statement. This advisory vote on the compensation of our named executive officers allows our shareowners to express their opinions about our executive compensation programs. As we seek to align our executive compensation programs with our performance results and shareowners’ interests, we ask that our shareowners approve the compensation of our named executive officers. Accordingly, for the reasons we discuss above, the Board of Directors recommends that shareowners vote in favor of the following resolution:

“RESOLVED, that the shareowners approve, on an advisory basis, the compensation of the named executive officers as disclosed pursuant to Item 402 of Regulation S-K, including the Compensation Discussion and Analysis section and the compensation tables and narrative discussion contained in this proxy statement.”

The votes cast “FOR” must exceed the votes cast “AGAINST” the proposal at the Annual Meeting (assuming a quorum is present) to approve the compensation of our named executive officers as disclosed in this proxy statement. For purposes of determining the vote required for this proposal, abstentions and broker non-votes will have no impact on the vote. This advisory vote on the compensation of our named executive officers is not binding on us, our Board of Directors or the Compensation and Personnel Committee.

The vote is non-binding. However, our Board of Directors and the Committee will review and consider the outcome of this advisory vote when making future compensation decisions for our named executive officers.

The Board of Directors recommends a vote “FOR” approval of the compensation of our named executive officers as disclosed in this proxy statement.

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DIRECTOR COMPENSATION

The following table summarizes the compensation paid to, or earned by, our non-employee directors for all services to us, Alliant Energy and Alliant Energy’s other subsidiaries during 2011.

Name(1)	Fees Earned or Paid in Cash ($)(2)		All Other Compensation ($)(3)		Total ($)
Patrick E. Allen	$	61,292	$	0	$	61,292
Michael L. Bennett	$	173,500	$	14,310	$	187,810
Darryl B. Hazel	$	148,500	$	0	$	148,500
Singleton B. McAllister	$	145,000	$	17,555	$	162,555
Ann K. Newhall	$	150,000	$	12,462	$	162,462
Dean C. Oestreich	$	150,000	$	0	$	150,000
David A. Perdue	$	148,500	$	21,892	$	170,392
Judith D. Pyle	$	145,000	$	169	$	145,169
Carol P. Sanders	$	158,500	$	0	$	158,500

⁽¹⁾  Directors who also are employees, such as Mr. Harvey and Ms. Kampling, receive no additional compensation for their service on our Board of Directors and are not included in this table. The compensation received by Mr. Harvey and Ms. Kampling for other services rendered to us, Alliant Energy and Alliant Energy’s subsidiaries during and for 2011 is shown in the Summary Compensation Table.

⁽²⁾ The amounts shown in this column include the following aggregate dollar amounts deferred and the number of shares of common stock acquired in the Alliant Energy Deferred Compensation Plan Stock Account by each of the following directors: Mr. Bennett $173,500 or 4,454 shares; Mr. Hazel $14,850 or 381 shares; Ms. Newhall $75,000 or 1,925 shares; Mr. Oestreich $75,000 or 1,925 shares; Mr. Perdue $148,500 or 3,812 shares; and Ms. Sanders $79,250 or 2,034 shares.

⁽³⁾ The amounts in this column reflect the amounts attributable to director charitable award premiums and, in the case of Ms. Pyle, $169 for imputed income on director life insurance, and, in the case of Mr. Bennett, our Lead Independent Director, $1,849 for air travel expenses on Alliant Energy aircraft associated with a customer event in Madison, Wisconsin, that was attended at the request of our Chairman of the Board. The personal use of aircraft owned by Alliant Energy is calculated on Standard Industry Fare Level rates published periodically by the Internal Revenue Service.

Retainer Fees — In 2011, all non-employee directors, each of whom served on the Boards of Directors of the Company, Alliant Energy, and IPL, received an annual retainer for service on all Boards consisting of $145,000 in cash. Also in 2011, the Chairperson of the Audit Committee received an additional $13,500 cash retainer and the Chairpersons of the Compensation and Personnel, Nominating and Governance, and Environmental, Nuclear, Health, and Safety Committees received an additional $5,000 cash retainer; other members of the Audit Committee received an additional $3,500 cash retainer; and the Lead Independent Director received an additional $20,000 cash retainer.

For 2012, after a review of market based compensation for outside directors presented by the Compensation and Personnel Committee’s independent consultant, the Board of Directors modified the compensation for all non-employee directors, each of whom serve on the Boards of the Company, Alliant Energy and IPL. The non-employee directors will receive an annual retainer for service on all Boards consisting of $160,000 in cash. Also in 2012, the Chairperson of the Audit Committee will receive an additional $13,500 cash retainer and the Chairpersons of the Compensation and Personnel, Nominating and Governance, and Environmental, Nuclear, Health, and Safety Committees will receive an additional $7,500 cash retainer; other members of the Audit Committee will receive an additional $3,500 cash retainer; and the Lead Independent Director will receive an additional $20,000 cash retainer.

Meeting Fees — In 2011, directors did not receive any additional compensation for attendance at Board or Committee meetings.

Other — Pursuant to Alliant Energy’s directors’ expense reimbursement policy, Alliant Energy reimburses all directors for travel and other necessary business expenses incurred in the performance of their responsibilities for us. Committees are

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provided the opportunity to retain outside independent advisors, as needed. Alliant Energy also extends coverage to directors under our travel accident and directors’ and officers’ indemnity insurance policies.

Receipt of Fees in Stock — For fees paid in 2011, each director was encouraged to voluntarily elect to use not less than 50% of his or her cash retainer to purchase shares of Alliant Energy’s common stock pursuant to Alliant Energy’s Shareowner Direct Plan or to defer such amount through the Alliant Energy Stock Account in the Alliant Energy Deferred Compensation Plan. For fees paid in 2012, the Compensation and Personnel Committee and the Nominating and Governance Committee again recommended that each non-employee director voluntarily elect to use a portion of his or her cash retainer to purchase shares of Alliant Energy common stock. Under Alliant Energy’s 2010 Omnibus Incentive Plan, in the discretion of, and subject to restrictions imposed by the Compensation and Personnel Committee, a non-employee director may elect to receive, or the Compensation and Personnel Committee may require that a non-employee director will be paid, all or any portion of his or her annual cash retainer payment or other cash fees for serving as a director in the form of shares of Alliant Energy common stock under that Plan.

Share Ownership Guidelines — Pursuant to Alliant Energy’s Restated Articles of Incorporation, directors are required to be shareowners. The target share ownership level is the number of shares equal to the value of two times the annual retainer amount received by each of the non-employee directors. The achievement of this ownership level is to be accomplished by each director within five years of joining the Board of Directors or as soon thereafter as practicable. Shares held by directors in the Alliant Energy Shareowner Direct Plan and the Alliant Energy Deferred Compensation Plan are included in the target goal. As of February 29, 2012, all non-management directors, with the exception of Mr. Allen, who was named a Director in 2011, had met the target ownership level. We will continue to monitor the status of the target ownership levels and review them with the Board of Directors.

Alliant Energy Deferred Compensation Plan — Under the Alliant Energy Deferred Compensation Plan, directors may elect to defer all or part of their retainer fee to an Interest Account, Equity Account, Alliant Energy Stock Account, or beginning in 2011, a Mutual Fund Account. Deferrals deposited to the Interest Account receive an annual return based on the 10-year Treasury Bond Rate plus 1.50% as established by the Federal Reserve. Deferrals deposited to the Alliant Energy’s Equity Account are treated as invested in an S&P 500 index fund. Deferrals deposited to the Mutual Fund Account, are treated as invested in a mutual fund or other investment vehicle offered under Alliant Energy’s 401(k) Savings Plan as selected by our Investment Committee. Deferrals deposited to the Alliant Energy Stock Account are treated as though invested in Alliant Energy common stock and will be credited with dividend equivalents, which are treated as if reinvested. The director may elect that the Deferred Compensation Account be paid in a lump sum or in annual installments for up to 10 years.

Directors’ Charitable Award Program — Alliant Energy maintains a Directors’ Charitable Award Program applicable to certain members of our Board of Directors beginning after three years of service. The Board has terminated this program for all directors who joined the Board after January 1, 2005. The participants in this program currently are Mr. Bennett, Ms. McAllister, Ms. Newhall, Mr. Perdue and Ms. Pyle. The purpose of the program is to recognize our directors’ interest in supporting worthy charitable institutions. Under the program, when a director dies, Alliant Energy will donate a total of $500,000 to one qualified charitable organization or divide that amount among a maximum of five qualified charitable organizations selected by the individual director. The individual director derives no financial benefit from the program. Alliant Energy takes all deductions for charitable contributions and Alliant Energy funds the donations through life insurance policies on the directors. Over the life of the program, all costs of donations and premiums on the life insurance policies, including a return of our cost of funds, will be recovered through life insurance proceeds on the directors. The program, over its life, will not result in any material cost to Alliant Energy. The cost to Alliant Energy of the program for the individual directors in 2011 is included in the “Director Compensation” table above.

Directors’ Life Insurance Program — Alliant Energy maintains a split-dollar Directors’ Life Insurance Program for non-employee directors. In November 2003, the Board of Directors terminated this insurance benefit for all new directors and for any then-serving director without the required vesting period of three years of service. The only active director participant in this program is Ms. Pyle. The program provides a maximum death benefit of $500,000 to each eligible director. Under the split-dollar arrangement, directors are provided a death benefit only and do not have any interest in the cash value of the policies. The program is structured to pay a portion of the total death benefit to us to reimburse Alliant Energy for all costs of the program, including a return on its funds. The program, over its life, will not result in any material cost to Alliant Energy. During 2011, there was no cost incurred under the program for current directors.

Alliant Energy Matching Gift Program — Directors are eligible to participate in the Alliant Energy Foundation, Inc. matching gift program, which is generally available to all employees and retirees. Under this program, the Foundation matches 100% of charitable donations over $25 to eligible charities up to a maximum of $10,000 per year for each director.

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REPORT OF THE AUDIT COMMITTEE

To Our Shareowners:

The Audit Committee of our Board of Directors is composed of four directors, each of whom is independent under the NYSE corporate governance listing standards and applicable SEC rules. The Committee operates under a written charter adopted by the Board of Directors.

Our management is responsible for our internal controls and the financial reporting process, including the system of internal controls. The independent registered public accounting firm is responsible for expressing opinions on the conformity of our audited consolidated financial statements with accounting principles generally accepted in the United States of America and on our internal controls over financial reporting. The Committee has reviewed and discussed the audited consolidated financial statements with management and the independent registered public accounting firm. The Committee has discussed with the independent registered public accounting firm matters required to be discussed by AU Section 380 of the Public Company Accounting Oversight Board, as amended, SEC regulations and NYSE requirements.

Our independent registered public accounting firm has provided to the Committee the written disclosures required by applicable requirements of the Public Company Accounting Oversight Board regarding the independent registered public accounting firm’s communications with the audit committee concerning independence, and the Committee discussed with the independent registered public accounting firm its independence.

The Committee has adopted a policy that requires advance approval of all audit, audit-related, tax and other permitted services performed by the independent registered public accounting firm. The policy provides for pre-approval by the Committee of specifically defined audit and non-audit services after the Committee is provided with the appropriate level of details regarding the specific services to be provided. The policy does not permit delegation of the Committee’s authority to management. In the event the need for specific services arises between Committee meetings, the Committee has delegated to the Chairperson of the Committee authority to approve permitted services provided that the Chairperson reports any decisions to the Committee at its next scheduled meeting. In accordance with the policy, the Committee pre-approved all audit, audit-related, tax and other permitted services performed by Deloitte & Touche LLP and its affiliates and related entities in 2011.

The fees that were billed to the Company by its independent registered public accounting firm for work performed on behalf of our Company and our subsidiaries for 2010 and 2011 were as follows:

	2010		2011
Audit Fees	$	907,000	$	872,000
Audit-Related Fees		129,000		33,000
Tax Fees		115,000		0
All Other Fees		8,000		3,000

Audit fees consisted of the fees billed for the audits of the consolidated financial statements of our Company and our subsidiaries, for reviews of financial statements included in Form 10-Q filings, and for services normally provided in connection with statutory and regulatory filings such as financing transactions. Audit fees also included our Company’s portion of fees for the audits of Alliant Energy’s consolidated financial statements and effectiveness of internal controls over financial reporting.

Audit-related fees consisted of the fees billed for services rendered related to employee benefits plan audits and attest services not required by statute or regulations for 2011 and 2010. Audit-related fees for 2010 also included fees billed for an assessment of International Financial Reporting Standards.

Tax fees consisted of the fees billed for professional services rendered for tax compliance, tax advice and tax planning, including all services performed by the tax professional staff of affiliates of the independent registered public accounting firm, except those rendered in connection with the audit.

All other fees consisted of license fees for accounting research software products and seminars.

The Committee does not consider the provision of non-audit services by the independent registered public accounting firm described above to be incompatible with maintaining independence of the independent registered public accounting firm.

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The Committee discussed with our internal auditor and independent registered public accounting firm the overall scope and plans for their respective audits. The Committee meets with the internal auditor and independent registered public accounting firm, with and without management present, to discuss the results of their examinations, the evaluation of our internal controls and the overall quality of our financial reporting.

Based on the Committee’s reviews and discussions with management, the internal auditor and the independent registered public accounting firm referred to above, the Committee recommended to the Board of Directors that the audited consolidated financial statements be included in our Annual Report on Form 10-K for the year ended December 31, 2011, for filing with the SEC.

AUDIT COMMITTEE

Carol P. Sanders (Chairperson)

Patrick E. Allen

Michael L. Bennett

Darryl B. Hazel

PROPOSAL THREE

RATIFICATION OF THE APPOINTMENT

OF DELOITTE & TOUCHE LLP AS THE COMPANY’S

INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM FOR 2012

In accordance with its charter, the Audit Committee of the Board of Directors appointed the firm of Deloitte & Touche LLP, independent registered public accounting firm, to audit the consolidated financial statements of the Company and its subsidiaries for 2012, and is requesting that its shareowners ratify such appointment.

Representatives of Deloitte & Touche LLP are not expected to attend the Annual Meeting. Further information about the services of Deloitte & Touche LLP, including the fees paid in 2010 and 2011, is set forth in the “Report of the Audit Committee.”

The votes cast “FOR” must exceed the votes cast “AGAINST” the proposal at the Annual Meeting (assuming a quorum is present) to ratify the appointment of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for 2012. For purposes of determining the vote required for this proposal, abstentions and broker non-votes will have no impact on the vote. If the appointment is not ratified, the failure by the shareowners to ratify will be considered by the Audit Committee as an indication that it should consider selecting another independent registered public accounting firm for the following fiscal year. Even if the shareowners ratify the appointment, the Audit Committee, in its discretion, may select a new independent registered public accounting firm at any time during the year if it feels that such a change would be in the best interest of the Company.

The Board of Directors recommends that shareowners vote “FOR” the ratification of the appointment of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for 2012.

53

SECTION 16(a) BENEFICIAL OWNERSHIP

REPORTING COMPLIANCE

Section 16(a) of the Securities Exchange Act of 1934 requires the Company’s directors and certain officers to file reports of ownership and changes in ownership of the Company’s preferred stock with the SEC and furnish copies of those reports to us. As a matter of practice, Alliant Energy’s Shareowner Services Department assists the Company’s directors and executive officers in the preparation of initial reports of ownership and reports of changes in ownership and files those reports with the SEC on their behalf. Based on the written representations of the reporting persons and on copies of the reports filed with the SEC, the Company believes that all reporting persons of the Company satisfied the filing requirements in 2011.

We will furnish to any shareowner, without charge, a copy of our 2011 Annual Report on Form 10-K. You may obtain a copy of the Form 10-K by writing Alliant Energy Shareowner Services at 4902 North Biltmore Lane, P.O. Box 14720, Madison, WI 53708-0720 or via email at shareownerservices@alliantenergy.com.

By Order of the Board of Directors,

F. J. Buri

Corporate Secretary and

Assistant General Counsel

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APPENDIX A

WISCONSIN POWER AND LIGHT COMPANY

ANNUAL REPORT

For the Year Ended December 31, 2011

Contents	Page
Forward-looking Statements		A-2
The Company		A-3
Selected Financial Data		A-4
Management’s Discussion and Analysis of Financial Condition and Results of Operations		A-5
Management’s Annual Report on Internal Control Over Financial Reporting		A-38
Report of Independent Registered Public Accounting Firm		A-39
Consolidated Financial Statements		A-40
Consolidated Statements of Income		A-40
Consolidated Balance Sheets		A-41
Consolidated Statements of Cash Flows		A-43
Consolidated Statements of Common Equity		A-44
Notes to Consolidated Financial Statements		A-45
Shareowner Information		A-81
Executive Officers and Directors		A-81

A-1

Wisconsin Power and Light Company (WPL) filed a combined Form 10-K for 2011 with the Securities and Exchange Commission (SEC). Such document included the filings of WPL’s parent, Alliant Energy Corporation (Alliant Energy), Interstate Power and Light Company (IPL) and WPL. The primary first tier subsidiaries of Alliant Energy are WPL, IPL, Alliant Energy Resources, LLC (Resources) and Alliant Energy Corporate Services, Inc. (Corporate Services). Certain portions of Management’s Discussion and Analysis of Financial Condition and Results of Operations (MDA) and the Notes to Consolidated Financial Statements included in this WPL Annual Report represent excerpts from the combined Form 10-K. As a result, the disclosure included in this WPL Annual Report at times includes information relating to Alliant Energy, IPL, Resources and/or Corporate Services. All required disclosures for WPL are included in this Annual Report thus such additional disclosures represent supplemental information. The information contained in this Annual Report, with the exception of the section entitled “Shareowner Information,” was filed with the SEC on February 27, 2012 and was complete and accurate as of that date. WPL disclaims any responsibility to update that information in this Annual Report.

FORWARD-LOOKING STATEMENTS

Statements contained in this report that are not of historical fact are forward-looking statements intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995. These forward-looking statements can be identified as such because the statements include words such as “expect,” “anticipate,” “plan” or other words of similar import. Similarly, statements that describe future financial performance or plans or strategies are forward-looking statements. Such forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements. Some, but not all, of WPL’s risks and uncertainties include:

• federal and state regulatory or governmental actions, including the impact of energy, tax, financial and health care legislation, and of regulatory agency orders;

• its ability to obtain adequate and timely rate relief to allow for, among other things, the recovery of operating costs, fuel costs, transmission costs, deferred expenditures, capital expenditures, and remaining costs related to generating units that may be permanently closed, earning its authorized rates of return, and the payments to its parent of expected levels of dividends;

• the ability to continue cost controls and operational efficiencies;

• the state of the economy in its service territory and resulting implications on sales, margins and ability to collect unpaid bills;

• developments that adversely impact its ability to implement its strategic plan, including unanticipated issues with new emission control equipment for its various coal-fired generating facilities, its potential purchase of the Riverside Energy Center (Riverside) and the potential decommissioning of certain of its generating facilities;

• weather effects on results of utility operations;

• successful resolution of the pending challenge by interveners of the approval by the Public Service Commission of Wisconsin (PSCW) of its Bent Tree — Phase I wind project;

• issues related to the availability of generating facilities and the supply and delivery of fuel and purchased electricity and price thereof, including the ability to recover and to retain the recovery of purchased power, fuel and fuel-related costs through rates in a timely manner;

• the impact that fuel and fuel-related prices may have on its customers’ demand for utility services;

• the ability to defend against environmental claims brought by state and federal agencies, such as the United States of America (U.S.) Environmental Protection Agency (EPA), or third parties, such as the Sierra Club;

• issues associated with environmental remediation efforts and with environmental compliance generally, including changing environmental laws and regulations;

• the ability to recover through rates all environmental compliance and remediation costs, including costs for projects put on hold due to uncertainty of future environmental laws and regulations;

• continued access to the capital markets on competitive terms and rates, and the actions of credit rating agencies;

• inflation and interest rates;

• changes to the creditworthiness of counterparties with which it has contractual arrangements, including participants in the energy markets and fuel suppliers and transporters;

• issues related to electric transmission, including operating in Regional Transmission Organization (RTO) energy and ancillary services markets, the impacts of potential future billing adjustments and cost allocation changes from RTOs and recovery of costs incurred;

• unplanned outages, transmission constraints or operational issues impacting fossil or renewable generating facilities and risks related to recovery of resulting incremental costs through rates;

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• Alliant Energy’s ability to successfully pursue appropriate appeals with respect to, and any liabilities arising out of, the alleged violation of the Employee Retirement Income Security Act of 1974 by Alliant Energy’s Cash Balance Pension Plan (Cash Balance Plan);

• current or future litigation, regulatory investigations, proceedings or inquiries;

• employee workforce factors, including changes in key executives, collective bargaining agreements and negotiations, work stoppages or additional restructurings;

• impacts that storms or natural disasters in its service territory may have on its operations and recovery of, and rate relief for, costs associated with restoration activities;

• access to technological developments;

• material changes in retirement and benefit plan costs;

• the impact of incentive compensation plans accruals;

• the effect of accounting pronouncements issued periodically by standard-setting bodies;

• the impact of changes to government incentive elections for wind projects;

• the impact of adjustments made to deferred tax assets and liabilities from state apportionment assumptions;

• the ability to utilize tax credits and net operating losses generated to date, and those that may be generated in the future, before they expire;

• the ability to successfully complete tax audits and appeals with no material impact on earnings and cash flows;

• the direct or indirect effects resulting from terrorist incidents, including cyber terrorism, or responses to such incidents; and

• factors listed in MDA.

WPL assumes no obligation, and disclaims any duty, to update the forward-looking statements in this report.

THE COMPANY

Overview—WPL was incorporated in 1917 in Wisconsin as Eastern Wisconsin Electric Company. WPL is a public utility engaged principally in the generation and distribution of electricity and the distribution and transportation of natural gas in selective markets in southern and central Wisconsin. WPL operates in municipalities pursuant to permits of indefinite duration and state statutes authorizing utility operation in areas annexed by a municipality. At Dec. 31, 2011, WPL supplied electric and gas service to 456,637 and 179,945 retail customers, respectively. In 2011, 2010 and 2009, WPL had no single customer for which electric, gas and/or other sales accounted for 10% or more of WPL’s consolidated revenues. WPL Transco LLC is a wholly-owned subsidiary of WPL and holds WPL’s investment in the American Transmission Company LLC (ATC). At Dec. 31, 2011, WPL had 1,308 full- and part-time employees.

Regulation—WPL is subject to regulation by the PSCW related to its operations in Wisconsin for various matters including, but not limited to, retail utility rates and standards of service, accounting requirements, issuance and use of proceeds of securities, affiliate transactions, approval of the location and construction of electric generating facilities and certain other additions and extensions to facilities.

Retail Utility Base Rates—WPL files periodic requests with the PSCW for retail rate relief. These filings are required to be based on forward-looking test periods. There is no statutory time limit for the PSCW to decide retail rate requests. However, the PSCW attempts to process base retail rate cases in approximately 10 months and has the ability to approve interim retail rate relief, subject to refund, if necessary.

Retail Commodity Cost Recovery Mechanisms—

Electric—WPL’s retail electric base rates include estimates of annual fuel-related costs (fuel and purchased power energy costs) anticipated during the test period. During each electric retail rate proceeding or in a separate fuel cost plan approval proceeding, the PSCW sets fuel monitoring ranges based on the forecasted fuel-related costs used to determine rates in such proceeding. If WPL’s actual fuel-related costs fall outside these fuel monitoring ranges, WPL is authorized to defer the incremental over- or under-collection of fuel-related costs from electric retail customers that are outside the approved ranges. Deferral of under-collections are reduced to the extent actual return on common equity earned by WPL during the fuel cost plan year exceeds the most recently authorized return on common equity. Subject to review and approval by the PSCW, any over- or under-collection of fuel-related costs for each year are reflected in future billings to retail customers. This cost recovery mechanism became effective for WPL on Jan. 1, 2011.

Natural Gas—WPL’s retail natural gas tariffs contain an automatic adjustment clause for changes in prudently incurred natural gas costs required to serve its retail gas customers. Any over- or under-collection of natural gas costs for each given month are automatically reflected in future billings to retail customers.

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Energy Efficiency Cost Recovery Mechanism—WPL contributes a certain percentage of its annual retail utility revenues to help fund Focus on Energy, Wisconsin’s statewide energy efficiency and renewable energy resource program. Estimated contributions to Focus on Energy, along with WPL-run energy efficiency program costs, are recovered from WPL’s retail customers through changes in base rates determined during periodic rate proceedings and include a reconciliation of such estimated amounts to actual costs incurred with any difference deferred for inclusion in future base rate changes.

New Electric Generating Facilities—A Certificate of Authority (CA) application is required to be filed with the PSCW for construction approval of any new electric generating facility with a capacity of less than 100 megawatts (MW). A Certificate of Public Convenience and Necessity application is required to be filed with the PSCW for construction approval of any new electric generating facility with a capacity of 100 MW or more built in Wisconsin. In addition, WPL’s ownership and operation of electric generating facilities (including those located outside the state of Wisconsin) to serve Wisconsin customers is subject to retail utility rate regulation by the PSCW.

Electric Generating Facility Upgrades—A CA application is required to be filed with the PSCW for construction approval of any additions to electric generating facilities, including emission control projects that exceed a certain threshold amount. The current PSCW rules require a CA for projects with an estimated cost in excess of approximately $8 million.

Advance Rate Making Principles—Wisconsin Statute §196.371 provides Wisconsin utilities with the opportunity to request rate making principles prior to the purchase or construction of any nuclear or fossil-fueled electric generating facility or renewable generating resource, such as a wind facility, utilized to serve Wisconsin customers. WPL is not obligated to file for or accept authorized rate making principles under Wisconsin Statute §196.371. WPL can proceed with an approved project under traditional rate making terms or accept authorized rate making principles under Wisconsin Statute §196.371.

Other—WPL is also subject to regulation by the Federal Energy Regulatory Commission (FERC) and the EPA, as well as various other federal, state and local agencies.

Electric Utility Operations—As of Dec. 31, 2011, WPL provided electric service to 456,637 retail, 21 wholesale and 2,236 other customers in 606 communities. 2011 electric utility operations accounted for 86% of WPL’s operating revenues and 94% of WPL’s operating income. Electric sales are seasonal to some extent with the annual peak normally occurring in the summer months due to air conditioning requirements. In 2011, the maximum peak hour demand for WPL was 2,761 MW on July 20, 2011.

Gas Utility Operations—As of Dec. 31, 2011, WPL provided natural gas service to 179,945 retail and 227 transportation and other customers in 239 communities. 2011 gas utility operations accounted for 14% of WPL’s operating revenues and 10% of WPL’s operating income. In addition to sales of natural gas to retail customers, WPL provides transportation service to commercial and industrial customers by moving customer-owned gas through WPL’s distribution system to the customers’ meters. Gas sales follow a seasonal pattern with an annual base-load of gas and a large heating peak occurring during the winter season. Natural gas obtained from producers, marketers and brokers, as well as gas in storage, is utilized to meet the peak heating season requirements.

SELECTED FINANCIAL DATA

	2011 (a)		2010 (a)		2009 (a)		2008		2007
	(in millions)
Operating revenues	$	1,434.4	$	1,423.6	$	1,386.1	$	1,465.8	$	1,416.8
Net income		163.5		152.3		89.5		118.4		113.5
Earnings available for common stock		160.2		149.0		86.2		115.1		110.2
Cash dividends declared on common stock		112.1		109.5		91.0		91.3		191.1
Cash flows from operating activities		428.8		372.4		305.8		239.7		258.0
Total assets		4,044.0		3,889.6		3,681.4		3,265.5		2,788.6
Long-term obligations, net		1,190.7		1,193.7		1,146.3		899.0		715.7

(a) Refer to “Results of Operations” in MDA for a discussion of the 2011, 2010 and 2009 results of operations.

Alliant Energy is the sole common shareowner of all 13,236,601 shares of WPL’s common stock outstanding. As such, earnings per share data is not disclosed herein.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

MDA consists of the following information:

• Executive Summary

• Strategic Overview

• Rate Matters

• Environmental Matters

• Legislative Matters

• Results of Operations

• Liquidity and Capital Resources

• Other Matters

• Market Risk Sensitive Instruments and Positions

• Critical Accounting Policies and Estimates

• Other Future Considerations

EXECUTIVE SUMMARY

Description of Business

General—WPL is a public utility engaged principally in the generation and distribution of electricity and the distribution and transportation of natural gas in selective markets in southern and central Wisconsin. WPL owns an approximate 16% interest in ATC, a transmission-only utility operating in Wisconsin, Michigan, Illinois and Minnesota. WPL also owns a portfolio of electric generating facilities located in Wisconsin with a diversified fuel mix including coal, natural gas and renewable resources. The output from these generating facilities, supplemented with purchased power, is used to provide electric service to approximately 457,000 retail electric customers in Wisconsin. WPL also procures natural gas from various suppliers to provide service to approximately 180,000 retail gas customers in Wisconsin. WPL’s earnings and cash flows are sensitive to various external factors including, but not limited to, the amount and timing of rate relief approved by regulatory authorities, the impact of weather and economic conditions on electric and gas sales volumes and other factors listed in “Forward-looking Statements.”

Financial Results—In 2011, 2010 and 2009, WPL’s earnings available for common stock were $160.2 million, $149.0 million and $86.2 million, respectively. Refer to “Results of Operations” for details regarding the various factors impacting earnings during 2011, 2010 and 2009.

Strategic Overview

WPL’s strategic plan focuses on its core business of delivering regulated electric and natural gas service in Wisconsin. The strategic plan is built upon three key elements: competitive costs, safe and reliable service and balanced generation. The strategic plan includes purchasing a natural gas-fired electric generating facility, implementing emission controls and performance upgrades at its more-efficient coal-fired electric generating facilities, and potential retirement of certain older and less-efficient coal-fired generating facilities. Key strategic plan developments impacting WPL during 2011 include:

• February 2011—WPL’s 200 MW Bent Tree—Phase I wind project in Freeborn County, Minnesota began full operation.

• February 2011—WPL received approval from the PSCW to install scrubbers and baghouses at Columbia Units 1 and 2 to reduce sulfur dioxide (SO2) and mercury emissions, respectively, at the facility.

• March 2011—WPL purchased Wisconsin Electric Power Company’s (WEPCO’s) 25% ownership interest in Edgewater Unit 5 for $38 million.

• August 2011—WPL announced plans to install a scrubber and baghouse at Edgewater Unit 5 to reduce SO2 and mercury emissions at the generating facility. Construction of the scrubber and baghouse is expected to begin by 2015 and be placed into service by 2017.

• November 2011—WPL filed a CA with the PSCW for the purchase of Riverside in late 2012. A decision from the PSCW is expected in April 2012.

Refer to “Strategic Overview” for additional details regarding these and other strategic plan developments.

Rate Matters

WPL is subject to federal regulation by FERC, which has jurisdiction over wholesale electric rates, and state regulation in Wisconsin for retail utility rates. Key regulatory developments impacting WPL during 2011 include:

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• January 2011—New electric fuel cost recovery rules in Wisconsin became effective, which allow WPL to defer electric fuel-related costs that fall outside a symmetrical cost tolerance band and reflect the under-/over-recovery of these deferred costs in future billings to its retail customers. WPL’s recovery of deferred electric fuel-related costs is restricted if it earns in excess of its authorized return on common equity during the period it under-recovers the fuel-related costs.

• January 2011—In accordance with the PSCW’s December 2010 order, WPL implemented an annual retail electric rate increase of $8 million, or approximately 1%, effective Jan. 1, 2011. This $8 million increase in annual rates combined with the termination of the $9 million interim fuel-related rate increase on Dec. 31, 2010 resulted in a net $1 million decrease in annual retail electric rates charged to customers effective January 2011.

• December 2011—WPL received an order from the PSCW authorizing an annual retail electric rate increase of $4 million related to expected changes in retail fuel-related costs, effective Jan. 1, 2012. The December 2011 order also required WPL to defer direct Cross-State Air Pollution Rule (CSAPR) compliance costs that are not included in the fuel monitoring level and set a zero percent tolerance band for the CSAPR-related deferral. The 2012 fuel costs, excluding deferred CSAPR compliance costs, will be monitored using an annual bandwidth of plus or minus 2%.

Refer to “Rate Matters” for additional details regarding these and other regulatory developments.

Environmental Matters

WPL is subject to regulation of environmental matters by various federal, state and local authorities. Key environmental developments during 2011 that may impact WPL include:

• January 2011—The EPA’s Greenhouse Gases (GHG) Tailoring Rule became effective. The rule establishes a GHG threshold for major sources under the Prevention of Significant Deterioration (PSD) and Title V Operation Permit programs at 75,000 and 100,000 tons per year of carbon dioxide-equivalent (CO2e) for existing and new sources, respectively. The rule is subject to legal challenge.

• March 2011—The EPA issued a revised proposed rule under Section 316(b) of the Federal Clean Water Act (Section 316(b) Rule), which applies to existing and new cooling water intake structures at large steam electric generating units (EGUs). A final rule is expected to be issued in 2012 and compliance is expected within eight years of the effective date of the final rule.

• July 2011—The EPA issued CSAPR (formerly known as the Clean Air Transport Rule (CATR)), which if ultimately implemented is expected to require SO2 and nitrogen oxide (NOx) emissions reductions from WPL’s fossil-fueled EGUs with greater than 25 MW of capacity beginning in 2012. However, in December 2011, the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit Court) stayed the implementation of CSAPR and as a result the Clean Air Interstate Rule (CAIR) obligations remain effective pending further review by the D.C. Circuit Court and the EPA.

• December 2011—The EPA issued the final Utility Maximum Achievable Control Technology (MACT) Rule, also referred to as the Mercury and Air Toxic Standard (MATS), which requires compliance with emission limits and work practice standards for the control of mercury and other hazardous air pollutants (HAPs). The compliance deadline for this rule is currently expected to be required by April 2015.

• December 2011—The EPA issued a proposed reconsidered Industrial Boiler and Process Heater MACT Rule, which sets compliance limits for HAPs from fossil-fueled EGUs with less than 25 MW capacity as well as certain auxiliary boilers and process heaters operated at EGUs. The EPA currently expects to issue a final reconsidered rule by April 2012, which would replace the current final rule, published by the EPA in March 2011, that is currently in effect. The compliance deadline for the reconsidered rule is currently expected to be mid-2015.

Refer to “Environmental Matters” for additional details regarding these and other environmental developments.

Legislative Matters

WPL monitors various legislative developments, including those relating to energy, tax, financial and other matters. Key legislative developments impacting WPL during 2011 include:

• June 2011—The 2011 Wisconsin Act 32 (Act 32) was enacted. The most significant provision of Act 32 for WPL relates to contribution requirements to the Focus on Energy Program.

• December 2011—The National Defense Authorization Act (NDAA) was enacted. The most significant provision of the NDAA for WPL states that regulated utilities are no longer subject to a tax normalization violation if they provide the benefits of cash grants related to renewable energy projects to their customers over a shorter time period than the regulatory life of the project assets. As a result, WPL is currently re-evaluating its options for government incentive elections for the Bent Tree—Phase I wind project.

Refer to “Legislative Matters” for additional details regarding these and other legislative developments.

Liquidity and Capital Resources

Based on its current liquidity position and capital structure, WPL believes it will be able to secure the additional capital required to implement its strategic plan and to meet its long-term contractual obligations. Key financing developments impacting WPL during 2011 include:

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• September 2011—Moody’s Investors Service changed WPL’s credit ratings outlook from stable to negative.

• November 2011—The PSCW authorized WPL to have up to $400 million of short-term borrowings and letters of credit outstanding through the earlier of the termination date of WPL’s credit facility agreement or December 2019.

• December 2011—WPL entered into a new revolving credit facility totaling $400 million, which expires in December 2016.

• December 2011—WPL’s shelf registration statement became effective with availability to issue up to $800 million of preferred stock and debt securities through December 2014.

• December 2011—At Dec. 31, 2011, WPL had $374 million of available capacity under its revolving credit facility.

Refer to “Liquidity and Capital Resources” for additional details regarding these and other financing developments.

STRATEGIC OVERVIEW

Strategic Plan—WPL’s strategic plan focuses on its core business of delivering regulated electric and natural gas service in its Wisconsin service territory. The strategic plan is built upon three key elements: competitive costs, safe and reliable service, and balanced generation.

Competitive Costs—Providing competitive and predictable energy costs for customers is a key element of the strategic plan. WPL is aware that the majority of its costs become part of rates charged to its customers and any rate increase has an impact on its customers. Given that potential public policy changes and resulting increases in future energy costs are possible, WPL is focused on controlling its costs with the intent of providing competitive rates to its customers. Energy efficiency is also an important part of the strategic plan and is an option that provides customers with the opportunity to save on their energy bills. WPL’s approach to energy efficiency is based on regulations in Wisconsin. The objective is to meet prescribed goals in the most cost-effective manner. Additional details regarding energy efficiency programs used by WPL are included in “Energy Efficiency Programs” below.

WPL periodically enters into purchased power agreements (PPAs) to meet its energy and capacity needs. WPL’s most significant PPAs are with Dominion Resources, Inc. for the purchase of energy and capacity from the Kewaunee Nuclear Power Plant (Kewaunee) through December 2013, and with a subsidiary of Calpine Corporation for the purchase of energy and capacity from Riverside through May 2013. These PPAs include annual payments by WPL for rights to the electric generating capacity from these facilities. WPL’s current strategic plan does not include the extension of these PPAs beyond their current terms. The elimination of the capacity payments at the end of these PPAs is expected to mitigate the impacts on customers’ rates from future capital expenditures for new potential natural gas-fired electric generation and environmental compliance plans, helping to provide competitive costs for WPL’s customers. Refer to “Results of Operations—Electric Margins—Purchased Electric Capacity Expense” for details of capacity payments from these PPAs and “Generation Plans” and “Environmental Compliance Plans” below for discussion of future capital expenditures.

Safe and Reliable Service—The strategic plan is intended to focus resources on providing safe and reliable electricity and natural gas service. Investments are expected to be targeted in system improvements, replacing aging infrastructure and distribution grid efficiency to maintain strong reliability. WPL monitors system performance and takes the necessary steps to continually improve the safety and reliability of its service for its customers. Providing exceptional customer service, including emergency and outage response, is part of WPL’s mission and commitment to the customers it serves.

