10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2011

Commission	Registrant; State of Incorporation	IRS Employer
File Number	Address; and Telephone Number	Identification No.

001-09057	WISCONSIN ENERGY CORPORATION	39-1391525
	(A Wisconsin Corporation)
	231 West Michigan Street
	P.O. Box 1331
	Milwaukee, WI 53201
	(414) 221-2345

Securities Registered Pursuant to Section 12(b) of the Act:
	Name of Each Exchange
Title of Each Class	on Which Registered
Common Stock, $.01 Par Value	New York Stock Exchange
Securities Registered Pursuant to Section 12(g) of the Act:     None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes [X]    No [  ]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.    Yes [  ]    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 [  ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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 [  ]

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 the 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. (Check one):

Large accelerated filer [X]	Accelerated filer [  ]
Non-accelerated filer [  ] (Do not	Smaller reporting company [  ]
check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes [  ]    No [X]

The aggregate market value of the common stock of Wisconsin Energy Corporation held by non-affiliates was approximately $7.3 billion based upon the reported closing price of such securities as of June 30, 2011.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date (January 31, 2012):

Common Stock, $.01 Par Value, 230,461,537 shares outstanding

Documents Incorporated by Reference

Portions of Wisconsin Energy Corporation's Definitive Proxy Statement on Schedule 14A for its Annual Meeting of Stockholders, to be held on May 3, 2012, are incorporated by reference into Part III hereof.

2011 Form 10-K

WISCONSIN ENERGY CORPORATION

FORM 10-K REPORT FOR THE YEAR ENDED DECEMBER 31, 2011

_______________________________________

TABLE OF CONTENTS
Item	Page
PART I
1.   Business	10
1A. Risk Factors	24
1B. Unresolved Staff Comments	32
2.    Properties	32
3.    Legal Proceedings	34
4.    Mine Safety Disclosures	35
Executive Officers of the Registrant	36

PART II
5.    Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases        of Equity Securities			37
6.    Selected Financial Data			39
7.    Management's Discussion and Analysis of Financial Condition and Results of Operations			40
7A. Quantitative and Qualitative Disclosures About Market Risk			70
8.    Financial Statements and Supplementary Data			71
	Consolidated Income Statements		71
	Consolidated Balance Sheets -- Assets		72
	Consolidated Balance Sheets -- Capitalization and Liabilities		73
	Consolidated Statements of Cash Flows		74
	Consolidated Statements of Common Equity		75
	Consolidated Statements of Capitalization		76
	Notes to Consolidated Financial Statements		77
	Note A	Summary of Significant Accounting Policies	77
	Note B	Recent Accounting Pronouncements	82
	Note C	Regulatory Assets and Liabilities	82
	Note D	Asset Sales, Divestitures and Discontinued Operations	83
	Note E	Accounting and Reporting for Power the Future Generating Units	84
	Note F	Asset Retirement Obligations	84
	Note G	Variable Interest Entities	84
	Note H	Income Taxes	85
	Note I	Common Equity	87
	Note J	Long-Term Debt and Capital Lease Obligations	91
	Note K	Short-Term Debt	93
	Note L	Derivative Instruments	93
	Note M	Fair Value Measurements	94
	Note N	Benefits	97

3 Wisconsin Energy Corporation

2011 Form 10-K

TABLE OF CONTENTS - (Cont'd)
Item			Page
	Note O	Guarantees	102
	Note P	Segment Reporting	102
	Note Q	Related Parties	103
	Note R	Commitments and Contingencies	104
	Note S	Supplemental Cash Flow Information	106
	Reports of Independent Registered Public Accounting Firm		107
9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			109
9A.  Controls and Procedures			109
9B.  Other Information			109
PART III
10.  Directors, Executive Officers and Corporate Governance of the Registrant			110
11.  Executive Compensation			110
12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder        Matters			110
13.  Certain Relationships and Related Transactions, and Director Independence			111
14.  Principal Accountant Fees and Services			111
PART IV
15.  Exhibits and Financial Statement Schedules			112
Schedule I - Condensed Parent Company Financial Statements			113
Schedule II - Valuation and Qualifying Accounts			119
Signatures			120
Exhibit Index			E-1

4 Wisconsin Energy Corporation

2011 Form 10-K

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS
The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:
Primary Subsidiaries
We Power	W.E. Power, LLC
Wisconsin Electric	Wisconsin Electric Power Company
Wisconsin Gas	Wisconsin Gas LLC
Significant Assets
OC 1	Oak Creek expansion Unit 1
OC 2	Oak Creek expansion Unit 2
PWGS	Port Washington Generating Station
PWGS 1	Port Washington Generating Station Unit 1
PWGS 2	Port Washington Generating Station Unit 2
VAPP	Valley Power Plant
Other Subsidiaries and Affiliates
ATC	American Transmission Company LLC
ERGSS	Elm Road Generating Station Supercritical, LLC
ERS	Elm Road Services, LLC
Minergy	Minergy LLC
WECC	Wisconsin Energy Capital Corporation
Wispark	Wispark LLC
Wisvest	Wisvest LLC
Federal and State Regulatory Agencies
DOE	United States Department of Energy
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
IRS	Internal Revenue Service
MPSC	Michigan Public Service Commission
PSCW	Public Service Commission of Wisconsin
SEC	Securities and Exchange Commission
WDNR	Wisconsin Department of Natural Resources
Environmental Terms
Act 141	2005 Wisconsin Act 141
BART	Best Available Retrofit Technology
BTA	Best Technology Available
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAVR	Clean Air Visibility Rule
CO2	Carbon Dioxide
CSAPR	Cross-State Air Pollution Rule
FIP	Federal Implementation Plan
MACT	Maximum Achievable Control Technology
MATS	Mercury and Air Toxics Standards
NODA	Notice of Data Availability

5 Wisconsin Energy Corporation

2011 Form 10-K

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS
The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:
NOV	Notice of Violation
NOx	Nitrogen Oxide
PM2.5	Fine Particulate Matter
SIP	State Implementation Plan
SO2	Sulfur Dioxide
Other Terms and Abbreviations
AQCS	Air Quality Control System
ARRs	Auction Revenue Rights
Bechtel	Bechtel Power Corporation
Compensation Committee	Compensation Committee of the Board of Directors
CPCN	Certificate of Public Convenience and Necessity
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act
Edison Sault	Edison Sault Electric Company
ERISA	Employee Retirement Income Security Act of 1974
Exchange Act	Securities Exchange Act of 1934, as amended
Fitch	Fitch Ratings
FTRs	Financial Transmission Rights
GCRM	Gas Cost Recovery Mechanism
GDP	Gross Domestic Product
Junior Notes	Wisconsin Energy's 2007 Series A Junior Subordinated Notes due 2067 issued in May 2007
LLC	Limited Liability Company
LMP	Locational Marginal Price
MISO	Midwest Independent Transmission System Operator, Inc.
MISO Energy Markets	MISO Energy and Operating Reserves Market
Moody's	Moody's Investor Service
NYMEX	New York Mercantile Exchange
OTC	Over-the-Counter
Plan	The Wisconsin Energy Corporation Retirement Account Plan
Point Beach	Point Beach Nuclear Power Plant
PTF	Power the Future
PUHCA 2005	Public Utility Holding Company Act of 2005
RCC	Replacement Capital Covenant dated May 11, 2007
RSG	Revenue Sufficiency Guarantee
RTO	Regional Transmission Organization
Settlement Agreement	Settlement Agreement and Release between ERS and Bechtel effective as of December 16, 2009
S&P	Standard & Poor's Ratings Services
WPL	Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corp.
Measurements
Btu	British Thermal Unit(s)
Dth	Dekatherm(s) (One Dth equals one million Btu)
kW	Kilowatt(s) (One kW equals one thousand Watts)

6 Wisconsin Energy Corporation

2011 Form 10-K

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS
The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:
kWh	Kilowatt-hour(s)
MW	Megawatt(s) (One MW equals one million Watts)
MWh	Megawatt-hour(s)
Watt	A measure of power production or usage
Accounting Terms
AFUDC	Allowance for Funds Used During Construction
ARO	Asset Retirement Obligation
CWIP	Construction Work in Progress
FASB	Financial Accounting Standards Board
GAAP	Generally Accepted Accounting Principles
IFRS	International Financial Reporting Standards
OPEB	Other Post-Retirement Employee Benefits

7 Wisconsin Energy Corporation

2011 Form 10-K

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Certain statements contained in this report are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (Exchange Act). These statements are based upon management's current expectations and are subject to risks and uncertainties that could cause our actual results to differ materially from those contemplated in the statements. Readers are cautioned not to place undue reliance on these forward-looking statements. Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of construction projects, regulatory matters, on-going legal proceedings, fuel costs, sources of electric energy supply, coal and gas deliveries, remediation costs, environmental and other capital expenditures, liquidity and capital resources and other matters. In some cases, forward-looking statements may be identified by reference to a future period or periods or by the use of forward-looking terminology such as "anticipates," "believes," "estimates," "expects," "forecasts," "goals," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects," "seeks," "should," "targets" or similar terms or variations of these terms.

Actual results may differ materially from those set forth in forward-looking statements. In addition to the assumptions and other factors referred to specifically in connection with these statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statements or otherwise affect our future results of operations and financial condition include, among others, the following:

• Factors affecting utility operations such as catastrophic weather-related or terrorism-related damage; cyber-security threats and disruptions to our technology network; availability of electric generating facilities; unscheduled generation outages, or unplanned maintenance or repairs; unanticipated events causing scheduled generation outages to last longer than expected; unanticipated changes in fossil fuel, purchased power, coal supply, gas supply or water supply costs or availability due to higher demand, shortages, transportation problems or other developments; unanticipated changes in the cost or availability of materials needed to operate new environmental controls at our electric generating facilities or replace and/or repair our electric and gas distribution systems; nonperformance by electric energy or natural gas suppliers under existing power purchase or gas supply contracts; environmental incidents; electric transmission or gas pipeline system constraints; unanticipated organizational structure or key personnel changes; collective bargaining agreements with union employees or work stoppages; or inflation rates.

• Factors affecting the demand for electricity and natural gas, including weather and other natural phenomena; the economic climate in our service territories; customer growth and declines; customer business conditions, including demand for their products and services; and energy conservation efforts.

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

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

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

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

8 Wisconsin Energy Corporation

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION - (Cont'd) 2011 Form 10-K

• Restrictions imposed by various financing arrangements and regulatory requirements on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans or advances.

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

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

• Events in the global credit markets that may affect the availability and cost of capital.

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

• The investment performance of our pension and other post-retirement benefit trusts.

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

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

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

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

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

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

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

• The cyclical nature of property values that could affect our real estate investments.

• Changes to the legislative or regulatory restrictions or caps on non-utility acquisitions, investments or projects, including the state of Wisconsin's public utility holding company law.

• Foreign governmental, economic, political and currency risks.

• Other business or investment considerations that may be disclosed from time to time in our Securities and Exchange Commission (SEC) filings or in other publicly disseminated written documents, including the risk factors set forth in Item 1A of this report.

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

9 Wisconsin Energy Corporation

2011 Form 10-K

PART I

ITEM 1. BUSINESS

INTRODUCTION

Wisconsin Energy Corporation was incorporated in the state of Wisconsin in 1981 and became a diversified holding company in 1986. We maintain our principal executive offices in Milwaukee, Wisconsin. Unless qualified by their context when used in this document, the terms Wisconsin Energy, the Company, our, us or we refer to the holding company and all of its subsidiaries.

We conduct our operations primarily in two operating segments: a utility energy segment and a non-utility energy segment. Our primary subsidiaries are Wisconsin Electric Power Company (Wisconsin Electric), Wisconsin Gas LLC (Wisconsin Gas) and W.E. Power, LLC (We Power).

Utility Energy Segment:   Our utility energy segment consists of Wisconsin Electric and Wisconsin Gas, operating together under the trade name of "We Energies." We Energies serves approximately 1,122,500 electric customers in Wisconsin and the Upper Peninsula of Michigan. We Energies serves approximately 1,068,200 gas customers in Wisconsin and approximately 465 steam customers in metropolitan Milwaukee, Wisconsin.

Non-Utility Energy Segment:   Our non-utility energy segment consists primarily of We Power, which owns and leases to Wisconsin Electric generation plants constructed as part of our PTF strategy. All four of the plants constructed as part of PTF have been placed in service. Port Washington Generating Station Unit 1 (PWGS 1) and Port Washington Generating Station Unit 2 (PWGS 2) are being leased to Wisconsin Electric under long-term leases that run for 25 years. Oak Creek expansion Unit 1 (OC 1) and Oak Creek expansion Unit 2 (OC 2) are being leased to Wisconsin Electric under long-term leases that run for 30 years.

For further financial information about our business segments, see Results of Operations in Item 7 and Note P -- Segment Reporting in the Notes to Consolidated Financial Statements in Item 8.

Reclassifications:   On January 20, 2011, our Board of Directors approved a two-for-one stock split of our common stock, which was effected through a stock dividend. New shares were distributed on March 1, 2011 to stockholders of record at the close of business on February 14, 2011. All share and per share information in this report has been restated for all periods presented to reflect this stock split.

Our annual and periodical filings with the SEC are available, free of charge, through our Internet website www.wisconsinenergy.com. These documents are available as soon as reasonably practicable after such materials are filed (or furnished) with the SEC.

UTILITY ENERGY SEGMENT

ELECTRIC UTILITY OPERATIONS

Our electric utility operations consist of the electric operations of Wisconsin Electric. Wisconsin Electric, which is the largest electric utility in the state of Wisconsin, generates and distributes electric energy in a territory that includes southeastern (including the metropolitan Milwaukee area), east central and northern Wisconsin and the Upper Peninsula of Michigan.

Wisconsin Electric participates in the MISO Energy Markets. The competitiveness of our generation offered in the MISO Energy Markets affects how our generating units are dispatched and how we buy and sell power. For further information, see Factors Affecting Results, Liquidity and Capital Resources in Item 7.

Electric Sales

Our electric energy sales to all classes of customers totaled approximately 31.3 million MWh during 2011 and approximately 30.5 million MWh during 2010. We had approximately 1,122,500 electric customers as of December 31, 2011 and 1,120,200 electric customers as of December 31, 2010.

10 Wisconsin Energy Corporation

ITEM 1. BUSINESS - (Cont'd) 2011 Form 10-K

Wisconsin Electric is authorized to provide retail electric service in designated territories in the state of Wisconsin, as established by indeterminate permits, Certificates of Public Convenience and Necessity (CPCNs) or boundary agreements with other utilities, and in certain territories in the state of Michigan pursuant to franchises granted by municipalities. Wisconsin Electric also sells wholesale electric power within the MISO Energy Markets.

Electric Sales Growth:   Our service territory continued to experience growth in 2011 in sustained recovery from the significant economic recession that occurred during late 2008 and 2009. Our normalized 2011 retail electric sales, excluding our two largest customers, two iron ore mines, were approximately 0.4% higher than our normalized 2010 electric sales. As we look toward 2012 and beyond, we presently anticipate that total retail electric kWh sales of our utility energy segment and the associated peak electric demand will grow at annual rates of 0.5% to 1.0% over the next five years. These estimates assume normal weather and exclude the two iron ore mines.

Sales to Large Electric Retail Customers:We provide electric utility service to a diversified base of customers in such industries as mining, paper, foundry, food products and machinery production, as well as to large retail chains.

Our largest retail electric customers are two iron ore mines located in the Upper Peninsula of Michigan. The combined electric energy sales to the two mines accounted for 7.1% and 6.9% of our total electric utility energy sales during 2011 and 2010, respectively. The mines have notified us that they expect production at one of the mines to be reduced in 2012.

Sales to Wholesale Customers:   During 2011, we sold wholesale electric energy to one municipally owned system, two rural cooperatives and two municipal joint action agencies located in the states of Wisconsin and Michigan. Our wholesale electric energy sales were also made to 14 other public utilities and power marketers throughout the region under rates approved by FERC. Wholesale sales accounted for approximately 13.1% of our total electric energy sales and 7.0% of total electric operating revenues during 2011, compared with 10.2% of total electric energy sales and 6.0% of total electric operating revenues during 2010.

Electric System Reliability Matters:   Our electric sales are impacted by seasonal factors and varying weather conditions. We sell more electricity during the summer months because of the residential cooling load. The Public Service Commission of Wisconsin (PSCW) has planning reserve requirements consistent with the MISO calculated planning reserve margin. The Michigan Public Service Commission (MPSC) has not yet established guidelines in this area. In accordance with the MISO calculated planning reserve margin requirements, we had adequate capacity to meet all of our firm electric load obligations during 2011 and expect to have adequate capacity to meet all of our firm obligations during 2012. For additional information, see Factors Affecting Results, Liquidity and Capital Resources in Item 7.

Electric Supply

Our electric supply strategy is to provide our customers with energy from plants using a diverse fuel mix that is expected to maintain a stable, reliable and affordable supply of electricity. We supply a significant amount of electricity to our customers from power plants that we own. We supplement our internally generated power supply with long-term power purchase agreements, including the Point Beach Nuclear Power Plant (Point Beach) power purchase agreement discussed later in this report, and through spot purchases in the MISO Energy Markets.

Our installed capacity by fuel type as of December 31 is shown below:

	Dependable Capability in MW (a)
	2011	2010	2009
Coal (b)	3,880	3,646	3,131
Natural Gas - Combined Cycle	1,090	1,090	1,090
Natural Gas/Oil - Peaking Units (c)	1,150	1,150	1,150
Renewables (d)	118	86	86
Total	6,238	5,972	5,457

(a) Dependable capability is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. The values were established by test and may change slightly from year to year.

11 Wisconsin Energy Corporation

ITEM 1. BUSINESS - (Cont'd) 2011 Form 10-K

(b) The increase in 2011 as compared to 2010 reflects the January 2011 in-service date of OC 2, partially offset by the March 2011 sale of our interest in Edgewater Generating Unit 5. The increase in 2010 as compared to 2009 reflects the February 2010 in-service date of OC 1. Our share of the dependable capability of OC 1 and OC 2 is 528 MW each.

(c) The dual-fueled facilities generally burn oil only if natural gas is not available due to constraints on the natural gas pipeline and/or at the local gas distribution company that delivers gas to the plants.

(d) Includes hydroelectric and wind generation. The increase in 2011 as compared to 2010 reflects the December 2011 in-service date of the Glacier Hills Wind Park. For purposes of measuring dependable capability, the 162 MW Glacier Hills Wind Park has a dependable capability of 32 MW and the 145 MW Blue Sky Green Field wind project has a dependable capability of 29 MW.

The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, 2011, as well as an estimate for 2012:

	Estimate		Actual
	2012		2011		2010		2009
Coal	48.6	%	54.2	%	53.9	%	52.8	%
Wind	2.0	%	1.0	%	1.0	%	1.2	%
Hydroelectric	1.1	%	1.0	%	1.0	%	0.8	%
Natural Gas -Combined Cycle	8.2	%	6.6	%	8.4	%	7.6	%
Natural Gas/Oil-Peaking Units	0.1	%	0.1	%	0.3	%	0.2	%
Net Generation	60.0	%	62.9	%	64.6	%	62.6	%
Purchased Power	40.0	%	37.1	%	35.4	%	37.4	%
Total	100.0	%	100.0	%	100.0	%	100.0	%

Our average fuel and purchased power costs per MWh by fuel type for the years ended December 31 are shown below:

	2011		2010		2009
Coal	$	29.78	$	26.44	$	25.01
Natural Gas - Combined Cycle	$	38.02	$	43.14	$	51.67
Natural Gas/Oil - Peaking Units	$	119.83	$	97.36	$	121.18
Purchased Power	$	42.79	$	43.11	$	42.21

Historically, the fuel costs for coal have been under long-term contracts, which helped with price stability. Coal and associated transportation services have continued to see volatility in pricing due to increased domestic and world-wide demand for coal and the impacts of diesel costs which are incorporated into fuel surcharges on rail transportation.

Natural gas costs have been volatile. We have a PSCW-approved hedging program to help manage our natural gas price risk. This hedging program is generally implemented on a 36-month forward-looking basis. Proceeds related to the natural gas hedging program are reflected in the average costs of natural gas and purchased power shown above.

Coal-Fired Generation

Coal Supply:   We diversify the coal supply for our power plants by purchasing coal from mines in Wyoming, Pennsylvania and Montana, as well as from various other states. During 2012, 100% of our projected coal requirements of 9.7 million tons are under contracts which are not tied to 2012 market pricing fluctuations. At the end of 2011, our coal-fired generation consisted of six operating plants with a dependable capability of approximately 3,880 MW.

12 Wisconsin Energy Corporation

ITEM 1. BUSINESS - (Cont'd) 2011 Form 10-K

The annual tonnage amounts contracted for 2012 through 2014 are as follows:

Year	Annual Tonnage
	(Thousands)
2012	9,868
2013	6,205
2014	3,270

Coal Deliveries:   Approximately 100% of our 2012 coal requirements are expected to be delivered by Wisconsin Electric-owned or leased unit trains. The unit trains will transport coal for the Oak Creek and Pleasant Prairie Power Plants from Wyoming mines, and transport coal for the Oak Creek expansion units from Pennsylvania and West Virginia. Coal from a Montana mine is also transported via rail to Lake Michigan transfer docks and delivered by lake vessel to the Milwaukee harbor for Milwaukee-based power plants. Montana and Wyoming coal for the Presque Isle Power Plant is transported via rail to Superior, Wisconsin, placed in dock storage and reloaded into lake vessels for plant delivery.

Certain of our coal transportation contracts contain fuel cost adjustments that are tied to changes in diesel fuel and crude oil prices. Currently, diesel fuel contracts are not actively traded; therefore, we use financial heating oil contracts to mitigate risk related to diesel fuel prices. We have a PSCW-approved hedging program that allows us to hedge up to 75% of our potential risks related to fuel surcharge exposure. The costs of this program are included in our fuel and purchased power costs.

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

Environmental Matters:   For information regarding emission restrictions, especially as they relate to coal-fired generating facilities, see Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7.

Natural Gas-Fired Generation

Our natural gas-fired generation consists of four operating plants with a dependable capability of approximately 1,983 MW as of December 31, 2011.

We purchase natural gas for these plants on the spot market from gas marketers, utilities and producers and we arrange for transportation of the natural gas to our plants. We have firm and interruptible transportation, balancing and storage agreements intended to support the plants' variable usage.

We have a PSCW-approved hedging program that allows us to hedge up to 65% of our estimated gas usage for electric generation in order to help manage our natural gas price risk. The costs of this program are included in our fuel and purchased power costs.

Oil-Fired Generation

Fuel oil is used for the combustion turbines at the Germantown Power Plant units 1-4, boiler ignition and flame stabilization at the Presque Isle Power Plant, and diesel engines at the Pleasant Prairie Power Plant and Valley Power Plant (VAPP). Our oil-fired generation had a dependable capability of approximately 257 MW as of December 31, 2011. Our natural gas-fired peaking units have the ability to burn oil if natural gas is not available due to delivery constraints. Fuel oil requirements are purchased under agreements with suppliers.

