Wisconsin Public Service (WSPBP) 10-K 2011 FY Annual report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D. C.  20549

FORM 10-K

(Mark One)

xANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

OR

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                          to                         

Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	IRS Employer Identification No.
1-3016	WISCONSIN PUBLIC SERVICE CORPORATION (A Wisconsin Corporation) 700 North Adams Street P. O. Box 19001 Green Bay, WI 54307-9001 800-450-7260	39-0715160

Securities registered pursuant to Section 12(b) of the Act:  None

Securities registered pursuant to Section 12(g) of the Act:

Preferred Stock, Cumulative, $100 par value

5.00% Series
5.04% Series 5.08% Series
6.76% Series 6.88% Series

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  o  No  x

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes  o  No  x

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  x    No  o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes  x    No  o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o	Accelerated filer o
Non-accelerated filer x	Smaller reporting company o

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  o  No  x

State the aggregate market value of the voting and
non-voting common equity held by non-affiliates of the Registrant.

None.

Number of shares outstanding of each class
of common stock, as of February 24, 2012

Common Stock, $4 par value, 23,896,962 shares. Integrys Energy Group, Inc. is the sole holder of
Wisconsin Public Service Corporation Common Stock.

DOCUMENT INCORPORATED BY REFERENCE

Portions of the definitive proxy statement for the Integrys Energy Group, Inc. Annual Meeting of Shareholders to be held on May 10, 2012, are incorporated by reference into Part III.

WISCONSIN PUBLIC SERVICE CORPORATION

ANNUAL REPORT ON FORM 10-K
For the Year Ended December 31, 2011

TABLE OF CONTENTS

			Page
Forward-Looking Statements			1
PART I			3
ITEM 1.	BUSINESS		3
	A.	GENERAL	3
	B.	ELECTRIC UTILITY OPERATIONS	3
	C.	NATURAL GAS UTILITY OPERATIONS	7
	D.	ENVIRONMENTAL MATTERS	9
	E.	CAPITAL REQUIREMENTS	10
	F.	EMPLOYEES	10
ITEM 1A.	RISK FACTORS		11
ITEM 1B.	UNRESOLVED STAFF COMMENTS		16
ITEM 2.	PROPERTIES		17
ITEM 3.	LEGAL PROCEEDINGS		19
ITEM 4.	MINE SAFETY DISCLOSURES		19
PART II			19
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES		19
ITEM 6.	SELECTED FINANCIAL DATA		20
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		21
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		43
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		45
	A.	Management Report on Internal Control over Financial Reporting	45
	B.	Consolidated Statements of Income	46
	C.	Consolidated Balance Sheets	47
	D.	Consolidated Statements of Capitalization	48
	E.	Consolidated Statements of Common Shareholder’s Equity	49
	F.	Consolidated Statements of Cash Flows	50
	G.	Notes to Consolidated Financial Statements	51-95

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		Note 1	Summary of Significant Accounting Policies	51
		Note 2	Risk Management Activities	57
		Note 3	Restructuring Expense	59
		Note 4	Property, Plant, and Equipment	60
		Note 5	Jointly Owned Utility Facilities	60
		Note 6	Regulatory Assets and Liabilities	61
		Note 7	Leases	62
		Note 8	Short-Term Debt and Lines of Credit	62
		Note 9	Long-Term Debt	64
		Note 10	Asset Retirement Obligations	65
		Note 11	Income Taxes	66
		Note 12	Commitments and Contingencies	68
		Note 13	Guarantees	74
		Note 14	Employee Benefit Plans	74
		Note 15	Preferred Stock	83
		Note 16	Common Equity	83
		Note 17	Stock-Based Compensation	84
		Note 18	Variable Interest Entities	88
		Note 19	Fair Value	89
		Note 20	Miscellaneous Income	91
		Note 21	Regulatory Environment	91
		Note 22	Segments of Business	92
		Note 23	Related Party Transactions	93
		Note 24	Quarterly Financial Information (Unaudited)	95
	H.	Report of Independent Registered Public Accounting Firm on Financial Statements			96
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE				97
ITEM 9A.	CONTROLS AND PROCEDURES				97
ITEM 9B.	OTHER INFORMATION				97
PART III					98
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE				98
ITEM 11.	EXECUTIVE COMPENSATION				101
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS				115
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE				116
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES				116
PART IV					118
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES				118
SIGNATURES					119
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS					120
EXHIBIT INDEX					121

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Acronyms Used in this Annual Report on Form 10-K

AFUDC	Allowance For Funds Used During Construction
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
ATC	American Transmission Company LLC
EPA	United States Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	United States Generally Accepted Accounting Principles
IBS	Integrys Business Support, LLC
IRS	United States Internal Revenue Service
MERC	Minnesota Energy Resources Corporation
MGU	Michigan Gas Utilities Corporation
MISO	Midwest Independent Transmission System Operator, Inc.
MPSC	Michigan Public Service Commission
N/A	Not Applicable
NSG	North Shore Gas Company
NYMEX	New York Mercantile Exchange
OCI	Other Comprehensive Income
PELLC	Peoples Energy, LLC (formerly known as Peoples Energy Corporation)
PGL	The Peoples Gas Light and Coke Company
PSCW	Public Service Commission of Wisconsin
SEC	United States Securities and Exchange Commission
UPPCO	Upper Peninsula Power Company
WDNR	Wisconsin Department of Natural Resources
WPS	Wisconsin Public Service Corporation
WRPC	Wisconsin River Power Company

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Forward-Looking Statements

In this report, we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance.  These statements are “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended.  Forward-looking statements are not guarantees of future results and conditions, but rather are subject to numerous management assumptions, risks, and uncertainties.  Therefore, actual results may differ materially from those expressed or implied by these statements.  Although we believe that these forward-looking statements and the underlying assumptions are reasonable, we cannot provide assurance that such statements will prove correct.

Forward-looking statements involve a number of risks and uncertainties.  Some risks that could cause actual results to differ materially from those expressed or implied in forward-looking statements include those described in Item 1A of this Annual Report on Form 10-K for the year ended December 31, 2011 and those identified below:

·The timing and resolution of rate cases and related negotiations, including recovery of deferred and current costs and the ability to earn a reasonable return on investment, and other regulatory decisions impacting us;

·Federal and state legislative and regulatory changes relating to the environment, including climate change and other environmental regulations impacting coal-fired generation facilities and renewable energy standards;

·Other federal and state legislative and regulatory changes, including deregulation and restructuring of the electric and natural gas utility industries, financial reform, health care reform, energy efficiency mandates, reliability standards, pipeline integrity and safety standards, and changes in tax and other laws and regulations to which we and our subsidiary are subject;

·Costs and effects of litigation and administrative proceedings, settlements, investigations, and claims, including manufactured gas plant site cleanup, third-party intervention in permitting and licensing projects, and compliance with Clean Air Act requirements at generation plants;

·Changes in credit ratings and interest rates caused by volatility in the financial markets and actions of rating agencies and their impact on our liquidity and financing efforts;

·The risks associated with changing commodity prices, particularly natural gas and electricity, and the available sources of fuel, natural gas, and purchased power, including their impact on margins, working capital, and liquidity requirements;

·The timing and outcome of any audits, disputes, and other proceedings related to taxes;

·The effects, extent, and timing of additional competition or regulation in the markets in which we operate;

·The investment performance of employee benefit plan assets and related actuarial assumptions, which impact future funding requirements;

·The impact of unplanned facility outages;

·Changes in technology, particularly with respect to new, developing, or alternative sources of generation;

·The effects of political developments, as well as changes in economic conditions and the related impact on customer use, customer growth, and our ability to adequately forecast energy use for customers;

·Potential business strategies, including acquisitions and construction or disposition of assets or businesses, which cannot be assured to be completed timely or within budgets;

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·The risk of terrorism or cyber security attacks, including the associated costs to protect our assets and respond to such events;

·The risk of failure to maintain the security of personally identifiable information, including the associated costs to notify affected persons and to mitigate their information security concerns;

·The effectiveness of risk management strategies, the use of financial and derivative instruments, and the related recovery of these costs from customers in rates;

·The risk of financial loss, including increases in bad debt expense, associated with the inability of our counterparties, affiliates, and customers to meet their obligations;

·Unusual weather and other natural phenomena, including related economic, operational, and/or other ancillary effects of any such events;

·The effect of accounting pronouncements issued periodically by standard-setting bodies; and

·Other factors discussed elsewhere herein and in other reports we and/or Integrys Energy Group file with the SEC.

Except to the extent required by the federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

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PART I

ITEM 1.  BUSINESS

A.  GENERAL

In this report, when we refer to “us,” “we,” “our,” or “ours,” we are referring to Wisconsin Public Service Corporation.  References to “Notes” are to the Notes to the Consolidated Financial Statements included in this Annual Report on Form 10-K.

We are a Wisconsin corporation and a wholly owned subsidiary of Integrys Energy Group, Inc.  We began operations in 1883.  We are a regulated electric and natural gas utility company serving an approximate 11,000 square mile service territory in northeastern Wisconsin and an adjacent portion of Michigan’s Upper Peninsula.  In 2011, electric revenues accounted for 78% of our total revenues, while natural gas revenues accounted for 22% of our total revenues.

For more financial information about our electric and natural gas utility operations, see Note 22, “Segments of Business” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations.”

Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, registration statements, and any amendments to these documents are available, free of charge, on Integrys Energy Group’s website, www.integrysgroup.com, as soon as reasonably practicable after they are filed with or furnished to the SEC.  Reports, statements, and amendments posted on Integrys Energy Group’s website do not include access to exhibits and supplemental schedules electronically filed with the reports, statements, or amendments.  We are not including the information contained on or available through the Integrys Energy Group website as a part of, or incorporating such information by reference into, this Annual Report on Form 10-K.

You may obtain materials we filed with or furnished to the SEC at the SEC Public Reference Room at 100 F Street, NE, Washington, DC  20549.  To obtain information on the operation of the Public Reference Room, you may call the SEC at 1-800-SEC-0330.  You may also view our reports, statements, and other information (including exhibits) filed or furnished electronically with the SEC, at the SEC’s website at www.sec.gov.

B.  ELECTRIC UTILITY OPERATIONS

Our electric utility operations provide service to approximately 441,000 residential, commercial and industrial, wholesale, and other customers.  Our customers are located in northeastern Wisconsin and an adjacent portion of Michigan’s Upper Peninsula.  Wholesale electric service is provided to various customers, including municipal utilities, electric cooperatives, energy marketers, other investor-owned utilities, and municipal joint action agencies.  In 2011, retail revenues accounted for 80.3% of total electric revenues, while wholesale revenues accounted for 19.7% of total electric revenues.

In 2011, we reached a firm net design peak of 2,344 megawatts (MW) on July 20.  At the time of this summer peak, our total firm resources (i.e., generation plus firm purchases) totaled 3,164 MW.  The summer period is the most relevant for our electric utility capacity due to the air conditioning requirements of our customers.  The PSCW requires us to maintain a planning reserve margin above our

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projected annual peak demand forecast to help ensure reliability of electric service to our customers.  The PSCW has a 14.5% reserve margin requirement for long-term planning (planning years two through ten).  For short-term planning (planning year one), the PSCW requires Wisconsin utilities to follow the planning reserve margin established by MISO under Module E of its Open Access Transmission and Energy Markets Tariff.  MISO has a 17.4% reserve margin requirement from January 1 through May 31, 2012, and 14.4% for the remainder of 2012. The MPSC does not have minimum guidelines for future supply reserves.

We expect future supply reserves to meet the minimum planning reserve margin requirements for 2012.  We had adequate capacity through company-owned generation units and power purchase contracts to meet all firm electric demand obligations during 2011 and expect to have adequate capacity to meet all obligations during 2012.

Facilities

For a complete list of our electric utility facilities, see Item 2, “Properties.”  For our utility plant asset book value, see Note 4, “Property, Plant, and Equipment.”

Electric Supply

We are a member of MISO, a FERC-approved, independent, non-profit organization, which operates a financial and physical electric wholesale market in the Midwest.  We offer our generation and bid our customer load into the MISO market.  MISO evaluates our and other market participants’ energy offers into, and subsequent withdrawals from, the system to economically dispatch electricity within the system.  MISO settles the participants’ offers and bids based on locational marginal prices, which are market-driven values based on the specific time and location of the purchase and/or sale of energy.

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Electric Generation and Supply Mix

The sources of our electric utility supply were as follows:

(Millions)
Energy Source (kilowatt-hours)	2011		2010		2009
Company-owned generation units
Coal	8,634.5		10,232.9		8,974.3
Wind	309.3		287.7		46.4
Hydroelectric	259.5		232.8		161.1
Natural gas, fuel oil, and tire derived	135.4		104.0		63.5
Total company-owned generation units	9,338.7		10,857.4		9,245.3
Power purchase contracts
Nuclear (Kewaunee Power Station)	2,674.4		2,940.8		2,663.9
Natural gas (Fox Energy Center, LLC and Combined Locks Energy Center, LLC)	1,593.9		608.4		673.7
Hydroelectric	570.7		526.7		569.5
Wind	210.6		149.1		136.9
Other	235.8		205.5		571.1
Total power purchase contracts	5,285.4		4,430.5		4,615.1
Purchased power from MISO	1,349.6		742.1		1,740.5
Total purchased power	6,635.0		5,172.6		6,355.6
Opportunity sales
Sales to MISO	(1,239.0	)	(668.6	)	(421.7	)
Net sales to other	(64.6	)	(248.4	)	(373.6	)
Total opportunity sales	(1,303.6	)	(917.0	)	(795.3	)
Total electric utility supply	14,670.1		15,113.0		14,805.6

Fuel Costs

The cost of fuel per generation of one million British thermal units was as follows:

Fuel Type	2011		2010		2009
Coal	$	2.44	$	2.05	$	1.94
Natural gas	5.64		6.28		6.73
Fuel oil	21.18		26.59		28.88

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Coal Supply

Coal is the primary fuel source for our electric generation facilities.  Our regulated fuel portfolio strategy is to maintain a 35- to 45-day supply of coal at each plant site.  Currently the coal supply is higher than the portfolio strategy due to lower coal burning rates as a result of decreased natural gas prices and economic conditions. The majority of the coal is purchased from Powder River Basin mines located in Wyoming.  This low sulfur coal has been our lowest cost coal source of any of the subbituminous coal-producing regions in the United States.  Historically, we have purchased coal directly from the producer for our wholly owned plants.  We also purchase the coal for the jointly owned Weston 4 plant and Dairyland Power Cooperative reimburses us for their share of the coal costs.  Wisconsin Power and Light purchases coal for the jointly owned Edgewater and Columbia plants and we reimburse them for our share of the coal costs.  At December 31, 2011, we had coal transportation contracts in place for 100% of our 2012 coal transportation requirements.  For more information on coal purchases and coal deliveries under contract, see Note 12, “Commitments and Contingencies.”

Power Purchase Agreements

We enter into short-term and long-term power purchase agreements to meet a portion of our electric energy supply needs.  For more information on power purchase obligations, see Note 12, “Commitments and Contingencies.”

Regulatory Matters

Our retail electric rates are regulated by the PSCW and the MPSC.  The FERC regulates our wholesale electric rates.  We must also comply with mandatory electric system reliability standards developed by the North American Electric Reliability Corporation (NERC), the electric reliability organization certified by the FERC. The Midwest Reliability Organization is responsible for the enforcement of NERC’s standards for us.

The PSCW sets rates through its ratemaking process, which is based on recovery of operating costs and a return on invested capital.  One of the cost recovery components is fuel and purchased power, which is governed by a fuel window mechanism, as described in Note 1(f), “Summary of Significant Accounting Policies — Revenues and Customer Receivables.”  The MPSC and the FERC ratemaking processes are similar to those of the PSCW, with the exception of fuel and purchased power, which are recovered on a one-for-one basis.

See Note 21, “Regulatory Environment,” for information regarding our rate cases and decoupling mechanisms.

Hydroelectric Licenses

We and WRPC (a company in which we have 50% ownership) have long-term licenses from the FERC for our hydroelectric facilities.

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Other Matters

Seasonality

Our electric utility sales are generally higher during the summer months due to the air conditioning requirements of customers.

Competition

The retail electric utility market in Wisconsin is regulated by the PSCW.  Retail electric customers currently do not have the ability to choose their electric supplier.  In order to increase sales, utilities work to attract new customers into their service territories.  As a result, there is competition among utilities to keep energy rates low.  Wisconsin utilities have continued to refine regulated tariffs in order to pass on the true cost of electricity to each class of customer by reducing or eliminating rate subsidies among different ratepayer classes.  Although Wisconsin electric energy markets are regulated, utilities still face competition from other energy sources, such as self-generation by large industrial customers and alternative energy sources.

Michigan electric energy markets are open to competition.  However, an active competitive market has not yet developed in the Upper Peninsula of Michigan, primarily due to a lack of excess generation and transmission system capacity.

C.  NATURAL GAS UTILITY OPERATIONS

Our natural gas utility operations provide service to approximately 319,000 residential, commercial and industrial, transportation, and other customers.  Our customers are located in northeastern Wisconsin and an adjacent portion of Michigan’s Upper Peninsula.

Facilities

For information regarding our natural gas facilities, see Item 2, “Properties.”  For our utility plant asset book value, see Note 4, “Property, Plant, and Equipment.”

Natural Gas Supply

We manage a portfolio of natural gas supply contracts, storage services, and pipeline transportation services designed to meet varying customer use patterns at the lowest reasonable cost.

Our natural gas supply requirements are met through a combination of index price purchases, contracted storage, and natural gas supply call options.  We contract for fixed-term firm natural gas supply each year to meet the demand of firm system sales customers.  To supplement natural gas supply and manage risk, we purchase additional natural gas supply on the monthly and daily spot markets.

For more information on our natural gas utility supply and transportation contracts, see Note 12, “Commitments and Contingencies.”

We contract with various underground storage service providers for storage services.  Storage allows us to manage significant changes in daily natural gas demand and to purchase steady levels of natural gas

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on a year-round basis, thus providing a hedge against supply cost volatility.  In addition, we use financial instruments such as commodity futures and options as part of our hedging program to further reduce supply cost volatility.

We had adequate capacity to meet all firm natural gas demand obligations during 2011 and expect to have adequate capacity to meet all firm obligations during 2012.  Our forecast design peak-day throughput is 610 thousands of dekatherms (MDth) for the 2011 through 2012 heating season.

The sources of our deliveries to customers (including transportation customers) in MDth were as follows:

(MDth)	2011		2010	2009
Natural gas purchases	43,310		34,618	39,468
Natural gas purchases for electric generation	1,780		1,389	957
Customer-owned natural gas received	33,497		33,233	33,849
Underground storage, net	(1,013	)	906	(149	)
Contracted pipeline and storage compressor fuel, franchise requirements, and unaccounted-for natural gas	(2,820	)	344	(351	)
Total	74,754		70,490	73,774

Regulatory Matters

Our natural gas retail rates are regulated by the PSCW and the MPSC.  These commissions have general supervisory and regulatory powers over public utilities in Wisconsin and Michigan, respectively.

Sales are made and services are rendered pursuant to rate schedules on file with the PSCW and MPSC.  These rate schedules contain various service classifications, which largely reflect customers’ different uses and levels of consumption.  We bill customers for the distribution of natural gas as well as for a natural gas charge representing third-party costs for purchasing, transporting, and storing natural gas.  This charge also includes gains, losses, and costs incurred under a hedging program, the amount of which is also subject to PSCW and MPSC authority.  Prudently incurred natural gas costs are passed directly through to customers in rates and, therefore, have no impact on margins.  Commissions in respective jurisdictions conduct annual proceedings regarding the reconciliation of revenues from the natural gas charge and related natural gas costs.

Almost all of the natural gas we distribute is transported to our distribution systems by interstate pipelines. The pipelines’ transportation and storage services are regulated by the FERC under the Natural Gas Act and the Natural Gas Policy Act of 1978.  Under United States Department of Transportation regulations, the PSCW is responsible for monitoring our safety compliance program for our pipelines under 49 Code of Federal Regulations (CFR) Part 192 (Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards) and 49 CFR Part 195 (Transportation of Hazardous Liquids by Pipeline).

We are required to provide service and grant credit (with applicable deposit requirements) to customers within our service territories.  We are generally not allowed to discontinue service during winter moratorium months to residential customers who do not pay their bills.  Federal, Wisconsin, and Michigan governments have legislation that provides for a limited amount of funding for assistance to our low-income customers.

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See Note 21, “Regulatory Environment,” for information regarding our rate cases and decoupling mechanisms.

Other Matters

Seasonality

Our natural gas throughput is generally higher during the winter months because the heating requirements of customers are temperature driven.  During 2011, the regulated natural gas utility segment recorded approximately 64% of its revenues in January, February, March, November, and December.

Competition

Although our natural gas retail rates are regulated by the PSCW and MPSC, we still face competition from other entities and forms of energy in varying degrees, particularly for large commercial and industrial customers who have the ability to switch between natural gas and alternate fuels.  Due to the volatility of energy commodity prices, we have seen customers with dual fuel capability switch to alternate fuels for short periods of time, then switch back to natural gas as market rates change.

We offer natural gas transportation service and interruptible natural gas sales to enable customers to better manage their energy costs.  Such transportation customers purchase natural gas directly from third-party natural gas suppliers and use our distribution system to transport the natural gas to their facilities.  We still earn a distribution charge for transporting the natural gas for these customers.  As such, the loss of revenue associated with the cost of natural gas our transportation customers now purchase from the third-party suppliers has no impact on our natural gas utility segment net income, as it is offset by an equal reduction to natural gas costs.  Additionally, some customers have elected to purchase their natural gas directly from us on an interruptible basis, as a means to reduce their costs.  Customers continue to switch between firm system supply, interruptible system supply, and transportation service each year as the economics and service options change.

Working Capital Requirements

The working capital needs of our natural gas utility operations vary significantly over time due to volatility in levels of natural gas inventories and the price of natural gas.  Our working capital needs are met by cash generated from operations and short-term debt.  The seasonality of natural gas revenues causes the timing of cash collections to be concentrated from January through June.  A portion of the winter natural gas supply needs is typically purchased and stored from April through November.  Also, planned capital spending on our natural gas distribution facilities is concentrated in April through November.  Because of these timing differences, the cash flow from customers is typically supplemented with temporary increases in short-term borrowings (from external sources) during the late summer and fall.  Short-term debt is typically reduced over the January through June period.

D.  ENVIRONMENTAL MATTERS

For information on our environmental matters, see Note 12, “Commitments and Contingencies.”

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E.  CAPITAL REQUIREMENTS

For information on our capital requirements, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

F.  EMPLOYEES

At December 31, 2011, we had 1,304 employees, of which approximately 69% were union employees represented by Local 310 of the International Union of Operating Engineers.  The current Local 310 collective bargaining agreement expires on October 13, 2012.

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ITEM 1A.               RISK FACTORS

You should carefully consider the following risk factors, as well as the other information included or incorporated by reference in this Annual Report on Form 10-K,when making an investment decision.

We are subject to government regulation, which may have a negative impact on our business, financial position, and results of operations.

We are subject to comprehensive regulation by several federal and state regulatory agencies and local governmental bodies.  This regulation significantly influences our operating environment and may affect our ability to recover costs from utility customers.  Many aspects of our operations are regulated, including, but not limited to, construction and operation of facilities, conditions of service, the issuance of securities, and the rates that we can charge customers.  We are required to have numerous permits, approvals, and certificates from these agencies to operate our business.  Failure to comply with any applicable rules or regulations may lead to penalties or customer refunds, which could have a material adverse impact on our financial results.

Existing statutes and regulations may be revised or reinterpreted by federal and state regulatory agencies, or these agencies may adopt new laws and regulations that apply to us.  We are unable to predict the impact on our business and operating results of any such actions by these agencies.  However, changes in regulations or the imposition of additional regulations may require us to incur additional expenses or change business operations, which may have an adverse impact on results of operations.

The rates that we are allowed to charge for our retail and wholesale services are the most important factors influencing our business, financial position, results of operations, and liquidity.  Rate regulation is premised on providing an opportunity to recover prudently incurred costs and earn a reasonable rate of return on invested capital.  However, there is no assurance that regulatory commissions will consider all of our regulated costs to have been prudently incurred.  In addition, the regulatory process will not always result in rates that will produce full recovery of such costs or provide for a reasonable return on equity.  Certain expense and revenue items are deferred as regulatory assets and liabilities for future recovery or refund to customers, as authorized by regulators.  Future recovery of regulatory assets is not assured, and is generally subject to review by regulators in rate proceedings for prudence and reasonableness.  If recovery of costs is not approved or is no longer deemed probable, regulatory assets would be recognized in current period expense and could have a material adverse impact on our financial results.

We are subject to environmental laws and regulations, compliance with which could be difficult and costly.

We are subject to numerous federal and state environmental laws and regulations that affect many aspects of our operations, including future operations.  These laws and regulations relate to air emissions, water quality, wastewater discharges, and the generation, transport, and disposal of solid wastes and hazardous substances.  These laws and regulations require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections, and other approvals.  Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, install pollution control equipment or environmental monitoring equipment at our facilities, incur fees for emissions and permits, and incur expenditures for cleanup costs, damages

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arising from contaminated properties, and monitoring obligations.   In addition, there is uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.  Compliance with current and future environmental laws and regulations may result in increased capital, operating, and other costs, and non-compliance could result in fines, penalties, and injunctive measures affecting our facilities.

Existing environmental laws or regulations may also be revised and/or new laws or regulations seeking to protect the environment may be adopted or become applicable to us.  These laws and regulations include, but are not limited to, regulation regarding mercury, sulfur dioxide, and nitrogen oxide emissions, and the management of coal combustion byproducts, including fly ash.  The steps we could be required to take to ensure that our facilities are in compliance with any such laws and regulations could be prohibitively expensive.  As a result, certain coal-fired electric generating facilities may become uneconomical to run and could result in early retirement of some of our units or may force us to convert the units to an alternative type of fuel.  Costs associated with these potential actions could affect our results of operations and financial condition.

We are accruing liabilities and deferring costs (recorded as regulatory assets) incurred in connection with our former manufactured gas plant sites.   These costs include all recoverable costs incurred to date, management’s best estimates of future costs for investigation and remediation, and legal expenses, and are net of amounts recovered by or that may be recovered from insurance or other entities.   The ultimate costs to remediate these sites could also vary from the amounts currently accrued.

Citizen groups that feel environmental regulations are not being sufficiently enforced by environmental regulatory agencies may also bring citizen enforcement actions against us.  Such actions could seek penalties, injunctive relief, and costs of litigation.  There is also a risk that private citizens may bring lawsuits to recover environmental damages they believe they have incurred.

We may incur significant costs if laws or regulations are adopted to address climate change.

Political interest in climate change and the effects of greenhouse gas emissions, most notably carbon dioxide, are a concern for the energy industry.  Although no legislation is currently pending that would affect us, state or federal legislation could be passed in the future to regulate greenhouse gas emissions.  In addition, the EPA has adopted regulations under the Clean Air Act (CAA) that apply to permitting new or significantly modified facilities.  The EPA also announced its intent to develop new source performance standards for greenhouse gas emissions.  The standards would apply to new and modified, as well as existing, electric utility steam generating units.  Until legislation is passed at the federal or state level or the EPA adopts final rules for electric utility steam generating units, it remains unclear as to (1) which industry sectors will be impacted, (2) when compliance will be required, (3) the magnitude of the greenhouse gas emissions reductions that will be required, and (4) the costs and opportunities associated with compliance.

It is possible that future carbon regulation will increase the cost of electricity produced at coal-fired generation units.  Future regulation may also affect the capital expenditures we would make at our generation units, including costs to further limit the greenhouse gas emissions from our operations through carbon capture and storage technology.  Any such regulation may also create substantial additional costs in the form of taxes or emission allowances and could also affect the availability or cost of fossil fuels.  Future legislation designed to reduce greenhouse gas emissions could make some

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generating units uneconomical to maintain or operate and could impact future results of operations, cash flows, and financial condition if such costs are not recoverable through regulated rates.

Our natural gas delivery systems may generate fugitive gas as a result of normal operations and as a result of excavation, construction, and repair of natural gas delivery systems.  Fugitive gas typically vents to the atmosphere and consists primarily of methane, a greenhouse gas.  Carbon dioxide is also a byproduct of natural gas consumption.  As a result, future legislation to regulate greenhouse gas emissions could increase the price of natural gas, restrict the use of natural gas, adversely affect our ability to operate our natural gas facilities, and/or reduce natural gas demand, which could have a material adverse impact on our results of operations and financial condition.

Our operations are subject to various conditions which can result in fluctuations in the number of customers and their usage.

Our operations are affected by the demand for electricity and natural gas, which can vary greatly based upon:

·          Fluctuations in general economic conditions and growth in the service areas in which we operate;

·          Weather conditions and seasonality;

·          The amount of energy available from current or new competitors; and

·          Our customers’ continued focus on energy efficiency.

Our operations are subject to risks arising from the reliability of our power plants and distribution system, as well as the reliability of third-party transmission providers.

The operation of electric generation and natural gas and electric distribution facilities involves many risks, including the risk of potential breakdown or failure of equipment or processes, which may occur due to storms, natural disasters, or other catastrophic events.  Other risks include aging infrastructure, fuel supply or transportation disruptions, accidents, employee labor disputes, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, and performance below expected levels.  Because our electric generation facilities are interconnected with third-party transmission facilities, the operation of our facilities could also be adversely affected by unexpected or uncontrollable events occurring on the systems of these third parties.

Operation of our power plants below expected capacity could result in lost revenues and increased expenses, including higher operating and maintenance costs, purchased power costs, and capital requirements.  Unplanned outages of generating units and extensions of scheduled outages due to mechanical failures or other problems may occur and are an inherent risk of our business.  Unplanned outages may reduce our revenues or may require us to incur significant costs as a result of selling less electric energy, including having to operate our higher cost electric generators or obtaining replacement power from third parties in the open market to satisfy our power sales obligations.  Insurance, warranties, performance guarantees, or recovery through the regulatory process may not cover any or all of the lost revenues or increased expenses.

New and pending environmental regulations may force many generation facility owners in the Midwest, including us, to retire a significant number of older coal-fired generation facilities, resulting in a potential reduction in the region’s capacity reserve margin to below acceptable risk levels. This could also impair

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the reliability of the Midwest portion of the grid, especially during peak demand periods.  A reduction in available future capacity could also adversely affect our ability to serve our customers’ needs.

We are obligated to provide safe and reliable service to customers within our service territories.  Meeting this commitment requires significant capital resources.  Failure to provide safe and reliable service and failure to meet regulatory reliability standards could adversely affect our operating results through the imposition of penalties and fines or other adverse regulatory outcomes.

Our operations are subject to risks beyond our control, including but not limited to, cyber security attacks, terrorist attacks, acts of war, or loss of personally identifiable information.

Any future terrorist attack, cyber security attack, and/or act of war affecting our facilities and operations could have an adverse impact on our results of operations, financial condition, and cash flows.  The energy industry uses sophisticated information technology systems and network infrastructure, which control an interconnected system of generation, distribution, and transmission systems with other third parties.  A cyber security attack may occur despite our security measures or those that we require our vendors to take, including compliance with reliability standards and critical infrastructure protection standards.  Cyber security attacks, including those targeting information systems and electronic control systems used at generating facilities and electric and natural gas transmission and distribution systems, could severely disrupt our operations and result in loss of service to customers.  The risk of such attacks may also increase our capital and operating costs as a result of having to implement increased security measures for protection of our information technology and infrastructure.  The cost of repairing damage to our facilities or for legal claims caused by these attacks may not be recoverable in rates or may exceed the insurance limits on our insurance policies or, in some cases, may not be covered by insurance.  The high cost or potential unavailability of insurance to cover terrorist activity may also adversely impact our results of operations and financial conditions.

Our business requires the collection and retention of personally identifiable information of our customers, shareholders, and employees, who expect that we will adequately protect such information.  A significant theft, loss, or fraudulent use of personally identifiable information may cause our business reputation to be adversely impacted, may lead to potentially large costs to notify and protect the impacted persons, and/or may cause us to become subject to legal claims, fines, or penalties, any of which could adversely impact our results of operations.