Balanced Generation—WPL believes a balanced and flexible generation portfolio provides long-term advantages to its customers and its parent company, Alliant Energy. The strategic plan calls for a focus on reducing overall fuel costs and the volatility of those costs by reducing reliance on purchased power and generation produced by older and less-efficient coal-fired EGUs to meet the demands of its customers. The strategic plan includes purchasing a natural gas-fired electric generating facility and possibly retiring certain older and less-efficient coal-fired generating facilities. Additional details of changes to WPL’s generation portfolio are included in “Generation Plans” below. The strategic plan also includes investments in performance and reliability upgrades, which are discussed in “Generation Performance Improvement Projects” below. In addition, the strategic plan includes new emission controls at WPL’s most-efficient coal-fired EGUs to continue producing affordable energy for customers and to benefit the environment, which are included in “Environmental Compliance Plans” below. Lastly, WPL currently purchases electricity from Kewaunee under a long-term PPA set to expire in late 2013. Refer to “Nuclear Generation PPA” below for discussion of the future of this PPA. WPL believes a diversified fuel mix for EGUs is important to meeting the needs of its customers, its parent company and the environment while preparing for a potentially carbon-constrained environment in the future.

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Generation Plans—WPL reviews and updates, as deemed necessary and in accordance with regulatory requirements, its generation plans. WPL is currently evaluating the types of capacity additions it will pursue to meet its customers’ long-term energy needs and is monitoring several related external factors that will influence those evaluations. Some of these external factors include regulatory decisions regarding proposed projects, changes in long-term projections of customer demand, availability and cost effectiveness of different generation technologies, forward market prices for fossil fuels, market conditions for obtaining financing, developments related to federal and state renewable portfolio standards, environmental requirements, such as any future requirements relating to GHG emissions or renewable energy sources, and federal and state tax incentives.

New Generation Project—WPL’s current new generation project is as follows (dollars in millions):

Primary Generation Type	Project Name / Location	Capacity (MW)	Expected Availability Date	Cost Estimate (a)	Expected Regulatory Decision Date
Natural gas	Riverside/Beloit, WI	600	Q4 2012	$390 - $395	April 2012

(a) Cost estimate represents WPL’s estimated portion of the total escalated construction and acquisition expenditures and excludes allowance for funds used during construction (AFUDC), if applicable.

Natural Gas-Fired Generation Project—

Potential Purchase of a Natural Gas-Fired Electric Generating Facility—WPL has a PPA with a subsidiary of Calpine Corporation related to Riverside, a 600 MW natural gas-fired electric generating facility in Beloit, Wisconsin, that extends through May 2013. For planning purposes, WPL currently anticipates it will acquire Riverside to replace the 490 MW of electricity output currently obtained from the Riverside PPA to meet the demand of its customers. In November 2011, WPL filed a CA with the PSCW for the purchase of Riverside in the fourth quarter of 2012. A decision from the PSCW is expected in April 2012.

Wind Generation Project—

Wind Site in Freeborn County, Minnesota—In 2009, WPL acquired approximately 400 MW of wind site capacity in Freeborn County, Minnesota. The initial 200 MW of the wind site was utilized to construct the Bent Tree—Phase I wind project, which began generating electricity in 2010. Future development of the balance of the wind site will depend on numerous factors such as renewable portfolio standards, environmental requirements, electricity and fossil fuel prices, technology advancements and transmission capabilities.

Bent Tree—Phase I Wind Project—In 2009, Wisconsin Industrial Energy Group, Inc. (WIEG) and Citizens Utility Board (CUB) filed a Petition for Review with the Circuit Court of Dane County, Wisconsin (Dane County Circuit Court) seeking judicial review of: (1) the PSCW’s 2008 interim order that determined WPL’s application for the Bent Tree—Phase I wind project must be reviewed under the CA statute and not the Certificate of Public Convenience and Necessity statute; and (2) the PSCW’s 2009 final order that granted WPL a CA to construct the Bent Tree—Phase I wind project. In 2009, the PSCW filed a motion to dismiss the petition, which was subsequently denied. In 2010, WIEG’s and CUB’s Petition for Review was denied by the Dane County Circuit Court. WIEG and CUB appealed the Dane County Circuit Court’s decision to the Wisconsin Appellate Court. In November 2011, the Wisconsin Appellate Court requested that the Wisconsin Supreme Court review and decide the case. The Wisconsin Supreme Court accepted the case and set a briefing schedule. In January 2012, WIEG and CUB filed a joint initial brief, and in February 2012, WPL filed its response brief. The Wisconsin Supreme Court scheduled oral arguments for April 2012.

Refer to Note 1(e) of the “Notes to Consolidated Financial Statements” for discussion of the additional wind site expected to be used by WPL to develop future wind projects.

Coal-Fired Generation Project—

Edgewater Unit 5—In March 2011, WPL purchased WEPCO’s 25% ownership interest (approximately 95 MW of generating capacity) in Edgewater Unit 5 for $38 million. Refer to Note 1(e) of the “Notes to Consolidated Financial Statements” for additional details of WPL’s Edgewater Unit 5 purchase.

WPL also continues to evaluate the potential retirement of other older and less-efficient EGUs within its generation fleet.

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Generation Performance Improvement Projects—WPL’s strategic plan includes investments in performance and reliability improvements at its most-efficient coal-fired EGUs. The generation performance improvement projects are currently planned for Edgewater Unit 5 and Columbia Units 1 and 2. Refer to “Liquidity and Capital Resources—Construction and Acquisition Expenditures” for details regarding the capital expenditures in 2012 through 2015 currently anticipated for these generation performance improvement projects.

Nuclear Generation PPA—

Kewaunee—WPL currently believes it is unlikely that it will enter into any long-term agreement with Dominion Resources, Inc. for the purchase of electricity generated by Kewaunee beyond the current Kewaunee PPA term, which extends through December 2013.

Environmental Compliance Plans—WPL has developed environmental compliance plans to help ensure cost effective compliance with current and proposed environmental laws and regulations. WPL expects these environmental laws and regulations will require significant reductions of future emissions of NOx, SO2, particulate matter (PM), mercury and other HAPs at its generating facilities. WPL reviews and updates, as deemed necessary and in accordance with regulatory requirements, its environmental compliance plans to address various external factors. Some of these external factors include regulatory decisions regarding proposed emission control projects, developments related to environmental regulations, outcomes of legal proceedings, availability and cost effectiveness of different emission reduction technologies, market prices for electricity and fossil fuels, market prices for emission allowances, market conditions for obtaining financings, and federal and state tax incentives. Refer to “Environmental Matters” for details of certain current and proposed environmental regulations, including regulations for which these plans are expected to support compliance obligations. The following provides current estimates of capital expenditures planned for 2012 through 2015 for emission control projects included in WPL’s current environmental compliance plans (in millions):

Generating Unit	Expected In-Service Date		Emissions Controlled	Technology (a)	2012		2013		2014		2015
Edgewater Unit 5		2013	NOx	SCR	$	55	$	10	$	—	$	—
Edgewater Unit 5		2017	SO2 & Mercury	Scrubber & Baghouse		—		—		15		85
Columbia Units 1 and 2		2014	SO2 & Mercury	Scrubber & Baghouse		110		140		20		—
Other			Various	Various		5		20		20		10
					$	170	$	170	$	55	$	95

(a) Selective Catalytic Reduction (SCR) is a post-combustion process that injects ammonia or urea into the stream of gases leaving the generating facility boiler to convert NOx emissions into nitrogen and water. The use of a catalyst enhances the effectiveness of the conversion enabling NOx emissions reductions of up to 90%.

Baghouse, including carbon injection, is a post-combustion process that injects carbon particles into the stream of gases leaving the generating facility boiler to facilitate the capture of mercury in filters or bags. This process can remove more than 85% of mercury emissions.

Scrubber is a post-combustion process that injects lime or lime slurry into the stream of gases leaving the generating facility boiler to remove SO2 and other acid gases (including hydrochloric acid) and capture them in a solid or liquid waste by-product. A scrubber typically removes more than 90% of the SO2 emissions regardless of generating facility boiler type or design.

These capital expenditure estimates represent WPL’s portion of the total escalated capital expenditures and exclude AFUDC, if applicable. Capital expenditure estimates are subject to change based on future changes to plant-specific costs of emission control technologies and environmental requirements. Refer to “Environmental Matters” for additional details regarding proposed environmental requirements that may impact environmental compliance plans.

Emission Control Projects—WPL must file a CA and receive authorization from the PSCW to proceed with any individual emission control project with estimated project costs of $8 million or more. In 2007, the PSCW approved the deferral of the retail portion of WPL’s incremental pre-certification and pre-construction costs for current or future emission control projects requiring PSCW approval, effective on the request date of November 2006. WPL currently anticipates that deferred costs as of Dec. 31, 2011 and thereafter will be recovered in future rates and therefore does not expect these costs to have an adverse impact on its financial condition or results of operations.

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Edgewater Unit 5—In May 2010, WPL received an order from the PSCW authorizing the installation of an SCR system at Edgewater Unit 5 to reduce NOx emissions at the facility. Construction began in the third quarter of 2010. The SCR system at Edgewater Unit 5 is expected to support compliance obligations for current and anticipated air quality regulatory requirements, including CAIR, CSAPR or some alternative to these rules that may be implemented, and the Wisconsin Reasonably Available Control Technology (RACT) Rule. WPL’s capital expenditures, excluding AFUDC, for the SCR system are currently estimated to be approximately $145 million, a portion of which is included in the above estimates for WPL’s environmental compliance plans. Refer to Note 1(e) of the “Notes to Consolidated Financial Statements” for further discussion of the Edgewater Unit 5 SCR system emission control project.

In addition, WPL’s current environmental compliance plans include installing a scrubber and baghouse at Edgewater Unit 5 to reduce SO2 and mercury emissions at the generating facility. The scrubber and baghouse at Edgewater Unit 5 are expected to support compliance obligations for current and anticipated air quality regulatory requirements, including CAIR, CSAPR or some alternative to these rules that may be implemented, the Utility MACT Rule and the Wisconsin State Mercury Rule. WPL currently plans to file a CA application with the PSCW for the projects in 2012. A portion of WPL’s capital expenditures, excluding AFUDC, for the scrubber and baghouse are included in the above estimates for WPL’s environmental compliance plans. An estimate of WPL’s total capital expenditures, excluding AFUDC, for the projects will be available upon filing the CA application.

Columbia Units 1 and 2—In February 2011, WPL received approval from the PSCW to install scrubbers and baghouses at Columbia Units 1 and 2 to reduce SO2 and mercury emissions at the generating facility. The scrubbers and baghouses at Columbia Units 1 and 2 are expected to support compliance obligations for current and anticipated air quality regulatory requirements, including CAIR, CSAPR or some alternative to these rules that may be implemented, the Utility MACT Rule and the Wisconsin State Mercury Rule. WPL’s portion of the capital expenditures, excluding AFUDC, for the scrubbers and baghouses is currently estimated to be between $280 million and $310 million, a portion of which is included in the above estimates for WPL’s environmental compliance plans.

Other—WPL’s current environmental compliance plans also include planned expenditures during 2012 through 2015 for lower-cost emission control options for certain of its electric generating facilities. The environmental compliance plan for these lower-cost emission control options is subject to change pending further clarity on anticipated air quality regulatory requirements including final requirements under the final Utility MACT Rule, CAIR, CSAPR or some alternative to these rules.

Energy Efficiency Programs—WPL has several energy efficiency programs and initiatives that help customers reduce their energy usage and related costs through the use of new energy efficient equipment, products and practices. The following are WPL’s current key energy efficiency programs:

Smart Grid Initiatives—Smart Grid initiatives are designed to improve customer service, enhance energy management and conservation and provide operational savings through increased efficiencies of electric distribution systems. Advanced metering infrastructure (AMI) is expected to be the foundation for the Smart Grid in WPL’s service territory. WPL has substantially completed its AMI deployment by installing over 641,000 AMI electric meters and gas modules in its service territory as of Dec. 31, 2011. WPL anticipates its total capital expenditures for AMI will be approximately $111 million upon completion of the deployment. There is approximately $3 million of planned AMI investment remaining to be made for system and network enhancements at WPL through 2012.

Focus on Energy Program—In 2011 and 2010, WPL contributed 1.5% and 1.2%, respectively, of annual retail utility revenues to help fund Focus on Energy, Wisconsin’s statewide energy efficiency and renewable energy resource program. Refer to “Legislative Matters” for discussion of changes to WPL’s anticipated contributions to this program.

Shared Savings Programs—WPL offers energy efficiency programs to certain customers referred to as Shared Savings programs. These programs provide low-cost financing to help customers identify, purchase and install energy efficiency improvement projects. The customers repay WPL with monthly payments over a term up to five years. Refer to Note 4 of the “Notes to Consolidated Financial Statements” for additional details of shared savings programs.

RATE MATTERS

Overview—WPL is subject to federal regulation by FERC, which has jurisdiction over wholesale electric rates and certain natural gas facilities, and state regulation in Wisconsin for retail utility rates and standards of service. Such regulatory oversight also covers WPL’s plans for construction and financing of new generation facilities and related activities.

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Recent Retail Base Rate Filings—Details of WPL’s recent retail base rate cases impacting its historical and future results of operations are as follows (dollars in millions; Electric (E); Gas (G)):

Retail Base Rate Cases	Utility Type	Filing Date	Final Increase Granted (a)	Final Effective Date
2011 Test Year	E	Apr-10	$8	Jan-11
2010 Test Year	E/G	May-09	E-59; G-6	Jan-10

(a) Base rate increases reflect both returns on additions to WPL’s infrastructure and a recovery of changes in costs incurred or expected to be incurred by WPL. Given a portion of the rate increases will offset changes in costs, revenues from rate increases should not be expected to result in an equal increase in income.

Retail Electric Rate Case (2011 Test Year)—In April 2010, WPL filed a request with the PSCW to reopen the rate order for its 2010 test year to increase annual retail electric rates for 2011 by $35 million, or approximately 4%. The request was based on a forward-looking test period that included 2011. The key drivers for the filing included recovery of investments in WPL’s Bent Tree—Phase I wind project and expiring deferral credits, partially offset by lower variable fuel expenses. In August 2010, WPL revised its request for an annual retail electric rate increase to $19 million, or approximately 2%. The primary differences between WPL’s original request in April 2010 and its revised request filed in August 2010 relate to reduced variable fuel expenses, increased wind generation production tax credits and the impact of the $9 million annual rate increase implemented in June 2010 with the interim order in WPL’s 2010 test year retail fuel-related rate filing, which is discussed below.

In December 2010, WPL received an order from the PSCW authorizing an annual retail electric rate increase of $8 million, or approximately 1%, effective Jan. 1, 2011. The annual retail electric rate increase of $8 million reflects a $38 million increase in the non-fuel component of rates and a $30 million decrease in the fuel component of rates. This $8 million increase in annual rates effective Jan. 1, 2011, combined with the termination of the $9 million interim fuel-related rate increase effective Dec. 31, 2010, resulted in a net $1 million decrease in annual retail electric rates charged to customers effective January 2011. Refer to “Retail Fuel-related Rate Filings—2010 Test Year” below for additional details of the interim fuel-related rate increase implemented in 2010 and a reduction to the 2011 test year base rate increase for refunds owed to retail electric customers related to interim fuel cost collections in 2010.

Retail Rate Case (2010 Test Year)—In May 2009, WPL filed a request with the PSCW to increase annual retail electric rates by $86 million, or approximately 9%, and increase annual retail natural gas rates by $6 million, or approximately 3%. The request was based on a 2010 forward-looking test year. The key drivers for the filing included recovery of infrastructure costs of the electric and natural gas utility systems, which had been impacted by a material reduction in sales and increased costs. In addition, WPL requested recovery of the remaining retail portion of the deferred costs for its cancelled 300 MW coal-fired electric generating facility project, Nelson Dewey #3. In September 2009, WPL revised its request to an annual electric retail rate increase of $99 million and annual retail natural gas rate increase of $8 million. The increase in the requested amount for the retail electric rates was primarily due to increased infrastructure costs and a reduced 2010 sales forecast.

In December 2009, WPL received an order from the PSCW authorizing an annual retail electric rate increase of $59 million, or approximately 6%, and an annual retail natural gas rate increase of $6 million, or approximately 2%, effective Jan. 1, 2010. The annual retail electric rate increase of $59 million reflects an increase in the non-fuel component of rates and a decrease in the fuel component of rates. The December 2009 order from the PSCW also approved recovery of certain deferred benefits costs incurred by WPL in 2009 and a portion of the previously deferred costs for the cancelled Nelson Dewey #3 project. Refer to Note 1(b) of the “Notes to Consolidated Financial Statements” for further discussion of the PSCW’s decision regarding recovery of these deferred costs and regulatory-related charges in 2009 for the portion of the cancelled Nelson Dewey #3 costs that WPL was denied recovery.

The 2010 test year retail electric rate increase approved by the PSCW included an amount that represented a current return on 50% of the estimated construction work in progress (CWIP) for WPL’s Bent Tree—Phase I wind project for 2010. The remaining CWIP balance for the Bent Tree—Phase I wind project accrued AFUDC during 2010. In addition, the PSCW authorized WPL to defer the retail portion of return on rate base, depreciation expense and other operation and maintenance expenses for those portions of the Bent Tree—Phase I wind project placed in service in 2010.

Planned Utility Rate Case in 2012—

Retail Electric and Gas Rate Case (2013/2014 Test Period)—WPL currently expects to make a retail rate filing in the first half of 2012 based on a forward-looking test period that includes 2013 and 2014. The form and magnitude of such filing is

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currently being analyzed and could range from a future test year 2013 electric fuel plan to a full rate case for the 2013 and 2014 test period. The key drivers for the anticipated filing include recovery of the emission control project at Edgewater Unit 5, partial recovery for the emission control projects at Columbia Units 1 and 2, and changes in fuel costs. Any rate changes granted are expected to be effective in early 2013.

Retail Fuel-related Rate Filings—

2012 Test Year—In May 2011, WPL filed a request with the PSCW to increase annual retail electric rates by $13 million, or approximately 1%, to recover anticipated increases in retail electric production fuel and energy purchases (fuel-related costs) in 2012 due to higher purchased power energy costs and emission compliance costs. In July 2011, the EPA issued CSAPR, which was expected to require SO2 and NOx emissions reductions from WPL’s fossil-fueled EGUs with greater than 25 MW of capacity beginning in 2012. After evaluating CSAPR, in November 2011, WPL revised its request for an annual retail electric rate increase to $31 million, or approximately 3%, to reflect higher anticipated emission compliance costs. In December 2011, WPL received an order from the PSCW authorizing an annual retail electric rate increase of $4 million related to expected changes in retail fuel-related costs. The December 2011 order also required WPL to defer direct CSAPR compliance costs that are not included in the fuel monitoring level and set a zero percent tolerance band for the CSAPR-related deferral. The 2012 fuel costs, excluding deferred CSAPR compliance costs, will be monitored using an annual bandwidth of plus or minus 2%. The rate change granted from this request was effective Jan. 1, 2012. Subsequent to the PSCW order issued in December 2011, the D.C. Circuit Court stayed the implementation of CSAPR and as a result CAIR obligations remain effective pending further review by the D.C. Circuit Court and the EPA. WPL is currently unable to predict the final outcome of the CSAPR stay and the impact on its financial condition or results of operations.

2010 Test Year—In April 2010, WPL filed a request with the PSCW to increase annual retail electric rates by $9 million to recover anticipated increased fuel-related costs in 2010. Actual fuel-related costs through March 2010, combined with projections of continued higher fuel-related costs for the remainder of 2010, significantly exceeded the amounts being recovered in retail electric rates at the time of the filing. WPL received approval from the PSCW to implement an interim rate increase of $9 million, on an annual basis, effective in June 2010. Updated annual 2010 fuel-related costs during the proceeding resulted in WPL no longer qualifying for a fuel-related rate increase for 2010. In December 2010, the PSCW issued an order authorizing no increase in retail electric rates in 2010 related to fuel-related costs and required the interim rate increase to terminate at the end of 2010. The order also required WPL to refund to its retail electric customers the interim fuel rates collected in 2010 as a reduction to the 2011 test year base rate increase. As of Dec. 31, 2011, WPL’s remaining reserves were $1 million, including interest, for interim fuel cost collections in 2010.

2009 Test Year—In August 2009, WPL notified the PSCW that its actual retail fuel-related costs incurred during the month of July 2009 were below the monthly monitoring range of plus or minus 8% and projected annual retail fuel-related costs for 2009 could fall outside the annual monitoring range of plus or minus 2%. In September 2009, the PSCW issued an order that set WPL’s retail electric fuel rates currently in effect subject to refund beginning Sep. 1, 2009. In January 2010, WPL filed a retail electric fuel refund report indicating retail fuel over collections of $4 million for the period from Sep. 1, 2009 through Dec. 31, 2009. In April 2010, WPL received approval from the PSCW to refund $4 million to its retail electric customers for retail fuel over collections for the period from Sep. 1, 2009 through Dec. 31, 2009. WPL refunded the $4 million to its retail electric customers in 2010.

Rule Changes—

Electric Fuel Cost Recovery Rule Changes in Wisconsin—In 2010, Act 403 was enacted in Wisconsin to change statutes related to the process by which utilities recover electric fuel-related costs from their retail electric customers. On Jan. 1, 2011, revised new fuel rules issued by the PSCW became effective. The new fuel rules currently provide the following provisions and requirements for Wisconsin utilities:

• PSCW approval of a future test year fuel cost plan resulting in changes in rates either as a separate proceeding or in a base rate case proceeding;

• deferral of any change in unit fuel costs from the approved fuel cost plan outside a range established by the PSCW;

• inclusion of selected other variable costs and revenues directly related to fuel costs in the fuel cost plan;

• reporting after completion of the plan year for comparison of actual plan year costs to those included in the fuel cost plan; and

• restrictions on the collection of deferred amounts if Wisconsin utilities earn in excess of their authorized return on common equity.

Refer to Note 1(h) of the “Notes to Consolidated Financial Statements” for additional details of WPL’s retail electric fuel-related cost recovery mechanism.

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Wholesale Formula Rate Structure—In 2009, WPL filed a request with FERC seeking approval of changes to WPL’s wholesale formula rates in order to implement for billing purposes the full impact of accounting for defined benefit pension and other postretirement benefits plans. In 2010, FERC approved a settlement agreement between WPL and the wholesale customers regarding the formula rate change. WPL recorded an additional $4 million of electric revenues and regulatory assets in 2010 to reflect the settlement and reduced the regulatory asset concurrently with collections from customers through June 2011.

Rate Case Details—Details of the most recent rate orders in WPL’s key jurisdictions were as follows (Common Equity (CE); Preferred Equity (PE); Long-term Debt (LD); Short-term Debt (SD); Weighted-average Cost of Capital (WACC)):

	Test Period			Authorized Return on Common Equity (a)	Capital Structure				After-tax WACC			Average Rate Base (in millions)
Jurisdictions					CE	PE	LD	SD
Retail (PSCW):
Electric		2011	(b)	10.40%	50.4%	2.4%	43.3%	3.9%		8.18	%(c)	$	1,697	(d)
Gas		2011	(b)	10.40%	50.4%	2.4%	43.3%	3.9%		8.18	%(c)		215	(d)
Wholesale electric (FERC) (e)		2011		10.90%	55.0%	N/A	45.0%	N/A		8.84	%		175

(a) Authorized returns on common equity may not be indicative of actual returns earned or projections of future returns.

(b) WPL’s 2011 rate order did not change the returns or capital structures approved in the prior rate order effective Jan. 1, 2010.

(c) WPL’s retail return on net investment rate base is an adjusted WACC that includes adjustments for CWIP in rate base and a cash working capital allowance. The most recently authorized return on net investment rate base for WPL retail electric and gas utility service is 9.81% and 8.84%, respectively.

(d) Average rate base amounts do not include CWIP or a cash working capital allowance. The PSCW provides a return on selected CWIP and a cash working capital allowance by adjusting the percentage return on rate base.

(e) WPL’s wholesale formula rates reflect annual changes in WACC and rate base.

Other—

Economic Development Program—In June 2010, the PSCW issued an order approving an economic development program effective July 2010, which is intended to attract and retain industrial customers in WPL’s service territory. The program permits WPL to provide eligible industrial customers a discounted energy rate based upon specifically-defined conditions. To be eligible for the program, each customer needs to demonstrate that it is also eligible for direct governmental assistance through a local, state or federal economic development program, in addition to other criteria. The discount amounts are limited to ensure recovery of marginal costs and will be decreased over time until a customer is paying the full tariff rate. In July 2010, CUB filed a petition for review with the Dane County Circuit Court. CUB requested that the order be set aside, reversed or remanded to the PSCW for further deliberation and action. In February 2011, CUB’s petition for review was denied by the Dane County Circuit Court. No party filed a Notice for Appeal, and the time for appeal has expired. Currently, there are three WPL customers utilizing the economic development program.

Service Agreement—Pursuant to a service agreement, WPL receives various administrative and general services from Corporate Services. These services are billed to WPL at cost based on expenses incurred by Corporate Services for the benefit of WPL. These costs consisted primarily of employee compensation, benefits and fees associated with various professional services. In December 2011, the PSCW approved a revised service agreement between Corporate Services and WPL. This revised agreement is subject to additional regulatory approvals prior to being effective. The revised service agreement is currently expected to be effective in 2012.

FERC Audit—As part of routine procedures, in the fourth quarter of 2011, FERC commenced an audit of Alliant Energy, including its centralized service company (Corporate Services) and other affiliated companies. A final report is expected to be issued by FERC in late 2012 or early 2013. WPL does not believe that the final report will have any impact on its financial condition or results of operations.

ENVIRONMENTAL MATTERS

Overview—WPL is subject to regulation of environmental matters by federal, state and local authorities as a result of its current and past operations. WPL monitors these environmental matters and addresses them with emission abatement programs. These programs are subject to continuing review and are periodically revised due to various factors, including changes in environmental regulations, litigation of environmental requirements, construction plans and compliance costs.

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There is currently significant regulatory uncertainty with respect to the various environmental rules and regulations discussed below. Given the dynamic nature of environmental regulations and other related regulatory requirements, WPL has established an integrated planning process that is used for environmental compliance for its operations. WPL anticipates future expenditures for environmental compliance will be material, including significant capital investments. WPL anticipates that prudent expenditures incurred to comply with environmental requirements likely would be recovered in rates from its customers. Refer to “Strategic Overview—Environmental Compliance Plans” for details of WPL’s environmental compliance plans, including estimated capital expenditures. The following are major environmental matters that could potentially have a significant impact on WPL’s financial condition and results of operations.

Air Quality—The Clean Air Act (CAA) and its amendments mandate preservation of air quality through existing regulations and periodic reviews to ensure adequacy of these provisions based on scientific data. As part of the basic framework under the CAA, the EPA is required to establish National Ambient Air Quality Standards (NAAQS), which serve to protect public health and welfare. These standards address six “criteria” pollutants, four of which (NOx, SO2, PM, and ozone) are particularly relevant to WPL’s electric utility operations. Ozone is not directly emitted from WPL’s generating facilities; however, NOx emissions may contribute to its formation in the atmosphere. Fine particulate matter (PM2.5) may also be formed in the atmosphere from SO2 and NOx emissions.

State implementation plans (SIPs) document the collection of regulations that individual state agencies will apply to maintain NAAQS and related CAA requirements. The EPA must approve each SIP and if a SIP is not acceptable to the EPA or if a state chooses not to issue separate state rules, then the EPA can assume enforcement of the CAA in that state by issuing a federal implementation plan (FIP). Areas that comply with NAAQS are considered to be in attainment, whereas routinely monitored locations that do not comply with these standards may be classified by the EPA as non-attainment and require further actions to reduce emissions. Additional emissions standards may also be applied under the CAA regulatory framework beyond NAAQS. The specific federal and state air quality regulations that may affect WPL’s operations include: CAIR, CSAPR (formerly known as CATR), Clean Air Visibility Rule (CAVR), Utility MACT Rule, Wisconsin State Mercury Rule, Wisconsin RACT Rule, Industrial Boiler and Process Heater MACT Rule and various NAAQS rules. WPL also monitors various other potential environmental matters related to air quality, including: litigation of various federal rules issued under the CAA statutory authority; revisions to the New Source Review/PSD permitting programs and New Source Performance Standards (NSPS); and proposed legislation or other regulatory actions to regulate the emission of GHG. Refer to the sections below the following tables for detailed discussion of the following air quality regulations.

Environmental Regulation	Emissions Regulated	Primary Facilities Potentially Affected	Actual/Anticipated Compliance Deadline
CAIR	SO2, NOx	Fossil-fueled EGUs over 25 MW capacity	Phase I - NOx (2009); SO2 (2010) Phase II - 2015
CSAPR	SO2, NOx	Fossil-fueled EGUs over 25 MW capacity	To Be Determined (TBD)
CAVR	SO2, NOx, PM	Fossil-fueled EGUs built between 1962 and 1977	TBD
Utility MACT Rule	Mercury and other HAPs	Coal-fueled EGUs over 25 MW capacity	2015
Wisconsin State Mercury Rule	Mercury	Coal-fueled EGUs over 25 MW capacity	Phase I - 2010 Phase II - 2015
Wisconsin RACT Rule	NOx	Edgewater Units 3-5	Phase I - 2009 Phase II - 2013
Industrial Boiler and Process Heater MACT Rule	Mercury and other HAPs	Fossil-fueled auxiliary boilers and process heaters	2014
Ozone NAAQS Rule	NOx	Fossil-fueled EGUs in designated non-attainment areas	TBD
Fine Particle NAAQS Rule	SO2, NOx, PM	Fossil-fueled EGUs in designated non-attainment areas	TBD
NO2 NAAQS Rule	NO2	Fossil-fueled EGUs in designated non-attainment areas	TBD
SO2 NAAQS Rule	SO2	Fossil-fueled EGUs in designated non-attainment areas	2017

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The following table lists the fossil-fueled EGUs by primary fuel type that WPL currently owns or operates with greater than 25 MW of nameplate capacity, all of which are located in Wisconsin.

Coal	Natural Gas
Columbia 1-2	Sheboygan Falls 1-2
Edgewater 3-5	Neenah 1-2
Nelson Dewey 1-2	South Fond du Lac 1-4 Rock River 3,5-6 Sheepskin 1

CAIR—CAIR established new SO2 and NOx (both annual and ozone season) emission caps beginning in 2010 and 2009, respectively, with further reductions in SO2 and NOx emission caps planned to be effective in 2015. CAIR impacts WPL’s fossil-fueled EGUs with greater than 25 MW of capacity. CAIR includes a large regional cap-and-trade system, where compliance may be achieved by either adding emission controls and/or purchasing emission allowances. In 2008, the D.C. Circuit Court remanded CAIR to the EPA for revision to address flaws identified in a 2008 opinion issued in response to legal challenges to this rule. In the interim, CAIR obligations became effective for NOx on Jan. 1, 2009 and SO2 on Jan. 1, 2010 and remain in place until a final CAIR replacement rule becomes effective.

CSAPR—In July 2011, the EPA issued CSAPR (formerly known as CATR), which includes requirements to reduce SO2 and NOx emissions from fossil-fueled EGUs located in 27 states in the eastern half of the U.S. WPL’s fossil-fueled EGUs with greater than 25 MW of capacity would be impacted by CSAPR requirements. CSAPR was expected to replace CAIR and establish state emission caps for SO2 and NOx beginning in 2012 (Phase I). These SO2 and NOx emission caps were expected to be lowered further by CSAPR in 2014 (Phase II). CSAPR also includes assurance provisions that would enforce state emission caps. These provisions require regulated EGUs with emissions in excess of the state emission caps to surrender additional penalty emission allowances beginning in 2012. The provisions required to surrender potential additional emission allowances were expected to limit the amount of emissions trading that would be used to meet compliance requirements. The emission allowances used for Acid Rain and CAIR program compliance cannot be used for compliance with CSAPR, and CSAPR emission allowances are not eligible to be used for compliance requirements under Acid Rain regulations and CAIR.

In December 2011, the EPA also issued a final supplemental rule that added Wisconsin to CSAPR for the ozone season NOx emissions trading program. In February 2012, the EPA issued additional revisions to CSAPR to correct the calculation of emission budgets in certain states, including an increase of the allowed 2014 annual SO2 budget and 2012 and 2014 annual NOx budgets for Wisconsin. These revisions would delay the effective date of the assurance provisions of CSAPR to 2014, rather than 2012. The EPA is proceeding with final issuance of these revisions in order to implement the changes as part of CSAPR, if the stay discussed below is removed.

In December 2011, the D.C. Circuit Court stayed the implementation of CSAPR and as a result CAIR obligations remain effective pending further review by the D.C. Circuit Court and the EPA. WPL is currently unable to predict with certainty the final outcome of the CSAPR stay and the impact on its financial condition or results of operations. WPL currently believes that CAIR will be replaced in the future, either by CSAPR, as currently written, or as modified based upon a ruling from the D.C. Circuit Court, or another rule that addresses the interstate transport of air pollutants, and expects that capital investments and/or modifications to its electric generating facilities to meet the final compliance requirements will be significant.

CAVR—CAVR requires states to develop and implement SIPs to address visibility impairment in designated national parks and wilderness areas across the country with a national goal of no impairment by 2064. A proposed CAVR SIP for Wisconsin has been submitted to the EPA for review and approval. This SIP includes Best Available Retrofit Technology Rule (BART) emission controls and other additional measures needed for reducing state contributions to regional haze. The EPA has not issued final action to approve this CAVR SIP. If a CAVR SIP is found to be deficient, then the EPA is required to promulgate a CAVR FIP to address these requirements in the interim until the CAVR SIP is approved. The CAVR SIP will determine required compliance actions and deadlines. In August 2011, a legal challenge was filed by several groups citing the EPA’s failure to issue timely approval of CAVR SIP submissions or alternatively issue CAVR FIPs. In December 2011, the EPA published a proposed consent decree in response to the legal challenge, which would require the EPA to finalize CAVR plans for Wisconsin by June 2012.

As a result of the lawsuit, there are uncertainties in the applicability of and compliance outcomes of BART control approaches that will be approved by the EPA for inclusion in CAVR SIPs. EGU emissions of primary concern for BART

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and regional haze regulation include SO2, NOx and PM. There are pending obligations under the EPA’s CAVR to complete BART determinations that would evaluate control options to reduce these emissions at certain fossil-fueled WPL EGUs that were under construction between 1962 and 1977. WPL’s facilities that may be impacted include Edgewater Unit 4, Nelson Dewey Unit 2 and Columbia Units 1 and 2. The D.C. Circuit Court remand of CAIR to the EPA in 2008 and stay of CSAPR in 2011 may have an indirect impact on the CAVR and BART SIP implementation approach. The EPA allowed BART obligations for SO2 and NOx emissions to be fulfilled by CAIR (often referred to as “CAIR equals BART”). In addition, in December 2011, the EPA issued a proposed rule that similarly would allow BART obligations for SO2 and NOx emission to be fulfilled by CSAPR. The EPA’s assessment of the relationship for the CAVR’s BART requirements relative to CAIR and CSAPR remains uncertain pending the D.C. Circuit Court’s review of these regulations. In addition, there are uncertainties whether additional emission reductions could be required to address regional haze impacts beyond BART. WPL is unable to predict with certainty the impact that CAVR might have on the operations of its existing EGUs until the EPA finalizes CAVR plans for Wisconsin.

Utility MACT Rule—In December 2011, the EPA issued the final Utility MACT Rule, also referred to as MATS. The MATS rule applies to all WPL coal-fueled EGUs with greater than 25 MW of capacity. The final rule requires compliance with emission limits for mercury, filterable PM as a substitute for non-mercury metal HAPs and hydrogen chloride (HCl) as a substitute for acid gas HAPs. The EPA also proposed alternative standards for total or individual non-mercury metals emissions (instead of filterable PM) and SO2 emissions (instead of HCl for acid gases if a scrubber is installed). In addition, work practice standards were proposed for organic HAPs emissions to ensure proper combustion. Compliance is currently anticipated to be required by April 2015. However, an entity can request an additional year for compliance, which may be granted on a case-by-case basis by state permitting authorities for units that are needed to assure power reliability, units repowering to gas, or units that need additional time to install air emission control technology. In addition, the issuance of the final Utility MACT Rule is expected to initiate a review of, and possible revisions to, the Wisconsin State Mercury Rule. The final Utility MACT Rule is subject to legal challenge in the D.C. Circuit Court. WPL is currently evaluating the final Utility MACT Rule, but expects that capital investments and/or modifications to its electric generating facilities could be significant to comply with the regulation.

Wisconsin State Mercury Rule—The Wisconsin State Mercury Rule requires electric utility companies in Wisconsin to meet compliance requirements to reduce annual mercury emissions by 40% from a historic baseline beginning in 2010 (Phase I). In addition, the Wisconsin State Mercury Rule requires large coal-fueled EGUs with greater than 150 MW of capacity to either achieve a 90% annual mercury emissions reduction standard or limit the annual concentration of mercury emissions to 0.008 pounds of mercury per gigawatt-hour beginning in 2015 (Phase II). Small coal-fueled EGUs between 25 MW and 150 MW of capacity must install Best Available Control Technology (BACT) by January 2015 to reduce mercury emissions. As an alternative, this rule allows large and small EGUs to achieve compliance through averaging of covered emissions. There is also an alternative multi-pollutant option that extends the time for compliance with the annual mercury reduction requirement until 2021 for large units. However, this requires the affected facilities to achieve NOx and SO2 reductions beyond those currently required by federal and state regulations. In 2010, WPL filed its compliance plan with the Wisconsin Department of Natural Resources (DNR). WPL’s plan states that it will utilize large and small EGU averaging to comply with the additional mercury rule emissions reduction requirements that commence in 2015 and not use the multi-pollutant option. The issuance of the final Utility MACT Rule is expected to initiate a review of, and may cause revisions to, the Wisconsin State Mercury Rule. WPL continues to evaluate the impact of this state mercury rule and the federal Utility MACT Rule discussed above to determine further mercury emission reductions that will be required.

Wisconsin RACT Rule—In 2004, the EPA designated 10 counties in Southeastern Wisconsin as non-attainment areas for the ozone NAAQS. This designation includes Sheboygan County, where WPL operates the Sheboygan Falls Energy Facility and Edgewater. In 2007, the Wisconsin DNR issued a RACT Rule that requires NOx emission reductions at EGUs as part of the federal ozone SIP submittal to address non-attainment areas in Wisconsin. Facility modifications are not necessary at the Sheboygan Falls Energy Facility to comply with this rule. As part of its environmental compliance plan, WPL completed investments for installation of NOx emission control technologies at Edgewater to meet the 2009 to 2012 compliance requirements (Phase I). WPL is currently installing an SCR system at Edgewater to achieve compliance with the 2013 requirements that include facility boiler NOx rate limitations and a mass emissions cap (Phase II). Refer to “Strategic Overview—Environmental Compliance Plans—Emission Control Projects” for discussion of the SCR system being implemented for further NOx emission reductions at Edgewater to meet 2013 compliance deadlines.