Renewable Generation

Hydroelectric:   Wisconsin Electric's hydroelectric generating system consists of 13 operating plants with a total installed capacity of approximately 88 MW and a dependable capability of approximately 57 MW as of December 31, 2011. Of these 13 plants, 12 plants (86 MW of installed capacity) have long-term licenses from

13 Wisconsin Energy Corporation

ITEM 1. BUSINESS - (Cont'd) 2011 Form 10-K

FERC. The thirteenth plant, with an installed generating capacity of approximately 2 MW, is operated under a permit granted by another agency of the federal government.

Wind:   The Blue Sky Green Field wind farm project, which has 88 turbines with an installed capacity of 145 MW and a dependable capability of 29 MW, commenced commercial operation in May 2008. The Glacier Hills Wind Park, which has 90 turbines with an installed capacity of 162 MW and a dependable capability of 32 MW, commenced commercial operation in December 2011.

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

Power Purchase Commitments

We enter into short and long-term power purchase commitments to meet a portion of our anticipated electric energy supply needs. The following table identifies our power purchase commitments as of December 31, 2011 with unaffiliated parties for the next five years:

Year	MW
2012	1,440
2013	1,269
2014	1,269
2015	1,269
2016	1,269

The above commitments include approximately 1,030 MW per year related to the Point Beach long-term power purchase agreement. Under this agreement, we pay a predetermined price per MWh for energy delivered according to a schedule included in the agreement. The balance of these power purchase commitments are tolling arrangements whereby we are responsible for the procurement, delivery and the cost of natural gas fuel related to specific units identified in the contracts.

Electric Transmission and Energy Markets

American Transmission Company:   ATC is a regional transmission company that owns, maintains, monitors and operates electric transmission systems in Wisconsin, Michigan and Illinois. ATC is expected to provide comparable service to all customers, including Wisconsin Electric, and to support effective competition in energy markets without favoring any market participant. ATC is regulated by FERC for all rate terms and conditions of service and is a transmission-owning member of MISO. MISO maintains operational control of ATC's transmission system, and Wisconsin Electric is a non-transmission owning member and customer of MISO. We owned approximately 26.2% of ATC as of December 31, 2011 and 2010. For additional information, see Note Q -- Related Parties in the Notes to Consolidated Financial Statements.

In April 2011, ATC and Duke Energy announced the creation of a joint venture, Duke-American Transmission Company (DATC), that will build, own and operate new electric transmission infrastructure in North America to address increasing demand for affordable, reliable transmission capacity.

MISO:   In connection with its status as a FERC approved Regional Transmission Organization (RTO), MISO developed bid-based energy markets, which were implemented on April 1, 2005. In January 2009, MISO commenced the Energy and Operating Reserves Markets, which includes the bid-based energy markets and the ancillary services market. For further information on MISO and the MISO Energy Markets, see Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition - Electric Transmission and Energy Markets in Item 7.

14 Wisconsin Energy Corporation

ITEM 1. BUSINESS - (Cont'd) 2011 Form 10-K

Electric Utility Operating Statistics

The following table shows certain electric utility operating statistics for the past five years:

SELECTED CONSOLIDATED ELECTRIC UTILITY OPERATING DATA
Year Ended December 31	2011		2010		2009		2008		2007
Operating Revenues (Millions)
Residential	$	1,159.2	$	1,114.3	$	977.6	$	962.5	$	915.5
Small Commercial/Industrial	1,006.9		922.2		860.3		869.7		840.6
Large Commercial/Industrial	763.7		677.1		599.4		646.3		664.2
Other - Retail	22.9		21.9		21.2		20.8		19.2
Total Retail Revenues	2,952.7		2,735.5		2,458.5		2,499.3		2,439.5
Wholesale - Other	154.0		134.6		116.7		77.7		83.5
Resale - Utilities	69.5		40.4		47.5		37.7		110.7
Other Operating Revenues	35.1		25.8		62.3		45.9		40.9
Total Operating Revenues	$	3,211.3	$	2,936.3	$	2,685.0	$	2,660.6	$	2,674.6
MWh Sales (Thousands)
Residential	8,278.5		8,426.3		7,949.3		8,277.1		8,416.1
Small Commercial/Industrial	8,795.8		8,823.3		8,571.6		9,023.7		9,185.4
Large Commercial/Industrial	9,992.2		9,961.5		9,140.3		10,691.7		11,036.7
Other - Retail	153.6		155.3		156.5		161.5		162.4
Total Retail Sales	27,220.1		27,366.4		25,817.7		28,154.0		28,800.6
Wholesale - Other	2,024.8		2,004.6		1,529.4		2,620.7		1,939.6
Resale - Utilities	2,065.7		1,103.8		1,548.9		881.0		1,920.7
Total Sales	31,310.6		30,474.8		28,896.0		31,655.7		32,660.9
Customers - End of Year (Thousands)
Residential	1,005.5		1,003.6		1,001.2		999.1		995.6
Small Commercial/Industrial	113.8		113.5		113.1		112.6		110.8
Large Commercial/Industrial	0.7		0.7		0.7		0.7		0.7
Other	2.5		2.4		2.4		2.4		2.4
Total Customers	1,122.5		1,120.2		1,117.4		1,114.8		1,109.5
Customers - Average (Thousands)	1,121.0		1,118.7		1,115.5		1,111.8		1,105.5
Degree Days (a)
Heating (6,615 Normal)	6,633		6,183		6,825		7,073		6,508
Cooling (709 Normal)	793		944		475		593		800

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

15 Wisconsin Energy Corporation

ITEM 1. BUSINESS - (Cont'd) 2011 Form 10-K

GAS UTILITY OPERATIONS

Our gas utility operations consist of Wisconsin Gas and the gas operations of Wisconsin Electric, both operating under the trade name of "We Energies." We are authorized to provide retail gas distribution service in designated territories in the state of Wisconsin, as established by indeterminate permits, CPCNs, or boundary agreements with other utilities. We also transport customer-owned gas. We are the largest natural gas distribution utility in Wisconsin and we operate throughout the state, including the City of Milwaukee, west and south of the City of Milwaukee, the Appleton area and areas within Iron and Vilas Counties.

Gas Deliveries

Our gas utility business is highly seasonal due to the heating requirements of residential and commercial customers, and annual gas sales are impacted by the variability of winter temperatures.

Total gas therms delivered, including customer-owned transported gas, were approximately 2,154.1 million therms during 2011, a 2.3% increase compared with 2010. As of December 31, 2011, we were transporting gas for approximately 1,400 customers who purchased gas directly from other suppliers. Transported gas accounted for approximately 41.8% of the total volumes delivered during 2011, 43.5% during 2010 and 40.4% during 2009. We had approximately 1,068,200 and 1,064,500 gas customers as of December 31, 2011 and 2010, respectively. Our peak daily send-out during 2011 was 1,545,577 Dth on February 9, 2011.

Sales to Large Gas Customers:   We provide gas utility service to a diversified base of industrial customers who are largely within our electric service territory. Major industries served include the paper, food products and fabricated metal products industries. Fuel used for Wisconsin Electric's electric generation represents our largest transportation customer.

Gas Deliveries Growth:   We currently forecast total retail therm deliveries (excluding natural gas deliveries for generation) to stay flat over the five-year period ending December 31, 2016 as new customer additions are expected to be offset by a reduction in the average use per customer. This forecast reflects a current year normalized sales level and normal weather.

Competition

Competition in varying degrees exists between natural gas and other forms of energy available to consumers. A number of our large commercial and industrial customers are dual-fuel customers that are equipped to switch between natural gas and alternate fuels. We are allowed to offer lower-priced gas sales and transportation services to dual-fuel customers. Under gas transportation agreements, customers purchase gas directly from gas marketers and arrange with interstate pipelines and us to have the gas transported to their facilities. We earn substantially the same margin (difference between revenue and cost of gas) whether we sell and transport gas to customers or only transport their gas.

Our ability to maintain our share of the industrial dual-fuel market depends on our success and the success of third-party gas marketers in obtaining long-term and short-term supplies of natural gas at competitive prices compared to other sources and in arranging or facilitating competitively-priced transportation service for those customers that desire to buy their own gas supplies.

Federal and state regulators continue to implement policies to bring more competition to the gas industry. While the gas utility distribution function is expected to remain a highly regulated, monopoly function, the sale of the natural gas commodity and related services are expected to remain subject to competition from third parties. It remains uncertain if and when the current economic disincentives for small customers to choose an alternative gas commodity supplier may be removed such that we begin to face competition for the sale of gas to our smaller firm customers.

Gas Supply, Pipeline Capacity and Storage

We have been able to meet our contractual obligations with both our suppliers and our customers despite periods of severe cold in recent heating seasons.

16 Wisconsin Energy Corporation

ITEM 1. BUSINESS - (Cont'd) 2011 Form 10-K

Pipeline Capacity and Storage:   The interstate pipelines serving Wisconsin originate in major gas producing areas of North America: the Oklahoma and Texas basins, the Gulf of Mexico, western Canada and the Rocky Mountains. We have contracted for long-term firm capacity from a number of these sources. This strategy reflects management's belief that overall supply security is enhanced by geographic diversification of the supply portfolio.

Due to the daily and seasonal variations in gas usage in Wisconsin, we have also contracted for substantial underground storage capacity, primarily in Michigan. We target storage levels at approximately 35% of winter demand. Storage capacity, along with our gas purchase contracts, enables us to manage significant changes in daily demand and to optimize our overall gas supply and capacity costs. We generally inject gas into storage during the spring and summer months when demand is lower and withdraw it in the winter months. As a result, we can contract for less long-line pipeline capacity during periods of peak usage than would otherwise be necessary and can purchase gas on a more uniform daily basis from suppliers year-round. Each of these capabilities enables us to reduce our overall costs.

We hold firm daily transportation and storage capacity entitlements from pipelines and other service providers under long-term contracts.

Term Gas Supply:   We have contracts for firm supplies with terms in excess of 30 days with suppliers for gas acquired in the Chicago, Illinois market hub and in the producing areas discussed above. The pricing of the term contracts is based upon first of the month indices. Combined with our storage capability, management believes that the volume of gas under contract is sufficient to meet our forecasted firm peak-day demand.

Secondary Market Transactions:   Capacity release is a mechanism by which pipeline long-line and storage capacity and gas supplies under contract can be resold in the secondary market. Local distribution companies, like Wisconsin Gas and Wisconsin Electric, must contract for capacity and supply sufficient to meet the firm peak-day demand of their customers. Peak or near peak demand days generally occur only a few times each year. Capacity release facilitates higher utilization of contracted capacity and supply during those times when the full contracted capacity and supply are not needed by the utility, helping to mitigate the fixed costs associated with maintaining peak levels of capacity and gas supply. Through pre-arranged agreements and day-to-day electronic bulletin board postings, interested parties can purchase this excess capacity and supply. The proceeds from these transactions are passed through to rate payers, subject to the Wisconsin Electric and Wisconsin Gas approved Gas Cost Recovery Mechanisms (GCRMs). During 2011, we continued to participate in the capacity release market. See Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters in Item 7 for information on the GCRMs.

Spot Market Gas Supply:   We expect to continue to make gas purchases in the 30-day spot market as price and other circumstances dictate. We have supply relationships with a number of sellers from whom we purchase spot gas.

Hedging Gas Supply Prices:   We have PSCW approval to hedge (i) up to 45% of planned flowing gas supply using New York Mercantile Exchange (NYMEX) based natural gas options and (ii) up to 15% of planned flowing gas supply using NYMEX based natural gas future contracts. Those approvals allow both Wisconsin Electric and Wisconsin Gas to pass 100% of the hedging costs (premiums and brokerage fees) and proceeds (gains and losses) to rate payers through their respective GCRMs. Hedge targets (volumes) are provided annually to the PSCW as part of each company's three-year gas supply plan and risk management filing.

To the extent that opportunities develop and our physical supply operating plans will support them, we also have PSCW approval to utilize NYMEX based natural gas derivatives to capture favorable forward market price differentials. That approval provides for 100% of the related proceeds to accrue to our GCRMs.

17 Wisconsin Energy Corporation

ITEM 1. BUSINESS - (Cont'd) 2011 Form 10-K

Gas Utility Operating Statistics

The following table shows certain gas utility operating statistics for the past five years:

SELECTED CONSOLIDATED GAS UTILITY OPERATING DATA
Year Ended December 31	2011		2010		2009		2008			2007
Operating Revenues (Millions)
Residential	$	737.4	$	754.2	$	856.6	$	1,057.6		$	934.3
Commercial/Industrial	369.9		373.1		442.9		572.4			485.4
Interruptible	9.4		11.8		11.9		21.3			17.5
Total Retail Gas Sales	1,116.7		1,139.1		1,311.4		1,651.3			1,437.2
Transported Gas	49.2		48.0		44.8		47.2			48.4
Other Operating Revenues	15.3		3.1		11.7		(3.9		)	(4.4		)
Total Operating Revenues	$	1,181.2	$	1,190.2	$	1,367.9	$	1,694.6		$	1,481.2
Therms Delivered (Millions)
Residential	776.8		741.2		803.4		841.8			791.7
Commercial/Industrial	461.7		429.6		479.4		503.2			461.9
Interruptible	16.0		19.4		19.1		23.0			22.7
Total Retail Gas Sales	1,254.5		1,190.2		1,301.9		1,368.0			1,276.3
Transported Gas	899.6		914.9		882.0		905.8			921.6
Total Therms Delivered	2,154.1		2,105.1		2,183.9		2,273.8			2,197.9
Customers - End of Year (Thousands)
Residential	975.2		971.7		967.7		963.9			957.9
Commercial/Industrial	91.5		91.3		91.1		91.0			90.2
Interruptible	0.1		0.1		0.1		0.1			0.1
Transported Gas	1.4		1.4		1.3		1.4			1.3
Total Customers	1,068.2		1,064.5		1,060.2		1,056.4			1,049.5
Customers - Average (Thousands)	1,064.1		1,060.2		1,055.6		1,050.2			1,042.8
Degree Days (a)
Heating (6,615 Normal)	6,633		6,183		6,825		7,073			6,508

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

OTHER UTILITY OPERATIONS

Steam Utility Operations:   Our steam utility generates, distributes and sells steam supplied by our VAPP and Milwaukee County Power Plant. We operate a district steam system in downtown Milwaukee and the near south side of Milwaukee. Steam is supplied to this system from VAPP, a coal-fired cogeneration facility. We also operate the steam production and distribution facilities of the Milwaukee County Power Plant located on the Milwaukee County Grounds in Wauwatosa, Wisconsin.

Annual sales of steam fluctuate from year to year based upon system growth and variations in weather conditions. During 2011, the steam utility had $39.0 million of operating revenues from the sale of 2,733 million pounds of steam compared with $38.8 million of operating revenues from the sale of 2,740 million pounds of steam during 2010. As of December 31, 2011 and 2010, steam was used by approximately 465 customers and 460 customers, respectively, for processing, space heating, domestic hot water and humidification.

18 Wisconsin Energy Corporation

ITEM 1. BUSINESS - (Cont'd) 2011 Form 10-K

UTILITY RATE MATTERS

See Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters in Item 7.

NON-UTILITY ENERGY SEGMENT

Our non-utility energy segment consists primarily of generating plants constructed as part of our PTF strategy. As of December 31, 2011, our PTF assets represented virtually all of our non-utility energy segment assets.

We Power

We Power, through wholly owned subsidiaries, has designed and built approximately 2,320 MW of new generation in Wisconsin, which is being leased to Wisconsin Electric under long-term leases. This new generation consists of approximately 1,230 MW of new capacity from OC 1 and OC 2, and 1,090 MW of capacity from PWGS 1 and PWGS 2. PWGS 1 and PWGS 2 were placed in service in July 2005 and May 2008, respectively. OC 1 and OC 2 were placed in service in February 2010 and January 2011, respectively. In November 2005, two unaffiliated entities collectively purchased an ownership interest of approximately 17%, or 200 MW, in OC 1 and OC 2. Similar to the generating capacity at PWGS 1 and PWGS 2, We Power owns the remaining generating capacity at OC 1 and OC 2.

Our PTFstrategy was designed to address Wisconsin Electric's electric supply needs by increasing the electric generating capacity in Wisconsin while allowing us to maintain a diversified fuel mix, by including both new coal-fired plants and natural-gas fired plants. Because of the significant investment necessary to construct these generating units, we constructed the plants under Wisconsin's Leased Generation Law, which became effective in August 2001 and allows a non-utility affiliate to construct an electric generating facility and lease it to the public utility. The law allows a public utility that has entered into a lease approved by the PSCW to recover fully in its retail electric rates that portion of any payments under the lease that the PSCW has allocated to the public utility's Wisconsin retail electric service, and all other costs that are prudently incurred in the public utility's operation and maintenance of the electric generating facility allocated to the utility's Wisconsin retail electric service. In addition, the PSCW may not modify or terminate a lease it has approved under the Leased Generation Law except as specifically provided in the lease or the PSCW's order approving the lease. This law effectively created regulatory certainty in light of the significant investment being made to construct the units. All four PTF units were constructed under leases approved by the PSCW. For additional background information on our PTF strategy, see Management's Discussion and Analysis of Financial Condition and Results of Operations - Corporate Developments - Corporate Strategy - Power the Future Strategy and - Factors Affecting Results, Liquidity and Capital Resources - Power the Future in Item 7 of our Form 10-K for the year ended December 31, 2007.

For further information about our PTF strategy, see Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Item 7.

Wisvest LLC

Wisvest was originally formed to develop, own and operate electric generating facilities and to invest in other energy-related entities. As a result of the change in corporate strategy to focus on our PTF strategy, Wisvest discontinued its development activity. As of December 31, 2011, Wisvest's sole operating asset and investment is Wisvest Thermal Energy Services, which provides chilled water services to the Milwaukee Regional Medical Center.

19 Wisconsin Energy Corporation

ITEM 1. BUSINESS - (Cont'd) 2011 Form 10-K

OTHER NON-UTILITY OPERATIONS

Wispark LLC and Bostco LLC

Wispark and Bostco develop and invest in real estate, and combined had $85.0 million in real estate holdings as of December 31, 2011. Wispark has developed several business parks and other commercial real estate projects, primarily in southeastern Wisconsin.

REGULATION

Wisconsin Energy Corporation

Wisconsin Energy is a holding company, but is exempt from the requirements of the Public Utility Holding Company Act of 2005 (PUHCA 2005).

Non-Utility Asset Cap:   Pursuant to the non-utility asset cap provisions of Wisconsin's public utility holding company law, the sum of certain assets of all non-utility affiliates in a holding company system may not exceed 25% of the assets of all public utility affiliates. However, among other items, the law exempts energy-related assets, including the generating plants constructed by We Power as part of our PTF strategy and assets used for providing environmental engineering services and for processing waste materials, from being counted against the asset cap provided that they are employed in qualifying businesses. As a result of these exemptions, our non-utility assets are significantly below the non-utility asset cap as of December 31, 2011.

Utility Energy Segment

Wisconsin Electric is a holding company because of its ownership interest in ATC, but is exempt from the requirements of PUHCA 2005.

Wisconsin Electric is subject to the Federal Power Act and the corresponding regulations developed by certain federal agencies. The Energy Policy Act amended the Federal Power Act in 2005 to, among other things, make electric utility industry consolidation more feasible, authorize FERC to review proposed mergers and the acquisition of generation facilities, change the FERC regulatory scheme applicable to qualifying cogeneration facilities and modify certain other aspects of energy regulations and Federal tax policies applicable to Wisconsin Electric. Additionally, the Energy Policy Act created an Electric Reliability Organization to be overseen by FERC, which established mandatory electric reliability standards and which has the authority to levy monetary sanctions for failure to comply with these standards.

Wisconsin Electric and Wisconsin Gas are subject to the regulation of the PSCW as to retail electric, gas and steam rates in the state of Wisconsin, standards of service, issuance of securities, construction of certain new facilities, transactions with affiliates, billing practices and various other matters. Wisconsin Electric is also subject to the regulation of the PSCW as to certain levels of short-term debt obligations. Wisconsin Electric is subject to the regulation of the MPSC as to the various matters associated with retail electric service in the state of Michigan, except as to the issuance of securities in the ordinary course of business, construction of certain new facilities, levels of short-term debt obligations and advance approval of transactions with affiliates in the ordinary course of business. Wisconsin Electric's hydroelectric facilities are regulated by FERC. Wisconsin Electric is subject to the regulation of FERC with respect to wholesale power service, electric reliability requirements and accounting and with respect to our participation in the interstate natural gas pipeline capacity market. For information on how rates are set for our regulated entities, see Utility Rates and Regulatory Matters under Factors Affecting Results, Liquidity and Capital Resources in Item 7.

20 Wisconsin Energy Corporation

ITEM 1. BUSINESS - (Cont'd) 2011 Form 10-K

The following table compares the source of our utility energy segment operating revenues by regulatory jurisdiction for each of the three years in the period ended December 31, 2011:

	2011				2010				2009
	Amount		Percent		Amount		Percent		Amount		Percent
	(Millions of Dollars)
Electric
Wisconsin - Retail	$	2,775.8	86.4	%	$	2,568.3	87.5	%	$	2,379.2	88.6	%
Michigan - Retail	212.0		6.6	%	193.0		6.6	%	141.6		5.3	%
FERC - Wholesale	223.5		7.0	%	175.0		5.9	%	164.2		6.1	%
Total	3,211.3		100.0	%	2,936.3		100.0	%	2,685.0		100.0	%
Gas - Wisconsin - Retail	1,181.2		100.0	%	1,190.2		100.0	%	1,367.9		100.0	%
Steam - Wisconsin - Retail	39.0		100.0	%	38.8		100.0	%	39.1		100.0	%
Total Utility Operating Revenues	$	4,431.5			$	4,165.3			$	4,092.0

The operations of Wisconsin Electric and Wisconsin Gas are also subject to regulations, where applicable, of the United States Environmental Protection Agency (EPA), the Wisconsin Department of Natural Resources (WDNR), the Michigan Department of Environmental Quality and the Michigan Department of Natural Resources.

Public Benefits and Renewable Portfolio Standard

Wisconsin Act 141 establishes a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. Under this act, we must meet certain minimum requirements for renewable energy generation. For the years 2010 through 2014, we must increase our percentage of total retail energy sales provided by renewable sources (renewable energy percentage) by at least two percentage points from our baseline renewable percentage of 2.27% to a level of 4.27%. Act 141 defines "baseline renewable percentage" as the average of an energy provider's renewable energy percentage for 2001, 2002 and 2003. As of December 31, 2011, we are in compliance with the Wisconsin renewable energy percentage of 4.27%. Act 141 further requires that for the year 2015 and beyond, the renewable energy percentage must increase at least six percentage points above the baseline to a level of 8.27%. In addition, under this Act, 1.5% of utilities' annual operating revenues were required to be used to fund energy conservation programs in 2011.  The funding required by Act 141 decreased to 1.2% of annual operating revenues in 2012.