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Counterparties and customers may not meet their obligations.

We are exposed to the risk that counterparties to various arrangements who owe us money, electricity, natural gas, coal, or other commodities or services will not be able to perform their obligations.  Should the counterparties to these arrangements fail to perform, we may be forced to replace the underlying commitment at then-current market prices or we may be unable to meet all of our customers’ natural gas and electric requirements unless or until alternative supply arrangements are put in place.  In such event, we may incur losses, or our results of operations, financial position, or liquidity could otherwise be adversely affected.

Some of our customers are experiencing, or may experience, financial problems that could have a significant impact on their creditworthiness.  We cannot provide assurance that financially distressed customers will not default on their obligations to us and that such defaults will not have a material adverse impact on our business, financial position, results of operations, or cash flows.  Furthermore, the bankruptcy of one or more of our customers, or some other similar proceeding or liquidity constraint, could adversely impact our receivable collections or increase our bad debt allowances for these customers, which could adversely affect our operating results.  In addition, such events might force customers to reduce their future use of our products and services, which could have a material adverse impact on our results of operations and financial condition.

Poor investment performance of retirement plan investments and other factors impacting retirement plan costs could unfavorably impact our liquidity and results of operations.

We participate in employee benefit plans that cover substantially all of our employees and retirees.  Our cost of providing these benefit plans is dependent upon actual plan experience and assumptions concerning the future.  These assumptions include earnings on and/or valuations of plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation, estimated withdrawals by retirees, and required or voluntary contributions to the plans.  Depending on the investment performance over time and other factors impacting our costs, we could be required to make larger contributions in the future to fund these plans.  These additional funding obligations could have a material adverse impact on our cash flows, financial condition, and/or results of operations.  Changes made to the plans may also impact current and future pension and other postretirement benefit costs.

Adverse capital and credit market conditions could negatively affect our ability to meet liquidity needs, access capital, and/or grow or sustain our current business.  Cost of capital and disruptions, uncertainty, and/or volatility in the financial markets could adversely impact our results of operations and financial condition.

Having access to the credit and capital markets, at a reasonable cost, is necessary for us to fund our operations and capital requirements.  The capital and credit markets provide us with liquidity to operate and grow our business that is not otherwise provided from operating cash flows.  Disruptions, uncertainty, and/or volatility in those markets could increase our cost of capital or limit the availability of capital.  If we or Integrys Energy Group are unable to access the credit and capital markets on terms that are reasonable, we may have to delay raising capital, issue shorter-term securities, and/or bear an increased cost of capital.  This, in turn, could impact our ability to grow or sustain our current business, cause a reduction in earnings, and/or result in a credit rating downgrade.

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A reduction in our credit ratings could materially and adversely affect our business, financial position, results of operations, and liquidity.

We cannot be sure that any of our credit ratings will remain in effect for any given period of time or that a credit rating will not be lowered by a rating agency if, in the rating agency’s judgment, circumstances in the future so warrant.  Any downgrade could:

·         Require the payment of higher interest rates in future financings and possibly reduce the potential pool of creditors;

·         Increase borrowing costs under certain existing credit facilities;

·         Limit access to the commercial paper market;

·         Require provision of additional credit assurance, including cash margin calls, to contract counterparties.

Fluctuating commodity prices may impact energy margins and result in changes to liquidity requirements.

The margins and liquidity requirements of our business are impacted by changes in the forward and current market prices of natural gas, coal, electricity, renewable energy credits, and ancillary services.  Changes in price could result in:

·Higher working capital costs, particularly related to natural gas inventory, accounts receivable, and cash collateral postings;

·Increased liquidity requirements due to potential counterparty margin calls related to the use of derivative instruments to manage commodity price and volume exposure;

·Reduced profitability to the extent that reduced margins, increased bad debt, and interest expenses are not recovered through rates;

·Higher rates charged to our customers, which could impact the company’s competitive position;

·Reduced demand for energy, which could impact margins and operating expenses; and

·Shutting down of generation facilities if the cost of generation exceeds the market price for electricity.

ITEM 1B.               UNRESOLVED STAFF COMMENTS

None.

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ITEM 2.  PROPERTIES

Electric Facilities

The following table summarizes information on our electric generation facilities, including owned and jointly owned facilities, as of December 31, 2011:

Type	Name	Location	Fuel	Rated Capacity (Megawatts) (1)
Steam	Columbia Units 1 and 2	Portage, WI	Coal	349.6	(2)
	Edgewater Unit 4	Sheboygan, WI	Coal	98.1	(2)
	Pulliam (4 units)	Green Bay, WI	Coal	328.4
	Weston Units 1, 2, and 3	Marathon County, WI	Coal	458.9
	Weston Unit 4	Marathon County, WI	Coal	382.5	(2)
Total Steam				1,617.5
Combustion Turbine and Diesel	De Pere Energy Center	De Pere, WI	Natural Gas	163.6
	Juneau #31	Adams County, WI	Distillate Fuel Oil	6.3	(2)
	Pulliam #31	Green Bay, WI	Natural Gas	85.0
	West Marinette #31	Marinette, WI	Natural Gas	38.3
	West Marinette #32	Marinette, WI	Natural Gas	34.1
	West Marinette #33	Marinette, WI	Natural Gas	77.7
	Weston #31	Marathon County, WI	Natural Gas	17.4
	Weston #32	Marathon County, WI	Natural Gas	46.9
Total Combustion Turbine and Diesel				469.3
Hydroelectric	Various	Wisconsin	Hydro	67.6	(3)
Wind	Lincoln	Wisconsin	Wind	1.1
	Crane Creek	Iowa	Wind	19.5
Total Wind				20.6
Total System				2,175.0

(1)Based on capacity ratings for July 2012, which can differ from nameplate capacity, especially on wind projects.  The summer period is the most relevant for capacity planning purposes as a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand.

(2)We jointly own these facilities with various other utilities.  The capacity indicated for each of these units is equal to our portion of total plant capacity based on our percent of ownership.

·Wisconsin Power and Light Company operates the Columbia and Edgewater units, and we hold a 31.8% ownership interest in these facilities.

·We operate the Weston 4 facility and hold a 70% ownership in this facility, while Dairyland Power Cooperative holds the remaining 30%.

·WRPC owns and operates the Juneau unit.  We hold a 50% ownership interest in WRPC.

(3)WRPC owns and operates the Castle Rock and Petenwell units.  We hold a 50% ownership interest in WRPC; however, we are entitled to 66.7% of total capacity at Castle Rock and Petenwell.   Our share of capacity for Castle Rock is 11.7 megawatts, and our share of capacity for Petenwell is 13.9 megawatts.

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As of December 31, 2011, our electric utility owned approximately 21,700 miles of electric distribution lines located in Michigan and Wisconsin and approximately 120 distribution substations.

Natural Gas Facilities

At December 31, 2011, our natural gas properties were located in northeastern Wisconsin and an adjacent portion of  Michigan’s Upper Peninsula and consisted of the following:

·          Approximately 7,700 miles of natural gas distribution mains,

·          Approximately 250 miles of natural gas transmission mains,

·          87 natural gas distribution and transmission gate stations, and

·          Approximately 298,000 natural gas lateral services.

General

Substantially all of our utility plant is subject to a first mortgage lien.

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ITEM 3.  LEGAL PROCEEDINGS

For information on material legal proceedings and matters related to us and our subsidiary, see Note 12, “Commitments and Contingencies.”

ITEM 4.  MINE SAFETY DISCLOSURES

Not Applicable.

PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Integrys Energy Group is the sole holder of our common stock; therefore, there is no established public trading market for our common stock.  We made no purchases of equity securities during the fourth quarter of 2011.  For information on dividends paid and dividend restrictions, see Note 16, “Common Equity.”

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ITEM 6.  SELECTED FINANCIAL DATA

WISCONSIN PUBLIC SERVICE CORPORATION

COMPARATIVE FINANCIAL DATA AND OTHER STATISTICS (2007 TO 2011)

As of or for Year Ended December 31
(Millions, except weather information)	2011			2010			2009			2008			2007
Operating revenues	$	1,563.1		$	1,589.0		$	1,583.8		$	1,748.4		$	1,596.1
Net income attributed to common shareholder	122.8			131.9			117.3			129.2			110.2
Total assets	3,427.5			3,386.0			3,311.3			3,313.7			3,017.6
Long-term debt (excluding current portion)	579.2			729.7			880.2			880.7			756.1
Weather information *
Cooling degree days	603			616			274			464			634
Cooling degree days as a percent of normal	125.6		%	130.8		%	54.3		%	93.9		%	128.6		%
Heating degree days	7,524			7,080			7,962			7,969			7,102
Heating degree days as a percent of normal	100.1		%	94.2		%	104.9		%	104.6		%	93.2		%

*Normal heating and cooling degree days are based on a 20-year average of monthly temperatures from the Green Bay Weather Station.  Daily degree days are calculated by subtracting the 24-hour average daily temperature from 65° Fahrenheit.  Heating degree days result if temperatures are less than 65° Fahrenheit and cooling degrees result if temperatures are more than 65° Fahrenheit.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

We are a regulated electric and natural gas utility and a wholly owned subsidiary of Integrys Energy Group, Inc.  We derive revenues primarily from the distribution and sale of electricity and natural gas to retail customers.  We also provide wholesale electric service to numerous utilities and cooperatives for resale.

Strategic Overview

The focus of our business plan is the creation of long-term value for Integrys Energy Group’s shareholders and our customers through growth, operational excellence, customer focus, risk management, and the continued emphasis on safe, reliable, competitively priced, and environmentally sound energy services.

The essential components of our business strategy are:

Maintaining and Growing a Strong Regulated Utility Base — A strong regulated utility base is essential to maintaining a strong balance sheet, predictable cash flows, the desired risk profile, and quality credit ratings, all of which are critical to our success.  Our continued investment in environmental projects to improve air quality and meet the requirements set by environmental regulators helps maintain and grow our regulated utility base and meet our customers’ needs.  Capital projects to construct and/or upgrade equipment are planned each year to enhance safety, reliability, and value for our customers and Integrys Energy Group’s shareholders.

For more detailed information on our capital expenditure program, see “Liquidity and Capital Resources, Capital Requirements.”

Continuing Emphasis on Safe, Reliable, Competitively Priced, and Environmentally Sound Energy Services— Our mission is the same as Integrys Energy Group’s, to provide customers with the best value in energy and energy related services.  Ensuring continued reliability for our customers, we strive to effectively operate a mixed portfolio of generation assets and invest in new generation and natural gas distribution assets, while maintaining or exceeding environmental standards. This allows us to provide a safe, reliable, value-priced service to our customers.  We concentrate our efforts on improving and operating efficiently in order to reduce costs and maintain a low risk profile.  We actively evaluate opportunities for increasing our focus on energy efficiency and for adding more renewable generation to provide additional environmentally sound energy to our portfolio.

Integrating Resources to Provide Operational Excellence and Customer Focus — We are committed to integrating resources and finding the best, most efficient processes while meeting all applicable legal and regulatory requirements.  Through innovative ideas, embracing change, leveraging capabilities and expertise, and using creative solutions to meet and exceed our customers’ expectations, we strive to provide value to Integrys Energy Group’s shareholders and our customers.  “Operational Excellence” initiatives were implemented to encourage top performance in the areas of project management, process improvement, contract administration, and compliance in order to reduce costs and manage projects and activities within appropriate budgets, schedules, and regulations.

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Placing Strong Emphasis on Risk Management — Our risk management strategy includes the management of market, credit, liquidity, and operational risks through the normal course of business.  Forward purchases of electric capacity, energy, natural gas, and other commodities, and the use of derivative financial instruments, including commodity options, provides opportunities to reduce the risk associated with price movement in a volatile energy market.  The risk profile related to these instruments is managed in a manner consistent with Integrys Energy Group’s risk management policy for regulated affiliates, which is approved by the Integrys Energy Group Board of Directors.  The Integrys Energy Group Corporate Risk Management Group, which reports through Integrys Energy Group’s Chief Financial Officer, provides oversight for us.  We also implemented formula-based market tariffs to manage risk in the wholesale market.

RESULTS OF OPERATIONS

Earnings Summary

	Year Ended December 31						Change in 2011 Over		Change in 2010 Over
(Millions)	2011		2010		2009		2010		2009
Electric utility operations	$	93.9	$	103.4	$	88.0	(9.2	)%	17.5	%
Natural gas utility operations	22.3		23.2		24.1		(3.9	)%	(3.7	)%
Other operations	6.6		5.3		5.2		24.5	%	1.9	%
Net income attributed to common shareholder	$	122.8	$	131.9	$	117.3	(6.9	)%	12.4	%

2011 Compared with 2010

We recognized earnings of $122.8 million in 2011 compared with $131.9 million in 2010. The $9.1 million decrease in earnings was driven by:

· A $10.9 million after-tax decrease in electric utility margins mainly caused by differences in the 2011 rate order, compared with the previous rate order.

· A $10.4 million after-tax decrease in natural gas utility margins driven by the negative impact of the 2011 rate order.

These decreases were partially offset by a $9.4 million after-tax decrease in operating expenses, driven by decreases in natural gas utility depreciation and amortization expense and employee benefit costs.

2010 Compared with 2009

We recognized earnings of $131.9 million in 2010 compared with $117.3 million in 2009.  The primary driver of the $14.6 million increase in earnings was a $30.3 million after-tax increase in margins, driven by retail rate increases at both the electric and natural gas utility segments, which were necessary, in part, for recovery of higher operating expenses, and lower fuel and purchased power costs incurred during 2010 (as compared with authorized fuel and purchased power cost recovery rates).  The increase in margins was partially offset by higher operating expenses, driven by a $12.7 million after-tax increase in customer assistance expense and an $8.1 million after-tax increase in electric transmission expense.

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Electric Utility Segment Operations

	Year Ended December 31									Change in 2011 Over		Change in 2010 Over
(Millions, except degree days)	2011			2010			2009			2010		2009
Revenues	$	1,220.7		$	1,223.4		$	1,188.2		(0.2	)%	3.0	%
Fuel and purchased power costs	527.5			512.1			527.0			3.0	%	(2.8	)%
Margins	693.2			711.3			661.2			(2.5	)%	7.6	%
Operating and maintenance expense	380.2			377.5			352.5			0.7	%	7.1	%
Restructuring expense	0.2			(0.3		)	7.8			N/A		N/A
Depreciation and amortization expense	80.8			88.2			84.1			(8.4	)%	4.9	%
Taxes other than income taxes	42.6			40.8			42.0			4.4	%	(2.9	)%
Operating income	189.4			205.1			174.8			(7.7	)%	17.3	%
Miscellaneous income	0.6			0.8			4.5			(25.0	)%	(82.2	)%
Interest expense	(38.1		)	(40.7		)	(38.6		)	(6.4	)%	5.4	%
Other expense	(37.5		)	(39.9		)	(34.1		)	(6.0	)%	17.0	%
Income before taxes	$	151.9		$	165.2		$	140.7		(8.1	)%	17.4	%
Sales in kilowatt-hours
Residential	2,866.5			2,846.9			2,771.4			0.7	%	2.7	%
Commercial and industrial	7,988.5			7,914.4			7,596.5			0.9	%	4.2	%
Wholesale	4,662.8			4,810.8			4,817.7			(3.1	)%	(0.1	)%
Other	33.2			33.6			34.5			(1.2	)%	(2.6	)%
Total sales in kilowatt-hours	15,551.0			15,605.7			15,220.1			(0.4	)%	2.5	%
Weather
Heating degree days	7,524			7,080			7,962			6.3	%	(11.1	)%
Cooling degree days	603			616			274			(2.1	)%	124.8	%

2011 Compared with 2010

Margins

Electric margins are defined as electric operating revenues less fuel and purchased power costs. Management believes that electric utility margins provide a more meaningful basis for evaluating utility operations than electric operating revenues.  To the extent changes in fuel and purchased power costs are passed through to customers, the changes are offset by comparable changes in operating revenues.  Any significant changes in fuel and purchased power costs that are not recovered from customers are explained in the margin discussion below.

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Electric utility segment margins decreased $18.1 million, driven by:

·An approximate $18 million decrease in retail margins due to differences between our 2011 rate order and the previous rate order. Although our 2011 rate order included a lower authorized return on common equity, lower rate base, and other reduced costs, which resulted in lower total revenues and margins, the rate order also projected lower total sales volumes, which led to a rate increase on a per-unit basis. The 2011 rate increase, calculated on a per-unit basis, was more than offset by the decoupling mechanism due to changes in the rate order that impact the decoupling calculation. For more details on our 2011 rate order, see Note 21, “Regulatory Environment.”

·An approximate $4 million decrease in margins from wholesale customers. The decrease was due to lower sales volumes and lower non-fuel revenue requirements driven by a lower return on common equity, lower rate base, and other reduced costs.

·A partially offsetting approximate $3 million increase in margins due to a year-over-year positive impact from the 2010 amortization of a regulatory asset related to energy efficiency legislation implemented in a prior year.

Operating Income

Operating income at the electric utility segment decreased $15.7 million.  The decrease was driven by the $18.1 million decrease in margins, partially offset by a $2.4 million decrease in operating expenses.

The decrease in operating expenses was primarily related to:

·A $7.7 million decrease in employee benefit costs. The decrease was partially due to lower pension expense driven by an increase in contributions, which increased plan assets.

·A $7.4 million decrease in depreciation and amortization expense.  The PSCW approved lower depreciation rates effective January 1, 2011, and we had lower software amortization in 2011.

·These decreases were partially offset by:

·A $4.1 million increase in the amortization of various regulatory deferrals.  This increase was offset in revenues, resulting in no impact on earnings.

·A $3.7 million increase in customer assistance expense related to payments made to the Focus on Energy program. The program promotes residential and small business energy efficiency and renewable energy products.

·A $2.2 million increase in electric transmission expense.

·A $1.8 million increase in taxes other than income taxes driven by an increase in gross receipts taxes.

·A $1.8 million increase in injuries and damages expenses.

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Other Expense

Other expense decreased $2.4 million, driven by a decrease in interest expense due to the maturity and repayment of $150 million of long-term debt in August 2011.

2010 Compared with 2009

Margins

Electric margins are defined as electric operating revenues less fuel and purchased power costs. Management believes that electric utility margins provide a more meaningful basis for evaluating utility operations than electric operating revenues.  To the extent changes in fuel and purchased power costs are passed through to customers, the changes are offset by comparable changes in operating revenues.  Any significant changes in fuel and purchased power costs that are not recovered from customers are explained in the margin discussion below.

Electric utility segment margins increased $50.1 million year over year, driven by:

·An approximate $26 million increase in margins driven by lower fuel and purchased power costs incurred during 2010 as compared with authorized fuel and purchased power cost recovery rates.

·An approximate $14 million positive impact of a retail electric rate increase, effective January 1, 2010.

·An approximate $7 million increase in margins due to a 2.7% increase in sales volumes to residential customers, primarily related to warmer year-over-year weather during the cooling season, as evidenced by the increase in cooling degree days.  Margins were impacted by the year-over-year increase in sales volumes because we reached the annual $14.0 million electric decoupling cap in the second quarter of 2010 and 2009 and remained over the cap through the end of both years.  Therefore, no additional decoupling deferral was allowed for additional shortfalls from authorized margin for the remainder of both years.  Under decoupling, we are allowed to defer (up to the established cap) the difference between our actual margin and the rate case authorized margin recognized from residential and small commercial and industrial customers.

·An approximate $7 million increase in margins due to a 7.5% increase in sales volumes to large commercial and industrial customers, primarily related to changes in the business operations of our customers year over year.

·These increases were partially offset by an approximate $2 million decrease in margins from wholesale customers, primarily due to a decrease in sales volumes.

Operating Income

Operating income at the electric utility segment increased $30.3 million year over year, driven by the $50.1 million increase in margins, partially offset by a $19.8 million increase in operating expenses.

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The increase in operating expenses was the result of:

·A $13.5 million increase in electric transmission expense.

·A $12.9 million increase in customer assistance expense related to payments made to the Focus on Energy program. The program promotes residential and small business energy efficiency and renewable energy products.

·An $8.1 million increase in employee benefit costs, partially due to an increase in pension and other postretirement benefit expenses, driven by the amortization of negative investment returns from prior years.

·A $4.1 million increase in depreciation and amortization expense, primarily related to the Crane Creek Wind Farm being placed in service for accounting purposes in December 2009.

·These increases were partially offset by:

·An $8.1 million year-over-year decrease in restructuring expenses related to a reduction in workforce.  See Note 3, “Restructuring Expense,” for more information.

·A $6.0 million decrease in labor costs, driven by the reduction in workforce and company-wide furloughs implemented as part of previously announced cost management efforts.

·A $2.1 million decrease in electric maintenance expense, primarily related to a greater number of planned outages at our generation plants during 2009 compared with 2010.

Other Expense

Other expense at the electric utility segment increased $5.8 million year over year, driven by a $5.6 million decrease in AFUDC, primarily related to the construction of the Crane Creek Wind Farm in 2009.

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Natural Gas Utility Segment Operations

	Year Ended December 31									Change in 2011 Over		Change in 2010 Over
(Millions, except degree days)	2011			2010			2009			2010		2009
Revenues	$	352.6		$	365.6		$	395.6		(3.6	)%	(7.6	)%
Natural gas purchased for resale	215.6			211.2			241.7			2.1	%	(12.6	)%
Margins	137.0			154.4			153.9			(11.3	)%	0.3	%
Operating and maintenance expense	70.9			77.3			71.1			(8.3	)%	8.7	%
Restructuring expense	—			—			2.6			N/A		(100.0	)%
Depreciation and amortization expense	14.7			22.4			23.0			(34.4	)%	(2.6	)%
Taxes other than income taxes	5.2			5.4			6.8			(3.7	)%	(20.6	)%
Operating income	46.2			49.3			50.4			(6.3	)%	(2.2	)%
Miscellaneous income (expense)	(0.1		)	0.2			0.6			N/A		(66.7	)%
Interest expense	(9.0		)	(9.6		)	(10.5		)	(6.3	)%	(8.6	)%
Other expense	(9.1		)	(9.4		)	(9.9		)	(3.2	)%	(5.1	)%
Income before taxes	$	37.1		$	39.9		$	40.5		(7.0	)%	(1.5	)%
Retail throughput in therms
Residential	238.8			222.1			242.8			7.5	%	(8.5	)%
Commercial and industrial	136.0			125.9			137.2			8.0	%	(8.2	)%
Other	28.9			24.2			18.4			19.4	%	31.5	%
Total retail throughput in therms	403.7			372.2			398.4			8.5	%	(6.6	)%
Transport throughput in therms
Commercial and industrial	343.8			332.7			339.3			3.3	%	(1.9	)%
Total throughput in therms	747.5			704.9			737.7			6.0	%	(4.4	)%
Weather
Heating degree days	7,524			7,080			7,962			6.3	%	(11.1	)%

2011 Compared with 2010

Margins

Natural gas utility margins are defined as natural gas utility operating revenues less the cost of natural gas purchased for resale.  Management believes that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas utility revenues since we pass through prudently incurred natural gas commodity costs to our customers in current rates.  There was an approximate 6% decrease in the average per-unit cost of natural gas sold during 2011, which had no impact on margins.

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Natural gas utility segment margins decreased $17.4 million, driven by:

·An approximate $16 million decrease in margins related to the negative impact of a rate order effective January 14, 2011.  See Note 21, “Regulatory Environment,” for more information on this rate order.

·An approximate $3 million net decrease in margins due to sales volume variances.  Sales increased in 2011, but the financial impact relating to changes in the decoupling mechanism as a result of the rate order in effect during 2011 more than offset the increase.

·Colder weather during 2011, as shown by the 6.3% increase in heating degree days, drove an approximate $4 million increase in margins.

·Higher sales volumes excluding the impact of weather resulted in approximately $4 million of additional margins.  We attribute this increase to a combination of higher use per customer, higher average customer counts, and improved economic conditions for certain customer classes.

·Margins decreased approximately $11 million in 2011 due to our decoupling mechanism.  Although decoupling was implemented to minimize the impact of changes in sales volumes, it does not cover all jurisdictions or customers. During 2011, decoupling lessened the positive impact from certain of the increased sales volumes through higher future customer refunds.  During 2010, decoupling lessened the negative impact from certain of the decreased sales volumes through higher future customer recoveries.

·A partially offsetting approximate $2 million increase in margins due to the year-over-year positive impact from the 2010 amortization of a regulatory asset related to energy efficiency legislation implemented in a prior year.

Operating Income

Operating income at the natural gas utility segment decreased $3.1 million.  This decrease was primarily driven by the $17.4 million decrease in margins discussed above, partially offset by a $14.3 million decrease in operating expenses.

The decrease in operating expenses primarily related to:

·A $7.7 million decrease in depreciation and amortization expense.  We received approval for lower depreciation rates from the PSCW, effective January 1, 2011.

·A $2.3 million decrease in customer assistance expense related to payments made to the Focus on Energy program.  The program promotes residential and small business energy efficiency and renewable energy products.

·A $3.1 million decrease in employee benefits expense driven by lower pension expense.  The decrease in pension expense was driven by an increase in contributions, which increased plan assets.

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2010 Compared with 2009

Margins

Natural gas utility margins are defined as natural gas utility operating revenues less the cost of natural gas purchased for resale.  Management believes that natural gas utility margins provide a more meaningful basis for evaluating natural gas utility operations than natural gas revenues since we pass through prudently incurred natural gas commodity costs to our customers in current rates.  There was an approximate 5% decrease in the average per-unit cost of natural gas sold during 2010, which had no impact on margins.

Natural gas utility segment margins increased $0.5 million, driven by the approximate $13 million positive impact of a rate order effective January 1, 2010.  This rate order was necessary, in part, to recover higher operating expenses.  See Note 21, “Regulatory Environment,” for more information on this rate order.

This increase was substantially offset by:

·An approximate $13 million decrease in margins driven by a 4.4% decrease in volumes sold.

·Warmer weather during 2010, as shown by the 11.1% decrease in heating degree days, drove an approximate $9 million decrease in margins.

·An approximate $4 million decrease related to lower sales volumes excluding the impact of weather.  Residential customer sales volumes decreased, which we attributed to energy conservation and efficiency efforts.  Commercial and industrial customers’ sales volumes also decreased, which we attributed to reduced demand related to changes in customers’ business operations and conservation and efficiency efforts.

Operating Income

Operating income at the natural gas utility segment decreased $1.1 million, driven by a $1.6 million increase in operating expenses, partially offset by the $0.5 million increase in natural gas margins disclosed above.

The increase in operating expenses was driven by:

·An $8.3 million increase in customer assistance expense related to payments made to the Focus on Energy program.

·A $2.2 million increase in employee benefit costs.  The increase primarily related to higher pension expense, driven by the amortization of negative investment returns from prior years.

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·These increases in operating expense were partially offset by:

·A $2.7 million decrease in bad debt expense.  The decrease primarily related to the positive impact lower sales volumes and lower energy prices had on accounts receivable balances, as well as a decrease in past due account balances.

·A $2.6 million decrease in restructuring expenses related to a reduction in workforce.  See Note 3, “Restructuring Expense,” for more information.

·A $1.4 million decrease in taxes other than income taxes related to lower gross receipts taxes.

·A $1.0 million decrease in labor costs as a result of the reduction in workforce and company-wide furloughs implemented as part of previously announced cost management efforts.

Other Segment Operations

								Change in		Change in
	Year Ended December 31							2011 Over		2010 Over
(Millions)	2011			2010		2009		2010		2009
Operating income (loss)	$	(0.2	)	$	0.6	$	0.4	N/A		50.0	%
Other income	10.3			7.3		6.8		41.1	%	7.4	%
Income before taxes	$	10.1		$	7.9	$	7.2	27.8	%	9.7	%

2011 Compared with 2010

Income before taxes for other segment operations increased $2.2 million.  The increase was driven by lower interest expense owed to participants in the deferred compensation plans.

2010 Compared with 2009

Income before taxes for other segment operations did not change significantly in 2010 compared with 2009.

Provision for Income Taxes

	Year Ended December 31
	2011		2010		2009
Effective Tax Rate	36.8	%	36.6	%	36.1	%

2011 Compared with 2010

Our effective tax rate increased slightly during 2011.  In 2011, we increased our provision for income taxes and deferred income tax liabilities by $1.6 million for a tax law change in Wisconsin.  See “Liquidity and Capital Resources, Other Future Considerations — Recent Tax Law Changes” for more information.

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2010 Compared with 2009

Our effective tax rate increased during 2010 and was primarily driven by the 2010 federal health care reform.  This legislation eliminated the tax deduction for retiree prescription drug charges that are paid by employers and are offset by the receipt of a federal Medicare Part D subsidy.  See “Liquidity and Capital Resources, Other Future Considerations — Federal Health Care Reform” for more information.  As a result, we expensed $4.4 million of deferred income taxes during 2010.  The increase in the effective tax rate was partially offset by an increase in wind production tax credits in 2010.

LIQUIDITY AND CAPITAL RESOURCES

We believe we have adequate resources to fund ongoing operations and future capital expenditures. These resources include cash balances, liquid assets, operating cash flows, access to debt markets, and available borrowing capacity.  However, our operating cash flows and access to capital markets can be impacted by macroeconomic factors outside of our control.  Our borrowing costs can be impacted by short-term and long-term debt ratings assigned by independent credit rating agencies, as well as the market rates for interest.

Operating Cash Flows

2011 Compared with 2010

During 2011, net cash provided by operating activities was $181.3 million, compared with $268.1 million during 2010.  The $86.8 million decrease in net cash provided by operating activities was largely driven by:

·Net cash paid for income taxes of $38.0 million in 2011, compared with $30.3 million of net cash received for income taxes in 2010.  The year-over-year change was primarily due to a 2010 change in tax accounting related to capitalization of overhead costs.

·A $21.2 million repayment of related party payables in 2011 due to a change in the administration of the deferred compensation plan.

·A $15.0 million year-over-year increase in net cash used for working capital.  The increase was driven by $20.0 million of cash used for inventory in 2011, compared with $1.5 million of cash generated from inventory in 2010.  The year-over-year change was primarily due to increased coal freight costs in 2011.

Partially offsetting these decreases was a $20.8 million net decrease in contributions to pension and other postretirement benefit plans.

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2010 Compared with 2009

During 2010, net cash provided by operating activities was $268.1 million, compared with $463.6 million during 2009.  The $195.5 million year-over-year decrease in net cash provided by operating activities was largely driven by:

·A $185.7 million net decrease in cash provided by working capital, driven by:

·An $82.1 million year-over-year increase in cash used for other current liabilities, which was driven by a year-over-year increase in refunds to customers, primarily related to fuel cost over-collections.

·A $1.4 million increase in accounts receivable and accrued unbilled revenues during 2010, compared with a $58.1 million decrease in accounts receivable and accrued unbilled revenues during 2009, mainly due to changes in natural gas prices.

·A $43.7 million year-over-year decrease in cash generated from reduced inventory levels due to changes in natural gas prices.

·An $83.4 million year-over-year increase in contributions to pension and other postretirement benefit plans.

Investing Cash Flows

2011 Compared with 2010

Net cash used for investing activities was $86.1 million during 2011, compared with $78.1 million during 2010.  The $8.0 million increase in net cash used for investing activities was primarily driven by a $6.0 million increase in cash used to fund capital expenditures (discussed below).

2010 Compared with 2009

Net cash used for investing activities was $78.1 million during 2010, compared with $253.5 million during 2009.  The $175.4 million year-over-year decrease in net cash used for investing activities was primarily driven by a year-over-year decrease in cash used to fund capital expenditures (discussed below).

Capital Expenditures

Capital expenditures by business segment for the years ended December 31 were as follows:

Reportable Segment (millions)	2011		2010		2009
Electric utility	$	68.5	$	62.7	$	235.2
Natural gas utility	22.7		22.8		24.3
Other	0.3		—		—
WPS consolidated	$	91.5	$	85.5	$	259.5

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The increase in capital expenditures at the electric utility segment in 2011 compared with 2010 was primarily due to the purchase of a combustion turbine, construction of temporary ash storage, and various projects at the Columbia plant.  These expenditures were partially offset by the year-over-year impact of cash payments made in 2010 relating to the Crane Creek Wind Farm project, which was placed in service for accounting purposes in December 2009.