Industrial Boiler and Process Heater MACT Rule—In March 2011, the EPA published the final Industrial Boiler and Process Heater MACT Rule with a compliance deadline of March 2014. The rule is expected to apply to fossil-fueled auxiliary boilers and process heaters operated at WPL’s fossil-fueled facilities. The rule requires compliance with HAPs emission limitations and work practice standards. In May 2011, the EPA published a stay postponing the effective date of the Industrial Boiler and Process Heater MACT Rule for major sources of emissions. In addition, the EPA announced

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reconsideration of the March 2011 final rule. In December 2011, the EPA issued a proposed reconsidered rule for public comment. In January 2012, the D.C. Circuit Court vacated the EPA’s stay and reinstated the compliance deadline of March 2014. The EPA currently expects to issue a final reconsidered rule by April 2012, with an expected compliance date of mid-2015. The final rule remains subject to legal challenges in the D.C. Circuit Court. WPL is monitoring future developments relating to this rule and plans to update its environmental compliance plans as needed. WPL is currently unable to predict with certainty the outcome of the Industrial Boiler and Process Heater MACT Rule, but expects that capital investments and/or modifications to its electric generating facilities to meet compliance requirements of the rule could be significant.

Ozone NAAQS Rule—In 2008, the EPA announced reductions in the primary NAAQS for eight-hour ozone to a level of 0.075 parts per million (ppm) from the previous standard of 0.08 ppm. In December 2011, the EPA responded to initial state recommendations and is proposing to designate Sheboygan County in Wisconsin as non-attainment. WPL operates the Sheboygan Falls Energy Facility and Edgewater in Sheboygan County, Wisconsin. The EPA is expected to designate final non-attainment areas by the second quarter of 2012. The schedule for compliance with this standard has not yet been established. WPL is currently unable to predict with certainty the impact of any potential ozone NAAQS changes on its financial condition and results of operations.

Fine Particle NAAQS Rule—The EPA lowered the 24-hour fine particle primary NAAQS (PM2.5 NAAQS) from 65 micrograms per cubic meter (ug/m3) to 35 ug/m3 in 2006. In 2009, the EPA announced final designation of PM2.5 non-attainment areas. WPL does not have any generating facilities in the non-attainment areas announced in 2009. However, in 2009, the D.C. Circuit Court issued a decision in litigation regarding the EPA’s determination not to lower the annual PM2.5 NAAQS in 2006. In accordance with the decision, the EPA must re-evaluate its justification for not tightening the annual standard related to adverse effects on health and visibility. If the annual PM2.5 standard becomes more stringent, it could require SO2 and NOx emission reductions in additional areas not currently designated as non-attainment. The schedule for compliance with this rule has not yet been established. WPL is currently unable to predict with certainty the potential impact of the re-evaluation of the annual PM2.5 NAAQS on its financial condition and results of operations.

Nitrogen Dioxide (NO2) NAAQS Rule—In 2010, the EPA issued a final rule to strengthen the primary NAAQS for NOx as measured by NO2. The final rule establishes a new one-hour NAAQS for NO2 of 100 parts per billion (ppb) and associated ambient air monitoring requirements, while maintaining the current annual standard of 53 ppb. In February 2012, the EPA issued a final response to state recommendations and is not proposing to designate any non-attainment areas in Wisconsin. The EPA is expected to re-evaluate these designations in 2016 based on expanded monitoring data. The schedule for compliance with this rule has not yet been established. WPL is currently unable to predict with certainty the impact of any potential NO2 NAAQS changes on its financial condition and results of operations.

SO2 NAAQS Rule—In 2010, the EPA issued a final rule that establishes a new one-hour NAAQS for SO2 at a level of 75 ppb. The final rule also revokes both the existing 24-hour and annual standards. The EPA is expected to designate non-attainment areas for the SO2 NAAQS by June 2012. Compliance with the new SO2 NAAQS rule is currently expected to be required by 2017 for non-attainment areas designated in 2012. WPL is currently unable to predict with certainty the impact of any potential SO2 NAAQS changes on its financial condition and results of operations.

Air Permit Renewal Challenges—WPL is aware of certain public comments or petitions from citizen groups that have been submitted to the Wisconsin DNR or to the EPA regarding the renewal of air operating permits at certain of WPL’s generating facilities. In some cases, the EPA has responded to these comments and petitions with orders to the Wisconsin DNR to reconsider the air operating permits of WPL’s generating facilities. WPL has received renewed air permits for Columbia, Edgewater and Nelson Dewey from the Wisconsin DNR, which considered all public comments received as part of the renewal process.

Columbia—In 2008, the Sierra Club submitted a notice of intent to sue the EPA for failure to respond to its petition encouraging the EPA to challenge the air permit issued by the Wisconsin DNR for Columbia. In 2009, the EPA issued an order on the Sierra Club petition and granted one of three issues from the Sierra Club petition, objecting to that portion of the permit issued by the Wisconsin DNR. In September 2010, the Wisconsin DNR proposed a construction permit and a revised operation permit for Columbia. In October 2010, WPL submitted comments objecting to the appropriateness of the proposed draft permits. In November 2010, the comment period closed, and in February 2011, the Wisconsin DNR made the determination not to issue either of the proposed new permits. In February 2011, the Sierra Club filed a lawsuit against the EPA in the U.S. District Court for the Western District of Wisconsin seeking to have the EPA take over the permit process. The Sierra Club alleges the EPA must now act on the reconsideration of the permit since the Wisconsin DNR has exceeded its 90-day timeframe in which to respond to the EPA’s order. In May 2011, the Wisconsin DNR proposed a revised draft operation permit for Columbia. In June 2011, WPL and the Sierra Club submitted comments objecting to the appropriateness of the revised draft operation permit. WPL believes the previously issued air permit for Columbia is still valid. WPL is

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currently unable to predict with certainty the outcome of this matter and the impact on its financial condition or results of operations.

Edgewater—In 2009, the Sierra Club petitioned the EPA to object to a proposed Title V air permit for Edgewater that the Wisconsin DNR had submitted to the EPA for review. In 2009, the Sierra Club filed a notice of intent to sue the EPA over its failure to act on the petition. In August 2010, the EPA issued an order to the Wisconsin DNR granting in part and denying in part the Sierra Club’s petition. The Wisconsin DNR has not yet acted on the EPA order. In December 2010, WPL received a copy of a notice of intent to sue by the Sierra Club against the EPA based on what the Sierra Club asserts is unreasonable delay in the EPA performing its duties related to the reconsideration of the Edgewater Title V air permit. Specifically, the Sierra Club alleges that because the Wisconsin DNR has exceeded its 90-day timeframe in which to respond to the EPA’s order, the EPA must now act on the reconsideration of the permit. WPL believes the previously issued air permit for Edgewater is still valid. WPL is currently unable to predict with certainty the outcome of this matter and the impact on its financial condition and results of operations.

Nelson Dewey—In September 2010, the Sierra Club petitioned the EPA and the Wisconsin DNR to reopen a Nelson Dewey air permit. The Sierra Club alleges that the Nelson Dewey air permit issued by the Wisconsin DNR in 2008 should be corrected because certain modifications were made at the facility without complying with the PSD program requirements. In November 2010, WPL filed a response to the petition with the EPA and the Wisconsin DNR objecting to its claims and supporting the Wisconsin DNR’s issuance of the current permit. No action on this petition has been taken by the EPA or the Wisconsin DNR. WPL believes the previously issued air permit for Nelson Dewey is still valid. WPL is currently unable to predict with certainty the outcome of this petition and the impact on its financial condition and results of operations.

Air Permitting Violation Claims—Refer to Note 13(b) of the “Notes to Consolidated Financial Statements” for discussion of complaints filed by the Sierra Club in 2010 and a notice of violation issued by the EPA in 2009 regarding alleged air permitting violations at Nelson Dewey, Columbia and Edgewater.

Water Quality—

Section 316(b) of Federal Clean Water Act—The Federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure that these structures reflect the “best technology available” for minimizing adverse environmental impacts to fish and other aquatic life. The second phase of this EPA rule is generally referred to as Section 316(b). Section 316(b) applies to existing cooling water intake structures at large steam EGUs. In 2007, a court opinion invalidated aspects of Section 316(b), which allowed for consideration of cost-effectiveness when determining the appropriate compliance measures. As a result, the EPA formally suspended Section 316(b) in 2007. In 2009, the U.S. Supreme Court granted the EPA authority to use a cost-benefit analysis when setting technology-based requirements under Section 316(b). In March 2011, the EPA issued a revised proposed Section 316(b) Rule, which applies to existing and new cooling water intake structures at large steam EGUs and manufacturing facilities. WPL has identified three (Columbia Units 1-2, Nelson Dewey Units 1-2 and Edgewater Units 3-5) electric generating facilities, which may be impacted by the revised Section 316(b) Rule. A final rule is expected to be issued by the EPA in 2012. The schedule for compliance with this rule has not yet been finalized; however, compliance is currently expected to be required within eight years of the effective date of the final rule. WPL is currently unable to predict with certainty the final requirements from the Section 316(b) Rule, but expects that capital investments and/or modifications resulting from the rule could be significant.

Wisconsin State Thermal Rule—Section 316(a) of the Federal Clean Water Act requires the EPA to regulate thermal impacts from wastewater discharges of industrial facilities, including those from EGUs. States have authority to establish standards for these discharges in order to minimize adverse environmental impacts to aquatic life. All WPL facilities are subject to these standards upon state promulgation, which become applicable upon their incorporation into a facility’s wastewater discharge permit. In January 2010, the Wisconsin Natural Resources Board adopted its state standard for regulating the amount of heat that facilities can discharge into Wisconsin waters. This rule was necessary because the EPA determined that Wisconsin had not developed a state thermal standard consistent with Section 316(a) of the Federal Clean Water Act. The Wisconsin State Thermal Rule was approved by the EPA in October 2010. Compliance with the thermal rule will be evaluated on a case-by-case basis when wastewater discharge permits for WPL’s generating facilities are renewed. WPL continues to evaluate the thermal rule regulatory requirements and the compliance options available to meet the heat limitations for discharges from its EGUs. WPL is unable to predict with certainty the final requirements of this rule until wastewater discharge permits for impacted facilities are renewed. If capital investments and/or modifications are required, WPL believes these investments could be significant.

Hydroelectric Fish Passages and Fish Protective Devices—In 2002, FERC issued an order requiring the following actions by WPL regarding its Prairie du Sac hydro plant: (1) develop a detailed engineering and biological evaluation of potential fish passages for the facility; (2) install an agency-approved fish-protective device at the facility; and (3) install an agency-

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approved fish passage at the facility. In 2009, WPL completed the installation of the agency-approved fish-protective device. WPL continues to work with the agencies to design and install the fish passage, which is currently required to be completed by Dec. 31, 2012. The U.S. Fish and Wildlife Service and the Wisconsin DNR have requested additional information to support the conceptual plan for the fish passage, and support extending the current required completion date to accomplish the additional work. WPL currently expects to request an additional extension from FERC in the first half of 2012. WPL believes the required capital investments and/or modifications to comply with the FERC order for the fish passage at its Prairie du Sac hydro plant could be significant.

Land and Solid Waste—

Coal Combustion Residuals (CCRs)—WPL is monitoring potential regulatory changes that may affect the rules for operation and maintenance of coal ash surface impoundments (ash ponds) and/or landfills, in the wake of a structural failure in the containment berm of a coal ash surface impoundment at a different utility. In 2009, WPL responded to information collection requests from the EPA for data on coal ash surface impoundments at certain of its facilities. The EPA continues to evaluate the responses and has been conducting site assessments of utilities’ coal ash surface impoundments, including certain coal ash surface impoundments operated by WPL.

In 2010, the EPA issued a proposed rule seeking comment regarding two potential regulatory options for management of CCRs: (1) regulate as a special waste under the federal hazardous waste regulations when the CCR is destined for disposal, but continue to allow beneficial use applications of CCRs as a non-hazardous material; or (2) regulate as a non-hazardous waste for all applications subject to new national standards. These proposed regulations include additional requirements with significant impact for CCR management, beneficial use applications and disposal. WPL has four current or former coal generating facilities with one or more existing coal ash surface impoundments at each location. In addition, WPL has two active CCR company-owned landfills. All of these CCR disposal units would be subject to the proposed rule currently anticipated to be finalized in late 2012. The schedule for compliance with this rule has not yet been established. WPL is currently unable to predict with certainty the impact of these information collection requests, site inspections, or potential regulations resulting from such requests for the management of CCRs, but expects that capital investments, operating expenditures and/or modifications to comply with CCR rules could be significant.

Polychlorinated Biphenyls (PCB)—In 2010, the EPA published an Advance Notice of Proposed Rulemaking to support a re-evaluation of all existing use authorizations for PCB-containing equipment. Based on the EPA’s review of the information obtained in response to this notice, significant changes in PCB regulations may be proposed, including a possible mandated phase out of all PCB-containing equipment. The EPA plans to issue a proposed PCB rule amendment for public comment by 2013. The schedule for compliance with this rule has not yet been established. Pending the development of a final rule, WPL is currently unable to predict with certainty the outcome of this possible regulatory change, but believes that the required capital investment and/or modifications resulting from these potential regulations could be significant.

Manufactured Gas Plant (MGP) Sites—Refer to Note 13(d) of the “Notes to Consolidated Financial Statements” for discussion of WPL’s liabilities related to MGP sites.

GHG Emissions—Climate change continues to be assessed by policymakers including consideration of the appropriate actions to mitigate global warming. There is continued debate regarding the public policy response that the U.S. should adopt, involving both domestic actions and international efforts. The EPA is responding to a court ruling that requires issuance of federal rules to reduce GHG emissions under the existing CAA. Associated regulations to implement these federal GHG rules are also underway in Wisconsin. Given the highly uncertain outcome and timing of future regulations regarding the control of GHG emissions, WPL currently cannot predict the financial impact of any future climate change regulations on its operations but believes the expenditures to comply with any new emissions regulations could be significant.

Significant uncertainty exists surrounding the final implementation of the EPA’s GHG regulations. Furthermore, while implementation of these regulations continues to proceed, the impacts of these regulations remain subject to change as a consequence of the complexity and magnitude of determining how to effectively control GHGs under the existing legal framework of the CAA, which may include the EPA and state agency interpretations of appropriate permitting and emission compliance requirements. The outcome of these regulations and challenges will determine whether and how GHG stationary sources, including electric utility operations, will be regulated under the CAA. WPL is currently unable to predict the timing and nature of stationary source rules for GHG emissions including future issuance of regulations that would mandate reductions of GHGs, including carbon dioxide (CO2) emissions, at electric utilities.

In 2009, the EPA issued a final Endangerment and Cause or Contribute Findings for GHG under the CAA with an effective date of January 2010. This final action includes two distinct findings regarding GHG emissions under the CAA. First, the current and projected concentrations of GHG emissions in the atmosphere threaten the public health and welfare of current

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and future generations. This is referred to as the endangerment finding and includes the six key GHG emissions identified in the EPA’s mandatory GHG reporting rule. Second, the combined emissions of CO2, methane (CH4), nitrous oxide (N2O), and hydrofluorocarbons (HFCs) from new motor vehicles and motor vehicle engines contribute to the atmospheric concentrations of these key GHG emissions and hence to the threat of climate change. This is referred to as the cause or contribute finding. In 2010, the EPA, under authority from the GHG Endangerment and Cause or Contribute Findings, also issued a final rule that regulates GHG emissions from motor vehicles as a pollutant under the CAA. This finding and rule are subject to legal challenges in the D.C. Circuit Court. These actions by the EPA enable it to regulate GHG stationary sources, including electric utility operations and natural gas distribution operations.

EPA Mandatory GHG Reporting Rule—In 2009, the final EPA Mandatory GHG Reporting rule became effective. The final rule does not require control of GHG emissions, rather it requires that sources above certain threshold levels monitor and report emissions. The EPA anticipates that the data collected by this rule will improve the U.S. government’s ability to formulate a set of climate change policy options. The GHG emissions covered by the final EPA reporting rule include CO2, CH4, N2O, sulfur hexafluoride, HFCs, perfluorocarbons and other fluorinated gases. The primary GHG emitted from WPL’s utility operations is CO2 from the combustion of fossil fuels at its larger EGUs. Emissions of GHG are reported at the facility level in CO2e and include those facilities that emit 25,000 metric tons or more of CO2e annually. WPL submitted its first GHG annual emissions report for calendar year 2010 by the Sep. 30, 2011 due date. WPL continues to maintain and update its emissions monitoring methodologies and data collection procedures to capture all the GHG emissions data required for ongoing compliance with the EPA’s mandatory GHG reporting rule. This rule is subject to a legal challenge that is pending in the D.C. Circuit Court. WPL’s annual 2010 emissions, in terms of total mass of CO2e, as reported to the EPA for electric utility and natural gas distribution operations, were as follows (in millions):

	Tons		Metric Tons
CO2e emissions (a)		16.4		14.9

(a) CO2e emissions reported to the EPA represent all emissions from the facilities operated by WPL and do not reflect its share of co-owned facilities operated by other companies.

EPA NSPS for GHG Emissions from Electric Utilities—In 2010, the EPA announced the future issuance of GHG standards for electric utilities under the CAA. The GHG emission limits are to be established as NSPS for new and existing fossil-fueled EGUs. The EPA entered a settlement agreement that required the issuance of proposed regulations for new and existing power plants by July 26, 2011 and final regulations no later than May 26, 2012. The EPA announced the issuance of proposed regulations will be delayed for existing EGUs, but has not yet established a new schedule. The EPA proposed rule for new EGUs is also delayed, and is expected to be issued in the first quarter of 2012. For existing EGUs, the NSPS issued by the EPA is expected to include emission guidelines that states must use to develop plans for reducing EGU GHG emissions. The guidelines will be established based on demonstrated controls, GHG emission reductions, costs and expected timeframes for installation and compliance. Under existing EPA regulations, states must submit their plans to the EPA within nine months after publication of the guidelines unless the EPA sets a different schedule. States have the ability to apply less or more stringent standards, or longer or shorter compliance schedules. The schedule for compliance with these rules has not yet been established. The implications of the EPA’s NSPS rule for GHG emissions from EGUs are highly uncertain, including the nature of required emissions controls and compliance timeline for mandating reductions of GHGs. WPL is currently unable to predict with certainty the final outcome, but expects that expenditures to comply with any regulations to reduce GHG emissions could be significant.

EPA GHG Tailoring Rule—In 2010, the EPA issued the GHG Tailoring Rule, which became effective on Jan. 2, 2011. The rule establishes a GHG emissions threshold for major sources under the PSD Construction Permit and Title V Operation Permit programs at 100,000 tons per year (tpy) of CO2e. The rule also establishes a threshold for what will be considered a significant increase in GHG emissions. New major sources and significantly modified existing sources of GHG will be required to obtain PSD construction permits that demonstrate BACT emissions measures to minimize GHG emissions. The rule establishes a phased-in implementation schedule for compliance with these GHG permitting requirements. Through June 2011, GHG requirements only applied to sources that were already required to obtain CAA permits for other (non-GHG) emissions. Effective July 2011, GHG requirements apply to all new major sources and modifications at existing major sources that increase GHG emissions by at least 75,000 tpy for CO2e. The rule is subject to a legal challenge that is pending in the D.C. Circuit Court. The implications of the EPA’s GHG Tailoring Rule are highly uncertain, and WPL is currently unable to predict with certainty the impact on its financial condition or results of operations, but expects that expenditures to comply with these regulations to reduce GHG emissions could be significant.

Refer to Note 13(d) of the “Notes to Consolidated Financial Statements,” “Strategic Overview” and “Liquidity and Capital Resources—Construction and Acquisition Expenditures” for further discussion of environmental matters.

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LEGISLATIVE MATTERS

Recent Legislative Developments—

Wisconsin Tax Legislation—In June 2011, Act 32 was enacted. The most significant provision of Act 32 for WPL relates to its contributions to the Focus on Energy Program. Act 32 prohibits the PSCW from requiring any energy utility to spend more than 1.2% of its annual retail utility revenues on energy efficiency and renewable resource programs effective Jan. 1, 2012. Focus on Energy works with eligible Wisconsin residents and businesses to finance and install energy efficiency and renewable energy equipment. Contributions to Focus on Energy are recovered from WPL’s retail customers through base rates.

Federal Tax Legislation—

Small Business Jobs Act of 2010 (SBJA) and the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 (the Act)—In 2010, the SBJA and the Act were enacted. The most significant provisions of the SBJA and the Act for WPL were provisions related to the extension of bonus depreciation deductions for certain expenditures for property that are incurred through Dec. 31, 2012. Based on capital projects placed into service in 2010, WPL claimed bonus depreciation deductions on its 2010 U.S. federal income tax return of $272 million. Based on capital projects placed into service in 2011, WPL currently estimates its total bonus depreciation deductions to be claimed on its 2011 U.S. federal income tax return will be approximately $334 million. WPL is currently unable to estimate its bonus depreciation deductions to be claimed on its 2012 U.S. federal income tax return but believes bonus depreciation deductions will likely contribute to an annual federal net operating loss in 2012. WPL’s federal net operating losses carryforwards are currently expected to offset future federal taxable income through 2014 resulting in minimal federal cash tax payments to the Internal Revenue Service (IRS) by WPL through 2014. Refer to Note 5 of the “Notes to Consolidated Financial Statements” for further discussion of the SBJA and the Act.

NDAA—In December 2011, the NDAA was enacted. The most significant provision of the NDAA for WPL eliminates a negative impact for regulated utilities that elect the cash grant for renewable energy projects. Prior to the enactment of NDAA, if a regulated utility elected the cash grant incentive for a renewable energy project, the utility was required to provide the benefits from the cash grant to its customers over the regulatory life of the related project assets or incur a tax normalization violation. As a result of the enactment of NDAA, utilities are no longer subject to a tax normalization violation if they provide the benefits of the cash grant incentive to their customers over a shorter time period than the regulatory life of the project assets. This provision of the NDAA can be applied retroactively to renewable energy projects placed into service since 2009. As a result of the enactment of NDAA, WPL is currently evaluating its options for government incentive elections for its Bent Tree—Phase I wind project. Refer to “Other Future Considerations—Government Incentives for Wind Projects” for additional information on government incentives for wind projects impacted by the NDAA.

Federal Pipeline Safety Act—In January 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (Pipeline Act) was enacted. The legislation includes, but is not limited to, provisions to increase civil penalties for violations of federal oil and gas pipeline safety laws, to enhance state damage prevention programs, to authorize more oil and gas pipeline inspectors, and to implement stronger safety standards, including automatic or remotely controlled shut-off valves on new or replaced oil and gas transmission pipelines. WPL currently does not believe the Pipeline Act will have a significant impact on its financial condition and results of operations.

RESULTS OF OPERATIONS

Overview—WPL’s earnings available for common stock increased $11 million and $63 million in 2011 and 2010, respectively. The 2011 increase was primarily due to a base retail electric rate increase implemented in January 2011, lower purchased electric capacity expenses related to the Kewaunee PPA and increased production tax credits generated by the Bent Tree—Phase I wind project. These items were partially offset by higher operating expenses related to the Bent Tree—Phase I wind project and various asset impairment charges in 2011. The 2010 increase was primarily due to the impact of the electric and gas retail rate increases effective in January 2010 and higher electric sales in 2010 compared to 2009 caused by weather conditions in WPL’s service territory.

Electric Margins—Electric margins are defined as electric operating revenues less electric production fuel, energy purchases and purchased electric capacity expenses. Management believes that electric margins provide a more meaningful basis for evaluating utility operations than electric operating revenues since electric production fuel, energy purchases and purchased electric capacity expenses are generally passed through to customers, and therefore result in changes to electric operating revenues that are comparable to changes in electric production fuel, energy purchases and purchased electric capacity expenses. Electric margins and megawatt-hour (MWh) sales for WPL were as follows:

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	Revenues and Costs (dollars in millions)												MWhs Sold (MWhs in thousands)
	2011		2010		(a)			2009		(b)			2011		2010		(a)			2009		(b)
Residential	$	442.6	$	439.6		1	%	$	389.7		13	%		3,517		3,541		(1	%)		3,419		4	%
Commercial		246.1		240.3		2	%		220.0		9	%		2,300		2,275		1	%		2,257		1	%
Industrial		333.5		320.9		4	%		298.2		8	%		4,424		4,252		4	%		4,119		3	%
Retail subtotal		1,022.2		1,000.8		2	%		907.9		10	%		10,241		10,068		2	%		9,795		3	%
Sales for resale:
Wholesale		160.2		167.0		(4	%)		166.6		—			2,955		2,900		2	%		2,848		2	%
Bulk power and other		27.6		20.6		34	%		61.0		(66	%)		1,028		695		48	%		1,682		(59	%)
Other		17.5		21.5		(19	%)		24.8		(13	%)		67		70		(4	%)		71		(1	%)
Total revenues/sales		1,227.5		1,209.9		1	%		1,160.3		4	%		14,291		13,733		4	%		14,396		(5	%)
Electric production fuel expense		197.4		171.7		15	%		160.6		7	%
Energy purchases expense		184.0		229.5		(20	%)		290.7		(21	%)
Purchased electric capacity expense		109.5		134.7		(19	%)		144.6		(7	%)
Margins	$	736.6	$	674.0		9	%	$	564.4		19	%

(a) Reflects the % change from 2010 to 2011. (b) Reflects the % change from 2009 to 2010.

2011 vs. 2010 Summary—Electric margins increased $63 million, or 9%, primarily due to the impact of a base retail electric rate increase (excluding fuel cost recoveries) implemented in January 2011, which increased WPL’s electric revenues by $38 million in 2011. Other increases in electric margins included $21 million of lower purchased electric capacity expenses related to the Kewaunee PPA, an estimated $2 million increase from changes in sales caused by weather conditions in WPL’s service territory in 2011 and a 4% increase in industrial sales volumes. Estimated increases to WPL’s electric margins from the impacts of weather in 2011 and 2010 were $13 million and $11 million, respectively. These items were partially offset by the impact of a wholesale formula rate change, which increased WPL’s electric revenues by $4 million in 2010 and a decrease in weather-normalized residential sales volumes.

2010 vs. 2009 Summary—Electric margins increased $110 million, or 19% in 2010, primarily due to the impact of a base retail electric rate increase (excluding fuel cost recoveries) effective January 2010, which increased WPL’s electric revenues by $94 million in 2010, an estimated $23 million increase in electric margins from changes in the net impacts of weather conditions and WPL’s weather hedging activities, $7 million of lower purchased electric capacity expenses related to the RockGen Energy Center (RockGen) PPA, which terminated in May 2009, and increased rates charged to wholesale customers including the impact of a wholesale formula rate change, which increased electric revenues by $4 million in 2010. Estimated increases (decreases) to WPL’s electric margins from the impacts of weather in 2010 and 2009 were $11 million and ($12) million (including $1 million of losses from weather derivatives in 2009), respectively. These items were partially offset by an $11 million decrease in electric margins from the impact of changes in the recovery of electric production fuel and energy purchases expense.

Base Retail Rate Increases—Increases to WPL’s electric revenues from the impacts of base retail rate increases (excluding fuel cost recoveries and net of any reserves for rate refunds) were as follows (dollars in millions):

		2011 vs. 2010		2010 vs. 2009
Retail Base Rate Cases	Effective Date	Revenue Increases		Revenue Increases
2011 Test Year	Jan. 1, 2011	$	38	$	—
2010 Test Year	Jan. 1, 2010		—		94
		$	38	$	94

Refer to “Rate Matters” for additional information relating to these retail electric rate increases and a potential retail electric rate filing by WPL in 2012.

Weather Conditions—WPL’s electric sales demand is seasonal to some extent with the annual peak normally occurring in the summer months due to air conditioning usage by its residential, commercial and wholesale customers. Cooling degree days (CDD) data is used to measure the variability of temperatures during summer months and is correlated with electric sales demand. Heating degree days (HDD) data is used to measure the variability of temperatures during winter months and is correlated with electric and gas sales demand. Refer to “Gas Margins—Weather Conditions” for details regarding HDD in WPL’s service territory. CDD in WPL’s service territory were as follows:

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	Actual
CDD (a):	2011		2010		2009		Normal (a)
Madison, Wisconsin		814		829		368		614

(a) CDD are calculated using a simple average of the high and low temperatures each day compared to a 65 degree base. Normal degree days are calculated using a rolling 20-year average of historical CDD.

Electric Production Fuel and Energy Purchases (Fuel-related) Cost Recoveries—WPL burns coal and other fossil fuels to produce electricity at its generating facilities. The cost of fossil fuels used during each period is included in electric production fuel expense. WPL also purchases electricity to meet the demand of its customers and charges these costs to energy purchases expense. WPL’s electric production fuel expense increased $26 million, or 15%, and $11 million, or 7%, in 2011 and 2010, respectively. The 2011 and 2010 increases were primarily due to higher coal volumes burned at its generating facilities resulting from increased generation needed to serve the higher electricity demand in 2011 and 2010. Also contributing to the 2011 increase were higher delivered coal prices. WPL’s energy purchases expense decreased $46 million, or 20%, and $61 million, or 21%, in 2011 and 2010, respectively. The 2011 decrease was primarily due to lower energy prices. The 2010 decrease was primarily due to lower energy prices and lower energy volumes purchased resulting from the higher Midwest Independent Transmission System Operator (MISO) dispatch of WPL’s generating facilities in 2010. The impact of the changes in energy volumes purchased were largely offset by the impact of changes in electricity volumes generated from WPL’s generating facilities and changes in bulk power sales volumes discussed below.

WPL’s rate recovery mechanism for wholesale fuel-related costs provides for adjustments to its wholesale electric rates for changes in commodity costs, thereby mitigating impacts of changes to commodity costs on its electric margins.

WPL’s retail fuel-related costs incurred in 2011 and 2010 were higher than the forecasted fuel-related costs used to set retail rates during such periods. WPL estimates the higher than forecasted retail fuel-related costs decreased electric margins by approximately $4 million and $3 million in 2011 and 2010, respectively. WPL’s retail fuel-related costs incurred in 2009 were lower than the forecasted fuel-related costs used to set retail rates during such period. WPL estimates the lower than forecasted retail fuel-related costs increased electric margins by approximately $8 million in 2009.

Refer to “Other Matters—Market Risk Sensitive Instruments and Positions” for discussion of risks associated with increased electric production fuel and energy purchases expenses on WPL’s electric margins. Refer to “Rate Matters” and Note 1(h) of the “Notes to Consolidated Financial Statements” for additional information relating to recovery mechanisms for electric production fuel and energy purchases expenses and changes to the retail rate recovery rules in Wisconsin for electric production fuel and energy purchases expenses beginning in 2011.

Purchased Electric Capacity Expense—WPL enters into PPAs to help meet the electricity demand of its customers. Certain of these PPAs include minimum payments for WPL’s rights to electric generating capacity. Details of purchased electric capacity expense included in the electric margins table above were as follows (in millions):

	2011		2010		2009
Riverside PPA	$	59	$	58	$	57
Kewaunee PPA		51		72		74
RockGen PPA (Expired May 2009)		—		—		7
Other		—		5		7
	$	110	$	135	$	145

At Dec. 31, 2011, the future estimated purchased electric capacity expense related to the Kewaunee (expires in 2013) and Riverside (expires in 2013) PPAs was as follows (in millions):

	2012		2013		Total
Kewaunee PPA	$	59	$	62	$	121
Riverside PPA (a)		59		17		76
	$	118	$	79	$	197

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(a) In November 2011, WPL filed a CA with the PSCW for the purchase of Riverside in the fourth quarter of 2012. A decision from the PSCW is expected in April 2012. If Riverside is purchased in the fourth quarter of 2012, capacity payments scheduled for 2013 will not occur.

Sales Trends—Retail sales volumes increased 2% and 3% in 2011 and 2010, respectively. The 2011 increase was primarily due to higher usage per customer caused by weather conditions in WPL’s service territory and higher sales to industrial customers driven by increased production requirements. These items were largely offset by a decrease in weather-normalized residential sales volumes. WPL believes the decrease in weather-normalized residential sales volumes is largely due to energy efficiency improvements implemented by customers and changes in customer’s usage patterns driven by economic challenges. The 2010 increase was primarily due to higher usage per customer caused by changes in weather and economic conditions in WPL’s service territory in 2010 compared to 2009.

Wholesale sales volumes increased 2% in both 2011 and 2010 primarily due to the impact of weather conditions and changes in sales to WPL’s partial-requirement wholesale customers that have contractual options to be served by WPL, other power supply sources or the MISO market.

Bulk power and other revenue changes were largely due to changes in sales in the wholesale energy markets operated by MISO and PJM Interconnection, LLC. These changes are impacted by several factors including the availability of WPL’s generating facilities and electricity demand within these wholesale energy markets. Changes in bulk power and other sales revenues were largely offset by changes in fuel-related costs and therefore did not have a significant impact on electric margins.

WPL is currently expecting relatively flat weather-normalized retail electric sales in 2012 compared to 2011. This is driven largely by low customer growth and continuing slow economic growth.

Refer to “Rate Matters” for discussion of WPL’s base retail electric rate increase implemented in January 2011 and a potential retail electric rate filing in 2012.

Gas Margins—Gas margins are defined as gas operating revenues less cost of gas sold. Management believes that gas margins provide a more meaningful basis for evaluating utility operations than gas operating revenues since cost of gas sold are generally passed through to customers, and therefore, result in changes to gas operating revenues that are comparable to changes in cost of gas sold. Gas margins and dekatherm (Dth) sales for WPL were as follows:

	Revenues and Costs (dollars in millions)												Dths Sold (Dths in thousands)
	2011		2010		(a)			2009		(b)			2011		2010		(a)			2009		(b)
Residential	$	114.5	$	118.1		(3	%)	$	122.2		(3	%)		11,231		11,205		—			11,639		(4	%)
Commercial		67.3		65.8		2	%		73.9		(11	%)		8,594		8,095		6	%		9,274		(13	%)
Industrial		5.5		8.9		(38	%)		5.7		56	%		825		1,289		(36	%)		771		67	%
Retail subtotal		187.3		192.8		(3	%)		201.8		(4	%)		20,650		20,589		—			21,684		(5	%)
Interdepartmental		0.4		0.5		(20	%)		2.0		(75	%)		771		739		4	%		464		59	%
Transportation/other		12.7		13.0		(2	%)		12.7		2	%		23,719		21,598		10	%		23,656		(9	%)
Total revenues/sales		200.4		206.3		(3	%)		216.5		(5	%)		45,140		42,926		5	%		45,804		(6	%)
Cost of gas sold		119.6		125.3		(5	%)		138.1		(9	%)
Margins	$	80.8	$	81.0		—		$	78.4		3	%

(a) Reflects the % change from 2010 to 2011. (b) Reflects the % change from 2009 to 2010.

2010 vs. 2009 Summary—Gas margins increased $3 million, or 3% in 2010, primarily due to the impact of the 2010 retail gas rate increase effective in January 2010, which increased gas revenues by $5 million in 2010. This item was partially offset by a 5% decrease in retail sales primarily due to lower usage per customer caused by weather conditions. Estimated decreases to WPL’s gas margins from the impacts of weather in 2010 and 2009 were $2 million and $0 (including $1 million of losses from weather derivatives in 2009), respectively.

Natural Gas Cost Recoveries—In 2011 and 2010, WPL’s cost of gas sold decreased $6 million, or 5%, and $13 million, or 9%, respectively. The 2011 and 2010 decreases were primarily due to a decrease in natural gas prices. Due to WPL’s rate recovery mechanisms for natural gas costs, these changes in cost of gas sold resulted in comparable changes in gas revenues and, therefore, did not have a significant impact on gas margins. Refer to Note 1(h) of the “Notes to Consolidated Financial Statements” for additional information relating to natural gas cost recoveries.

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Weather Conditions—WPL’s gas sales demand follows a seasonal pattern with an annual base load of gas and a large heating peak occurring during the winter season. HDD data is used to measure the variability of temperatures during winter months and is correlated with gas sales demand. HDD in WPL’s service territory were as follows:

	Actual
HDD (a):	2011		2010		2009		Normal (a)
Madison, Wisconsin		6,992		6,798		7,356		7,083

(a) HDD are calculated using a simple average of the high and low temperatures each day compared to a 65 degree base. Normal degree days are calculated using a rolling 20-year average of historical HDD.

Refer to “Rate Matters” for discussion of WPL’s gas rate increase and potential retail gas rate filing in 2012.

Electric Transmission Service Expenses—

2010 vs. 2009 Summary—Electric transmission service expenses increased $6 million in 2010, largely due to increased transmission rates billed to WPL by ATC.

Other Operation and Maintenance Expenses—

2011 vs. 2010 Summary—Other operation and maintenance expenses increased $23 million primarily due to $7 million of higher wind turbine operation and maintenance expenses related to the Bent Tree—Phase I wind project, which began generating electricity in late 2010, $7 million of regulatory asset impairment charges recorded in 2011, a $5 million wind site impairment charge recorded in 2011, $4 million of additional benefits costs recorded in 2011 resulting from an amendment to the Cash Balance Plan and $3 million of higher energy conservation cost recovery amortizations. These items were partially offset by $4 million of lower other postretirement benefits costs primarily due to a plan amendment in 2011, and $2 million of restructuring charges incurred in 2010 related to the elimination of certain corporate and operations positions.

2010 vs. 2009 Summary—Other operation and maintenance expenses decreased $2 million in 2010, primarily due to $11 million of regulatory-related charges in 2009 related to the Nelson Dewey #3 project, $7 million of restructuring charges incurred in 2009 related to the elimination of certain corporate and operations positions, $7 million of lower pension and other postretirement benefits costs, a $2 million loss contingency reserve recorded in 2009 related to the Cash Balance Plan lawsuit and lower expenses related to other energy-related products and services. These items were partially offset by a $12 million deferral of retail pension and benefits costs recorded in 2009 in accordance with the stipulation agreement approved by the PSCW related to WPL’s 2009 retail rate case, $12 million of higher incentive-related compensation expenses and $2 million of restructuring charges incurred in 2010 related to the elimination of certain corporate and operations positions.

WPL currently expects other operations and maintenance expense to decrease in 2012 as compared to 2011 largely due to the full year realization of cost control initiatives implemented in 2011 including the elimination of certain corporate and operations positions, and continued focus on cost controls and operational efficiencies in 2012. These items are expected to be partially offset by increases in retirement plan costs in 2012 as compared to 2011 (excluding the impacts of the Cash Balance Plan amendment in 2011), resulting from significant reductions in discount rates in 2011 and settlement losses expected in 2012 related to benefit payments for retired executives.