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

For additional information on Act 141 and current renewable projects, see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters - Renewables, Efficiency and Conservation and Utility Rates and Regulatory Matters - Renewable Energy Portfolio in Item 7.

Non-Utility Energy Segment

We Power was formed to design, construct, own and lease the new generating capacity in our PTF strategy. We Power owns the interests in the companies that constructed this new generating capacity (collectively, the We Power project companies). These facilities are being leased on a long-term basis to Wisconsin Electric. We Power received determinations from FERC that upon the transfer of the facilities by lease to Wisconsin Electric, the We Power project companies are not deemed public utilities under the Federal Power Act and thus are not subject to FERC's jurisdiction.

Environmental permits necessary for operating the facilities are the responsibility of the operating entity, Wisconsin Electric.

21 Wisconsin Energy Corporation

ITEM 1. BUSINESS - (Cont'd) 2011 Form 10-K

ENVIRONMENTAL COMPLIANCE

Our operations are subject to extensive environmental regulations by state and federal environmental agencies governing air and water quality, hazardous and solid waste management, environmental remediation and management of natural resources. Costs associated with complying with these requirements are significant. Additional future environmental statutes and regulations or revisions to existing laws, including for example, additional regulation of greenhouse gas emissions, coal combustion products, air emissions or wastewater discharges, could significantly increase these environmental compliance costs.

Expenditures for environmental compliance and remediation issues are included in anticipated capital expenditures described in Liquidity and Capital Resources in Item 7. For discussion of additional environmental issues, see Environmental Matters in Item 3. For further information concerning air and water quality standards and rulemaking initiated by the EPA, including estimated costs of compliance, see Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7. For a discussion of matters related to certain solid waste and coal combustion product landfills, manufactured gas plant sites and air quality, see Note R -- Commitments and Contingencies in the Notes to Consolidated Financial Statements in Item 8.

Compliance with federal, state and local environmental protection requirements resulted in capital expenditures by Wisconsin Electric of approximately $120.3 million in 2011 compared with $215.5 million in 2010. Expenditures incurred during 2011 and 2010 primarily included costs associated with the installation of pollution abatement facilities at Wisconsin Electric's power plants. These expenditures are expected to be approximately $71.0 million during 2012, reflecting the addition of Nitrogen Oxide (NO_x), Sulfur Dioxide (SO₂) and other pollution control equipment needed to comply with various rules promulgated by the EPA. Operation, maintenance and depreciation expenses for fly ash removal equipment and other environmental protection systems were approximately $79.0 million and $76.2 million during 2011 and 2010, respectively.

Coal Combustion Product Fills and Landfills

We currently have a program of beneficial utilization for substantially all of our coal combustion products, including fly ash, bottom ash and gypsum, which minimizes the need for disposal in specially-designed landfills. Some early designed and constructed coal combustion product landfills, which we used prior to developing this program, may allow the release of low levels of constituents resulting in the need for various levels of remediation. Where we have become aware of these conditions, efforts have been made to define the nature and extent of any release, and work has been performed to address these conditions. In addition, fill areas for coal ash were used prior to the introduction of landfill regulations. Sites currently undergoing review include the following:

Oak Creek Site Landfills:   Groundwater impacts identified near the sites, located in the Village of Caledonia and the City of Oak Creek, Wisconsin, prompted Wisconsin Electric to begin investigation in 2009 for the source of impacts found in monitoring wells on the site and surrounding area. Preliminary results indicate that the groundwater impacts may be naturally occurring or are from other sources based on groundwater flow direction and increasing concentrations of elements deeper in the ground. The WDNR began sampling work in 2011 to identify the source of the impacts.

See Item 3 Legal Proceedings -- Environmental Matters for a discussion of the bluff collapse at our Oak Creek Power Plant.

OTHER

Research and Development:   We had immaterial research and development expenditures in the last three years, primarily for improvement of service and abatement of air and water pollution by our electric utility operations. Research and development activities include work done by employees, consultants and contractors, plus sponsorship of research by industry associations.

22 Wisconsin Energy Corporation

ITEM 1. BUSINESS - (Cont'd) 2011 Form 10-K

Employees:As of December 31, 2011, we had the following number of employees:

	Total Employees	Represented Employees
Utility Energy Segment
Wisconsin Electric	4,133	2,685
Wisconsin Gas	450	314
Total	4,583	2,999
Non-Utility Energy Segment	7	—
Other	5	—
Total Employees	4,595	2,999

The employees represented under labor agreements were with the following bargaining units as of December 31, 2011:

	Number of Employees	Expiration Date of Current Labor Agreement
Wisconsin Electric
Local 2150 of International Brotherhood of Electrical Workers	1,853	August 15, 2012
Local 317 of International Union of Operating Engineers	548	March 31, 2013
Local 2006 Unit 5 of United Steel Workers	159	October 31, 2013
Local 510 of International Brotherhood of Electrical Workers	125	April 30, 2012
Total Wisconsin Electric	2,685
Wisconsin Gas
Local 2150 of International Brotherhood of Electrical Workers	85	August 15, 2012
Local 2006 Unit 1 of United Steel Workers	223	November 1, 2012
Local 2006 Unit 3 of United Steel Workers	6	February 28, 2013
Total Wisconsin Gas	314
Total Represented Employees	2,999

23 Wisconsin Energy Corporation

2011 Form 10-K

ITEM 1A. RISK FACTORS

Risks Related to the Operation of Our Business

Our business is significantly impacted by governmental regulation.

We are subject to significant state, local and federal governmental regulation. We are subject to the regulation of the PSCW as to retail electric, gas and steam rates in the state of Wisconsin, standards of service, issuance of securities, short-term debt obligations, construction of certain new facilities, transactions with affiliates, billing practices and various other matters. In addition, we are subject to the regulation of the MPSC as to the various matters associated with retail electric service in the state of Michigan, except as to the issuance of securities in the ordinary course of business, construction of certain new facilities, levels of short-term debt obligations and advance approval of transactions with affiliates in the ordinary course of business. Further, Wisconsin Electric's hydroelectric facilities are regulated by FERC, and FERC also regulates our wholesale power service practices, electric reliability requirements, and participation in the interstate natural gas pipeline capacity market. Our significant level of regulation imposes restrictions on our operations and causes us to incur substantial compliance costs.

We are obligated to comply in good faith with all applicable governmental rules and regulations. If it is determined that we failed to comply with any applicable rules or regulations, whether through new interpretations or applications of the regulations or otherwise, we may be liable for customer refunds, penalties and other amounts, which could materially and adversely affect our results of operations and financial condition.

We estimate that within our regulated energy segment, approximately 86% of our electric revenues are regulated by the PSCW, 7% are regulated by the MPSC and the balance of our electric revenues is regulated by FERC. All of our natural gas and steam revenues are regulated by the PSCW. Our ability to obtain rate adjustments in the future is dependent upon regulatory action, and there can be no assurance that we will be able to obtain rate adjustments in the future that will allow us to recover our costs and expenses and to maintain our current authorized rates of return.

We believe we have obtained the necessary permits, approvals and certificates for our existing operations and that our respective businesses are conducted in accordance with applicable laws; however, the impact of any future revision or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to us cannot be predicted. Changes in regulation, interpretations of regulations or the imposition of additional regulations could influence our operating environment and may result in substantial compliance costs.

Governmental agencies could modify our permits, authorizations or licenses.

Wisconsin Electric and Wisconsin Gas are required to comply with the terms of various permits, authorizations and licenses. These permits, authorizations and licenses may be revoked or modified by the agencies that granted them if facts develop that differ significantly from the facts assumed when they were issued. In addition, discharge permits and other approvals and licenses are often granted for a term that is less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency.

Also, if we are unable to obtain, renew or comply with these governmental permits, authorizations or licenses, or if we are unable to recover any increased costs of complying with additional license requirements or any other associated costs in our rates in a timely manner, our results of operations and financial condition could be materially and adversely affected.

Factors beyond our control could adversely affect project costs and completion of major construction projects.

We are in the process of constructing new renewable generation and adding environmental controls equipment to existing generating facilities. These types of large construction projects are subject to usual construction risks over which we will have limited or no control and which might adversely affect project costs and completion time. These risks include, but are not limited to, shortages of, the ability to obtain or the cost of labor or materials; the ability of the contractors to perform under their contracts; strikes; adverse weather conditions; the ability to obtain necessary operating permits in a timely manner; legal challenges; changes in applicable law or regulations; adverse interpretation or enforcement of permit conditions, laws and regulations by courts or the permitting agencies; other

24 Wisconsin Energy Corporation

ITEM 1A. RISK FACTORS - (Cont'd) 2011 Form 10-K

governmental actions; and events in the global economy.

If we are unable to complete the development or construction of a facility or decide to delay or cancel construction, we may not be able to recover our investment in the facility and may incur substantial cancellation payments under equipment and construction contracts. Even if a construction project is completed, the total costs may be higher than estimated and/or higher than amounts approved by our regulators, and there is no guarantee that we will be allowed to recover these costs in rates. In addition, construction delays can result in the delay of revenues and, therefore, could affect our results of operations.

We estimate that the final cost of the Oak Creek expansion is approximately $181 million, or 8.3%, over the amount initially approved by the PSCW, of which our share is approximately $154 million. This additional amount includes the amounts payable to Bechtel Power Corporation (Bechtel) pursuant to the Settlement Agreement. The order approving the Oak Creek expansion provides that if final costs are within 5% of the costs initially approved by the PSCW, and the additional costs are deemed to be prudent by the PSCW, the final lease payments for the Oak Creek expansion to be recovered from Wisconsin Electric's ratepayers would be adjusted to reflect the actual construction costs. Costs above the 5% cap would not be included in lease payments or recovered from customers absent a finding by the PSCW that such costs were prudently incurred and were the result of force majeure conditions, an excused event and/or an event of loss. In addition, the leases provided for a guaranteed in-service date of September 29, 2009 for OC 1 and September 29, 2010 for OC 2, and imposed liquidated damages of $250,000 per day, of which Elm Road Generating Station Supercritical, LLC's (ERGSS) share is approximately $208,350 per day, for failure to achieve the guaranteed in-service date unless the delays resulted from force majeure conditions or an excused event. ERGSS is entitled to receive its share of liquidated damages from Bechtel for each day Bechtel failed to achieve the same guaranteed in-service dates, unless the delays resulted from force majeure conditions or an excused event. Bechtel was granted total schedule relief of 120 days for OC 1 and 81 days for OC 2. All liquidated damages collected are for the benefit of Wisconsin Electric's customers. There is no guarantee that the PSCW will grant ERGSS the same schedule relief. In light of the weather delays incurred on the project and other factors, we expect to request authorization from the PSCW to recover all costs associated with the units and to grant relief from liquidated damages. If the PSCW does not allow Wisconsin Electric to collect our share of the additional costs or grant ERGSS the same schedule relief, our results of operations could be adversely affected.

Customer growth in our service areas affects our results of operations.

Our results of operations are affected by customer growth in our service areas. Customer growth can be affected by population growth as well as economic factors in Wisconsin and the Upper Peninsula of Michigan, including job and income growth. Customer growth directly influences the demand for electricity and gas, and the need for additional power generation and generating facilities. Population declines and/or business closings in our service territories or slower than anticipated customer growth has a negative impact on our results of operations and cash flow.

Energy sales are impacted by seasonal factors and varying weather conditions from year-to-year.

Our electric and gas utility businesses are generally seasonal businesses. Demand for electricity is greater in the summer and winter months associated with cooling and heating. In addition, demand for natural gas peaks in the winter heating season. As a result, our overall results in the future may fluctuate substantially on a seasonal basis. In addition, we have historically had lower revenues and net income when weather conditions are milder. Our rates in Wisconsin are set by the PSCW based on estimated temperatures which approximate 20-year averages. Mild temperatures during the summer cooling season and during the winter heating season will negatively impact the results of operations and cash flows of our electric utility business. In addition, mild temperatures during the winter heating season negatively impact the results of operations and cash flows of our gas utility business.

Severe weather events, such as floods, droughts, tornadoes and blizzards, could result in substantial damage to or limit the operation of our facilities.

Severe weather events could result in substantial damage to our electric generating and gas distribution facilities, as well as ATC's transmission lines. Our hydroelectric generation operations could be adversely affected if there is a significant change in water levels in their respective waterways. In addition, a significant reduction in water levels in waterways that supply cooling water to our coal- and natural gas-fired power plants, whether by drought or otherwise, could restrict or prevent the operation of such facilities.

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ITEM 1A. RISK FACTORS - (Cont'd) 2011 Form 10-K

In the event we experience any of these weather events or other natural disaster, recovery of any costs in excess of any reserves or applicable insurance is subject to the approval of the PSCW and/or MPSC. There is no guarantee that we will be allowed to fully recover any such costs or that cost recovery will not be delayed or otherwise conditioned. Any denial or delay in recovery of any such costs could adversely affect our results of operations and cash flows.

In addition, damages resulting from severe weather events within our service territories may result in the loss of customers and reduced demand for electricity and natural gas for extended periods. Any significant loss of customers or reduction in demand could adversely affect our results of operations and cash flows.

Our financial performance may be adversely affected if we are unable to successfully operate our facilities.

Our financial performance depends on the successful operation of our electric generating and gas distribution facilities. Operation of these facilities involves many risks, including: operator error and breakdown or failure of equipment processes; fuel supply interruptions; labor disputes; operating limitations that may be imposed by environmental or other regulatory requirements; or catastrophic events such as fires, earthquakes, explosions, floods or other similar occurrences. Unplanned outages can result in additional maintenance expenses as well as incremental replacement power costs. A decrease in revenues from these facilities or an increase in operating costs could adversely affect our results of operations and cash flows.

We are a holding company and rely on the earnings of our subsidiaries to meet our financial obligations.

As a holding company, our ability to meet our financial obligations and pay dividends on our common stock is dependent upon the ability of our subsidiaries to pay amounts to us, whether through dividends or other payments. The ability of our subsidiaries to pay amounts to us will depend on the earnings, cash flows, capital requirements and general financial condition of our subsidiaries and on regulatory limitations. Prior to distributing cash to Wisconsin Energy, our subsidiaries have financial obligations that must be satisfied, including among others, debt service and preferred stock dividends. Our subsidiaries also have dividend payment restrictions based on the terms of their outstanding preferred stock and regulatory limitations applicable to them. In addition, each of the bank back-up credit facilities for Wisconsin Energy, Wisconsin Electric and Wisconsin Gas have specified total funded debt to capitalization ratios that must be maintained. Wisconsin Energy's subsidiaries are separate legal entities and have no obligation to provide us with funds for our payment obligations.

An increase in natural gas costs could negatively impact our electric and gas utility operations.

Wisconsin Electric burns natural gas in several of its peaking power plants and in PWGS 1 and PWGS 2, and as a supplemental fuel at several coal-fired plants. In many instances the cost of purchased power is tied to the cost of natural gas. Disruption in the supply of natural gas due to a curtailment in production or distribution can increase the cost of natural gas, as can international market conditions and demand for natural gas. Higher natural gas costs can have the effect of increasing demand for other sources of fuel thereby increasing the costs of those fuels as well.

For Wisconsin customers, Wisconsin Electric bears the risk for the recovery of fuel and purchased power costs within a symmetrical two percent fuel tolerance band compared to the forecast of fuel and purchased power costs established in its rate structure. Our gas distribution business receives dollar for dollar recovery of the cost of natural gas, subject to tolerance bands and prudency review. However, increased natural gas costs increase the risk that customers will switch to alternative sources of fuel or reduce their usage, which could reduce future gas margins. In addition, an increase in natural gas costs combined with slower economic conditions could also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills. Additionally, high natural gas costs increase our working capital requirements.

We may not be able to obtain an adequate supply of coal, which could limit our ability to operate our coal-fired facilities.

We are dependent on coal for much of our electric generating capacity. Although we currently have an adequate supply of coal at our coal-fired facilities, there can be no assurance that we will continue to have an adequate supply of coal in the future. While we have coal supply and transportation contracts in place, there can be no assurance that the counterparties to these agreements will be able to fulfill their obligations to supply coal to us. The suppliers under these agreements may experience financial or operational problems that inhibit their ability to fulfill

26 Wisconsin Energy Corporation

ITEM 1A. RISK FACTORS - (Cont'd) 2011 Form 10-K

their obligations to us. In addition, suppliers under these agreements may not be required to supply coal to us under certain circumstances, such as in the event of a natural disaster. Furthermore, international demand for coal can impact its availability and cost. If we significantly reduce our inventory of coal and are unable to obtain our coal requirements under our coal supply and transportation contracts, we may be required to purchase coal at higher prices, or we may be forced to reduce generation at our coal units and replace this lost generation from higher cost generating resources or through additional power purchases in the MISO Energy Markets.

Acts of terrorism could materially and adversely affect our financial condition and results of operations.

Our electric generation and gas distribution facilities, including the facilities of third parties on which we rely, could be targets of terrorist activities. A terrorist attack on our facilities (or those of third parties) could result in a full or partial disruption of our ability to generate, transmit, transport, purchase or distribute electricity or natural gas or cause environmental repercussions. Any operational disruption or environmental repercussions could result in a significant decrease in our revenues or significant reconstruction or remediation costs, which could materially and adversely affect our results of operations and financial condition.

We could be the subject of cyber intrusions that disrupt our electric generation and gas distribution operations and/or result in security breaches that expose us to a risk of loss or misuse of confidential and proprietary information, litigation and potential liability.

Cyber intrusions, including those targeting the electronic control systems used at our generating facilities and for the electric and gas distribution systems, could result in a full or partial disruption of our electric generation and/or gas distribution operations. Any disruption of these operations could result in a loss of service to customers and a significant decrease in revenues, as well as significant expense to repair system damage and remedy security breaches. Furthermore, we may need to obtain more expensive purchased power to meet customer demand for electricity if our electric generating facilities are unable to operate at full capacity as a result of a cyber intrusion. Any resulting loss of revenue or increase in expense could have a material adverse effect on our results of operations, cash flow and financial condition.

In addition, any theft, loss and/or fraudulent use of customer, stockholder, employee or proprietary data as a result of cyber intrusion or otherwise could subject us to significant litigation, liability and costs, as well as adversely impact our reputation with customers, stockholders and regulators, among others.

As cyber attacks become more sophisticated generally, we may be required to incur significant costs to strengthen our information and electronic control systems from outside intrusions and/or to obtain insurance coverage related to the threat of such attacks.

Wisconsin Electric could be subject to higher costs and penalties as a result of mandatory reliability standards.

Wisconsin Electric is subject to mandatory reliability and critical infrastructure protection standards established by the North American Electric Reliability Corporation. The critical infrastructure protection standards focus on controlling access to critical and physical and cybersecurity assets. Compliance with the mandatory reliability standards could subject Wisconsin Electric to higher operating costs. If Wisconsin Electric is found to be in noncompliance with the mandatory reliability standards, it could be subject to sanctions, including substantial monetary penalties.

A downgrade in the credit ratings of WEC or any of its subsidiaries could negatively affect their ability to access capital at reasonable costs and/or require the posting of collateral.

There are a number of factors that impact Wisconsin Energy's and its subsidiaries' credit ratings, including, without limitation, capital structure, regulatory environment, the ability to cover liquidity requirements, and other requirements for capital. Wisconsin Energy or any of its subsidiaries could experience a downgrade in their ratings if the rating agencies determine that the level of business or financial risk of the industry or Wisconsin Energy and/or its subsidiaries has deteriorated. Changes in rating methodologies by the rating agencies could also have a negative impact on credit ratings. If Wisconsin Energy or its subsidiaries are downgraded by the rating agencies, their borrowing costs could increase, funding sources could decrease and, for any downgrade to below investment grade, collateral requirements may be triggered in several contracts.

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ITEM 1A. RISK FACTORS - (Cont'd) 2011 Form 10-K

Failure to attract and retain an appropriately qualified workforce could adversely impact our results of operations.

Events such as an aging workforce without appropriate replacements may lead to operating challenges or increased costs. These operating challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. Failure to hire and obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be adversely affected.

The use of derivative contracts could result in financial losses.

We use derivative instruments such as swaps, options, futures and forwards to manage commodity and, to a much lesser extent, interest rate exposures. We could recognize financial losses as a result of volatility in the market value of these contracts or if a counterparty fails to perform. These risks are managed through risk management policies, which might not work as planned and cannot entirely eliminate the risks associated with these activities. In addition, although the hedging programs of Wisconsin Electric and Wisconsin Gas must be approved by the PSCW, derivative contracts entered into for hedging purposes might not offset the underlying exposure being hedged as expected, resulting in financial losses. In the absence of actively quoted market prices and pricing information from external sources, the value of these financial instruments can involve management's judgment or use of estimates. Changes in the underlying assumptions or use of alternative valuation methods could affect the value of the reported fair value of these contracts.

The Dodd-Frank Act could impact our use of over-the-counter (OTC) derivatives. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of OTC derivatives, which could affect both the use and cost of OTC derivatives. The impact, if any, cannot be determined until the regulations are finalized.

Our revenues could be negatively impacted by competitive activity in the wholesale electricity markets.

FERC rules related to transmission are designed to facilitate competition in the wholesale electricity markets among regulated utilities, non-utility generators, wholesale power marketers and brokers by providing greater flexibility and more choices to wholesale customers, including initiatives designed to encourage the integration of renewable sources of supply. In addition, along with transactions contemplating physical delivery of energy, futures contracts and derivatives are traded on various commodities exchanges. We currently cannot predict the impact of these developments or the effect of changes in levels of wholesale supply and demand, which are driven by factors beyond our control.

Restructuring in the regulated energy industry could have a negative impact on our business.

The regulated energy industry continues to experience significant structural changes. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant adverse financial impact on us. It is uncertain when retail access might be implemented in Wisconsin; however, Michigan has adopted retail choice which allows customers to choose their own electric generation supplier. Although competition and customer switching to alternative suppliers in our service territories in Michigan has been limited, the additional competitive pressures resulting from retail access could lead to a loss of customers and our incurring stranded costs.

FERC continues to support the existing RTOs that affect the structure of the wholesale market within those RTOs. In connection with its status as a FERC approved RTO, MISO implemented bid-based energy markets that are part of the MISO Energy Markets. The MISO Energy Markets rules require that all market participants submit day-ahead and/or real-time bids and offers for energy at locations across the MISO region. MISO then calculates the most efficient solution for all of the bids and offers made into the market that day and establishes a Locational Marginal Price (LMP) that reflects the market price for energy. As a participant in the MISO Energy Markets, we are required to follow MISO's instructions when dispatching generating units to support MISO's responsibility for maintaining stability of the transmission system. MISO also implemented an Ancillary Services Market for operating reserves that was simultaneously co-optimized with its existing energy markets.