The decrease in capital expenditures at the electric utility segment in 2010 compared with 2009 was primarily due to decreased expenditures related to the Crane Creek Wind Farm project.

Financing Cash Flows

2011 Compared with 2010

Net cash used for financing activities was $161.1 million during 2011, compared with $124.6 million during 2010.  The $36.5 million increase in net cash used for financing activities was driven by:

·A $150.0 million increase due to the repayment of our 6.125% Senior Notes, which matured in 2011.

·A $74.3 million increase in return of capital payments to Integrys Energy Group.

Partially offsetting these increases was a $180.7 million decrease due to $173.7 million of net borrowings of commercial paper in 2011, compared with $7.0 million of net repayments in 2010.

2010 Compared with 2009

Net cash used for financing activities was $124.6 million during 2010, compared with $213.1 million during 2009.  The $88.5 million year-over-year decrease in net cash used for financing activities was primarily driven by:

·A $55.0 million year-over-year decrease in return of capital payments to Integrys Energy Group.

·A $36.0 million year-over-year decrease in the repayment of short-term borrowings, mainly due to the year-over-year decrease in net cash provided by operating activities.

Significant Financing Activities

We had $173.7 million of outstanding commercial paper borrowings at December 31, 2011, and no outstanding commercial paper borrowings at December 31, 2010. We had no other outstanding short-term debt as of December 31, 2011, and $10.0 million of other outstanding short-term debt as of December 31, 2010.  See Note 8, “Short-Term Debt and Lines of Credit” for more information.

For information on the issuance and redemption of our long-term debt, see Note 9, “Long-Term Debt.”

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Credit Ratings

We use internally generated funds and commercial paper borrowings to satisfy most of our capital requirements.  We periodically issue long-term debt and receive equity contributions from Integrys Energy Group to reduce short-term debt, fund future growth, and maintain capitalization ratios as authorized by the PSCW.

Our current credit ratings are listed in the table below.

Credit Ratings	Standard & Poor’s	Moody’s
Issuer credit rating	A-	A2
First mortgage bonds	N/A	Aa3
Senior secured debt	A	Aa3
Preferred stock	BBB	Baa1
Commercial paper	A-2	P-1
Credit facility	N/A	A2

Credit ratings are not recommendations to buy or sell securities. They are subject to change and each rating should be evaluated independent of any other rating.

On January 24, 2012, Standard & Poor’s confirmed our “stable” outlook.

On May 27, 2010, Moody’s revised the outlook for Integrys Energy Group and all of its subsidiaries to “stable” from “negative.”  According to Moody’s, the revised outlook reflected a reduced business risk profile driven by the recently completed restructuring of Integrys Energy Group’s nonregulated operations into a smaller segment with significantly reduced collateral requirements.  Moody’s also raised the senior secured debt and first mortgage bonds ratings for us from “A1” to “Aa3.”  According to Moody’s, the upgrade follows the August 2009 upgrade of the senior secured ratings of the majority of its investment grade regulated utilities (issuers with negative outlooks were excluded from the August 2009 upgrade).

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Future Capital Requirements and Resources

Contractual Obligations

The following table shows our contractual obligations as of December 31, 2011, including those of our subsidiary.

			Payments Due By Period
(Millions)	Total Amounts Committed		2012		2013 to 2014		2015 to 2016		2017 and Thereafter
Long-term debt principal and interest payments (1)	$	1,038.0	$	188.6	$	202.6	$	166.4	$	480.4
Operating lease obligations	19.7		1.3		2.7		1.3		14.4
Commodity purchase obligations (2)	1,810.6		337.2		471.3		225.6		776.5
Purchase orders (3)	179.6		178.3		1.3		—		—
Pension and other postretirement funding obligations (4)	266.3		124.9		126.2		15.2		—
Total contractual cash obligations	$	3,314.2	$	830.3	$	804.1	$	408.5	$	1,271.3

(1)Represents bonds and notes issued.  We record all principal obligations on the balance sheet.

(2)The costs of commodity purchase obligations are expected to be recovered in future customer rates.

(3)Includes obligations related to normal business operations and large construction obligations.

(4)Obligations for pension and other postretirement benefit plans, other than the Integrys Energy Group Retirement Plan, cannot reasonably be estimated beyond 2014.

The table above does not reflect payments related to the manufactured gas plant remediation liability of $67.6 million at December 31, 2011, as the amount and timing of payments are uncertain.  We expect to incur costs annually to remediate these sites.  See Note 12, “Commitments and Contingencies,” for more information about environmental liabilities.  The table also does not reflect payments for the December 31, 2011 liability of $0.5 million related to unrecognized tax benefits, as the amount and timing of payments are uncertain.  See Note 11, “Income Taxes,” for more information about unrecognized tax benefits.

Capital Requirements

As of December 31, 2011, our capital expenditures for the three-year period 2012 through 2014 were expected to be as follows:

(Millions)
Environmental projects	$	510.7
Electric and natural gas distribution projects	201.1
Electric and natural gas delivery and customer service projects	63.7
Other projects	176.0
Total capital expenditures	$	951.5

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All projected capital and investment expenditures are subject to periodic review and may vary significantly from the estimates, depending on a number of factors.  These factors include, but are not limited to, industry restructuring, regulatory constraints and requirements, changes in tax laws and regulations, market volatility, and economic trends.

Capital Resources

Management prioritizes the use of capital and debt capacity, determines cash management policies, uses risk management policies to hedge the impact of volatile commodity prices, and makes decisions regarding capital requirements in order to manage the liquidity and capital resource needs of the business segments.  We plan to meet our capital requirements for the period 2012 through 2014 primarily through internally generated funds (net of forecasted dividend payments), debt financings, and equity infusions from Integrys Energy Group.  We plan to keep debt to equity ratios at levels that can support current credit ratings and corporate growth.  We believe we have adequate financial flexibility and resources to meet our future needs.

Under an existing shelf registration statement, we may issue up to $500.0 million of senior debt securities with amounts, prices, and terms to be determined at the time of future offerings.

At December 31, 2011, we were in compliance with all covenants related to outstanding short-term and long-term debt.  We expect to be in compliance with all such debt covenants for the foreseeable future.

See Note 8, “Short-Term Debt and Lines of Credit,” for more information on credit facilities and other short-term credit agreements, including short-term debt covenants.  See Note 9, “Long-Term Debt,” for more information on long-term debt and related covenants.

Other Future Considerations

Decoupling

Decoupling for natural gas and electric residential and small commercial and industrial sales was approved by the PSCW on a four-year trial basis for us, effective January 1, 2009, and ending on December 31, 2012.  Decoupling allows us to adjust future rates to recover or refund a portion of the difference between the actual and authorized margin per customer impact of variations in volumes.  The mechanism does not adjust for variations in volumes resulting from changes in customer count compared to rate case levels, nor does it cover all customer classes.  This decoupling mechanism includes an annual $14.0 million cap for electric service and an annual $8.0 million cap for natural gas service.  Amounts recoverable from or refundable to customers are subject to these caps and are included in rates upon approval in a rate order.  We expect to address decoupling beyond 2012 in our rate case filing for 2013.  See Note 21, “Regulatory Environment,” for more information.

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Climate Change

The EPA began regulating greenhouse gas emissions under the Clean Air Act in January 2011 by applying the Best Available Control Technology (BACT) requirements (associated with the New Source Review program) to new and modified larger greenhouse gas emitters.  Technology to remove and sequester greenhouse gas emissions is not commercially available at scale.  Therefore, the EPA issued guidance that defines BACT in terms of improvements in energy efficiency as opposed to relying on pollution control equipment.  In December 2010, the EPA announced its intent to develop new source performance standards for greenhouse gas emissions.  The standards would apply to new and modified, as well as existing, electric utility steam generating units.  The EPA planned to propose these standards in 2011 and finalize them in 2012; however, the proposal has since been delayed.

A risk exists that any greenhouse gas legislation or regulation will increase the cost of producing energy using fossil fuels.  However, we believe the capital expenditures being made at our plants are appropriate under any reasonable mandatory greenhouse gas program.  We also believe that our future expenditures that may be required to control greenhouse gas emissions or meet renewable portfolio standards will be recoverable in rates.  We will continue to monitor and manage potential risks and opportunities associated with future greenhouse gas legislative or regulatory actions.

All of our generation and distribution facilities are located in the upper Midwest region of the United States.  The same is true for all of our customers’ facilities.  The physical risks posed by climate change for these areas are not expected to be significant at this time.  Ongoing evaluations will be conducted as more information on the extent of such physical changes becomes available.

Federal Health Care Reform

In March 2010, the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (HCR) were signed into law.  HCR contains various provisions that will affect the cost of providing health care coverage to our active and retired employees and their dependents.  Although these provisions become effective at various times over the next 10 years, some provisions that affect the cost of providing benefits to retirees were reflected in our financial statements in 2010 and 2011.

Beginning in 2013, a provision of HCR will eliminate the tax deduction for employer-paid postretirement prescription drug charges to the extent those charges will be offset by the receipt of a federal Medicare Part D subsidy.  As a result, we eliminated $4.4 million of our deferred tax asset related to postretirement benefits in 2010.  All of this flowed through to net income as a component of income tax expense in 2010.  An additional $1.6 million was expensed in June 2011 for deferred income taxes related to a Wisconsin tax law change (see discussion in Recent Tax Law changes below).  In February 2012, we were authorized recovery for the portion related to our Michigan operations.  We expect to seek rate recovery for the remaining $5.9 million of income tax expense that relates to this tax law change.  If recovery in rates becomes probable, income tax expense will be reduced in that period.  We are not currently able to predict how much, if any, will be recovered in rates.

Other provisions of HCR include the elimination of certain annual and lifetime maximum benefits and the broadening of plan eligibility requirements.  It also includes the elimination of pre-existing condition restrictions, an excise tax on high-cost health plans, changes to the Medicare Part D prescription drug program, and numerous other changes.  We participate in the Early Retiree Reinsurance Program that

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became effective on June 1, 2010.  We continue to assess the extent to which the provisions of the new law will affect our future health care and related employee benefit plan costs.

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

The Dodd-Frank Act was signed into law in July 2010.  However, significant rulings essential to its framework still remain outstanding.  Depending on the final rules, certain provisions of the Dodd-Frank Act relating to derivatives could increase capital and/or collateral requirements.  Final rules for these provisions are expected in the second quarter of 2012.  We are monitoring developments related to this act and their impacts on our future financial results.

Recent Tax Law Changes

Federal

In December 2010, President Obama signed into law The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010.  This act includes tax incentives, such as an extension and increase of bonus depreciation, the extension of the research and experimentation credit, and the extension of treasury grants in lieu of claiming the Investment Tax Credit or production tax credit for certain renewable energy investments.  In September 2010, President Obama signed into law the Small Business Jobs Act of 2010.  This act includes tax incentives, such as an extension to bonus depreciation and changes to listed property, that affect us.  We anticipate that these tax law changes will likely result in $40.0 million to $50.0 million of reduced cash payments for taxes during 2012.  These tax incentives may also reduce our utility rate base and, thus, future earnings relative to prior expectations.  We have primarily used the proceeds from these incentives to make incremental contributions to our various employee benefit plans.  In addition, these tax incentives have helped reduce our financing needs.

In December 2011, the National Defense Authorization Act (NDAA) was enacted.  The most significant provision of the NDAA was to retroactively eliminate the application of the tax normalization rule for cash grants taken by a regulated utility in lieu of the investment tax credit or production tax credits.  Prior to the enactment of NDAA, a regulated utility would have been required to amortize the grant in rates over the regulatory life of the renewable energy generating plant.  Further, the allowed rate of return on the generating plant could not be reduced by the unamortized grant balance during the life of the plant.  As a result of the enactment of NDAA, we are evaluating our options for taking advantage of cash grants in lieu of the production tax credits we are currently claiming for our Crane Creek wind project.

Michigan

In May 2011, Governor Snyder signed legislation that replaced Michigan’s business tax with a state income tax, effective January 1, 2012.  In accounting for this tax law change, we deferred $1.0 million in 2011 for recovery in future rates.

Wisconsin

In June 2011, Governor Walker signed into law a two-year budget bill.  Under the bill, the Wisconsin tax code was changed to conform to the federal tax code, retroactive to December 2010.  In accounting for

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this tax law change, we expensed an additional $1.6 million of deferred income taxes in 2011 related to the Medicare Part D subsidy.

OFF BALANCE SHEET ARRANGEMENTS

See Note 13, “Guarantees,” for information regarding guarantees.

CRITICAL ACCOUNTING POLICIES

The following accounting policies have been determined to be critical to the understanding of our financial statements because their application requires significant judgment and reliance on estimations of matters that are inherently uncertain.  Management has discussed these critical accounting policies with the Audit Committee of the Board of Directors of our parent, Integrys Energy Group.

Goodwill Impairment

We review goodwill for impairment as required by GAAP.  Goodwill is tested for impairment annually on April 1.  Interim impairment tests are performed when impairment indicators are present.  The test for impairment includes estimating the fair market value of the reporting unit using assumptions about future profitability and the correlation between the natural gas utility operations and published projections for other similar natural gas utility operations.  A significant decrease in market values and/or projected future cash flows could result in an impairment loss.

As of December 31, 2011, our natural gas utility reporting unit had goodwill of $36.4 million.  The fair value of the reporting unit currently exceeds the carrying amount by a significant amount, such that we believe it is unlikely to fail step one of the goodwill impairment test in the foreseeable future.

Accrued Unbilled Revenues

We accrue estimated amounts of revenues for services provided or energy delivered but not yet billed to customers.  Estimated unbilled revenues are calculated using a variety of judgments and assumptions related to customer class or contracted rates.  Significant changes in these judgments and assumptions could have a material impact on our results of operations.  At December 31, 2011 and 2010, our unbilled revenues were $68.2 million and $69.7 million, respectively.  The amount of unbilled revenues can vary significantly from period to period as a result of numerous factors, including seasonality, weather, customer usage patterns, commodity prices, and customer mix.

Pension and Other Postretirement Benefits

The costs of providing non-contributory defined benefit pension benefits and other postretirement benefits, described in Note 14, “Employee Benefit Plans,” are dependent upon numerous factors resulting from actual plan experience and assumptions regarding future experience.

Pension and other postretirement benefit costs are impacted by actual employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans, and earnings on plan assets.  Pension and other postretirement benefit costs may be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets,

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discount rates, and expected health care cost trends.  Changes made to the plan provisions may also impact current and future pension and other postretirement benefit costs.

Pension and other postretirement benefit plan assets are primarily made up of equity and fixed income investments.  Fluctuations in actual equity and fixed income market returns, as well as changes in general interest rates, may result in increased or decreased benefit costs in future periods.  Management believes that such changes in costs would be recovered through the ratemaking process.

The following table shows how a given change in certain actuarial assumptions would impact the projected benefit obligation and the reported net periodic pension cost.  Each factor below reflects an evaluation of the change based on a change in that assumption only.

Actuarial Assumption (Millions, except percentages)	Percentage-Point Change in Assumption		Impact on Projected Benefit Obligation			Impact on 2011 Pension Cost
Discount rate	(0.5	)	$	39.3		$	2.9
Discount rate	0.5		(36.4		)	(2.8		)
Rate of return on plan assets	(0.5	)	N/A			2.9
Rate of return on plan assets	0.5		N/A			(2.9		)

The following table shows how a given change in certain actuarial assumptions would impact the accumulated other postretirement benefit obligation and the reported net periodic other postretirement benefit cost.  Each factor below reflects an evaluation of the change based on a change in that assumption only.

Actuarial Assumption (Millions, except percentages)	Percentage-Point Change in Assumption		Impact on Postretirement Benefit Obligation			Impact on 2011 Postretirement Benefit Cost
Discount rate	(0.5	)	$	22.4		$	2.1
Discount rate	0.5		(20.8		)	(1.8		)
Health care cost trend rate	(1.0	)	(36.8		)	(5.5		)
Health care cost trend rate	1.0		45.7			6.8
Rate of return on plan assets	(0.5	)	N/A			0.9
Rate of return on plan assets	0.5		N/A			(0.9		)

The discount rates are selected based on hypothetical bond portfolios consisting of non-callable (or callable with make-whole provisions), non-collateralized, high-quality corporate bonds with maturities between 0 and 30 years.  The bonds are generally rated “Aa” with a minimum amount outstanding of $50 million.  From the hypothetical bond portfolios, a single rate is determined that equates the market value of the bonds purchased to the discounted value of the plans’ expected future benefit payments.

The expected return on asset assumption is based on consideration of historical and projected asset class returns, as well as the target allocations of the benefit trust portfolios.  The assumed long-term rate of return was 8.25% in 2011, and 8.50% in 2010 and 2009.  For 2011, 2010, and 2009, the actual rates of return on pension plan assets, net of fees, were 1.4%, 13.1%, and 22.0%, respectively.

The determination of expected return on qualified plan assets is based on a market-related valuation of assets, which reduces year-to-year volatility.  Cumulative gains and losses in excess of 10% of the greater

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of the pension or other postretirement benefit obligation or market-related value are amortized over the average remaining future service period.  In computing the expected return on plan assets, a market-related value of plan assets is used that recognizes changes in realized and unrealized investment gains and losses over the subsequent five years for plans sponsored by us, while the Integrys Energy Group Retirement Plan, sponsored by IBS, recognizes differences between actual investment returns and the expected return on plan assets over a five-year period.  Because of this method, the future value of assets will be impacted as previously deferred gains or losses are included in market-related value.

In selecting assumed health care cost trend rates, past performance and forecasts of health care costs are considered.  For more information on health care cost trend rates and a table showing future payments that we expect to make for pension and other postretirement benefits, see Note 14, “Employee Benefit Plans.”

Regulatory Accounting

Our electric and natural gas utility segments follow the guidance under the Regulated Operations Topic of the FASB ASC.  Our financial statements reflect the effects of the ratemaking principles followed by the various jurisdictions regulating these segments.  Certain items that would otherwise be immediately recognized as revenues and expenses are deferred as regulatory assets and regulatory liabilities for future recovery or refund to customers, as authorized by our regulators.  Future recovery of regulatory assets is not assured, and is generally subject to review by regulators in rate proceedings for matters such as prudence and reasonableness.  Management regularly assesses whether these regulatory assets and liabilities are probable of future recovery or refund by considering factors such as changes in the regulatory environment, earnings at the electric and natural gas utility segments, and the status of any pending or potential deregulation legislation.  Once approved, the regulatory assets and liabilities are amortized into earnings over the rate recovery period.  If recovery or refund of costs is not approved or is no longer deemed probable, these regulatory assets or liabilities are recognized in current period earnings.

The application of the Regulated Operations Topic of the FASB ASC would be discontinued if all or a separable portion of our electric and natural gas utility segment’s operations no longer meet the criteria for application.  Assets and liabilities recognized as a result of the actions of rate regulation would be written off as extraordinary items in income for the period in which the discontinuation occurred.  A write-off of all of our regulatory assets and regulatory liabilities at December 31, 2011, would result in a 14.6% decrease in total assets and a 12.1% decrease in total liabilities.  The largest regulatory asset at December 31, 2011, related to unrecognized pension and other postretirement benefit costs.  A write-off of that regulatory asset at December 31, 2011, would result in a 9.4% decrease in total assets.  See Note 6, “Regulatory Assets and Liabilities,” for more information.

Income Tax Provision

We are required to estimate income taxes for each of the jurisdictions in which we operate as part of the process of preparing consolidated financial statements.  This process involves estimating current income tax liabilities together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for income tax and accounting purposes.  These differences result in deferred income tax assets and liabilities, which are included within our balance sheets.  We also assess the likelihood that our deferred income tax assets will be recovered through future taxable income.  To

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the extent we believe that realization is not likely, we establish a valuation allowance, which is offset by an adjustment to the provision for income taxes in the income statements.

Uncertainty associated with the application of tax statutes and regulations and the outcomes of tax audits and appeals requires that judgments and estimates be made in the accrual process and in the calculation of effective tax rates.  Only income tax benefits that meet the “more likely than not” recognition threshold may be recognized or continue to be recognized.  Unrecognized tax benefits are re-evaluated quarterly and changes are recorded based on new information, including the issuance of relevant guidance by the courts or tax authorities and developments occurring in the examinations of our tax returns.

Significant management judgment is required in determining our provision for income taxes, deferred income tax assets and liabilities, the liability for unrecognized tax benefits, and any valuation allowance recorded against deferred income tax assets.  The assumptions involved are supported by historical data, reasonable projections, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions.  Significant changes in these assumptions could have a material impact on our financial condition and results of operations.  See Note 1(p) “Summary of Significant Accounting Policies - Income Taxes,” and Note 11, “Income Taxes,” for a discussion of accounting for income taxes.

IMPACT OF INFLATION

Our financial statements are prepared in accordance with GAAP.  The statements provide a reasonable, objective, and quantifiable statement of financial results, but generally do not evaluate the impact of inflation.  To the extent we are not recovering the effects of inflation, we will file rate cases as necessary in the various jurisdictions in which we operate.

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ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks and Other Significant Risks

We have potential market risk exposure related to commodity price risk, interest rate risk, and equity return and principal preservation risk.  We have risk management policies in place to monitor and assist in controlling these risks and may use derivative and other instruments to manage some of these exposures, as further described below.

Commodity Price Risk

The electric utility segment purchases coal, natural gas, and fuel oil for use in power generation. They also purchase power from the MISO market at a price that is often reflective of the underlying cost of natural gas used in power generation.  Prudent fuel and purchased power costs and capacity payments are recovered from customers under one-for-one recovery mechanisms by the wholesale electric operations and Michigan retail electric operations.  The costs of natural gas used by the natural gas operations are also generally recovered from customers under one-for-one recovery mechanisms.  These recovery mechanisms greatly reduce commodity price risk for the utilities.

Our Wisconsin retail electric operations do not have a one-for-one recovery mechanism for price fluctuations.  Instead, a “fuel window” mechanism substantially mitigates this price risk.

To manage commodity price risk for our customers, we enter into contracts of various durations for the purchase and/or sale of natural gas, fuel for electric generation, and electricity.  In addition, we employ risk management techniques pursuant to the risk plans approved by the PSCW, which include the use of derivative instruments such as futures and options.

See Note 1(f), “Summary of Significant Accounting Policies — Revenues and Customer Receivables,” for more information.

Interest Rate Risk

We are exposed to interest rate risk resulting primarily from our short-term commercial paper borrowings and projected near-term debt financing needs. We manage exposure to interest rate risk by limiting the amount of variable rate obligations and continually monitoring the effects of market changes on interest rates.  We enter into long-term fixed rate debt when it is advantageous to do so.

Due to short-term borrowings, we are exposed to variable interest rates.  Based on our variable rate debt outstanding at December 31, 2011, a hypothetical increase in interest rates of 100 basis points would have increased annual interest expense by $1.7 million.  Comparatively, based on the variable rate debt outstanding at December 31, 2010, an increase in interest rates of 100 basis points would have increased interest expense by $0.1 million. This sensitivity analysis was performed assuming a constant level of variable rate debt during the period and an immediate increase in interest rates, with no other changes for the remainder of the period.

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Equity Return and Principal Preservation Risk

We currently fund liabilities related to employee benefits through various external trust funds.  The trust funds are managed by numerous investment managers and hold investments in debt and equity securities.  Changes in the market value of these investments can have an impact on the future expenses related to these liabilities.  Declines in the equity markets or declines in interest rates may result in increased future costs for the plans and require additional contributions into the plans.  We monitor the trust fund portfolio by benchmarking the performance of the investments against certain security indices.  The employee benefit costs are recovered in customers’ rates, reducing the equity return and principal preservation risk on these exposures.  Also, the likelihood of an increase in the employee benefit obligations, which the investments must fund, has been partially mitigated as a result of certain employee groups no longer being eligible to participate in, or accumulate benefits in, certain pension and other postretirement benefit plans.  Our defined benefit pension plans are closed to all new hires.

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ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

A.  MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting.  Our control systems were designed to provide reasonable assurance to our management and the Board of Directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations.  Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2011.  In making this assessment, we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework.  Based on this assessment, management believes that, as of December 31, 2011, our internal control over financial reporting is effective.

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B.   CONSOLIDATED STATEMENTS OF INCOME

Year Ended December 31
(Millions)	2011			2010			2009
Operating revenues	$	1,563.1		$	1,589.0		$	1,583.8
Cost of fuel, natural gas, and purchased power	731.9			722.5			767.8
Operating and maintenance expense	452.2			455.0			424.2
Restructuring expense	0.2			(0.3		)	10.4
Depreciation and amortization expense	95.6			110.6			107.1
Taxes other than income taxes	47.8			46.2			48.7
Operating income	235.4			255.0			225.6
Miscellaneous income	13.2			12.4			16.8
Interest expense	(49.5		)	(54.4		)	(54.0		)
Other expense	(36.3		)	(42.0		)	(37.2		)
Income before taxes	199.1			213.0			188.4
Provision for income taxes	73.2			78.0			68.0
Net income	125.9			135.0			120.4
Preferred stock dividend requirements	(3.1		)	(3.1		)	(3.1		)
Net income attributed to common shareholder	$	122.8		$	131.9		$	117.3

The accompanying notes to the consolidated financial statements are an integral part of these statements.

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C.  CONSOLIDATED BALANCE SHEETS

At December 31
(Millions)	2011		2010
Assets
Cash and cash equivalents	$	5.5	$	71.4
Accounts receivable and accrued unbilled revenues, net of reserves of $3.0 and $3.1, respectively	199.5		203.9
Receivables from related parties	4.6		4.2
Inventories	90.7		70.4
Regulatory assets	44.6		46.0
Materials and supplies, at average cost	28.7		25.5
Prepaid taxes	112.6		90.0
Other current assets	11.6		16.7
Current assets	497.8		528.1
Property, plant, and equipment, net of accumulated depreciation of $1,280.7 and $1,213.8, respectively	2,340.1		2,345.7
Regulatory assets	454.3		379.0
Receivables from related parties	12.8		13.7
Goodwill	36.4		36.4
Other long-term assets	86.1		83.1
Total assets	$	3,427.5	$	3,386.0
Liabilities and Shareholders’ Equity
Short-term debt	$	173.7	$	10.0
Current portion of long-term debt	150.0		150.0
Accounts payable	114.6		102.8
Payables to related parties	14.1		23.2
Regulatory liabilities	19.1		18.5
Other current liabilities	61.8		59.1
Current liabilities	533.3		363.6
Long-term debt to parent	7.9		8.6
Long-term debt	571.3		721.1
Deferred income taxes	476.1		427.9
Deferred investment tax credits	8.7		9.2
Regulatory liabilities	256.3		255.9
Environmental remediation liabilities	67.6		76.1
Pension and other postretirement benefit obligations	272.8		220.4
Payables to related parties	7.4		9.0
Other long-term liabilities	72.8		95.8
Long-term liabilities	1,740.9		1,824.0
Commitments and contingencies
Preferred stock - $100 par value; 1,000,000 shares authorized; 511,882 shares issued and outstanding	51.2		51.2
Common stock - $4 par value; 32,000,000 shares authorized; 23,896,962 shares issued and outstanding	95.6		95.6
Additional paid-in capital	561.9		626.7
Retained earnings	444.6		424.9
Total liabilities and shareholders’ equity	$	3,427.5	$	3,386.0

The accompanying notes to the consolidated financial statements are an integral part of these statements.

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D.   CONSOLIDATED STATEMENTS OF CAPITALIZATION

At December 31
(Millions, except share amounts)				2011			2010
Common stock equity
Common stock - $4 par value; 32,000,000 shares authorized; 23,896,962 shares outstanding				$	95.6		$	95.6
Additional paid-in capital				561.9			626.7
Retained earnings				444.6			424.9
Total common stock equity				1,102.1			1,147.2
Preferred stock
Cumulative; $100 par value; 1,000,000 shares authorized with no mandatory redemption -
	Series		Shares Outstanding
	5.00	%	131,916	13.2			13.2
	5.04	%	29,983	3.0			3.0
	5.08	%	49,983	5.0			5.0
	6.76	%	150,000	15.0			15.0
	6.88	%	150,000	15.0			15.0
Total preferred stock				51.2			51.2
Long-term debt to parent
	Series		Year Due
	8.76	%	2015	3.1			3.4
	7.35	%	2016	4.8			5.2
Total long-term debt to parent				7.9			8.6
Long-term debt
First Mortgage Bonds
	Series		Year Due
	7.125	%	2023	0.1			0.1
Senior Notes
	Series		Year Due
	6.125	%	2011	—			150.0
	4.875	%	2012	150.0			150.0
	3.95	%	2013	22.0			22.0
	4.80	%	2013	125.0			125.0
	6.375	%	2015	125.0			125.0
	5.65	%	2017	125.0			125.0
	6.08	%	2028	50.0			50.0
	5.55	%	2036	125.0			125.0
Total First Mortgage Bonds and Senior Notes				722.1			872.1
Unamortized discount on long-term debt, net				(0.8		)	(1.0		)
Total				721.3			871.1
Current portion				(150.0		)	(150.0		)
Total long-term debt				571.3			721.1
Total capitalization				$	1,732.5		$	1,928.1

The accompanying notes to the consolidated financial statements are an integral part of these statements.

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E.  CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY

								Additional
	Comprehensive					Common		Paid in			Retained
(Millions)	Income		Total			Stock		Capital			Earnings
Balance at December 31, 2008			$	1,175.0		$	95.6	$	707.4		$	372.0
Net income attributed to common shareholder	$	117.3	117.3			—		—			117.3
Comprehensive income	$	117.3
Net return of capital to parent			(70.0		)	—		(70.0		)	—
Dividends to parent			(96.7		)	—		—			(96.7		)
Other			2.4			—		2.8			(0.4		)
Balance at December 31, 2009			$	1,128.0		$	95.6	$	640.2		$	392.2
Net income attributed to common shareholder	$	131.9	131.9			—		—			131.9
Comprehensive income	$	131.9
Net return of capital to parent			(15.0		)	—		(15.0		)	—
Dividends to parent			(99.6		)	—		—			(99.6		)
Other			1.9			—		1.5			0.4
Balance at December 31, 2010			$	1,147.2		$	95.6	$	626.7		$	424.9
Net income attributed to common shareholder	$	122.8	122.8			—		—			122.8
Comprehensive income	$	122.8	—			—		—			—
Equity contribution from parent			20.0			—		20.0			—
Net return of capital to parent			(89.3		)	—		(89.3		)	—
Dividends to parent			(102.5		)	—		—			(102.5		)
Other			3.9			—		4.5			(0.6		)
Balance at December 31, 2011			$	1,102.1		$	95.6	$	561.9		$	444.6

The accompanying notes to the consolidated financial statements are an integral part of these statements.