Depreciation and Amortization Expenses—

2011 vs. 2010 Summary—Depreciation and amortization expenses increased $32 million in 2011, primarily due to property additions, including $17 million of depreciation expense recognized in 2011 related to the Bent Tree—Phase I wind project, which began generating electricity in late 2010. Also contributing to the increase was a depreciation adjustment recorded in 2010, which is not anticipated to have a material impact on future periods.

2010 vs. 2009 Summary—Depreciation and amortization expenses decreased $7 million in 2010, primarily due to a depreciation adjustment recorded in 2010, which is not anticipated to have a material impact on future periods. This item was partially offset by additional depreciation from the impact of property additions related to AMI placed into service in 2009 and the June 2009 acquisition of the Neenah Energy Facility.

WPL currently expects its depreciation expense to increase in 2012 as compared to 2011 due to property additions in 2011 and 2012.

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Refer to Note 1(e) of the “Notes to Consolidated Financial Statements” for details of WPL’s Bent Tree—Phase I wind project. Refer to “Rate Matters” for discussion of the interplay between utility operating expenses and utility margins given their impact on WPL’s rate activities.

Interest Expense—

2011 vs. 2010 Summary—Interest expense increased $1 million in 2011, primarily due to interest expense from WPL’s issuance of $150 million of 4.6% debentures in June 2010. This item was partially offset by the impact of WPL’s retirement of $100 million of 7.625% debentures in March 2010.

2010 vs. 2009 Summary—Interest expense increased $4 million in 2010, primarily due to interest expense from WPL’s issuances of $250 million of 5% debentures in July 2009 and $150 million of 4.6% debentures in June 2010. These items were partially offset by the impact of WPL’s retirement of $100 million of 7.625% debentures in March 2010.

Refer to Note 9 of the “Notes to Consolidated Financial Statements” for additional details of WPL’s debt.

AFUDC—

2011 vs. 2010 Summary—AFUDC decreased $6 million in 2011, primarily due to $10 million of AFUDC recognized in 2010 for the Bent Tree—Phase I wind project. This item was partially offset by $3 million of AFUDC recognized in 2011 for the Edgewater Unit 5 emission controls project.

2010 vs. 2009 Summary—AFUDC increased $7 million in 2010 primarily due to $7 million of higher AFUDC recognized in 2010 as compared to 2009 for the Bent Tree—Phase I wind project.

WPL currently expects AFUDC to increase in 2012 compared to 2011 primarily due to expected increased levels of CWIP balances in 2012 related to large construction projects at its Columbia Units 1 and 2, and Edgewater Unit 5. Refer to “Liquidity and Capital Resources—Construction and Acquisition Expenditures” for details regarding anticipated construction expenditures for 2012 through 2015.

Income Taxes—WPL’s effective income tax rates were 33.4%, 39.2% and 33.9% in 2011, 2010 and 2009, respectively. Details of the effective income tax rates were as follows:

	2011			2010			2009
Statutory federal income tax rate		35.0	%		35.0	%		35.0	%
Production tax credits		(6.0	)		(1.4	)		(2.9	)
Federal Health Care Legislation enacted in March 2010		—			1.2			—
State filing changes due to Wisconsin Senate Bill 62 (SB 62) enacted in February 2009		—			—			(1.8	)
Other items, net		4.4			4.4			3.6
Overall income tax rate		33.4	%		39.2	%		33.9	%

2011 vs. 2010 Summary—The decrease in the effective income tax rate for 2011 was primarily due to $11 million of higher production tax credits in 2011 largely due to the Bent Tree—Phase I wind project, which began generating electricity in late 2010, and $3 million of income tax expense recognized in 2010 related to the impacts of the Patient Protection and Affordable Care Act, and Health Care and Education Reconciliation Act of 2010 (Federal Health Care Legislation) enacted in March 2010, which is expected to reduce WPL’s tax deductions for retiree health care costs beginning in 2013, to the extent prescription drug expenses are reimbursed under the Medicare Part D retiree drug subsidy program.

2010 vs. 2009 Summary—The increase in the effective income tax rate for 2010 was primarily due to $3 million of income tax expense recognized in 2010 related to the impacts of the Federal Health Care Legislation enacted in March 2010, which is expected to reduce WPL’s tax deductions for retiree health care costs beginning in 2013, to the extent prescription drug expenses are reimbursed under the Medicare Part D retiree drug subsidy program, and $2 million of income tax benefits recognized in 2009 related to the net impacts of SB 62 enacted in February 2009 and a 2009 decision to allow WPL to do business in Iowa thus requiring WPL to file as part of the Iowa consolidated tax return.

Refer to Note 5 of the “Notes to Consolidated Financial Statements” for additional information regarding production tax credits, Federal Health Care Legislation enacted in 2010 and state filing changes due to SB 62 enacted in 2009. Refer to “Critical Accounting Policies and Estimates—Income Taxes” for discussion of possible changes to state apportionment projections resulting from Alliant Energy’s decision in February 2012 to sell RMT. Refer to “Other Matters—Other Future

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Considerations” for discussion of possible impacts to WPL’s future income taxes resulting from trends in production tax credits and a re-evaluation currently underway of different options for wind project incentives due to a recent law change.

LIQUIDITY AND CAPITAL RESOURCES

Overview—WPL believes it has, and expects to maintain, adequate liquidity to operate its business as a result of available capacity under its revolving credit facility and operating cash flows. Based on its liquidity and capital structure, WPL believes it will be able to secure the additional capital required to implement its strategic plan and meet its long-term contractual obligations. Access by WPL to capital markets to fund its future capital requirements at reasonable terms is largely dependent on its credit quality and on developments in those capital markets.

Liquidity Position—At Dec. 31, 2011, WPL had $374 million of available capacity under its revolving credit facility. Refer to “Cash Flows—Financing Activities—Short-term Debt” and Note 9(a) of the “Notes to Consolidated Financial Statements” for further discussion of the credit facility.

Capital Structure—WPL plans to maintain debt-to-total capitalization ratios that are consistent with its investment-grade credit ratings in order to facilitate ongoing and reliable access to capital markets on reasonable terms and conditions. WPL’s capital structure at Dec. 31, 2011 was as follows (dollars in millions):

Common equity	$	1,442.4	55.2	%
Preferred stock		60.0	2.3	%
Long-term debt		1,082.2	41.5	%
Short-term debt		25.7	1.0	%
	$	2,610.3	100.0	%

In addition to capital structure, other important financial considerations used to determine the characteristics of future financings include financial coverage ratios, flexibility in capital spending plans, regulatory orders and rate making considerations, the levels of debt imputed by rating agencies, market conditions and the impact of tax initiatives. The most significant debt imputations include operating leases, a portion of the Kewaunee and Riverside PPAs, and postretirement benefits obligations. The PSCW explicitly factors certain imputed debt adjustments in establishing a regulatory capital structure as part of WPL’s retail rate cases, particularly those related to operating leases and PPAs.

WPL intends to manage its capital structure and liquidity position in such a way that does not compromise its ability to raise the necessary funds required to provide utility services reliably and at reasonable costs, while maintaining a financial capital structure consistent with those approved by regulators. Key considerations include maintaining access to the financial markets on the terms, in the amounts and within the timeframes required to fund WPL’s strategic plan, retaining a prudent level of financial flexibility and maintaining its investment-grade credit ratings. The capital structure is only one of a number of components that needs to be actively managed in order to achieve these objectives. WPL currently expects to maintain a capital structure in which total debt would not exceed 45% to 55%, and preferred stock would not exceed 5% to 10%, of total capital. These targets may be adjusted depending on subsequent developments and their impact on WPL’s weighted average cost of capital and investment-grade credit ratings.

Credit and Capital Market Developments—WPL’s ability to facilitate or to provide reliable and cost-effective utility services depends on its reliable access to cost-effective capital. Financial markets that were subjected to considerable strain since 2007 have shown signs of selective recovery. Certain business sectors, including the regulated utility sector, have attracted and retained investor interest in the equity and debt capital markets. However, areas of concern remain, including certain issues in the U.S. and internationally that have impacted the availability of credit and the liquidity of financial assets. Among these are the evolving financial situation in Europe and the economic expansion in China and other emerging countries, with their respective consequences for international liquidity. There is also concern about the level of spending by the U.S. federal government and the temporary monetary policies of the Federal Reserve System intended to spur economic growth, with potential implications over time for inflation and interest rate levels. The evolving profile and impact of financial market regulation, both in the U.S. and internationally, contributes to the unsettled tone of the global financial markets. These developments translate into uncertainties and volatility regarding the availability of capital and for the terms and conditions of capital raised to meet funding requirements.

WPL is aware of the potential implications that these credit and capital market developments might have on its ability to raise the external funding required for its operations and capital expenditure plans. The strategic implications include protecting its liquidity position and avoiding over-reliance on short-term funding. WPL maintains a revolving credit facility to provide

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backstop liquidity to its commercial paper program, ensures a committed source of liquidity in the event the commercial paper market becomes disrupted and manages its long-term debt maturity profile. As discussed below, WPL retains flexibility in undertaking its capital expenditure program, particularly with respect to capital expenditures timing associated with the investment program within its strategic plan.

Primary Sources and Uses of Cash—WPL’s most significant source of cash is from electric and gas sales to its customers. Cash from these sales reimburses WPL for prudently-incurred expenses to provide service to its customers and provides WPL a return on the assets used to provide such services. Operating cash flows are expected to cover the majority of WPL’s capital expenditures required to maintain its current infrastructure and to pay dividends to Alliant Energy. Capital needed to retire debt, as well as to fund capital expenditures related to environmental compliance programs and other strategic projects, is expected to be met primarily through external financings. Ongoing monitoring of credit and capital market conditions allows management to evaluate the availability of funding and the terms and conditions attached to such financing. In order to maintain debt-to-total capitalization ratios that are consistent with investment-grade ratings, WPL may periodically fund such capital requirements with additional debt and equity.

Cash Flows—Selected information from the Consolidated Statements of Cash Flows was as follows (in millions):

	2011			2010			2009
Cash and cash equivalents at Jan. 1	$	0.1		$	18.5		$	4.5
Cash flows from (used for):
Operating activities		428.8			372.4			305.8
Investing activities		(305.4	)		(449.3	)		(493.4	)
Financing activities		(120.8	)		58.5			201.6
Net increase (decrease)		2.6			(18.4	)		14.0
Cash and cash equivalents at Dec. 31	$	2.7		$	0.1		$	18.5

Operating Activities—

2011 vs. 2010—WPL’s cash flows from operating activities increased $56 million primarily due to $47 million of higher income tax refunds, increased collections from WPL’s customers in 2011 caused by the impacts of a rate increase and $21 million of lower payments related to the Kewaunee PPA. These items were partially offset by $47 million of pension plan contributions in 2011.

2010 vs. 2009—WPL’s cash flows from operating activities increased $67 million primarily due to increased collections from WPL’s customers during 2010 caused by the impacts of rate increases and higher electric sales, $47 million of pension plan contributions during 2009 and $23 million of refunds paid by WPL to its retail customers during 2009 for over-collected fuel-related costs in 2008. These items were partially offset by $72 million of lower income tax refunds.

Pension Plan Contributions—Pension plan contributions by WPL include contributions to its qualified pension plan as well as an assigned portion of the contributions to pension plans sponsored by Corporate Services and were $47 million, $0 and $47 million for 2011, 2010 and 2009, respectively. WPL currently does not expect to make any significant pension plan contributions in 2012 through 2014 based on the funded status and assumed return on assets as of the Dec. 31, 2011 measurement date. Refer to Note 6(a) of the “Notes to Consolidated Financial Statements” for discussion of the current funded levels of WPL’s pension plan and contributions expected in 2012.

Income Tax Refunds—Income tax refunds received by WPL were $51 million, $4 million and $76 million for 2011, 2010 and 2009, respectively. WPL’s income tax refund in 2009 was primarily due to claims filed with the IRS to carryback net operating losses to prior years. WPL currently does not expect to make any significant federal income tax payments in 2012 through 2014 based on the federal net operating loss and credit carryforward positions as of Dec. 31, 2011. Refer to Note 5 of the “Notes to Consolidated Financial Statements” for discussion of the carryforward positions.

Rate Increases—WPL implemented rate increases in 2011 and 2010 that resulted in higher collections from its retail customers. A portion of these higher collections was used to reimburse WPL for prudently-incurred expenses to provide service to its customers (e.g. higher payments for operation and maintenance expenses or electric transmission services) resulting in limited impacts on cash flows from operations. Another portion of these rate increases provided WPL recovery of and return on new rate base additions (e.g. returns on new wind projects), which significantly increased cash flows from operations for WPL in 2011 and 2010. Refer to “Rate Matters” for additional details of retail rate increases implemented by WPL in 2011 and 2010.

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Investing Activities—

2011 vs. 2010—WPL’s cash flows used for investing activities decreased $144 million primarily due to $136 million of lower construction and acquisition expenditures. The lower construction and acquisition expenditures resulted from expenditures during 2010 for the Bent Tree—Phase I wind project. This item was partially offset by expenditures during 2011 for the acquisition of the remaining 25% interest in Edgewater Unit 5 and the Edgewater Unit 5 emission controls project.

2010 vs. 2009—WPL’s cash flows used for investing activities decreased $44 million primarily due to $58 million of lower construction and acquisition expenditures resulting from expenditures during 2009 for the acquisition of the Neenah Energy Facility and implementation of AMI, partially offset by higher expenditures during 2010 for its Bent Tree—Phase I wind project. The lower construction and acquisition expenditures were partially offset by changes in the collection of and advances for customer energy efficiency projects.

Construction and Acquisition Expenditures—Capital expenditures and financing plans are reviewed, approved and updated as part of WPL’s strategic planning and budgeting processes. In addition, significant capital expenditures and investments are subject to a cross-functional review prior to approval. Changes in WPL’s anticipated construction and acquisition expenditures may result from a number of reasons including economic conditions, regulatory requirements, changing legislation, ability to obtain adequate and timely rate relief, changing market conditions and new opportunities. WPL has not yet entered into contractual commitments relating to the majority of its anticipated future capital expenditures. As a result, it has some discretion with regard to the level, and timing of, capital expenditures eventually incurred and closely monitors and frequently updates such estimates. WPL currently anticipates construction and acquisition expenditures for 2012 through 2015 as follows (in millions). Cost estimates represent WPL’s estimated portion of total escalated construction and acquisition expenditures and exclude AFUDC, if applicable. Refer to “Strategic Overview” for further discussion of the generation plans and environmental compliance plans.

	2012		2013		2014		2015
Generation—new gas facility—Riverside	$	390	$	—	$	—	$	—
Environmental		170		170		55		95
Generation—performance improvements		10		20		25		25
Other utility capital expenditures		160		175		190		190
Total utility business	$	730	$	365	$	270	$	310

WPL expects to finance its 2012 through 2015 capital expenditure plans in a manner that allows it to adhere to the capital structure targets discussed in the “Capital Structure” section above. 2012 capital expenditures are expected to be funded with a combination of internally-generated cash, long- and short-term debt and capital contributions from WPL’s parent. The precise characteristics of the financing for the 2013 through 2015 capital expenditures will be determined closer to the time that the financing is required. Flexibility will be required in implementing the long-term financing plans to allow for scheduling variations in the required authorization and construction work, changing market conditions and any adjustments that might be required to ensure there are no material adverse impacts to WPL’s capital structure.

Government Grants for Wind Projects—Refer to “Other Matters—Other Future Considerations—Government Incentives for Wind Projects” for additional information regarding the government incentives for wind projects and a re-evaluation currently underway by WPL regarding government incentive options for its Bent Tree—Phase I wind project due to a recent law change. If WPL is eligible for, and elects to change its election to, the government grant option for its Bent Tree—Phase I wind project, WPL could realize approximately $125 million to $150 million of grant proceeds in 2012 or early 2013.

Financing Activities—

2011 vs. 2010—WPL’s cash flows used for financing activities increased $179 million primarily due to changes in the amount of commercial paper outstanding, the impacts of long-term debt issued and retired during 2010 discussed below and $50 million of lower capital contributions from its parent company during 2011 compared to 2010.

WPL’s increases (decreases) in financing cash flows due to changes in long-term debt for 2011 vs. 2010 were as follows (in millions):

Proceeds from issuances:
4.6% debentures issued in June 2010	($	150	)
Payments to retire:
7.625% debentures retired in March 2010		100
	($	50	)

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2010 vs. 2009—WPL’s cash flows from financing activities decreased $143 million primarily due to impacts of long-term debt issued and retired during 2010 and 2009 discussed below and $100 million of capital contributions received during 2009 from its parent company. These items were partially offset by changes in the amount of commercial paper outstanding and $75 million of capital contributions received during 2010 from WPL’s parent company.

WPL’s increases (decreases) in financing cash flows due to changes in long-term debt for 2010 vs. 2009 were as follows (in millions):

Proceeds from issuances:
4.6% debentures issued in June 2010	$	150
5% debentures issued in July 2009		(250	)
Payments to retire:
7.625% debentures retired in March 2010		(100	)
	($	200	)

State Regulatory Financing Authorizations—In November 2011, WPL received authorization from the PSCW to have up to $400 million of short-term borrowings and letters of credit outstanding through the earlier of the termination date of WPL’s credit facility agreement or December 2019. In February 2012, the PSCW issued a decision authorizing WPL to issue up to $700 million of long-term debt securities during 2012 and 2013, with no more than $400 million to be issued in either year. In August 2011, WPL requested authority from the PSCW to arrange an interim credit facility not to exceed 364 days in length beginning no later than the date of the prospective purchase of Riverside and to increase the short-term debt limit up to $700 million during this interim period. WPL expects a decision on this request in the first half of 2012.

Shelf Registrations—WPL has a current shelf registration statement with the Securities and Exchange Commission for availability to issue up to $800 million of preferred stock and debt securities from December 2011 through December 2014.

Common Stock Dividends—Refer to Note 7 of the “Notes to Consolidated Financial Statements” for discussion of WPL’s dividend payment restrictions based on the terms of its outstanding preferred stock and applicable regulatory limitations.

Capital Contributions—Refer to Note 7 of the “Notes to Consolidated Financial Statements” for discussion of capital contributions from Alliant Energy to WPL and payments of common stock dividends by WPL to its parent company.

Short-term Debt—WPL maintains committed bank lines of credit to provide short-term borrowing flexibility and backstop liquidity for commercial paper outstanding. At Dec. 31, 2011, WPL’s short-term borrowing arrangements included a revolving credit facility of $400 million, which expires in December 2016. There are currently 12 lenders that participate in the credit facility, with aggregate respective commitments ranging from $10 million to $45 million. At Dec. 31, 2011, additional credit facility information was as follows (dollars in millions):

Commercial paper:
Amount outstanding	$	26
Remaining maturity		3 days
Interest rate		0.3	%
Available credit facility capacity	$	374

During 2011, WPL issued commercial paper to meet short-term financing requirements and did not borrow directly under its credit facility.

WPL’s credit agreement contains a covenant, which requires WPL to maintain a debt-to-capital ratio of less than 58% in order to borrow under the credit facility. At Dec. 31, 2011, WPL’s actual debt-to-capital ratio was 45%. The debt component of the capital ratio generally includes long- and short-term debt (excluding non-recourse debt and hybrid securities to the extent the total carrying value of such hybrid securities does not exceed 15% of consolidated capital of the applicable borrower), capital lease obligations, letters of credit, guarantees of the foregoing and new synthetic leases. Unfunded vested benefits under qualified pension plans are not included in the debt-to-capital ratio. The equity component of the capital ratio excludes accumulated other comprehensive income (loss).

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The credit agreement contains provisions that generally prohibit placing liens on any of WPL’s property or its subsidiaries with certain exceptions. Exceptions include among others, liens to secure obligations of up to 5% of the consolidated assets of the applicable borrower (valued at carrying value), liens imposed by government entities, materialmens’ and similar liens, judgment liens to secure non-recourse debt not to exceed $100 million outstanding at any one time, and purchase money liens.

The credit agreement contains provisions that require, during its term, any proceeds from asset sales, with certain exclusions, in excess of 20% of WPL’s consolidated assets be used to reduce commitments under its facility. Exclusions include, among others, certain sale and lease-back transactions.

The credit agreement contains customary events of default. A cross-default provision would be triggered under the credit agreement if WPL, as applicable, or a majority-owned subsidiary accounting for 20% or more of WPL’s, as applicable, consolidated assets (valued at carrying value) defaults on debt totaling $50 million or more. A default by Alliant Energy, IPL, Corporate Services or Resources and its subsidiaries would not trigger a cross-default under the credit agreement. If an event of default under the credit agreement occurs and is continuing, then the lenders may declare any outstanding obligations under the credit agreement immediately due and payable. In addition, if any order for relief is entered under bankruptcy laws with respect to WPL, then any outstanding obligations under the credit agreement would be immediately due and payable. At Dec. 31, 2011, WPL did not have any direct borrowings outstanding under its credit agreement.

A material adverse change representation is not required for borrowings under the credit agreement. At Dec. 31, 2011, WPL was in compliance with all covenants and other provisions of the credit agreement.

Refer to Note 9(a) of the “Notes to Consolidated Financial Statements” for additional information on short-term debt.

Long-term Debt—There were no significant issuances or retirements of long-term debt in 2011. In 2010, WPL issued $150 million of 4.6% debentures due June 2020. The proceeds were used to repay short-term debt, fund capital expenditures and for general working capital purposes. In 2010, WPL retired its $100 million 7.625% debentures, which were due March 2010. Refer to Note 9(b) of the “Notes to Consolidated Financial Statements” for additional information on long-term debt.

WPL currently expects to issue up to $300 million of long-term debt in 2012. As a result of the enactment of the NDAA, WPL is currently re-evaluating its options for government incentive elections for its Bent Tree—Phase I wind project. The outcome of this re-evaluation along with other factors could impact the timing and amounts of this long-term issuance.

Creditworthiness—

Ratings Triggers—The long-term debt of WPL is not subject to any repayment requirements as a result of explicit credit rating downgrades or so-called “ratings triggers.” However, WPL is party to various agreements, including PPAs and commodity contracts that are dependent on maintaining investment-grade credit ratings. In the event of a downgrade below investment-grade level, WPL may need to provide credit support, such as letters of credit or cash collateral equal to the amount of the exposure, or may need to unwind the contract or pay the underlying obligation. In the event of a downgrade below investment-grade level, management believes WPL has sufficient liquidity to cover counterparty credit support or collateral requirements under these various agreements. In addition, a downgrade in the credit ratings of WPL could also result in it paying higher interest rates in future financings, reduce its pool of potential lenders, increase its borrowing costs under the existing credit facility or limit its access to the commercial paper market. WPL is committed to taking the necessary steps required to maintain investment-grade credit ratings. WPL’s current credit ratings and outlooks are as follows:

	Standard & Poor’s Ratings Services	Moody’s Investors Service
Corporate/issuer	A-	A2
Commercial paper	A-2	P-1
Senior unsecured long-term debt	A-	A2
Preferred stock	BBB	Baa1
Outlook	Stable	Negative

Credit ratings are not recommendations to buy or sell securities and are subject to change, and each rating should be evaluated independently of any other rating. WPL assumes no obligation to update its credit ratings. Refer to Note 12 of the “Notes to Consolidated Financial Statements” for additional information on ratings triggers for commodity contracts accounted for as derivatives.

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Off-Balance Sheet Arrangements—

Synthetic Leases—WPL utilizes off-balance sheet synthetic operating leases related to the financing of certain utility railcars. Synthetic leases provide favorable financing rates to WPL while allowing it to maintain operating control of its leased assets. Refer to Note 3(a) of the “Notes to Consolidated Financial Statements” for future minimum lease payments and residual value guarantees associated with these synthetic leases.

Special Purpose Entities—Refer to Note 19 of the “Notes to Consolidated Financial Statements” for information regarding variable interest entities.

Certain Financial Commitments—

Contractual Obligations—WPL’s consolidated long-term contractual obligations as of Dec. 31, 2011 were as follows (in millions):

	2012		2013		2014		2015		2016		Thereafter		Total
Operating expense purchase obligations (Note 13(a)):
Purchased power and fuel commitments (a)	$	188	$	141	$	38	$	24	$	13	$	7	$	411
Other (b)		8		8		—		—		—		—		16
Long-term debt maturities (Note 9(b))		—		—		8		31		—		1,050		1,089
Interest—long-term debt obligations		66		66		66		65		64		993		1,320
Operating leases (Note 3(a))		64		24		5		1		—		1		95
Capital lease—Sheboygan Falls Energy Facility (Note 3(b))		15		15		15		15		15		128		203
Capital leases—other		1		1		—		—		—		—		2
	$	342	$	255	$	132	$	136	$	92	$	2,179	$	3,136

(a) Purchased power and fuel commitments represent normal business contracts used to ensure adequate purchased power, coal and natural gas supplies and to minimize exposure to market price fluctuations. Alliant Energy, through its subsidiary Corporate Services, has entered into various coal commitments that have not yet been directly assigned to WPL. Such commitments are not included in WPL’s purchased power and fuel commitments.

(b) Other operating expense purchase obligations represent individual commitments incurred during the normal course of business that exceeded $1 million at Dec. 31, 2011.

At Dec. 31, 2011, WPL had $13 million of uncertain tax positions recorded as liabilities, which are not included in the above table. It is uncertain if, and when, such amounts may be settled with the respective taxing authorities.

Refer to Note 6(a) of the “Notes to Consolidated Financial Statements” for anticipated pension and other postretirement benefits funding amounts, which are not included in the above table. Refer to “Cash Flows—Investing Activities—Construction and Acquisition Expenditures” for additional information on WPL’s construction and acquisition programs. In addition, at Dec. 31, 2011, there were various other long-term liabilities and deferred credits included on the Consolidated Balance Sheet that, due to the nature of the liabilities, the timing of payments cannot be estimated and are therefore excluded from the above table.

OTHER MATTERS

Market Risk Sensitive Instruments and Positions—WPL’s primary market risk exposures are associated with commodity prices, investment prices and interest rates. WPL has risk management policies to monitor and assist in controlling these market risks and uses derivative instruments to manage some of the exposures. Refer to Notes 1(i) and 12 of the “Notes to Consolidated Financial Statements” for further discussion of WPL’s derivative instruments.

Commodity Price—WPL is exposed to the impact of market fluctuations in the price and transportation costs of commodities it procures and markets. WPL employs established policies and procedures to mitigate its risks associated with these market fluctuations including the use of various commodity derivatives and contracts of various durations for the forward sale and purchase of these commodities. WPL’s exposure to commodity price risks is also significantly mitigated by current rate making structures in place for recovery of its electric production fuel and purchased energy expenses (fuel-related costs) as well as its cost of natural gas purchased for resale. WPL’s wholesale electric and gas tariffs provide for subsequent monthly adjustments to its tariff rates for material changes in prudently incurred commodity costs. WPL’s rate mechanisms, combined with commodity derivatives, significantly reduce commodity risk associated with its electric and gas margins.

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WPL’s retail electric margins have the most exposure to the impact of changes in commodity prices due largely to the current retail recovery mechanism in place in Wisconsin for fuel-related costs, which became effective on Jan. 1, 2011. The cost recovery mechanism applicable for WPL’s retail electric customers is based on forecasts of fuel-related costs expected to be incurred during forward-looking test year periods and fuel monitoring ranges determined by the PSCW during each retail electric rate proceeding or in a separate fuel cost plan approval proceeding. Under the new cost recovery mechanism, if WPL’s actual fuel-related costs fall outside this fuel monitoring range during the test period, WPL is authorized to defer the incremental under-/over-collection of fuel-related costs from retail electric customers that are outside the approved ranges. Deferral of under-collection of fuel-related costs are reduced to the extent WPL’s return on common equity during the fuel cost plan year exceeds the most recently authorized return on common equity. WPL’s retail fuel-related costs incurred in 2011 were higher than forecasted retail fuel-related costs approved by the PSCW in December 2010 resulting in an under-collection of fuel-related costs for 2011 of approximately $4 million. The amount of under-collected fuel-related costs for 2011 did not fall outside of the fuel monitoring range and therefore did not qualify for deferral.

In December 2011, the PSCW approved annual forecasted fuel-related costs per MWh of $25.98 based on $357 million of variable fuel costs for WPL’s 2012 test period. These 2012 fuel-related costs, excluding deferred CSAPR compliance costs, will be monitored using an annual bandwidth of plus or minus 2%. The December 2011 order also required WPL to defer direct CSAPR compliance costs that are not included in the fuel monitoring level and set a zero percent tolerance band for the CSAPR-related deferral. Subsequent to the PSCW order issued in December 2011, the D.C. Circuit Court stayed the implementation of CSAPR and CAIR remains effective. WPL is currently unable to predict the final outcome of the CSAPR stay and the impact on its financial condition or results of operations. Based on the cost recovery mechanism in Wisconsin and the annual forecasted fuel-related costs and fuel monitoring range approved by the PSCW in December 2011, WPL currently estimates the commodity risk exposure to its electric margins in 2012 is approximately $6 million. This amount excludes any potential additional risk if WPL’s return on common equity during 2012 exceeds its most recently authorized return on common equity.

Refer to “Rate Matters” and Note 1(h) of the “Notes to Consolidated Financial Statements” for additional details of utility cost recovery mechanisms that significantly reduce WPL’s commodity risk.

Investment Price—WPL is exposed to investment price risk as a result of its investments in debt and equity securities, largely related to securities held by its pension and other postretirement benefits plans. Refer to Note 6(a) of the “Notes to Consolidated Financial Statements” for details of the debt and equity securities held by its pension and other postretirement benefits plans. Refer to “Critical Accounting Policies and Estimates—Pensions and Other Postretirement Benefits” for the impact on WPL’s retirement plan costs of changes in the rate of returns earned by its plan assets.

Interest Rate—WPL is exposed to risk resulting from changes in interest rates as a result of its issuance of variable-rate short-term borrowings. Assuming the impact of a hypothetical 100 basis point increase in interest rates on variable-rate short-term borrowings at Dec. 31, 2011, WPL’s annual pre-tax expense would increase by approximately $0.3 million. Refer to 9(a) of the “Notes to Consolidated Financial Statements” for additional information on variable-rate short-term borrowings. Refer to “Critical Accounting Policies and Estimates—Pensions and Other Postretirement Benefits” for the impacts of changes in discount rates on retirement plan obligations and costs.

Critical Accounting Policies and Estimates—The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the U.S. (GAAP) requires that management apply accounting policies and make estimates that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Based on historical experience and various other factors, WPL believes the following accounting policies and estimates are critical to its business and the understanding of its financial results as they require critical assumptions and judgments by management. The results of these assumptions and judgments form the basis for making estimates regarding the results of operations and the amounts of assets and liabilities that are not readily apparent from other sources. Actual financial results may differ materially from these estimates. WPL’s management has discussed these critical accounting policies and estimates with the Audit Committee of its Board of Directors. Refer to Note 1 of the “Notes to Consolidated Financial Statements” for additional discussion of WPL’s accounting policies and the estimates used in the preparation of the consolidated financial statements.

Contingencies—WPL makes assumptions and judgments each reporting period regarding the future outcome of contingent events and records loss contingency amounts for any contingent events that are both probable and reasonably estimated based upon current available information. The amounts recorded may differ from the actual income or expense that occurs when the uncertainty is resolved. The estimates that WPL makes in accounting for contingencies, and the gains and losses that it records upon the ultimate resolution of these uncertainties, could have a significant effect on the results of operations and the amount of assets and liabilities in its financial statements. Note 13 of the “Notes to Consolidated Financial Statements”

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provides discussion of contingencies assessed at Dec. 31, 2011 including various pending legal proceedings that may have a material impact on WPL’s financial condition and results of operations.

Regulatory Assets and Regulatory Liabilities—WPL is regulated by various federal and state regulatory agencies. As a result, it is subject to accounting guidance for regulated operations, which recognizes that the actions of a regulator can provide reasonable assurance of the existence of an asset or liability. Regulatory assets or regulatory liabilities arise as a result of a difference between GAAP and the accounting principles imposed by the regulatory agencies. Regulatory assets represent incurred costs that have been deferred as they are probable of recovery in future customer rates. Regulatory liabilities represent obligations to make refunds to customers and amounts collected in rates for which the related costs have not yet been incurred. WPL recognizes regulatory assets and regulatory liabilities in accordance with the rulings of its federal and state regulators and future regulatory rulings may impact the carrying value and accounting treatment of WPL’s regulatory assets and regulatory liabilities.

WPL makes assumptions and judgments each reporting period regarding whether its regulatory assets are probable of future recovery and its regulatory liabilities are probable future obligations by considering factors such as regulatory environment changes, rate orders issued by the applicable regulatory agencies and historical decisions by applicable regulatory agencies regarding similar regulatory assets and regulatory liabilities. The judgments used by regulatory authorities have an impact on the recovery of costs, the rate of return on invested capital and the timing and amount of assets to be recovered by rates. A change in these judgments may result in a material impact on WPL’s results of operations and the amount of assets and liabilities in its financial statements. Note 1(b) of the “Notes to Consolidated Financial Statements” provides details of the nature and amounts of WPL’s regulatory assets and regulatory liabilities assessed at Dec. 31, 2011 as well as material changes to these regulatory assets and regulatory liabilities during 2011.

Long-Lived Assets—WPL completes periodic assessments regarding the recoverability of certain long-lived assets when factors indicate the carrying value of such assets may be impaired. These assessments require significant assumptions and judgments by management. The long-lived assets assessed for impairment generally include assets within its non-regulated operations, which are not yet generating cash flows, and assets within its regulated operations, which may not be fully recovered from its customers as a result of regulatory decisions in the future.

Non-regulated Operations—Factors considered in determining if an impairment review is necessary for long-lived assets within non-regulated operations include a significant underperformance of the assets relative to historical or projected future operating results, a significant change in the use of the acquired assets or business strategy related to such assets, and significant negative industry, regulatory or economic trends. When an impairment review is deemed necessary, a comparison is made between the expected undiscounted future cash flows and the carrying amount of the asset. If the carrying amount of the asset exceeds the expected undiscounted future cash flows, an impairment loss is recognized equal to the amount the carrying amount of the asset exceeds the fair value of the asset. The fair value is determined by the use of quoted market prices, appraisals, or the use of valuation techniques such as expected discounted future cash flows. WPL’s long-lived assets within its non-regulated operations assessed in 2011 included a wind site currently expected to be used to develop a future wind project.

Undeveloped Wind Site—As of Dec. 31, 2011, WPL has an undeveloped wind site with capitalized costs of $13 million related to its 200 MW of wind site capacity in Freeborn County, Minnesota. WPL assessed the recoverability of this undeveloped wind site given further reductions in forward fossil fuel prices in 2011 and concluded no impairment was required as of Dec. 31, 2011. Changes in the estimated cash flows from this remaining undeveloped wind site could result in the undiscounted future cash flows from the wind site being less than the carrying amount of the wind site and a future material impairment could be required. The future expected cash flows from the undeveloped wind site are dependent on the future demand of wind energy in the region where the wind site is located. The future demand of wind energy in the region where the wind site is located is dependent on various factors including future government incentives for wind projects, energy policy and legislation including federal and state renewable energy standards and regulation of carbon emissions, electricity and fossil fuel prices, transmission constraints in the region where the wind site is located and further technological advancements for wind generation. WPL currently believes, based on a combination of the various factors, further wind development in the region where the wind site is located will occur. WPL could realize an impairment related to this wind site if one or more of these factors are no longer expected to occur, or actions by regulatory agencies with jurisdiction over WPL indicate the costs of the undeveloped wind site would not be approved to be recovered from customers.

Regulated Operations—Long-lived assets within regulated operations are reviewed for possible impairment whenever events or changes in circumstances indicate all or a portion of the carrying value of the assets may be disallowed for rate-making purposes. If WPL is disallowed recovery of any portion of the carrying value of its regulated property, plant and equipment,

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an impairment charge is recognized equal to the amount of the carrying value that was disallowed. If WPL is disallowed a full or partial return on the carrying value of its regulated property, plant and equipment, an impairment charge is recognized equal to the difference between the carrying amount of the asset and the present value of the future revenues expected from its regulated property, plant and equipment. WPL’s long-lived assets that may not be fully recovered from customers that were assessed in 2011 included generating units subject to early retirement.

Generating Units Subject to Early Retirement—Due to current and proposed environmental regulations including, among others, the Utility MACT Rule issued by the EPA in December 2011 and CSAPR issued by the EPA in July 2011, WPL is evaluating future plans for its electric generation fleet. One of the outcomes of the evaluation could be the early retirement of certain older and less-efficient EGUs. When it becomes probable that an EGU will be retired before the end of its useful life, WPL must assess whether it is probable that less than full recovery will be provided by its regulators on the remaining carrying value of the EGU. If it is probable that regulators will not allow full recovery of and a return on the remaining carrying amount of the asset, an impairment charge is recorded for the portion of the remaining carrying value that is disallowed recovery. WPL completed an evaluation of its EGUs that are being assessed for early retirement in 2011 and concluded no impairment charges were required as of Dec. 31, 2011. Changes in the probability of regulators allowing full recovery of and return on the remaining carrying amount of these EGUs could result in future material impairments.

Unbilled Revenues—Energy sales to individual customers are based on the reading of customers’ meters, which occurs on a systematic basis throughout the month. Amounts of energy delivered to customers since the date of the last meter reading are estimated at the end of each reporting period and the corresponding estimated unbilled revenue is recorded. The unbilled revenue estimate is based on daily system demand volumes, estimated customer usage by class, weather impacts, line losses and the most recent customer rates. Such process involves the use of various judgments and assumptions and significant changes in these judgments and assumptions could have a material impact on WPL’s results of operations. As of Dec. 31, 2011, WPL’s unbilled revenues were $75 million.

Pensions and Other Postretirement Benefits—WPL sponsors various defined benefit pension and other postretirement benefits plans that provide benefits to a significant portion of its employees. WPL makes assumptions and judgments periodically to estimate the obligations and costs related to its retirement plans. There are many judgments and assumptions involved in determining an entity’s pension and other postretirement liabilities and costs each period including employee demographics (including age, life expectancies and compensation levels), discount rates, assumed rate of returns and funding. Changes made to the plan provisions may also impact current and future benefits costs. Judgments and assumptions are supported by historical data and reasonable projections and are reviewed at least annually. As of Dec. 31, 2011 (the most recent measurement date), future assumptions for WPL included the following:

	Defined Benefit Pension Plans			Other Postretirement Benefits Plans
Discount rate to calculate benefit obligations (a)		4.95	%		4.6	%
Future annual expected rate of return on plan assets (b)		7.9	%		6.3	%

(a) In selecting an assumed discount rate, management reviews various corporate Aa bonds in an investment portfolio, which provides for the plans’ projected benefit payments over their remaining expected period.