These market designs have the potential to increase the costs of transmission, the costs associated with inefficient

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ITEM 1A. RISK FACTORS - (Cont'd) 2011 Form 10-K

generation dispatching, the costs of participation in the market and the costs associated with estimated payment settlements.

Risks Related to Legislation and Regulation

We may face significant costs of compliance with existing and future environmental regulations.

Our operations are subject to extensive environmental legislation and regulation by state and federal environmental agencies governing, among other things, air emissions such as Carbon Dioxide (CO₂), SO₂, NO_x, fine particulates and mercury; water discharges; and management of hazardous, toxic and solid wastes and substances. We incur significant expenditures in complying with these environmental requirements, including expenditures for the installation of pollution control equipment, environmental monitoring, emissions fees and permits at all of our facilities. In April 2003, Wisconsin Electric reached a Consent Decree with the EPA to significantly reduce air emissions from its coal-fired generating facilities. Through the end of 2011, we had invested approximately $1.0 billion to comply with the Consent Decree. The total cost of implementing the Consent Decree is currently estimated to be approximately $1.1 billion over the ten year period ending 2013.

Several new environmental regulations have recently been proposed or adopted, including the EPA's Cross-State Air Pollution Rule (CSAPR), the Mercury and Air Toxics Standards (MATS) rule (also referred to as the utility Maximum Achievable Control Technology (MACT) rule) and new SO₂ National Ambient Air Quality Standards. Various petitioners have requested judicial and administrative review of many of these regulations, including CSAPR. The December 30, 2011 decision of the U.S. Court of Appeals for the District of Columbia to grant a motion to stay CSAPR, which was scheduled to become effective on January 1, 2012, adds substantial uncertainty as to what capital expenditures may be required to comply with new environmental regulations. Despite this uncertainty, we currently estimate the capital expenditures necessary to comply with these new environmental regulations, including the utility MACT rule, over the three year period ending 2014 could be up to $16 million more than the estimated cost of implementing the Consent Decree. These costs are included in the table under "Capital Expenditures" in the Liquidity and Capital Resources section of Management's Discussion and Analysis of Financial Condition and Results of Operations.

Existing environmental regulations may be revised or new laws or regulations may be adopted at the federal or state level which could result in significant additional expenditures, operating restrictions on our facilities and increased compliance costs. In addition, the operation of emission control equipment and further regulations on our intake and discharge of water could increase our operating costs and could reduce the generating capacity of our power plants.

In the event we are not able to recover all of our environmental expenditures from our customers in the future, our results of operations could be adversely affected.

Environmental legislation and regulation and the related compliance costs could affect future unit retirement and replacement decisions, and could result in some of our coal-fired generating units being retired or converted to an alternative type of fuel. In order to comply with new environmental requirements we are currently exploring different alternatives with regard to the Presque Isle Power Plant in the Upper Peninsula of Michigan and the VAPP in Milwaukee, Wisconsin. We have committed to convert the VAPP from coal to natural gas if we are able to determine that such conversion will have a direct economic benefit to our customers and we receive approval from the PSCW. Costs associated with these potential actions could affect our results of operations and financial condition.

Our electric and gas utility businesses are also subject to significant liabilities related to the investigation and remediation of environmental contamination at certain of our current and former facilities, and at third-party owned sites. Due to the potential for imposition of stricter standards and greater regulation in the future and the possibility that other potentially responsible parties may not be financially able to contribute to cleanup costs, conditions may change or additional contamination may be discovered, our remediation costs could increase, and the timing of our capital and/or operating expenditures in the future may accelerate.

We may also be subject to potential liability in connection with the environmental condition of the facilities that we have previously owned and operated, regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. If we fail (or failed) to comply with environmental laws and regulations or cause (or caused) harm to the environment or persons, that failure or harm may result in the assessment of civil penalties and

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ITEM 1A. RISK FACTORS - (Cont'd) 2011 Form 10-K

damages against us. The incurrence of a material environmental liability or a material judgment in any action for personal injury or property damage related to environmental matters could have a significant adverse effect on our results of operations and financial condition.

Energy conservation and rate increases could negatively impact financial results.

Wisconsin and Michigan have adopted energy efficiency targets to reduce energy consumption by certain dates. To the extent there is any regulatory lag to adjust rates as a result of reduced sales from effective conservation measures, these measures could have a negative impact on our results of operations and cash flows.

In addition, any higher costs that are collected through rates could contribute to reduced demand for electricity, natural gas or steam, which could adversely impact our results of operations and financial condition.

We may face significant costs if coal combustion products are regulated as hazardous waste.

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

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

In addition, the EPA finalized the Commercial and Industrial Solid Waste Incineration Units rule under the Clean Air Act (CAA), and finalized a Non-Hazardous Secondary Materials Rule. Both of these rules have the potential to negatively affect our ability to reburn coal ash from power plants and landfills.

We may face significant costs to comply with the regulation of greenhouse gas emissions.

The regulation of greenhouse gas emissions through legislation and regulation has been, and continues to be, a focus of the President and his administration. Although legislation that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards and/or energy efficiency standards has failed to pass in the U.S. Congress, we expect such legislation to be considered in the future. Although we cannot currently predict with any certainty what form these future regulations will take, the stringency of the regulations or when they will become effective, we do believe that future governmental legislation and/or regulation may require us to limit or control greenhouse gas emissions from our operations, purchase allowances for such emissions or otherwise incur costs in connection with such emissions.

While climate legislation has yet to be adopted, the EPA is pursuing regulation of greenhouse gas emissions using its existing authority under the CAA. In December 2009, the EPA issued its endangerment finding related to greenhouse gas emissions, which set in motion a regulatory process that has led to the regulation of greenhouse gas emissions from stationary sources, including electric generating units. In March 2010, the EPA issued regulations governing the applicability of the CAA's permitting requirements for greenhouse gas emissions from facilities, including electric generating units. These rules became applicable to sources that are already subject to CAA permitting requirements, as well as new and modified sources, during 2011. Additionally, the EPA plans to propose new source performance standards pertaining to greenhouse gas emissions from certain new or modified coal-fired power plants by the end of May 2012. Regulation of greenhouse gas emissions from power plants may negatively impact our ability to perform maintenance or modify our existing facilities, and permit new facilities. Depending on the extent of rate recovery and other factors, these rules could have a material adverse impact on our financial condition.

Legislation to regulate greenhouse gas emissions and establish renewable and efficiency standards has also been considered on the state level. The state of Michigan has enacted legislation that calls for the implementation of a

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ITEM 1A. RISK FACTORS - (Cont'd) 2011 Form 10-K

renewable portfolio standard by 2015 and energy optimization (efficiency) targets up to 1% annually by 2015. The state of Wisconsin has adopted its own renewable portfolio standard and energy optimization targets. Although the Wisconsin legislature ultimately did not pass a legislative proposal to increase Wisconsin's renewable portfolio standard and energy optimization targets, there is no guarantee the legislature will not consider similar legislation in the future.

Some states and environmental groups are also bringing lawsuits against electric utilities and others to force reductions in greenhouse gas emissions based upon their contribution to the alleged public nuisance of climate change. On June 20, 2011, in Connecticut v. American Electric Power Co., however, the United States Supreme Court ruled that the plaintiffs in that litigation did not have standing to claim nuisance due to the release of greenhouse gas into the atmosphere by the defendants, and the plaintiffs have since voluntarily dismissed their remaining claims. Similar cases are pending in other courts.

There is no guarantee that we will be allowed to fully recover costs incurred to comply with any future legislation, regulation or order that requires a reduction in greenhouse gas emissions or that cost recovery will not be delayed or otherwise conditioned. Any cap-and-trade or greenhouse gas tax program that may be adopted, either at the federal or state level, or other legislation, regulation or order designed to reduce greenhouse gas emissions could have a material adverse impact on our electric generation and natural gas distribution operations. Such regulation could make some of our electric generating units uneconomic to maintain or operate, and could adversely affect our future results of operations, cash flows and possibly financial condition if such costs are not recovered through regulated rates.

We continue to monitor the legislative, regulatory and legal developments in this area. Although we expect the regulation of greenhouse gas emissions to have a material impact on our operations and rates, we believe it is premature to attempt to quantify the possible costs of the impacts.

Provisions of the Wisconsin Utility Holding Company Act limit our ability to invest in non-utility businesses and could deter takeover attempts by a potential purchaser of our common stock that would be willing to pay a premium for our common stock.

Under the Wisconsin Utility Holding Company Act, we remain subject to certain restrictions that have the potential of limiting our diversification into non-utility businesses. Under the Act, the sum of certain assets of all non-utility affiliates in a holding company system may not exceed 25% of the assets of all public utility affiliates in the system.

In addition, the Act precludes the acquisition of 10% or more of the voting shares of a holding company of a Wisconsin public utility unless the PSCW has first determined that the acquisition is in the best interests of utility customers, investors and the public. This provision and other requirements of the Act may delay or reduce the likelihood of a sale or change of control of Wisconsin Energy. As a result, stockholders may be deprived of opportunities to sell some or all of their shares of our common stock at prices that represent a premium over market prices.

Risks Related to Economic and Market Volatility

Our business is dependent on our ability to successfully access capital markets.

We rely on access to short-term and long-term capital markets to support our capital expenditures and other capital requirements, including expenditures for our utility infrastructure and to comply with future regulatory requirements. We have historically secured funds from a variety of sources, including the issuance of short-term and long-term debt securities and common stock. Successful implementation of our long-term business strategies is dependent upon our ability to access the capital markets, including the banking and commercial paper markets, under competitive terms and rates. In addition, we rely on committed bank credit agreements as back-up liquidity which allows us to access the low cost commercial paper markets. If our access to any of these markets were limited, or our cost of capital significantly increased, due to a rating downgrade, an economic downturn or uncertainty, prevailing market conditions, concerns over foreign economic conditions and/or the ability of foreign governments and central banks to respond to changing economic conditions, a negative view of the utility industry, failures of financial institutions or other factors, our results of operations and financial condition could be materially and adversely affected.

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ITEM 1A. RISK FACTORS - (Cont'd) 2011 Form 10-K

We are exposed to risks related to general economic conditions in our service territories.

Our electric and gas utility businesses are impacted by economic cycles and the competitiveness of the customers we serve. As the demand for products produced in our service area declines, we ordinarily experience reduced demand for electricity and/or natural gas. During 2011, our service territory experienced growth, but future growth could be impacted by the overall economy in our service territories. If the economic conditions in our service territories and/or demand for products produced in our service area does not continue to improve or declines again, we could experience a reduction in demand for electricity and/or natural gas that could result in decreased earnings and cash flow. We would also expect our collections of accounts receivable to be adversely impacted.

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

Our cost of providing defined benefit pension plans is dependent upon a number of factors including actual plan experience and assumptions concerning the future, such as earnings on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation and our required or voluntary contributions to be made to the plans. Plan assets are subject to market fluctuations and may yield returns that fall below projected return rates. A decline in the market value of these assets, as experienced in prior periods, may increase our funding requirements. Changes in interest rates affect plan liabilities - as rates decrease, the liabilities increase, which could increase our funding requirements. Changes in demographics, such as an increase in the number of retirements or changes in life expectancy assumptions, may also increase our funding requirements. Changes made to the plans may also impact current and future pension costs. These additional funding obligations could have a material adverse impact on our cash flows, financial condition or results of operations.

Our ability to obtain insurance and the terms of any available insurance coverage could be adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers. Our insurance coverage may not provide protection against all significant losses.

Our ability to obtain insurance, as well as the cost and coverage of such insurance, could be affected by developments affecting our business, as well as by international, national, state or local events, as well as the financial condition of insurers. Insurance coverage may not continue to be available at all or at rates or terms similar to those presently available to us. A loss for which we are not fully insured could have a material adverse effect on our results of operations. In addition, our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

We own our principal properties outright, except that the major portion of our electric utility distribution lines, steam utility distribution mains and gas utility distribution mains and services are located, for the most part, on or under streets and highways and on land owned by others and are generally subject to granted easements, consents or permits.

32 Wisconsin Energy Corporation

ITEM 2. PROPERTIES - (Cont'd) 2011 Form 10-K

As of December 31, 2011, we owned the following generating stations:

		No. of	Dependable
		Generating	Capability
Name	Fuel	Units	In MW (a)
Coal-Fired Plants
South Oak Creek	Coal	4	1,055
Oak Creek Expansion	Coal	2	1,056
Presque Isle	Coal	5	346
Pleasant Prairie	Coal	2	1,188
Valley	Coal	2	227
Milwaukee County	Coal	3	8
Total Coal-Fired Plants		18	3,880
Hydro Plants (13 in number)		33	57
Port Washington Generating Station	Gas	2	1,090
Germantown Combustion Turbines	Gas/Oil	5	345
Concord Combustion Turbines	Gas/Oil	4	400
Paris Combustion Turbines	Gas/Oil	4	400
Other Combustion Turbines & Diesel	Gas/Oil	2	5
Byron Wind Turbines	Wind	2	—
Blue Sky Green Field	Wind	88	29
Glacier Hills	Wind	90	32
Total System		248	6,238

(a) Dependable capability is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. We are a summer peaking electric utility. The values are established by tests and may change slightly from year to year.

As of December 31, 2011, we operated approximately 21,632 pole-miles of overhead distribution lines and 23,780 miles of underground distribution cable, as well as approximately 350 distribution substations and 287,446 line transformers.

As of December 31, 2011, our gas distribution system included approximately 20,687 miles of distribution and transmission mains connected at 183 gate stations to the pipeline transmission systems of ANR Pipeline Company, Guardian Pipeline L.L.C., Natural Gas Pipeline Company of America, Northern Natural Pipeline Company, Great Lakes Transmission Company, Viking Gas Transmission and Michigan Consolidated Gas Company. We have liquefied natural gas storage plants which convert and store, in liquefied form, natural gas received during periods of low consumption. The liquefied natural gas storage plants have a send-out capability of 73,600 Dth per day. We also have propane air systems for peaking purposes. These propane air systems will provide approximately 2,960 Dth per day of supply to the system. Our gas distribution system consists almost entirely of plastic and coated steel pipe.

We also own office buildings, gas regulating and metering stations and major service centers, including garage and warehouse facilities, in certain communities we serve. Where distribution lines and services and gas distribution mains and services occupy private property, we have in some, but not all instances, obtained consents, permits or easements for these installations from the apparent owners or those in possession of those properties, generally without an examination of ownership records or title.

As of December 31, 2011, the combined steam systems supplied by the VAPP and Milwaukee County Power Plant consisted of approximately 43 miles of both high pressure and low pressure steam piping, nine miles of walkable tunnels and other pressure regulating equipment.

33 Wisconsin Energy Corporation

2011 Form 10-K

ITEM 3. LEGAL PROCEEDINGS

In addition to those legal proceedings discussed below, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these other legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material effect on our financial statements.

ENVIRONMENTAL MATTERS

We are subject to federal, state and certain local laws and regulations governing the environmental aspects of our operations. Management believes that our existing facilities are in material compliance with applicable environmental requirements.

Bluff Collapse:  On October 31, 2011, a portion of the bluff at our Oak Creek Power Plant collapsed. The affected area, located south of the Air Quality Control System (AQCS) that is currently under construction, was a former ravine that had been filled with coal ash prior to the advent of landfill regulations.

It is estimated that approximately 23,000 cubic yards of soil, coal ash and water was released from the bluff. This mixture of materials, along with several trailers, vehicles and other construction materials from the AQCS construction site, slid down the bluff to the shoreline area. Some of the soil and coal ash mixture fell into Lake Michigan.

We worked with the U.S. Coast Guard, WDNR and EPA to coordinate an incident action plan for completing the recovery and clean-up efforts. Ash and soil materials have been removed from the area, and construction equipment and related materials have been removed from Lake Michigan. The clean-up work has been completed, and the bluff has been stabilized for the winter. We expect that permanent bluff stabilization efforts will commence during the second quarter of 2012.

We have consulted with nearby water utilities who have indicated that they have not detected any impacts to public drinking water supplies. In November 2011, the WDNR conducted a survey of Lake Michigan's lakebed. The survey did not locate any fly ash or construction materials on the lakebed immediately east and south of the Oak Creek site. Both water quality and sediment sampling have not indicated a serious risk of harm to human health or the environment.

We anticipate the WDNR will release its investigative findings during the first quarter of 2012. At this time, we cannot predict with certainty whether the WDNR or other regulatory agency will seek fines or penalties from us as a result of this incident.

In addition, on November 8, 2011, the Sierra Club provided a Notice of Intent to file a citizens suit under the CAA and Resource Conservation and Recovery Act for alleged violations related to this incident. We have responded that we do not believe there is any basis for a citizen suit. To date, Sierra Club has not indicated whether they intend to file suit.

Solvay Coke and Gas Site:  Wisconsin Electric and Wisconsin Gas have been identified as potentially responsible parties at the Solvay Coke and Gas Site located in Milwaukee, Wisconsin. A predecessor company of Wisconsin Electric owned a parcel of property that is within the property boundaries of the site. A predecessor company of Wisconsin Gas had a customer and corporate relationship with the entity that owned and operated the site. In 2007, Wisconsin Electric, Wisconsin Gas and several other parties entered into an Administrative Settlement Agreement and Order with the EPA to perform additional investigation and assessment and reimburse the EPA's oversight costs. In-field investigation activities have commenced. Under the Administrative Settlement Agreement, neither Wisconsin Electric nor Wisconsin Gas admits to any liability for the site, waives any liability defenses, or commits to perform future site remedial activities. The companies' share of the costs to perform the required work and reimburse the EPA's oversight costs, as well as potential future remediation cost estimates and reserves, are included in the estimated manufactured gas plant values reported in Note R -- Commitments and Contingencies in the Notes to Consolidated Financial Statements in Item 8.

34 Wisconsin Energy Corporation

ITEM 3. LEGAL PROCEEDINGS - (Cont'd) 2011 Form 10-K

Edgewater Generating Unit 5:   In December 2009, the EPA issued a Notice of Violation (NOV) concerning several coal-fired power plants owned and operated by WPL, including Edgewater Generating Unit 5, of which Wisconsin Electric owned 25%. Due to its ownership interest at the time, Wisconsin Electric was named in the NOV. On March 1, 2011, Wisconsin Electric sold its interest to WPL. Although Wisconsin Electric sold its interest, it retained its share of liability, if any, related to the NOV. The NOV alleges that certain maintenance projects at WPL's units, including Edgewater 5, were undertaken without obtaining air permits required by the CAA. Wisconsin Electric, WPL and the co-owners of the other plants identified in the NOV are discussing resolution of this NOV with the EPA. At this time, we cannot predict the outcome of this matter.

In September 2010, the Sierra Club filed a complaint against WPL generally alleging air permitting and opacity violations at the Edgewater Generating Station. Wisconsin Electric is not a named party to this litigation. WPL, the other co-owner of the Edgewater Generating Station, and Wisconsin Electric as a former co-owner, are discussing resolution of this matter with the Sierra Club. At this time, we cannot predict the outcome of this matter.

See Environmental Compliance in Item 1 and Environmental Matters, Manufactured Gas Plant Sites, Coal Combustion Product Landfill Sites and EPA - Consent Decree in Note R -- Commitments and Contingencies in the Notes to Consolidated Financial Statements which are incorporated by reference herein, for a discussion of matters related to certain solid waste and coal combustion product landfills, manufactured gas plant sites and air quality.

UTILITY RATE MATTERS

See Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters in Item 7 for information concerning rate matters in the jurisdictions where Wisconsin Electric and Wisconsin Gas do business.

OTHER MATTERS

Used Nuclear Fuel Storage and Removal:See Factors Affecting Results, Liquidity and Capital Resources -- Nuclear Operations in Item 7 for information concerning the United States Department of Energy's (DOE) breach of contract with Wisconsin Electric that required the DOE to begin permanently removing used nuclear fuel from Point Beach by January 31, 1998.

Stray Voltage:Dairy farmers continue to make claims against Wisconsin Electric for loss of milk production and other damages to livestock allegedly caused by stray voltage resulting from the operation of its electrical system. For additional information, see Factors Affecting Results, Liquidity and Capital Resources -- Legal Matters in Item 7.

Cash Balance Pension Plan:   See Factors Affecting Results, Liquidity and Capital Resources -- Legal Matters in Item 7 and Note R -- Commitments and Contingencies in the Notes to Consolidated Financial Statements for information regarding a lawsuit filed against the Plan.

For information regarding additional legal matters, see Factors Affecting Results, Liquidity and Capital Resources -- Legal Matters in Item 7. For information concerning our PTF strategy, including the Settlement Agreement with Bechtel, see Factors Affecting Results, Liquidity and Capital Resources -- Power the Future and Note R -- Commitments and Contingencies in the Notes to Consolidated Financial Statements.

ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable.

35 Wisconsin Energy Corporation

2011 Form 10-K

EXECUTIVE OFFICERS OF THE REGISTRANT

The names, ages at December 31, 2011 and positions of our executive officers are listed below along with their business experience during the past five years. All officers are appointed until they resign, die or are removed pursuant to the Bylaws. There are no family relationships among these officers, nor is there any agreement or understanding between any officer and any other person pursuant to which the officer was selected.

Gale E. Klappa.   Age 61.

• Wisconsin Energy -- Chairman of the Board and Chief Executive Officer since May 2004. President since April 2003.

• Wisconsin Electric -- Chairman of the Board since May 2004. President and Chief Executive Officer since August 2003.

• Wisconsin Gas -- Chairman of the Board since May 2004. President and Chief Executive Officer since August 2003.

• Director of Joy Global, Inc. and Badger Meter, Inc.

• Director of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas since 2003.

Charles R. Cole.   Age 65.

• Wisconsin Electric -- Senior Vice President since 2001.

• Wisconsin Gas -- Senior Vice President since July 2004.

Mr. Cole is retiring effective March 1, 2012.

Stephen P. Dickson.   Age 51.

• Wisconsin Energy -- Vice President since 2005. Controller since 2000.

• Wisconsin Electric -- Vice President since 2005. Controller since 2000.

• Wisconsin Gas -- Vice President since 2005. Controller since 1998.

James C. Fleming.   Age 66.

• Wisconsin Energy -- General Counsel since March 2006. Executive Vice President since January 2006.

• Wisconsin Electric -- General Counsel since March 2006. Executive Vice President since January 2006.

• Wisconsin Gas -- General Counsel since March 2006. Executive Vice President since January 2006.

Mr. Fleming is retiring effective April 1, 2012.

J. Kevin Fletcher.   Age 53.

• Wisconsin Electric -- Senior Vice President since October 2011.

• Wisconsin Gas -- Senior Vice President since October 2011.

• Georgia Power -- Vice President - Community and Economic Development from 2007 to October 2011. Georgia Power is an affiliate of The Southern Company, a public utility holding company serving the southeastern United States.

Robert M. Garvin.   Age 45.