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F.  CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31
(Millions)	2011			2010			2009
Operating Activities
Net Income	$	125.9		$	135.0		$	120.4
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization expense	95.6			110.6			107.1
Refund of nonqualified decommissioning fund	—			(0.5		)	(0.5		)
Recoveries and refunds of regulatory assets and liabilities	30.8			10.8			12.2
Deferred income taxes and investment tax credit	53.6			125.3			102.2
Bad debt expense	7.4			7.3			11.7
Allowance for equity funds used during construction	(0.8		)	(1.0		)	(7.2		)
Pension and other postretirement expense	19.1			24.2			14.0
Pension and other postretirement contributions	(73.0		)	(93.8		)	(10.4		)
Equity income, net of dividends	(1.4		)	(1.2		)	(1.9		)
Repayment of related party payables	(21.2		)	—			—
Other	15.3			6.4			(14.7		)
Changes in working capital
Collateral on deposit	—			(2.4		)	11.1
Accounts receivable and accrued unbilled revenues	(2.3		)	(1.4		)	58.1
Inventories	(20.0		)	1.5			45.2
Other current assets	(25.0		)	(18.5		)	(30.8		)
Accounts payable	(4.7		)	(1.1		)	(1.0		)
Accrued taxes	(0.1		)	0.2			(0.7		)
Other current liabilities	(17.9		)	(33.3		)	48.8
Net cash provided by operating activities	181.3			268.1			463.6
Investing Activities
Capital expenditures	(91.5		)	(85.5		)	(259.5		)
Proceeds from sale of property, plant, and equipment	2.7			3.4			3.1
Other	2.7			4.0			2.9
Net cash used for investing activities	(86.1		)	(78.1		)	(253.5		)
Financing Activities
Redemption of notes payable	(10.0		)	—			—
Commercial paper - net	173.7			(7.0		)	(43.0		)
Redemption of long-term debt	(150.0		)	—			—
Payments of long-term debt	(0.7		)	(0.7		)	(0.6		)
Dividends to parent	(102.5		)	(99.6		)	(96.7		)
Equity contribution from parent	20.0			—			—
Return of capital to parent	(89.3		)	(15.0		)	(70.0		)
Preferred stock dividends	(3.1		)	(3.1		)	(3.1		)
Other	0.8			0.8			0.3
Net cash used for financing activities	(161.1		)	(124.6		)	(213.1		)
Net change in cash and cash equivalents	(65.9		)	65.4			(3.0		)
Cash and cash equivalents at beginning of year	71.4			6.0			9.0
Cash and cash equivalents at end of year	$	5.5		$	71.4		$	6.0

The accompanying notes to the consolidated financial statements are an integral part of these statements.

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G.  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a)           Nature of Operations—We are a regulated electric and natural gas utility company, serving customers in northeastern Wisconsin and an adjacent portion of Michigan’s Upper Peninsula.  We are subject to the jurisdiction of, and regulation by, the PSCW and the MPSC, which have general supervisory and regulatory powers over virtually all phases of the public utility industry in Wisconsin and Michigan, respectively.  We are also subject to the jurisdiction of the FERC, which regulates our natural gas pipelines and wholesale electric rates.  At December 31, 2011, we had one wholly owned subsidiary, WPS Leasing.

As used in these notes, the term “financial statements” refers to the consolidated financial statements.  This includes the consolidated statements of income, consolidated balance sheets, consolidated statements of capitalization, consolidated statements of common shareholder’s equity, and consolidated statements of cash flows, unless otherwise noted.

The term “utility” refers to our regulated activities, while the term “nonutility” refers to our activities that are not regulated, as well as the activities of our subsidiary.

(b)           Consolidated Basis of Presentation—The financial statements include our accounts and the accounts of our wholly owned subsidiary, after eliminating intercompany transactions and balances.  These financial statements also reflect our proportionate interests in certain jointly owned utility facilities.  The cost method of accounting is used for investments when we do not have significant influence over the operating and financial policies of the investee.  Investments in businesses not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method.

(c)           Reclassifications—We reclassified $9.1 million reported in other current assets at December 31, 2010, to prepaid taxes to match the current year presentation on the balance sheet.

(d)           Use of Estimates—We prepare our financial statements in conformity with accounting principles generally accepted in the United States of America.  We make estimates and assumptions that affect assets, liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period.  Actual results may differ from these estimates.

(e)           Cash and Cash Equivalents—Short-term investments with an original maturity of three months or less are reported as cash equivalents.

The following is supplemental disclosure to our statements of cash flows:

(Millions)	2011		2010			2009
Cash paid for interest	$	49.2	$	49.1		$	49.4
Cash paid (received) for income taxes	38.0		(30.3		)	(4.5		)

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Construction costs funded through accounts payable and treated as noncash investing activities totaled $11.3 million, $5.7 million, and $13.5 million at December 31, 2011, 2010, and 2009, respectively.

(f)            Revenues and Customer Receivables—Revenues related to the sale of energy are recognized when service is provided or energy is delivered to customers and include estimated amounts for services provided but not billed.  At December 31, 2011 and 2010, our unbilled revenues were $68.2 million and $69.7 million, respectively.  At December 31, 2011, there were no customers that accounted for more than 10% of our operating revenues.  However, the paper industry and wholesale sales to other utilities each accounted for approximately 12% of our operating revenues.  We present revenues net of pass-through taxes on the income statements.

We have various rate-adjustment mechanisms in place that currently provide for the recovery of prudently incurred electric fuel costs,  purchased power costs, and natural gas costs, which allow subsequent adjustments to rates for changes in commodity costs.  A summary of significant rate-adjustment mechanisms follows:

·Fuel and purchased power are recovered from customers on a one-for-one basis by our wholesale electric operations and Michigan retail electric operations.

·Our Wisconsin retail electric operations use a “fuel window” mechanism to recover fuel and purchased power costs.  Under the fuel window rules effective January 1, 2011, a deferral is required for under or over-collections of actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers.  Under or over-collections deferred in the current year are recovered or refunded in a future rate proceeding.

·Our rates include a one-for-one recovery mechanism for natural gas commodity costs.

·Our rates include a decoupling mechanism, which allows us to adjust our rates going forward to recover or refund all or a portion of the differences between the actual and authorized margin.

Revenues are also impacted by other accounting policies related to our participation in the MISO market.  We both sell and purchase power in the MISO market.  If we are a net seller in a particular hour, the net amount is reported as revenue.  If we are a net purchaser in a particular hour, the net amount is recorded as cost of fuel, natural gas, and purchased power on the income statements.

(g)           Inventories—Inventories consist of natural gas in storage and fossil fuels, including coal.  Average cost is used to value fossil fuels and natural gas in storage.

(h)           Risk Management Activities—As part of our regular operations, we enter into contracts, including options, futures, forwards, and other contractual commitments, to manage changes in commodity prices, which are described more fully in Note 2, “Risk Management Activities.”  Derivative instruments are entered into in accordance with the terms of the risk management plans approved by our Board of Directors and the PSCW or MPSC.

All derivatives are recognized on the balance sheets at their fair value unless they are designated as and qualify for the normal purchases and sales exception.  We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met.  Most of our energy-related physical and financial derivatives qualify for regulatory deferral.  These derivatives are marked to fair value; the resulting risk management assets are offset with regulatory liabilities or decreases to regulatory assets, and risk management liabilities are offset with regulatory assets or decreases to regulatory liabilities.  Management believes any gains or losses

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resulting from the eventual settlement of these derivative instruments will be refunded to or collected from customers in rates.

We classify unrealized gains and losses on derivative instruments that do not qualify for regulatory deferral as a component of natural gas purchased for resale or operating and maintenance expense, depending on the nature of the transaction.

Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions.  We elected not to net these items.  On the balance sheets, cash collateral provided to others is reflected in other current assets.

We have risk management contracts with various counterparties. We monitor credit exposure levels and the financial condition of our counterparties on a continuous basis to minimize credit risk.  At December 31, 2011, we did not have risk management contracts with any one counterparty or industry that accounted for more than 10% of our total credit risk exposure.

(i)            Emission Allowances—We account for emission allowances as inventory at average cost by vintage year.  Charges to income result when allowances are used in operating our generation plants.  Gains on sales of allowances are returned to ratepayers.  Losses on emission allowances are included in the costs subject to the fuel window rules.

(j)            Property, Plant, and Equipment—Utility plant is stated at cost, including any associated AFUDC and asset retirement costs.  The costs of renewals and betterments of units of property (as distinguished from minor items of property) are capitalized as additions to the utility plant accounts.  Except for land, no gains or losses are recognized in connection with ordinary retirements of utility property units.  We charge the cost of units of property retired, sold, or otherwise disposed of, less salvage value, to accumulated depreciation.  In addition, we record a regulatory liability for cost of removal accruals, which are included in rates.  Actual removal costs are charged against the regulatory liability as incurred.  Maintenance, repair, replacement, and renewal costs associated with items not qualifying as units of property are considered operating expenses.

We record straight-line depreciation expense over the estimated useful life of utility property, using depreciation rates as approved by the applicable regulators.  Annual utility composite depreciation rates are shown below.  We received approval from the PSCW for lower depreciation rates, effective January 1, 2011.

Annual Utility Composite Depreciation Rates	2011		2010		2009
Electric	2.88	%	3.05	%	3.04	%
Natural gas	2.22	%	3.28	%	3.30	%

We capitalize certain costs related to software developed or obtained for internal use and amortize those costs to operating expense over the estimated useful life of the related software, which ranges from 3 to 5 years.  If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statements.

See Note 4, “Property, Plant, and Equipment,” for details regarding our property, plant, and equipment balances.

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(k)           AFUDC—We capitalize the cost of funds used for construction using a calculation that includes both internal equity and external debt components, as required by regulatory accounting.  The internal equity component of capitalized AFUDC is accounted for as other income, and the external debt component is accounted for as a decrease to interest expense.

Approximately 50% of our retail jurisdictional construction work in progress expenditures are subject to the AFUDC calculation.  For 2011, our average AFUDC retail rate was 7.71%, and our AFUDC wholesale rate was 4.16%.  Our allowance for equity funds used during construction for 2011, 2010, and 2009 was $0.6 million, $0.7 million, and $5.1 million, respectively.  Our allowance for borrowed funds used during construction for 2011, 2010, and 2009 was $0.2 million, $0.3 million, and $2.0 million, respectively.

(l)            Regulatory Assets and Liabilities—Regulatory assets represent probable future revenue associated with certain costs or liabilities that have been deferred and are expected to be recovered from customers through the ratemaking process.  Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or amounts collected in rates for future costs.  If at any reporting date a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery with the reduction charged to expense in the year the determination is made.  See Note 6, “Regulatory Assets and Liabilities,” for more information.

(m)          Goodwill—Goodwill is not amortized, but is subject to an annual impairment test.  Our natural gas utility reporting unit contains goodwill and performs its annual goodwill impairment test during the second quarter of each year.  Interim impairment tests are performed when impairment indicators are present.

(n)           Retirement of Debt—Any call premiums or unamortized expenses associated with refinancing utility debt obligations are amortized consistent with regulatory treatment of those items.  Any gains or losses resulting from the retirement of utility debt that is not refinanced are either amortized over the remaining life of the original debt or recorded through current earnings.

(o)           Asset Retirement Obligations—We recognize at fair value legal obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction or development, and/or normal operation of the assets.  A liability is recorded for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown.  The asset retirement obligations are accreted using a credit-adjusted risk-free interest rate commensurate with the expected settlement dates of the asset retirement obligations; this rate is determined at the date the obligation is incurred.  The associated retirement costs are capitalized as part of the related long-lived assets and are depreciated over the useful lives of the assets.  Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease in the carrying amount of the liability and the associated retirement cost.  See Note 10, “Asset Retirement Obligations,” for more information.

(p)           Income Taxes—We and our subsidiary are included in the consolidated United States income tax return filed by Integrys Energy Group.  We and our subsidiary are parties to a federal and state tax allocation arrangement with Integrys Energy Group and its subsidiaries under which each entity determines its provision for income taxes on a stand-alone basis.  We settle the intercompany liabilities

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at the time that payments are made to the applicable taxing authority.  See Note 23, “Related Party Transactions,” for disclosure of intercompany payables or receivables related to income taxes.

Deferred income taxes have been recorded to recognize the expected future tax consequences of events that have been included in the financial statements by using currently enacted tax rates for the differences between the income tax basis of assets and liabilities and the basis reported in the financial statements.  We record valuation allowances for deferred income tax assets when it is uncertain if the benefit will be realized in the future.  We defer certain adjustments made to income taxes that will impact future rates and record regulatory assets or liabilities related to these adjustments.

We use the deferral method of accounting for investment tax credits (ITCs).  Under this method, we record the ITC as a deferred credit and amortize such credit as a reduction to the provision for income taxes over the life of the asset that generated the ITC.  Production tax credits generally reduce the provision for income taxes in the year that electricity from the qualifying facility is generated and sold.  Investment tax credits and production tax credits that do not reduce income taxes payable for the current year are eligible for carryover and recognized as a deferred income tax asset.  A valuation allowance is established unless it is more likely than not that the credits will be realized during the carryforward period.

We report interest and penalties accrued related to income taxes as a component of provision for income taxes in the income statements, as well as regulatory assets or regulatory liabilities in the balance sheets.

For more information regarding our accounting for income taxes, see Note 11, “Income Taxes.”

(q)           Guarantees—We follow the guidance of the Guarantees Topic of the FASB ASC, which requires that the guarantor recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee.  For additional information on guarantees, see Note 13, “Guarantees.”

(r)           Employee Benefits—The costs of pension and other postretirement benefits are expensed over the periods during which employees render service.  Our transition obligation related to the other postretirement benefit plans is being recognized over a 20-year period beginning in 1993.  In computing the expected return on plan assets, we use a market-related value of plan assets.  Changes in realized and unrealized investment gains and losses are recognized over the subsequent five years for plans we sponsor, while differences between actual investment returns and the expected return on plan assets are recognized over a five-year period for the Integrys Energy Group Retirement Plan, sponsored by IBS.  The benefit costs associated with employee benefit plans are allocated among Integrys Energy Group’s subsidiaries based on employees’ time reporting and actuarial calculations, as applicable.  Our regulators allow recovery in rates for the net periodic benefit cost calculated under GAAP.

We recognize the funded status of defined benefit postretirement plans on the balance sheet, and recognize changes in the plans’ funded status in the year in which the changes occur.  We record changes in the funded status to regulatory asset or liability accounts, pursuant to the Regulated Operations Topic of the FASB ASC.

We account for our participation in benefit plans sponsored by IBS and other postretirement benefit plans we sponsor as multiple employer plans.  Under affiliate agreements, we are responsible for our

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share of plan costs and obligations and are entitled to our share of plan assets; accordingly, we account for our pro rata share of these plans as our own plan.

For more information on our employee benefits, see Note 14, “Employee Benefit Plans.”

(s)           Fair Value—A fair value measurement is required to reflect the assumptions market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risks inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model. Transaction costs should not be considered in the determination of fair value.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).  We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities.

Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  The three levels of the fair value hierarchy are defined as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 — Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1.  Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methodologies.

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources.  These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

We determine fair value using a market-based approach that uses observable market inputs where available, and internally developed inputs where observable market data is not readily available.  For the unobservable inputs, consideration is given to the assumptions that market participants would use in valuing the asset or liability.  These factors include not only the credit standing of the counterparties involved, but also the impact of our nonperformance risk on our liabilities.

See Note 19, “Fair Value,” for more information.

(t)            New Accounting Pronouncements—ASU 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRS),” was issued in May 2011.  The amendments change the wording used to describe the requirements for measuring fair value and for disclosing information about fair value measurements.

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The amendments also clarify the intent concerning the application of existing fair value measurement requirements.  This guidance is effective for our reporting period ending March 31, 2012.  Management is currently evaluating the impact that the adoption of this standard will have on our financial statements.

ASU 2011-05, “Presentation of Comprehensive Income,” was issued in June 2011.  The guidance requires that the total of comprehensive income, the components of net income, and the components of OCI be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements.  The FASB has deferred the requirement regarding the presentation of reclassification adjustments between OCI and net income on the face of the financial statements.  This guidance is effective for our reporting period ending March 31, 2012, and is expected to change the format of our financial statements.

ASU 2011-08, “Testing Goodwill for Impairment,” was issued in September 2011.  The amendments give companies an option to first perform a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount.  If a company concludes that this is the case, the quantitative impairment test is required.  Otherwise, a company can bypass the quantitative impairment test.  This guidance is effective for our reporting period ending March 31, 2012, and is not expected to have a significant impact on our financial statements.

ASU 2011-11, Disclosures about Offsetting Assets and Liabilities,” was issued in December 2011.  The guidance requires enhanced disclosures about offsetting and related arrangements.  This guidance is effective for our reporting period ending March 31, 2013.  Management is currently evaluating the impact that the adoption of this standard will have on our financial statements.

NOTE 2—RISK MANAGEMENT ACTIVITIES

We use derivative instruments to manage commodity costs.  None of these derivatives are designated as hedges for accounting purposes.  The derivatives include physical commodity contracts and NYMEX futures and options used by both the electric and natural gas utility segments to manage the risks associated with the market price volatility of natural gas costs and the costs of gasoline and diesel fuel used by our utility vehicles.  The electric utility segment also uses financial transmission rights (FTRs) to manage electric transmission congestion costs and NYMEX oil futures and options to reduce price risk related to coal transportation.

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The tables below show our assets and liabilities from risk management activities:

	Balance Sheet	December 31, 2011
(Millions)	Presentation *	Assets		Liabilities
Natural gas contracts	Other Current	$	0.1	$	2.5
FTRs	Other Current	1.3		0.1
Petroleum product contracts	Other Current	0.1		—
Coal contract	Other Current	—		2.5
Coal contract	Other Long-term	—		4.4
Total commodity contracts	Other Current	$	1.5	$	5.1
Total commodity contracts	Other Long-term	$	—	$	4.4

*All derivatives are recognized on the balance sheet at their fair value unless they qualify for the normal purchases and sales exception.  We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met.  We classify assets and liabilities from risk management activities as current or long-term based on the maturities of the underlying contracts.

	Balance Sheet	December 31, 2010
(Millions)	Presentation *	Assets		Liabilities
Natural gas contracts	Other Current	$	0.4	$	2.3
FTRs	Other Current	2.2		0.2
Petroleum product contracts	Other Current	0.3		—
Coal contract	Other Current	—		1.2
Coal contract	Other Long-term	3.7		—
Total commodity contracts	Other Current	$	2.9	$	3.7
Total commodity contracts	Other Long-term	$	3.7	$	—

* All derivatives are recognized on the balance sheet at their fair value unless they qualify for the normal purchases and sales exception.  We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met.  We classify assets and liabilities from risk management activities as current or long-term based on the maturities of the underlying contracts.

The following table shows the unrealized gains (losses) recorded related to our derivatives:

(Millions)	Financial Statement Presentation	2011			2010
Natural gas contracts	Balance Sheet – Regulatory assets (current)	$	(0.1	)	$	(1.4	)
Natural gas contracts	Balance Sheet – Regulatory liability (current)	(0.2		)	—
FTRs	Balance Sheet – Regulatory assets (current)	(0.1		)	0.9
FTRs	Balance Sheet – Regulatory liabilities (current)	(1.1		)	(2.1		)
Petroleum product contract	Balance Sheet – Regulatory asset (current)	(0.1		)	—
Petroleum product contract	Balance Sheet – Regulatory liabilities (current)	—			0.1
Petroleum product contract	Income Statement – Operating and maintenance expense	(0.1		)	—
Coal contract	Balance Sheet – Regulatory assets (current)	(1.3		)	(1.2		)
Coal contract	Balance Sheet – Regulatory assets (long-term)	(4.4		)	—
Coal contract	Balance Sheet – Regulatory liability (long-term)	(3.7		)	3.7

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(Millions)	Financial Statement Presentation	2009
Commodity contracts	Balance Sheet – Regulatory assets (current)	$	10.5
Commodity contracts	Balance Sheet – Regulatory assets (long-term)	0.2
Commodity contracts	Balance Sheet – Regulatory liabilities (current)	(0.8		)
Commodity contracts	Income Statement – Natural gas purchased for resale	0.1

We had the following notional volumes of outstanding derivative contracts:

	December 31, 2011		December 31, 2010
Commodity	Purchases	Other Transactions	Purchases	Other Transactions
Natural gas (millions of therms)	58.4	N/A	100.6	N/A
FTRs (millions of kilowatt-hours)	N/A	4,814.8	N/A	5,645.3
Petroleum products (barrels)	26,770.0	N/A	44,648.0	N/A
Coal contract (millions of tons)	4.1	N/A	4.9	N/A

The following table shows our cash collateral positions:

(Millions)	December 31, 2011		December 31, 2010
Cash collateral provided to others	$	4.1	$	3.7

NOTE 3—RESTRUCTURING EXPENSE

In an effort to permanently remove costs from its operations, Integrys Energy Group developed a plan at the end of 2009 that included reductions in our workforce and the IBS workforce that supports us.  In connection with this plan, employee-related costs shown in the restructuring expense line item on the Statements of Income were distributed across our segments as follows:

(Millions)	2011		2010			2009
Natural gas utility	$	—	$	—		$	2.6
Electric utility	0.2		(0.3		)	7.8
Total restructuring costs	$	0.2	$	(0.3	)	$	10.4

The following table summarizes the activity related to these restructuring costs:

(Millions)	2011			2010
Accrued restructuring costs at beginning of period	$	—		$	10.7
Add: Adjustments to accrual during the period	—		*	—		*
Deduct: Cash payments	—			7.4
Deduct: Payments to IBS for allocated restructuring costs	—			3.3
Accrued restructuring costs at end of period	$	—		$	—

* In 2010, restructuring costs of $0.3 million were billed to certain companies in accordance with provisions in the operating agreements with these companies that allow us to recover a portion of our administrative and general expenses.  In 2011, the amounts previously billed to these companies were adjusted and reduced by $0.2 million.

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We do not expect to recognize any additional restructuring costs associated with this plan in future periods.

NOTE 4—PROPERTY, PLANT, AND EQUIPMENT

Property, plant, and equipment consisted of the following utility and nonutility assets at December 31:

(Millions)	2011		2010
Electric utility	$	2,895.5	$	2,855.1
Natural gas utility	680.6		671.5
Total utility plant	3,576.1		3,526.6
Less: Accumulated depreciation	1,272.6		1,206.2
Net	2,303.5		2,320.4
Construction work in progress	29.5		18.1
Net utility plant	2,333.0		2,338.5
Nonutility plant	15.2		14.8
Less: Accumulated depreciation	8.1		7.6
Net nonutility plant	7.1		7.2
Total property, plant, and equipment	$	2,340.1	$	2,345.7

NOTE 5—JOINTLY OWNED UTILITY FACILITIES

We hold a joint ownership interest in certain electric generating facilities.  We are entitled to our share of generating capability and output of each facility equal to our respective ownership interest.  We also pay our ownership share of additional construction costs, fuel inventory purchases, and operating expenses, unless specific agreements have been executed to limit our maximum exposure to additional costs.  We recorded our proportionate share of significant jointly owned electric generating facilities on the balance sheets, and the amounts were as follows at December 31, 2011:

(Millions, except for percentages and megawatts)	Weston 4	Columbia Energy Center Units 1 and 2	Edgewater Unit No. 4
Ownership	70.0%	31.8%	31.8%
Our share of rated capacity (megawatts)	374.5	335.2	105.0
Utility plant in service	$573.3	$167.8	$39.8
Accumulated depreciation	$78.5	$106.6	$25.4
In-service date	2008	1975 and 1978	1969

Our proportionate share of direct expenses for the joint operation of these plants is recorded in operating expenses in the income statements.  We have supplied our own financing for all jointly owned projects.

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NOTE 6—REGULATORY ASSETS AND LIABILITIES

We expect to recover our regulatory assets and incur future costs or refund our regulatory liabilities through rates charged to customers.  These rates are based on specific ratemaking decisions over periods determined by the regulators or over the normal operating period of the assets and liabilities to which they relate.  Based on prior and current rate treatment for such costs, we believe it is probable that we will continue to recover from customers the regulatory assets described below.

Most of our regulatory assets are earning a return, except for costs associated with environmental remediation and the Weston 3 lightning strike.  The carrying costs related to the regulatory assets not earning a return are borne by Integrys Energy Group’s shareholders.  The following regulatory assets and liabilities were reflected in our Balance Sheets as of December 31:

(Millions)	2011		2010		See Note
Regulatory assets
Unrecognized pension and other postretirement benefit costs	$	322.0	$	222.8	14
Environmental remediation costs (net of insurance recoveries) (1)	75.7		72.7		12
De Pere Energy Center (2)	28.6		31.0
Decoupling	21.7		43.5		21
Weston 3 lightning strike (3)	10.9		14.5
Derivatives	10.5		4.5		1(h)
Income tax related items	7.6		8.4		11
Asset retirement obligations	6.2		5.6		10
Other	15.7		22.0
Total	$	498.9	$	425.0
Balance Sheet Presentation
Current	$	44.6	$	46.0
Long-term	454.3		379.0
Total	$	498.9	$	425.0
Regulatory liabilities
Removal costs (4)	$	229.9	$	226.8
Unrecognized pension and other postretirement benefit costs	18.2		19.8		14
Decoupling	16.9		—		21
Other	10.4		27.8
Total	$	275.4	$	274.4
Balance Sheet Presentation
Current	$	19.1	$	18.5
Long-term	256.3		255.9
Total	$	275.4	$	274.4

(1)   Recovery depends on timing of actual expenditures.

(2)Prior to us purchasing the De Pere Energy Center, we had a long-term power purchase contract with the De Pere Energy Center that was accounted for as a capital lease.  As a result of the purchase, the capital lease

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obligation was reversed and the difference between the capital lease asset and the purchase price was recorded as a regulatory asset.  We are authorized recovery of this regulatory asset through 2023.

(3) In 2007, a lightning strike caused significant damage to the Weston 3 generating facility.  The PSCW approved the deferral of the incremental fuel and purchased power expenses, as well as the non-fuel operating and maintenance expenditures incurred as a result of the outage that were not covered by insurance.  We are authorized recovery of this regulatory asset through 2014.

(4) Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment.

NOTE 7—LEASES

We lease various property, plant, and equipment. Terms of the leases vary, but generally require us to pay property taxes, insurance premiums, and maintenance costs associated with the leased property. Many of our leases contain one of the following options upon the end of the lease term: (a) purchase the property at the current fair market value or (b) exercise a renewal option, as set forth in the lease agreement. Rental expense attributable to operating leases was $2.7 million, $4.3 million, and $5.1 million in 2011, 2010, and 2009, respectively. Future minimum rental obligations under non-cancelable operating leases are payable as follows:

Year ending December 31
(Millions)
2012	$	1.3
2013	1.7
2014	1.0
2015	0.7
2016	0.6
Later years	14.4
Total payments	$	19.7

NOTE 8—SHORT-TERM DEBT AND LINES OF CREDIT

Our short-term borrowings were as follows as of December 31:

(Millions, except for percentages)	2011			2010			2009
Commercial paper outstanding	$	173.7		$	—		$	7.0
Average discount rate on outstanding commercial paper	0.26		%	—			0.22		%
Short-term notes payable outstanding	—			$	10.0		$	10.0
Average interest rate on short-term notes payable outstanding	—			0.32		%	0.18		%

The commercial paper outstanding at December 31, 2011, had maturity dates ranging from January 3, 2012, through January 26, 2012.

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The table below presents our average amount of short-term borrowings outstanding based on daily outstanding balances during the years ended December 31:

(Millions)	2011		2010		2009
Average amount of commercial paper outstanding	$	57.5	$	0.1	$	3.2
Average amount of short-term notes payable outstanding	3.6		10.0		10.0

We manage our liquidity by maintaining adequate external financing commitments.  The information in the table below relates to our short-term debt, lines of credit, and remaining available capacity as of December 31:

(Millions)	Maturity	2011		2010
Revolving credit facility (1)	04/23/13	$	115.0	$	115.0
Revolving credit facility (2)	05/15/12	$	135.0	—
Revolving short-term notes payable (3)	05/13/11	—		10.0
Total short-term credit capacity		$	250.0	$	125.0
Less:
Letters of credit issued inside credit facilities		$	0.2	$	0.2
Loans outstanding under credit agreements and notes payable		—		10.0
Commercial paper outstanding		173.7		—
Available capacity under existing agreements		$	76.1	$	114.8

(1)Support for our commercial paper borrowing program.

(2)In May 2011, we entered into a new revolving credit agreement to support our commercial paper borrowing program. We requested approval from the PSCW to extend this facility through May 17, 2014.

(3)These short-term notes payable were repaid in May 2011.

At December 31, 2011, we were in compliance with all financial covenants related to outstanding short-term debt.  Our revolving credit agreement contains financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%, excluding non-recourse debt.  Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations.

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NOTE 9—LONG-TERM DEBT

See our statements of capitalization for details on our long-term debt.

In August 2011, our $150 million of 6.125% Senior Notes matured, and the outstanding principal balance was repaid.

In December 2012, our 4.875% Senior Notes will mature.  As a result, the $150.0 million balance of these notes was included in the current portion of long-term debt on our balance sheet at December 31, 2011.

Our First Mortgage Bonds and Senior Notes are subject to the terms and conditions of our First Mortgage Indenture.  Under the terms of the Indenture, substantially all our property is pledged as collateral for these outstanding debt securities.  All of these debt securities require semi-annual payments of interest.  Our Senior Notes become non-collateralized if we retire all of our outstanding First Mortgage Bonds and no new mortgage indenture is put in place.

At December 31, 2011, we were in compliance with all financial covenants related to outstanding long-term debt.  Our long-term debt obligations contain covenants related to payment of principal and interest when due and various financial reporting obligations.  Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations.

A schedule of all principal debt payment amounts related to bond maturities, excluding those associated with long-term debt to parent, is as follows:

Year ending December 31(Millions)
2012	$	150.0
2013	147.0
2014	—
2015	125.0
2016	—
Later years	300.1
Total payments	$	722.1

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NOTE 10—ASSET RETIREMENT OBLIGATIONS

We have asset retirement obligations primarily related to asbestos abatement at certain generation facilities, office buildings, and service centers; dismantling wind generation projects; disposal of PCB-contaminated transformers; and closure of fly-ash landfills at certain generation facilities.  We establish regulatory assets and liabilities to record the differences between ongoing expense recognition under the asset retirement obligations accounting rules and the ratemaking practices for retirement costs authorized by the applicable regulators.  All asset retirement obligations are recorded as other long-term liabilities on our Balance Sheets.  No asset retirement obligations were settled during 2011, 2010, and 2009.

The following table shows changes to our asset retirement obligations through December 31, 2011:

(Millions)
Asset retirement obligations at December 31, 2008	$	9.0
Accretion	0.5
Additions and revisions to estimated cash flows	8.3		*
Asset retirement obligations at December 31, 2009	17.8
Accretion	1.0
Asset retirement obligations at December 31, 2010	18.8
Accretion	1.1
Revisions to estimated cash flows	(1.3		)
Asset retirement obligations at December 31, 2011	$	18.6

*This amount includes a $6.3 million asset retirement obligation related to the 99-megawatt Crane Creek wind generation project that became operational in the fourth quarter of 2009.

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NOTE 11—INCOME TAXES

Deferred Income Tax Assets and Liabilities

The principal components of deferred income tax assets and liabilities recognized on the balance sheets as of December 31 are included in the table below.  Certain temporary differences are netted in the table when the offsetting amount is recorded as a regulatory asset or liability.  This is consistent with regulatory treatment.

(Millions)	2011		2010
Deferred income tax assets
Tax credit carryforwards	$	13.7	$	—
Employee benefits	—		4.4
Other	2.1		5.5
Total deferred income tax assets	$	15.8	$	9.9
Deferred income tax liabilities
Plant-related	$	434.1	$	382.4
Employee benefits	31.0		—
Regulatory deferrals	17.3		30.2
Other	16.4		21.1
Total deferred income tax liabilities	$	498.8	$	433.7
Total net deferred income tax liabilities	$	483.0	$	423.8
Balance sheet presentation
Current deferred income tax assets - included in other current assets	$	—	$	4.1
Current deferred income tax liabilities — included in other current liabilities	6.9		—
Long-term deferred income tax liabilities	476.1		427.9
Net deferred income tax liabilities	$	483.0	$	423.8

During 2011, legislation was signed in Michigan and Wisconsin that impacted the recognition of our deferred income tax assets and liabilities.  Michigan replaced its business tax with a state income tax, effective January 1, 2012.  The Wisconsin tax code was changed to conform to the federal tax code, retroactive to December 2010.  These changes in state income taxes, including regulatory impacts, combined to increase net deferred income tax liabilities by $2.7 million.

Deferred tax credit carryforwards included $12.3 million of general business credits, which have a carryforward period of 20 years, with the majority of the general business credits to expire in 2028.   Other deferred tax credit carryforwards at December 31, 2011, included $1.4 million of alternative minimum tax credits, which can be carried forward indefinitely.