(b) Future annual expected rates of return on plan assets are based on projected long-term equity and bond returns, maturities and asset allocations.

The following table shows WPL’s impacts of changing certain key actuarial assumptions discussed above (in millions):

	Defined Benefit Pension Plans				Other Postretirement Benefits Plans
Change in Actuarial Assumption	Impact on Projected Benefit Obligation at Dec. 31, 2011		Impact on 2012 Net Periodic Benefit Costs		Impact on Projected Benefit Obligation at Dec. 31, 2011		Impact on 2012 Net Periodic Benefit Costs
1% change in discount rate	$	57	$	4	$	8	$	1
1% change in expected rate of return		—		4		—		—
1% change in medical trend rates		—		—		1		—

Note 6(a) of the “Notes to Consolidated Financial Statements” provides additional details of pension and other postretirement benefits plans. Note 13(c) of the “Notes to Consolidated Financial Statements” provides recent developments of the class action lawsuit filed against the Cash Balance Plan in 2008 and details of an amendment to the Cash Balance Plan in 2011 to comply with a settlement agreement reached with the IRS, which resulted in a favorable determination letter for the Plan.

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Income Taxes—WPL is subject to income taxes in various jurisdictions. WPL makes assumptions and judgments each reporting period to estimate its income tax assets, liabilities, benefits and expenses. Judgments and assumptions are supported by historical data and reasonable projections. Significant changes in these judgments and assumptions could have a material impact on WPL’s financial condition and results of operations. WPL’s critical assumptions and judgments for 2011 include projections of its future taxable income used to determine its ability to utilize loss and credit carryforwards prior to their expiration, state apportionment projections and the interpretation of tax laws regarding uncertain tax positions.

Carryforward Utilization—Note 5 of the “Notes to Consolidated Financial Statements” provides discussion of carryforwards. Changes in assumptions regarding WPL’s future taxable income could require valuation allowances in the future resulting in a material impact on its financial condition and results of operations.

State Apportionment—WPL utilizes state apportionment projections to record its deferred tax assets and liabilities each reporting period. Deferred tax assets and liabilities for temporary differences between the tax basis of assets and liabilities and the amounts reported in the consolidated financial statements are recorded utilizing currently enacted tax rates and estimates of future state apportionment rates expected to be in effect at the time the temporary differences reverse. These state apportionment projections are most significantly impacted by the estimated amount of revenues expected in the future from each state jurisdiction for Alliant Energy’s consolidated tax group, including both its regulated operations and its non-regulated operations. A significant change in the forecasted amount of revenues from each state jurisdiction for Alliant Energy’s consolidated tax group could have a material impact on WPL’s deferred tax assets and liabilities. WPL may record approximately $7 million of income tax expense in 2012 due to changes in state apportionment projections caused by Alliant Energy’s planned sale of the RMT business.

Refer to Notes 1(c) and 5 of the “Notes to Consolidated Financial Statements” for further discussion of regulatory accounting for taxes and details of uncertain tax positions, respectively.

Other Future Considerations—In addition to items discussed earlier in MDA and in the “Notes to Consolidated Financial Statements,” the following items could impact WPL’s future financial condition or results of operations:

Electric Transmission Service Charges—

MISO Transmission Cost Allocation—In July 2010, MISO filed a proposed revised tariff with FERC for a new category of transmission projects called Multi-Value Projects (MVPs). MVPs include new large scale transmission projects that enable the reliable and economic delivery of energy in support of documented energy policy mandates or provide economic value across multiple pricing zones within MISO. The MVP category is intended to facilitate the integration of large amounts of location-constrained resources including renewable resources, support MISO member and customer compliance with evolving state and federal energy policy requirements, enable MISO to address multiple reliability needs and provide economic opportunities through regional transmission development. The proposed revised tariff would allow certain costs of MVPs to be socialized across the entire MISO footprint based on energy usage by the MISO participants to ensure that areas within the MISO footprint that have large amounts of generation and a small share of load are not allocated a disproportionate amount of the costs for MVPs. In December 2010, FERC conditionally approved MISO’s proposal for the MVP transmission cost allocation. In July 2011, MISO submitted a compliance filing, which FERC conditionally approved in October 2011, and also requested that MISO submit additional compliance filings. WPL is currently unable to determine the ultimate impact that the revised tariff may have on its financial condition and results of operation, but believes the outcome could be material to its future electric transmission service expense.

Government Incentives for Wind Projects—WPL’s generation plans have included building wind projects to produce electricity to meet customer demand and renewable portfolio standards. In addition to producing electricity, these wind projects may also generate material incentives depending on when they are placed in service. The American Recovery and Reinvestment Act (ARRA) enacted in 2009 provided incentives to owners of wind projects placed into service between Jan. 1, 2009 and Dec. 31, 2012. The incentive options available to qualified wind projects under the ARRA include production tax credits for a 10-year period based on the electricity output generated by the wind project, an investment tax credit equal to 30% of the qualified cost basis of the wind project, or a government grant equal to 30% of the qualified cost basis of wind projects that began construction in 2009 and 2010. In 2010, the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 modified the requirements for the government grant incentive. The government grant incentive is now available for qualified wind projects that began construction in 2009, 2010 and 2011 and are placed into service by Dec. 31, 2012.

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WPL’s generation plan has two wind projects that currently qualify for one of the government incentives. The two wind projects are the Cedar Ridge wind project (68 MW capacity) that began generating electricity in late 2008 and the Bent Tree—Phase I wind project (200 MW capacity) that began generating electricity in late 2010. Based on an evaluation of the most beneficial alternative for customers, WPL chose to recognize production tax credits for the two eligible wind projects that are already generating electricity.

In December 2011, the NDAA was enacted. As a result, utilities are no longer subject to a tax normalization violation if they provide the benefits of the government grant incentive to their customers over a shorter time period than the regulatory life of the project assets. This provision of the NDAA can be applied retroactively to renewable energy projects placed into service since 2009. As a result of the enactment of NDAA, WPL is currently re-evaluating its options for government incentive elections for the Bent Tree—Phase I wind project. Refer to “Legislative Matters” for further discussion of the NDAA.

Production Tax Credits—As stated above, WPL is currently re-evaluating its options for the governmental incentive elections as a result of the NDAA. If WPL decides not to pursue a retroactive election of the government grant incentive, it will continue to earn production tax credits for its wind projects already generating electricity. The amount of production tax credits earned is dependent on the level of electricity output generated by each wind project, which is impacted by a variety of operating and economic parameters including transmission availability. Any incentives for WPL’s wind projects are expected to be utilized in determining customers’ rates. Production tax credits earned in 2009, 2010 and 2011, along with estimates of production tax credits currently expected to be earned in 2012, for these wind projects are as follows (in millions):

	2009		2010		2011		2012
Cedar Ridge	$	4	$	3	$	5	$	3 - $  4
Bent Tree—Phase I		—		1		9		11 - 12
	$	4	$	4	$	14	$	14 - $16

ATC—In April 2011, Duke Energy Corporation and ATC announced the creation of Duke-American Transmission Co. (DATC), a joint venture that is expected to build, own and operate new electric transmission infrastructure in North America. In September 2011, DATC announced its first set of transmission projects, which include seven new transmission lines in five Midwestern states to be constructed over the next 10 years for an aggregate cost of approximately $4 billion. These transmission projects are subject to approval by various regulatory agencies. WPL currently owns a 16% ownership interest in ATC. WPL’s investment in ATC generated equity income of $38 million and cash distributions of $31 million in 2011 for WPL. WPL is currently unable to determine what impacts the joint venture and transmission line projects noted above will have on its future equity income, distributions from ATC, capital contributions to ATC, or ownership in ATC.

Incentive Compensation Plans—Alliant Energy’s total compensation package includes an incentive compensation program, which provides substantially all of Alliant Energy’s non-bargaining employees an opportunity to receive annual short-term incentive cash payments based on the achievement of specific annual operational and financial performance measures. The operational performance measures for 2012 relate to diversity, safety, customer satisfaction, service reliability and the availability of certain generating facilities. The financial performance measures for 2012 relate to utility earnings per share from continuing operations and cash flows from operations generated by WPL, IPL and Corporate Services, as adjusted pursuant to the terms of the Alliant Energy 2010 Omnibus Incentive Plan. In addition, the total compensation program for certain key employees includes long-term incentive awards issued under an equity incentive plan. Alliant Energy allocates a portion of incentive compensation plan costs to WPL. Refer to “Results of Operations—Other Operation and Maintenance Expenses” for discussion of higher incentive-related compensation expenses in 2010 and Note 6(b) of the “Notes to Consolidated Financial Statements” for additional discussion of long-term incentive awards. WPL is currently unable to determine what impacts these incentive compensation plans will have on its future financial condition or results of operations.

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MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Wisconsin Power and Light Company and subsidiaries (WPL) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. WPL’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.

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

WPL’s management assessed the effectiveness of WPL’s internal control over financial reporting as of December 31, 2011 using the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, WPL’s management concluded that, as of December 31, 2011, WPL’s internal control over financial reporting was effective.

/s/ William D. Harvey

William D. Harvey

Chairman and Chief Executive Officer

/s/ Thomas L. Hanson

Thomas L. Hanson

Vice President and Chief Financial Officer

/s/ Robert J. Durian

Robert J. Durian

Controller and Chief Accounting Officer

February 27, 2012

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareowners of Wisconsin Power and Light Company

Madison, Wisconsin

We have audited the accompanying consolidated balance sheets of Wisconsin Power and Light Company and subsidiaries (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 the 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 the Company as of December 31, 2011 and 2010, and the results of its operations and its 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.

/s/ DELOITTE & TOUCHE LLP

Milwaukee, Wisconsin

February 27, 2012

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CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
	2011			2010			2009
	(in millions)
Operating revenues:
Electric utility	$	1,227.5		$	1,209.9		$	1,160.3
Gas utility		200.4			206.3			216.5
Other		6.5			7.4			9.3
Total operating revenues		1,434.4			1,423.6			1,386.1
Operating expenses:
Electric production fuel and energy purchases		381.4			401.2			451.3
Purchased electric capacity		109.5			134.7			144.6
Electric transmission service		104.6			100.4			94.2
Cost of gas sold		119.6			125.3			138.1
Other operation and maintenance		255.2			232.7			234.3
Depreciation and amortization		140.1			108.6			115.4
Taxes other than income taxes		43.6			41.9			41.2
Total operating expenses		1,154.0			1,144.8			1,219.1
Operating income		280.4			278.8			167.0
Interest expense and other:
Interest expense		79.9			78.6			74.8
Equity income from unconsolidated investments		(38.7	)		(37.8	)		(37.0	)
Allowance for funds used during construction		(6.2	)		(12.5	)		(5.7	)
Interest income and other		—			(0.1	)		(0.4	)
Total interest expense and other		35.0			28.2			31.7
Income before income taxes		245.4			250.6			135.3
Income taxes		81.9			98.3			45.8
Net income		163.5			152.3			89.5
Preferred dividend requirements		3.3			3.3			3.3
Earnings available for common stock	$	160.2		$	149.0		$	86.2

Earnings per share data is not disclosed given Alliant Energy Corporation is the sole shareowner of all shares of WPL’s common stock outstanding during the periods presented.

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

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CONSOLIDATED BALANCE SHEETS

	December 31,
ASSETS	2011			2010
	(in millions)
Property, plant and equipment:
Electric plant in service	$	3,481.4		$	3,114.6
Gas plant in service		424.7			411.4
Other plant in service		228.8			219.0
Accumulated depreciation		(1,372.2	)		(1,243.8	)
Net plant		2,762.7			2,501.2
Leased Sheboygan Falls Energy Facility, less accumulated amortization of $40.6 and $34.4		83.2			89.4
Construction work in progress:
Edgewater Generating Station Unit 5 emission controls		77.7			17.2
Bent Tree—Phase I wind project		—			154.5
Other		82.9			63.8
Other, less accumulated depreciation of $1.3 and $2.2		15.1			20.0
Total property, plant and equipment		3,021.6			2,846.1
Current assets:
Cash and cash equivalents		2.7			0.1
Accounts receivable:
Customer, less allowance for doubtful accounts		76.2			84.2
Unbilled utility revenues		75.1			82.3
Other, less allowance for doubtful accounts		38.2			38.1
Income tax refunds receivable		0.7			40.6
Production fuel, at weighted average cost		34.2			42.7
Materials and supplies, at weighted average cost		25.7			25.7
Gas stored underground, at weighted average cost		32.2			26.8
Regulatory assets		44.6			50.0
Prepaid gross receipts tax		40.2			38.6
Prepayments and other		16.2			15.9
Total current assets		386.0			445.0
Investments:
Investment in American Transmission Company LLC		238.8			227.9
Other		19.8			20.8
Total investments		258.6			248.7
Other assets:
Regulatory assets		333.1			292.1
Deferred charges and other		44.7			57.7
Total other assets		377.8			349.8
Total assets	$	4,044.0		$	3,889.6

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

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CONSOLIDATED BALANCE SHEETS (Continued)

	December 31,
CAPITALIZATION AND LIABILITIES	2011		2010
	(in millions, except per share and share amounts)
Capitalization:
Wisconsin Power and Light Company common equity:
Common stock—$5 par value—18,000,000 shares authorized; 13,236,601 shares outstanding	$	66.2	$	66.2
Additional paid-in capital		869.0		844.0
Retained earnings		507.2		459.1
Total Wisconsin Power and Light Company common equity		1,442.4		1,369.3
Cumulative preferred stock		60.0		60.0
Long-term debt, net		1,082.2		1,081.7
Total capitalization		2,584.6		2,511.0
Current liabilities:
Commercial paper		25.7		47.4
Accounts payable		98.5		118.5
Accounts payable to associated companies		20.5		16.0
Regulatory liabilities		27.6		17.9
Accrued interest		21.6		21.6
Derivative liabilities		31.4		32.3
Other		32.3		38.9
Total current liabilities		257.6		292.6
Other long-term liabilities and deferred credits:
Deferred income taxes		672.5		570.4
Regulatory liabilities		161.2		154.3
Capital lease obligations—Sheboygan Falls Energy Facility		103.3		107.0
Pension and other benefit obligations		128.0		119.2
Other		136.8		135.1
Total long-term liabilities and deferred credits		1,201.8		1,086.0
Commitments and contingencies (Note 13)
Total capitalization and liabilities	$	4,044.0	$	3,889.6

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2011			2010			2009
	(in millions)
Cash flows from operating activities:
Net income	$	163.5		$	152.3		$	89.5
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		140.1			108.6			115.4
Other amortizations		42.4			39.5			35.2
Deferred tax expense and investment tax credits		93.7			98.5			157.7
Equity income from unconsolidated investments		(38.7	)		(37.8	)		(37.0	)
Distributions from equity method investments		32.3			32.2			29.9
Equity component of allowance for funds used during construction		(4.1	)		(8.2	)		(4.0	)
Non-cash valuation charges and other		10.8			—			12.5
Other changes in assets and liabilities:
Accounts receivable		9.8			4.6			31.3
Income tax refunds receivable		39.9			40.7			(72.9	)
Regulatory assets		(84.3	)		28.7			(54.2	)
Regulatory liabilities		12.0			(9.1	)		(22.2	)
Derivative liabilities		1.1			(23.0	)		51.5
Non-current taxes payable		(0.3	)		(38.5	)		36.2
Pension and other benefit obligations		8.8			(2.5	)		(63.4	)
Other		1.8			(13.6	)		0.3
Net cash flows from operating activities		428.8			372.4			305.8
Cash flows used for investing activities:
Utility construction and acquisition expenditures:
Neenah Energy Facility and related assets		—			—			(92.4	)
Other		(314.4	)		(450.5	)		(416.0	)
Advances for customer energy efficiency projects		(5.1	)		(16.0	)		(28.1	)
Collections of advances for customer energy efficiency projects		26.8			30.3			58.6
Other		(12.7	)		(13.1	)		(15.5	)
Net cash flows used for investing activities		(305.4	)		(449.3	)		(493.4	)
Cash flows from (used for) financing activities:
Common stock dividends		(112.1	)		(109.5	)		(91.0	)
Preferred stock dividends		(3.3	)		(3.3	)		(3.3	)
Capital contributions from parent		25.0			75.0			100.0
Proceeds from issuance of long-term debt		—			150.0			250.0
Payments to retire long-term debt		—			(100.0	)		—
Net change in short-term borrowings		(21.7	)		47.4			(43.7	)
Other		(8.7	)		(1.1	)		(10.4	)
Net cash flows from (used for) financing activities		(120.8	)		58.5			201.6
Net increase (decrease) in cash and cash equivalents		2.6			(18.4	)		14.0
Cash and cash equivalents at beginning of period		0.1			18.5			4.5
Cash and cash equivalents at end of period	$	2.7		$	0.1		$	18.5
Supplemental cash flows information:
Cash paid (refunded) during the period for:
Interest	$	79.9		$	80.9		$	69.6
Income taxes, net of refunds	($	51.3	)	($	3.8	)	($	76.1	)
Significant noncash investing and financing activities:
Accrued capital expenditures	$	19.7		$	27.4		$	16.4

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

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CONSOLIDATED STATEMENTS OF COMMON EQUITY

	Common Stock		Additional Paid-In Capital		Retained Earnings			Total WPL Common Equity
	(in millions)
2009:
Beginning balance	$	66.2	$	668.9	$	424.4		$	1,159.5
Earnings available for common stock						86.2			86.2
Common stock dividends						(91.0	)		(91.0	)
Capital contribution from parent				100.0					100.0
Ending balance		66.2		768.9		419.6			1,254.7
2010:
Earnings available for common stock						149.0			149.0
Common stock dividends						(109.5	)		(109.5	)
Capital contribution from parent				75.0					75.0
Other				0.1					0.1
Ending balance		66.2		844.0		459.1			1,369.3
2011:
Earnings available for common stock						160.2			160.2
Common stock dividends						(112.1	)		(112.1	)
Capital contribution from parent				25.0					25.0
Ending balance	$	66.2	$	869.0	$	507.2		$	1,442.4

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) General—

Description of Business—The consolidated financial statements include the accounts of Wisconsin Power and Light Company (WPL) and its consolidated subsidiary, WPL Transco LLC, which holds WPL’s investment in the American Transmission Company LLC (ATC). WPL is a direct subsidiary of Alliant Energy Corporation (Alliant Energy) and is engaged principally in the generation and distribution of electricity and the distribution and transportation of natural gas. WPL’s service territories are located in southern and central Wisconsin.

Basis of Presentation—The consolidated financial statements reflect investments in controlled subsidiaries on a consolidated basis and WPL’s proportionate share of jointly owned utility facilities. Unconsolidated investments, which WPL does not control, but does have the ability to exercise significant influence over operating and financial policies, are accounted for under the equity method of accounting. Investments that do not meet the criteria for consolidation or the equity method of accounting are accounted for under the cost method. WPL did not reflect any variable interest entities on a consolidated basis in its consolidated financial statements. Refer to Notes 10(a) and 19 for further discussion of equity method investments and variable interest entities, respectively.

All intercompany balances and transactions have been eliminated from the consolidated financial statements. The consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (U.S.) (GAAP), which give recognition to the rate making and accounting practices of the Federal Energy Regulatory Commission (FERC) and the Public Service Commission of Wisconsin (PSCW). Certain prior period amounts have been reclassified on a basis consistent with the current period financial statement presentation.

Use of Estimates—The preparation of the consolidated financial statements requires management to make estimates and assumptions that affect: a) the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements; and b) the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

(b) Regulatory Assets and Liabilities—WPL is subject to regulation by FERC and the PSCW. As a result, WPL is subject to GAAP provisions for regulated operations, which provide that rate-regulated public utilities record certain costs and credits allowed in the rate making process in different periods than for non-regulated entities. These are deferred as regulatory assets or accrued as regulatory liabilities and are generally recognized in the Consolidated Statements of Income at the time they are reflected in rates.

Regulatory Assets—At Dec. 31, regulatory assets were comprised of the following items (in millions):

	2011		2010
Pension and other postretirement benefits costs	$	249.2	$	201.5
Derivatives		44.2		42.8
Tax-related		20.1		18.7
Asset retirement obligations (AROs)		17.2		16.4
Proposed clean air compliance projects costs		8.0		8.4
Debt redemption costs		6.7		7.2
Environmental-related costs		6.7		6.3
Proposed base-load project costs		6.2		8.4
Wholesale customer rate recovery		2.7		7.9
Other		16.7		24.5
	$	377.7	$	342.1

A portion of the regulatory assets in the above table are not earning a return. These regulatory assets are expected to be recovered from customers in future rates, however the carrying costs of these assets are borne by WPL. At Dec. 31, 2011, WPL had $8 million of regulatory assets representing past expenditures that were not earning a return, which consisted primarily of amounts related to wholesale customer rate recovery and the wholesale portion of costs for clean air compliance projects. The other regulatory assets reported in the above table either earn a return or the cash has not yet been expended, in which case the assets are offset by liabilities that also do not incur a carrying cost.

Pension and other postretirement benefits costs—The PSCW has authorized WPL to record the retail portion of its previously unrecognized net actuarial gains and losses, prior service costs and credits, and transition assets and obligations as

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regulatory assets in lieu of accumulated other comprehensive loss on the Consolidated Balance Sheets. WPL also recognizes the wholesale portion of its previously unrecognized net actuarial gains and losses, prior service costs and credits and transition assets and obligations as regulatory assets on the Consolidated Balance Sheets because these costs are expected to be recovered in rates in future periods under the formula rate structure. These regulatory assets will be increased or decreased as the net actuarial gains or losses, prior service costs or credits, and transition assets or obligations are subsequently amortized and recognized as a component of net periodic benefit costs.

Pension and other postretirement benefits costs are included within the recoverable cost of service component of rates charged to WPL’s customers. The recoverable costs included in customers’ rates are based upon pension and other postretirement benefits costs determined in accordance with GAAP and are calculated using different methods for the various regulatory jurisdictions in which WPL operates. The methods for WPL’s primary regulatory jurisdictions are described below. The PSCW authorized WPL to recover from its electric and gas retail customers an estimated allocated portion of the 2010 annual costs in base rates. WPL is authorized to recover from its wholesale customers an allocated portion of actual pension costs incurred each year. In accordance with FERC-approved formula rates, any over- or under-collection of these costs each year are refunded to or recovered from customers through subsequent changes to wholesale customer rates. WPL is authorized to recover from its wholesale customers an allocated portion of other postretirement benefits costs based on the amount of other postretirement benefits costs incurred in 2006.

Refer to Note 6(a) for additional details regarding WPL’s pension and other postretirement benefits costs, including a plan amendment and remeasurement.

Derivatives—In accordance with WPL’s fuel and natural gas recovery mechanisms, prudently incurred costs from derivative instruments are recovered from customers in the future after any losses are realized. Based on these recovery mechanisms, the changes in the fair value of derivative liabilities resulted in comparable changes to regulatory assets on the Consolidated Balance Sheet in 2011. Refer to Note 12 for additional details of WPL’s derivative liabilities.

Tax-related—WPL records regulatory assets for certain temporary differences that result in a decrease in current rates charged to customers and an increase in future rates charged to customers based on the timing of income tax expense that is used to determine such rates.

AROs—WPL believes it is probable that any differences between expenses accrued for legal AROs related to its regulated operations and expenses recovered currently in rates will be recoverable in future rates, and is deferring the differences as regulatory assets. Refer to Note 18 for additional details of WPL’s AROs.

Proposed clean air compliance plan (CACP) projects costs—CACP projects require material expenditures for activities related to determining the feasibility of environmental compliance projects under consideration. These expenditures are commonly referred to as preliminary survey and investigation charges. The wholesale portion of these amounts is recorded as regulatory assets on the Consolidated Balance Sheets in accordance with FERC regulations. The retail portion of these amounts is expensed immediately unless otherwise authorized by the PSCW. However, since these amounts are material for WPL’s CACP projects, WPL requested and received deferral accounting approval to record the retail portion of these costs as regulatory assets on the Consolidated Balance Sheets.

The wholesale portion of amounts deferred and recorded as preliminary survey and investigation charges do not include any accrual of carrying costs or allowance for funds used during construction (AFUDC). WPL’s retail portion of deferred preliminary survey and investigation charges (commonly referred to as pre-certification expenditures) and construction expenditures incurred prior to project approval that are recorded in regulatory assets include accrual of carrying costs as prescribed in the approved deferral order. Upon regulatory approval of the project, the wholesale portion of deferred preliminary survey and investigation charges as well as all pre-construction expenditures are transferred to construction work in progress (CWIP) and begin to accrue AFUDC. The retail portion of deferred preliminary survey and investigation charges or pre-certification expenditures remain as regulatory assets until they are approved for inclusion in revenue requirements and amortized to expense. In 2009, WPL received approval from the PSCW to recover $4 million from its retail customers over a three-year period ending December 2012 for a portion of the pre-certification expenditures incurred through December 2008.

WPL anticipates that all remaining costs for proposed CACP projects are probable of recovery from future rates charged to customers. The recovery period for these remaining costs will generally be determined by regulators in future rate proceedings.

Debt redemption costs—For debt retired early with no subsequent re-issuance, WPL defers any debt repayment premiums and unamortized debt issuance costs and discounts as regulatory assets. These regulatory assets are amortized over the

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remaining original life of the debt retired early. Debt repayment premiums and other losses resulting from the refinancing of debt are deferred as regulatory assets and amortized over the life of the new debt issued.

Environmental-related costs—Under the current rate making treatment approved by the PSCW, the manufactured gas plants (MGP) expenditures of WPL are deferred and collected from retail gas customers over a five-year period after new rates are implemented. Regulatory assets have been recorded by WPL, which reflect the probable future rate recovery of MGP expenditures. Refer to Note 13(d) for additional details of WPL’s environmental-related MGP costs.

Proposed base-load project costs—In 2008, the PSCW issued an order denying WPL’s application to construct a 300 megawatt (MW) coal-fired electric generating facility in Cassville, Wisconsin referred to as Nelson Dewey #3. In 2009, WPL received approval from the PSCW to recover $11 million of project costs from its retail customers over a five-year period ending December 2014. WPL amortized $2 million of this regulatory asset in each of 2011 and 2010. In 2009, the PSCW also denied WPL recovery of the remaining project costs, which represent all project costs incurred by WPL after June 2008 and one-half of the pre-construction project costs incurred by WPL prior to July 2008. As a result of this PSCW order, WPL recorded a pre-tax regulatory-related charge of $11 million in “Other operation and maintenance” in the Consolidated Statement of Income in 2009.

Wholesale customer rate recovery—WPL accrues revenues from its wholesale customers to the extent that the actual net revenue requirements calculated in accordance with FERC-approved formula rates for the reporting period are higher than the amounts billed to wholesale customers during such period. In accordance with authoritative guidance, regulatory assets are recorded as the offset for these accrued revenues under formulaic rate making programs. WPL’s estimated recovery amount is recorded in the current period of service and subject to final adjustments after a customer audit period in the subsequent year. Final settled recovery amounts are reflected in WPL’s customer bills within two years under the provisions of approved formula rates.

In 2009, WPL filed a request with FERC seeking approval of changes to WPL’s wholesale formula rates in order to implement for billing purposes the full impact of accounting for defined benefit postretirement plans. In 2010, FERC approved a settlement agreement reached between WPL and the wholesale customers regarding the formula rate change. In 2010, WPL recorded an additional $4 million of electric revenues and regulatory assets to reflect the settlement and is reducing the regulatory asset concurrently with collections from customers.

Other—WPL assesses whether its regulatory assets are probable of future recovery by considering factors such as applicable regulations, recent orders by the applicable regulatory agencies, historical treatment of similar costs by the applicable regulatory agencies and regulatory environment changes. Based on these assessments, WPL believes the regulatory assets recognized as of Dec. 31, 2011 in the above table are probable of future recovery. However, no assurance can be made that WPL will recover all of these regulatory assets in future rates. If future recovery of a regulatory asset ceases to be probable, the regulatory asset will be charged to expense in the period in which future recovery ceases to be probable. Based on assessments completed in 2011, WPL recognized impairment charges of $7 million for regulatory assets that are no longer probable of future recovery. The regulatory asset impairment charges were recorded by WPL as reductions in “Regulatory assets” on its Consolidated Balance Sheet and charges to “Other operation and maintenance” in its Consolidated Statement of Income in 2011.

Regulatory Liabilities—At Dec. 31, regulatory liabilities were comprised of the following items (in millions):

	2011		2010
Cost of removal obligations	$	143.0	$	137.8
Energy conservation cost recovery		24.9		6.9
Commodity cost recovery		0.6		5.2
Other		20.3		22.3
	$	188.8	$	172.2

Regulatory liabilities related to cost of removal obligations, to the extent expensed through depreciation rates, reduce rate base. A significant portion of the remaining regulatory liabilities are not used to reduce rate base in the revenue requirement calculations utilized in WPL’s rate proceedings.

Cost of removal obligations—WPL collects in rates future removal costs for many assets that do not have associated legal AROs. WPL records a regulatory liability for the estimated amounts it has collected in rates for these future removal costs less amounts spent on removal activities.

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Energy conservation cost recovery—WPL collects revenues from its customers to offset certain expenditures incurred by WPL for conservation programs, including state mandated programs and WPL’s Shared Savings program. Differences between forecasted costs used to set rates and actual costs for these programs are deferred as a regulatory asset or regulatory liability. In 2011, WPL’s forecasted costs used to set current rates exceeded actual costs for these programs, resulting in a $18 million increase to the “Energy conservation cost recovery” regulatory liability.

Commodity cost recovery—WPL’s wholesale electric rates and retail gas rates provide for subsequent adjustments to rates for changes in prudently incurred commodity costs used to serve customers. The cumulative under-/over-collection of these commodity costs are recorded as regulatory assets/regulatory liabilities until they are automatically reflected in future billings to customers. Refer to Note 1(h) for additional details of WPL’s cost recovery mechanisms. Refer to Note 2 for discussion of certain rate refund reserves recorded as regulatory liabilities on the Consolidated Balance Sheets.

(c) Income Taxes—WPL follows the liability method of accounting for deferred income taxes, which requires the establishment of deferred income tax assets and liabilities, as appropriate, for temporary differences between the tax basis of assets and liabilities and the amounts reported in the consolidated financial statements. Deferred income taxes are recorded using currently enacted tax rates and estimates of state apportionment rates. The PSCW has allowed rate recovery of deferred taxes on all temporary differences since 1991.

WPL recognizes positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. If it is more-likely-than-not that a tax position, or some portion thereof, will not be sustained, the related tax benefits are not recognized in the financial statements. For the majority of uncertain tax positions, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility. Uncertain tax positions may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Generally WPL recognizes current taxes payable related to uncertain tax positions in “Other current liabilities” and non-current taxes payable related to uncertain tax positions in “Other long-term liabilities and deferred credits” on the Consolidated Balance Sheets. However, if the uncertain tax position would be settled through the reduction of a net operating loss rather than through the payment of cash, the uncertain tax position is reflected in “Deferred income taxes” on the Consolidated Balance Sheets. Refer to Note 5 for further discussion of uncertain tax positions.

WPL defers investment tax credits and amortizes the credits to income over the average lives of the related property. Other tax credits for WPL reduce income tax expense in the year claimed.

WPL has elected the alternative transition method to calculate its beginning pool of excess tax benefits available to absorb any tax deficiencies associated with recognition of share-based payment awards.

(d) Cash and Cash Equivalents—Cash and cash equivalents include short-term liquid investments that have original maturities of less than 90 days.

(e) Utility Property, Plant and Equipment—

General—Plant in service is recorded at the original cost of acquisition or construction, which includes material, labor, contractor services, AFUDC and allocable overheads, such as supervision, engineering, benefits, certain taxes and transportation. Repairs, replacements and renewals of items of property determined to be less than a unit of property or that do not increase the property’s life or functionality are charged to maintenance expense. Ordinary retirements of plant in service and salvage value are netted and charged to accumulated depreciation upon removal from plant in service accounts and no gain or loss is recognized. Removal costs incurred reduce the regulatory liability.

Electric Plant In Service—Electric plant in service by functional category at Dec. 31 was as follows (in millions):

	2011		2010
Generation	$	1,708.3	$	1,431.2
Distribution		1,707.3		1,621.5
Other		65.8		61.9
	$	3,481.4	$	3,114.6

During 2011, the increase in WPL’s generation portion of electric plant in service was primarily due to the impact of placing the remaining portion of the Bent Tree—Phase I wind project into service and the purchase of Wisconsin Electric Power Company’s (WEPCO’s) 25% ownership interest in Edgewater Unit 5.

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Wind Generation Projects—

Wind Site in Freeborn County, Minnesota—In 2009, WPL acquired approximately 400 MW of wind site capacity in Freeborn County, Minnesota. The initial 200 MW of the wind site was utilized to construct the Bent Tree—Phase I wind project, which began generating electricity in 2010. Future development of the balance of the wind site will depend on numerous factors such as renewable portfolio standards, environmental legislation, fossil fuel prices, technology advancements and transmission capabilities. As of Dec. 31, 2011, WPL’s capitalized costs related to the remaining approximately 200 MW of wind site capacity in Freeborn County, Minnesota were $13 million and were recorded in “Other property, plant and equipment” on the Consolidated Balance Sheet.

Bent Tree—Phase I Wind Project—In 2009, WPL received approval from the Minnesota Public Utilities Commission and the PSCW to construct the 200 MW Bent Tree—Phase I wind project. WPL incurred capitalized expenditures of $435 million and recognized $14 million of AFUDC for the wind project. In 2010, WPL placed $265 million of the wind project into service. In 2011, WPL placed the remaining portion of the wind project into service, which resulted in a transfer of $184 million of capitalized project costs from “Construction work in progress—Bent Tree—Phase I wind project” to “Electric plant in service” on the Consolidated Balance Sheets in 2011. At Dec. 31, 2011, the capitalized project costs for the Bent Tree—Phase I wind project of $449 million were recorded in “Electric plant in service” on the Consolidated Balance Sheet. The capitalized costs for the wind project are being depreciated using a straight-line method of depreciation over a 30-year period. Refer to Note 18 for discussion of AROs recorded by WPL in 2010 related to its Bent Tree—Phase I wind project.

Wind Site in Green Lake and Fond du Lac Counties in Wisconsin—In 2009, WPL purchased development rights to an approximate 100 MW wind site in Green Lake and Fond du Lac Counties in Wisconsin. Due to events in 2011 resulting in uncertainty regarding wind siting requirements in Wisconsin and increased risks with permitting this wind site, WPL determined it would be difficult to sell or effectively use the site for wind development. As a result, WPL recognized a $5 million impairment in 2011 for the amount of capitalized costs incurred for this site. The impairment was recorded as a reduction to “Other property, plant and equipment” on the Consolidated Balance Sheet and a charge to “Other operation and maintenance” in the Consolidated Statement of Income in 2011.

Environmental Compliance Plans Project—

Edgewater Unit 5 Emission Controls Project—WPL is currently installing a selective catalytic reduction (SCR) system at Edgewater Unit 5 to reduce nitrogen oxide (NOx) emissions at the generating facility. Construction began in the third quarter of 2010 and is expected to be completed prior to May 2013 when additional NOx emission reductions at Edgewater are required for WPL to comply with Wisconsin Reasonably Available Control Technology Rule compliance deadlines. As of Dec. 31, 2011, WPL recorded capitalized expenditures of $75 million and AFUDC of $3 million for the SCR system in “Construction work in progress—Edgewater Generating Station Unit 5 emission controls” on the Consolidated Balance Sheet.

Coal-fired Generation Project—

Edgewater Unit 5 Purchase—In March 2011, WPL purchased WEPCO’s 25% ownership interest in Edgewater Unit 5 for $38 million. The $38 million was equal to WEPCO’s net book value of the facility and related assets at the time of the purchase. WPL now owns 100% of Edgewater Unit 5. As of the closing date, the carrying values of the assets purchased were as follows (in millions):

Electric plant in service	$	84
Accumulated depreciation		(50	)
CWIP		2
Production fuel		1
Materials and supplies		1
	$	38

Depreciation—WPL uses a combination of remaining life and straight-line depreciation methods as approved by the PSCW. The composite or group method of depreciation is used, in which a single depreciation rate is applied to the gross investment in a particular class of property. This method pools similar assets and then depreciates each group as a whole. Periodic depreciation studies are performed to determine the appropriate group lives, net salvage and group depreciation rates. These depreciation studies are subject to review and approval by the PSCW. Depreciation expense is included within the recoverable cost of service component of rates charged to customers. The average rates of depreciation for electric, gas and other properties, consistent with current rate making practices, were as follows:

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	2011			2010			2009
Electric:
Generation		3.3	%		2.9	%		3.2	%
Distribution		2.9	%		2.6	%		3.0	%
Gas		2.6	%		2.2	%		2.8	%
Other		5.2	%		6.5	%		6.4	%

AFUDC—AFUDC represents costs to finance construction additions including a return on equity component and cost of debt component as required by regulatory accounting. The concurrent credit for the amount of AFUDC capitalized is recorded as “Allowance for funds used during construction” in the Consolidated Statements of Income. The amount of AFUDC generated by equity and debt components was as follows (in millions):

	2011		2010		2009
Equity	$	4.1	$	8.2	$	4.0
Debt		2.1		4.3		1.7
	$	6.2	$	12.5	$	5.7

WPL recognized $1 million, $10 million and $3 million of AFUDC in 2011, 2010 and 2009, respectively, for its Bent Tree—Phase I wind project, a portion of which was placed in service in 2010 and 2011.

AFUDC for WPL’s retail and wholesale jurisdiction construction projects is calculated in accordance with PSCW and FERC guidelines, respectively. The AFUDC recovery rates, computed in accordance with the prescribed regulatory formula, were as follows:

	2011			2010			2009
PSCW formula - retail jurisdiction (a)		8.8	%		8.8	%		9.0	%
FERC formula - wholesale jurisdiction		6.2	%		7.2	%		6.7	%

(a) Consistent with the PSCW’s retail rate case order issued in 2009, WPL earned a current return on 50% of the estimated CWIP related to its Bent Tree—Phase I wind project for 2010 and accrued AFUDC on the remaining 50% in 2010. In addition, the PSCW’s order changed WPL’s AFUDC recovery rate to 8.8% from 9.0% effective Jan. 1, 2010.