• Wisconsin Energy -- Senior Vice President since April 2011.

• Wisconsin Electric -- Senior Vice President since April 2011.

• Wisconsin Gas -- Senior Vice President since April 2011.

• American Transmission Co. -- Vice President and General Counsel from 2009 to April 2011.

• NextEra Energy Resources -- Vice President from 2007 to 2009.

• Commissioner - Public Service Commission of Wisconsin -- 2001 to 2007.

Frederick D. Kuester.   Age 61.

• Wisconsin Energy -- Executive Vice President since May 2004. Chief Financial Officer since March 2011.

• Wisconsin Electric -- Executive Vice President since May 2004. Chief Operating Officer from October 2003 until February 2011. Chief Financial Officer since March 2011.

• Wisconsin Gas -- Executive Vice President since May 2004. Chief Financial Officer since March 2011.

Mirant Corporation, of which Mr. Kuester was Senior Vice President - International from 2001 to October 2003 and Chief Executive Officer of Mirant Asia - Pacific Limited from 1999 to October 2003, and certain of its subsidiaries

36 Wisconsin Energy Corporation

EXECUTIVE OFFICERS OF THE REGISTRANT - (Cont'd) 2011 Form 10-K

voluntarily filed for bankruptcy in July 2003. Other than certain Canadian subsidiaries, none of Mirant's international subsidiaries filed for bankruptcy.

Allen L. Leverett.   Age 45.

• Wisconsin Energy -- Executive Vice President since May 2004. Chief Financial Officer from July 2003 until February 2011.

• Wisconsin Electric -- Executive Vice President since May 2004. Chief Financial Officer from July 2003 until February 2011.

• Wisconsin Gas -- Executive Vice President since May 2004. Chief Financial Officer from July 2003 until February 2011.

Kristine A. Rappé.   Age 55.

• Wisconsin Energy -- Senior Vice President and Chief Administrative Officer since May 2004.

• Wisconsin Electric -- Senior Vice President and Chief Administrative Officer since May 2004.

• Wisconsin Gas -- Senior Vice President and Chief Administrative Officer since May 2004.

Certain executive officers also hold offices in our non-utility subsidiaries.

PART II

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

NUMBER OF COMMON STOCKHOLDERS

As of December 31, 2011, based upon the number of Wisconsin Energy Corporation stockholder accounts (including accounts in our dividend reinvestment and stock purchase plan), we had approximately 42,550 registered stockholders.

COMMON STOCK LISTING AND TRADING

Our common stock is listed on the New York Stock Exchange under the ticker symbol "WEC." Daily trading prices and volume can be found in the "NYSE Composite" section of most major newspapers, usually abbreviated as WI Engy.

DIVIDENDS AND COMMON STOCK PRICES

Common Stock Dividends of Wisconsin Energy:Cash dividends on our common stock, as declared by the Board of Directors, are normally paid on or about the first day of March, June, September and December of each year. We review our dividend policy on a regular basis. Subject to any regulatory restrictions or other limitations on the payment of dividends, future dividends will be at the discretion of the Board of Directors and will depend upon, among other factors, earnings, financial condition and other requirements. For information regarding restrictions on the ability of our subsidiaries to pay us dividends, see Note I -- Common Equity in the Notes to Consolidated Financial Statements in Item 8.

On January 19, 2012, our Board of Directors approved a new dividend policy. Pursuant to this new policy, we will target a dividend payout ratio that trends toward 60% in the year 2014. At the same time, in accordance with that policy, our Board of Directors increased our quarterly dividend to $0.30 per share effective with the first quarter 2012 dividend payment, which would result in annual dividends of $1.20 per share.

On January 20, 2011, our Board of Directors approved a two-for-one stock split of our common stock, which was effected through a stock dividend. Stockholders of record at the close of business on February 14, 2011 were entitled to one additional share of Wisconsin Energy common stock for each share then owned. The additional

37 Wisconsin Energy Corporation

ITEM 5. MARKET FOR RESITRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES - (Cont'd) 2011 Form 10-K

shares were distributed on March 1, 2011. The table below reflects the impact of the two-for-one stock split.

Range of Wisconsin Energy Common Stock Prices and Dividends:

	2011						2010
Quarter	High		Low		Dividend		High		Low		Dividend
First	$	31.01	$	28.83	$	0.26	$	25.71	$	23.44	$	0.20
Second	$	31.89	$	29.39	0.26		$	26.90	$	23.42	0.20
Third	$	32.49	$	27.00	0.26		$	29.29	$	24.71	0.20
Fourth	$	35.38	$	29.82	0.26		$	30.51	$	28.76	0.20
Annual	$	35.38	$	27.00	$	1.04	$	30.51	$	23.42	$	0.80

ISSUER PURCHASES OF EQUITY SECURITIES

2011	Total Number of Shares Purchased (a)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (b)	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
					(Millions of Dollars)
October 1 - October 31	2,598	$	31.45	—	$	225.1
November 1 - November 30	777,317	$	32.25	777,317	$	200.0
December 1 - December 31	—	$	—	—	$	200.0
Total	779,915	$	32.24	777,317

(a) All shares reported during October 2011 were surrendered by employees to satisfy tax withholding obligations upon vesting of restricted stock.

(b) On May 5, 2011, Wisconsin Energy's Board of Directors authorized a share repurchase program for up to $300 million of our common stock through December 31, 2013.

38 Wisconsin Energy Corporation

2011 Form 10-K

ITEM 6. SELECTED FINANCIAL DATA

WISCONSIN ENERGY CORPORATION
CONSOLIDATED SELECTED FINANCIAL AND STATISTICAL DATA
Financial	2011			2010			2009			2008			2007
Year Ended December 31
Net income - Continuing Operations (Millions)	$	512.8		$	454.4		$	375.7		$	355.1		$	332.4
Earnings per share - Continuing Operations
Basic	$	2.20		$	1.94		$	1.61		$	1.52		$	1.42
Diluted	$	2.18		$	1.92		$	1.59		$	1.50		$	1.40
Dividends per share of common stock	$	1.04		$	0.80		$	0.675		$	0.54		$	0.50
Operating revenues (Millions)
Utility energy	$	4,431.5		$	4,165.3		$	4,092.0		$	4,395.5		$	4,190.9
Non-utility energy	435.1			320.2			163.1			126.2			75.7
Eliminations and Other	(380.2		)	(283.0		)	(154.2		)	(119.3		)	(62.3		)
Total operating revenues	$	4,486.4		$	4,202.5		$	4,100.9		$	4,402.4		$	4,204.3
As of December 31 (Millions)
Total assets	$	13,862.1		$	13,059.8		$	12,697.9		$	12,617.8		$	11,720.3
Long-term debt (including current maturities) and capital lease obligations	$	4,646.9		$	4,405.4		$	4,171.5		$	4,136.5		$	3,525.3
Common Stock Closing Price	$	34.96		$	29.43		$	24.92		$	20.99		$	24.36
CONSOLIDATED SELECTED QUARTERLY FINANCIAL DATA (Unaudited)
	(Millions of Dollars, Except Per Share Amounts) (a)
	March						June
Three Months Ended	2011			2010			2011			2010
Operating revenues	$	1,328.7		$	1,248.6		$	991.7		$	890.9
Operating income	295.6			228.4			174.4			163.3
Income from Continuing Operations	170.9			129.0			98.0			87.5
Income (loss) from Discontinued Operations	—			0.7			11.5			1.2
Total Net Income	$	170.9		$	129.7		$	109.5		$	88.7
Earnings per share of common stock (basic) (b)
Continuing operations	$	0.73		$	0.55		$	0.42		$	0.37
Discontinued operations	—			—			0.05			0.01
Total earnings per share (basic)	$	0.73		$	0.55		$	0.47		$	0.38
Earnings per share of common stock (diluted) (b)
Continuing operations	$	0.72		$	0.55		$	0.41		$	0.37
Discontinued operations	—			—			0.05			—
Total earnings per share (diluted)	$	0.72		$	0.55		$	0.46		$	0.37
	September						December
Three Months Ended	2011			2010			2011			2010
Operating revenues	$	1,052.8		$	973.2		$	1,113.2		$	1,089.8
Operating income	224.3			203.0			193.0			215.7
Income from Continuing Operations	129.8			112.3			114.1			125.6
Income (loss) from Discontinued Operations	—			(0.1		)	1.9			0.3
Total Net Income	$	129.8		$	112.2		$	116.0		$	125.9
Earnings per share of common stock (basic) (b)
Continuing operations	$	0.56		$	0.48		$	0.49		$	0.54
Discontinued operations	—			—			0.01			—
Total earnings per share (basic)	$	0.56		$	0.48		$	0.50		$	0.54
Earnings per share of common stock (diluted) (b)
Continuing operations	$	0.55		$	0.47		$	0.49		$	0.53
Discontinued operations	—			—			0.01			—
Total earnings per share (diluted)	$	0.55		$	0.47		$	0.50		$	0.53

(a) Quarterly results of operations are not directly comparable because of seasonal and other factors. See Management's Discussion and Analysis of Financial Condition and Results of Operations.

(b) Quarterly earnings per share may not total to the amounts reported for the year because the computation is based on the weighted average common shares outstanding during each quarter.

39 Wisconsin Energy Corporation

2011 Form 10-K

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

INTRODUCTION

Wisconsin Energy Corporation is a diversified holding company with subsidiaries primarily in a utility energy segment and a non-utility energy segment. Unless qualified by their context, when used in this document the terms Wisconsin Energy, the Company, our, us or we refer to the holding company and all of its subsidiaries.

Our utility energy segment primarily consists of Wisconsin Electric and Wisconsin Gas, both doing business under the trade name of "We Energies." We generate and distribute electricity in Wisconsin and the Upper Peninsula of Michigan and we distribute natural gas in Wisconsin. Our non-utility energy segment primarily consists of We Power. We Power is principally engaged in the engineering, construction and development of electric power generating facilities for long-term lease to Wisconsin Electric under our PTF strategy.

CORPORATE STRATEGY

Business Opportunities

We have three primary investment opportunities and earnings streams: our regulated utility business; our investment in ATC; and our generation plants within our non-utility energy segment.

Our regulated utility business primarily consists of electric generation assets and the electric and gas distribution assets that serve the electric and gas customers of We Energies. During 2011, our regulated utility earned $544.8 million of operating income. Over the next three years, we expect to invest approximately $2.0 billion in this business to construct renewable generation and environmental projects at our electric generation assets, to update the electric and gas distribution infrastructure, and for other utility projects.

We have a $349.7 million investment in ATC, which represents a 26.2% ownership interest. Our 2011 pre-tax earnings from ATC totaled $62.5 million and we received $49.7 million in dividends from ATC. Over the next three years, we expect to invest approximately $29.4 million in ATC as it continues to upgrade the transmission infrastructure within Wisconsin.

Our non-utility energy segment consists primarily of the four generation plants constructed as part of our PTF strategy. All four plants have been placed in service and are being leased to Wisconsin Electric under long-term leases that run for 25 years (PWGS 1 and PWGS 2) and 30 years (OC 1 and OC 2). We recognize revenues on a levelized basis over the life of the lease. During 2012, we expect this segment's operating income to be between $345 million and $350 million. Over the next three years, we expect to invest approximately $75 million in this segment. The PTF strategy was developed with the primary goal of constructing the four power plants discussed above. With the completion of the final PTF unit, OC 2, in January 2011, we believe that our future capital expenditures in this segment will consist primarily of smaller capital projects within the existing PTF units.

40 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

RESULTS OF OPERATIONS

CONSOLIDATED EARNINGS

The following table compares our operating income by business segment and our net income for 2011, 2010 and 2009:

Wisconsin Energy Corporation	2011			2010			2009
	(Millions of Dollars)
Utility Energy	$	544.8		$	564.0		$	550.9
Non-Utility Energy	348.9			252.4			120.1
Corporate and Other	(6.4		)	(6.0		)	(10.7		)
Total Operating Income	887.3			810.4			660.3
Equity in Earnings of Transmission Affiliate	62.5			60.1			59.1
Other Income and Deductions, net	62.7			40.2			28.5
Interest Expense, net	235.8			206.4			156.7
Income from Continuing Operations Before Income Taxes	776.7			704.3			591.2
Income Tax Expense	263.9			249.9			215.5
Income from Continuing Operations	512.8			454.4			375.7
Income from Discontinued Operations, Net of Tax	13.4			2.1			6.7
Net Income	$	526.2		$	456.5		$	382.4
Diluted Earnings Per Share
Continuing Operations	$	2.18		$	1.92		$	1.59
Discontinued Operations	0.06			0.01			0.03
Total Diluted Earnings Per Share	$	2.24		$	1.93		$	1.62

An analysis of contributions to operating income by segment and a more detailed analysis of results follows.

UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

The following table summarizes our utility energy segment's operating income during 2011, 2010 and 2009:

Utility Energy Segment	2011		2010		2009
	(Millions of Dollars)
Operating Revenues
Electric	$	3,211.3	$	2,936.3	$	2,685.0
Gas	1,181.2		1,190.2		1,367.9
Other	39.0		38.8		39.1
Total Operating Revenues	4,431.5		4,165.3		4,092.0
Fuel and Purchased Power	1,174.5		1,104.7		1,064.5
Cost of Gas Sold	728.7		751.5		912.0
Gross Margin	2,528.3		2,309.1		2,115.5
Other Operating Expenses
Other Operation and Maintenance	1,613.4		1,587.0		1,372.3
Depreciation and Amortization	257.0		251.4		313.1
Property and Revenue Taxes	113.1		105.1		109.9
Total Operating Expenses	3,886.7		3,799.7		3,771.8
Amortization of Gain	—		198.4		230.7
Operating Income	$	544.8	$	564.0	$	550.9

41 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

2011 vs. 2010:   Our utility energy segment contributed $544.8 million of operating income during 2011 compared with $564.0 million of operating income during 2010. The decrease in operating income was primarily caused by increased other operation and maintenance expense and unfavorable weather during 2011 as compared to the prior year, partially offset by wholesale electric pricing increases and electric sales growth.

2010 vs. 2009:   Our utility energy segment contributed $564.0 million of operating income during 2010 compared with $550.9 million of operating income during 2009. The increase in operating income was primarily caused by favorable weather during 2010, partially offset by unfavorable recoveries of revenues associated with fuel and purchased power in 2010.

Electric Utility Gross Margin

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

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

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

Electric Utility Revenues and Sales

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

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

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

42 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

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

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

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

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

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

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

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

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

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

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

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

Electric Fuel and Purchased Power Expenses

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

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

Gas Utility Revenues, Gross Margin and Therm Deliveries

The following table compares our total gas utility operating revenues and gross margin (total gas utility operating revenues less cost of gas sold) during 2011, 2010 and 2009. Operating revenues and cost of gas sold has declined over the last three years due to the decline in the commodity cost of natural gas during this three year period.

43 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

Gas Utility Operations	2011		2010		2009
	(Millions of Dollars)
Operating Revenues	$	1,181.2	$	1,190.2	$	1,367.9
Cost of Gas Sold	728.7		751.5		912.0
Gross Margin	$	452.5	$	438.7	$	455.9

We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under GCRMs. The following table compares our gas utility gross margin and therm deliveries by customer class during 2011, 2010 and 2009:

	Gross Margin						Therm Deliveries
Gas Utility Operations	2011		2010		2009		2011	2010	2009
	(Millions of Dollars)						(Millions, Except Degree Days)
Customer Class
Residential	$	290.2	$	282.2	$	291.5	776.8	741.2	803.4
Commercial/Industrial	101.5		95.8		104.6		461.7	429.6	479.4
Interruptible	1.8		2.2		2.0		16.0	19.4	19.1
Total Retail	393.5		380.2		398.1		1,254.5	1,190.2	1,301.9
Transported Gas	52.6		51.3		49.6		899.6	914.9	882.0
Other Operating	6.4		7.2		8.2		—	—	—
Total	$	452.5	$	438.7	$	455.9	2,154.1	2,105.1	2,183.9
Weather - Degree Days (a)
Heating (6,615 Normal)							6,633	6,183	6,825

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

2011 vs. 2010:   Our gas margin increased by $13.8 million, or approximately 3.1%, when compared to 2010 primarily because of an increase in sales volumes as a result of colder winter weather in 2011 as compared to 2010. As measured by heating degree days, 2011 was 7.3% colder than 2010 and 0.3% colder than normal.

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

2010 vs. 2009:   Our gas margin decreased by $17.2 million, or approximately 3.8%, when compared to 2009 primarily because of a decline in sales volumes as a result of warmer winter weather in 2010 as compared to 2009. As measured by heating degree days, 2010 was 9.4% warmer than 2009 and 6.5% warmer than normal.

Other Operation and Maintenance Expense

2011 vs. 2010:   Our other operation and maintenance expense increased by $26.4 million, or approximately 1.7%, when compared to 2010. Higher maintenance costs at one of our natural gas peaking plants, increased spending on forestry work for our electric distribution system and increased costs associated with the amortization of deferred PTF costs related to wholesale and Michigan customers were the primary drivers of the increase.

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

44 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

2010 vs. 2009:   Our other operation and maintenance expense increased by $214.7 million, or approximately 15.6%, when compared to 2009. The 2010 PSCW rate case order allowed for pricing increases related to regulatory items including PTF lease costs, bad debt expense and amortization of other deferred costs. We estimate that these items were approximately $87.3 million higher in 2010 as compared to 2009. In addition, operation and maintenance expenses at our power plants increased approximately $63.9 million primarily because of the operation of OC 1, which was placed in service in February 2010, and higher maintenance costs at our other power plants. We also had increased operation and maintenance expenses of approximately $20.8 million related to increased reliability maintenance in our distribution system in 2010 and responding to damage caused by a larger number of summer storms compared to 2009. In addition, our benefits expense increased by approximately $28.8 million in 2010 as compared to 2009 primarily because of increased pension costs.

Depreciation and Amortization Expense

2011 vs. 2010:   Depreciation and Amortization expense increased by $5.6 million, or approximately 2.2%, when compared to 2010. This increase was primarily because of an overall increase in utility plant in service.

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

2010 vs. 2009:   Depreciation and Amortization expense decreased by $61.7 million, or approximately 19.7%, when compared to 2009. This decrease was primarily because of new depreciation rates that were implemented in connection with the 2010 PSCW rate case order. The new depreciation rates generally reflect longer lives for our utility assets.

Amortization of Gain

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

NON-UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Our non-utility energy segment consists primarily of our PTF units (PWGS 1, PWGS 2, OC 1 and OC 2). PWGS 1 and PWGS 2 were placed in service in July 2005 and May 2008, respectively. The common facilities associated with the Oak Creek expansion include the water intake system, which was placed in service in January 2009, the coal handling system, which was placed in service in November 2007, and other smaller assets. OC 1 and OC 2 were placed in service in February 2010 and January 2011, respectively.

The table below reflects:

• A full year's earnings for 2011, 2010 and 2009 for:

◦ PWGS 1;

◦ PWGS 2;

◦ the coal handling system for the Oak Creek expansion; and

◦ the water intake system for the Oak Creek expansion

• A full year's earnings for 2011 and approximately eleven months of earnings for 2010 for OC 1; and

• Approximately eleven and a half months of earnings for 2011 for OC 2.

45 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

This segment reflects the lease revenues on the new units as well as the depreciation expense. Operating and maintenance costs and limited management fees associated with the plants are the responsibility of Wisconsin Electric and are recorded in the utility segment.

	Year Ended December 31, 2011
	Port Washington		Oak Creek Expansion		All Other			Total
	(Millions of Dollars)
Operating Revenues	$	104.7	$	320.5	$	9.9		$	435.1
Operation and Maintenance Expense	0.8		4.6		8.3			13.7
Depreciation Expense	19.8		51.0		1.7			72.5
Operating Income (Loss)	$	84.1	$	264.9	$	(0.1	)	$	348.9

	Year Ended December 31, 2010
	Port Washington		Oak Creek Expansion		All Other		Total
	(Millions of Dollars)
Operating Revenues	$	104.6	$	203.3	$	12.3	$	320.2
Operation and Maintenance Expense	0.8		4.7		8.8		14.3
Depreciation Expense	19.8		32.0		1.7		53.5
Operating Income	$	84.0	$	166.6	$	1.8	$	252.4

	Year Ended December 31, 2009
	Port Washington		Oak Creek Expansion		All Other		Total
	(Millions of Dollars)
Operating Revenues	$	104.8	$	48.0	$	10.3	$	163.1
Operation and Maintenance Expense	0.9		5.2		7.7		13.8
Depreciation Expense	19.8		7.8		1.6		29.2
Operating Income	$	84.1	$	35.0	$	1.0	$	120.1

In 2012, we expect our non-utility energy segment to generate slightly higher operating income because OC 2 went into service on January 12, 2011 and changes in the depreciable lives of the plants.

CORPORATE AND OTHER CONTRIBUTION TO OPERATING INCOME

2011 vs. 2010:   Corporate and other affiliates had an operating loss of $6.4 million in 2011 compared with an operating loss of $6.0 million in 2010.

2010 vs. 2009:   Corporate and other affiliates had an operating loss of $6.0 million in 2010 compared with an operating loss of $10.7 million in 2009. This change is primarily due to a reduction in other operation and maintenance expense.

46 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

CONSOLIDATED OTHER INCOME AND DEDUCTIONS, NET

Other Income and Deductions, net	2011		2010		2009
	(Millions of Dollars)
AFUDC - Equity	$	59.4	$	32.5	$	16.0
Gain on Property Sales	2.4		4.4		1.7
Other, net	0.9		3.3		10.8
Total Other Income and Deductions, net	$	62.7	$	40.2	$	28.5

2011 vs. 2010:   Other income and deductions, net increased by approximately $22.5 million, or 56.0%, when compared to 2010. The increase in AFUDC - Equity is primarily related to the construction of the Oak Creek AQCS project and the Glacier Hills Wind Park.

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

2010 vs. 2009:   Other income and deductions, net increased by approximately $11.7 million, or 41.1%, when compared to 2009. This increase primarily relates to increased AFUDC - Equity related to the construction of the Oak Creek AQCS project.

CONSOLIDATED INTEREST EXPENSE, NET

Interest Expense, net	2011		2010		2009
	(Millions of Dollars)
Gross Interest Costs	$	262.5	$	258.7	$	235.4
Less: Capitalized Interest	26.7		52.3		78.7
Interest Expense, net	$	235.8	$	206.4	$	156.7

2011 vs. 2010:   Our gross interest costs increased by $3.8 million, or 1.5%, during 2011, primarily because of higher average long-term debt balances as compared to 2010. In January 2011, we issued $420 million of long-term debt and used the net proceeds to repay short-term debt incurred to finance the construction of OC 2 and for other corporate purposes. In September 2011, we issued $300 million of long-term debt and used the net proceeds to repay short-term debt and for other general corporate purposes. In April 2011, we retired $450 million of long-term debt that matured, which partially offset the debt issuances. Our capitalized interest decreased by $25.6 million primarily because we stopped capitalizing interest on OC 2 when it was placed in service in January 2011. As a result, our net interest expense increased by $29.4 million, or 14.2%, as compared to 2010.