Regulated utilities record certain adjustments related to deferred income taxes to regulatory assets and liabilities.  As the related temporary differences reverse, we are prospectively refunding taxes to or collecting taxes from customers for which deferred taxes were recorded in prior years at rates potentially different than current rates or upon enactment of changes in tax law.  The net regulatory assets for these and other regulatory tax effects totaled $5.4 million and $3.7 million at December 31, 2011, and 2010, respectively.

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Provision for Income Tax Expense

The components of the provision for income taxes were as follows:

(Millions)	2011			2010			2009
Current provision
Federal	$	15.4		$	(38.7	)	$	(36.1	)
State	4.2			(8.8		)	2.7
Total current provision	19.6			(47.5		)	(33.4		)
Deferred provision
Federal	46.1			109.9			95.2
State	7.9			16.0			7.9
Total deferred provision	54.0			125.9			103.1
Unrecognized tax benefits	—			—			(0.3		)
Interest	—			0.2			(0.5		)
Investment tax credits, net	(0.4		)	(0.6		)	(0.9		)
Total provision for income taxes	$	73.2		$	78.0		$	68.0

Statutory Rate Reconciliation

The following table presents a reconciliation of the difference between the effective tax rate and the amount computed by applying the statutory federal tax rate to income before taxes.

	2011					2010					2009
(Millions, except for percentages)	Rate		Amount			Rate		Amount			Rate		Amount
Statutory federal income tax	35.0	%	$	69.7		35.0	%	$	74.5		35.0	%	$	66.0
State income taxes, net	5.3		10.6			4.8		10.3			5.2		9.7
Federal tax credits	(3.2	)	(6.4		)	(2.8	)	(5.9		)	(0.2	)	(0.3		)
Other differences, net	(0.3	)	(0.7		)	(0.4	)	(0.9		)	(3.9	)	(7.4		)
Effective income tax	36.8	%	$	73.2		36.6	%	$	78.0		36.1	%	$	68.0

Unrecognized Tax Benefits

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

(Millions)	2011			2010			2009
Balance at January 1	$	4.8		$	9.3		$	0.6
Increase related to tax positions taken in prior years	0.4			0.9			9.0
Decrease related to tax positions taken in prior years	(0.5		)	(5.4		)	—
Decrease related to settlements	(4.2		)	—			(0.3		)
Balance at December 31	$	0.5		$	4.8		$	9.3

We had accrued interest expense of $0.2 million and no accrued penalties related to unrecognized tax benefits at December 31, 2011.  We had accrued interest expense of $1.4 million and no accrued penalties related to unrecognized tax benefits at December 31, 2010.

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As of December 31, 2011, recognition in subsequent periods of $0.2 million of unrecognized tax benefits could affect our effective tax rate.

We file income tax returns in the United States federal jurisdiction and in various state and local jurisdictions on a stand-alone basis or as part of Integrys Energy Group filings.

We are no longer subject to income tax examinations by the IRS for years prior to 2009.  During 2011, we effectively settled the majority of our IRS audits for the 2004 through 2008 tax years, which decreased our liability for unrecognized tax benefits by $4.2 million.  In 2011, the IRS commenced an examination of tax years 2009 and 2010.

We file state tax returns based on income in our major operating jurisdictions of Wisconsin and Michigan.  With a few exceptions, we are no longer subject to state and local tax examinations by tax authorities for years prior to 2007.  As of December 31, 2011, we were subject to examination by state or local tax authorities for the 2007 through 2010 tax years.  As of December 31, 2011, our earliest open tax years that were subject to examination by state taxing authorities in our major operating jurisdictions were as follows:

State	Year
Wisconsin	2007
Michigan	2007

During 2011, Wisconsin commenced an examination of tax years 2007 and 2008.

In the next 12 months, we do not expect to significantly change the amount of unrecognized tax benefits related to tax years prior to 2011.

NOTE 12—COMMITMENTS AND CONTINGENCIES

Commodity and Purchase Order Commitments

We routinely enter into long-term purchase and sale commitments for various quantities and lengths of time.  We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates.

The purchase obligations described below were as of December 31, 2011.

· Our electric utility segment had obligations of $167.0 million related to coal supply and transportation that extend through 2016, obligations of $1,292.4 million for either capacity or energy related to purchased power that extend through 2027, and obligations of $5.4 million for other commodities that extend through 2013.

· Our natural gas utility segment had obligations of $345.8 million related to natural gas supply and transportation contracts that extend through 2024.

· We also had commitments of $179.6 million in the form of purchase orders issued to various vendors that relate to normal business operations, including construction projects.

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Environmental

Clean Air Act (CAA) New Source Review Issues

Weston and Pulliam Plants:

In November 2009, the EPA issued us a Notice of Violation (NOV) alleging violations of the CAA’s New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009.  We continue to meet with the EPA and exchange proposals on a possible resolution.  We are currently unable to estimate the possible loss or range of loss related to this matter.

In May 2010, we received from the Sierra Club a Notice of Intent (NOI) to file a civil lawsuit based on allegations that we violated the CAA at the Weston and Pulliam plants.  We entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. We are working on a possible resolution with the Sierra Club and the EPA.  We are currently unable to estimate the possible loss or range of loss related to this matter.

Columbia and Edgewater Plants:

In December 2009, the EPA issued an NOV to Wisconsin Power and Light (WP&L), the operator of the Columbia and Edgewater plants, and the other joint owners of these plants (including us).  The NOV alleges violations of the CAA’s New Source Review requirements related to certain projects completed at those plants.  WP&L and the other joint owners exchanged proposals with the EPA on a possible resolution.  We are currently unable to estimate the possible loss or range of loss related to this matter.

In September 2010, the Sierra Club filed a lawsuit against WP&L, which included allegations that modifications made at the Columbia plant did not comply with the CAA.  While the previous stay has been lifted and the case is moving forward to a December 2012 trial, the Sierra Club continues to participate in settlement negotiations with the EPA and the joint owners of the Columbia plant to seek resolution.  We are currently unable to estimate the possible loss or range of loss related to this matter.

In September 2010, the Sierra Club filed a lawsuit against WP&L, which included allegations that modifications made at the Edgewater plant did not comply with the CAA.  The previous stay of this case has been extended through mid-April 2012 and settlement negotiations with the Sierra Club, the EPA, and the joint owners of the Edgewater plant continue.  We are currently unable to estimate the possible loss or range of loss related to this matter.

EPA Settlements with Other Utilities:

In response to the EPA’s CAA enforcement initiative, several utilities elected to settle with the EPA, while others are in litigation.  The fines, penalties, and costs of supplemental beneficial environmental projects associated with settlements involving comparably-sized facilities to Weston and Pulliam combined ranged between $6 million and $30 million.  The regulatory interpretations upon which the lawsuits or settlements are based may change depending on future court decisions made in the pending litigation.

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If it were settled or determined that historical projects at the Weston, Pulliam, Columbia, and Edgewater plants required either a state or federal CAA permit, we may, under the applicable statutes, be required to complete the following remedial steps:

·      shut down the facility,

·      install additional pollution control equipment and/or impose emission limitations, and/or

·      conduct a supplemental beneficial environmental project.

In addition, we may also be required to pay a fine.  Finally, under the CAA, citizen groups may pursue a claim.

Weston Air Permits

Weston 4 Construction Permit:

From 2004 to 2009, the Sierra Club filed various petitions objecting to the construction permit issued for the Weston 4 plant.  In June 2010, the Wisconsin Court of Appeals affirmed the Weston 4 construction permit, but directed the WDNR to reopen the permit to set specific visible emissions limits.  In July 2010, we, the WDNR, and the Sierra Club filed Petitions for Review with the Wisconsin Supreme Court.  In March 2011, the Wisconsin Supreme Court denied all Petitions for Review.  Other than the specific visible emissions limits issue, all other challenges to the construction permit are now resolved.  We are working with the WDNR and the Sierra Club to resolve this issue.  We do not expect this matter to have a material impact on our financial statements.

Weston Title V Air Permit:

In November 2010, the WDNR provided a draft revised permit.  We objected to proposed changes in mercury limits and requirements on the boiler as beyond the authority of the WDNR.  We continue to meet with the WDNR to resolve these issues.  On September 14, 2011, the WDNR issued a draft revised permit and a request for public comments.  We filed comments objecting to certain provisions in the draft permit.  We do not expect this matter to have a material impact on our financial statements.

WDNR Issued NOVs:

Since 2008, we received four NOVs from the WDNR alleging various violations of the different air permits for the entire Weston plant, Weston 4, Weston 1, and Weston 2, as well as one NOV for a clerical error involving pages missing from a quarterly report for Weston.  Corrective actions have been taken for the events in the five NOVs.  On December 20, 2011, the WDNR dismissed two of the NOVs and referred the other three NOVs to the state Justice Department for enforcement.  We do not expect this matter to have a material impact on our financial statements.

Pulliam Title V Air Permit

The WDNR issued the renewal of the permit for the Pulliam plant in April 2009.  In June 2010, the EPA issued an order directing the WDNR to respond to comments raised by the Sierra Club in its June 2009 Petition objecting to this permit.

We also challenged the permit in a contested case proceeding and Petition for Judicial Review.  The Petition was dismissed in an order remanding the matter to the WDNR.  In February 2011, the WDNR granted a contested case proceeding before an Administrative Law Judge on the issues we raised, which included averaging times in the emission limits in the permit.  We participated in the contested case

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proceeding on October 11 and 12, 2011.  On December 7, 2011, the Administrative Law Judge did not require the WDNR to insert averaging times as we had argued for.  We have decided not to appeal.

In October 2010, we received from the Sierra Club a copy of an NOI to file a civil lawsuit against the EPA based on what the Sierra Club alleges to be the EPA’s unreasonable delay in performing its duties related to the grant or denial of the permit.  We received notification that the Sierra Club filed suit against the EPA in April 2011.  We intervened in the case as a necessary party to protect our interests.  The WDNR sent the proposed permit to the EPA for a 45-day review, which allowed the parties to enter into a settlement agreement that has not yet been entered by the court.

We are reviewing all of these matters, but we do not expect them to have a material impact on our financial statements.

Columbia Title V Air Permit

In October 2009, the EPA issued an order objecting to the permit renewal issued by the WDNR for the Columbia plant.  The order determined that the WDNR did not adequately analyze whether a project in 2006 constituted a “major modification that required a permit.”  The EPA’s order directed the WDNR to resolve the objections within 90 days and “terminate, modify, or revoke and reissue” the permit accordingly.

In July 2010, we, along with our co-owners, received from the Sierra Club a copy of an NOI to file a civil lawsuit against the EPA.  The Sierra Club alleges that the EPA should assert jurisdiction over the permit because the WDNR failed to respond to the EPA’s objection within 90 days.

In September 2010, the WDNR issued a draft construction permit and a draft revised Title V permit in response to the EPA’s order.  In November 2010, the EPA notified the WDNR that the EPA “does not believe the WDNR’s proposal is responsive to the order.”  In January 2011, the WDNR issued a letter stating that upon review of the submitted public comments, the WDNR has determined not to issue the draft permits that were proposed to respond to the EPA’s order.  In February 2011, the Sierra Club filed for a declaratory action, claiming that the EPA had to assert jurisdiction over the permits.  In May 2011, the WDNR issued a second draft Title V permit in response to the EPA’s order.  We are monitoring this situation with WP&L and meeting with the WDNR.  We do not expect this matter to have a material impact on our financial statements.

Mercury and Interstate Air Quality Rules

Mercury:

The State of Wisconsin’s mercury rule, Chapter NR 446, requires a 40% reduction from the 2002 through 2004 baseline mercury emissions in Phase I, beginning January 1, 2010, through the end of 2014.  In Phase II, which begins in 2015, electric generating units above 150 megawatts will be required to reduce mercury emissions by 90%.  Reductions can be phased in and the 90% target delayed until 2021 if additional sulfur dioxide and nitrogen oxide reductions are implemented.  By 2015, electric generating units above 25 megawatts but less than 150 megawatts must reduce their mercury emissions to a level defined by the Best Available Control Technology rule.  As of December 31, 2011, we estimate capital costs of approximately $2 million, which includes estimates for both wholly owned and jointly owned

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plants, to achieve the required Phase I and Phase II reductions.  The capital costs are expected to be recovered in future rate cases.

In December 2011, the EPA issued the final Utility Maximum Achievable Control Technology rule that will regulate emissions of mercury and other hazardous air pollutants.  The requirements and impact of the final rule are being evaluated.  We do not anticipate the impact of this rule to be significant.  We expect to recover future compliance costs in future rates.

Sulfur Dioxide and Nitrogen Oxide:

The EPA issued the Clean Air Interstate Rule (CAIR) in 2005 in order to reduce sulfur dioxide and nitrogen oxide emissions from utility boilers located in 29 states, including Wisconsin and Michigan.  In July 2008, the United States Court of Appeals (Court of Appeals) issued a decision vacating CAIR, which the EPA appealed.  In December 2008, the Court of Appeals reinstated CAIR and directed the EPA to address the deficiencies noted in its previous ruling to vacate CAIR.  In July 2011, the EPA issued a final CAIR replacement rule known as the Cross State Air Pollution Rule (CSAPR).  The new rule was to become effective January 1, 2012; however, on December 30, 2011, the D.C. Circuit Court (Court) issued a decision that stayed the rule pending the Court’s resolution of the petitions for review.  The Court directed the EPA to implement CAIR during the stay period.  In January 2012, a briefing and oral argument schedule was set.  All briefing by the parties is to be completed by March 16, 2012, and the oral argument is set for April 13, 2012.  In comparison to the CAIR rule, CSAPR, in the version that was stayed, significantly reduced the emission allowances allocated to our existing units for sulfur dioxide and nitrogen oxide in 2012, with a further reduction in 2014.

CSAPR also established new sulfur dioxide and nitrogen oxide emission allowances and did not allow carryover of the existing nitrogen oxide emission allowances allocated to us under CAIR.  We did not acquire any CAIR nitrogen oxide emission allowances for 2011 and beyond other than those directly allocated to us, which were free.  Sulfur dioxide emission allowances allocated under the Acid Rain Program will continue to be issued and surrendered independent of the stayed CSAPR emission allowance program.  Thus, we do not expect any material impact on our financial statements as a result of being unable to carry over existing emission allowances.

Under CAIR, units affected by the Best Available Retrofit Technology (BART) rule are considered in compliance with BART for sulfur dioxide and nitrogen oxide emissions if they are in compliance with CAIR.  Although particulate emissions also contribute to visibility impairment, the WDNR’s modeling has shown the impairment to be so insignificant that additional capital expenditures on controls are not warranted.  The EPA has proposed that units in compliance with CSAPR, if the stay is lifted and CSAPR is reinstated, will also be considered in compliance with BART.

The Court may uphold CSAPR, invalidate CSAPR, or direct the EPA to make changes to CSAPR.  In order to be in compliance with the stayed version of CSAPR, additional sulfur dioxide and nitrogen oxide controls would need to be installed, emission allowances would need to be purchased, and/or we would have to make other changes to how we operate our existing units.  The installation of any necessary controls will be scheduled as part of our long-term maintenance plan for our existing units; however, we do not currently believe we could meet the stayed CSAPR’s sulfur dioxide and nitrogen oxide emission limits without purchasing additional emission allowances or by changing how our existing units are operated.  Due to the uncertainty surrounding the rule, we are currently unable to predict whether, or if, additional emission allowances would be available to purchase or how much it would cost to comply. 

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We are also currently unable to predict whether CSAPR, or any future version of CSAPR, will cause us to idle or abandon certain units or impact the estimated useful lives of certain units.  We expect to recover any such future compliance costs in future rates.

Manufactured Gas Plant Remediation

We operated facilities in the past at multiple sites for the purpose of manufacturing and storing manufactured gas.  In connection with these activities, waste materials were produced that may have resulted in soil and groundwater contamination at these sites.  Under certain laws and regulations relating to the protection of the environment, we are required to undertake remedial action with respect to some of these materials.  We are coordinating the investigation and cleanup of the sites subject to EPA jurisdiction under what is called a “multi-site” program.  This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies.

We are responsible for the environmental remediation of ten sites, of which seven have been transferred to the EPA Superfund Alternative Sites Program.  Under the EPA’s program, the remedy decisions at these sites will be made using risk-based criteria typically used at Superfund sites.  As of December 31, 2011, we estimated and accrued for $67.6 million of future undiscounted investigation and cleanup costs for all sites.  We may adjust these estimates in the future due to remedial technology, regulatory requirements, remedy determinations, and any claims of natural resource damages.  As of December 31, 2011, we recorded a regulatory asset of $75.7 million, which is net of insurance recoveries received of $22.2 million, related to the expected recovery of both cash expenditures and estimated future expenditures through rates.  Under current PSCW policies, we may not recover carrying costs associated with the cleanup expenditures.

Management believes that any costs incurred for environmental activities relating to former manufactured gas plant operations that are not recoverable through contributions from other entities or from insurance carriers have been prudently incurred and are, therefore, recoverable through rates.  Accordingly, we do not expect these costs to have a material impact on our financial statements.  However, any changes in the approved rate mechanisms for recovery of these costs, or any adverse conclusions by the various regulatory commissions with respect to the prudence of costs actually incurred, could materially affect rate recovery of such costs.

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NOTE 13—GUARANTEES

The following table shows our outstanding guarantees:

	Total Amounts		Expiration
(Millions)	Committed at December 31, 2011		Less Than 1 Year		Over 1 Year
Standby letters of credit (1)	$	0.3	$	0.3	$	—
Other guarantee (2)	0.5		—		0.5
Total guarantees	$	0.8	$	0.3	$	0.5

(1)At our request, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to us.  These amounts are not reflected on the balance sheets.

(2)Issued for workers compensation self insurance programs in Wisconsin and Michigan.  This amount is not reflected on the balance sheets.

NOTE 14—EMPLOYEE BENEFIT PLANS

Defined Benefit Plans

We participate in the Integrys Energy Group Retirement Plan, a non-contributory, qualified retirement plan sponsored by IBS.  We are responsible for our share of the plan assets and obligations, and our balance sheets reflect only the liabilities associated with our past and current employees and our share of the plan assets.

We serve as plan sponsor for certain unfunded nonqualified retirement plans.  Our balance sheets reflect the liabilities associated with these plans.  We also serve as plan sponsor and administrator for certain other postretirement benefit plans and fund benefits for retirees through irrevocable trusts, as allowed for income tax purposes.  Our balance sheets reflect only the liabilities associated with our past and current employees and our share of the plan assets for these other postretirement benefit plans.

In addition, Integrys Energy Group offers medical, dental, and life insurance benefits to our active employees and their dependents.  We expense the allocated costs of these benefits as incurred.

Effective January 1, 2008, and December 18, 2009, the defined benefit pension plans were closed to new non-union and union hires, respectively. 

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The following tables provide a reconciliation of the changes in our share of the plans’ benefit obligations and fair value of assets during 2011 and 2010:

	Pension Benefits						Other Benefits
(Millions)	2011			2010			2011			2010
Change in of benefit obligation
Obligation at January 1	$	658.2		$	622.6		$	268.9		$	243.6
Service cost	12.2			12.6			7.1			5.8
Interest cost	37.1			37.7			15.1			14.1
Transfer to affiliates	(4.2		)	(16.0		)*	(0.1		)	—
Actuarial loss, net	46.8			43.3			12.4			14.2
Participant contributions	—			—			0.2			0.5
Benefit payments	(28.7		)	(42.0		)	(9.7		)	(10.1		)
Federal subsidy on benefits paid	—			—			0.9			0.8
Obligation at December 31	$	721.4		$	658.2		$	294.8		$	268.9
Change in fair value of plan assets
Fair value of plan assets at January 1	$	517.0		$	435.5		$	185.1		$	165.7
Actual return on plan assets	7.8			56.3			(0.8		)	18.3
Employer contributions	62.1			83.2			10.9			10.6
Participant contributions	—			—			0.2			0.5
Benefit payments	(28.7		)	(42.0		)	(9.7		)	(10.1		)
Transfer to affiliates	(4.2		)	(16.0		)*	(0.1		)	0.1
Fair value of plan assets at December 31	$	554.0		$	517.0		$	185.6		$	185.1
Funded status at December 31	$	(167.4	)	$	(141.2	)	$	(109.2	)	$	(83.8	)

*The transfer of pension plan assets and obligations to affiliates relates to our past employees who at retirement were employed by IBS.  The assets and corresponding obligations were transferred to IBS, as IBS pays the benefits.

The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows:

	Pension Benefits				Other Benefits
(Millions)	2011		2010		2011		2010
Current liabilities	$	3.6	$	4.4	$	0.2	$	0.2
Noncurrent liabilities	163.8		136.8		109.0		83.6
Total liabilities	$	167.4	$	141.2	$	109.2	$	83.8

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The accumulated benefit obligation for the defined benefit pension plans was $643.1 million and $584.3 million at December 31, 2011, and 2010, respectively.  Information for pension plans with an accumulated benefit obligation in excess of plan assets is presented in the following table:

	December 31
(Millions)	2011		2010
Projected benefit obligation	$	721.4	$	658.2
Accumulated benefit obligation	643.1		584.3
Fair value of plan assets	554.0		517.0

The following table shows the amounts that had not yet been recognized in our net periodic benefit cost as of December 31:

	Pension Benefits				Other Benefits
(Millions)	2011		2010		2011			2010
Net regulatory assets
Net actuarial loss	$	228.4	$	150.5	$	82.0		$	57.5
Prior service cost (credit)	10.5		15.3		(17.3		)	(20.8		)
Transition obligation	—		—		0.2			0.5
Total	$	238.9	$	165.8	$	64.9		$	37.2

The following table shows the estimated amounts that will be amortized into net periodic benefit cost during 2012:

(Millions)	Pension Benefits		Other Benefits
Net actuarial losses	$	15.2	$	5.3
Prior service cost (credit)	4.5		(3.0		)
Transition obligation	—		0.2
Total 2012 — estimated amortization	$	19.7	$	2.5

The following table shows the components of our net periodic benefit costs (including amounts capitalized to our balance sheets) for the benefit plans:

	Pension Benefits									Other Benefits
(Millions)	2011			2010			2009			2011			2010			2009
Net periodic benefit cost
Service cost	$	11.3		$	11.5		$	10.3		$	7.1		$	5.8		$	5.7
Interest cost	36.1			36.6			38.0			15.1			14.1			14.1
Expected return on plan assets	(46.8		)	(39.6		)	(39.4		)	(14.2		)	(14.2		)	(13.9		)
Amortization of transition obligation	—			—			—			0.2			0.2			0.2
Amortization of prior service cost (credit)	4.8			4.8			4.5			(3.5		)	(3.5		)	(3.5		)
Amortization of net actuarial loss	8.6			4.1			1.1			3.0			1.2			0.1
Regulatory deferral *	—			4.5			(4.5		)	—			(1.3		)	1.3
Net periodic benefit cost	$	14.0		$	21.9		$	10.0		$	7.7		$	2.3		$	4.0

*The PSCW authorized recovery for net increased 2009 pension and other postretirement benefit costs related to plan asset losses that occurred in 2008.  Amortization and recovery of these deferred costs occurred in 2010.

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Assumptions — Pension and Other Postretirement Benefit Plans

The weighted-average assumptions used at December 31 to determine benefit obligations for the plans were as follows:

	Pension Benefits				Other Benefits
	2011		2010		2011		2010
Discount rate	5.10	%	5.80	%	5.04	%	5.80	%
Rate of compensation increase	4.28	%	4.29	%	N/A		N/A
Assumed medical cost trend rate (under age 65)	N/A		N/A		7.00	%	7.50	%
Ultimate trend rate	N/A		N/A		5.00	%	5.00	%
Year ultimate trend rate is reached	N/A		N/A		2016		2016
Assumed medical cost trend rate (over age 65)	N/A		N/A		7.50	%	8.00	%
Ultimate trend rate	N/A		N/A		5.50	%	5.50	%
Year ultimate trend rate is reached	N/A		N/A		2016		2016
Assumed dental cost trend rate	N/A		N/A		5.00	%	5.00	%

The weighted-average assumptions used to determine net periodic benefit cost for the plans were as follows for the years ended December 31:

	Pension Benefits
	2011		2010		2009
Discount rate	5.80	%	6.15	%	6.45	%
Expected return on assets	8.25	%	8.50	%	8.50	%
Rate of compensation increase	4.28	%	4.29	%	4.27	%

	Other Benefits
	2011		2010		2009
Discount rate	5.80	%	6.05	%	6.50	%
Expected return on assets	8.25	%	8.50	%	8.50	%
Assumed medical cost trend rate (under age 65)	7.50	%	8.00	%	9.00	%
Ultimate trend rate	5.00	%	5.00	%	5.00	%
Year ultimate trend rate is reached	2016		2013		2013
Assumed medical cost trend rate (over age 65)	8.00	%	8.50	%	9.50	%
Ultimate trend rate	5.50	%	5.50	%	5.50	%
Year ultimate trend rate is reached	2016		2013		2013
Assumed dental cost trend rate	5.00	%	5.00	%	5.00	%

We establish our expected return on assets assumption based on consideration of historical and projected asset class returns, as well as the target allocations of the benefit trust portfolios.

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Assumed health care cost trend rates have a significant effect on the amounts reported by us for the health care plans.  For the year ended December 31, 2011, a one-percentage-point change in assumed health care cost trend rates would have had the following effects:

	One-Percentage-Point
(Millions)	Increase		Decrease
Effect on total of service and interest cost components of net periodic postretirement health care benefit cost	$	4.0	$	(3.2	)
Effect on the health care component of the accumulated postretirement benefit obligation	45.7		(36.8		)

Pension and Other Postretirement Benefit Plan Assets

Integrys Energy Group’s investment policy includes various guidelines and procedures designed to ensure assets are invested in an appropriate manner to meet expected future benefits to be earned by participants.  The investment guidelines consider a broad range of economic conditions.  The policy is established and administered in a manner that is compliant at all times with applicable regulations.

Central to the policy are target allocation ranges by major asset categories.  The objectives of the target allocations are to maintain investment portfolios that diversify risk through prudent asset allocation parameters and to achieve asset returns that meet or exceed the plans’ actuarial assumptions and that are competitive with like instruments employing similar investment strategies.  The portfolio diversification provides protection against significant concentrations of risk in the plan assets.  The target asset allocations for pension and other postretirement benefit plans that have significant assets are: 70% equity securities and 30% fixed income securities.  Equity securities primarily include investments in large-cap and small-cap companies.  Fixed income securities primarily include corporate bonds of companies from diversified industries, United States government securities, and mortgage-backed securities.

The Board of Directors of Integrys Energy Group established the Employee Benefits Administrator Committee (composed of members of Integrys Energy Group and its subsidiaries’ management) to manage the operations and administration of all its and its subsidiaries’ benefit plans and trusts.  The committee periodically reviews the asset allocation and the portfolio is rebalanced when necessary.

Pension and other postretirement benefit plan investments are recorded at fair value. Information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used are discussed in Note 1(s), “Summary of Significant Accounting Policies — Fair Value.”

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The following table provides the fair value of our investments by asset class:

	December 31, 2011
	Pension Plan Assets											Other Benefit Plan Assets
(Millions)	Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Asset Class
Cash and cash equivalents	$	2.2		$	11.7		$	—	$	13.9		$	—	$	2.9	$	—	$	2.9
Equity securities:
United States equity	62.9			159.4			—		222.3			19.8		52.7		—		72.5
International equity	34.2			122.4			—		156.6			11.2		40.8		—		52.0
Fixed income securities:
United States government	—			46.2			—		46.2			53.7		—		—		53.7
Foreign government	—			8.5			2.8		11.3			—		—		—		—
Corporate debt	—			77.5			1.1		78.6			—		—		—		—
Asset-backed securities	—			27.3			—		27.3			—		—		—		—
Other	—			4.0			—		4.0			0.2		—		—		0.2
	99.3			457.0			3.9		560.2			84.9		96.4		—		181.3
401(h) other benefit plan assets invested as pension assets (1)	(0.8		)	(3.7		)	—		(4.5		)	0.8		3.7		—		4.5
Total(2)	$	98.5		$	453.3		$	3.9	$	555.7		$	85.7	$	100.1	$	—	$	185.8

(1)Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h).

(2)Investments do not include accruals or pending transactions that are included in the table reconciling the change in fair value of plan assets.

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	December 31, 2010
	Pension Plan Assets												Other Benefit Plan Assets
(Millions)	Level 1			Level 2			Level 3			Total			Level 1		Level 2		Level 3		Total
Asset Class
Cash and cash equivalents	$	1.6		$	16.0		$	—		$	17.6		$	—	$	5.6	$	—	$	5.6
Equity securities:
United States equity	59.1			141.0			—			200.1			21.1		49.8		—		70.9
International equity	35.8			116.7			—			152.5			12.5		41.9		—		54.4
Fixed income securities:
United States government	—			34.5			—			34.5			8.1		27.3		—		35.4
Foreign government	—			6.2			3.7			9.9			—		—		—		—
Corporate debt	—			67.5			1.0			68.5			—		15.4		—		15.4
Asset-backed securities	—			24.9			0.1			25.0			—		—		—		—
Other	—			2.4			—			2.4			0.2		—		—		0.2
Real estate securities	—			—			14.1			14.1			—		—		—		—
	96.5			409.2			18.9			524.6			41.9		140.0		—		181.9
401(h) other benefit plan assets invested as pension assets (1)	(0.7		)	(3.0		)	(0.1		)	(3.8		)	0.7		3.0		0.1		3.8
Total (2)	$	95.8		$	406.2		$	18.8		$	520.8		$	42.6	$	143.0	$	0.1	$	185.7

(1)Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h).

(2)Investments do not include accruals or pending transactions that are included in the table reconciling the change in fair value of plan assets.

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The following table sets forth a reconciliation of changes in the fair value of pension plan assets categorized as Level 3 measurements:

(Millions)	Foreign GovernmentDebt			Corporate Debt			Asset- Backed Securities			Real Estate Securities			Total
Beginning balance at December 31, 2010	$	3.7		$	1.0		$	0.1		$	14.1		$	18.9
Net realized and unrealized gains	0.2			—			—			1.2			1.4
Purchases	1.1			1.0			—			0.9			3.0
Sales	(2.2		)	(0.9		)	—			(16.2		)	(19.3		)
Transfers into Level 3	—			0.1			—			—			0.1
Transfers out of Level 3	—			(0.1		)	(0.1		)	—			(0.2		)
Ending balance at December 31, 2011	$	2.8		$	1.1		$	—		$	—		$	3.9
Net unrealized (losses) related to assets still held at the end of the period	$	(0.1	)	$	—		$	—		$	—		$	(0.1	)

(Millions)	Foreign Government Debt			Corporate Debt			Asset- Backed Securities		Other Fixed Income Securities			Real Estate Securities		Total
Beginning balance at December 31, 2009	$	0.2		$	1.3		$	—	$	0.5		$	11.7	$	13.7
Net realized and unrealized gains (losses)	(0.1		)	0.2			—		—			1.8		1.9
Purchases, sales, and settlements	3.6			(0.5		)	0.1		(0.5		)	0.6		3.3
Ending balance at December 31, 2010	$	3.7		$	1.0		$	0.1	$	—		$	14.1	$	18.9
Net unrealized gains (losses) related to assets still held at the end of the period	$	(0.1	)	$	0.2		$	—	$	—		$	1.8	$	1.9

Cash Flows Related to Pension and Other Postretirement Benefit Plans

Our funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes.  We expect to contribute $112.5 million to pension plans and $12.4 million to other postretirement benefit plans in 2012, dependent upon various factors affecting us, including our liquidity position and tax law changes.

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The following table shows the payments, reflecting expected future service, that we expect to make for pension and other postretirement benefits.  In addition, the table shows the expected federal subsidies, provided under the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which will partially offset other postretirement benefits.