(f) Other Property, Plant and Equipment—Other property, plant and equipment is recorded at the original cost of acquisition or construction, which includes material, labor and contractor services. Repairs, replacements and renewals of items of property determined to be less than a unit of property or that do not increase the property’s life or functionality are charged to maintenance expense. Upon retirement or sale of other property, plant and equipment, the original cost and related accumulated depreciation are removed from the accounts and any gain or loss is included in the Consolidated Statements of Income. Refer to Note 1(e) for discussion of wind site costs recorded in “Other property, plant and equipment” on the Consolidated Balance Sheets.

(g) Operating Revenues—Revenues are primarily from electricity and natural gas sales and are recognized on an accrual basis as services are rendered or commodities are delivered to customers. Energy sales to individual customers are based on the reading of customers’ meters, which occurs on a systematic basis throughout each reporting period. Amounts of energy delivered to customers since the date of the last meter reading are estimated at the end of each reporting period and the corresponding estimated unbilled revenue is recorded. The unbilled revenue estimate is based on daily system demand volumes, estimated customer usage by class, weather impacts, line losses and the most recent customer rates.

WPL participates in bid/offer-based wholesale energy and ancillary services markets operated by the Midwest Independent Transmission System Operator (MISO). WPL’s customers and generating resources are located in the MISO region. MISO requires that all load serving entities and generation owners, including WPL, submit hourly day-ahead and/or real-time bids and offers for energy and ancillary services. The MISO day-ahead and real-time transactions are grouped together, resulting in a net supply to or net purchase from MISO of megawatt-hours (MWhs) for each hour of each day. The net supply to MISO is recorded in “Electric utility operating revenues” and the net purchase from MISO is recorded in “Electric production fuel and energy purchases” in the Consolidated Statements of Income. WPL also periodically engages in related transactions in PJM Interconnection, LLC’s bid/offer-based wholesale energy market, which are accounted for similar to the MISO transactions.

Taxes Collected from Customers—WPL serves as a collection agent for sales or various other taxes and records revenues on a net basis. Operating revenues do not include the collection of the aforementioned taxes.

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(h) Utility Cost Recovery Mechanisms—

Electric Production Fuel and Energy Purchases (fuel-related costs)—WPL incurs fuel-related costs each period to generate and purchase the electricity to meet the demand of its electric customers. These fuel-related costs include the cost of fossil fuels (primarily coal) used during each period to produce electricity at its generating facilities, electricity purchased each period from wholesale energy markets (primarily MISO) and under long-term purchased power agreements (PPAs), costs for allowances acquired to allow certain emissions (primarily sulfur dioxide (SO2) and NOx) from its generating facilities and costs for chemicals utilized to control emissions from its generating facilities. WPL records these fuel-related costs in “Electric production fuel and energy purchases” in the Consolidated Statements of Income.

Retail—The cost recovery mechanism applicable for WPL’s retail electric customers was changed effective January 2011. For periods prior to 2011, WPL’s retail electric rates approved by the PSCW were based on forecasts of forward-looking test periods and included estimates of future fuel-related costs anticipated during the test period. During each electric retail rate proceeding, the PSCW set fuel monitoring ranges based on the forecasted fuel-related costs used to determine retail base rates. If WPL’s actual fuel-related costs fell outside these fuel monitoring ranges during the test period, WPL and/or other parties could request, and the PSCW could authorize, an adjustment to future retail electric rates based on changes in fuel-related costs only. The PSCW could also authorize an interim retail rate increase. However, if the final retail rate increase was less than the monitoring range threshold required to be met in order to request interim rate relief, all interim rates collected would be subject to refund to WPL’s retail customers with interest at the current authorized return on common equity rate. In addition, if the final retail rate increase was less than the interim retail rate increase, WPL must refund any excess collections above the final rate increase to its retail customers with interest at the current authorized return on common equity rate.

For periods after 2010, the cost recovery mechanism applicable for WPL’s retail electric customers continues to be based on forecasts of fuel-related costs expected to be incurred during forward-looking test year periods and fuel monitoring ranges determined by the PSCW during each electric retail rate proceeding or in a separate fuel cost plan approval proceeding. However, under the new cost recovery mechanism if WPL’s actual fuel-related costs fall outside these fuel monitoring ranges during the test period, WPL is authorized to defer the incremental under-/over-collection of fuel costs that are outside the approved ranges. Deferral of under-collections are reduced to the extent actual return on common equity earned by WPL during the fuel cost plan year exceeds the most recently authorized return on common equity. Such deferred amounts are recognized in “Electric production fuel and energy purchases” in the Consolidated Statements of Income each period. The cumulative effects of these deferred amounts are recorded in current “Regulatory assets” or current “Regulatory liabilities” on the Consolidated Balance Sheets until they are reflected in future billings to customers. Effective January 2012, WPL’s retail fuel-related costs will include costs for emission allowances and emission control chemicals. Prior to 2012, WPL’s retail fuel-related costs have excluded costs for emission allowances and emission control chemicals.

Wholesale—The cost recovery mechanisms applicable for WPL’s wholesale electric customers provide for subsequent adjustments to its electric rates for changes in electric production fuel and purchased energy costs. Changes in the under-/over-collection of these costs each period are recognized in “Electric production fuel and energy purchases” in the Consolidated Statements of Income. The cumulative effects of the under-/over-collection of these costs are recorded in current “Regulatory assets” or current “Regulatory liabilities” on the Consolidated Balance Sheets until they are reflected in future billings to customers. WPL’s costs for emission allowances and emission control chemicals are recovered through the capacity charge component of its wholesale formula rates.

Purchased Electric Capacity—WPL enters into PPAs to help meet the electricity demand of its customers. Certain of these PPAs include minimum payments for WPL’s rights to electric generating capacity, which are charged each period to “Purchased electric capacity” in the Consolidated Statements of Income. Purchased electric capacity expenses are recovered from WPL’s retail electric customers through changes in base rates determined during periodic rate proceedings. Purchased electric capacity expenses are recovered from WPL’s wholesale electric customers through annual changes in base rates determined by a formula rate structure.

Electric Transmission Service—WPL incurs costs for the transmission of electricity to its customers and charges these costs each period to “Electric transmission service” in the Consolidated Statements of Income. Electric transmission service expenses are recovered from WPL’s retail electric customers through changes in base rates determined during periodic rate proceedings. Electric transmission service expenses are recovered from WPL’s wholesale electric customers through annual changes in base rates determined by a formula rate structure.

Cost of Gas Sold—WPL incurs costs for the purchase, transportation and storage of natural gas to serve its gas customers and charges the costs associated with the natural gas delivered to customers during each period to “Cost of gas sold” in the Consolidated Statements of Income. The tariffs for WPL’s retail gas customers provide for subsequent adjustments to its

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rates for changes in the cost of gas sold. Changes in the under-/over-collection of these costs are also recognized in “Cost of gas sold” in the Consolidated Statements of Income. The cumulative effects of the under-/over-collection of these costs are recorded in current “Regulatory assets” or current “Regulatory liabilities” on the Consolidated Balance Sheets until they are reflected in future billings to customers.

Energy Efficiency Costs—WPL incurs costs to fund energy efficiency programs and initiatives that help customers reduce their energy usage and charges these costs incurred each period to “Other operation and maintenance” in the Consolidated Statements of Income. Energy efficiency costs incurred by WPL are recovered from retail electric and gas customers through changes in base rates determined during periodic rate proceedings and include a reconciliation to eliminate any under-/over-collection of energy efficiency costs from prior periods. Changes in the under-/over-collection of energy efficiency costs each period are recognized in “Other operation and maintenance” in the Consolidated Statements of Income. The cumulative effects of the under-/over-collection of these costs are recorded in current “Regulatory assets” or current “Regulatory liabilities” on the Consolidated Balance Sheets until they are reflected in future billings to customers.

Refer to Notes 1(b) and 2 for additional information regarding these utility cost recovery mechanisms.

(i) Financial Instruments—WPL periodically uses financial instruments for risk management purposes to mitigate exposures to fluctuations in certain commodity prices, transmission congestion costs and currency exchange rates. The fair value of those financial instruments that are determined to be derivatives are recorded as assets or liabilities on the Consolidated Balance Sheets. Derivative instruments representing unrealized gain positions are reported as derivative assets, and derivative instruments representing unrealized loss positions are reported as derivative liabilities at the end of each reporting period. WPL also has certain commodity purchase and sales contracts that have been designated, and qualify for, the normal purchase and sale exception and based on this designation, these contracts are accounted for on the accrual basis of accounting. WPL does not offset fair value amounts recognized for the right to reclaim cash collateral (receivable) or the obligation to return cash collateral (payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. Refer to Note 1(b) for discussion of the recognition of regulatory assets related to the unrealized losses on WPL’s derivative instruments. Refer to Notes 12 and 13(e) for further discussion of derivatives and related credit risk, respectively.

(j) Pension and Other Postretirement Benefits Plans—Alliant Energy Corporate Services, Inc. (Corporate Services) sponsors various pension and other postretirement benefits plans. Some of the costs related to these plans are directly assigned to WPL for WPL’s non-bargaining employees who are participants in Corporate Services’ qualified and non-qualified defined benefit pension plans. The remaining costs related to Corporate Services’ plans are allocated to WPL based on labor costs of plan participants. Refer to Note 6(a) for additional information on defined benefit pension plans costs directly assigned to WPL.

(k) Asset Impairments—

Property, Plant and Equipment of Regulated Operations—Property, plant and equipment of regulated operations are reviewed for possible impairment whenever events or changes in circumstances indicate all or a portion of the carrying value of the assets may be disallowed for rate making purposes. If WPL is disallowed recovery of any portion of the carrying value of its regulated property, plant and equipment, an impairment charge is recognized equal to the amount of the carrying value that was disallowed. If WPL is disallowed a full or partial return on the carrying value of its regulated property, plant and equipment, an impairment charge is recognized equal to the difference between the carrying value and the present value of the future revenues expected from its regulated property, plant and equipment.

Property, Plant and Equipment of Non-regulated Operations and Intangible Assets—Property, plant and equipment of non-regulated operations and intangible assets are reviewed for possible impairment whenever events or changes in circumstances indicate the carrying value of the assets may not be recoverable. Impairment is indicated if the carrying value of an asset exceeds its undiscounted future cash flows. An impairment charge is recognized equal to the amount the carrying value exceeds the asset’s fair value. Refer to Note 1(e) for discussion of an impairment recorded by WPL in 2011 related to the Green Lake and Fond du Lac Counties wind site and Note 16 for additional discussion of intangible assets.

Unconsolidated Equity Investments—If events or circumstances indicate the carrying value of investments accounted for under the equity method of accounting may not be recoverable, potential impairment is assessed by comparing the fair value of these investments to their carrying values as well as assessing if a decline in fair value is temporary. If an impairment is indicated, a charge is recognized equal to the amount the carrying value exceeds the investment’s fair value. Refer to Note 10(a) for additional discussion of investments accounted for under the equity method of accounting.

(l) Operating Leases—WPL has certain PPAs that provide it exclusive rights to all or a substantial portion of the output from the specific generating facility over the contract term and therefore are accounted for as operating leases. Costs associated with these PPAs are included in “Electric production fuel and energy purchases” and “Purchased electric capacity”

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in the Consolidated Statements of Income based on monthly payments for these PPAs. Monthly capacity payments related to one of these PPAs is higher during the peak demand period from May 1 through Sep. 30 and lower in all other periods during each calendar year. These seasonal differences in capacity charges are consistent with expected market pricing trends and the expected usage of energy from the facility.

(m) Emission Allowances—Emission allowances are granted by the U.S. Environmental Protection Agency (EPA) at zero cost and permit the holder of the allowances to emit certain gaseous by-products of fossil fuel combustion, including SO2 and NOx. Unused emission allowances may be bought and sold or carried forward to be utilized in future years. Acid Rain and Clear Air Interstate Rule (CAIR) emission allowances are not eligible to be used for compliance requirements under the Cross-State Air Pollution Rule (CSAPR), and CSAPR emission allowances are not eligible to be used for compliance requirements under Acid Rain regulations and CAIR. Purchased emission allowances are recorded as intangible assets at their original cost and evaluated for impairment as long-lived assets to be held and used. Emission allowances allocated to or acquired by WPL are held primarily for consumption. Amortization of emission allowances is based upon a weighted average cost for each category of vintage year utilized during the reporting period and is recorded in “Electric production fuel and energy purchases” in the Consolidated Statements of Income. Cash inflows and outflows related to sales and purchases of emission allowances are recorded as investing activities in the Consolidated Statements of Cash Flows. Refer to Note 16 for additional discussion of emission allowances.

(n) AROs—The fair value of any retirement costs associated with an asset for which WPL has a legal obligation is recorded as a liability with an equivalent amount added to the asset cost when an asset is placed in service or when sufficient information becomes available to determine a reasonable estimate of the fair value of future retirement costs. The fair value of AROs is generally determined using discounted cash flow analyses. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. For WPL, accretion and depreciation expense related to its regulated operations is recorded to regulatory assets on the Consolidated Balance Sheets. Upon settlement of the ARO liability, an entity settles the obligation for its recorded amount or incurs a gain or loss. For WPL, any gain or loss related to its regulated operations is recorded to regulatory liabilities or regulatory assets on the Consolidated Balance Sheets. Refer to Note 18 for additional discussion of AROs.

(o) Debt Issuance and Retirement Costs—WPL defers and amortizes debt issuance costs and debt premiums or discounts over the expected lives of the debt issues, considering maturity dates and, if applicable, redemption rights held by others. Refer to Note 9(b) for details on long-term debt and Note 1(b) for information on regulatory assets related to debt retired early or refinanced.

(p) Allowance for Doubtful Accounts—WPL maintains allowances for doubtful accounts for estimated losses resulting from the inability of its customers to make required payments. WPL estimates the allowance for doubtful accounts based on historical write-offs, customer arrears and other economic factors within its service territory. Allowance for doubtful accounts at Dec. 31 was as follows (in millions):

	2011		2010
Customer	$	1.6	$	1.4
Other		0.3		0.3
	$	1.9	$	1.7

(q) Comprehensive Income—In 2011, 2010 and 2009, WPL had no other comprehensive income; therefore its comprehensive income was equal to its earnings available for common stock for such periods.

(2) UTILITY RATE CASES

Retail Fuel-related Rate Case (2012 Test Year)—In May 2011, WPL filed a request with the PSCW to increase annual retail electric rates by $13 million to recover anticipated increases in retail electric production fuel and energy purchases (fuel-related costs) in 2012 due to higher purchased power energy costs and emission compliance costs. In July 2011, the EPA issued CSAPR, which was expected to require SO2 and NOx emissions reductions from WPL’s fossil-fueled electric generating units (EGUs) with greater than 25 MW of capacity beginning in 2012. After evaluating CSAPR, in November 2011, WPL revised its request for an annual retail electric rate increase to $31 million to reflect higher anticipated emission compliance costs. In December 2011, WPL received an order from the PSCW authorizing an annual retail electric rate increase of $4 million related to expected changes in retail fuel-related costs. The December 2011 order also required WPL to defer direct CSAPR compliance costs that are not included in the fuel monitoring level and set a zero percent tolerance band for the CSAPR-related deferral. The 2012 fuel costs, excluding deferred CSAPR compliance costs, will be monitored using an annual bandwidth of plus or minus 2%. The rate change granted from this request was effective Jan. 1, 2012. Subsequent to the PSCW order issued in December 2011, the U.S. Court of Appeals for the D.C. Circuit stayed the

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implementation of CSAPR and directed the EPA to reinstate CAIR. WPL is currently unable to predict the final outcome of the CSAPR stay and the impact on its financial condition or results of operations.

Retail Electric Rate Case (2011 Test Year)—In April 2010, WPL filed a request with the PSCW to reopen the rate order for its 2010 test year to increase annual retail electric rates for 2011. The request was based on a forward-looking test period that included 2011. The key drivers for the filing included recovery of investments in WPL’s Bent Tree—Phase I wind project and expiring deferral credits, partially offset by lower variable fuel expenses. In December 2010, WPL received an order from the PSCW authorizing an annual retail electric rate increase of $8 million, or approximately 1%, effective Jan. 1, 2011. This $8 million increase in annual rates effective Jan. 1, 2011, combined with the termination of the $9 million interim fuel-related rate increase effective Dec. 31, 2010, resulted in a net $1 million decrease in annual retail electric rates charged to customers effective January 2011. Refer to “Retail Fuel-related Rate Case (2010 Test Year)” below for additional details of the interim fuel-related rate increase implemented in 2010 and a $5 million reduction to the 2011 test year base rate increase for refunds owed to retail electric customers related to interim fuel cost collections in 2010.

Retail Rate Case (2010 Test Year)—In December 2009, WPL received an order from the PSCW authorizing an annual retail electric rate increase of $59 million, or approximately 6%, and an annual retail natural gas rate increase of $6 million, or approximately 2%, effective January 2010. Refer to Note 1(b) for discussion of the PSCW’s decision in the December 2009 order regarding recovery of previously incurred costs for the cancelled Nelson Dewey #3 base-load project.

Retail Fuel-related Rate Case (2010 Test Year)—In April 2010, WPL filed a request with the PSCW to increase annual retail electric rates by $9 million to recover anticipated increased fuel-related costs in 2010. Actual fuel-related costs through March 2010, combined with projections of continued higher fuel-related costs for the remainder of 2010, significantly exceeded the amounts being recovered in retail electric rates at the time of the filing. WPL received approval from the PSCW to implement an interim rate increase of $9 million, on an annual basis, effective in June 2010. Updated annual 2010 fuel-related costs during the proceeding resulted in WPL no longer qualifying for a fuel-related rate increase for 2010. In December 2010, the PSCW issued an order authorizing no increase in retail electric rates in 2010 related to fuel-related costs and required the interim rate increase to terminate at the end of 2010. The order also authorized WPL to use $5 million of the interim fuel rates collected in 2010 as a reduction to the 2011 test year base rate increase. As of Dec. 31, 2011, WPL’s remaining reserves were $1 million, including interest, for interim fuel cost collections in 2010.

Refer to Note 1(h) for further discussion of WPL’s fuel cost recovery mechanism and Note 1(b) for discussion of various other rate matters.

(3) LEASES

(a) Operating Leases—WPL has entered into various agreements related to property, plant and equipment rights that are accounted for as operating leases. WPL’s most significant operating leases relate to certain PPAs. These PPAs contain fixed rental payments related to capacity and contingent rental payments related to the energy portion (actual MWhs) of the respective PPAs. Rental expenses associated with WPL’s operating leases were as follows (in millions):

	2011		2010		2009
Operating lease rental expenses (excluding contingent rentals)	$	63	$	63	$	68
Contingent rentals related to certain PPAs		4		4		7
	$	67	$	67	$	75

At Dec. 31, 2011, future minimum operating lease payments, excluding contingent rentals, were as follows (in millions):

	2012		2013		2014		2015		2016		Thereafter		Total
Riverside Energy Center (Riverside) PPA (a)	$	59	$	17	$	—	$	—	$	—	$	—	$	76
Synthetic leases (b)		1		2		4		1		—		—		8
Other		4		5		1		—		—		1		11
	$	64	$	24	$	5	$	1	$	—	$	1	$	95

(a) In November 2011, WPL filed a Certificate of Authority with the PSCW for the purchase of Riverside in the fourth quarter of 2012. A decision from the PSCW is expected in April 2012. If Riverside is purchased in the fourth quarter of 2012, capacity payments scheduled for 2013 will not occur. Refer to Note 19 for additional information on the Riverside PPA.

(b) The synthetic leases relate to the financing of certain utility railcars. The entities that lease these assets to WPL do not meet consolidation requirements and are not included on the Consolidated Balance Sheets. WPL has guaranteed the residual value of the related assets, which total $4 million in the aggregate. The guarantees extend through the maturity

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of each respective underlying lease with remaining terms up to four years. Residual value guarantee amounts have been included in the future minimum operating lease payments.

(b) Capital Leases—In 2005, WPL entered into a 20-year agreement with Alliant Energy Resources, LLC’s (Resources’) Non-regulated Generation business to lease the Sheboygan Falls Energy Facility (SFEF), with an option for two lease renewal periods thereafter. The lease became effective in 2005 when SFEF began commercial operation. WPL is responsible for the operation of SFEF and has exclusive rights to its output. In 2005, the PSCW approved this affiliated lease agreement with initial monthly payments of approximately $1.3 million. The lease payments were based on a 50% debt to capital ratio, a return on equity of 10.9%, a cost of debt based on the cost of senior notes issued by Resources’ Non-regulated Generation business in 2005 and certain costs incurred to construct the facility. In accordance with its order approving the lease agreement, the PSCW reserved the right to review the capital structure, return on equity and cost of debt every five years from the date of the order. No revisions to the lease were made in 2010. The capital lease asset is amortized using the straight-line method over the 20-year lease term. Since the inception of the lease in 2005, WPL’s retail and wholesale rates have included recovery of the monthly SFEF lease payments. SFEF lease expenses were included in the Consolidated Statements of Income as follows (in millions):

	2011		2010		2009
Interest expense	$	11.7	$	12.0	$	12.3
Depreciation and amortization		6.2		6.2		6.2
	$	17.9	$	18.2	$	18.5

At Dec. 31, 2011, WPL’s estimated future minimum capital lease payments for SFEF were as follows (in millions):

	2012		2013		2014		2015		2016		Thereafter		Total		Less: amount representing interest		Present value of net minimum capital lease payments
SFEF	$	15	$	15	$	15	$	15	$	15	$	128	$	203	$	96	$	107

(4) RECEIVABLES

Advances for Customer Energy Efficiency Projects—WPL offers energy efficiency programs to certain of its customers. The energy efficiency programs provide low-cost financing to help customers identify, purchase and install energy efficiency improvement projects. The customers repay WPL with monthly payments over a term up to five years. The advances for and collections of customer energy efficiency projects are recorded as investing activities in the Consolidated Statements of Cash Flows. The current portion and non-current portion of outstanding advances for customer energy efficiency projects are recorded in “Accounts receivable—other” and “Deferred charges and other,” respectively, on the Consolidated Balance Sheets. At Dec. 31, outstanding advances for customer energy efficiency projects were as follows (in millions):

	2011		2010
Current portion	$	20.5	$	25.0
Non-current portion		26.5		43.7
	$	47.0	$	68.7

(5) INCOME TAXES

Income Taxes—The components of “Income taxes” in the Consolidated Statements of Income were as follows (in millions):

	2011			2010			2009
Current tax expense (benefit):
Federal		($4.3	)	$	26.8		($	137.7	)
State		(7.1	)		14.7			(14.3	)
Deferred tax expense:
Federal		111.3			63.3			153.6
State		19.0			6.6			9.3
Production tax credits		(14.8	)		(3.5	)		(3.9	)
Investment tax credits		(1.2	)		(1.2	)		(1.3	)
Provision recorded as a change in uncertain tax positions:
Current		(0.3	)		(41.7	)		39.7
Deferred		(20.7	)		33.3			—
Provision recorded as a change in accrued interest		—			—			0.4
		$81.9		$	98.3		$	45.8

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Income Tax Rates—The overall income tax rates shown in the following table were computed by dividing income tax expense by income before income taxes.

	2011			2010			2009
Statutory federal income tax rate		35.0	%		35.0	%		35.0	%
State income taxes, net of federal benefits		5.0			5.1			4.5
Adjustment of prior period taxes		—			2.0			0.7
Production tax credits		(6.0	)		(1.4	)		(2.9	)
Effect of rate making on property related differences:
Federal		(0.4	)		(1.0	)		(0.8	)
State		(0.1	)		(0.1	)		(0.1	)
Federal Health Care Legislation		—			1.2			—
State filing changes		—			—			(1.8	)
Other items, net		(0.1	)		(1.6	)		(0.7	)
Overall income tax rate		33.4	%		39.2	%		33.9	%

Production tax credits—WPL earns production tax credits from the wind projects it owns and operates. Production tax credits are based on the electricity generated by each wind project during the first 10 years of operations. WPL has two wind projects that are currently generating production tax credits: the 68 MW Cedar Ridge wind project, which began generating electricity in late 2008; and the 200 MW Bent Tree—Phase I wind project, which began generating electricity in late 2010. Production tax credits (net of state tax impacts) resulting from these wind projects were as follows (in millions):

	2011		2010			2009
Bent Tree—Phase I (a)	$	9.3	$	1.2		$	—
Cedar Ridge		4.5		3.3			3.9
		13.8		4.5			3.9
Deferral (a)		1.0		(1.0	)		—
	$	14.8	$	3.5		$	3.9

(a) In accordance with its December 2009 order, the PSCW authorized WPL to defer the retail portion of the production tax credits generated from its Bent Tree—Phase I wind project in 2010. As a result of a regulatory assessment completed in 2011, the retail portion of the production tax credit deferral was reversed.

Federal health care legislation—In 2010, the Patient Protection and Affordable Care Act, and Health Care and Education Reconciliation Act of 2010 (Federal Health Care Legislation) were enacted. One of the most significant provisions of the Federal Health Care Legislation for WPL requires a reduction in its tax deductions for retiree health care costs beginning in 2013, to the extent its drug expenses are reimbursed under the Medicare Part D retiree drug subsidy program. The reduction in the future deductibility of retiree health care costs accrued as of Dec. 31, 2009 required WPL to record deferred income tax expense of $3 million in 2010.

State filing changes—In 2009, the Wisconsin Senate Bill 62 (SB 62) was enacted. The most significant provision of SB 62 for WPL required combined reporting for corporate income taxation in Wisconsin beginning with tax returns filed for the calendar year 2009. This provision requires all legal entities in which Alliant Energy owns a 50% or more interest to file as members of a unitary return in Wisconsin. As a result of this provision in SB 62 and in order to take advantage of efficiencies that may be available as a result of WPL and Interstate Power and Light Company (IPL) sharing resources and facilities, WPL filed as a member of Iowa consolidated tax returns beginning with calendar year 2009. Changes in state apportioned income tax rates resulting from Wisconsin combined reporting requirements and WPL’s plans to be included in Iowa consolidated tax returns required WPL to adjust the carrying value of its deferred income tax assets and liabilities in 2009. WPL recognized net income tax benefits in 2009 of $2 million from the changes in state apportioned income tax rates and additional valuation allowances.

Deferred Tax Assets and Liabilities—Consistent with rate making treatment, deferred taxes are offset in the table below for temporary differences that have related regulatory assets and regulatory liabilities. The deferred income tax (assets) and liabilities included on the Consolidated Balance Sheets at Dec. 31 arise from the following temporary differences (in millions):

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	2011								2010
	Deferred Tax Assets			Deferred Tax Liabilities		Net			Deferred Tax Assets			Deferred Tax Liabilities		Net
Property	$	—		$	697.1	$	697.1		$	—		$	494.8	$	494.8
Investment in ATC		—			93.8		93.8			—			83.9		83.9
Pension and other postretirement benefits obligations		—			49.6		49.6			—			32.1		32.1
Net operating losses carryforward—state (a)		(5.1	)		—		(5.1	)		—			—		—
Investment tax credits		(6.6	)		—		(6.6	)		(7.4	)		—		(7.4	)
Customer advances		(11.6	)		—		(11.6	)		(13.1	)		—		(13.1	)
Federal credit carryforward (a)		(26.1	)		—		(26.1	)		(11.5	)		—		(11.5	)
Net operating losses carryforward—federal (b)		(141.1	)		—		(141.1	)		(38.2	)		—		(38.2	)
Other		(17.6	)		34.1		16.5			(12.0	)		37.2		25.2
	($	208.1	)	$	874.6	$	666.5		($	82.2	)	$	648.0	$	565.8
						2011								2010
Other current assets						($	6.0	)						($	4.6	)
Deferred income taxes							672.5								570.4
Total deferred tax liabilities						$	666.5							$	565.8

(a) Earliest expiration date is 2022.

(b) Earliest expiration date is 2030.

Property—The increase in property-related deferred tax liabilities in the table above was primarily due to temporary differences from bonus depreciation deductions available in 2011 and a change in the tax accounting method for mixed service cost deductions in 2011.

Bonus depreciation deductions—In 2010, the Small Business Jobs Act of 2010 (SBJA) and the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 (the Act) were enacted. The most significant provisions of the SBJA and the Act for WPL are related to the extension of bonus depreciation deductions for certain expenditures for property that are placed in service through Dec. 31, 2012. Based on capital projects placed into service in 2011, WPL currently estimates its total bonus depreciation deductions to be claimed in its 2011 federal income tax return will be approximately $334 million.

Mixed service costs deductions—In 2010, Alliant Energy filed a request with the Internal Revenue Service (IRS) for a change in its tax accounting method for mixed service costs. In March 2011, Alliant Energy received consent from the IRS to reflect this change as part of its 2010 federal income tax return. The change allows Alliant Energy and its subsidiaries to currently deduct a portion of its mixed service costs, which have historically been capitalized for tax purposes. This change was applied retroactively to mixed service costs incurred since 1989. WPL recently completed an assessment of its eligible mixed service costs for the period from 1989 through 2010 and included $106 million of mixed service costs deductions for these years in its 2010 federal income tax return.

Pension and other postretirement benefits obligations—The increase in pension and other postretirement benefits obligations in the table above was primarily due to employer contributions of $52 million made to company-sponsored defined benefit pension and other postretirement benefits plans in 2011. These contributions are deductible on WPL’s 2011 federal income tax return.

Uncertain Tax Positions—A reconciliation of the beginning and ending amounts of uncertain tax positions, excluding interest, is as follows (in millions):

	2011			2010			2009
Balance, Jan. 1	$	33.7		$	42.1		$	2.5
Additions based on tax positions related to the current year		0.6			1.3			2.5
Reductions based on tax positions related to the current year		—			—			—
Additions for tax positions of prior years (a)		—			5.2			37.3
Reductions for tax positions of prior years (b)		(21.7	)		(8.0	)		(0.2	)
Settlements with taxing authorities		—			(6.9	)		—
Lapse of statute of limitations		—			—			—
Balance, Dec. 31	$	12.6		$	33.7		$	42.1

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(a) The additions for tax positions of prior years were related to positions taken by WPL on its federal and state tax returns related to the capitalization and dispositions of property.

(b) The reductions of tax positions of prior years during 2011 were related to guidance published by the IRS clarifying the treatment of repair expenditures for electric distribution property. The reductions of tax positions of prior years during 2010 were primarily related to deductions taken by WPL on its federal and state tax returns that were settled under audit for amounts less than the recorded amounts.

	Dec. 31,
	2011		2010		2009
Tax positions favorably impacting future effective tax rates	$	—	$	—	$	1.4
Interest accrued		—		—		2.1
Penalties accrued		—		—		—

Open tax years—Tax years that remain subject to examination by major jurisdictions are as follows:

Major Jurisdiction	Open Years
Consolidated federal income tax returns (a)		2005-2010
Consolidated Iowa income tax returns		2005-2010
Wisconsin income tax returns		2005-2008
Wisconsin combined tax returns		2009-2010

(a) The statute of limitations for 2005 through 2008 has been extended to Dec. 31, 2012.

Reasonably possible changes to uncertain tax positions in 2012—In 2012, statutes of limitations will expire for WPL’s tax returns in multiple state jurisdictions. The expiration of the statutes of limitations is not anticipated to have any impact on WPL’s uncertain tax positions in 2012. In 2010, the IRS completed the audits of Alliant Energy’s U.S. federal income tax return for calendar years 2005 through 2008. In 2011, the IRS completed the audit of Alliant Energy’s U.S. federal income tax return for calendar year 2009. The IRS audit of Alliant Energy’s federal income tax return for calendar year 2010 is expected to be completed in 2012. Alliant Energy has agreed to all of the IRS’ proposed adjustments for deductions and credits included in the 2005 through 2010 income tax returns with the exception of the deductions for the repair expenditures change in method of tax accounting included in Alliant Energy’s 2008 through 2010 income tax returns. The IRS denied the full amount ($291 million for WPL) of deductions for the repair expenditures included in Alliant Energy’s 2008 through 2010 income tax returns given the absence of current IRS guidelines regarding this deduction. Alliant Energy is appealing the IRS’ denial of these deductions. Uncertain tax positions for WPL may decrease within the next 12 months as a result of the expected issuance in 2012 of revenue procedures clarifying the treatment of repair expenditures for electric generation and gas distribution property. An estimate of the expected changes for 2012 cannot be determined at this time.

Other Income Tax Matters—Alliant Energy files a consolidated federal income tax return, which includes the aggregate taxable income or loss of Alliant Energy and its subsidiaries. In addition, a combined return including Alliant Energy and all of its subsidiaries is filed in Wisconsin. Alliant Energy subsidiaries with a presence in Iowa file as part of a consolidated return in Iowa. Under the terms of a tax sharing agreement between Alliant Energy and its subsidiaries, the subsidiaries calculate state income tax using consolidated apportionment rates applied to separate company taxable income. In 2011, 2010 and 2009, WPL’s foreign sources of income were not material.

(6) BENEFIT PLANS

(a) Pension and Other Postretirement Benefits Plans—WPL provides retirement benefits to substantially all of its employees through various non-contributory defined benefit pension plans, and through a defined contribution plan (401(k) savings plan). WPL’s non-contributory defined benefit pension plans are currently closed to new hires. Benefits of the non-contributory defined benefit pension plans are based on the plan participant’s years of service, age and compensation. Benefits of the defined contribution plans are based on the plan participant’s years of service, age, compensation and contributions. WPL also provides certain defined benefit postretirement health care and life benefits to eligible retirees. In general, the retiree health care plans consist of fixed benefit subsidy structures and the retiree life insurance plans are non-contributory.

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Assumptions—The assumptions for WPL’s qualified defined benefit pension and other postretirement benefits plans at the measurement date of Dec. 31 were as follows (Not Applicable (N/A)):

	Qualified Defined Benefit Pension Plan									Other Postretirement Benefits Plans
	2011			2010			2009			2011			2010			2009
Discount rate for benefit obligations		4.95	%		5.7	%		5.8	%		4.6	%		5.25	%		5.55	%
Discount rate for net periodic cost		5.7	%		5.8	%		6.15	%		5.25	%		5.55	%		6.15	%
Expected rate of return on plan assets		7.9	%		8	%		8.25	%		6.3	%		6.3	%		8.25	%
Rate of compensation increase		3.5	%		3.5	%		3.5	%		3.5	%		3.5	%		3.5	%
Medical cost trend on covered charges:
Initial trend rate (end of year)		N/A			N/A			N/A			8	%		7	%		7.5	%
Ultimate trend rate		N/A			N/A			N/A			5	%		5	%		5	%

Expected rate of return on plan assets—The expected rate of return on plan assets is determined by analysis of projected asset class returns based on the target asset class allocations. WPL uses a portfolio return simulator and also reviews historical returns, survey information and capital market information to support the expected rate of return on plan assets assumption. Refer to “Investment Policy and Strategy for Plan Assets” below for additional information related to WPL’s investment policy and strategy and mix of assets for the pension and other postretirement benefits plans.

Medical cost trend on covered charges—The assumed medical trend rates are critical assumptions in determining the service and interest cost and accumulated postretirement benefit obligation related to postretirement benefits costs. A 1% change in the medical trend rates for 2011, holding all other assumptions constant, would have the following effects (in millions):

	1% Increase		1% Decrease
Effect on total of service and interest cost components	$	0.2	($	0.2	)
Effect on postretirement benefit obligation		1.5		(1.4	)

Net Periodic Benefit Costs—In the first table below, the qualified defined benefit pension plan costs represent only those costs for WPL’s bargaining unit employees covered under the plan that is sponsored by WPL. Also in the first table below, the other postretirement benefits plans costs represent costs for all WPL employees. The “Directly assigned defined benefit pension plans” table below includes amounts directly assigned to WPL related to its current and former non-bargaining employees who are participants in Alliant Energy and Corporate Services sponsored qualified and non-qualified defined benefit pension plans. The components of WPL’s net periodic benefit costs for its sponsored qualified defined benefit pension and other postretirement benefits plans, and defined benefit pension plans amounts directly assigned to WPL, as recognized on the Consolidated Statements of Income, were as follows (in millions):

	Qualified Defined Benefit Pension Plan									Other Postretirement Benefits Plans (a)
	2011			2010			2009			2011			2010			2009
Service cost	$	4.5		$	4.9		$	4.9		$	2.9		$	3.6		$	3.4
Interest cost		16.1			15.7			15.5			4.9			5.5			5.5
Expected return on plan assets (b)		(20.0	)		(19.1	)		(14.1	)		(1.3	)		(1.3	)		(1.1	)
Amortization of (c):
Prior service cost (credit)		0.5			0.5			0.5			(3.4	)		(0.7	)		(0.9	)
Actuarial loss		7.1			8.5			10.4			2.1			2.5			1.3
Curtailment loss (d)		—			—			0.7			—			—			—
Special termination benefits costs (e)		—			—			0.9			—			—			—
	$	8.2		$	10.5		$	18.8		$	5.2		$	9.6		$	8.2

Directly assigned defined benefit pension plans	2011			2010			2009
Interest cost	$	5.5		$	5.6		$	6.1
Expected return on plan assets (b)		(7.3	)		(7.3	)		(6.3	)
Amortization of (c):
Prior service credit		(0.2	)		(0.2	)		—
Actuarial loss		3.0			2.8			3.6
Additional benefit costs (f)		0.7			—			—
	$	1.7		$	0.9		$	3.4

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(a) In May 2011, WPL amended its defined benefit postretirement health care plan resulting in a revision to the method and level of coverage provided for participants more than 65 years of age. This amendment was determined to be a significant event, which required WPL to remeasure its defined benefit postretirement health care plan in May 2011. The amendment resulted in a decrease in WPL’s postretirement benefit obligations of $16 million in 2011 with the impact of the remeasurement on net periodic benefit costs being recognized prospectively from the remeasurement date. The impact of the remeasurement decreased WPL’s net periodic benefit costs by $3.8 million in 2011. The discount rate used for the remeasurement was 5.20%. All other assumptions used for the remeasurement were consistent with the measurement assumptions used at Dec. 31, 2010.

(b) The expected return on plan assets is based on the expected rate of return on plan assets and the fair value approach to the market-related value of plan assets.

(c) Unrecognized net actuarial gains or losses in excess of 10% of the greater of the plans’ benefit obligation or asset are amortized over the average future service lives of plan participants, except for the Alliant Energy Cash Balance Pension Plan (Cash Balance Plan) where gains or losses outside the 10% threshold are amortized over the time period the participants are expected to receive benefits. Unrecognized prior service costs (credits) for the postretirement benefits plans are amortized over the average future service period to full eligibility of the participants of each plan.