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

2010 vs. 2009:   Our gross interest costs increased by $23.3 million, or 9.9%, during 2010, primarily because of higher long-term debt balances compared to 2009. In February 2010, we issued $530 million of long-term debt in connection with the commercial operation of OC 1 and used the net proceeds to repay short-term debt incurred during construction. Our capitalized interest decreased by $26.4 million primarily because we stopped capitalizing interest on OC 1 when it was placed in service in February 2010. As a result, our net interest expense increased by $49.7 million, or 31.7%, as compared to 2009.

47 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

CONSOLIDATED INCOME TAX EXPENSE

2011 vs. 2010:   Our effective tax rate applicable to continuing operations was 34.0% in 2011 compared to 35.5% in 2010. This reduction in our effective tax rate was primarily the result of increased AFUDC - Equity. For further information, see Note H -- Income Taxes in the Notes to Consolidated Financial Statements. We expect our 2012 annual effective tax rate to be between 36% and 37%.

2010 vs. 2009:   Our effective tax rate applicable to continuing operations was 35.5% in 2010 compared to 36.5% in 2009. This reduction in our effective tax rate was primarily the result of increased AFUDC - Equity and increased production activities tax deductions.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

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

Wisconsin Energy Corporation	2011			2010			2009
	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$	993.4		$	810.4		$	628.9
Investing Activities	$	(892.5	)	$	(633.5	)	$	(736.1	)
Financing Activities	$	(111.3	)	$	(172.6	)	$	95.7

Operating Activities

2011 vs. 2010:   Cash provided by operating activities was $993.4 million during 2011, which was an increase of $183.0 million over 2010. The largest increases in cash provided by operating activities related to higher net income, higher depreciation expense, higher deferred income tax benefits and the elimination of the amortization of the gain on the sale of Point Beach. Combined these items totaled $1,293.2 million during 2011 as compared to $680.4 million during 2010. The largest reduction in cash provided by operating activities related to our contributions to qualified benefit plans. During 2011, we contributed $277.4 million to our qualified benefit plans. We made no contributions to our qualified plans during 2010.

2010 vs. 2009:   Cash provided by operating activities was $810.4 million during 2010, which was an increase of $181.5 million over 2009. This increase is primarily related to a $289.3 million contribution to our qualified benefit plans in 2009. No such contributions were made in 2010. This increase was partially offset by an increase in cash paid for taxes during 2010.

Investing Activities

2011 vs. 2010:   Cash used in investing activities was $892.5 million during 2011, which was $259.0 million higher than 2010. This increase in cash used primarily reflects changes in restricted cash and increased capital expenditures. During 2011, our restricted cash increased by $37.2 million primarily because of the nuclear fuel settlement we received from the DOE. During 2010, our restricted cash decreased by $186.2 million due to the release of restricted cash related to the Point Beach bill credits. See Nuclear Operations in this report for additional information regarding the settlement with the DOE. In addition, capital expenditures increased by approximately $32.6 million during 2011 as compared to 2010 primarily due to increased spending related to the construction of the Oak Creek AQCS project and the Glacier Hills Wind Park in 2011 as compared to 2010.

48 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

The following table identifies capital expenditures by year:

Capital Expenditures	2011		2010		2009
	(Millions of Dollars)
Utility	$	792.2	$	687.0	$	547.0
We Power	31.2		109.3		253.2
Other	7.4		1.9		14.4
Total Capital Expenditures	$	830.8	$	798.2	$	814.6

2010 vs. 2009:   Cash used in investing activities was $633.5 million during 2010, which was $102.6 million lower than the same period in 2009 because of lower capital expenditures, lower investments in ATC and higher proceeds from asset sales. During 2010, we received $63 million of proceeds from the sale of Edison Sault.

Financing Activities

The following table summarizes our cash flows from financing activities:

	2011			2010			2009
	(Millions of Dollars)
Net Increase in Debt	$	265.4		$	71.1		$	263.2
Dividends on Common Stock	(242.0		)	(187.0		)	(157.8		)
Common Stock Repurchased, Net	(139.5		)	(65.7		)	(12.6		)
Other	4.8			9.0			2.9
Cash (Used in) Provided by Financing	$	(111.3	)	$	(172.6	)	$	95.7

2011 vs. 2010:   Cash used in financing activities was $111.3 million during 2011, compared to $172.6 million during 2010. During 2011, we issued a total of $720.0 million of long-term debt and retired $466.6 million of long-term debt. The net proceeds from the new issuance of debt were used to repay short-term debt and for other corporate purposes. For additional information on the debt issuances, see Note J -- Long-Term Debt and Capital Lease Obligations in the Notes to Consolidated Financial Statements.

Our common stock dividends increased in 2011 as we raised our dividend rate by 30.0%. In January 2012, our Board of Directors approved an increase of approximately 15.4% in the quarterly common stock dividend.

In addition, on May 5, 2011, our Board of Directors authorized a share repurchase program for up to $300 million of our common stock through the end of 2013. Funds for the repurchases are expected to come from internally generated funds and working capital supplemented, if required in the short-term, by the sale of commercial paper. The repurchase program does not obligate Wisconsin Energy to acquire any specific number of shares and may be suspended or terminated by the Board of Directors at any time. Through December 31, 2011, we repurchased approximately 3.2 million shares in the open market pursuant to this program at an average cost of $30.79 per share and a total cost of $100.0 million.

2010 vs. 2009:   Cash used in financing activities during 2010 was $172.6 million, compared to $95.7 million of cash provided in 2009. During 2010, we issued a total of $530.0 million of long-term debt and retired $291.7 million of long-term debt. The net proceeds from the new issuance of debt were used to repay short-term debt incurred to finance the construction of OC 1 and for other corporate purposes.

Our common stock dividends increased in 2010 as we raised our dividend rate by 18.5%.

No new shares of Wisconsin Energy's common stock were issued in 2011, 2010 or 2009. During these years, our plan agents purchased, in the open market, 3.0 million shares at a cost of $93.9 million, 5.8 million shares at a cost of $156.6 million and 1.4 million shares at a cost of $29.6 million, respectively, to fulfill exercised stock options and restricted stock awards. In 2011, 2010 and 2009, we received proceeds of $54.4 million, $90.9 million and

49 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

$17.0 million, respectively, related to the exercise of stock options. In addition, we instructed our independent agents to purchase shares of our common stock in the open market to satisfy our obligations under our dividend reinvestment plan and various employee benefit plans.

CAPITAL RESOURCES AND REQUIREMENTS

Liquidity

We anticipate meeting our capital requirements during 2012 and beyond primarily through internally generated funds and short-term borrowings, supplemented by the issuance of intermediate or long-term debt securities depending on market conditions and other factors.

We currently have access to the capital markets and have been able to generate funds internally and externally to meet our capital requirements. Our ability to attract the necessary financial capital at reasonable terms is critical to our overall strategic plan. We currently believe that we have adequate capacity to fund our operations for the foreseeable future through our existing borrowing arrangements, access to capital markets and internally generated cash.

Wisconsin Energy, Wisconsin Electric and Wisconsin Gas maintain bank back-up credit facilities, which provide liquidity support for each company's obligations with respect to commercial paper and for general corporate purposes.

As of December 31, 2011, we had approximately $1.2 billion of available, undrawn lines under our bank back-up credit facilities that were entered into in December 2010. As of December 31, 2011, we had approximately $669.9 million of commercial paper outstanding on a consolidated basis that was supported by the available lines of credit. During 2011, our maximum commercial paper outstanding was $717.3 million with a weighted-average interest rate of 0.25%. For additional information regarding our commercial paper balances during 2011, see Note K -- Short-Term Debt in the Notes to Consolidated Financial Statements.

We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. The following table summarizes such facilities as of December 31, 2011:

Company	Total Facility		Letters of Credit		Credit Available		Facility Expiration
	(Millions of Dollars)
Wisconsin Energy	$	450.0	$	0.4	$	449.6	December 2013
Wisconsin Electric	$	500.0	$	5.9	$	494.1	December 2013
Wisconsin Gas	$	300.0	$	—	$	300.0	December 2013

Each of these facilities has a renewal provision for two one-year extensions, subject to lender approval.

The following table shows our capitalization structure as of December 31, 2011 and 2010, as well as an adjusted capitalization structure that we believe is consistent with the manner in which the rating agencies currently view the Junior Notes:

50 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

	2011						2010
Capitalization Structure	Actual			Adjusted			Actual			Adjusted
	(Millions of Dollars)
Common Equity	$	3,963.3		$	4,213.3		$	3,802.1		$	4,052.1
Preferred Stock of Subsidiary	30.4			30.4			30.4			30.4
Long-Term Debt (including current maturities)	4,646.9			4,396.9			4,405.4			4,155.4
Short-Term Debt	669.9			669.9			657.9			657.9
Total Capitalization	$	9,310.5		$	9,310.5		$	8,895.8		$	8,895.8
Total Debt	$	5,316.8		$	5,066.8		$	5,063.3		$	4,813.3
Ratio of Debt to Total Capitalization	57.1		%	54.4		%	56.9		%	54.1		%

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

Included in Long-Term Debt on our Consolidated Balance Sheet as of December 31, 2011 and 2010 is $500 million aggregate principal amount of the Junior Notes. The adjusted presentation attributes $250 million of the Junior Notes to Common Equity and $250 million to Long-Term Debt. We believe this presentation is consistent with the 50% or greater equity credit the majority of rating agencies currently attribute to the Junior Notes.

The adjusted presentation of our consolidated capitalization structure is presented as a complement to our capitalization structure presented in accordance with GAAP. Management evaluates and manages Wisconsin Energy's capitalization structure, including its total debt to total capitalization ratio, using the GAAP calculation as adjusted by the rating agency treatment of the Junior Notes. Therefore, we believe the non-GAAP adjusted presentation reflecting this treatment is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.

As described in Note I -- Common Equity, in the Notes to Consolidated Financial Statements, certain restrictions exist on the ability of our subsidiaries to transfer funds to us. We do not expect these restrictions to have any material effect on our operations or ability to meet our cash obligations.

Wisconsin Electric is the obligor under two series of tax exempt pollution control refunding bonds in outstanding principal amounts of $147 million. In August 2009, Wisconsin Electric terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. Wisconsin Electric issued commercial paper to fund the purchase of the bonds. As of December 31, 2011, the repurchased bonds were still outstanding, but were reported as a reduction in our consolidated long-term debt because they are held by Wisconsin Electric. Depending on market conditions and other factors, Wisconsin Electric may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.

Bonus Depreciation Provisions

In December 2010, the President of the United States signed tax legislation extending the bonus depreciation rules to certain projects placed in service in 2010, 2011 and 2012. As a result of this extension, we recognized increased federal tax depreciation in 2010 and 2011 relating to assets placed in service during those years, including the Glacier Hills Wind Park, OC 1 and OC 2. In addition, we also anticipate an increase in tax depreciation in 2012 for assets placed in service during 2012, including the Oak Creek AQCS project. As a result of the increased tax depreciation in 2011 and 2012, we will not make federal income tax payments for 2011 and do not anticipate making federal income tax payments for 2012.

51 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

Credit Rating Risk

We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. We do have certain agreements in the form of commodity contracts and employee benefit plans that could require collateral or a termination payment in the event of a credit rating change to below BBB- at S&P and/or Baa3 at Moody's. As of December 31, 2011, we estimate that the collateral or the termination payments required under these agreements totaled approximately $184.5 million. Generally, collateral may be provided by a Wisconsin Energy guaranty, letter of credit or cash. We also have commodity contracts that in the event of a credit rating downgrade could result in a reduction of our unsecured credit granted by counterparties.

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

In November 2011, Moody's affirmed the ratings of Wisconsin Gas (commercial paper, P-1; senior unsecured, A2). In December 2011, Moody's affirmed the ratings of Wisconsin Energy (commercial paper, P-2; senior unsecured, A3; junior unsecured, Baa1), Wisconsin Electric (commercial paper, P-1; senior unsecured, A2), ERGSS (senior notes, A2) and WECC (senior unsecured, A3). Moody's affirmed the stable ratings outlook assigned to each company.

In June 2011, S&P raised the rating of Wisconsin Energy's junior unsecured debt to BBB from BBB-, and affirmed the ratings of the remaining debt of Wisconsin Energy (commercial paper, A-2; senior unsecured, BBB+), Wisconsin Electric (commercial paper, A-2; senior unsecured, A-), Wisconsin Gas (commercial paper, A-2; senior unsecured, A-) and ERGSS (senior notes, A-). S&P also revised the ratings outlooks assigned to each company from positive to stable in June 2011, after revising the ratings outlooks of each company from stable to positive in March 2011.

In June 2011, Fitch affirmed the ratings of Wisconsin Energy (commercial paper, F2; senior unsecured, A-; junior unsecured, BBB), Wisconsin Electric (commercial paper, F1; senior unsecured, A+), Wisconsin Gas (commercial paper, F1; senior unsecured, A+), ERGSS (senior notes, A+) and WECC (senior unsecured, A-). Fitch also affirmed the stable ratings outlooks assigned to each company.

Subject to other factors affecting the credit markets as a whole, we believe our current ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agencies only. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency.

Capital Requirements

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

Capital Expenditures	2012		2013		2014
	(Millions of Dollars)
Utility
Renewable	$	160.6	$	24.4	$	—
Environmental	71.0		43.3		38.8
Base Spending	473.2		611.0		586.4
Total Utility	704.8		678.7		625.2
We Power	20.1		41.4		16.5
Other	15.3		9.3		1.7
Total	$	740.2	$	729.4	$	643.4

Base spending primarily consists of upgrading our electric and gas distribution systems. Our actual future long-term capital requirements may vary from these estimates because of changing environmental and other regulations such

52 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

as air quality standards, renewable energy standards and electric reliability initiatives that impact our utility energy segment.

Common Stock Matters:   During 2012, we expect to continue to repurchase our common stock under the share repurchase program approved by the Board on May 5, 2011, and to pay the increased quarterly dividend of $0.30 per share approved by the Board in January 2012.

Investments in Outside Trusts:   We use outside trusts to fund our pension and certain other post-retirement obligations. These trusts had investments of approximately $1.5 billion as of December 31, 2011. These trusts hold investments that are subject to the volatility of the stock market and interest rates.

During 2011, we contributed $236.4 million to our qualified pension plans and $41.0 million to our qualified Other Post-Retirement Employee Benefit (OPEB) plans. We did not make contributions to the plans during 2010 as they were adequately funded. Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates. For additional information, see Note N -- Benefits in the Notes to Consolidated Financial Statements.

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

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

	Payments Due by Period
Contractual Obligations (a)	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
	(Millions of Dollars)
Long-Term Debt Obligations (b)	$	8,245.2	$	273.1	$	1,181.6	$	891.1	$	5,899.4
Capital Lease Obligations (c)	295.1		38.9		82.3		88.6		85.3
Operating Lease Obligations (d)	63.3		16.3		10.4		7.6		29.0
Purchase Obligations (e)	13,473.1		974.1		1,446.1		1,072.4		9,980.5
Other Long-Term Liabilities (f)	111.4		110.3		0.8		0.3		—
Total Contractual Obligations	$	22,188.1	$	1,412.7	$	2,721.2	$	2,060.0	$	15,994.2

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

(b) Principal and interest payments on Long-Term Debt (excluding capital lease obligations). For the purpose of determining our contractual obligations and commercial commitments only, we assumed the Junior Notes would be retired in 2017 with the proceeds from the issuance of qualifying securities pursuant to the terms of the Replacement Capital Covenant (RCC).

(c) Capital Lease Obligations of Wisconsin Electric for power purchase commitments.

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

(e) Purchase Obligations under various contracts for the procurement of fuel, power, gas supply and associated transportation related to utility operations and for construction, information technology and other services for utility and We Power operations. This includes the power purchase agreement for Point Beach.

(f) Other Long-Term Liabilities includes the expected 2012 supplemental executive retirement plan obligation. For additional information on employer contributions to our benefit plans, see Note N -- Benefits in the Notes to Consolidated Financial Statements.

53 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

The table above does not include liabilities related to the accounting treatment for uncertainty in income taxes because we are not able to make a reasonably reliable estimate as to the amount and period of related future payments at this time. For additional information regarding these liabilities, refer to Note H -- Income Taxes in the Notes to Consolidated Financial Statements in this report.

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

FACTORS AFFECTING RESULTS, LIQUIDITY AND CAPITAL RESOURCES

MARKET RISKS AND OTHER SIGNIFICANT RISKS

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

Regulatory Recovery:   Our utility energy segment accounts for its regulated operations in accordance with accounting guidance for regulated entities. Our rates are determined by regulatory authorities. Our primary regulator is the PSCW. Regulated entities are allowed to defer certain costs that would otherwise be charged to expense, if the regulated entity believes the recovery of these costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators, and recovery of these deferred costs in future rates is subject to the review and approval of those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of these costs is not approved by our regulators, the costs are charged to income in the current period. We expect to recover our outstanding regulatory assets in rates over a period of no longer than 20 years. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. As of December 31, 2011, our regulatory assets totaled $1,265.7 million and our regulatory liabilities totaled $915.9 million.

Commodity Prices:   In the normal course of providing energy, we are subject to market fluctuations of the costs of coal, natural gas, purchased power and fuel oil used in the delivery of coal. We manage our fuel and gas supply costs through a portfolio of short and long-term procurement contracts with various suppliers for the purchase of coal, natural gas and fuel oil. In addition, we manage the risk of price volatility by utilizing gas and electric hedging programs.

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

Natural Gas Costs:   Higher natural gas costs increase our working capital requirements and result in higher gross receipts taxes in the state of Wisconsin. Higher natural gas costs combined with slower economic conditions also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills. Higher natural gas costs may also lead to increased energy efficiency investments by our customers to reduce utility usage and/or fuel substitution.

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

As a result of GCRMs, our gas utility operations receive dollar for dollar recovery on the cost of natural gas. However, increased natural gas costs increase the risk that customers will switch to alternative fuel sources, which could reduce future gas margins. For information concerning the natural gas utilities' GCRMs, see Utility Rates and Regulatory Matters.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

Weather:   Our Wisconsin utility rates are set by the PSCW based upon estimated temperatures which approximate 20-year averages. Wisconsin Electric's electric revenues and sales are unfavorably sensitive to below normal temperatures during the summer cooling season, and to some extent, to above normal temperatures during the winter heating season. Our gas revenues and sales are unfavorably sensitive to above normal temperatures during the winter heating season. A summary of actual weather information in the utility segment's service territory during 2011, 2010 and 2009, as measured by degree days, may be found above in Results of Operations.

Interest Rate:We have various short-term borrowing arrangements to provide working capital and general corporate funds. We also have variable rate long-term debt outstanding as of December 31, 2011. Borrowing levels under these arrangements vary from period to period depending on capital investments and other factors. Future short-term interest expense and payments will reflect both future short-term interest rates and borrowing levels.

We performed an interest rate sensitivity analysis as of December 31, 2011 of our outstanding portfolio of commercial paper and variable rate long-term debt. As of December 31, 2011, we had $669.9 million of commercial paper outstanding with a weighted average interest rate of 0.27% and $147.0 million of variable-rate long-term debt outstanding with a weighted average interest rate of 0.50%. A one-percentage point change in interest rates would cause our annual interest expense to increase or decrease by approximately $8.2 million.

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

The fair value of our trust fund assets as of December 31, 2011 was approximately:

Wisconsin Energy Corporation	Millions of Dollars
Pension trust funds	$	1,262.5
Other post-retirement benefits trust funds	$	255.4

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

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

We consult with our investment advisors on an annual basis to help us forecast expected long-term returns on plan assets by reviewing actual historical returns and calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund.

Economic Conditions:   Our service territory is within the state of Wisconsin and the Upper Peninsula of Michigan. We are exposed to market risks in the regional midwest economy.

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

For additional information concerning risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report and Risk Factors in Item 1A.

55 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

POWER THE FUTURE

All of the PTF units have been placed into service and are positioned to provide a significant portion of our future generation needs. The PTF units include PWGS 1, PWGS 2, OC 1 and OC 2. The following table identifies certain key items related to the units:

Unit Name	In Service	Cash Costs (a)
PWGS 1	July 2005	$333 million
PWGS 2	May 2008	$331 million
OC 1	February 2010	$1,354 million
OC 2	January 2011	$662 million

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

We are recovering our costs in these units through lease payments associated with PWGS 1, PWGS 2 and OC 1 that are billed from We Power to Wisconsin Electric and then recovered in Wisconsin Electric's rates as authorized by the PSCW, the MPSC and FERC. Wisconsin Electric is recovering the lease payments associated with OC 2 as authorized by the PSCW and FERC, and has requested authorization from the MPSC in the rate case filed in July 2011. Under the lease terms, our return is calculated using a 12.7% return on equity and the equity ratio is assumed to be 53% for the PWGS Units and 55% for the Oak Creek Units. The interest component of the return has been determined at rates in effect at the time of commercial operation.

Background:The PSCW issued orders granting CPCNs for the construction of the PWGS and the Oak Creek expansion in 2002 and 2003, respectively.

PWGS consists of two natural gas-fired combined cycle generating units on the site of Wisconsin Electric's former Port Washington Power Plant, the natural gas lateral to supply the new plant, and the transmission system upgrades required of ATC. PWGS 1 and PWGS 2 were completed within the PSCW approved cost parameters and were placed in service in July 2005 and May 2008, respectively.

The Oak Creek expansion consists of two coal-fired generating units located adjacent to the site of Wisconsin Electric's existing Oak Creek Power Plant. OC 1 and OC 2 were placed into service on February 2, 2010 and January 12, 2011, respectively. The PSCW set the total cost for the two units at $2.191 billion. We estimate that the final cost of the Oak Creek expansion is approximately $181 million, or 8.3%, over the amount initially approved by the PSCW, of which our share is approximately $154 million. The additional amount includes the amounts payable to Bechtel pursuant to the Settlement Agreement. The order approving the Oak Creek expansion provides for recovery of excess costs of up to 5% of the total project, subject to a prudence review by the PSCW. Costs above the 5% cap would also be included in lease payments and recovered from customers if the PSCW finds that such costs were prudently incurred and were the result of force majeure conditions, an excused event and/or event of loss. In addition, the leases provided for a guaranteed in-service date of September 29, 2009 for OC 1 and September 29, 2010 for OC 2, and imposed liquidated damages of $250,000 per day, of which ERGSS' share is approximately $208,350 per day, for failure to achieve the guaranteed in-service date unless the delays resulted from force majeure conditions or an excused event. In light of the weather delays incurred on the project and other factors, we expect to request authorization from the PSCW to recover all costs associated with the units and to grant relief from liquidated damages.