(Millions)	Pension Benefits		Other Benefits		Federal Subsidies
2012	$	41.4	$	12.5	$	(0.8	)
2013	42.3		13.0		(0.9		)
2014	43.3		13.7		(0.9		)
2015	46.4		14.4		(1.0		)
2016	47.8		15.3		(1.0		)
2017-2021	256.0		92.4		(5.5		)

Defined Contribution Benefit Plans

Integrys Energy Group maintains a 401(k) Savings Plan for substantially all of our full-time employees.  A percentage of employee contributions are matched through an employee stock ownership plan (ESOP) contribution up to certain limits.  Certain union employees receive a contribution to their ESOP account regardless of their participation in the 401(k) Savings Plan.  Employees who are no longer eligible to participate in the defined benefit pension plan participate in a defined contribution pension plan, in which certain amounts are contributed to an employee’s account based on the employee’s wages, age, and years of service.  Our share of the total costs incurred under these plans was $5.0 million in 2011, $4.7 million in 2010, and $5.2 million in 2009.

Integrys Energy Group maintains deferred compensation plans that enable certain key employees, including some who are our employees, to defer a portion of their compensation on a pre-tax basis.  The deferred compensation arrangements for which distributions are made solely in Integrys Energy Group common stock are classified as an equity instrument on the balance sheets. Changes in the fair value of this portion of the deferred compensation obligation are not recognized. The deferred compensation obligation classified as an equity instrument was $8.2 million at December 31, 2011, and $11.2 million at December 31, 2010.

The portion of the deferred compensation obligation that is indexed to various investment options and allows for distributions in cash is classified as a liability on the balance sheets. The liability is adjusted, with a charge or credit to expense, to reflect changes in the fair value of the deferred compensation obligation. The obligation classified within other long-term liabilities was $15.5 million at December 31, 2011, and $35.7 million at December 31, 2010.  The costs incurred under this arrangement were $0.5 million in 2011, $3.4 million in 2010, and $4.3 million in 2009.  The reduction to the long-term liability at December 31, 2011 is due to a change in the administration of the plan in 2011.

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NOTE 15—PREFERRED STOCK

We have 1,000,000 authorized shares of preferred stock with no mandatory redemption and a $100 par value. Outstanding shares were as follows at December 31:

	2011			2010
(Millions, except share amounts) Series	Shares Outstanding	Carrying Value		Shares Outstanding	Carrying Value
5.00%	131,916	$	13.2	131,916	$	13.2
5.04%	29,983	3.0		29,983	3.0
5.08%	49,983	5.0		49,983	5.0
6.76%	150,000	15.0		150,000	15.0
6.88%	150,000	15.0		150,000	15.0
Total	511,882	$	51.2	511,882	$	51.2

All shares of preferred stock of all series are of equal rank except as to dividend rates and redemption terms.  Payment of dividends from any earned surplus or other available surplus is not restricted by the terms of any indenture or other undertaking by us.  Each series of outstanding preferred stock is redeemable in whole or in part at our option at any time on 30 days’ notice at the respective redemption prices.  We may not redeem less than all, nor purchase any, of our preferred stock during the existence of any dividend default.

In the event of our dissolution or liquidation, the holders of preferred stock are entitled to receive (a) the par value of their preferred stock out of the corporate assets other than profits before any of such assets are paid or distributed to the holders of common stock and (b) the amount of dividends accumulated and unpaid on their preferred stock out of the surplus or net profits before any of such surplus or net profits are paid to the holders of common stock.  Thereafter, the remainder of the corporate assets, surplus, and net profits would be paid to the holders of common stock.

The preferred stock has no pre-emptive, subscription, or conversion rights, and has no sinking fund provisions.

NOTE 16—COMMON EQUITY

Various laws, regulations, and financial covenants impose restrictions on our ability to pay dividends to the sole holder of our common stock, Integrys Energy Group.

The PSCW allows us to pay normal dividends on our common stock of no more than 103% of the previous year’s common stock dividend.  In addition, the PSCW currently requires us to maintain a calendar year average financial common equity ratio of 50.24% or higher.  We must obtain PSCW approval if the payment of dividends would cause us to fall below this authorized level of common equity.  Integrys Energy Group’s right to receive dividends on our common stock is also subject to the prior rights of our preferred shareholders and to provisions in our restated articles of incorporation, which limit the amount of common stock dividends that we may pay if our common stock and common stock surplus accounts constitute less than 25% of our total capitalization.

Our short-term debt obligations contain financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65%.  Failure to comply with

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these covenants could result in an event of default which could result in the acceleration of outstanding debt obligations.

As of December 31, 2011, our total restricted net assets were approximately $1,089.8 million.  Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was $26.2 million at December 31, 2011.

Except for the restrictions described above and subject to applicable law, we do not have any other significant dividend restrictions.

Integrys Energy Group may provide equity contributions to us or request a return of capital from us in order to maintain utility common equity levels consistent with those allowed by the PSCW.  Wisconsin law prohibits us from making loans to or guaranteeing obligations of Integrys Energy Group or its other subsidiaries.  During the twelve months ended December 31, 2011, we returned $89.3 million of capital to Integrys Energy Group, paid common stock dividends of $102.5 million to Integrys Energy Group, and received $20.0 million of equity contributions from Integrys Energy Group.

NOTE 17—STOCK-BASED COMPENSATION

Our employees may be granted awards under Integrys Energy Group’s stock-based compensation plans.  At December 31, 2011, stock options, performance stock rights, and restricted share units were outstanding under various plans.  Compensation cost associated with these awards is allocated to us based on the percentages used for allocation of the award recipients’ labor costs.

The following table reflects the stock-based compensation expense and the related deferred tax benefit recognized in income for the years ended December 31:

(Millions)	2011		2010		2009
Performance stock rights	$	1.3	$	3.8	$	1.7
Restricted shares and restricted share units	2.3		3.7		1.7
Total stock-based compensation expense	$	3.6	$	7.5	$	3.4
Income tax benefit	$	1.4	$	3.0	$	1.4

Compensation cost recognized for stock options was not significant during 2011, 2010, and 2009.

The total compensation cost capitalized for all awards during 2011, 2010, and 2009 was not significant.

Stock Options

Under the provisions of the 2010 Integrys Energy Group Omnibus Incentive Compensation Plan, no single employee who is Integrys Energy Group’s chief executive officer or one of the other three highest compensated officers of Integrys Energy Group (including officers of its subsidiaries) can be granted options for more than 1,000,000 shares during any calendar year. All stock options  granted to our employees are for the option to purchase shares of Integrys Energy Group common stock.  No stock options can have a term longer than ten years. The exercise price of each stock option is equal to the fair market value of the stock on the date the stock option is granted. Generally, one-fourth of the stock options granted vest and become exercisable each year on the anniversary of the grant date.

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The fair values of stock option awards granted were estimated using a binomial lattice model. The expected term of option awards is calculated based on historical exercise behavior and represents the period of time that options are expected to be outstanding. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate of Integrys Energy Group. The expected stock price volatility was estimated using its 10-year historical volatility. The following table shows the weighted-average fair values per stock option along with the assumptions incorporated into the valuation models:

	2011 Grant	2010 Grant	2009 Grant
Weighted-average fair value per option	$6.57	$5.30	$3.83
Expected term	5 years	6 years	8 - 9 years
Risk-free interest rate	0.27% - 3.90%	2.38%	2.50% - 2.78%
Expected dividend yield	5.34%	5.46%	5.50%
Expected volatility	25%	25%	19%

A summary of stock option activity for 2011 and information related to outstanding and exercisable stock options at December 31, 2011, is presented below:

	Stock Options		Weighted-Average Exercise Price Per Share		Weighted- Average Remaining Contractual Life (in Years)	Aggregate Intrinsic Value (Millions)
Outstanding at December 31, 2010	154,963		$	47.10
Granted	15,293		49.40
Exercised	(35,280	)	43.09
Outstanding at December 31, 2011	134,976		$	48.41	5.44	$	0.8
Exercisable at December 31, 2011	87,561		$	50.24	4.05	$	0.4

As of December 31, 2011, future compensation cost expected to be recognized for unvested and outstanding stock options was not significant.

Cash received from option exercises was not significant during 2011, 2010, and 2009.

The aggregate intrinsic value for outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they all exercised their options at December 31, 2011. This is calculated as the difference between Integrys Energy Group’s closing stock price on December 31, 2011, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during 2011, 2010, and 2009 was not significant.

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Performance Stock Rights

Performance stock rights vest over a three-year performance period.  For accounting purposes, awards granted to retirement eligible employees vest over a shorter period; however, the distribution of these awards is not accelerated. No single employee who is Integrys Energy Group’s chief executive officer or one of the other three highest compensated officers of Integrys Energy Group (including officers of its subsidiaries) can receive a payout in excess of 250,000 performance shares during any calendar year.  Performance stock rights are either paid out in shares of Integrys Energy Group common stock or an eligible employee can elect to defer the value of their awards into the deferred compensation plan and choose among various investment options, some of which are ultimately paid out in Integrys Energy Group common stock and some of which are ultimately paid out in cash. Beginning in 2011, eligible employees can now only elect to defer up to 80% of the value of their awards. The number of shares paid out is calculated by multiplying a performance percentage by the number of outstanding stock rights at the completion of the performance period. The performance percentage is based on the total shareholder return of Integrys Energy Group’s common stock relative to the total shareholder return of a peer group of companies. The payout may range from 0% to 200% of target.

Performance stock rights are accounted for as either an equity award or a liability award depending on their settlement features. Awards that can only be settled in shares of Integrys Energy Group common stock are accounted for as equity awards. Awards that an employee has elected to defer or is still able to defer into the deferred compensation plan are accounted for as liability awards and are recorded at fair value each reporting period.

Six months prior to the end of the performance period, employees can no longer change their election to defer the value of their performance stock rights into the deferred compensation plan. As a result, any awards not elected for deferral at this point in the performance period will be settled in Integrys Energy Group’s common stock.  This changes the classification of these awards from a liability award to an equity award.  The change in classification is accounted for as an award modification. The fair value on the modification date is used to measure these awards for the remaining six months of the performance period. No incremental compensation expense is recorded as a result of this award modification.

The fair values of performance stock rights were estimated using a Monte Carlo valuation model. The risk-free interest rate is based on the United States Treasury yield curve. The expected dividend yield incorporates the current and historical dividend rate of Integrys Energy Group. The expected volatility was estimated using one to three years of historical data. The table below reflects the assumptions used in the valuation of the outstanding grants at December 31:

	2011	2010	2009
Risk-free interest rate	0.00% - 1.27%	0.21% - 0.56%	1.38% - 4.71%
Expected dividend yield	5.28% - 5.34%	5.34%	4.50% - 5.50%
Expected volatility	21% - 36%	20% - 34%	15% -26%

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A summary of the 2011 activity related to performance stock rights accounted for as equity awards is presented below:

	Performance Stock Rights	Weighted-Average Fair Value *
Outstanding at December 31, 2010	—	$	—
Granted	697	49.21
Award modifications	3,932	45.62
Outstanding at December 31, 2011	4,629	$	46.16

*Reflects the weighted-average fair value used to measure equity awards. Equity awards are measured using the grant date fair value or the fair value on the modification date.

A summary of the 2011 activity related to performance stock rights accounted for as liability awards is presented below:

	Performance Stock Rights
Outstanding at December 31, 2010	10,272
Granted	2,781
Award modifications	(3,932	)
Distributed	(4,100	)
Adjustment for final payout	794
Outstanding at December 31, 2011	5,815

The weighted-average fair value of all outstanding performance stock rights accounted for as liability awards as of December 31, 2011, was $57.54 per performance stock right.

As of December 31, 2011, future compensation cost expected to be recognized for unvested and outstanding performance stock rights (equity and liability awards) was not significant.

The total intrinsic value of performance stock rights distributed during the years ended December 31, 2011 and 2010 was not significant. No performance stock rights were distributed in 2009 because the performance percentage was below the threshold payout level for those rights that were vested and eligible to be distributed during the year ended December 31, 2009.

Restricted Shares and Restricted Share Units

Restricted shares and restricted share units generally have a four-year vesting period, with 25% of each award vesting on each anniversary of the grant date. During the vesting period, restricted share recipients had voting rights and were entitled to dividends in the same manner as other Integrys Energy Group common shareholders. Restricted share unit recipients do not have voting rights, but they receive Integrys Energy Group dividend equivalents in the form of additional restricted share units. During 2011, the last of the outstanding restricted shares vested. Only restricted share units remain outstanding at December 31, 2011.

Restricted shares and restricted share units are accounted for as either an equity award or a liability award depending on their settlement features. Awards that can only be settled in shares of Integrys

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Energy Group common stock and cannot be deferred into the deferred compensation plan are accounted for as equity awards.  Beginning in 2011, eligible employees can now only elect to defer up to 80% of their awards into the deferred compensation plan. Equity awards are measured based on the fair value on the grant date. Awards that an employee has elected to defer into the deferred compensation plan are accounted for as liability awards and are recorded at fair value each reporting period.

A summary of the activity related to all restricted share and restricted share unit awards (equity and liability awards) for the year ended December 31, 2011, is presented below:

	Restricted Share and Restricted Share Unit Awards		Weighted-Average Grant Date Fair Value
Outstanding at December 31, 2010	60,432		$	43.12
Granted	23,488		49.40
Dividend equivalents	3,234		44.87
Vested	(19,927	)	43.86
Outstanding at December 31, 2011	67,227		$	45.18

As of December 31, 2011, $1.1 million of compensation cost related to these awards was expected to be recognized over a weighted-average period of 2.5 years.

The total intrinsic value of restricted share and restricted share unit awards vested for the year ended December 31, 2011, was $1.0 million, and was not significant for the years ended December 31, 2010 and 2009. The actual tax benefit realized for the tax deductions from the vesting of restricted shares and restricted share units during the year ended December 31, 2011, 2010, and 2009 was not significant.

The weighted-average grant date fair value of restricted shares and restricted share units awarded during the years ended December 31, 2011, 2010, and 2009 was $49.40, $41.58, and $42.12 per share, respectively.

NOTE 18—VARIABLE INTEREST ENTITIES

We have a variable interest in an entity through a power purchase agreement relating to the cost of fuel.  This agreement contains a tolling arrangement in which we supply the scheduled fuel and purchase capacity and energy from the facility.  This contract expires in 2016.  As of December 31, 2011 and December 31, 2010, we had approximately 500 megawatts of capacity available under this agreement.

We evaluated this variable interest entity for possible consolidation.  We considered which interest holder has the power to direct the activities that most significantly impact the economics of the variable interest entity; this interest holder is considered the primary beneficiary of the entity and is required to consolidate the entity.  For a variety of reasons, including qualitative factors such as the length of the remaining term of the contracts compared with the remaining lives of the plants and the fact that we do not have the power to direct the operations and maintenance of the facilities, we determined we are not the primary beneficiary of this variable interest entity.

At December 31, 2011, the assets and liabilities on the balance sheets that related to our involvement with this variable interest entity pertained to working capital accounts and represented the amounts we owed for current deliveries of power.  We have not guaranteed any debt or provided any equity

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support, liquidity arrangements, performance guarantees, or other commitments associated with this contract.  There is not a significant potential exposure to loss as a result of our involvement with the variable interest entity.

NOTE 19—FAIR VALUE

Fair Value Measurements

The following tables show assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:

	December 31, 2011
(Millions)	Level 1		Level 2		Level 3		Total
Risk management assets
Natural gas contracts	$	0.1	$	—	$	—	$	0.1
FTRs	—		—		1.3		1.3
Petroleum products contracts	0.1		—		—		0.1
Total	$	0.2	$	—	$	1.3	$	1.5
Risk management liabilities
Natural gas contracts	$	2.5	$	—	$	—	$	2.5
FTRs	—		—		0.1		0.1
Coal contract	—		—		6.9		6.9
Total	$	2.5	$	—	$	7.0	$	9.5

	December 31, 2010
(Millions)	Level 1		Level 2		Level 3		Total
Risk management assets
Natural gas contracts	$	0.4	$	—	$	—	$	0.4
FTRs	—		—		2.2		2.2
Petroleum products contracts	0.3		—		—		0.3
Coal contract	—		—		3.7		3.7
Total	$	0.7	$	—	$	5.9	$	6.6
Risk management liabilities
Natural gas contracts	$	2.3	$	—	$	—	$	2.3
FTRs	—		—		0.2		0.2
Coal contract	—		—		1.2		1.2
Total	$	2.3	$	—	$	1.4	$	3.7

The risk management assets and liabilities listed in the tables above include NYMEX futures and options, as well as financial contracts used to manage transmission congestion costs in the MISO market.  NYMEX contracts are valued using the NYMEX end-of-day settlement price, which is a Level 1 input.  The valuation for FTRs is derived from historical data from MISO, which is considered a Level 3 input.  The valuation for the physical coal contract is categorized in Level 3, as significant assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term.   For more

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information on our derivative instruments, see Note 2, “Risk Management Activities.”  There were no transfers between the levels of the fair value hierarchy during 2011.

The following table sets forth a reconciliation of changes in the fair value of items categorized as Level 3 measurements:

	2011
(Millions)	FTRs			Coal Contract			Total
Balance at beginning of period	$	2.0		$	2.5		$	4.5
Net realized loss included in earnings	(1.2		)	—			(1.2		)
Net unrealized loss recorded as regulatory assets or liabilities	(1.2		)	(8.0		)	(9.2		)
Purchases	2.8			—			2.8
Sales	(0.1		)	—			(0.1		)
Settlements	(1.1		)	(1.4		)	(2.5		)
Balance at end of period	$	1.2		$	(6.9	)	$	(5.7	)

	2010								2009
(Millions)	FTRs			Coal Contract		Total			FTRs
Balance at beginning of period	$	3.1		$	—	$	3.1		$	2.7
Net realized gain included in earnings	4.0			—		4.0			(2.9		)
Net unrealized gain (loss) recorded as regulatory assets or liabilities	(1.2		)	2.5		1.3			2.0
Net purchases and settlements	(3.9		)	—		(3.9		)	1.3
Balance at end of period	$	2.0		$	2.5	$	4.5		$	3.1

Unrealized gains and losses on FTRs and the coal contract are deferred as regulatory assets or liabilities.  Therefore, these fair value measurements have no impact on earnings.  Realized gains and losses on FTRs, as well as the related transmission congestion costs, are recorded in cost of fuel, natural gas, and purchased power on the statements of income.

Fair Value of Financial Instruments

The following table shows the financial instruments included on our balance sheets that are not recorded at fair value:

	2011				2010
(Millions)	Carrying  Amount		Fair Value		Carrying  Amount		Fair Value
Long-term debt	$	721.3	$	816.7	$	871.1	$	924.3
Long-term debt to parent	7.9		9.2		8.6		10.0
Preferred stock	51.2		51.9		51.2		46.9

The fair values of long-term debt are estimated based on the quoted market price for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity.  The fair values of preferred stock are estimated based on quoted market prices, when available, or by using a perpetual dividend discount model.

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Due to the short-term nature of cash and cash equivalents, accounts receivable, accounts payable, notes payable, and outstanding commercial paper, the carrying amount for each such item approximates fair value.

NOTE 20—MISCELLANEOUS INCOME

Our total miscellaneous income was as follows at December 31:

(Millions)	2011		2010			2009
Equity earnings on investments	$	10.7	$	10.8		$	11.0
Key executive life insurance income	1.1		1.6			1.2
Equity portion of AFUDC	0.6		0.7			5.1
Other	0.8		(0.7		)	(0.5		)
Total miscellaneous income	$	13.2	$	12.4		$	16.8

NOTE 21—REGULATORY ENVIRONMENT

Wisconsin

2012 Rates

On December 9, 2011, the PSCW issued a final written order, effective January 1, 2012.  It authorized an electric rate increase of $8.1 million and required a natural gas rate decrease of $7.2 million.  The rate order allows for the netting of the 2010 electric decoupling under-collection with the 2011 electric decoupling over-collection.  The rate order also allows for the deferral of direct Cross State Air Pollution Rule (CSAPR) compliance costs, including carrying costs.  No amounts were deferred related to CSAPR as of December 31, 2011.

2011 Rates

On January 13, 2011, the PSCW issued a final written order authorizing an electric rate increase of $21.0 million, calculated on a per-unit basis.  Although the rate order included a lower authorized return on common equity, lower rate base, and other reduced costs, which resulted in lower total revenues and margins, the rate order also projected lower total sales volumes, which led to a rate increase on a per-unit basis. The rate order also included a projected increase in customer counts that did not materialize, which impacts the decoupling calculation as it adjusts for differences between the actual and authorized margin per customer. The $21.0 million electric rate increase included $20.0 million of recovery of prior deferrals, the majority of which related to the recovery of the 2009 electric decoupling deferral.  The $21.0 million excluded the impact of a $15.2 million estimated fuel refund (including carrying costs) from 2010.  The PSCW rate order also required an $8.3 million decrease in natural gas rates, which included $7.1 million of recovery for the 2009 decoupling deferral.  The new rates were effective January 14, 2011, and reflected a 10.30% return on common equity, down from a 10.90% return on common equity in the previous rate order, and a common equity ratio of 51.65% in our regulatory capital structure.

The order also addressed the new Wisconsin electric fuel rule, which was finalized on March 1, 2011.  The new fuel rule is effective retroactive to January 1, 2011.  It requires the deferral of under or over-collections of fuel and purchased power costs that exceed a 2% price variance from the cost of fuel

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and purchased power included in rates.  Under or over-collections deferred in the current year will be recovered or refunded in a future rate proceeding.  As of December 31, 2011, $2.2 million was deferred as a regulatory liability related to 2011 fuel and purchased power cost over-collections.  All 2010 fuel cost over-collections were refunded to customers in 2011.

2010 Rates

On December 22, 2009, the PSCW issued a final written order, effective January 1, 2010.  It authorized an electric rate increase of $18.2 million, offset by an $18.2 million refund of 2009 and 2008 fuel cost over-collections.  It also authorized a retail natural gas rate increase of $13.5 million.  Based on an order issued on April 1, 2010, the remaining $10.0 million of the total 2008 and 2009 fuel cost over-collections, plus interest of $1.3 million, was refunded to customers in April and May 2010.

NOTE 22—SEGMENTS OF BUSINESS

At December 31, 2011, we reported three segments.  We manage our reportable segments separately due to their different operating and regulatory environments.  Our principal business segments are the regulated electric utility operations and the regulated natural gas utility operations.  The other segment includes nonutility activities, as well as equity earnings from our investments in WRPC and WPS Investments, LLC, which holds an interest in ATC.

The tables below present information for the respective years pertaining to our reportable segments:

	Regulated Utilities
2011 (Millions)	Electric Utility			Natural Gas Utility			Total Utility			Other		Reconciling Eliminations			WPS Consolidated
Income Statement
External revenues	$	1,220.7		$	342.4		$	1,563.1		$	1.4	$	(1.4	)	$	1,563.1
Intersegment revenues	—			10.2			10.2			—		(10.2		)	—
Depreciation and amortization expense	80.8			14.7			95.5			0.6		(0.5		)	95.6
Miscellaneous income	0.6			(0.1		)	0.5			12.7 11.3		—			13.2
Interest expense	38.1			9.0			47.1			2.4		—			49.5
Provision for income taxes	55.5			14.2			69.7			3.5		—			73.2
Preferred stock dividend requirements	(2.5		)	(0.6		)	(3.1		)	—		—			(3.1		)
Net income attributed to common shareholders	93.9			22.3			116.2			6.6		—			122.8
Total assets	2,689.8			632.7			3,322.5			105.0		—			3,427.5
Cash expenditures for long-lived assets	68.5			22.7			91.2			0.3		—			91.5

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	Regulated Utilities
2010 (Millions)	Electric Utility			Natural Gas Utility			Total Utility			Other		Reconciling Eliminations			WPS Consolidated
Income Statement
Operating revenues	$	1,223.4		$	365.6		$	1,589.0		$	1.4	$	(1.4	)	$	1,589.0
Depreciation and amortization expense	88.2			22.4			110.6			0.5		(0.5		)	110.6
Miscellaneous income	0.8			0.2			1.0			11.4 11.3		—			12.4
Interest expense	40.7			9.6			50.3			4.1		—			54.4
Provision for income taxes	59.3			16.1			75.4			2.6		—			78.0
Preferred stock dividend requirements	(2.5		)	(0.6		)	(3.1		)	—		—			(3.1		)
Net income attributed to common shareholder	103.4			23.2			126.6			5.3		—			131.9
Total assets	2,653.4			628.7			3,282.1			103.9		—			3,386.0
Cash expenditures for long-lived assets	62.7			22.8			85.5			—		—			85.5

	Regulated Utilities
2009 (Millions)	Electric Utility			Natural Gas Utility			Total Utility			Other		Reconciling Eliminations			WPS Consolidated
Income Statement
Operating revenues	$	1,188.2		$	395.6		$	1,583.8		$	1.4	$	(1.4	)	$	1,583.8
Depreciation and amortization expense	84.1			23.0			107.1			0.5		(0.5		)	107.1
Miscellaneous income	4.5			0.6			5.1			11.7 11.3		—			16.8
Interest expense	38.6			10.5			49.1			4.9		—			54.0
Provision for income taxes	50.2			15.8			66.0			2.0		—			68.0
Preferred stock dividend requirements	(2.5		)	(0.6		)	(3.1		)	—		—			(3.1		)
Net income attributed to common shareholder	88.0			24.1			112.1			5.2		—			117.3
Total assets	2,602.5			606.2			3,208.7			102.6		—			3,311.3
Cash expenditures for long-lived assets	235.2			24.3			259.5			—		—			259.5

NOTE 23—RELATED PARTY TRANSACTIONS

We and our subsidiary, WPS Leasing, routinely enter into transactions with related parties, including Integrys Energy Group, its subsidiaries, and other entities in which we have material interests.

We provide and receive services, property, and other items of value to and from our parent, Integrys Energy Group, and other subsidiaries of Integrys Energy Group.  All such transactions are made pursuant to an affiliated interest agreement (“Regulated Agreement”) approved by the PSCW.  MGU, MERC, UPPCO, PGL, and NSG (together with us, the “regulated subsidiaries”) have all been added as parties to the Regulated Agreement and, like us, can also provide and receive services, property, and other items of value to and from their parent, Integrys Energy Group, and other regulated subsidiaries of Integrys Energy Group.  We are also a party to an agreement with Integrys Energy Group and Integrys Energy Group’s non-regulated subsidiaries.  This affiliated interest agreement (“Non-Regulated Agreement”) was also approved by the PSCW.  The other regulated subsidiaries are not parties to the Non-Regulated Agreement.  The Regulated Agreement requires that all services are provided at cost.  The Non-Regulated Agreement provides that we must receive payment equal to the higher of our cost or fair

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value for services, property, and other items of value that we provide to Integrys Energy Group or its other non-regulated subsidiaries, and that we must make payments equal to the lower of the provider’s cost or fair value for services, property, and other items of value that Integrys Energy Group or its other non-regulated subsidiaries provide to us.  Modification or amendment to these agreements requires the approval of the PSCW.

IBS provides 15 categories of services (including financial, human resource, and administrative services) to us pursuant to an affiliated interest agreement (IBS AIA), which has been approved, or from which we have been granted appropriate waivers, by the appropriate regulators, including the PSCW.  As required by FERC regulations for centralized service companies, IBS renders services at cost.  The PSCW must be notified prior to making changes to the services offered under and the allocation methods specified in the IBS AIA.  Other modifications or amendments to the IBS AIA would require PSCW approval.  Recovery of allocated costs is addressed in our rate cases.

In 2010, a new affiliated interest agreement (Non-IBS AIA) that would govern the provision of intercompany services, other than IBS services, within Integrys Energy Group, was submitted to the PSCW for approval.  The Non-IBS AIA was written primarily to limit the scope of services now provided by IBS that had been provided under the Regulated Agreement and the Non-Regulated Agreement.  The Non-IBS AIA would replace these current agreements, except the IBS AIA, after proper approvals.  The pricing methodologies from the current agreements would carry forward to the Non-IBS AIA.  On January 23, 2012, the PSCW issued its final decision.  We are currently evaluating the requirements in the final decision.

We provide repair and maintenance services to ATC under an Operation and Maintenance Services Agreement for Transmission Facilities approved by the PSCW.  Services are billed to ATC under this agreement at our fully allocated cost.

The table below includes information related to transactions entered into with related parties as of December 31:

(Millions)	2011		2010
Notes payable (1)
Integrys Energy Group	$	7.9	$	8.6
Benefit costs (2)
Receivables from related parties	13.0		11.8
Liability related to income tax allocation
Integrys Energy Group	8.0		9.0

(1)WPS Leasing, our consolidated subsidiary, has a note payable to our parent company, Integrys Energy Group.

(2)We serve as plan sponsor and administrator for certain other postretirement benefit plans.  The net periodic benefit cost associated with the plans and the portions of the funded status not yet recognized in income are allocated among Integrys Energy Group’s subsidiaries.

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The following table shows activity associated with related party transactions for the years ended December 31:

(Millions)	2011		2010		2009
Electric transactions
Sales to UPPCO	$	22.6	$	26.7	$	42.5
Purchases from UPPCO	—		—		0.2
Natural gas transactions
Sales to Integrys Energy Services	0.4		0.7		0.5
Purchases from Integrys Energy Services	1.1		1.2		1.5
Interest expense (1)
Integrys Energy Group	0.7		0.8		0.8
Transactions with equity method investments
Charges from ATC for network transmission services	96.6		96.6		84.5
Charges to ATC for services and construction	11.4		11.2		7.2
Net proceeds from WRPC sales of energy to MISO	4.7		4.5		2.6
Purchases of energy from WRPC	4.9		4.7		4.6
Revenues from services provided to WRPC	0.7		0.6		0.6
Income from WPS Investments, LLC (2)	9.8		9.8		10.0

(1)WPS Leasing, our consolidated subsidiary, has a note payable to our parent company, Integrys Energy Group.

(2)WPS Investments, LLC is a consolidated subsidiary of Integrys Energy Group that is jointly owned by Integrys Energy Group, UPPCO, and us.  At December 31, 2011, we had a 12.27% interest in WPS Investments accounted for under the equity method.  Our percentage ownership interests have continued to decrease as additional equity contributions are made by Integrys Energy Group to WPS Investments.

NOTE 24—QUARTERLY FINANCIAL INFORMATION (Unaudited)

(Millions)	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
2011
Operating revenues	$	441.8	$	351.0	$	376.8	$	393.5	$	1,563.1
Operating income	78.8		40.2		63.2		53.2		235.4
Net income attributed to common shareholder	43.5		17.6		34.6		27.1		122.8
2010
Operating revenues	$	467.0	$	345.0	$	388.1	$	388.9	$	1,589.0
Operating income	89.8		46.5		70.7		48.0		255.0
Net income attributed to common shareholder	47.5		23.7		39.5		21.2		131.9

Because of various factors, the quarterly results of operations are not necessarily comparable.

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H.  REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON FINANCIAL STATEMENTS

To the Board of Directors of Wisconsin Public Service Corporation:

We have audited the accompanying consolidated balance sheets and statements of capitalization of Wisconsin Public Service Corporation and subsidiary (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of income, common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Wisconsin Public Service Corporation and subsidiary as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ Deloitte & Touche LLP

Milwaukee, Wisconsin

February 28, 2012

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ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of WPS’s disclosure controls and procedures (as defined by Securities Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report.  Based upon that evaluation, management, including our Chief Executive Officer and Chief Financial Officer, has concluded that WPS’s disclosure controls and procedures were effective as of the end of the period covered by this report.

Changes in Internal Controls

There were no changes in our internal control over financial reporting (as defined by Securities Exchange Act Rules 13a-15(f) and 15d-15(f)) during the quarter ended December 31, 2011, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management Report on Internal Control over Financial Reporting

For WPS’s Management Report on Internal Control Over Financial Reporting see Section A of Item 8.

ITEM 9B.  OTHER INFORMATION

None.