(d) In 2007, members of the International Brotherhood of Electrical Workers Local 965 ratified a four-year collective bargaining agreement reached with WPL, resulting in changes to WPL’s qualified pension plan. One of these changes provided WPL qualified pension plan participants an option to cease participating in the WPL qualified pension plan and begin participating in the Alliant Energy 401(k) Savings Plan with increased levels of contribution by WPL. The election of this option did not impact a participant’s eligibility for benefits previously vested under the WPL qualified pension plan. In 2009, certain of these employees elected to cease participating in the WPL qualified pension plan, resulting in WPL recognizing a curtailment loss related to the WPL qualified pension plan of $0.7 million in 2009.

(e) WPL recognized special termination benefits costs related to the qualified defined benefit pension plan that is sponsored by WPL of $0.9 million in 2009 as a result of the elimination of certain operations positions in 2009.

(f) Alliant Energy reached an agreement with the IRS, which resulted in a favorable determination letter for the Cash Balance Plan in 2011. The agreement with the IRS required Alliant Energy to amend the Cash Balance Plan, which was completed in 2011 resulting in aggregate additional benefits of $10.2 million paid by Alliant Energy to certain former participants in the Cash Balance Plan in 2011. WPL recognized $3.4 million ($0.7 million directly assigned and $2.7 million allocated by Corporate Services) of additional benefits costs in 2011 related to these benefits. Refer to Note 13(b) for additional information regarding the Cash Balance Plan.

Corporate Services provides services to WPL, and as a result, WPL is allocated pension and other postretirement benefits costs associated with Corporate Services employees. The following table includes the allocated qualified and non-qualified pension and other postretirement benefits costs associated with Corporate Services employees providing services to WPL (in millions):

	Pension Benefits (a)						Other Postretirement Benefits
	2011		2010		2009		2011		2010		2009
Costs	$	4.2	$	1.9	$	3.2	$	0.2	$	1.3	$	1.2

(a) In 2011, additional qualified pension benefits costs resulting from the 2011 amendment to the Cash Balance Plan allocated to WPL by Corporate Services were $2.7 million.

The estimated amortization from “Regulatory assets” on the Consolidated Balance Sheet into net periodic benefit cost in 2012 is as follows (in millions):

	Qualified Defined Benefit Pension Plan		Other Postretirement Benefits Plans			Directly Assigned Defined Benefit Pension Plans
Actuarial loss	$	12.1	$	2.3		$	3.6
Prior service cost (credit)		0.5		(3.9	)		(0.1	)
	$	12.6	($	1.6	)	$	3.5

In addition to the estimated amortizations from “Regulatory assets” in the above table, $1.2 million of amortizations are expected in 2012 from “Regulatory assets” associated with Corporate Services employees participating in other Alliant Energy sponsored plans allocated to WPL.

WPL’s net periodic benefit costs are primarily included in “Other operation and maintenance” in the Consolidated Statements of Income.

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Benefit Plan Assets and Obligations—A reconciliation of the funded status of WPL’s sponsored qualified defined benefit pension and other postretirement benefits plans to the amounts recognized on the Consolidated Balance Sheets at Dec. 31 was as follows (in millions):

	Qualified Defined Benefit Pension Plan						Other Postretirement Benefits Plans
	2011			2010			2011			2010
Change in projected benefit obligation:
Net projected benefit obligation at Jan. 1	$	283.3		$	271.6		$	103.3		$	99.1
Service cost		4.5			4.9			2.9			3.6
Interest cost		16.1			15.7			4.9			5.5
Plan participants’ contributions		—			—			3.3			3.2
Plan amendments (a)		—			—			(18.2	)		(1.5	)
Actuarial loss		43.3			2.5			2.3			1.9
Early Retiree Reinsurance Program proceeds		—			—			0.2			—
Gross benefits paid		(14.7	)		(11.4	)		(9.6	)		(9.0	)
Federal subsidy on other postretirement benefits paid		—			—			0.5			0.5
Net projected benefit obligation at Dec. 31		332.5			283.3			89.6			103.3
Change in plan assets:
Fair value of plan assets at Jan. 1		255.2			236.6			25.0			18.8
Actual return on plan assets		9.1			30.0			0.9			2.1
Employer contributions		40.0			—			5.5			9.9
Plan participants’ contributions		—			—			3.3			3.2
Gross benefits paid		(14.7	)		(11.4	)		(9.6	)		(9.0	)
Fair value of plan assets at Dec. 31		289.6			255.2			25.1			25.0
Under funded status at Dec. 31	($	42.9	)	($	28.1	)	($	64.5	)	($	78.3	)
Amounts recognized on the Consolidated
Balance Sheets consist of:
Non-current asset	$	—		$	—		$	1.3		$	—
Pension and other benefit obligations		(42.9	)		(28.1	)		(65.8	)		(78.3	)
Net amount recognized at Dec. 31	($	42.9	)	($	28.1	)	($	64.5	)	($	78.3	)
Amounts recognized in Regulatory Assets (b):
Net actuarial loss	$	142.7		$	95.6		$	27.8		$	27.2
Prior service cost (credit)		2.4			2.9			(17.3	)		(2.5	)
	$	145.1		$	98.5		$	10.5		$	24.7

(a) Refer to “Net Periodic Benefit Costs” above for additional information regarding plan amendments to the defined benefit pension and other postretirement benefits plans in 2011.

(b) Refer to Note 1(b) for amounts recognized in “Regulatory assets” on the Consolidated Balance Sheets.

Included in the following table are WPL’s accumulated benefit obligations, aggregate amounts applicable to qualified defined benefit pension and other postretirement benefits plans with accumulated benefit obligations in excess of plan assets, as well as the qualified defined benefit pension plan with projected benefit obligations in excess of plan assets as of the Dec. 31 measurement date (Not Applicable (N/A); in millions):

	Qualified Defined Benefit Pension Plan				Other Postretirement Benefits Plans
	2011		2010		2011		2010
Accumulated benefit obligations	$	314.7	$	270.2	$	89.6	$	103.3
Plans with accumulated benefit obligations in excess of plan assets:
Accumulated benefit obligations		314.7		270.2		89.6		103.3
Fair value of plan assets		289.6		255.2		25.1		25.0
Plans with projected benefit obligations in excess of plan assets:
Projected benefit obligations		332.5		283.3		N/A		N/A
Fair value of plan assets		289.6		255.2		N/A		N/A

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The “Directly assigned defined benefit pension plans” table below includes amounts directly assigned to WPL related to its current and former non-bargaining employees who are participants in Alliant Energy and Corporate Services sponsored qualified and non-qualified defined benefit pension plans. A reconciliation of the funded status of the directly assigned qualified and non-qualified defined benefit pension plans to the amounts recognized on the Consolidated Balance Sheets at Dec. 31 was as follows (in millions):

Directly assigned defined benefit pension plans	2011			2010
Change in projected benefit obligation:
Net projected benefit obligation at Jan. 1	$	107.4		$	100.9
Interest cost		5.5			5.6
Plan amendments		0.7			—
Actuarial loss		10.3			8.7
Gross benefits paid		(8.7	)		(7.8	)
Net projected benefit obligation at Dec. 31		115.2			107.4
Change in plan assets:
Fair value of plan assets at Jan. 1		95.6			92.0
Actual return on plan assets		3.2			11.2
Employer contributions		6.9			0.2
Gross benefits paid		(8.7	)		(7.8	)
Fair value of plan assets at Dec. 31		97.0			95.6
Under funded status at Dec. 31	($	18.2	)	($	11.8	)
Change in projected benefit obligation:
Amounts recognized on the Consolidated Balance Sheets consist of:
Other current liabilities	($	0.2	)	($	0.1	)
Pension and other benefit obligations		(18.0	)		(11.7	)
Net amount recognized at Dec. 31	($	18.2	)	($	11.8	)
Amounts recognized in Regulatory Assets (a):
Net actuarial loss	$	73.7		$	62.3
Prior service credit		(2.4	)		(2.6	)
	$	71.3		$	59.7
Accumulated benefit obligations	$	115.2		$	107.4

(a) Refer to Note 1(b) for amounts recognized in “Regulatory assets” on the Consolidated Balance Sheets.

In addition to the amounts recognized in “Regulatory assets” in the above table, “Regulatory assets” and “Regulatory liabilities” were recognized for amounts associated with Corporate Services employees participating in other Alliant Energy sponsored benefit plans that were allocated to WPL at Dec. 31 as follows (in millions):

	2011		2010
Regulatory assets	$	22.3	$	18.6
Regulatory liabilities		0.2		—

Estimated Future Employer Contributions and Benefit Payments—WPL estimates that funding for the qualified defined benefit pension plan, other postretirement benefits plans, and the directly assigned qualified and non-qualified defined benefit pension plans during 2012 will be $0, $3.9 million and $0.2 million, respectively. Amounts directly assigned to WPL are for non-bargaining employees who are participants in Alliant Energy and Corporate Services sponsored qualified and non-qualified defined benefit pension plans.

WPL’s expected benefit payments, and the directly assigned qualified and non-qualified defined benefit pension benefits amounts, which reflect expected future service, as appropriate, are as follows (in millions):

	2012		2013		2014		2015		2016		2017 - 2021
Qualified defined benefit pension benefits	$	13.0	$	13.8	$	14.9	$	15.9	$	17.0	$	103.3
Directly assigned defined benefit pension benefits		9.0		9.4		9.5		9.5		9.2		40.9
Other postretirement benefits		6.8		7.0		7.2		7.1		7.3		37.4
	$	28.8	$	30.2	$	31.6	$	32.5	$	33.5	$	181.6

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Investment Policy and Strategy for Plan Assets—WPL’s investment strategy and its policies employed with respect to assets of defined benefit pension and other postretirement benefits plans are to combine both preservation of principal and prudent and reasonable risk-taking to protect the integrity of plan assets, in order to meet the obligations to plan participants while minimizing benefit costs over the long term. It is recognized that risk and volatility are present with all types of investments. However, high levels of risk are mitigated at the total fund level through diversification by asset class including both U.S. and international equity exposure, the number of individual investments, and sector and industry limits when applicable. WPL also uses an overlay management service to help maintain target allocations, liquidity needs and intended exposures to the plan assets. The overlay manager is authorized to use derivative financial instruments to facilitate this service.

Defined Benefit Pension Plans Assets—For assets of defined benefit pension plans, the mix among asset classes is controlled by long-term asset allocation targets. The assets are viewed as long-term with moderate liquidity needs. Historical performance results and future expectations suggest that equity securities will provide higher total investment returns than debt securities over a long-term investment horizon. Consistent with the goals of meeting obligations to plan participants and minimizing benefit costs over the long-term, the defined benefit pension plans have a long-term investment posture more heavily weighted towards equity holdings. The asset allocation mix is monitored regularly and appropriate steps are taken as needed to rebalance the assets within the prescribed range. Prohibited investment vehicles include, but may not be limited to, direct ownership of real estate, options and futures (unless specifically approved as is the case of the overlay manager), margin trading, oil and gas limited partnerships, commodities, short selling and securities of the managers’ firms or affiliate firms. At Dec. 31, 2011, the current target range and actual allocations for WPL’s qualified defined benefit pension plan assets were as follows:

	Target Range Allocation	Actual Allocation
Cash and equivalents (a)	0%-5%	13%
Equity securities:
U.S. large cap core	10%-20%	12%
U.S. large cap value	8%-16%	10%
U.S. large cap growth	8%-16%	10%
U.S. small cap value	0%-6%	3%
U.S. small cap growth	0%-4%	2%
International—developed markets	12%-24%	14%
International—emerging markets	0%-8%	4%
Fixed income securities	20%-40%	32%

(a) Pension contributions of $40 million were made in late December 2011 and were invested in equity futures.

Other Postretirement Benefits Plans Assets—Other postretirement benefits plans assets are comprised of specific assets within certain defined benefit pension plans (401(h) assets) as well as assets held in Voluntary Employees’ Beneficiary Association (VEBA) trusts. The investment policy and strategy of the 401(h) assets mirrors those of the defined benefit pension plans, which are discussed above. A mix of both equity and debt securities are utilized to maximize returns and mitigate risk over the long-term. There are no specific target allocations for the VEBA trusts as a whole. Separate investment guidelines have been established for the VEBA trusts, which are actively managed. At Dec. 31, 2011, WPL’s other postretirement benefits plan assets consisted of 39% equity securities, 19% fixed income securities and 42% cash and equivalents.

Securities Lending Program—WPL has a securities lending program with a third-party agent that allows the agent to lend certain securities from WPL’s qualified defined benefit pension and other postretirement benefits plans to selected entities against receipt of collateral (in the form of cash, government and agency securities or letters of credit) as provided for and determined in accordance with its securities lending agency agreement. Initial collateral levels are no less than 100% of the market value of loans to non-affiliated borrowers of U.S. government securities; 102% of the market value of loans to affiliated borrowers of U.S. government securities; 102% of the market value of loans on U.S. corporate bonds and U.S. equity securities; 105% of the market value of loans on non-U.S. securities; and 102% of the market value of loans on all other securities. Refer to “Fair Value Measurements” below for details of WPL’s fair value of invested collateral and amounts due to borrowers for the securities lending program.

Fair Value Measurements—The following tables report a framework for measuring fair value. The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. The three levels of the fair value hierarchy and examples of each are as follows:

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Level 1—Pricing inputs are quoted prices available in active markets for identical assets or liabilities as of the reporting date. WPL’s investments in equity and fixed income securities held in registered investment companies and directly held equity securities are valued at the closing price reported in the active market in which the securities are traded. Level 1 plan assets also include interest-bearing cash, which is held in money market accounts managed by an affiliate of the trustee and money market funds within its securities lending invested collateral.

Level 2—Pricing inputs are quoted prices for similar asset or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means. WPL’s investments in corporate bonds and government and agency obligations are valued at the closing price reported in the active market for similar assets in which the individual securities are traded or based on yields currently available on comparable securities of issuers with similar credit ratings. WPL’s investments in equity and fixed income securities in common/collective trusts are valued at the net asset value of shares held by the plans, which is based on the fair market value of the underlying investments in equity and fixed income securities of the common/collective trusts. Level 2 plan assets also consist of asset backed securities within its securities lending invested collateral.

Level 3—Pricing inputs are unobservable inputs for assets or liabilities for which little or no market data exist and require significant management judgment or estimation. WPL’s Level 3 plan assets include certain asset backed securities and corporate bonds within its securities lending invested collateral.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Furthermore, while WPL believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.

At Dec. 31, the fair values of WPL’s qualified defined benefit pension plan assets by asset category and fair value hierarchy level were as follows (in millions):

	2011									2010
	Fair Value			Level 1		Level 2		Level 3		Fair Value			Level 1		Level 2		Level 3
Cash and equivalents	$	37.9		$	37.9	$	—	$	—	$	3.4		$	3.4	$	—	$	—
Equity securities:
U.S. large cap core		35.7			35.7		—		—		36.7			36.7		—		—
U.S. large cap value		29.6			—		29.6		—		31.2			—		31.2		—
U.S. large cap growth		29.5			—		29.5		—		31.3			—		31.3		—
U.S. small cap value		8.3			—		8.3		—		9.0			—		9.0		—
U.S. small cap growth		7.0			7.0		—		—		5.2			5.2		—		—
International—developed markets		40.8			21.1		19.7		—		44.1			23.6		20.5		—
International—emerging markets		9.8			9.8		—		—		10.6			10.6		—		—
Fixed income securities:
Corporate bonds		18.4			—		18.4		—		16.8			—		16.8		—
Government and agency obligations		28.3			—		28.3		—		24.5			—		24.5		—
Fixed income funds		47.4			0.1		47.3		—		44.2			—		44.2		—
Securities lending invested collateral		3.0			1.5		0.9		0.6		5.4			1.0		3.5		0.9
		295.7		$	113.1	$	182.0	$	0.6		262.4		$	80.5	$	181.0	$	0.9
Accrued investment income		0.3									0.3
Due to brokers, net (a)		(1.5	)								(0.2	)
Due to borrowers for securities lending program		(4.9	)								(7.3	)
Total pension plan assets	$	289.6								$	255.2

(a) This category represents pending trades with brokers.

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At Dec. 31, the fair values of WPL’s qualified and non-qualified defined benefit pension plan assets associated with its current and former non-bargaining employees who are participants in Alliant Energy and Corporate Services sponsored plans that were directly assigned to WPL were as follows (in millions):

	2011									2010
	Fair Value			Level 1		Level 2		Level 3		Fair Value			Level 1		Level 2		Level 3
Cash and equivalents	$	12.7		$	12.7	$	—	$	—	$	1.3		$	1.3	$	—	$	—
Equity securities:
U.S. large cap core		12.0			12.0		—		—		13.7			13.7		—		—
U.S. large cap value		9.9			—		9.9		—		11.7			—		11.7		—
U.S. large cap growth		9.9			—		9.9		—		11.7			—		11.7		—
U.S. small cap value		2.8			—		2.8		—		3.4			—		3.4		—
U.S. small cap growth		2.3			2.3		—		—		1.9			1.9		—		—
International—developed markets		13.7			7.1		6.6		—		16.5			8.8		7.7		—
International—emerging markets		3.3			3.3		—		—		4.0			4.0		—		—
Fixed income securities:
Corporate bonds		6.2			—		6.2		—		6.3			—		6.3		—
Government and agency obligations		9.5			—		9.5		—		9.2			—		9.2		—
Fixed income funds		15.8			—		15.8		—		16.6			—		16.6		—
Securities lending invested collateral		1.0			0.5		0.3		0.2		2.0			0.5		1.2		0.3
		99.1		$	37.9	$	61.0	$	0.2		98.3		$	30.2	$	67.8	$	0.3
Accrued investment income		0.1									0.1
Due to brokers, net (a)		(0.5	)								(0.1	)
Due to borrowers for securities lending program		(1.7	)								(2.7	)
Total pension plan assets	$	97.0								$	95.6

(a) This category represents pending trades with brokers.

At Dec. 31, the fair values of WPL’s other postretirement benefits plans assets by asset category and fair value hierarchy level were as follows (in millions):

	2011									2010
	Fair Value			Level 1		Level 2		Level 3		Fair Value			Level 1		Level 2		Level 3
Cash and equivalents	$	10.5		$	10.5	$	—	$	—	$	10.7		$	10.7	$	—	$	—
Equity securities:
U.S. large cap core		1.2			1.2		—		—		1.3			1.3		—		—
U.S. large cap value		1.0			—		1.0		—		1.1			—		1.1		—
U.S. large cap growth		1.0			—		1.0		—		1.1			—		1.1		—
U.S. small cap core		4.7			4.7		—		—		3.8			3.8		—		—
U.S. small cap value		0.3			—		0.3		—		0.3			—		0.3		—
U.S. small cap growth		0.2			0.2		—		—		0.2			0.2		—		—
International—developed markets		1.3			0.7		0.6		—		1.6			0.8		0.8		—
International—emerging markets		0.3			0.3		—		—		0.4			0.4		—		—
Fixed income securities:
Corporate bonds		1.1			—		1.1		—		1.4			—		1.4		—
Government and agency obligations		1.0			—		1.0		—		1.0			—		1.0		—
Fixed income funds		2.6			1.0		1.6		—		2.3			0.7		1.6		—
Securities lending invested collateral		0.1			0.1		—		—		0.2			0.1		0.1		—
		25.3		$	18.7	$	6.6	$	—		25.4		$	18.0	$	7.4	$	—
Due to brokers, net (a)		(0.1	)								(0.1	)
Due to borrowers for securities lending program		(0.1	)								(0.3	)
Total other postretirement benefits plan assets	$	25.1								$	25.0

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(a) This category represents pending trades with brokers.

For the various defined benefit pension and other postretirement benefits plans, Alliant Energy’s common stock represented less than 1% of total plan assets at Dec. 31, 2011 and 2010.

Cash Balance Plan—Alliant Energy’s defined benefit pension plans include the Cash Balance Plan that provides benefits for certain non-bargaining unit employees. The Cash Balance Plan has been closed to new hires since 2005. Effective 2008, Alliant Energy amended the Cash Balance Plan by discontinuing additional contributions into employees’ Cash Balance Plan accounts. Also effective 2008, Alliant Energy increased its level of contributions to its 401(k) Savings Plan, which offset the impact of discontinuing additional contributions into the employees’ Cash Balance Plan accounts. In 2009, Alliant Energy amended the Cash Balance Plan by changing participants’ future interest credit formula to use the annual change in the consumer price index as the interest credit. This amendment provides participants an interest crediting rate that is 3% more than the annual change in the consumer price index. Refer to Note 13(b) for discussion of a class action lawsuit filed against the Cash Balance Plan in 2008 and the IRS review of the tax qualified status of the Plan.

401(k) Savings Plan—A significant number of WPL employees participate in a defined contribution retirement plan (401(k) savings plan). The number of employees participating in this plan has increased recently as certain bargaining unit employees have elected to participate in defined contribution retirement plans instead of defined benefit pension plans. In 2009, WPL implemented several cost saving initiatives to reduce operation and maintenance expenses, including suspension of a portion of 401(k) savings plan contributions during the second half of 2009. In 2011, 2010 and 2009, WPL’s costs related to the 401(k) savings plan, which are partially based on the participants’ level of contribution, were $8.4 million, $8.9 million and $4.3 million, respectively.

(b) Equity Incentive Plans—In 2010, Alliant Energy’s shareowners approved the Alliant Energy 2010 Omnibus Incentive Plan (OIP), which permits the grant of stock options, restricted stock, restricted stock units, performance shares, performance units, and other stock-based awards and cash incentive awards to key employees. At Dec. 31, 2011, performance shares and restricted stock were outstanding and 4.3 million shares of Alliant Energy’s common stock remained available for grants under the OIP. Upon shareowner approval of the OIP, the Alliant Energy 2002 Equity Incentive Plan (EIP) terminated resulting in no new awards authorized to be granted under the EIP. All awards previously granted under the EIP that are still outstanding remain valid and continue to be subject to all of the terms and conditions of the EIP. At Dec. 31, 2011, non-qualified stock options, restricted stock and performance shares were outstanding under the EIP and another predecessor plan under which new awards can no longer be granted. Alliant Energy also has the Alliant Energy Director Long Term Incentive Plan (DLIP), which permits the grant of long-term incentive awards, including performance units and restricted cash awards to certain key employees. At Dec. 31, 2011, performance units and performance contingent cash awards were outstanding under the DLIP. There is no limit to the number of grants that can be made under the DLIP.

A summary of compensation expense that was allocated to WPL and the related income tax benefits recognized for share-based compensation awards was as follows (in millions):

	2011		2010		2009
Compensation expense	$	4.1	$	3.0	$	1.1
Income tax benefits		1.7		1.2		0.4

Share-based compensation expense is recognized on a straight-line basis over the requisite service periods and is primarily recorded in “Other operation and maintenance” in the Consolidated Statements of Income.

(7) COMMON EQUITY

Dividend Restrictions—WPL has common stock dividend restrictions based on the terms of its outstanding preferred stock and applicable regulatory limitations. At Dec. 31, 2011, WPL was in compliance with all such dividend restrictions.

WPL is restricted from paying common stock dividends to its parent company, Alliant Energy, if for any past or current dividend period, dividends on its preferred stock have not been paid, or declared and set apart for payment. WPL has paid all dividends on its preferred stock through 2011.

WPL’s most significant regulatory limitation on distributions to its parent company is included in an order issued by the PSCW in 2009 that prohibits WPL from paying annual common stock dividends in excess of $112 million if WPL’s common stock equity ratio is or will fall below 51.01%. WPL’s dividends are also restricted to the extent that such dividend would reduce WPL’s common stock equity ratio to less than 25%. As of Dec. 31, 2011, WPL’s amount of retained earnings that were free of restrictions was $112 million for 2012.

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Restricted Net Assets—WPL does not have regulatory authority to lend or advance any amounts to its parent company. As of both Dec. 31, 2011 and 2010, the amount of WPL’s net assets that were not available to be transferred to its parent company in the form of loans, advances or cash dividends without the consent of WPL’s regulatory authorities was $1.3 billion.

Capital Transactions—In 2011, 2010 and 2009, WPL paid common stock dividends of $112.1 million, $109.5 million and $91.0 million, respectively, to its parent. In 2011, 2010 and 2009, WPL received capital contributions of $25.0 million, $75.0 million and $100.0 million, respectively, from its parent.

(8) REDEEMABLE PREFERRED STOCK

Information related to the carrying value of WPL’s cumulative preferred stock at Dec. 31 was as follows (dollars in millions):

Liquidation Preference/ Stated Value	Authorized Shares			Shares Outstanding		Series			Redemption (a)	2011		2010
$100		(b	)		99,970		4.50	%	Any time	$	10.0	$	10.0
$100		(b	)		74,912		4.80	%	Any time		7.5		7.5
$100		(b	)		64,979		4.96	%	Any time		6.5		6.5
$100		(b	)		29,957		4.40	%	Any time		3.0		3.0
$100		(b	)		29,947		4.76	%	Any time		3.0		3.0
$100		(b	)		150,000		6.20	%	Any time		15.0		15.0
$  25		(b	)		599,460		6.50	%	Any time		15.0		15.0
										$	60.0	$	60.0

(a) None are mandatorily redeemable.

(b) WPL has 3,750,000 authorized shares in total.

The articles of organization of WPL contain a provision that grants the holders of its preferred stock voting rights to elect a majority of WPL’s Board of Directors if preferred dividends equal to the annual dividend requirements are in arrears. The exercise of such voting rights would provide the holders of WPL’s preferred stock control of the decision on redemption of WPL’s preferred stock and could force WPL to exercise its call option. Therefore, the contingent control right and the embedded call option cause WPL’s preferred stock to be presented outside of total equity on the Consolidated Balance Sheets in a manner consistent with temporary equity.

Refer to Note 11 for information on the fair value of WPL’s cumulative preferred stock.

(9) DEBT

(a) Short-term Debt—WPL maintains committed bank lines of credit to provide short-term borrowing flexibility and backstop liquidity for commercial paper outstanding. At Dec. 31, 2011, WPL’s short-term borrowing arrangements included a $400 million revolving credit facility, which expires in December 2016. Information regarding commercial paper issued under credit facilities was as follows (dollars in millions):

	2011			2010
Commercial paper at Dec. 31:
Amount outstanding	$	25.7		$	47.4
Weighted average interest rates		0.3	%		0.3	%
Total short-term debt outstanding for the year ended:
Maximum amount outstanding (based on daily outstanding balances)	$	96.5		$	170.2
Average amount outstanding (based on daily outstanding balances)	$	17.6		$	36.6
Weighted average interest rates		0.3	%		0.3	%

WPL’s credit agreement contains a covenant, which requires it to maintain a debt-to-capital ratio of less than 58% in order to borrow under the credit facility. At Dec. 31, 2011, WPL’s actual debt-to-capital ratio was 45%.

The debt component of the capital ratio generally includes long- and short-term debt (excluding non-recourse debt and hybrid securities to the extent the total carrying value of such hybrid securities does not exceed 15% of consolidated capital of the applicable borrower), capital lease obligations, letters of credit, guarantees of the foregoing and new synthetic leases. Unfunded vested benefits under qualified pension plans are not included in the debt-to-capital ratios. The equity component of the capital ratio excludes accumulated other comprehensive income (loss).

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(b) Long-Term Debt—

WPL’s long-term debt, net as of Dec. 31 was as follows (dollars in millions):

	2011			2010
Debentures:
5%, due 2019	$	250.0		$	250.0
4.6%, due 2020		150.0			150.0
6.25%, due 2034		100.0			100.0
6.375%, due 2037		300.0			300.0
7.6%, due 2038		250.0			250.0
		1,050.0			1,050.0
Pollution Control Revenue Bonds:
5%, due 2014 and 2015		24.5			24.5
5.375%, due 2015		14.6			14.6
		39.1			39.1
Subtotal		1,089.1			1,089.1
Unamortized debt (discount) and premium, net		(6.9	)		(7.4	)
Long-term debt, net	$	1,082.2		$	1,081.7

Five-Year Schedule of Debt Maturities—At Dec. 31, 2011, WPL’s debt maturities for 2012 to 2016 were $0, $0, $8 million, $31 million and $0, respectively.

Indenture—WPL maintains an indenture related to its debentures due 2019 through 2038.

Optional Redemption Provisions—WPL has certain issuances of long-term debt that contain optional redemption provisions which, if elected by the issuer at its sole discretion, could require material redemption premium payments by the issuer. The redemption premium payments under these optional redemption provisions are variable and dependent on applicable U.S. Treasury rates at the time of redemption. At Dec. 31, 2011, the debt issuances that contained these optional redemption provisions included WPL’s debentures due 2019 through 2038.

Unamortized Debt Issuance Costs—WPL’s unamortized debt issuance costs recorded in “Deferred charges and other” on the Consolidated Balance Sheets at Dec. 31, 2011 and 2010 were $8.4 million and $9.1 million, respectively.

Carrying Amount and Fair Value of Long-term Debt—Refer to Note 11 for information on the carrying amount and fair value of WPL’s long-term debt outstanding at Dec. 31, 2011 and 2010.

(10) INVESTMENTS

(a) Unconsolidated Equity Investments—WPL’s unconsolidated investments accounted for under the equity method of accounting are as follows (dollars in millions):

	Ownership Interest at Dec. 31, 2011			Carrying Value at Dec. 31,				Equity (Income) / Loss
				2011		2010		2011			2010			2009
ATC (a)		16	%	$	238.8	$	227.9	($	37.8	)	($	36.9	)	($	36.1	)
Wisconsin River Power Company		50	%		7.7		8.1		(0.9	)		(0.9	)		(0.9	)
				$	246.5	$	236.0	($	38.7	)	($	37.8	)	($	37.0	)

(a) WPL has the ability to exercise significant influence over ATC’s financial and operating policies through its participation on ATC’s Board of Directors. Refer to Note 20 for information regarding related party transactions with ATC.

Summary financial information from the financial statements of these investments is as follows (in millions):

	2011		2010		2009
Operating revenues	$	575	$	564	$	529
Operating income		308		308		294
Net income		226		221		215
As of Dec. 31:
Current assets		61		63
Non-current assets		3,071		2,906
Current liabilities		299		429
Non-current liabilities		1,487		1,263

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(b) Cash Surrender Value of Life Insurance Policies—WPL has various life insurance policies that cover certain current and former employees and directors. At Dec. 31, 2011 and 2010, the cash surrender value of these investments was $11.9 million and $12.4 million, respectively.

(11) FAIR VALUE MEASUREMENTS

Fair Value of Financial Instruments—The carrying amounts of WPL’s current assets and current liabilities approximate fair value because of the short maturity of such financial instruments. Carrying amounts and the related estimated fair values of other financial instruments at Dec. 31 were as follows (in millions):

	Carrying Amount		Fair Value
2011
Assets:
Derivative assets (Note 12)	$	5.1	$	5.1
Capitalization and liabilities:
Long-term debt (Note 9(b))		1,082.2		1,439.0
Cumulative preferred stock (Note 8)		60.0		58.2
Derivative liabilities (Note 12)		44.4		44.4
2010
Assets:
Derivative assets (Note 12)		8.0		8.0
Capitalization and liabilities:
Long-term debt (Note 9(b))		1,081.7		1,219.6
Cumulative preferred stock (Note 8)		60.0		56.0
Derivative liabilities (Note 12)		43.3		43.3

Valuation Techniques—

Derivative assets and derivative liabilities—As of Dec. 31, 2011 and 2010, derivative assets and derivative liabilities included swap contracts, option contracts, and physical forward purchase and sale contracts for electricity and natural gas, financial transmission rights (FTRs) and embedded foreign currency derivatives. WPL’s swap, option and physical forward commodity contracts were non-exchange-based derivative instruments valued using indicative price quotations available through a pricing vendor that provides daily exchange forward price settlements, from broker or dealer quotations or from on-line exchanges. The indicative price quotations reflected the average of the bid-ask mid-point prices and were obtained from sources believed to provide the most liquid market for the commodity. WPL corroborated a portion of these indicative price quotations using quoted prices for similar assets or liabilities in active markets and categorized derivative instruments based on such indicative price quotations as Level 2. WPL’s commodity contracts that were valued using indicative price quotations based on significant assumptions such as seasonal or monthly shaping and indicative price quotations that could not be readily corroborated were categorized as Level 3. WPL’s swap, option and physical forward commodity contracts were predominately at liquid trading points. WPL’s FTRs were measured at fair value each reporting date using monthly or annual auction shadow prices from relevant auctions. The embedded foreign currency derivatives related to Euro-denominated payment terms included in the wind turbine supply contract with Vestas-American Wind Technology, Inc. (Vestas) were measured at fair value using an extrapolation of forward currency rates. Refer to Note 12 for additional details of derivative assets and derivative liabilities.

Long-term debt—For long-term debt instruments that are actively traded, the fair value was based upon quoted market prices each reporting date. For long-term debt instruments that are not actively traded, the fair value was based on discounted cash flow methodology and utilizes assumptions of current market pricing curves. Refer to Note 9(b) for additional information regarding long-term debt.

Cumulative preferred stock—The fair value of WPL’s 4.50% cumulative preferred stock was based on the closing market price quoted by the NYSE Amex LLC on each reporting date. The fair value of WPL’s remaining preferred stock was calculated based on the market yield of similar securities. Refer to Note 8 for additional information regarding cumulative preferred stock.

Valuation Hierarchy—Fair value measurement accounting establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The three levels of the fair value hierarchy and examples of each are as follows:

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Level 1—Pricing inputs are quoted prices available in active markets for identical assets or liabilities as of the reporting date.

Level 2—Pricing inputs are quoted prices for similar asset or liabilities in active markets or quoted prices for identical or similar assets or liabilities in markets that are not active as of the reporting date. Level 2 assets and liabilities as of Dec. 31, 2011 and 2010 included non-exchange traded commodity contracts valued using indicative price quotations that are corroborated with quoted prices for similar assets or liabilities in active markets.

Level 3—Pricing inputs are unobservable inputs for assets or liabilities for which little or no market data exist and require significant management judgment or estimation. Level 3 assets and liabilities as of Dec. 31, 2011 and 2010 included embedded foreign currency derivatives, FTRs, natural gas option contracts and certain commodity contracts that are valued using indicative price quotations with shaping assumptions.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.

Recurring Fair Value Measurements—Disclosure requirements for WPL’s recurring items subject to fair value measurements at Dec. 31 were as follows (in millions):

	2011								2010
	Fair Value		Level 1		Level 2		Level 3		Fair Value		Level 1		Level 2		Level 3
Assets:
Derivative assets:
Commodity contracts	$	5.1	$	—	$	2.1	$	3.0	$	8.0	$	—	$	6.4	$	1.6
Liabilities:
Derivative liabilities:
Commodity contracts		44.4		—		36.2		8.2		43.2		—		40.1		3.1
Foreign exchange contracts		—		—		—		—		0.1		—		—		0.1
Total derivative liabilities		44.4		—		36.2		8.2		43.3		—		40.1		3.2

Additional information for WPL’s recurring fair value measurements using significant unobservable inputs (Level 3 inputs) was follows (in millions):

	Derivative Assets and (Liabilities), net
	Commodity Contracts						Foreign Contracts
	2011			2010			2011			2010
Beginning balance, Jan. 1	($	1.5	)	$	1.2		($	0.1	)	($	1.5	)
Total losses (realized/unrealized) included in changes in net assets (a)		(4.2	)		(1.3	)		—			—
Transfers in and/or out of Level 3 (b)		0.2			(0.3	)		—			—
Purchases		3.7			—			—			—
Settlements		(3.4	)		(1.1	)		0.1			1.4
Ending balance, Dec. 31	($	5.2	)	($	1.5	)	$	—		($	0.1	)
The amount of total losses for the period included in changes in net assets attributable to the change in unrealized losses relating to assets and liabilities held at Dec. 31 (a)	($	4.2	)	($	1.3	)	$	—		$	—

(a) Gains and losses related to derivative assets and derivative liabilities are recorded in “Regulatory assets” and “Regulatory liabilities” on the Consolidated Balance Sheets.

(b) Observable market inputs became available for certain commodity contracts previously classified as Level 3. The transfers were valued as of the beginning of the period.

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(12) DERIVATIVE INSTRUMENTS

Commodity and Foreign Exchange Derivatives—

Purpose—WPL periodically uses derivative instruments for risk management purposes to mitigate exposures to fluctuations in certain commodity prices, transmission congestion costs and currency exchange rates. WPL’s derivative instruments as of Dec. 31, 2011 and 2010 were not designated as hedging instruments. WPL’s derivative instruments as of Dec. 31, 2011 and 2010 included electric physical forward purchase contracts and swap contracts to mitigate pricing volatility for the electricity purchased to supply to its customers; electric physical forward sale contracts to offset long positions created by reductions in electricity demand forecasts; natural gas swap contracts to mitigate pricing volatility for the fuel used to supply to the natural gas-fired electric generating facilities it operates; natural gas options to mitigate price increases during periods of high demand or lack of supply; FTRs acquired to manage transmission congestion costs; natural gas physical forward purchase contracts to mitigate pricing volatility for natural gas supplied to its retail customers; natural gas physical forward purchase and sale contracts to optimize the value of natural gas pipeline capacity; and embedded foreign currency derivatives related to Euro-denominated payment terms included in the wind turbine supply contract with Vestas.

Notional Amounts—As of Dec. 31, 2011, WPL had notional amounts related to outstanding swap contracts, option contracts, physical forward contracts and FTRs that were accounted for as commodity derivative instruments as follows (units in thousands):

	2012		2013		2014		Total
Electricity (MWhs)		1,577		1,138		—		2,715
FTRs (MWs)		9		—		—		9
Natural gas (dekatherms)		17,276		4,162		450		21,888

The notional amounts in the above table were computed by aggregating the absolute value of purchase and sale positions within commodities for each year.