ERGSS was entitled to receive its share of $250,000 per day from Bechtel under the contract with Bechtel for each day Bechtel failed to achieve the guaranteed in-service dates of September 29, 2009 and September 29, 2010, unless the delays resulted from force majeure conditions or excused events. Pursuant to the terms of the Settlement Agreement and a change order signed concurrent with the turnover of OC 2, Bechtel was granted total schedule relief of 120 days for OC 1 and 81 days for OC 2. Therefore, Bechtel was responsible for 5 days of liquidated damages for OC 1 and 23 days for OC 2. All liquidated damages collected are for the benefit of Wisconsin Electric's customers. Although we anticipate the PSCW will agree that the excused delays were caused by force majeure and other conditions, there is no guarantee that it will grant ERGSS the same schedule relief.

56 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

For information regarding the Settlement Agreement, see Oak Creek Construction Contract in Note R -- Commitments and Contingencies in the Notes to Consolidated Financial Statements.

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

PWGS 1 & PWGS 2

• Initial lease term of 25 years with the potential for subsequent renewals at reduced rates;

• Cost recovery over a 25 year period on a mortgage basis amortization schedule;

• Imputed capital structure of 53% equity, 47% debt;

• Authorized rate of return of 12.7% after tax on equity;

• Fixed construction cost of PWGS 1 and PWGS 2 at $309.6 million and $280.3 million (2001 dollars) subject to escalation at the GDP inflation rate;

• Recovery of carrying costs during construction; and

• Ongoing PSCW supervisory authority over those lease terms and conditions specifically identified in the order, which do not include the key financial terms.

OC 1 & OC 2

• Initial lease term of 30 years with the potential for subsequent renewals at reduced rates;

• Cost recovery over a 30 year period on a mortgage basis amortization schedule;

• Imputed capital structure of 55% equity, 45% debt;

• Authorized rate of return of 12.7% after tax on equity;

• Recovery of carrying costs during construction; and

• Ongoing PSCW supervisory authority over those lease terms and conditions specifically identified in the order, which do not include the key financial terms.

UTILITY RATES AND REGULATORY MATTERS

The PSCW regulates our retail electric, natural gas and steam rates in the state of Wisconsin, while FERC regulates our wholesale power, electric transmission and interstate gas transportation service rates. The MPSC regulates our retail electric rates in the state of Michigan. Within our regulated segment, we estimate that approximately 86% of our electric revenues are regulated by the PSCW, 7% are regulated by the MPSC and the balance of our electric revenues is regulated by FERC. In Wisconsin, a general rate case is typically filed every two years. All of our natural gas and steam revenues are regulated by the PSCW. Orders from the PSCW can be viewed at http://psc.wi.gov/ and orders from the MPSC can be viewed at www.michigan.gov/mpsc/.

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

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

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

• Authorizes the refund of $26 million of net proceeds from Wisconsin Electric's settlement of the spent nuclear fuel litigation with the DOE.

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

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

On October 6, 2011, the PSCW approved our proposal as filed. We received a final written order from the PSCW on

57 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

November 3, 2011. For information related to the proceeding to establish a 2012 fuel cost plan, see 2012 Fuel Recovery Request below. We expect to initiate a traditional rate case filing in early 2012 for new electric, gas and steam rates to be effective in January 2013.

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

2010 Wisconsin Rate Case:   In March 2009, Wisconsin Electric and Wisconsin Gas initiated rate proceedings with the PSCW. Wisconsin Electric initially asked the PSCW to approve a rate increase for its Wisconsin retail electric customers of approximately $76.5 million, or 2.8%, and a rate increase for its natural gas customers of approximately $22.1 million, or 3.6%. In addition, Wisconsin Electric requested increases of approximately $1.4 million, or 5.8%, and approximately $1.3 million, or 6.8%, for its Milwaukee Downtown (Valley) steam utility customers and Milwaukee County steam utility customers, respectively. Wisconsin Gas asked the PSCW to approve a rate increase for its natural gas customers of approximately $38.9 million, or 4.6%.

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

In December 2009, the PSCW authorized rate adjustments related to Wisconsin Electric's and Wisconsin Gas' requests to increase electric, natural gas and steam rates. The PSCW approved the following rate adjustments:

• An increase of approximately $85.8 million (3.35%) in retail electric rates for Wisconsin Electric, which was partially offset by bill credits in 2010 and included a decrease in base fuel revenues of approximately $111.0 million, or a fuel rate component decrease of 13.8%;

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

• An increase of approximately $5.7 million (0.70%) for natural gas service for Wisconsin Gas; and

• A decrease of approximately $0.4 million (1.65%) for Wisconsin Electric's Valley steam utility customers and a decrease of approximately $0.1 million (0.47%) for its Milwaukee County steam utility customers.

These rate adjustments became effective January 1, 2010. In addition, the PSCW lowered the authorized return on equity for Wisconsin Electric from 10.75% to 10.4% and for Wisconsin Gas from 10.75% to 10.5%.

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

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

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

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

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

58 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

2010 Michigan Rate Increase Request:   In July 2009, Wisconsin Electric filed a $42 million rate increase request with the MPSC, primarily to recover the costs of PTF projects. In December 2009, the MPSC approved Wisconsin Electric's modified self-implementation plan to increase electric rates in Michigan by approximately $12 million, effective upon commercial operation of OC 1, which occurred on February 2, 2010. On July 1, 2010, the MPSC issued the final order, approving an additional increase of $11.5 million effective July 2, 2010. The combined total increase is $23.5 million annually, or 14.2%. In August 2010, our largest customers, two iron ore mines, filed an appeal with the MPSC regarding this rate order. In October 2010, the MPSC ruled on the mines' appeal and reduced the rate increase by approximately $0.3 million annually, effective November 1, 2010. In November 2010, the mines filed a Claim of Appeal of the October 2010 order with the Michigan Court of Appeals. In December 2010, the MPSC filed a Motion for Remand with the Court of Appeals. In March 2011, the Court of Appeals denied the Motion for Remand. All briefs have been filed and the case is awaiting scheduling of oral argument, which we expect to occur in the first quarter of 2012.

Limited Rate Adjustment Requests

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

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

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

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

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

Other Utility Rate Matters

Oak Creek Air Quality Control System Approval:   In July 2008, we received approval from the PSCW granting Wisconsin Electric authority to construct wet flue gas desulfurization and selective catalytic reduction facilities at Oak Creek Power Plant units 5-8. Construction of these emission controls began in late July 2008, and we expect the installation to be completed during 2012. We currently expect the cost of completing this project to be approximately $750 million ($900 million including AFUDC). The cost of constructing these facilities has been included in our previous estimates of the costs to implement the Consent Decree with the EPA.

Wisconsin Fuel Rules:   Embedded within Wisconsin Electric's base rates is an amount to recover fuel costs. New fuel rules adopted in December 2010 require the company to defer, for subsequent rate recovery or refund, any

59 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

under-collection or over-collection of fuel costs that are outside of the utility's symmetrical fuel cost tolerance, which the PSCW set at plus or minus 2% of the utility's approved fuel cost plan. Fuel cost plans approved by the PSCW after January 1, 2011 are subject to the new rules. The deferred fuel costs are subject to an excess revenues test.

Electric Transmission Cost Recovery:   Wisconsin Electric divested its transmission assets with the formation of ATC in January 2001. We now procure transmission service from ATC at FERC approved tariff rates. In connection with the formation of ATC, our transmission costs have escalated due to the socialization of costs within ATC and increased transmission infrastructure requirements in the state. In 2002, in connection with the increased costs experienced by our customers, the PSCW issued an order which allowed us to use escrow accounting whereby we deferred transmission costs that exceeded amounts embedded in our rates. We were allowed to earn a return on the unrecovered transmission costs we deferred at our weighted-average cost of capital. As of December 31, 2011, we had $118.3 million of unrecovered transmission costs. The escrow accounting treatment has been discontinued as our 2008 and 2010 PSCW rate orders have provided for recovery of these costs.

Gas Cost Recovery Mechanism:   Our natural gas operations operate under GCRMs as approved by the PSCW. Generally, the GCRMs allow for a dollar for dollar recovery of gas costs. As part of its January 2010 rate order, the PSCW approved changes to the GCRMs. The GCRMs now use a modified one for one method that measures commodity purchase costs against a monthly benchmark which includes a 2% tolerance. Costs in excess of this monthly benchmark are subject to additional review by the PSCW before they can be passed through to our customers. The modified one for one is the same method used by the other utilities in Wisconsin.

Depreciation Rates:   In January 2009, we filed a depreciation study with the PSCW, proposing new depreciation rates that would reduce annual depreciation expense by approximately $55 million. The PSCW approved the depreciation study and the new depreciation rates began on January 1, 2010. We estimate that the new depreciation rates did not have a material impact on earnings because the new depreciation rates were considered when the PSCW set our 2010 electric and gas rates.

Renewables, Efficiency and Conservation:In March 2006, Wisconsin revised the requirements for renewable energy generation by enacting Act 141. Act 141 defines "baseline renewable percentage" as the average of an energy provider's renewable energy percentage for 2001, 2002 and 2003. A utility's renewable energy percentage is equal to the amount of its total retail energy sales that are provided by renewable sources. Wisconsin Electric's baseline renewable energy percentage is 2.27%. Under Act 141, Wisconsin Electric could not decrease its renewable energy percentage for the years 2006-2009, and for the years 2010-2014, it must increase its renewable energy percentage at least two percentage points to a level of 4.27%. As of December 31, 2011, we are in compliance with the Wisconsin renewable energy percentage of 4.27%. Act 141 further requires that for the year 2015 and beyond, the renewable energy percentage must increase at least six percentage points above the baseline to a level of 8.27%. Act 141 establishes a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. To comply with increasing requirements, Wisconsin Electric has constructed and contracted for several hundred megawatts of wind generation and is in the process of constructing approximately 50 MW of biomass fueled generation. With the commercial operation of the Glacier Hills Wind Park in December 2011 and assuming the biomass project is completed on schedule, we expect to be in compliance with Act 141 through the year 2016. To remain in compliance with Act 141, we would need to construct or contract for the equivalent of approximately 400 MW of additional wind generating capacity beyond 2016. See Renewable Energy Portfolio discussion below for additional information regarding the development of renewable energy generation.

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

Act 141 also redirects the administration of energy efficiency, conservation and renewable programs from the

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

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

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

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

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

ELECTRIC SYSTEM RELIABILITY

In response to customer demand for higher quality power required by modern equipment, we are evaluating and updating our electric distribution system. We are taking steps to reduce the likelihood of outages by upgrading substations and rebuilding lines to upgrade voltages and reliability. These improvements, along with better technology for analysis of our existing system, better resource management to speed restoration and improved customer communication, are near-term efforts to enhance our current electric distribution infrastructure. For the long-term, we have developed a distribution system asset management strategy that requires increased levels of automation of both substations and line equipment to consistently provide the level of reliability needed for a digital economy.

We had adequate capacity to meet all of our firm electric load obligations during 2011 and 2010. All of our generating plants performed well during the warmest periods of the summer and all power purchase commitments under firm contract were received. During this period, public appeals for conservation were not required and we did not interrupt or curtail service to non-firm customers who participate in load management programs. We expect to have adequate capacity to meet all of our firm load obligations during 2012. However, extremely hot weather, unexpected equipment failure or unavailability could require us to call upon load management procedures.

ENVIRONMENTAL MATTERS

Overview

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting our utility and non-utility energy segments include but are not limited to current and future regulation of: (1) air emissions such as SO₂, NO_x, fine particulates, mercury and greenhouse gas emissions; (2) water discharges; (3) disposal of coal combustion by-products such as fly ash; and (4) remediation of impacted properties, including former manufactured gas plant sites.

We are continuing to pursue a proactive strategy to manage our environmental compliance obligations, including: (1) developing additional sources of renewable electric energy supply; (2) reviewing water quality matters such as

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discharge limits and cooling water requirements and implementing improvements to our cooling water intake systems as needed; (3) adding emission control equipment to existing facilities to comply with new ambient air quality standards and federal clean air rules; (4) implementing a Consent Decree with the EPA to reduce emissions of SO₂ and NO_x by more than 65% by 2013; (5) continuing the beneficial use of ash and other solid products from coal-fired generating units; and (6) conducting the clean-up of former manufactured gas plant sites.

Air Quality

EPA Consent Decree:   In April 2003, Wisconsin Electric reached a Consent Decree with the EPA, in which it agreed to significantly reduce air emissions from certain of its coal-fired generating facilities. The U.S. District Court for the Eastern District of Wisconsin approved the amended Consent Decree and entered it in October 2007. The Consent Decree was further amended in January 2012 to change the point of air monitoring at the Oak Creek Power Plant to accommodate the AQCS scheduled to begin service in 2012. For further information, see Note R -- Commitments and Contingencies in the Notes to Consolidated Financial Statements.

8-hour Ozone Standard:   In April 2004, the EPA designated 10 counties in southeastern Wisconsin as non-attainment areas for the 8-hour ozone ambient air quality standard. The EPA has since redesignated three of these counties - Kewaunee, Manitowoc and Door - in attainment with the standard, and has made a finding that the remaining seven counties have achieved attainment with the standard. The EPA has stated, however, that Wisconsin must revise a portion of its State Implementation Plan (SIP) relating to volatile organic compounds, which do not apply to our facilities, before these seven counties can be formally redesignated. Pending redesignation, we will continue to be subject to more stringent permitting standards for new or revised facilities in the affected seven counties.

In March 2008, the EPA announced its decision to further lower the 8-hour ozone standard, and in January 2010, the EPA proposed to lower that standard further. However, in September 2011, President Obama requested the EPA to delay the reconsideration of the 8-hour ozone standard until 2013, and the EPA began implementing the 2008 standard. The EPA has stated that it plans to finalize the designations under the 2008 ozone standard by May 31, 2012. The EPA has preliminarily designated Waukesha, Washington, Milwaukee and Racine Counties as being in attainment with the standard. Currently, the only counties in Wisconsin that are proposed for non-attainment are Kenosha and Sheboygan Counties.

Fine Particulate Standard:   In December 2006, a more restrictive federal standard for fine particulate matter (PM_2.5) became effective; however, in February 2009, the U.S. Court of Appeals for the D.C. Circuit issued a decision on the revised standard and remanded it back to the EPA for revision. In October 2009, the EPA designated three counties in southeast Wisconsin (Milwaukee, Waukesha and Racine) as not meeting the 2006 daily standard for PM_2.5. Wisconsin has submitted a request to the EPA to redesignate these three counties as being in attainment with the 2006 standard. If the EPA denies this request, Wisconsin will be required to develop a SIP and submit it to the EPA for approval, and will need to implement actions to reach attainment in the 2014-2019 time period. The impact of future SIP requirements on our operations, if any, cannot be determined at this time, particularly given the EPA's continued efforts to revise the 2006 standard in light of the D.C. Circuit Court's decision.

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

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

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

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

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

Mercury and Other Hazardous Air Pollutants:   On December 16, 2011, the EPA issued the final utility MACT rule (referred to as the MATS rule), which imposes stringent limitations on numerous hazardous air pollutants, including mercury, from coal and oil-fired electric generating units. While we are continuing to evaluate the impact of the rule on the operation of our existing coal-fired generation facilities, as well as alternatives for complying with the rule, we currently estimate our cost to comply with this rule will be approximately $16 million. Based upon our review, the VAPP and Presque Isle Power Plant may require additional modifications. In addition, we believe that our clean air strategy, including the environmental upgrades that have already been constructed and that are currently under construction at our other plants, positions those plants well to meet the rule's requirements.

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

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

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

Clean Air Visibility Rule:   The EPA issued the Clean Air Visibility Rule (CAVR) in June 2005 to address Regional Haze, or regionally-impaired visibility caused by multiple sources over a wide area. The rule defines Best Available Retrofit Technology (BART) requirements for electric generating units and how BART will be addressed in the 28 states subject to EPA's CAIR. The pollutants from power plants that reduce visibility include PM_2.5 or compounds that contribute to fine particulate formation, NO_x, SO₂ and ammonia.

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

The BART rules completed by Wisconsin and Michigan, which cover one aspect of the CAVR regulations, are partially based on utility reductions of NO_x and SO₂ that were expected to occur under CAIR. While the EPA has

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expressed its intention to allow states to consider utility reductions of NO_x and SO₂ expected under CSAPR in its Regional Haze SIPs, we will not be able to determine final impacts of these rules until judicial review of CSAPR is completed and any subsequent rulemaking activities required as result of that review have been finalized.

Climate Change:   We continue to take measures to reduce our emissions of greenhouse gases. We support flexible, market-based strategies to curb greenhouse gas emissions, including emissions trading, joint implementation projects and credit for early actions. We support an approach that encourages technology development and transfer and includes all sectors of the economy and all significant global emitters. Our emissions in future years will continue to be influenced by several actions completed, planned or underway, including:

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

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

• Increasing investment in energy efficiency and conservation.

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

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

Federal, state, regional and international authorities have undertaken efforts to limit greenhouse gas emissions. The regulation of greenhouse gas emissions through legislation and regulation has been, and continues to be, a focus of the President and his administration. Although legislation that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards and/or energy efficiency standards failed to pass in the U.S. Congress, we expect such legislation to be considered in the future. Any mandatory restrictions on our CO₂ emissions that may be adopted by Congress or Wisconsin's or Michigan's legislature could result in significant compliance costs that could affect future results of operations, cash flows and financial condition. While climate legislation has yet to be adopted, the EPA is pursuing regulation of greenhouse gas emissions using its existing authority under the CAA. These regulations are expected to impact our ability to do maintenance or modify our existing facilities, and permit new facilities. Depending on the extent of rate recovery and other factors, these rules could have a material adverse impact on our financial condition. For additional information, see the caption "We may face significant costs to comply with the regulation of greenhouse gas emissions." under Item 1A Risk Factors in this report.

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

We are also required to report CO₂ amounts related to the natural gas our gas utility distributes and sells. For 2010, we reported approximately 9.0 million metric tonnes of CO₂ to the EPA related to our distribution and sale of natural gas. Based upon our preliminary analysis of the monitoring data, we estimate that we will report CO₂ emissions of approximately 9.6 million metric tonnes to the EPA for 2011.

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

Water Quality

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

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

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

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

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

Steam Electric Effluent Guidelines:   The federal Steam Electric Effluent guidelines, which regulate waste water discharges, are under review by the EPA. These rules govern discharges of waste water from our power plant processes. The EPA rules are expected to be finalized in 2014. After the promulgation of final rules, it is expected that the WDNR will need to modify Wisconsin's rules. The existing Wisconsin state rules for waste water discharge are very stringent, and therefore, the systems that have been installed at the Pleasant Prairie Power Plant and the Oak Creek Power Plant use advanced technology. We are unable to determine the impact, if any, of these rules on our facilities at this time.

Land Quality

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

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

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

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

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

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LEGAL MATTERS

Cash Balance Pension Plan:   In June 2009, a lawsuit was filed by Alan M. Downes, a former employee, against the Plan in the U.S. District Court for the Eastern District of Wisconsin. The complaint alleged that Plan participants who received a lump sum distribution under the Plan prior to their normal retirement age did not receive the full benefit to which they were entitled in violation of the Employee Retirement Income Security Act of 1974 (ERISA) and were owed additional benefits, because the Plan failed to apply the correct interest crediting rate to project the cash balance account to their normal retirement age. In September 2010, the plaintiff filed a First Amended Class Action Complaint alleging additional claims under ERISA and adding Wisconsin Energy as a defendant.

In November 2011, we entered into a settlement agreement with the plaintiffs for $45.0 million, and the court promptly issued an order preliminarily approving the settlement. As part of the settlement agreement, we agreed to class certification for all similarly situated plaintiffs. The resolution of this matter resulted in a cost of less than $0.04 per share for 2011 after considering insurance and reserves established in the prior year. We do not anticipate further charges as a result of the settlement, other than certain process-related costs we expect to incur to implement the settlement. We expect the court to provide final approval of the settlement agreement in April 2012, and to pay additional benefits to class members promptly after receiving this approval.

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

Dairy farmers continue to make claims against Wisconsin Electric for loss of milk production and other damages to livestock allegedly caused by stray voltage and ground currents resulting from the operation of its electrical system, even though that electrical system has been operated within the parameters of the PSCW's order. The Wisconsin Supreme Court has rejected the arguments that, if a utility company's measurement of stray voltage is below the PSCW "level of concern," that utility could not be found negligent in stray voltage cases. Additionally, the Court has held that the PSCW regulations regarding stray voltage were only minimum standards to be considered by a jury in stray voltage litigation. As a result of these rulings, claims by dairy farmers for livestock damage have been based upon ground currents with levels measuring less than the PSCW "level of concern." In December 2008, a stray voltage lawsuit was filed against Wisconsin Electric. This lawsuit was settled in May 2011. This settlement did not have a material effect on our financial condition or results of operations. Another stray voltage lawsuit was filed against Wisconsin Electric in January 2011, but was dismissed without prejudice by the court on February 21, 2012. We continue to evaluate various options and strategies to mitigate this risk.

NUCLEAR OPERATIONS

Used Nuclear Fuel Storage and Disposal:   During Wisconsin Electric's ownership of Point Beach, Wisconsin Electric was authorized by the PSCW to load and store sufficient dry fuel storage containers to allow Point Beach Units 1 and 2 to operate to the end of their original operating licenses, but not to exceed the original 48-canister capacity of the dry fuel storage facility. The original operating licenses were set to expire in October 2010 for Unit 1 and in March 2013 for Unit 2 before they were renewed and extended by the United States Nuclear Regulatory Commission in December 2005.

Temporary storage alternatives at Point Beach are necessary until the DOE takes ownership of and permanently removes the used fuel as mandated by the Nuclear Waste Policy Act of 1982, as amended in 1987. The Nuclear Waste Policy Act established the Nuclear Waste Fund which is composed of payments made by the generators and owners of such waste and fuel. Effective January 31, 1998, the DOE failed to meet its contractual obligation to begin removing used fuel from Point Beach, a responsibility for which Wisconsin Electric paid a total of $215.2 million into the Nuclear Waste Fund over the life of its ownership of Point Beach.

In August 2000, the United States Court of Appeals for the Federal Circuit ruled in a lawsuit brought by Maine Yankee and Northern States Power Company that the DOE's failure to begin performance by January 31, 1998 constituted a breach of the Standard Contract, providing clear grounds for filing complaints in the Court of Federal

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Claims. Consequently, Wisconsin Electric filed a complaint in November 2000 against the DOE in the Court of Federal Claims. In October 2004, the Court of Federal Claims granted Wisconsin Electric's motion for summary judgment on liability. The Court held a trial during September and October 2007 to determine damages. In December 2009, the Court ruled in favor of Wisconsin Electric, granting us more than $50 million in damages. In February 2010, the DOE filed an appeal. We negotiated a settlement with the DOE for $45.5 million, which we received in the first quarter of 2011. This amount, net of costs incurred, is being returned to customers as part of the PSCW's approval of our 2012 fuel recovery request and the MPSC's approval of our interim order for the 2012 Michigan rate case.