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PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Name and Age (1)		Position and Business Experience During Past Five Years	Effective Date
Charles A. Schrock	58	Chairman, President and Chief Executive Officer of Integrys Energy Group and Director of WPS	05-10-11
		Chairman, President and Chief Executive Officer of Integrys Energy Group and Chairman and Director of WPS	04-01-10
		President and Chief Executive Officer of Integrys Energy Group and Chairman and Director of WPS	03-16-09
		President and Chief Executive Officer of Integrys Energy Group and Director of WPS	01-01-09
		President, Chief Executive Officer and Director	05-31-08
		President and Director	02-21-07
		President and Chief Operating Officer — Generation	08-15-04
Lawrence T. Borgard	50	President and Chief Operating Officer — Utilities of Integrys Energy Group and Chairman and Chief Executive Officer and Director of WPS	12-25-11
		President and Chief Operating Officer — Utilities of Integrys Energy Group and Chairman, President and Chief Executive Officer and Director of WPS	05-10-11
		President and Chief Operating Officer — Utilities of Integrys Energy Group and President and Chief Executive Officer and Director of WPS	04-05-09
		President and Chief Operating Officer — Integrys Gas Group (2) and Director of WPS	02-21-07
		President and Chief Operating Officer — Energy Delivery	08-15-04
Charles A. Cloninger	54	President	12-25-11
		President of MERC and MGU	10-05-08
		President of MERC	12-18-05
Phillip M. Mikulsky	63	Executive Vice President — Business Performance and Shared Services of Integrys Energy Group and Director of WPS	12-26-10
		Executive Vice President — Corporate Development and Shared Services of Integrys Energy Group and Director of WPS	09-21-08
		Executive Vice President and Chief Development Officer of Integrys Energy Group and Director of WPS	02-21-07
		Executive Vice President — Development of Integrys Energy Group	09-12-04
Mark A. Radtke	50	Executive Vice President and Chief Strategy Officer of Integrys Energy Group and Director of WPS	05-10-11
		Executive Vice President and Chief Strategy Officer of Integrys Energy Group	12-26-10
		Chief Executive Officer — Integrys Energy Services	01-10-10
		President and Chief Executive Officer — Integrys Energy Services	06-01-08
		President — Integrys Energy Services (previously named WPS Energy Services, Inc.)	10-17-99
Joseph P. O’Leary	57	Senior Vice President and Chief Financial Officer of Integrys Energy Group and WPS and Director of WPS	02-21-07
		Senior Vice President and Chief Financial Officer of Integrys Energy Group and WPS	06-04-01
Diane L. Ford	58	Vice President and Corporate Controller of Integrys Energy Group and WPS	02-21-07
		Vice President — Controller and Chief Accounting Officer of Integrys Energy Group and WPS	07-11-99

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Name and Age (1)		Position and Business Experience During Past Five Years	Effective Date
William J. Guc	42	Vice President and Treasurer of Integrys Energy Group and Treasurer of WPS	12-01-10
		Vice President — Finance and Accounting and Controller — Integrys Energy Services	03-07-10
		Vice President and Controller — Integrys Energy Services	09-21-08
		Controller — Integrys Energy Services (previously named WPS Energy Services)	02-21-05
William D. Laakso	49	Vice President — Human Resources of Integrys Energy Group and Director of WPS	09-21-08
		Interim Vice President — Human Resources of IBS and Director of WPS	08-25-08
		Interim Vice President — Human Resources of IBS	05-15-08
		Director — Workforce and Organizational Development of IBS	08-12-07
		Director of Organizational Development	12-12-05
James F. Schott	54	Vice President — External Affairs of Integrys Energy Group and WPS and Director of WPS	05-12-10
		Vice President — External Affairs of Integrys Energy Group and Vice President — Regulatory Affairs and Director of WPS	04-01-10
		Vice President — External Affairs of Integrys Energy Group and Vice President — Regulatory Affairs	03-22-10
		Vice President — Regulatory Affairs	07-18-04
Barth J. Wolf	54	Vice President, Chief Legal Officer, and Secretary of Integrys Energy Group and Secretary of WPS	07-31-07
		Vice President — Legal Services and Chief Compliance Officer — IBS	02-21-07
		Secretary and Manager — Legal Services of Integrys Energy Group and WPS	09-19-99

(1)	Officers and their ages are as of December 31, 2011. None of the executives and/or directors listed above are related by blood, marriage, or adoption to any of the other officers listed or to any of our directors. Each officer holds office until his or her successor has been duly elected and qualified, or until his or her death, resignation, disqualification, or removal.
(2)	The Integrys Gas Group included PGL, NSG, MERC, and MGU.

Our board of directors is comprised solely of inside directors, and we do not have any standing committees of our board of directors.  The role of an effective director inherently requires certain personal qualities, such as integrity, as well as the ability to comprehend, discuss, and critically analyze materials and issues that are presented so that the director may exercise judgment and reach conclusions in fulfilling his or her duties and fiduciary obligations.  We believe that the specific background of each director, as set forth in the table above, evidences their ability to serve as a director and, accordingly, led to the conclusion that each of the directors should continue to serve as a director.

We are a wholly owned subsidiary of Integrys Energy Group.  See Integrys Energy Group’s Proxy Statement for its Annual Meeting of Shareholders to be held May 10, 2012 (Proxy Statement), under “Ownership of Voting Securities — Section 16(a) Beneficial Ownership Reporting Compliance” for information related to Section 16 compliance.

Integrys Energy Group has adopted a Code of Conduct, which covers us and serves as our Code of Business Conduct and Ethics.  The Code of Conduct applies to all of our directors, officers, and employees, including the Chief Executive Officer, Chief Financial Officer, Corporate Controller, and any other persons performing similar functions.

Integrys Energy Group’s Code of Conduct may be accessed on the Integrys Energy Group website at www.integrysgroup.com by selecting “Investors,” then selecting “Corporate Governance,” then selecting

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“Governance Documents.”  Amendments to, or waivers from, the Code of Conduct will be disclosed on Integrys Energy Group’s website within the prescribed time period.

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ITEM 11.  EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

The purpose of this Compensation Discussion and Analysis is to provide material information that is necessary for an understanding of our compensation policies and decisions relating to our named executive officers, including the identification of key components of our executive compensation program, and an explanation of the purpose of each key component.  Our named executive officers for 2011 consisted of the following:

·Lawrence T. Borgard, Chief Executive Officer;

·Joseph P. O’Leary, Senior Vice President and Chief Financial Officer;

·Charles A. Schrock, Chairman, President and Chief Executive Officer of Integrys Energy Group;

·Phillip M. Mikulsky, Executive Vice President — Business Performance and Shared Services of Integrys Energy Group; and

·Barth J. Wolf, Secretary.

Mr. Borgard was President and Chief Executive Officer until December 25, 2011, at which time Charles A. Cloninger was appointed President.

This discussion relates specifically to Mr. Wolf, as Mr. Borgard, Mr. O’Leary, Mr. Schrock and Mr. Mikulsky are also named executive officers of Integrys Energy Group, and the compensation paid to them will be reported in the Proxy Statement of Integrys Energy Group and not herein.  The compensation reported below reflects total compensation paid to Mr. Wolf in consideration of his service to Integrys Energy Group and its subsidiaries, including us.  For the “Compensation Discussion and Analysis” related to Mr. Borgard, Mr. O’Leary, Mr. Schrock and Mr. Mikulsky, see the Proxy Statement, which addresses, among other things, the short-term incentive compensation, the long-term incentive compensation and the other benefits paid or payable to these named executive officers.

Compensation Philosophy and Objectives

We are a wholly owned subsidiary of Integrys Energy Group.  As such, we do not have a standing compensation committee because our executives participate in the compensation programs and plans of Integrys Energy Group, which are administered by the Compensation Committee of Integrys Energy Group’s Board of Directors (referred to as the Committee).  The Committee presents recommendations regarding appropriate compensation packages for our named executive officers to the Integrys Energy Group Board of Directors for its approval.  The recommendations of the Committee are based on the same compensation philosophy and use of market studies as those used in determining compensation for executives of Integrys Energy Group.  For information relating to these matters, as well as a discussion of the role of the Committee and the role of advisors to the Committee, see the Proxy Statement under the caption “Executive Compensation — Compensation Discussion and Analysis.”

Base Salary

Base salary is used to provide cash income to executives to compensate them for services rendered during the fiscal year.  Salary increases for 2011 were determined by the Committee based on recommendations of the Chief Executive Officer of Integrys Energy Group, which may include overall company performance and individual performance of the executive and the Committee’s evaluation of

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current market data as provided by the independent compensation consultant hired by the Committee.  In December 2010, the Committee granted base salary increases for 2011 for our named executive officers that ranged from 3% to 10% to bring base pay closer to market median and averaged approximately 4.5%.  Base salaries for 2011 for our named executive officers were competitive with the market at the time that the base salaries were approved.  The goal of setting base salary at or near market median levels allows the company to be competitive in the marketplace.

Short-Term Incentive Compensation

All of our named executive officers participated in the Integrys Energy Group 2011 Executive Incentive Plan (Incentive Plan).  Provided below are the specific performance goals and measurement weightings established for Mr. Wolf.

	Barth J. Wolf
Diluted EPS — Adjusted (1)	70	%
Environmental Impact (2)	5	%
Customer Satisfaction — Utility Customers (3)	5	%
Customer Satisfaction — Business Partners (4)	10	%
Safety (5)	10	%

(1)	Performance is measured based on Integrys Energy Group diluted earnings per share, which is based on forecasted net income available for common shareholders used to establish investor guidance, and adjusted on an after-tax basis.
(2)	Performance is measured based on the implementation of projects and activities in 2011 that reduced annual emissions of carbon dioxide (CO2) and other greenhouse gases.
(3)	Performance is measured based on customer satisfaction through surveys performed by an outside vendor as compared to survey results of other regional benchmark energy suppliers.
(4)	Performance is measured based on internal customer satisfaction at the Integrys Business Support, LLC subsidiary through biannual partner surveys of internal company business partners as compared to a target score.
(5)	Performance is measured based on OSHA recordable incident rates determined on an Integrys Energy Group consolidated basis.

Under the Incentive Plan, no payouts for financial measure results are made to any of our named executive officers if the Diluted EPS — Adjusted threshold level is not attained.  In addition, Incentive Plan payouts related to non financial measures are reduced by 50% if the Diluted EPS — Adjusted threshold level is not attained.

Threshold, target and superior performance levels for each goal, as well as the weighting of each measure, are approved by the Committee.  For each of the short-term incentive measures, the Committee sets specific performance levels early in the plan year and factors in stretch performance objectives in developing the performance measures.  Threshold levels represent minimally acceptable performance, target levels represent performance that should typically be achievable in any given year, and superior levels represent stellar performance beyond that typically achievable in any given year.

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Provided below are the specific payout levels established for 2011 for Mr. Wolf.

	Payout Levels (as a percent of actual paid base salary)
Named Executive Officer	Threshold	Target	Superior
Barth J. Wolf	—	55.0	110.0

Provided below are threshold, target and superior levels, as well as information related to actual results achieved for 2011 and related payout percentage for the financial measure:

							2011 Actual Results
Financial Measure	Threshold		Target		Superior		Amount		Payout % of Target
Diluted EPS — Adjusted	$	3.31	$	3.58	$	3.84	$	3.53	81.5	%

In making the determination as to the payout related to the financial measure, as provided for in the Incentive Plan, the Committee concluded that certain adjustments to the Diluted EPS — Adjusted measure were appropriate because the events were non-recurring in nature and the accounting effects of these items were not indicative of the performance of our named executive officers during 2011.  These adjustments included adjustments related to a tax law change and health care reform costs, as well as adjustments related to Integrys Energy Group’s nonregulated operations, including mark to market adjustments and a plant impairment.  The total adjustment to the Diluted EPS — Adjusted result was $0.51, with the largest adjustment resulting from a noncash charge related to mark to market adjustments at Integrys Energy Services, Inc.  All adjustments approved by the Committee were consistent with the types of adjustments allowed under the Incentive Plan.

The 2011 non financial measures and performance range results are provided in the following table:

Non Financial Measures	Range of Performance Result
Environmental Impact	Below Threshold
Customer Satisfaction — Utility Customers	Below Threshold
Customer Satisfaction — Business Partners	At Target
Safety	Between Threshold and Target

The amount of total payouts awarded under the Incentive Plan for Mr. Wolf, along with the payout percentages as a percent of targets and individual base salary earnings, are summarized in the table below.

	Barth J. Wolf
Amount of Payout	$	147,097
Payout as % of Target	73.6		%
Payout as % of Base Salary	40.5		%

The Committee believes it is important to establish performance targets and incentives that align executive compensation with financial and operational performance, promote value-driven decision making by executives and provide total compensation levels that are competitive in the market.  Payout

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is made on any individual measure with results above threshold (provided that no payout for any financial measure is made unless the Diluted EPS — Adjusted threshold is reached, and payouts related to non financial measures are also reduced by 50% if the Diluted EPS — Adjusted threshold is not reached).  Company performance and the use of stretch performance objectives have had an effect on payout levels, with payouts for our named executive officers ranging from 60.6% to 101.5% of target and from 40.5% to 101.5% of actual paid base salary during the 2009 through 2011 periods.

Long-Term Incentive Compensation

The long-term incentive compensation granted by the Committee for 2011 as a percent of annualized base salary for Mr. Wolf was 110%.

Other Benefits and Plans

We have certain other plans which provide, or may provide, cash compensation and benefits to our named executive officers.  These benefits and plans include a nonqualified deferred compensation plan, a qualified pension plan, a nonqualified pension restoration plan and supplemental retirement plan, and perquisites.  We also provide life insurance as part of our compensation package.  The Committee considers all of these benefits and plans when reviewing total compensation of our named executive officers.

Deferred Compensation Plan

Our named executive officers may participate in the nonqualified Integrys Energy Group Deferred Compensation Plan.  This nonqualified benefit allows eligible executives to defer 1% to 80% of base salary, annual short-term incentive, and long-term incentive compensation (other than options for Integrys Energy Group common stock) on a pre-tax (federal and state) basis.

Qualified Pension Plan

Our named executive officers are eligible to participate in the qualified Integrys Energy Group Retirement Plan (referred to as the pension plan) upon completion of one year of service and 1,000 or more hours of work during that year.  All named executive officers are eligible to participate in the pension plan.  The pension plan requires three years of employment or the attainment of age 65 to be vested in the plan.

For a more detailed discussion of the pension plan, see the Proxy Statement under the caption “Executive Compensation — Compensation Discussion and Analysis — Other Benefits and Plans — Qualified Pension Plan.”

Provided below is the pension service credit for Mr. Wolf.

Named Executive Officer	Annual Percentage Credit Earned in 2011		Accumulated Total Service Credits Earned as of December 31, 2011
Barth J. Wolf	15	%	346	%

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The pension plan does not allow for granting of additional service credit not otherwise authorized under the plan terms.  Provided in the Pension Benefits Table for 2011 below is a tabulation of the present value of the accumulated pension benefit using full years of credited service only.

Pension Restoration Plan and Supplemental Retirement Plan

Our named executive officers receive a nonqualified pension restoration benefit under the Nonqualified Pension Restoration Plan.  Pension restoration provides a benefit based upon the difference between (1) the benefit the executive would have been entitled to under the pension plan if the maximum benefit limitation under IRS Section 415 and the compensation limitation under IRS Section 401(a)(17) did not apply, and if all base compensation and annual incentive amounts had been paid to the executive in cash rather than being deferred into the Integrys Energy Group Deferred Compensation Plan, and (2) the executive’s actual benefit under the pension plan.  The Nonqualified Deferred Compensation Table for 2011 below provides information on the deferrals into the Pension Restoration Plan and earnings for Mr. Wolf.

In addition, the Integrys Energy Group Board of Directors, based on the recommendation of the Committee, has authorized each of our named executive officers to be provided with a nonqualified supplemental retirement benefit under the Supplemental Retirement Plan (SERP).  This benefit provides income replacement when taking into account other retirement benefits provided to the eligible executive and assures that the eligible executive will receive 60% of his/her final average pay (over the last 36 months or the 3 preceding years, whichever is higher).  To qualify for the full supplemental retirement benefit, the executive must have completed 15 years of service and retire/terminate after age 62.  Reduced benefits are payable if the executive has attained age 55 and completed 10 years of service at retirement or termination.

These additional retirement benefits are designed to attract and retain key management employees who are important to the successful operation of the company.  The Pension Benefits Table for 2011 below provides additional information regarding the present value of accumulated benefits under the SERP for Mr. Wolf.

Beginning in 2008, we made the decision to move away from the use of defined benefit plans for all non-union employees, including executives, because of market trends.  A ten-year transition period applies, which means that, ultimately, no qualified or nonqualified benefit pension plans will exist for future benefit accruals.  These plans are being replaced with defined contribution plans.

Perquisites

Our named executive officers are provided with a modest level of personal benefits.  These may include payments for executive physicals, financial counseling, home office equipment and office parking.

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Life Insurance

Our named executive officers are eligible for an enhanced life insurance benefit of up to three times their annual base salary, with a maximum benefit level (taking into account both employer-provided coverage and any supplemental coverage that the officer voluntarily purchases) of $1,500,000.  Accidental Death and Dismemberment (AD&D) coverage is also provided for these same named executive officers up to three times their annual base salary, subject to a separate $1,500,000 maximum benefit level.  The IRS requires that imputed income be calculated and recorded for company paid life insurance in excess of $50,000.  In compliance with IRS regulations, imputed income is recorded to the extent that an executive’s life insurance benefit exceeds this limit.  Listed below is the life insurance coverage in place as of December 31, 2011 for Mr. Wolf.

Named Executive Officer	Life Insurance Coverage ($)
Barth J. Wolf	1,006,000

Change in Control Agreements

The Committee has authorized each of our named executive officers to receive protection and associated benefits in the event of a covered termination following a change in control of Integrys Energy Group.  These agreements between our named executive officers and Integrys Energy Group each contain a “double trigger” arrangement, whereby a payment is made only if there is a change in control of Integrys Energy Group and the executive is actually terminated or terminates employment under certain circumstances after being demoted or after certain other adverse changes in the executive’s working conditions or status.  The Committee periodically reviews the payment and benefit levels in the change in control agreements and the triggers to ensure that they remain competitive and appropriate.  As part of this process, no tax gross-up provisions are being provided to our named executive officers, except for Mr. Mikulsky.  Mr. Mikulsky’s agreement is a legacy agreement which has contained the gross-up provision since 2000.  We do not intend to provide gross-ups to any other executives.

For a more detailed discussion of the change in control agreements, see the Proxy Statement under the caption “Executive Compensation — Compensation Discussion and Analysis — Other Benefits and Plans — Change in Control Agreements.”

Common Stock Ownership Guidelines

We believe that it is important to align executive and shareholder interests by defining stock ownership guidelines for executives.  Because we are wholly owned by Integrys Energy Group, the stock ownership guidelines are based on Integrys Energy Group common stock.  For 2011, our named executive officers are expected to retain at least 50% of their future vested stock awards until certain levels of common stock are owned, with such levels ranging from one to five times base annual salary, depending on the position.  The target level for ownership of Integrys Energy Group common stock was five times annualized base salary for Charles A. Schrock, three times annualized base salary for Lawrence T. Borgard and Joseph P. O’Leary, two times annualized base salary for Phillip M. Mikulsky, and one times annualized base salary for Barth J. Wolf.  All of our named executive officers are complying with our stock ownership guidelines.

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Summary Compensation Table for 2011

The following table sets forth for Mr. Wolf compensation information for the past three fiscal years during which he was a named executive officer:  (1) the dollar value of base salary and bonus earned during the applicable fiscal years; (2) the aggregate grant date fair value of stock and option awards, as computed in accordance with the FASB ASC Topic 718 (all stock option awards in this and the other tables relate to Integrys Energy Group common stock); (3) the dollar value of earnings for services pursuant to awards granted during the applicable fiscal years under non-equity incentive plans; (4) the change in pension value and nonqualified compensation earnings during the applicable fiscal years; (5) all other compensation for the applicable fiscal years; and (6) the dollar value of total compensation for the applicable fiscal years.  This Summary Compensation Table for 2011 and the tables that follow reflect the compensation paid to Mr. Wolf for all services rendered in all capacities to Integrys Energy Group and its subsidiaries, including us, regardless of whether the compensation was paid by Integrys Energy Group or any of its subsidiaries.  For Mr. Borgard, Mr. O’Leary, Mr. Schrock and Mr. Mikulsky, see the Proxy Statement under the caption “Executive Compensation — Summary Compensation Table for 2011.”

Name and Principal Position	Year	Salary ($)(1)	Bonus ($)	Stock Awards ($)(2)	Option Awards ($)(2)	Non-Equity Incentive Plan Compensation ($)(3)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)(4)	All Other Compensation ($)(5)	Total ($)
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)
Barth J. Wolf Secretary	2011	363,292	—	288,508	83,465	147,097	415,597	17,456	1,315,415
	2010	321,594	—	319,446	105,650	137,559	520,240	16,858	1,421,347
	2009	301,154	—	193,156	58,785	165,595	196,953	19,763	935,406

(1)	Amounts shown include amounts deferred into the Integrys Energy Group Deferred Compensation Plan. See the Nonqualified Deferred Compensation Table for 2011 for more information.
(2)	The amounts shown in columns (e) and (f) reflect the grant date fair value of the awards computed in accordance with FASB ASC Topic 718 - Stock Compensation.  For information regarding the assumptions made in valuing the stock and option awards, see Note [17], “Stock-Based Compensation.”
(3)	Non-equity incentive compensation is payable annually in the first quarter of the next fiscal year, and may be deferred at the election of Mr. Wolf. Payment is calculated based on the measurement outcomes and as a percent of adjusted gross base salary earnings from the company for services performed during the payroll year.
(4)	The calculation of above-market earnings on nonqualified deferred compensation is based on the difference between 120% of the applicable federal long-term rate (AFR) and the rate of return received on Reserve Accounts A and B. Provided below are the actual rates of return used in the calculation: Note that Reserve Account A was frozen to new deferrals beginning on January 1, 1996. Reserve Account B was frozen to new deferrals beginning on April 1, 2008.

Time Period	AFR 120%		Reserve A – Daily		Reserve B – Daily
January 2011 – March 2011	3.99	%	8.2603	%	5.8531	%
April 2011 – September 2011	5.11	%	8.9674	%	6.3604	%
October 2011 – December 2011	3.55	%	7.9370	%	6.0000	%

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(5) The amounts shown include other compensation items consisting of life insurance premiums, imputed income from life insurance benefits, and Employee Stock Ownership Plan (ESOP) matching contributions.  For individual items included in column (i) that were in excess of $10,000, see the table below reflecting ESOP matching contributions.

Named Executive Officer	ESOP ($)
Barth J. Wolf	13,333

With regard to equity awards, no re-pricing, extension of exercise periods, change of vesting or forfeiture conditions, change or elimination of performance criteria, change of bases upon which returns are determined, or any other material modification of any outstanding option or other equity based award occurred during fiscal years reported in the table.

Grants of Plan-Based Awards Table for 2011

The following table sets forth information regarding all incentive plan awards that were made to Mr. Wolf during 2011, including equity and non-equity based awards.  For Mr. Borgard, Mr. O’Leary, Mr. Schrock and Mr. Mikulsky, see the Proxy Statement under the caption “Executive Compensation — Grants of Plan-Based Awards Table for 2011.”

		Estimated Future Payouts Under Non- Equity Incentive Plan Awards Annual Incentive Plan (1)			Estimated Future Payouts Under Equity Incentive Plan Awards Performance Share Program			All Other Stock Awards: Number of Shares of Stock or Units (#) Restricted	All Other Option Awards: Number of Securities Underlying Options (#) Stock	Exercise or Base Price Option	Grant Date Fair Value of Stock and Option
Name	Grant Date	Threshold ($)	Target ($)	Superior ($)	Threshold (#)	Target (#)	Superior (#)	Stock Program	Option Program	Awards ($/Sh)	Awards ($) (2)
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)
Barth J. Wolf	2011	—	202,645	405,290
	02/10/11				2,231	4,463	8,926				206,949
	02/10/11							1,651			81,559
	02/10/11								12,704	49.40	83,465

(1)	Based on 2011 Executive Incentive Plan payout percentages. For more information, see the Proxy Statement under the caption “Executive Compensation — Compensation Discussion and Analysis — Key Components of the Executive Compensation Program — Short-Term Incentive Compensation.”
(2)	Performance shares are valued at $46.37, the target payout value derived from a Monte Carlo simulation. Restricted stock units are valued at $49.40, the closing stock price on the grant date. Stock options are valued at $6.57 on an accounting expense basis based on a proprietary “advance lattice” option pricing model.

For a narrative description of the material factors necessary to understand the information disclosed in the Summary Compensation Table for 2011 and the Grants of Plan-Based Award Table for 2011, see the Proxy Statement under the caption “Executive Compensation.”

Outstanding Equity Awards Table for 2011

The following table sets forth information for Mr. Wolf regarding outstanding awards under the stock option plan, restricted stock plan, incentive plans, and similar plans, including market based values of associated rights and/or shares as of December 31, 2011.  For Mr. Borgard, Mr. O’Leary, Mr. Schrock and Mr. Mikulsky, see the Proxy Statement under the caption “Executive Compensation — Outstanding Equity Awards Table for 2011.”

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	Options Awards (1)					Stock Awards (2)
Name	Number of securities underlying unexercised options (#) Exercisable	Number of securities underlying unexercised options (#) Unexercisable	Equity incentive plan awards: Number of securities underlying unexercised unearned options (#)	Option exercise price ($)	Option expiration date	Number of shares or units of stock that have not vested (#)	Market value of shares or units of stock that have not vested ($)	Equity incentive plan awards: Number of unearned shares, units or other rights that have not vested (#) (3)	Equity incentive plan awards: Market or payout value of unearned shares, units or other rights that have not vested ($) (3)
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)
Barth J. Wolf	5,156	—	—	48.11	12/08/14	4,244	229,940	9,877	535,136
	6,491	—	—	54.85	12/07/15
	6,783	—	—	52.73	12/07/16
	2,967	—	—	58.65	05/17/17
	11,015	3,671	—	48.36	02/14/18
	7,966	7,965	—	42.12	02/12/19
	4,984	14,950	—	41.58	02/11/20
	—	12,704		49.40	02/10/21

(1) Provided below is the corresponding vesting date relative to each option expiration date:

Grant Date	Full Vesting Date	Expiration Date
12/08/04	12/08/08	12/08/14
12/07/05	12/07/09	12/07/15
12/07/06	12/07/10	12/07/16
05/17/07	05/17/11	05/17/17
02/14/08	02/14/12	02/14/18
02/12/09	02/12/13	02/12/19
02/11/10	02/11/14	02/11/20
02/10/11	02/10/15	02/10/21

(2)	Integrys Energy Group stock price on December 31, 2011, was $54.18.
(3)	The following table reflects the amounts of unvested restricted stock units and corresponding grant dates.  Restricted stock units vest over four years, with 25% of the original grant amount vesting each year on the anniversary of the respective grant date.

Named Executive Officer	02/14/08	02/12/09	02/11/10	02/10/11
Barth J. Wolf	308	762	1,433	1,741

(4) Included in columns (i) and (j) above are the performance shares pertaining to grants made in 2010 and 2011 for the performance periods of 2010-2012 and 2011-2013 and associated payout values, assuming that both grants will pay out at target following completion of each applicable performance period.  Based on total shareholder return (TSR) performance as of December 31, 2011, the grant made in 2010 would pay out at 126% (between target and superior) and the grant made in 2011 would pay out at 0% (below threshold).  The following two tables show projected payouts of the 2010 and 2011 performance share grants assuming TSR performance as of December 31, 2011, as well as projected payouts that would occur assuming superior performance (200%).

2010 Performance Share Grant:

Named Executive Officer	Shares at 126% Payout (#)	Market Value ($)	Shares at 200% Payout	Market Value ($)
Barth J. Wolf	6,822	369,616	10,828	586,661

2011 Performance Share Grant:

Named Executive Officer	Shares at 0% Payout (#)	Market Value ($)	Shares at 200% Payout	Market Value ($)
Barth J. Wolf	—	—	8,926	483,611

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(5) Not included in columns (i) and (j) above are the performance shares pertaining to grants made in 2009 for the performance period of 2009-2011.  Subsequent to December 31, 2011, a payout at 74% will occur on performance shares for the performance period of 2009-2011 based on final TSR results.  The number of earned performance shares attributable as a result of the threshold level being exceeded, along with the corresponding market value of such shares, is as follows:

Named Executive Officer	Earned Shares  (#)	Market  or payout value of earned shares ($)
Barth J. Wolf	2,794	151,379

Option Exercises and Stock Vested Table for 2011

The following table sets forth amounts received by Mr. Wolf upon exercise of options (or similar instruments) or the vesting of stock (or similar instruments) during 2011.  For Mr. Borgard, Mr. O’Leary, Mr. Schrock and Mr. Mikulsky, see the Proxy Statement under the caption “Executive Compensation — Option Exercises and Stock Vested Table for 2011.”

	Option Awards		Stock Awards *
Name	Number of shares acquired on exercise (#)	Value realized on exercise ($)	Number of shares acquired on vesting (#)	Value realized on vesting ($)
(a)	(b)	(c)	(d)	(e)
Barth J. Wolf	—	—	4,944	262,343

* A payout will be made on performance shares in 2012 based on total shareholder return for the performance period ending December 31, 2011, meeting the threshold payout level. These performance shares had a performance period beginning on January 1, 2009, and ending on December 31, 2011.

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Pension Benefits Table for 2011

The following table sets forth the actuarial present value of Mr. Wolf’s accumulated benefit under each defined benefit plan, assuming benefits are paid at normal retirement age based on current levels of compensation.  For Mr. Borgard, Mr. O’Leary, Mr. Schrock and Mr. Mikulsky, see the Proxy Statement under the caption “Executive Compensation — Pension Benefits Table for 2011.”  None of our named executive officers are currently eligible for early retirement other than Mr. O’Leary, Mr. Schrock and Mr. Mikulsky.  No pension benefits were paid to any of the currently employed named executive officers during the year.  Specific details of these benefits are discussed in more detail in the Proxy Statement under the caption “Executive Compensation — Compensation Discussion and Analysis — Key Components of the Executive Compensation Program — Other Benefits and Plans.”

Name	Plan Name (1)	Number of years of credited service (#)(2)	Present value of accumulated benefits ($)(3)	Payments during last fiscal year ($)
(a)	(b)	(c)	(d)	(e)
Barth J. Wolf	Retirement Plan	23	752,490	—
	Restoration Plan	23	520,723	—
	SERP	23	1,053,625	—
	Total	23	2,326,838	—

(1)For a description of the material terms and conditions of the above-named plans, see the Proxy Statement under the caption “Executive Compensation — Compensation Discussion and Analysis — Key Components of the Executive Compensation Program — Other Benefits and Plans.”

(2)Full years of credited service only.  Actual plan benefits are calculated taking into account full and fractional years of credited service.

(3)Change in pension value during 2011 and present value of accumulated benefit at year-end:

Pension Plan

The amount shown is based on the present value of the projected pension plan account balances payable at the plan’s normal retirement age (age 65).  The projected age 65 pension plan account equals the participant’s accrued account balance at year-end rolled forward with interest credits to age 65 using the plan’s interest rate (3.25% at December 31, 2011, and 4.05% at December 31, 2010).  The present value was determined using an interest rate consistent with assumptions used for financial reporting under the Compensation-Retirement Benefits Topic of the FASB ASC (5.10% at December 31, 2011, and 5.80% at December 31, 2010).

Since Mr. Wolf is covered under the Integrys Energy Group Retirement Plan, the value of the temporary supplemental benefit has been added.  The present value was determined assuming current commencement (if currently eligible) or commencement at earliest eligibility (generally age 55) and payment in a single lump sum form, using the plan’s interest rate to calculate the lump sum payment (Pension Protection Act segment lump sum rates at December 31, 2011, and December 31, 2010) and using an interest rate consistent with assumptions used in financial reporting under the Compensation-Retirement Benefits Topic of the FASB ASC to determine the present value at year-end of the lump sum payable.  The benefit was prorated based on current service over service from hire date to date of earliest eligibility.

Pension Restoration Plan

The amount shown is based on the present value of the projected pension plan account balance payable at the plan’s normal retirement age (age 65).  The projected age 65 pension plan account equals the participant’s accrued account balance at year-end rolled forward with interest credits to age 65 using the plan’s interest rate (3.25% at December 31, 2011, and 4.05% at December 31, 2010).  The present value was determined using an interest rate

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consistent with assumptions used for financial reporting under the Compensation-Retirement Benefits Topic of the FASB ASC (5.10% at December 31, 2011, and 5.80% at December 31, 2010).