Financial Statement Presentation—WPL records derivative instruments at fair value each reporting date on the balance sheets as assets or liabilities. At Dec. 31, 2011 and 2010, the fair values of current derivative assets were included in “Prepayments and other,” non-current derivative assets were included in “Deferred charges and other,” current derivative liabilities were included in “Derivative liabilities” and non-current derivative liabilities were included in “Other long-term liabilities and deferred credits” on the Consolidated Balance Sheets as follows (in millions):

	2011		2010
Current derivative assets
Commodity contracts	$	3.5	$	6.5
Non-current derivative assets
Commodity contracts	$	1.6	$	1.5
Current derivative liabilities
Commodity contracts	$	31.4	$	32.2
Foreign exchange contracts		—		0.1
	$	31.4	$	32.3
Non-current derivative liabilities
Commodity contracts	$	13.0	$	11.0

WPL generally records gains and losses from its derivative instruments with offsets to regulatory assets or regulatory liabilities, based on its fuel and natural gas cost recovery mechanisms, as well as other specific regulatory authorizations. Gains and losses from derivative instruments not designated as hedging instruments were recorded as follows (in millions):

	Location Recorded on Balance Sheets	Gains (Losses)
		2011			2010			2009
Commodity contracts	Regulatory assets	($	37.2	)	($	30.6	)	($	68.1	)
Commodity contracts	Regulatory liabilities		2.9			0.9			12.7
Foreign exchange contracts	Regulatory liabilities		—			—			(0.4	)

Losses from commodity contracts during 2011, 2010 and 2009 were primarily due to impacts of decreases in electricity and natural gas prices during such periods.

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Credit Risk-related Contingent Features—WPL has entered into various agreements that contain credit risk-related contingent features including requirements for it to maintain certain credit ratings from each of the major credit rating agencies and limitations on its liability positions under the various agreements based upon its credit ratings. In the event of a downgrade in its credit ratings or if its liability positions exceed certain contractual limits, WPL may need to provide credit support in the form of letters of credit or cash collateral up to the amount of its exposure under the contracts, or may need to unwind the contracts and pay the underlying liability positions.

Certain of these agreements with credit risk-related contingency features are accounted for as derivative instruments. The aggregate fair value of all derivatives with credit risk-related contingent features that were in a net liability position on Dec. 31, 2011 was $44.4 million. At Dec. 31, 2011, WPL had investment-grade credit ratings. If the most restrictive credit risk-related contingent features for derivative agreements in a net liability position were triggered on Dec. 31, 2011, WPL would be required to post $44.4 million of credit support to its counterparties.

(13) COMMITMENTS AND CONTINGENCIES

(a) Operating Expense Purchase Obligations—WPL has entered into various commodity supply, transportation and storage contracts to meet its obligations to deliver electricity and natural gas to its customers. WPL also enters into other operating expense purchase obligations with various vendors for other goods and services. At Dec. 31, 2011, WPL’s minimum future commitments related to these operating expense purchase obligations were as follows (in millions):

	2012		2013		2014		2015		2016		Thereafter		Total
Purchased power (a):
Kewaunee Nuclear Power Plant	$	72	$	77	$	—	$	—	$	—	$	—	$	149
Other		29		8		—		—		—		—		37
		101		85		—		—		—		—		186
Natural gas		69		38		20		13		13		7		160
Coal (b)		18		18		18		11		—		—		65
Other (c)		8		8		—		—		—		—		16
	$	196	$	149	$	38	$	24	$	13	$	7	$	427

(a) Includes payments required by PPAs for capacity rights and minimum quantities of MWhs required to be purchased. Refer to Note 20 for additional information on purchased power transactions.

(b) WPL enters into coal transportation contracts that are directly assigned to its specific generating stations, the amounts of which are included in the table. In addition, Corporate Services entered into system-wide coal contracts on behalf of WPL and IPL of $88 million for 2012 and $62 million for 2013 to allow flexibility for the changing needs of the quantity of coal consumed by each. Coal contract quantities are allocated to specific WPL or IPL generating stations at or before the time of delivery based on various factors including projected heat input requirements, combustion compatibility and efficiency. These system-wide coal contracts have not been directly assigned to WPL and IPL since the specific needs of each utility were not yet known as of Dec. 31, 2011 and therefore are excluded from the table.

(c) Includes individual commitments incurred during the normal course of business that exceeded $1 million at Dec. 31, 2011.

WPL enters into certain contracts that are considered leases and are therefore not included here, but are included in Note 3.

(b) Legal Proceedings—

Air Permitting Violation Claims—In September 2010, Sierra Club filed in the U.S. District Court for the Western District of Wisconsin a complaint against WPL, as owner and operator of the Nelson Dewey Generating Station (Nelson Dewey) and the Columbia Energy Center (Columbia), based on allegations that modifications were made at the facilities without complying with the Prevention of Significant Deterioration (PSD) program requirements, Title V Operating Permit requirements of the Clean Air Act (CAA) and state regulatory counterparts contained within the Wisconsin state implementation plan (SIP) designed to implement the CAA. In October 2010, WPL responded to these claims related to Nelson Dewey and Columbia by filing with the U.S. District Court an answer denying the Columbia allegations and a motion to dismiss the Nelson Dewey allegations based on statute of limitations arguments. In November 2010, WPL filed a motion to dismiss the Nelson Dewey and Columbia allegations based on lack of jurisdiction. Sierra Club has responded to the motions. WPL and Sierra Club are engaged in settlement negotiations. In January 2012, the Court reset the trial date to Dec. 10, 2012 and scheduled a status conference for Feb. 15, 2012 to receive an update on settlement progress. At the Feb. 15, 2012 status conference, the Court reaffirmed the Dec. 10, 2012 trial date, but set a pre-trial schedule that allows the parties to work toward settlement.

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In September 2010, Sierra Club filed in the U.S. District Court for the Eastern District of Wisconsin a complaint against WPL, as owner and operator of the Edgewater Generating Station (Edgewater), which contained similar allegations regarding air permitting violations at Edgewater. In the Edgewater complaint, additional allegations were made regarding violations of emission limits for visible emissions. In February 2011, WPL responded to these claims related to Edgewater by filing with the U.S. District Court an answer denying the allegations and a motion to dismiss the allegations based on lack of jurisdiction. WPL and Sierra Club are engaged in settlement negotiations. In December 2011, the Court stayed all discovery and scheduling deadlines for 60 days (through Feb. 15, 2012) so that the Parties may continue settlement negotiations. In February 2012, the Court extended the stay through April 16, 2012.

In December 2009, the EPA sent a Notice of Violation (NOV) to WPL as an owner and the operator of Edgewater, Nelson Dewey and Columbia. The NOV alleges that the owners failed to comply with appropriate pre-construction review and permitting requirements and as a result violated the PSD program requirements, Title V Operating Permit requirements of the CAA and the Wisconsin SIP. WPL is engaged in settlement negotiations with the EPA in conjunction with the settlement negotiations with the Sierra Club discussed above.

In response to similar EPA CAA enforcement initiatives, certain utilities have elected to settle with the EPA, while others have elected to litigate. If the EPA and/or Sierra Club successfully prove their claims that projects completed in the past at Edgewater, Nelson Dewey and Columbia required either a state or federal CAA permit, WPL may, under the applicable statutes, be required to pay civil penalties in amounts of up to $37,500 per day for each violation and/or complete actions for injunctive relief. Payment of fines and/or injunctive relief could be included in a settlement outcome. Injunctive relief contained in settlements or court-ordered remedies for other utilities required the installation of emission control technology, changed operating conditions including use of alternative fuels other than coal, caps for emissions and limitations on generation including retirement of generating units, and other beneficial environmental projects. If similar remedies are required for final resolution of these matters at Edgewater, Nelson Dewey and Columbia, WPL would incur additional capital and operating expenditures. WPL is continuing to analyze the allegations and is unable to predict the impact of the allegations on its financial condition or results of operations, but believes that the outcome could be significant. WPL and the other owners of Edgewater and Columbia are exploring settlement options while simultaneously defending against these allegations. WPL believes the projects at Edgewater, Nelson Dewey and Columbia were routine or not projected to increase emissions and therefore did not violate the permitting requirements of the CAA.

WPL does not currently believe any material losses from these air permitting violation claims are both probable and reasonably estimated and therefore has not recognized any material related loss contingency amounts as of Dec. 31, 2011. WPL is not able to estimate the possible loss or range of possible loss related to these air permit violation claims given the various litigation and settlement scenarios being pursued to resolve this contingency as well as uncertainty regarding which, if any, allegations will be determined to be violations and the nature and cost of any fines and injunctive relief that could be required to resolve any violations.

Alliant Energy Cash Balance Pension Plan (Plan)—In February 2008, a class action lawsuit was filed against the Plan in the U.S. District Court for the Western District of Wisconsin (Court). The complaint alleged that certain Plan participants who received distributions 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) because the Plan applied an improper interest crediting rate to project the cash balance account to their normal retirement age. These Plan participants were limited to individuals who, prior to normal retirement age, received a lump sum distribution or an annuity payment. The Court certified two subclasses of plaintiffs that in aggregate include all persons vested or partially vested in the Plan who received these distributions from Jan. 1, 1998 to Aug. 17, 2006 including: (1) persons who received distributions from Jan. 1, 1998 through Feb. 28, 2002; and (2) persons who received distributions from March 1, 2002 to Aug. 17, 2006.

In June 2010, the Court issued an opinion and order that granted the plaintiffs’ motion for summary judgment on liability in the lawsuit and decided with respect to damages that prejudgment interest on damages would be allowed. In December 2010, the Court issued an opinion and order that decided the interest crediting rate that the Plan used to project the cash balance accounts of the plaintiffs during the class period should have been 8.2% and that a pre-retirement mortality discount would not be applied to the damages calculation. In March 2011, the Court issued an opinion and order that prejudgment interest on damages would be calculated using the average prime rate from the date that the Plan failed to make the total payment to a particular participant through the date of the final judgment (which has not yet been issued). In September 2011, plaintiffs filed a motion for leave to file a supplemental complaint to assert that the 2011 amendment to the Plan, made to conform with the IRS determination letter (described below), was itself an ERISA violation. In November 2011, the Court allowed the filing of the Plaintiffs’ supplemental complaint and denied a separate motion for reconsideration filed by the Plan arguing that certain of Plaintiffs’ claims were time-barred. Following the November 2011 ruling, Plaintiffs filed a new complaint. The Plan filed an answer in January 2012, pursuant to the scheduling order issued by the Court. Following resolution of the new complaint, the Plan may appeal the final judgment to the Seventh Circuit Court of Appeals.

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Based on opinions and orders issued by the Court to date and the $10.2 million of IRS-related offset benefits paid by the Plan in 2011, the Plan currently estimates that the final trial court judgment of damages, after offsetting the additional benefits paid to participants by the Plan, may be up to approximately $17 million, which includes prejudgment interest through Dec. 31, 2011, but does not include any award for plaintiffs’ attorney’s fees or costs or the potential value of additional claims newly asserted in the supplemental complaint by the Plaintiffs in November 2011 whose value is not yet known. WPL does not currently believe any material losses related to the final judgment of damages from this class action lawsuit are both probable and reasonably estimated, and therefore has not recognized any material loss contingency amounts for the final judgment of damages as of Dec. 31, 2011. WPL is currently unable to predict the final outcome of the class action lawsuit or the ultimate impact on its financial condition or results of operations but believes the outcome could have a material effect on its retirement plan funding and expense.

The IRS also considered the interest crediting rate used to project the cash balance account to participants’ normal retirement age as part of its review of Alliant Energy’s request for a favorable determination letter with respect to the tax-qualified status of the Plan. Alliant Energy reached an agreement with the IRS, which resulted in a favorable determination letter for the Plan in 2011. The agreement with the IRS required Alliant Energy to amend the Plan in 2011 resulting in $10.2 million of aggregate additional benefits paid by Alliant Energy to certain former participants in the Plan in 2011. The $10.2 million of aggregate payments by Alliant Energy are an offset against any final judgment of damages by the Court in the case discussed above, in whole or in part, depending on the scope of the final judgment. Refer to Note 6(a) for discussion of the additional benefits costs recognized by WPL in 2011 related to the $10.2 million of benefit payments by Alliant Energy.

Other—WPL is involved in other legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although unable to predict the outcome of these matters, WPL believes that appropriate reserves have been established and final disposition of these actions will not have a material effect on its financial condition or results of operations.

(c) Guarantees and Indemnifications—Refer to Note 3(a) for discussion of WPL’s residual value guarantees of its synthetic leases.

(d) Environmental Matters—WPL is subject to environmental regulations as a result of its current and past operations. These regulations are designed to protect public health and the environment and have resulted in compliance, remediation, containment and monitoring obligations, which are recorded as environmental liabilities. At Dec. 31, current environmental liabilities were included in “Other current liabilities” and non-current environmental liabilities were included in “Other long-term liabilities and deferred credits” on the Consolidated Balance Sheets as follows (in millions):

	2011		2010
Current environmental liabilities	$	1.3	$	0.3
Non-current environmental liabilities		3.8		4.1
	$	5.1	$	4.4

MGP Sites—WPL has current or previous ownership interests in 14 sites previously associated with the production of gas for which it may be liable for investigation, remediation and monitoring costs. WPL has received letters from state environmental agencies requiring no further action at 9 of these sites. WPL is working pursuant to the requirements of various federal and state agencies to investigate, mitigate, prevent and remediate, where necessary, the environmental impacts to property, including natural resources, at and around the sites in order to protect public health and the environment.

WPL records environmental liabilities related to these MGP sites based upon periodic studies. Such amounts are based on the best current estimate of the remaining amount to be incurred for investigation, remediation and monitoring costs for those sites where the investigation process has been or is substantially completed, and the minimum of the estimated cost range for those sites where the investigation is in its earlier stages. There are inherent uncertainties associated with the estimated remaining costs for MGP projects primarily due to unknown site conditions and potential changes in regulatory agency requirements. It is possible that future cost estimates will be greater than current estimates as the investigation process proceeds and as additional facts become known. The amounts recognized as liabilities are reduced for expenditures incurred and are adjusted as further information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their fair value. Management currently estimates the range of remaining costs to be incurred for the investigation, remediation and monitoring of these sites to be $4 million to $6 million. At Dec. 31, 2011, WPL had recorded $5 million in current and non-current environmental liabilities for its remaining costs to be incurred for these MGP sites.

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Refer to Note 1(b) for discussion of regulatory assets recorded by WPL, which reflect the probable future rate recovery of MGP expenditures. Considering the current rate treatment, and assuming no material change therein, WPL believes that the clean-up costs incurred for these MGP sites will not have a material effect on its financial condition or results of operations. Settlement has been reached with all of WPL’s insurance carriers regarding reimbursement for its MGP-related costs and such amounts have been accounted for as directed by the applicable regulatory jurisdiction.

Other Environmental Contingencies—In addition to the environmental liabilities discussed above, WPL is also monitoring various environmental regulations that may have a significant impact on its future operations. Given uncertainties regarding the outcome, timing and compliance plans for these environmental regulations, WPL is currently not able to determine the complete financial impact of these regulations but does believe that future capital investments and/or modifications to its electric generating facilities to comply with these regulations could be significant. Specific current, proposed or potential environmental regulations that may require significant future expenditures by WPL are included below along with a brief description of these environmental regulations.

Air Quality—

CAIR is an emissions trading program that requires SO2 and NOx emissions reductions at WPL’s fossil-fueled EGUs with greater than 25 MW capacity through installation of emission controls and/or purchases of allowances. The requirements for NOx and SO2 reductions started in 2009 and 2010, respectively. The requirements of CAIR remain subject to further review by the federal courts and EPA.

CSAPR (formerly known as the Clean Air Transport Rule) was expected to require SO2 and NOx emissions reductions from WPL’s fossil-fueled EGUs with greater than 25 MW of capacity. CSAPR emissions reductions were expected to replace CAIR beginning in 2012. However, in December 2011, the CSAPR requirements were stayed by the federal courts and CAIR was reinstated. The requirements of CSAPR remain subject to further review by the federal courts and EPA.

Clean Air Visibility Rule (CAVR) addresses regional haze at national parks and wilderness areas and is expected to require reductions in visibility-impairing emissions, including SO2, NOx and particulate matter, from certain EGUs by installing emission controls including those determined to be Best Available Retrofit Technology. The requirements of CAVR remain subject to further review by the federal courts and the EPA. The CAVR SIPs will determine required compliance actions and deadlines.

Utility Maximum Achievable Control Technology (MACT) Rule requires compliance with numerical emission limitations and work practice standards for the control of mercury and other federal hazardous air pollutants for coal- and oil-fueled EGUs with greater than 25 MW capacity. Compliance is currently expected to be required by April 2015.

Wisconsin State Mercury Rule requires WPL’s existing coal-fueled EGUs to reduce annual mercury emissions by 40% from a historic baseline beginning in 2010, and to either achieve a 90% annual mercury emissions reduction standard or limit the annual concentration of mercury emissions to 0.008 pounds of mercury per gigawatt-hour beginning in 2015.

Wisconsin Reasonably Available Control Technology Rule requires NOx emissions reductions at Edgewater to achieve compliance with 2013 requirements since it is located in Sheboygan County, which is currently designated as a non-attainment area for Ozone National Ambient Air Quality Standard (NAAQS). WPL installed NOx emission control technologies at Edgewater to meet 2009 to 2012 compliance requirements under this rule.

Ozone NAAQS Rule reduced the primary standard to a level of 0.075 parts per million. The schedule for compliance with the Ozone NAAQS Rule has not yet been established.

Fine Particle NAAQS Rule is expected to require SO2 and NOx emission reductions in areas designated as non-attainment. The EPA lowered the 24-hour standard and left the annual standard unchanged. In response to a court decision, the EPA is reviewing whether the annual fine particulate matter standard should also be lowered. The schedule for compliance with the Fine Particle NAAQS Rule has not yet been established.

Nitrogen Dioxide (NO2) NAAQS Rule requires a new one-hour NAAQS for NO2 at a level of 100 parts per billion (ppb) and associated ambient air monitoring requirements, while maintaining the current annual standard of 53 ppb. The EPA is expected to re-evaluate non-attainment areas for the NO2 NAAQS in 2016 based on expanded monitoring data. The schedule for compliance has not yet been established.

SO2 NAAQS Rule requires a new one-hour NAAQS for SO2 at a level of 75 ppb. The EPA’s final designations identifying non-attainment areas for the SO2 NAAQS are expected to be issued in 2012. The compliance deadline for SO2 NAAQS is currently expected to be required by 2017 for non-attainment areas.

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Industrial Boiler and Process Heater MACT Rule requires reductions of emissions of hazardous air pollutants at EGUs with less than 25 MW capacity, and auxiliary boilers and process heaters located at EGUs. The requirements of this rule remain subject to further review by the EPA, which proposed a reconsidered rule in December 2011 and expects to issue a final reconsidered rule by April 2012. The compliance deadline for existing units located at major sources subject to the final Industrial Boiler and Process Heater MACT rule is currently 2014, but is expected to be extended to mid-2015 pursuant to the final reconsidered rule.

Water Quality—

Section 316(b) of the Federal Clean Water Act proposal is expected to require modifications to cooling water intake structures to assure that these structures reflect the “best technology available” for minimizing adverse environmental impacts to fish and other aquatic life. The schedule for compliance has not yet been finalized; however, compliance will be required within eight years of the effective date of the final rule. The EPA expects to issue a final rule in 2012.

Wisconsin State Thermal Rule may require modifications to certain of WPL’s EGUs to limit the amount of heat those facilities can discharge into Wisconsin waters. Compliance with the thermal rule will be evaluated on a case-by-case basis as discharge permits for WPL’s EGUs are renewed.

Hydroelectric Fish Passages and Fish Protective Devices—FERC issued an order requiring an agency-approved fish passage to be installed at WPL’s Prairie du Sac hydro plant by December 2012. WPL currently expects to request an extension from FERC in 2012.

Land and Solid Waste—

Coal Combustion Residuals (CCR) could impose additional requirements for CCR management, beneficial use applications and disposal including operation and maintenance of coal ash surface impoundments (ash ponds) and/or landfills. The EPA issued a proposed regulation for public comment in 2010, and a final rule is expected by late 2012. The schedule for compliance with the CCR Rule has not yet been established.

Polychlorinated Biphenyls (PCB)—The EPA is re-examining the current authorized uses of PCB in electrical equipment and other applications to determine if these uses present an unreasonable risk of injury to health and the environment. The EPA is expected to issue proposed PCB rules for public comment in 2013 and could include a possible mandate to phase out all PCB-containing equipment. The schedule for compliance with the PCB Rule has not yet been established.

Greenhouse Gases (GHG) Emissions—

EPA New Source Performance Standard (NSPS) for GHG Emissions from Electric Utilities is expected to require performance standards for GHG emissions from new and existing fossil-fueled EGUs. The EPA announced the issuance of proposed regulations will be delayed for existing EGUs and has not yet established a new schedule. The EPA’s proposed rule for new EGUs is also delayed and is currently expected to be issued in the first quarter of 2012. The schedule for compliance with the NSPS has not yet been established.

EPA GHG Tailoring Rule establishes GHG emissions thresholds for construction and operation of facilities emitting GHG incorporated with air permits applied for after January 2011. The rule also requires new and significantly modified facilities to demonstrate use of the Best Available Control Technologies and energy efficiency measures to minimize GHG emissions.

(e) Credit Risk—WPL is subject to credit risk related to the ability of counterparties to meet their contractual payment obligations or the potential non-performance of counterparties to deliver contracted commodities, other goods or services at the contracted price.

WPL provides regulated electricity and natural gas services to residential, commercial, industrial and wholesale customers in the Midwest region of the U.S. The geographic concentration of its customers did not contribute significantly to its overall exposure to credit risk. In addition, as a result of its diverse customer base, WPL did not have any significant concentration of credit risk for receivables arising from the sale of electricity and natural gas services.

WPL is typically a net buyer of commodities (primarily electricity, coal and natural gas) required to provide regulated electricity and natural gas services to its customers. As a result, WPL is also subject to credit risk related to its counterparties’ failures to deliver commodities at the contracted price.

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WPL maintains credit policies to minimize its credit risk. These credit policies include evaluation of the financial condition of counterparties, use of credit risk-related contingent provisions in certain commodity agreements that require credit support from counterparties that exceed certain exposure limits, diversification of counterparties to minimize concentrations of credit risk and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. Based on these credit policies, it is unlikely that a material effect on WPL’s financial condition or results of operations would occur as a result of counterparty non-performance. However, there is no assurance that such policies will protect WPL against all losses from non-performance by counterparties.

Refer to Notes 1(p) and 12 for details of allowances for doubtful accounts and credit risk-related contingent features, respectively.

(14) JOINTLY-OWNED ELECTRIC UTILITY PLANT

Under joint ownership agreements with other utilities, WPL has undivided ownership interests in jointly-owned electric generating facilities. Each of the respective owners is responsible for the financing of its portion of the construction costs. Kilowatt-hour generation and operating expenses are primarily divided between the joint owners on the same basis as ownership. WPL’s share of expenses from jointly-owned electric generating facilities is included in the corresponding operating expenses (e.g. electric production fuel, other operation and maintenance, etc.) in its Consolidated Statements of Income. Refer to Note 1(b) for further discussion of cost of removal obligations. Information relative to WPL’s ownership interest in these jointly-owned electric generating facilities at Dec. 31, 2011 was as follows (dollars in millions):

	In-service Dates	Fuel Type		Ownership Interest %			Plant in Service		Accumulated Provision for Depreciation		Construction Work in Progress		Cost of Removal Obligations Included in Regulatory Liabilities
Columbia Units 1-2	1975-1978		Coal		46.2	%	$	242.9	$	152.3	$	12.5	$	10.0
Edgewater Unit 4	1969		Coal		68.2	%		88.3		46.3		0.6		2.5
							$	331.2	$	198.6	$	13.1	$	12.5

(15) SEGMENTS OF BUSINESS

WPL is a utility serving customers in Wisconsin and includes three reportable segments: a) electric operations; b) gas operations; and c) other, which includes various other energy-related products and services and the unallocated portions of the utility business. Various line items in the following tables are not allocated to the electric and gas segments for management reporting purposes and therefore are included only in “Total.” Intersegment revenues were not material to WPL’s operations and there was no single customer whose revenues were 10% or more of WPL’s consolidated revenues. Certain financial information relating to WPL’s business segments was as follows (in millions):

	Electric			Gas		Other			Total
2011
Operating revenues	$	1,227.5		$	200.4	$	6.5		$	1,434.4
Depreciation and amortization		127.7			12.4		—			140.1
Operating income (loss)		262.6			27.2		(9.4	)		280.4
Interest expense, net of AFUDC										73.7
Equity income from unconsolidated investments		(38.7	)		—		—			(38.7	)
Income taxes										81.9
Net income										163.5
Preferred dividends										3.3
Earnings available for common stock										160.2
Total assets		3,316.3			360.8		366.9			4,044.0
Investments in equity method subsidiaries		246.5			—		—			246.5
Construction and acquisition expenditures		297.1			16.8		0.5			314.4

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	Electric			Gas		Other			Total
2010
Operating revenues	$	1,209.9		$	206.3	$	7.4		$	1,423.6
Depreciation and amortization		98.0			10.6		—			108.6
Operating income (loss)		250.1			29.8		(1.1	)		278.8
Interest expense, net of AFUDC										66.1
Equity income from unconsolidated investments		(37.8	)		—		—			(37.8	)
Interest income and other										(0.1	)
Income taxes										98.3
Net income										152.3
Preferred dividends										3.3
Earnings available for common stock										149.0
Total assets		3,201.9			357.3		330.4			3,889.6
Investments in equity method subsidiaries		236.0			—		—			236.0
Construction and acquisition expenditures		430.3			19.9		0.3			450.5
	Electric			Gas		Other			Total
2009
Operating revenues	$	1,160.3		$	216.5	$	9.3		$	1,386.1
Depreciation and amortization		103.2			12.2		—			115.4
Operating income (loss)		145.4			24.6		(3.0	)		167.0
Interest expense, net of AFUDC										69.1
Equity income from unconsolidated investments		(37.0	)		—		—			(37.0	)
Interest income and other										(0.4	)
Income taxes										45.8
Net income										89.5
Preferred dividends										3.3
Earnings available for common stock										86.2
Total assets		2,891.0			341.7		448.7			3,681.4
Investments in equity method subsidiaries		227.1			—		—			227.1
Construction and acquisition expenditures		480.5			27.7		0.2			508.4

(16) OTHER INTANGIBLE ASSETS

Emission Allowances—The gross carrying amount and accumulated amortization of emission allowances were recorded as intangible assets in “Deferred charges and other” on the Consolidated Balance Sheets at Dec. 31 as follows (in millions):

	2011		2010
Gross carrying amount	$	0.5	$	3.9
Accumulated amortization		0.5		3.4

Amortization expense for emission allowances was recorded in “Electric production fuel and energy purchases” in the Consolidated Statements of Income. In 2011, 2010 and 2009, amortization expense for emission allowances was $0.5 million, $3.4 million and $4.9 million, respectively. No amortization expense for emission allowances is currently expected to be recorded during 2012 through 2016.

(17) SELECTED CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)

	2011								2010
	March 31		June 30		Sep. 30		Dec. 31		March 31		June 30		Sep. 30		Dec. 31
	(in millions)
Operating revenues	$	388.5	$	326.8	$	374.6	$	344.5	$	392.9	$	312.9	$	369.6	$	348.2
Operating income		74.8		45.5		86.9		73.2		69.7		52.3		86.7		70.1
Net income		44.4		25.0		51.4		42.7		37.0		30.2		50.0		35.1
Earnings available for common stock		43.6		24.1		50.6		41.9		36.2		29.3		49.2		34.3

Earnings per share data is not disclosed for WPL given Alliant Energy is the sole shareowner of all shares of WPL’s common stock outstanding during the periods presented.

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(18) ASSET RETIREMENT OBLIGATIONS

AROs recognized by WPL relate to legal obligations for the removal, closure or dismantlement of several assets including, but not limited to, wind projects, certain ash ponds, active ash landfills and above ground storage tanks. WPL’s recognized AROs also include legal obligations for the management and final disposition of asbestos and PCB. WPL’s AROs are recorded in “Other long-term liabilities and deferred credits” on the Consolidated Balance Sheets. Refer to Note 1(b) for information regarding regulatory assets related to AROs. A reconciliation of the changes in recognized AROs associated with long-lived assets is as follows (in millions):

	2011			2010
Balance, Jan. 1	$	32.3		$	21.4
Accretion expense		1.7			1.3
Liabilities incurred (a)		0.9			9.8
Revisions in estimated cash flows		0.1			—
Liabilities settled		(0.1	)		(0.2	)
Balance, Dec. 31	$	34.9		$	32.3

(a) In 2010, WPL recorded AROs of $9.8 million related to its Bent Tree—Phase I wind project.

In addition, certain of WPL’s AROs related to electric generating facility assets have not been recognized. Due to an indeterminate remediation date, the fair values of the AROs for these assets cannot be currently estimated. A liability for these AROs will be recorded when fair value is determinable.

(19) VARIABLE INTEREST ENTITIES (VIEs)

An entity is considered a VIE if its equity investors do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties or its equity investors lack any one of the following three characteristics: (1) power, through voting rights or similar rights, to direct the activities of the entity that most significantly impact the entity’s economic performance; (2) the obligation to absorb expected losses of the entity; or (3) the right to receive expected benefits of the entity. The primary beneficiary of a VIE is required to consolidate the financial statements of the VIE.

After making an ongoing exhaustive effort, WPL concluded it was unable to obtain the information necessary from the counterparty (subsidiary of Calpine Corporation) for the Riverside PPA for WPL to determine whether the counterparty is a VIE and if WPL is the primary beneficiary. This PPA is currently accounted for as an operating lease. The counterparty for the Riverside PPA sells a portion of its generating capacity to WPL and can sell its energy output to WPL. WPL’s maximum exposure to loss from this PPA is undeterminable due to the inability to obtain the necessary information to complete such evaluation. In 2011, 2010 and 2009, Alliant Energy’s (primarily WPL’s) costs, excluding fuel costs, related to the Riverside PPA were $62 million, $61 million and $63 million, respectively.

(20) RELATED PARTIES

System Coordination and Operating Agreement—WPL and IPL are parties to a system coordination and operating agreement whereby Corporate Services serves as agent on behalf of WPL and IPL. The agreement, which has been approved or reviewed by FERC and all state regulatory bodies having jurisdiction, provides a contractual basis for coordinated planning, construction, operation and maintenance of the interconnected electric generation systems of WPL and IPL. As agent of the agreement, Corporate Services enters into energy, capacity, ancillary services, and transmission sale and purchase transactions. Corporate Services allocates such sales and purchases among WPL and IPL based on procedures included in the agreement. The sales credited to and purchases billed to WPL were as follows (in millions):

	2011		2010		2009
Sales credited	$	28	$	24	$	72
Purchases billed		77		73		121

Service Agreement—Pursuant to a service agreement, WPL receives various administrative and general services from an affiliate, Corporate Services. These services are billed to WPL at cost based on expenses incurred by Corporate Services for the benefit of WPL. These costs totaled $119 million, $127 million and $112 million for 2011, 2010 and 2009, respectively, and consisted primarily of employee compensation, benefits and fees associated with various professional services. As of Dec. 31, 2011 and 2010, WPL had net intercompany payables to Corporate Services of $48 million and $42 million, respectively.

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ATC—Pursuant to various agreements, WPL receives a range of transmission services from ATC. WPL provides operation, maintenance, and construction services to ATC. WPL and ATC also bill each other for use of shared facilities owned by each party. The related amounts billed between the parties were as follows (in millions):

	2011		2010		2009
ATC billings to WPL	$	90	$	92	$	83
WPL billings to ATC		12		11		13

As of Dec. 31, 2011 and 2010, WPL owed ATC net amounts of $6 million and $7 million, respectively.

Acquisition of the Neenah Energy Facility—In 2009, WPL acquired a 300 MW, simple-cycle, dual-fueled (natural gas/diesel) electric generating facility and related inventories (diesel fuel and materials and supplies) located in Neenah, Wisconsin from Resources for $92.4 million. The purchase price was allocated to property, plant and equipment ($90 million), production fuel ($1 million) and materials and supplies ($1 million) based on the net book value of the assets acquired.

Sheboygan Falls Energy Facility Lease—Refer to Note 3(b) for discussion of WPL’s Sheboygan Falls Energy Facility lease.

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SHAREOWNER INFORMATION

Market Information—The 4.50% series of preferred stock is listed on the NYSE Amex LLC, with the trading symbol of WIS_PR. All other series of preferred stock are traded on the over-the-counter market. As of Dec. 31, 2011, 69% of WPL’s individual preferred shareowners were Wisconsin residents.

Dividend Information—Preferred stock dividends paid per share for each quarter during 2011 were as follows:

Series	Dividend
4.40%	$	1.10
4.50%	$	1.125
4.76%	$	1.19
4.80%	$	1.20
4.96%	$	1.24
6.20%	$	1.55
6.50%	$	0.40625

As authorized by the WPL Board of Directors, preferred stock dividend record and payment dates for 2012 are as follows:

Record Date	Payment Date
February 29	March 15
May 31	June 15
August 31	September 14
November 30	December 14

Stock Transfer Agent and Registrar

Wells Fargo Shareowner Services

161 North Concord Exchange

P.O. Box 64854

St. Paul, MN 55164-0854

Form 10-K Information—A copy of the combined Annual Report on Form 10-K for the year ended Dec. 31, 2011 as filed with the SEC will be provided without charge upon request. Requests may be directed to Alliant Energy Shareowner Services, P.O. Box 14720, Madison, Wisconsin 53708-0720.

EXECUTIVE OFFICERS AND DIRECTORS

Executive Officers—Numbers following the names represent the officer’s age as of Feb. 27, 2012, the date the combined Annual Report on Form 10-K for the year ended Dec. 31, 2011 was filed with the SEC.

William D. Harvey, 63, was elected Chairman of the Board effective February 2006 and Chief Executive Officer effective July 2005, and has been a director since January 2005. Mr. Harvey announced his intent to retire effective March 31, 2012.

Patricia L. Kampling, 52, was elected to serve as a director effective Jan. 20, 2012 and to serve as Chairman of the Board and Chief Executive Officer effective April 1, 2012. She has served as Chief Operating Officer since February 2011. She previously served as Executive Vice President and Chief Financial Officer since September 2010, as Executive Vice President-Chief Financial Officer and Treasurer from January 2010 to September 2010, as Vice President-Chief Financial Officer and Treasurer from January 2009 to January 2010, and as Vice President and Treasurer from January 2007 to January 2009.

John O. Larsen, 48, was elected President effective December 2010. He previously served as Senior Vice President-Generation since January 2010, as Vice President-Generation from August 2008 to January 2010 and as Vice President-Technical and Integrated Services from January 2004 to August 2008.

Thomas L. Aller, 62, was elected Senior Vice President-Energy Resource Development effective January 2009. He previously served as Senior Vice President-Energy Delivery since January 2004.

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James H. Gallegos, 51, was elected Vice President and General Counsel effective November 2010. He previously served as Vice President and Corporate General Counsel of BNSF Railway Company, a subsidiary of Burlington Northern and Santa Fe Corporation from April 2003 to April 2010.

Thomas L. Hanson, 58, was elected Vice President and Chief Financial Officer effective May 2011. He previously served as Vice President-Chief Financial Officer and Treasurer since February 2011, Vice President-Chief Accounting Officer and Treasurer from September 2010 to February 2011, and as Vice President-Controller and Chief Accounting Officer from January 2007 to September 2010.

Robert J. Durian, 41, was elected Controller and Chief Accounting Officer effective February 2011. He previously served as Controller since September 2010, as Assistant Controller from March 2009 to September 2010 and as Director of Financial Reporting from February 2006 to March 2009.

Directors—Refer to WPL’s Proxy Statement for information on WPL’s board members.

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	Shareowner Services P.O. Box 64945 St. Paul, MN 55164-0945
Address Change? Mark box, sign, and indicate changes below:     ¨

2012 ANNUAL MEETING - May 21, 2012

The Board of Directors recommends a vote “FOR” all nominees listed in Proposal 1, “FOR” Proposal 2 and “FOR” Proposal 3.
1. Election of directors:	Nominees for terms ending in 2014:	Nominees for terms ending in 2015:	¨	FOR all nominees (except as marked to the contrary below)	¨	WITHHOLD AUTHORITY (to vote for all nominees)
	(01) Patrick E. Allen	(03) Ann K. Newhall
	(02) Patricia L. Kampling	(04) Dean C. Oestreich
		(05) Carol P. Sanders
È Please fold here – Do not separate È
(Instructions: To withhold authority to vote for any indicated nominee, write that nominee’s number in the box.)

2. Advisory vote on approval of the compensation of the Company’s named executive officers.	¨	For	¨	Against	¨	Abstain
3. Ratification of the appointment of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for 2012.	¨	For	¨	Against	¨	Abstain
This proxy, when properly executed, will be voted in the manner directed herein by the shareowner. If no direction is made, then the proxy will be voted “FOR” all nominees listed in Proposal 1, “FOR” Proposal 2, “FOR” Proposal 3 and in the discretion of the proxies upon such other matters what may properly come before the meeting or any adjournment or postponement thereof.
(Important information contained on reverse side; please read.)

Date
	Signature(s) in Box Please sign exactly as your name(s) appears on this Proxy. If held in joint tenancy, all persons should sign. Trustees, administrators, etc., should include title and authority. Corporations should provide full name of corporation and title of authorized officer signing the Proxy.

WISCONSIN POWER AND LIGHT COMPANY

2012 Annual Meeting of Shareowners

Monday, May 21, 2012,

at 2:30 p.m. (Central Daylight Time)

Alliant Energy Corporate Headquarters

Sandy River Conference Room

4902 North Biltmore Lane

Madison, WI 53718

Photo ID required for entry.

www.shareowneronline.com

1-800-356-5343

To access the Wisconsin Power and Light Company Annual Report and proxy statement on the Internet, please open Alliant Energy’s website at www.alliantenergy.com/WPLproxy. We encourage you to check out Alliant Energy’s website to see how easy and convenient it is. You may print or just view these materials.

	Wells Fargo Shareowner Services
	P.O. Box 64873
	St. Paul, MN 55164-0873	proxy

This proxy is solicited on behalf of the Board of Directors of Wisconsin Power and Light Company.

The undersigned appoints John O. Larsen and F. J. Buri, or either of them, attorneys and proxies with the power of substitution to vote all shares of stock of Wisconsin Power and Light Company (the “Company”), held of record in the name of the undersigned at the close of business on April 3, 2012, at the Annual Meeting of Shareowners of the Company to be held at 4902 N. Biltmore Lane, Madison, Wisconsin at 2:30 p.m., and at all adjournments thereof, upon all matters that properly come before the meeting, including the matters described in the Company’s Notice of Annual Meeting of Shareowners dated April, 17, 2012, and accompanying proxy statement, subject to any directions indicated on the reverse side of this card.

VOTE BY MAIL

Mark, sign and date your proxy card and return it in the postage-paid envelope provided.

Your proxy card must be received by May 18, 2012.