SERP

The value shown is based on the present value of the accrued benefit at unreduced retirement age (age 62) reflecting final average pay and service as of the calculation date.  The present value was determined assuming commencement at age 62 using an interest rate consistent with assumptions used for financial reporting under the Compensation-Retirement Benefits Topic of the FASB ASC (5.10% at December 31, 2011, and 5.80% at December 31, 2010).

Nonqualified Deferred Compensation Table for 2011

The following table sets forth information regarding the contributions, earnings, and balances for Mr. Wolf relative to the nonqualified deferred compensation plan for 2011.  For Mr. Borgard, Mr. O’Leary, Mr. Schrock and Mr. Mikulsky, see the Proxy Statement under the caption “Executive Compensation — Nonqualified Deferred Compensation Table for 2011.”

Name	Executive Contributions in last fiscal year ($)(1)	Registrant contributions in last fiscal year ($)(1)	Aggregate earnings in last fiscal year ($)(2)	Aggregate withdrawals/ distributions ($)	Aggregate balance at last fiscal year end ($)(3)
(a)	(b)	(c)	(d)	(e)	(f)
Barth J. Wolf	14,375	—	106,269	—	1,019,277

(1)Deferrals into the Deferred Compensation Plan were made from compensation earned in 2011 and are reported in column (c) of the Summary Compensation Table for 2011, with the exception of annual incentive and performance share amounts earned in 2010, but paid out and deferred in 2011.  These amounts are as follows:

Name	Annual Incentive Payout	Performance Share Payout
Barth J. Wolf	—	—

(2)Above-market earnings received on Reserve Accounts A and B are reported in column (h) of the Summary Compensation Table for 2011.

(3)The aggregate balance includes amounts shown in footnote (1) and the above-market earnings on Reserve Accounts A and B, which are included in column (h) of the Summary Compensation Table for 2011.

The following table sets forth the actual earnings during 2011 of each deferred compensation account held by Mr. Wolf.  For Mr. Borgard, Mr. O’Leary, Mr. Schrock and Mr. Mikulsky, see the Proxy Statement under the caption “Executive Compensation — Nonqualified Deferred Compensation Table for 2011.”

Name	Aggregate earnings for Reserve A in last fiscal year ($)	Aggregate earnings for Reserve B in last fiscal year ($)	Aggregate earnings for Mutual Funds in last fiscal year ($)	Aggregate earnings for company stock in last fiscal year ($)	Aggregate earnings in last fiscal year ($)
Barth J. Wolf	—	16,348	2,766	87,155	106,269

For further details regarding the deferred compensation accounts, including rates of return, see the Proxy Statement under the caption “Executive Compensation — Compensation Discussion and Analysis — Key Components of the Executive Compensation Program — Other Benefits and Plans.”  Upon retirement

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or termination of employment, distribution of our named executive officer’s account will commence in January of the year that is both (1) following the calendar year of termination of employment and (2) at least six months following termination or later if a later date is selected by our named executive officer.  Our named executive officer can elect a distribution period from 1 to 15 years.  Payouts, withdrawals or other distributions cannot commence under the plan while our named executive officer is actively employed by us.

Termination of Employment

Provided below are estimated aggregate compensation and benefits that may be payable to Mr. Wolf in the event of termination of employment.  These estimates assume that termination occurred on the last business day of the last fiscal year (December 31, 2011).  For Mr. Borgard, Mr. O’Leary, Mr. Schrock and Mr. Mikulsky, see the Proxy Statement under the caption “Executive Compensation — Termination of Employment.”

Type of Termination	Barth J. Wolf
Retirement (1)	N/A
Change In Control (CIC)	$	6,024,474

(1)Termination for reasons that are voluntary/involuntary/for cause, including death/disability would be treated the same as retirement.  Mr. Wolf was not eligible for retirement as of December 31, 2011.  Included in the value shown is the present value of future retirement benefit payments.  Under the Pension Restoration Plan and the Supplemental Retirement Plan, certain participants will be paid a monthly benefit (for a fixed number of payments or a lifetime annuity).  The present value of future monthly benefit payments was determined using an interest rate and mortality table consistent with assumptions used for financial reporting under the Compensation-Retirement Benefits Topic of the FASB ASC.  Also included in the total is the enhanced value for any outstanding equity grants.

Our named executives have been provided with an agreement such that, in the event of a termination following a change in control, a termination payment may be provided.  For further details regarding the nature of these agreements, see the Proxy Statement under the caption “Executive Compensation — Termination of Employment.”

No change in control triggering event occurred in 2011 that affected our named executive officers.  The Change in Control estimate above provides the approximate cash severance amount, the present value of enhanced pension, health and welfare and outplacement benefits, the amount due for interrupted performance cycles, and the intrinsic value of stock-based awards.

Director Compensation

At December 31, 2011, the seven directors consisted entirely of employees of Integrys Energy Group or its subsidiaries.  The directors are Lawrence T. Borgard, Chairman; William D. Laakso; Phillip M. Mikulsky; Joseph P. O’Leary; Mark A. Radtke; James F. Schott and Charles A. Schrock.  None of these directors receive compensation for serving in the role of a director for us.  Each director is compensated in his role as an employee of Integrys Energy Group or a subsidiary of Integrys Energy Group.  For the compensation paid to Mr. Borgard, Mr. Mikulsky, Mr. O’Leary, Mr. Radtke and Mr. Schrock see the Proxy Statement under the caption “Executive Compensation — Summary Compensation Table for 2011.”  The remaining directors as of December 31, 2011, were paid the following total compensation (calculated in a similar fashion to how total compensation in column (j) of the Summary

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Compensation Table for 2011 is calculated) by Integrys Energy Group for the year ended December 31, 2011:  William D. Laakso $591,615 and James F. Schott $591,894.

Compensation Committee Report

For the Committee’s report, see the Proxy Statement under the caption “Executive Compensation — Compensation Committee Report.”

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ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Ownership of Voting Securities

All of our common stock is held by our parent, Integrys Energy Group.

The following table indicates the shares of Integrys Energy Group’s common stock and stock options beneficially owned by our directors and executive officers as of February 1, 2012.  None of the persons listed beneficially owns shares of any other class of our or Integrys Energy Group’s equity securities.

	Amount and Nature of Shares Beneficially Owned
Name and Title	Aggregate Number of Shares Beneficially Owned (1)		Number of Shares Subject to Stock Options	Percent of Shares
Charles A. Schrock Director	288,623		226,838	(2	)
Lawrence T. Borgard Chairman and Chief Executive Officer and Director	132,549		103,414	(2	)
Charles A. Cloninger President and Director	25,977		19,463	(2	)
Phillip M. Mikulsky Director	209,312		167,620	(2	)
Mark A. Radke Director	195,625		158,759	(2	)
Joseph P. O’Leary Senior Vice President, Chief Financial Officer and Director	276,080		228,394	(2	)
Diane L. Ford Vice President and Corporate Controller	85,684		64,224	(2	)
William J. Guc Treasurer	6,983		949	(2	)
William D. Laakso Director	20,289		14,175	(2	)
James F. Schott Vice President — External Affairs and Director	39,709	(3)	33,043	(2	)
Barth J. Wolf Secretary	77,435		61,176	(2	)
All 11 directors and executive officers as a group	1,358,266		1,078,055	1.7	%

(1)Includes shares and share equivalents of common stock held in the Integrys Energy Group Employee Stock Ownership Plan and the Integrys Energy Group, LLC Deferred Compensation Trust, as well as stock options exercisable within 60 days of February 1, 2012, restricted stock units vested within 60 days of February 1, 2012, and performance shares paid out within 60 days of February 1, 2012.  Each director or officer has sole voting and investment power with respect to the shares reported, unless otherwise noted.  No voting or investment power exists related to the stock options reported until exercised.

(2)Less than 1% of Integrys Energy Group’s outstanding shares of common stock as of February 1, 2012.

(3)524 of reported shares are owned in the spouse’s name only.

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Equity Compensation Plan Information

Information required by this Item regarding equity compensation plans of Integrys Energy Group can be found in Integrys Energy Group’s Proxy Statement, under the caption “Ownership of Voting Securities — Equity Compensation Plan Information.”  Such information is incorporated by reference as if fully set forth herein.

ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Our directors are also employees of WPS, our parent company, or our sister companies.

Our directors and executive officers who are also executive officers of Integrys Energy Group are subject to Integrys Energy Group’s policy regarding related person transactions.  Information required by this Item regarding such related person transactions can be found in Integrys Energy Group’s Proxy Statement under the caption “Election of Directors — Related Person Transaction Policy.”  Such information is incorporated by reference as if fully set forth herein.

ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES

The following is a summary of the fees for professional services provided to us by Deloitte & Touche LLP in 2011 and 2010:

Fees	2011		2010
Audit Fees (a)	$	749,013	$	722,438
Audit Related Fees (b)	12,600		—
Tax Fees (c)	—		305,791
All Other Fees (d)	—		891
Total Fees	$	761,613	$	1,029,120

(a)Audit Fees. Consists of aggregate fees for the audits of the annual consolidated financial statements and reviews of the interim condensed consolidated financial statements included in quarterly reports.  Audit fees also include services that are normally provided by Deloitte & Touche in connection with statutory and regulatory filings or engagements, including comfort letters, consents and other services related to SEC matters, and consultations arising during the course of the audits and reviews concerning financial accounting and reporting standards.

(b)Audit Related Fees. Consists of fees billed for assurance and related services that are reasonably related to the performance of the audit or review of the consolidated financial statements or internal control over financial reporting and are not reported under “Audit Fees.”

(c)Tax Fees. Consists of fees billed for professional services rendered for tax compliance.

(d)All Other Fees. Consists of other fees for services provided to us by Deloitte & Touche LLP for products and services other than the services reported above.  All Other Fees are for software licensing and training provided in 2010.  The nature of the software license fees, which include support, learning services, and training, has been deemed permissible non-attest services.

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In considering the nature of the services provided by the independent registered public accounting firm, the Audit Committee of the Board of Directors of Integrys Energy Group (Audit Committee) determined that such services are compatible with the provision of independent audit services.  The Audit Committee discussed these services with the independent registered public accounting firm and Integrys Energy Group’s management and determined that they are permitted under the rules and regulations concerning auditor independence promulgated by the SEC to implement the Sarbanes-Oxley Act of 2002, as well as those of the American Institute of Certified Public Accountants.  The Audit Committee has approved in advance 100% of the audit services described above in accordance with its pre-approval policy.

For information on the Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Registered Public Accounting Firm, see the discussion in the Proxy Statement, under the caption “Principal Fees and Services Paid to Independent Registered Public Accounting Firm.”

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PART IV

ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Documents filed as part of this report:

(1)	Consolidated Financial Statements included in Part II at Item 8 above:
	Description	Pages in 10-K
	Consolidated Statements of Income for the three years ended December 31, 2011, 2010, and 2009	46
	Consolidated Balance Sheets as of December 31, 2011 and 2010	47
	Consolidated Statements of Capitalization as of December 31, 2011 and 2010	48
	Consolidated Statements of Common Shareholder’s Equity for the three years ended December 31, 2011, 2010, and 2009	49
	Consolidated Statements of Cash Flows for the three years ended December 31, 2011, 2010, and 2009	50
	Notes to Consolidated Financial Statements	51
	Report of Independent Registered Public Accounting Firm	96
(2)	Financial Statement Schedule. The following financial statement schedule is included in Part IV of this report. Schedules not included herein have been omitted because they are not applicable or the required information is shown in the financial statements or notes thereto.
	Description	Pages in 10-K
	Schedule II — WPS Valuation and Qualifying Accounts	120
(3)	List of all exhibits, including those incorporated by reference. See Exhibit Index.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on this 28th day of February, 2012.

WISCONSIN PUBLIC SERVICE CORPORATION
	(Registrant)
By:	/s/ Lawrence T. Borgard
	Lawrence T. Borgard Chairman and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature		Title	Date
Charles A. Cloninger*		Director
William D. Laakso *		Director
Phillip M. Mikulsky *		Director
Mark A. Radtke *		Director
James F. Schott *		Director
Charles A. Schrock *		Director
/s/ Lawrence T. Borgard		Chairman, Chief Executive Officer and Director (principal executive officer)	February 28, 2012
Lawrence T. Borgard
/s/ Joseph P. O’Leary		Senior Vice President, Chief Financial Officer and Director (principal financial officer)	February 28, 2012
Joseph P. O’Leary
/s/ Diane L. Ford		Vice President and Corporate Controller (principal accounting officer)	February 28, 2012
Diane L. Ford
* By:	/s/ Diane L. Ford
	Diane L. Ford	Attorney-in-Fact	February 28, 2012

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SCHEDULE II

WISCONSIN PUBLIC SERVICE CORPORATION

VALUATION AND QUALIFYING ACCOUNTS

Allowance for Doubtful Accounts

Years Ended December 31, 2011, 2010, and 2009

(In Millions)

	Balance at		Charged to				Balance at
Fiscal Year	Beginning of Year		Expense (1)		Deductions (2)		End of Year
2009	$	4.8	$	11.7	$	11.5	$	5.0
2010	$	5.0	$	7.3	$	9.2	$	3.1
2011	$	3.1	$	7.5	$	7.6	$	3.0

(1) Net of recoveries.

(2) Represents amounts written off to the reserve, net of adjustments to regulatory assets.

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EXHIBIT INDEX

Set forth below is a listing of all exhibits to this Annual Report on Form 10-K, including those incorporated by reference.

Certain other instruments, which would otherwise be required to be listed below, have not been so listed as such instruments do not authorize long-term securities in an amount that exceeds 10% of the total assets of us and our subsidiary on a consolidated basis.  We agree to furnish a copy of any such instrument to the SEC upon request.  Integrys Energy Group, Inc.’s SEC File No. is 1-11337.

Exhibit Number	Description of Documents
2.1*	Asset Contribution Agreement between ATC and Wisconsin Electric Power Company, Wisconsin Power and Light Company, WPS, Madison Gas & Electric Co., Edison Sault Electric Company, South Beloit Water, Gas and Electric Company, dated as of December 15, 2000.  (Incorporated by reference to Exhibit 2A-3 to Integrys Energy Group’s and WPS’s Form 10-K for the year ended December 31, 2000.)
3.1	Articles of Incorporation of WPS as effective May 26, 1972, and amended through May 31, 1988 (Incorporated by reference to Exhibit 3A to Form 10-K for the year ended December 31, 1991); Articles of Amendment to Articles of Incorporation dated June 9, 1993. (Incorporated by reference to Exhibit 3 to Form 8-K filed June 10, 1993.)
3.2	By-Laws of WPS, as amended through March 16, 2009.  (Incorporated by reference to Exhibit 3.2 to WPS’s Form 8-K filed March 19, 2009.)
4.1	First Mortgage and Deed of Trust, dated as of January 1, 1941, from WPS to U.S. Bank National Association (successor to First Wisconsin Trust Company), Trustee (Incorporated by reference to Exhibit 7.01 - File No. 2-7229); Supplemental Indenture, dated as of November 1, 1947 (Incorporated by reference to Exhibit 7.02 - File No.  2-7602); Supplemental Indenture, dated as of November 1, 1950 (Incorporated by reference to Exhibit 4.04 - File No.  2-10174); Supplemental Indenture, dated as of May 1, 1953 (Incorporated by reference to Exhibit 4.03 - File No. 2-10716); Supplemental Indenture, dated as of October 1, 1954 (Incorporated by reference to Exhibit 4.03 - File No. 2-13572); Supplemental Indenture, dated as of December 1, 1957 (Incorporated by reference to Exhibit 4.03 - File No. 2-14527); Supplemental Indenture, dated as of October 1, 1963 (Incorporated by reference to Exhibit 2.02B - File No. 2-65710); Supplemental Indenture, dated as of June 1, 1964 (Incorporated by reference to Exhibit 2.02B - File No. 2-65710); Supplemental Indenture, dated as of November 1, 1967 (Incorporated by reference to Exhibit 2.02B - File No. 2-65710); Supplemental Indenture, dated as of April 1, 1969 (Incorporated by reference to Exhibit 2.02B - File No. 2-65710); Fifteenth Supplemental Indenture, dated as of May 1, 1971 (Incorporated by reference to Exhibit 2.02B - File No. 2-65710); Sixteenth Supplemental Indenture, dated as of August 1, 1973 (Incorporated by reference to Exhibit 2.02B - File No. 2-65710); Seventeenth Supplemental Indenture, dated as of September 1, 1973 (Incorporated by reference to Exhibit 2.02B - File No. 2-65710); Eighteenth Supplemental Indenture, dated as of October 1, 1975 (Incorporated by reference to Exhibit 2.02B - File No. 2-65710); Nineteenth Supplemental Indenture,

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dated as of February 1, 1977 (Incorporated by reference to Exhibit 2.02B - File No. 2-65710); Twentieth Supplemental Indenture, dated as of July 15, 1980 (Incorporated by reference to Exhibit 4B to Form 10-K for the year ended December 31, 1980); Twenty-First Supplemental Indenture, dated as of December 1, 1980 (Incorporated by reference to Exhibit 4B to Form 10-K for the year ended December 31, 1980); Twenty-Second Supplemental Indenture dated as of April 1, 1981 (Incorporated by reference to Exhibit 4B to Form 10-K for the year ended December 31, 1981); Twenty-Third Supplemental Indenture, dated as of February 1, 1984 (Incorporated by reference to Exhibit 4B to Form 10-K for the year ended December 31, 1983); Twenty-Fourth Supplemental Indenture, dated as of March 15, 1984 (Incorporated by reference to Exhibit 1 to Form 10-Q for the quarter ended June 30, 1984); Twenty-Fifth Supplemental Indenture, dated as of October 1, 1985 (Incorporated by reference to Exhibit 1 to Form 10-Q for the quarter ended September 30, 1985); Twenty-Sixth Supplemental Indenture, dated as of December 1, 1987 (Incorporated by reference to Exhibit 4A-1 to Form 10-K for the year ended December 31, 1987); Twenty-Seventh Supplemental Indenture, dated as of September 1, 1991 (Incorporated by reference to Exhibit 4 to Form 8-K filed September 18, 1991); Twenty-Eighth Supplemental Indenture, dated as of July 1, 1992 (Incorporated by reference to Exhibit 4B - File No. 33-51428); Twenty-Ninth Supplemental Indenture, dated as of October 1, 1992 (Incorporated by reference to Exhibit 4 to Form 8-K filed October 22, 1992); Thirtieth Supplemental Indenture, dated as of February 1, 1993 (Incorporated by reference to Exhibit 4 to Form 8-K filed January 27, 1993); Thirty-First Supplemental Indenture, dated as of July 1, 1993 (Incorporated by reference to Exhibit 4 to Form 8-K filed July 7, 1993); Thirty-Second Supplemental Indenture, dated as of November 1, 1993 (Incorporated by reference to Exhibit 4 to Form 10-Q for the quarter ended September 30, 1993); Thirty-Third Supplemental Indenture, dated as of December 1, 1998 (Incorporated by reference to Exhibit 4D to Form 8-K filed December 18, 1998); Thirty-Fourth Supplemental Indenture, dated as of August 1, 2001 (Incorporated by reference to Exhibit 4D to Form 8-K filed August 24, 2001); Thirty-Fifth Supplemental Indenture, dated as of December 1, 2002 (Incorporated by reference to Exhibit 4D to Form 8-K filed December 16, 2002); Thirty-Sixth Supplemental Indenture, dated as of December 8, 2003 (Incorporated by reference to Exhibit 4.2 to Form 8-K filed December 9, 2003); Thirty-Seventh Supplemental Indenture, dated as of December 1, 2006 (Incorporated by reference to Exhibit 4.2 to Form 8-K filed November 30, 2006); Thirty-Eighth Supplemental Indenture, dated as of August 1, 2006 (Incorporated by reference to Exhibit 4.1 to Form 10-K for the year ended December 31, 2006); Thirty-Ninth Supplemental Indenture, dated as of November 1, 2007 (Incorporated by reference to Exhibit 4.2 to Form 8-K filed November 16, 2007); Fortieth Supplemental Indenture, dated as of December 1, 2008 (Incorporated by reference to Exhibit 4.2 to Form 8-K filed December 4, 2008); Forty-First Supplemental Indenture, dated as of December 18, 2008 (Incorporated by reference to Exhibit 4.1 to Form 10-Q filed May 6, 2010); and 42nd Supplemental Indenture, dated as of April 25, 2010 (Incorporated by reference to Exhibit 4.2 to Form 10-Q filed May 6, 2010).  All references to periodic reports are to those of WPS.

4.2

Indenture, dated as of December 1, 1998, between WPS and U.S. Bank National Association (successor to Firstar Bank Milwaukee, N.A., National Association) (Incorporated by reference to Exhibit 4A to Form 8-K filed December 18, 1998); First Supplemental Indenture, dated as of December 1, 1998, between WPS and Firstar Bank Milwaukee, N.A., National Association (Incorporated by reference to Exhibit 4C to Form 8-K filed December 18, 1998);

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	Second Supplemental Indenture, dated as of August 1, 2001, between WPS and Firstar Bank, National Association (Incorporated by reference to Exhibit 4C of Form 8-K filed August 24, 2001); Third Supplemental Indenture, dated as of December 1, 2002, between WPS and U.S. Bank National Association (Incorporated by reference to Exhibit 4C of Form 8-K filed December 16, 2002); Fourth Supplemental Indenture, dated as of December 8, 2003, by and between WPS and U.S. Bank National Association (successor to Firstar Bank, National Association and Firstar Bank Milwaukee, N.A., National Association)  (Incorporated by reference to Exhibit 4.1 to Form 8-K filed December 9, 2003); Fifth Supplemental Indenture, dated as of December 1, 2006, by and between WPS and U.S. Bank National Association (successor to Firstar Bank, National Association and Firstar Bank Milwaukee, N.A., National Association)  (Incorporated by reference to Exhibit 4.1 to Form 8-K filed November 30, 2006); Sixth Supplemental Indenture, dated as of December 1, 2006, by and between WPS and U.S. Bank National Association (successor to Firstar Bank, National Association and Firstar Bank Milwaukee, N.A., National Association) (Incorporated by reference to Exhibit 4.2 to Form 10-K for the year ended December 31, 2006); Seventh Supplemental Indenture, dated as of November 1, 2007, by and between WPS and U.S. Bank National Association (successor to Firstar Bank, National Association and Firstar Bank Milwaukee, N.A., National Association) (Incorporated by reference to Exhibit 4.1 to Form 8-K filed November 16, 2007); and Eighth Supplemental Indenture, dated as of December 1, 2008, by and between WPS and U.S. Bank National Association (successor to Firstar Bank, National Association and Firstar Bank Milwaukee, N.A., National Association) (Incorporated by reference to Exhibit 4.1 to Form 8-K filed December 4, 2008).  References to periodic reports are to those of WPS.
10.1	Joint Power Supply Agreement among WPS, Wisconsin Power and Light Company, and Madison Gas and Electric Company, dated February 2, 1967.  (Incorporated by reference to Exhibit 4.09 in File No. 2-27308.)
10.2*	Joint Power Supply Agreement among WPS, Wisconsin Power and Light Company, and Madison Gas and Electric Company dated July 26, 1973.  (Incorporated by reference to Exhibit 5.04A in File No. 2-48781.)
10.3* #	Joint Plant Agreement by and between WPS and Dairyland Power Cooperative, dated as of November 23, 2004.  (Incorporated by reference to Exhibit 10.19 to Integrys Energy Group’s and WPS’s Form 10-K for the year ended December 31, 2004.)
10.4	Basic Generating Agreement, Unit 4, Edgewater Generating Station, dated June 5, 1967, between Wisconsin Power and Light Company and WPS.  (Incorporated by reference to Exhibit 4.10 in File No. 2-27308.)
10.5	Agreement for Construction and Operation of Edgewater 5 Generating Unit, dated February 24, 1983, between Wisconsin Power and Light Company, Wisconsin Electric Power Company, and WPS.  (Incorporated by reference to Exhibit 10C-1 to WPS’s Form 10-K for the year ended December 31, 1983.)
10.6	Amendment No. 1 to Agreement for Construction and Operation of Edgewater 5 Generating Unit, dated December 1, 1988.  (Incorporated by reference to Exhibit 10C-2 to WPS’s Form 10-K for the year ended December 31, 1988.)

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10.7	Revised Agreement for Construction and Operation of Columbia Generating Plant among WPS, Wisconsin Power and Light Company, and Madison Gas and Electric Company, dated July 26, 1973.  (Incorporated by reference to Exhibit 5.07 in File No. 2-48781.)
10.8+	Form of Key Executive Employment and Severance Agreement entered into between Integrys Energy Group and Phillip M. Mikulsky.  (Incorporated by reference to Exhibit 10.1 to Integrys Energy Group’s Form 10-K for the year ended December 31, 2008.)
10.9+	Form of Key Executive Employment and Severance Agreement entered into between Integrys Energy Group and each of the following:  Charles A. Schrock, Joseph P. O’Leary, Lawrence T. Borgard, Diane L. Ford, and Barth J. Wolf.  (Incorporated by reference to Exhibit 10.1 to Integrys Energy Group’s Form 8-K filed May 12, 2010.)
10.10+	Integrys Energy Group Executive Change in Control Severance Plan applicable to the following: William D. Laakso and James F. Schott.  (Incorporated by reference to Exhibit 10.3 to Integrys Energy Group’s Form 10-K for the year ended December 31, 2010.)
10.11+	Form of Integrys Energy Group 2005 Omnibus Incentive Compensation Plan Performance NonQualified Stock Option Agreement approved December 7, 2005.  (Incorporated by reference to Exhibit 10.1 to Integrys Energy Group’s and WPS’s Form 8-K filed December 13, 2005.)
10.12+	Form of Integrys Energy Group 2005 Omnibus Incentive Compensation Plan Performance NonQualified Stock Option Agreement approved December 7, 2006.  (Incorporated by reference to Exhibit 10.2 to Integrys Energy Group’s and WPS’s Form 8-K filed December 13, 2006.)
10.13+	Form of Integrys Energy Group 2007 Omnibus Incentive Compensation Plan Restricted Stock Award Agreement approved May 17, 2007.  (Incorporated by reference to Exhibit 10.8 to Integrys Energy Group’s Form 10-K for the year ended December 31, 2007.)
10.14+	Form of Integrys Energy Group 2007 Omnibus Incentive Compensation Plan NonQualified Stock Option Agreement approved May 17, 2007.  (Incorporated by reference to Exhibit 10.10 to Integrys Energy Group’s Form 10-K for the year ended December 31, 2007.)
10.15+	Form of Integrys Energy Group 2007 Omnibus Incentive Compensation Plan Performance Stock Right Agreement approved February 14, 2008.  (Incorporated by reference to Exhibit 10.6 to Integrys Energy Group’s Form 10-K for the year ended December 31, 2007.)
10.16+	Form of Integrys Energy Group 2007 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement approved February 14, 2008.  (Incorporated by reference to Exhibit 10.9 to Integrys Energy Group’s Form 10-K for the year ended December 31, 2007.)
10.17+	Form of Integrys Energy Group 2007 Omnibus Incentive Compensation Plan NonQualified Stock Option Agreement approved February 14, 2008.  (Incorporated by reference to Exhibit 10.11 to Integrys Energy Group’s Form 10-K for the year ended December 31, 2007.)

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10.18+	Form of Integrys Energy Group, Inc. 2010 Omnibus Incentive Compensation Plan Performance Stock Right Agreement approved September 16, 2010.  (Incorporated by reference to Exhibit 10.3 to Integrys Energy Group’s Form 8-K filed September 22, 2010.)
10.19+	Form of Integrys Energy Group, Inc. 2010 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement approved September 16, 2010.  (Incorporated by reference to Exhibit 10.4 to Integrys Energy Group’s Form 8-K filed September 22, 2010.)
10.20+	Form of Integrys Energy Group, Inc. 2010 Omnibus Incentive Compensation Plan Nonqualified Stock Option Agreement approved September 16, 2010.  (Incorporated by reference to Exhibit 10.5 to Integrys Energy Group’s Form 8-K filed September 22, 2010.)
10.21+	Form of Integrys Energy Group, Inc. 2010 Omnibus Incentive Compensation Plan Performance Stock Right Agreement approved February 9, 2012.  (Incorporated by reference to Exhibit 10.14 to Integrys Energy Group’s Form 10-K for the year ended December 31, 2011.)
10.22+	Form of Integrys Energy Group, Inc. 2010 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement approved February 9, 2012.  (Incorporated by reference to Exhibit 10.15 to Integrys Energy Group’s Form 10-K for the year ended December 31, 2011.)
10.23+	Form of Integrys Energy Group, Inc. 2010 Omnibus Incentive Compensation Plan Nonqualified Stock Option Agreement approved February 9, 2012.  (Incorporated by reference to Exhibit 10.16 to Integrys Energy Group’s Form 10-K for the year ended December 31, 2011.)
10.24+	Integrys Energy Group, Inc. Deferred Compensation Plan, as Amended and Restated Effective January 1, 2012.  (Incorporated by reference to Exhibit 10.17 to Integrys Energy Group’s Form 10-K for the year ended December 31, 2011.)
10.25+	Integrys Energy Group, Inc. Pension Restoration and Supplemental Retirement Plan, as Amended and Restated Effective January 1, 2011.  (Incorporated by reference to Exhibit 10.2 to Integrys Energy Group’s Form 8-K filed September 22, 2010.)
10.26+	Integrys Energy Group 2001 Omnibus Incentive Compensation Plan.  (Incorporated by reference to Exhibit 10.16 to Integrys Energy Group’s and WPS’s Form 10-K for the year ended December 31, 2005, filed February 28, 2006.)
10.27+	Integrys Energy Group, Inc. 2005 Omnibus Incentive Compensation Plan.  (Incorporated by reference to Exhibit 10.2 to Integrys Energy Group’s and WPS’s Form 10-Q filed August 4, 2005.)
10.28+	Integrys Energy Group, Inc. 2007 Omnibus Incentive Compensation Plan.  (Incorporated by reference to Exhibit 10.17 to Integrys Energy Group’s Form 10-K for the year ended December 31, 2007.)
10.29+	Integrys Energy Group 2010 Omnibus Incentive Compensation Plan, as amended.  (Incorporated by reference to Exhibit 10.22 to Integrys Energy Group’s Form 10-K for the

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	year ended December 31, 2011.)
12	WPS Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed Charges and Preferred Dividends.
21	Subsidiaries of WPS.
23	Consent of Independent Registered Public Accounting Firm for WPS.
24	Powers of Attorney.
31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for WPS.
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for WPS.
32	Written Statement of the Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350 for WPS.
99	Proxy Statement for Integrys Energy Group’s 2012 Annual Meeting of Shareholders.  [To be filed with the SEC under Regulation 14A within 120 days after December 31, 2011; except to the extent specifically incorporated by reference, the Proxy Statement for the 2012 Annual Meeting of Shareholders shall not be deemed to be filed with the SEC as part of this Annual Report on Form 10-K.]

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101 ^ Financial statements from the Annual Report on Form 10-K of Wisconsin Public Service Corporation for the year ended December 31, 2011, filed on February 28, 2012, formatted in eXtensible Business Reporting Language (XBRL): (i) the Consolidated Statements of Income; (ii) the Consolidated Balance Sheets; (iii) the Consolidated Statements of Capitalization; (iv) the Consolidated Statements of Common Shareholder’s Equity; (v) the Consolidated Statements of Cash Flows; (vi) the Notes to Consolidated Financial Statements; and (vii) document and entity information.

*	Schedules and exhibits to this document are not filed therewith.  The registrant agrees to furnish supplementally a copy of any such schedule or exhibit to the SEC upon request.
+	A management contract or compensatory plan or arrangement.
#	Portions of this exhibit have been redacted and are subject to a confidential treatment request filed with the Secretary of SEC pursuant to Rule 24b-2 under the Securities and Exchange Act of 1934, as amended.  The redacted material was filed separately with the SEC.
^	In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing.

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