INDUSTRY RESTRUCTURING AND COMPETITION

Electric Utility Industry

The regulated energy industry continues to experience significant changes. FERC continues to support large RTOs, which will affect the structure of the wholesale market. To this end, the MISO implemented bid-based markets, the MISO Energy Markets, including the use of LMP to value electric transmission congestion and losses. The MISO Energy Markets commenced operation in April 2005 for energy distribution and in January 2009 for operating reserves. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant and adverse financial impact on us. It is uncertain when retail access might be implemented, if at all, in Wisconsin; however, Michigan has adopted retail choice which potentially affects our Michigan operations.

Restructuring in Wisconsin:Electric utility revenues in Wisconsin are regulated by the PSCW. Due to many factors, including relatively competitive electric rates charged by the state's electric utilities, the PSCW has been focused on electric reliability infrastructure issues for the state of Wisconsin in recent years.

The PSCW continues to maintain the position that the question of whether to implement electric retail competition in Wisconsin should ultimately be decided by the Wisconsin legislature. No such legislation has been introduced in Wisconsin to date.

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

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

Electric Transmission and Energy Markets

In connection with its status as a FERC approved RTO, MISO developed bid-based energy markets, which were implemented on April 1, 2005. In January 2009, MISO commenced the Energy and Operating Reserves Markets, which includes the bid-based energy markets and an ancillary services market. We previously self-provided both regulation reserves and contingency reserves. In the MISO ancillary services market, we buy/sell regulation and contingency reserves from/to the market. The MISO ancillary services market has been able to reduce overall ancillary services costs in the MISO footprint. The MISO ancillary services market has enabled MISO to assume significant balancing area responsibilities such as frequency control and disturbance control.

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

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

In April 2006, FERC issued an order determining that MISO had not applied its energy markets tariff correctly in the assessment of Revenue Sufficiency Guarantee (RSG) charges. FERC ordered MISO to resettle all affected transactions retroactive to the commencement of the energy market. In October 2006 and March 2007, we received additional rulings from FERC on these issues. FERC's rulings have been challenged by MISO and numerous other market participants. In July 2007, MISO commenced with the resettlement of the market in response to the orders. The resettlement was completed in January 2008 and resulted in a net cost increase of $7.8 million to us. Several entities filed formal complaints with FERC on the assessment of these charges. We filed in support of these complaints.

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

In addition, FERC ruled on the formal complaints filed by other entities in August 2007. FERC ruled that the current RSG cost allocation methodology may be unjust and unreasonable and established a refund effective date of August 10, 2007. MISO was ordered to file a new cost allocation methodology by March 2008. MISO filed new tariff language which indicated the new cost allocation methodology cannot be applied retroactively. We extended our previous rehearing/clarification request to include the timeframe from the established refund date through March 2008. In September 2008, FERC set a paper hearing for the formal complaints filed in 2007. FERC ruled on the outstanding rehearing/clarification requests and formal complaints in November 2008. FERC's ruling ordered the resettlements to begin from the date the MISO Energy Markets commenced in order to correct the RSG cost allocation methodology. Additionally, the order also set a new RSG cost allocation effective August 10, 2007. However, numerous entities filed rehearing requests in objection of these rulings. Although MISO requested a postponement of the resettlements until the matter is resolved, the resettlement commenced in March 2009. In May 2009, FERC issued an order denying rehearing on substantive matters for the rate period beginning August 10, 2007. However, FERC modified the effective date of that rate to November 10, 2008, and ordered MISO to cease the ongoing resettlement and to reconcile all invoices and payments therein. Similarly, in June 2009, FERC dismissed rehearing requests, but waived refunds for the period April 25, 2006 through November 4, 2007. FERC also stated for the first time that it was waiving refunds for the period April 1, 2005 through April 24, 2006. We, along with others, have sought rehearing and/or appeal of the FERC's May and June 2009 determinations pertaining to refunds. In addition, there are contested compliance matters pending FERC review. The net effects of FERC's rulings are uncertain at this time.

As part of MISO, a market-based platform was developed for valuing transmission congestion premised upon the LMP system that has been implemented in certain northeastern and mid-Atlantic states. The LMP system includes the ability to mitigate or eliminate congestion costs through Auction Revenue Rights (ARRs) and Financial Transmission Rights (FTRs). ARRs are allocated to market participants by MISO and FTRs are purchased through auctions. A new allocation and auction was completed for the period of June 1, 2011 through May 31, 2012. The resulting ARR valuation and the secured FTRs should mitigate our transmission congestion risk for that period.

Natural Gas Utility Industry

Restructuring in Wisconsin:   The PSCW previously instituted generic proceedings to consider how its regulation of gas distribution utilities should change to reflect the changing competitive environment in the natural gas industry. To date, the PSCW has made a policy decision to deregulate the sale of natural gas in customer segments with workably competitive market choices and has adopted standards for transactions between a utility and its gas marketing affiliates. However, work on deregulation of the gas distribution industry by the PSCW is presently on hold. Currently, we are unable to predict the impact of potential future deregulation on our results of operations or financial position.

68 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

ACCOUNTING DEVELOPMENTS

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

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

CRITICAL ACCOUNTING ESTIMATES

Preparation of financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions. In addition, the financial and operating environment may also have a significant effect, not only on the operation of our business, but on our results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied have not changed.

The following is a list of accounting policies that are most significant to the portrayal of our financial condition and results of operations and that require management's most difficult, subjective or complex judgments:

Regulatory Accounting:Our utility subsidiaries operate under rates established by state and federal regulatory commissions which are designed to recover the cost of service and provide a reasonable return to investors. The actions of our regulators may allow us to defer costs that non-regulated entities would expense and accrue liabilities that non-regulated companies would not. As of December 31, 2011, we had $1,265.7 million in regulatory assets and $915.9 million in regulatory liabilities. In the future, if we move to market based rates, or if the actions of our regulators change, we may conclude that we are unable to follow regulatory accounting. In this situation, we would record the regulatory assets related to unrecognized pension and OPEB costs as a reduction of equity, after tax. The balance of our regulatory assets net of regulatory liabilities would be recorded as an extraordinary after-tax non-cash charge to earnings. We continually review the applicability of regulatory accounting and have determined that it is currently appropriate to continue following it. In addition, each quarter we perform a review of our regulatory assets and our regulatory environment and we evaluate whether we believe that it is probable that we will recover the regulatory assets in future rates. See Note C -- Regulatory Assets and Liabilities in the Notes to Consolidated Financial Statements for additional information.

Pension and OPEB:   Our reported costs of providing non-contributory defined pension benefits (described in Note N -- Benefits in the Notes to Consolidated Financial Statements) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. Pension costs are impacted by actual employee demographics (including age, compensation levels and employment periods), the level of contributions made to plans and earnings on plan assets. Changes made to the provisions of the plans may also impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs.

Changes in pension obligations associated with these factors may not be immediately recognized as pension costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants.

69 Wisconsin Energy Corporation

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Cont'd) 2011 Form 10-K

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

Pension Plan	Impact on
Actuarial Assumption	Annual Cost
	(Millions of Dollars)
0.5% decrease in discount rate and lump sum conversion rate	$4.7
0.5% decrease in expected rate of return on plan assets	$5.7

In addition to pension plans, we maintain OPEB plans which provide health and life insurance benefits for retired employees (described in Note N -- Benefits in the Notes to Consolidated Financial Statements). Our reported costs of providing these post-retirement benefits are dependent upon numerous factors resulting from actual plan experience including employee demographics (age and compensation levels), our contributions to the plans, earnings on plan assets and health care cost trends. Changes made to the provisions of the plans may also impact current and future OPEB costs. OPEB costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the OPEB and post-retirement costs. Our OPEB plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns, as well as changes in general interest rates, may result in increased or decreased other post-retirement costs in future periods. Similar to accounting for pension plans, the regulators of our utility segment have adopted accounting guidance for compensation related to retirement benefits for rate-making purposes.

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

OPEB Plan	Impact on
Actuarial Assumption	Annual Cost
	(Millions of Dollars)
0.5% decrease in discount rate	$2.3
0.5% decrease in health care cost trend rate in all future years	$(3.1)
0.5% decrease in expected rate of return on plan assets	$1.2

Unbilled Revenues:   We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated. This unbilled revenue is estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses and applicable customer rates. Significant fluctuations in energy demand for the unbilled period or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. Total utility operating revenues during 2011 of approximately $4.4 billion included accrued utility revenues of $252.7 million as of December 31, 2011.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See Management's Discussion and Analysis of Financial Condition and Results of Operations - Factors Affecting Results, Liquidity and Capital Resources -- Market Risks and Other Significant Risks in Item 7 of this report, as well as Note L -- Derivative Instruments and Note M -- Fair Value Measurements in the Notes to Consolidated Financial Statements, for information concerning potential market risks to which Wisconsin Energy and its subsidiaries are exposed.

70 Wisconsin Energy Corporation

2011 Form 10-K

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

WISCONSIN ENERGY CORPORATION
CONSOLIDATED INCOME STATEMENTS
Year Ended December 31
	2011		2010		2009
	(Millions of Dollars, Except Per Share Amounts)
Operating Revenues	$	4,486.4	$	4,202.5	$	4,100.9
Operating Expenses
Fuel and purchased power	1,169.7		1,099.9		1,059.7
Cost of gas sold	728.7		751.5		912.0
Other operation and maintenance	1,256.8		1,327.5		1,246.1
Depreciation and amortization	330.2		305.6		343.0
Property and revenue taxes	113.7		106.0		110.5
Total Operating Expenses	3,599.1		3,590.5		3,671.3
Amortization of Gain	—		198.4		230.7
Operating Income	887.3		810.4		660.3
Equity in Earnings of Transmission Affiliate	62.5		60.1		59.1
Other Income and Deductions, net	62.7		40.2		28.5
Interest Expense, net	235.8		206.4		156.7
Income from Continuing Operations Before Income Taxes	776.7		704.3		591.2
Income Tax Expense	263.9		249.9		215.5
Income from Continuing Operations	512.8		454.4		375.7
Income from Discontinued Operations, Net of Tax	13.4		2.1		6.7
Net Income	$	526.2	$	456.5	$	382.4
Earnings Per Share (Basic)
Continuing Operations	$	2.20	$	1.94	$	1.61
Discontinued Operations	0.06		0.01		0.03
Total Earnings Per Share (Basic)	$	2.26	$	1.95	$	1.64
Earnings Per Share (Diluted)
Continuing Operations	$	2.18	$	1.92	$	1.59
Discontinued Operations	0.06		0.01		0.03
Total Earnings Per Share (Diluted)	$	2.24	$	1.93	$	1.62
Weighted Average Common Shares Outstanding (Millions)
Basic	232.6		233.8		233.8
Diluted	235.4		236.7		235.9
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

71 Wisconsin Energy Corporation

2011 Form 10-K

WISCONSIN ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31
ASSETS
	2011			2010
	(Millions of Dollars)
Property, Plant and Equipment
In service	$	12,977.7		$	11,590.8
Accumulated depreciation	(3,797.8		)	(3,624.0		)
	9,179.9			7,966.8
Construction work in progress	921.3			1,569.9
Leased facilities, net	59.2			64.8
Net Property, Plant and Equipment	10,160.4			9,601.5
Investments
Equity investment in transmission affiliate	349.7			330.5
Other	43.6			45.8
Total Investments	393.3			376.3
Current Assets
Cash and cash equivalents	14.1			24.5
Restricted cash	45.5			8.3
Accounts receivable, net of allowance for
doubtful accounts of $61.7 and $58.1	349.4			344.6
Income taxes receivable	155.1			83.7
Accrued revenues	252.7			280.3
Materials, supplies and inventories	382.0			379.1
Prepayments	140.3			125.6
Other	87.1			85.0
Total Current Assets	1,426.2			1,331.1
Deferred Charges and Other Assets
Regulatory assets	1,238.7			1,090.1
Goodwill	441.9			441.9
Other	201.6			218.9
Total Deferred Charges and Other Assets	1,882.2			1,750.9
Total Assets	$	13,862.1		$	13,059.8
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

72 Wisconsin Energy Corporation

2011 Form 10-K

WISCONSIN ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31
CAPITALIZATION AND LIABILITIES
	2011		2010
	(Millions of Dollars)
Capitalization
Common equity	$	3,963.3	$	3,802.1
Preferred stock of subsidiary	30.4		30.4
Long-term debt	4,614.3		3,932.0
Total Capitalization	8,608.0		7,764.5
Current Liabilities
Long-term debt due currently	32.6		473.4
Short-term debt	669.9		657.9
Accounts payable	325.7		315.4
Accrued payroll and vacation	105.9		88.3
Other	230.4		186.1
Total Current Liabilities	1,364.5		1,721.1
Deferred Credits and Other Liabilities
Regulatory liabilities	902.0		883.8
Deferred income taxes - long-term	1,696.1		1,154.8
Deferred revenue, net	754.5		805.5
Pension and other benefit obligations	222.7		353.2
Other long-term liabilities	314.3		376.9
Total Deferred Credits and Other Liabilities	3,889.6		3,574.2
Commitments and Contingencies (Note R)
Total Capitalization and Liabilities	$	13,862.1	$	13,059.8
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

73 Wisconsin Energy Corporation

2011 Form 10-K

WISCONSIN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31
	2011			2010			2009
	(Millions of Dollars)
Operating Activities
Net income	$	526.2		$	456.5		$	382.4
Reconciliation to cash
Depreciation and amortization	336.4			317.4			346.9
Amortization of gain	—			(198.4		)	(230.7		)
Deferred income taxes and investment tax credits, net	430.6			104.9			187.4
Deferred revenue	3.5			100.8			201.7
Contributions to qualified benefit plans	(277.4		)	—			(289.3		)
Change in - Accounts receivable and accrued revenues	30.1			(50.4		)	111.1
Inventories	(2.9		)	(1.0		)	(34.6		)
Other current assets	(20.5		)	14.1			24.8
Accounts payable	11.8			21.3			(119.1		)
Accrued income taxes, net	(87.4		)	(42.7		)	43.4
Deferred costs, net	25.9			25.9			46.2
Other current liabilities	44.1			22.0			(11.7		)
Other, net	(27.0		)	40.0			(29.6		)
Cash Provided by Operating Activities	993.4			810.4			628.9
Investing Activities
Capital expenditures	(830.8		)	(798.2		)	(814.6		)
Investment in transmission affiliate	(6.6		)	(5.2		)	(25.9		)
Proceeds from asset sales	41.5			68.7			16.8
Change in restricted cash	(37.2		)	186.2			192.0
Other, net	(59.4		)	(85.0		)	(104.4		)
Cash Used in Investing Activities	(892.5		)	(633.5		)	(736.1		)
Financing Activities
Exercise of stock options	54.4			90.9			17.0
Purchase of common stock	(193.9		)	(156.6		)	(29.6		)
Dividends paid on common stock	(242.0		)	(187.0		)	(157.8		)
Issuance of long-term debt	720.0			530.0			261.5
Retirement and repurchase of long-term debt	(466.6		)	(291.7		)	(221.1		)
Change in short-term debt	12.0			(167.2		)	222.8
Other, net	4.8			9.0			2.9
Cash (Used in) Provided by Financing Activities	(111.3		)	(172.6		)	95.7
Change in Cash and Cash Equivalents	(10.4		)	4.3			(11.5		)
Cash and Cash Equivalents at Beginning of Year	24.5			20.2			31.7
Cash and Cash Equivalents at End of Year	$	14.1		$	24.5		$	20.2
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

74 Wisconsin Energy Corporation

2011 Form 10-K

WISCONSIN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMMON EQUITY
									Accumulated
									Other			Stock
	Common		Other Paid			Retained			Comprehensive			Options
	Stock		In Capital			Earnings			Income (Loss)			Exercisable			Total
	(Millions of Dollars)
Balance - December 31, 2008	$	2.3	$	751.2		$	2,584.2		$	(0.9	)	$	0.1		$	3,336.9
Net income						382.4									382.4
Other comprehensive income
Hedging, net									0.4						0.4
Comprehensive income	—		—			382.4			0.4			—			382.8
Common stock cash
dividends of $0.675 per share						(157.8		)							(157.8		)
Exercise of stock options			17.0												17.0
Purchase of common stock			(29.6		)										(29.6		)
Tax benefit from share based compensation			6.3												6.3
Stock-based compensation and other			11.4			—						(0.1		)	11.3
Balance - December 31, 2009	2.3		756.3			2,808.8			(0.5		)	—			3,566.9
Net income						456.5									456.5
Other comprehensive income
Hedging, net									0.4						0.4
Comprehensive income	—		—			456.5			0.4			—			456.9
Common stock cash
dividends of $0.80 per share						(187.0		)							(187.0		)
Exercise of stock options			90.9												90.9
Purchase of common stock			(156.6		)										(156.6		)
Tax benefit from share based compensation			21.9												21.9
Stock-based compensation and other			9.1												9.1
Balance - December 31, 2010	2.3		721.6			3,078.3			(0.1		)	—			3,802.1
Net income						526.2									526.2
Other comprehensive income
Hedging, net									0.2						0.2
Comprehensive income	—		—			526.2			0.2			—			526.4
Common stock cash
dividends of $1.04 per share						(242.0		)							(242.0		)
Exercise of stock options			54.4												54.4
Purchase of common stock			(193.9		)										(193.9		)
Tax benefit from share based compensation			11.9												11.9
Stock-based compensation and other			4.4												4.4
Balance - December 31, 2011	$	2.3	$	598.4		$	3,362.5		$	0.1		$	—		$	3,963.3
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

75 Wisconsin Energy Corporation

2011 Form 10-K

WISCONSIN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31
		2011			2010
		(Millions of Dollars)
Common Equity (see accompanying statement)		$	3,963.3		$	3,802.1
Preferred Stock
Wisconsin Energy
$.01 par value; authorized 15,000,000 shares; none outstanding		—			—
Wisconsin Electric
Six Per Cent. Preferred Stock - $100 par value;
authorized 45,000 shares; outstanding - 44,498 shares		4.4			4.4
Serial preferred stock -
$100 par value; authorized 2,286,500 shares; 3.60% Series
redeemable at $101 per share; outstanding - 260,000 shares		26.0			26.0
$25 par value; authorized 5,000,000 shares; none outstanding		—			—
Total Preferred Stock		30.4			30.4
Long-Term Debt
Debentures (unsecured)	4.50% due 2013	300.0			300.0
	6.60% due 2013	45.0			45.0
	6.00% due 2014	300.0			300.0
	5.20% due 2015	125.0			125.0
	6.25% due 2015	250.0			250.0
	4.25% due 2019	250.0			250.0
	2.95% due 2021	300.0			—
	6-1/2% due 2028	150.0			150.0
	5.625% due 2033	335.0			335.0
	5.90% due 2035	90.0			90.0
	5.70% due 2036	300.0			300.0
	6-7/8% due 2095	100.0			100.0
Notes (secured, nonrecourse)	4.81% effective rate due 2030	2.0			2.0
	4.91% due 2011-2030	131.2			135.4
	5.209% due 2011-2030	245.4			251.9
	4.673% due 2011-2031	202.3			—
	6.00% due 2011-2033	145.5			148.7
	6.09% due 2030-2040	275.0			275.0
	5.848% due 2031-2041	215.0			—
Notes (unsecured)	6.50% due 2011	—			450.0
	6.51% due 2013	30.0			30.0
	6.94% due 2028	50.0			50.0
	0.504% variable rate due 2016 (a)	67.0			67.0
	0.504% variable rate due 2030 (a)	80.0			80.0
	Variable rate notes held by Wisconsin Electric	(147.0		)	(147.0		)
	6.20% due 2033	200.0			200.0
Junior Notes (unsecured)	6.25% due 2067	500.0			500.0
Obligations under capital leases		132.4			141.9
Unamortized discount, net and other		(26.9		)	(24.5		)
Long-term debt due currently		(32.6		)	(473.4		)
Total Long-Term Debt		4,614.3			3,932.0
Total Capitalization		$	8,608.0		$	7,764.5

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

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

76 Wisconsin Energy Corporation

2011 Form 10-K

WISCONSIN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General:Our consolidated financial statements include the accounts of Wisconsin Energy Corporation (Wisconsin Energy, the Company, our, we or us), a diversified holding company, as well as our subsidiaries in the following operating segments:

• Utility Energy Segment -- Consisting of Wisconsin Electric and Wisconsin Gas, engaged primarily in the generation of electricity and the distribution of electricity and natural gas; and

• Non-Utility Energy Segment -- Consisting primarily of We Power, engaged principally in the design, development, construction and ownership of electric power generating facilities for long-term lease to Wisconsin Electric.

Our Corporate and Other segment includes Wispark, which develops and invests in real estate. We have also eliminated all intercompany transactions and balances within this segment from the consolidated financial statements.

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

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

On January 20, 2011, our Board of Directors approved a two-for-one stock split of our common stock, which was effected through a stock dividend. New shares were distributed on March 1, 2011 to stockholders of record at the close of business on February 14, 2011. All share and per share information has been restated for all periods presented to reflect this stock split.

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

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

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

For information regarding revenue recognition for We Power, see Note E.

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

77 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

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

Other Income and Deductions, net	2011		2010		2009
	(Millions of Dollars)
AFUDC - Equity	$	59.4	$	32.5	$	16.0
Gain on Property Sales	2.4		4.4		1.7
Other, net	0.9		3.3		10.8
Total Other Income and Deductions, net	$	62.7	$	40.2	$	28.5

Property and Depreciation:We record property, plant and equipment at cost. Cost includes material, labor, overheads and capitalized interest. Utility property also includes AFUDC - Equity. Additions to and significant replacements of property are charged to property, plant and equipment at cost; minor items are charged to maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.

We recorded the following property in service by segment as of December 31:

Property In Service	2011		2010
	(Millions of Dollars)
Utility Energy	$	9,817.7	$	9,221.1
Non-Utility Energy	3,067.5		2,283.4
Other	92.5		86.3
Total	$	12,977.7	$	11,590.8

Our utility depreciation rates are certified by the PSCW and MPSC and include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 2.8% in 2011 and 2010, and 3.7% in 2009.

PWGS 1, PWGS 2, OC 1 and OC 2 are being depreciated over the estimated useful life of the various property components. The components have useful lives of between 10 to 45 years for PWGS 1 and PWGS 2, and 10 to 55 years for OC 1 and OC 2.

Our regulated utilities collect in their rates amounts representing future removal costs for many assets that do not have an associated Asset Retirement Obligation (ARO). We record a regulatory liability on our balance sheet for the estimated amounts we have collected in rates for future removal costs less amounts we have spent in removal activities. This regulatory liability was $728.2 million as of December 31, 2011 and $723.9 million as of December 31, 2010.

We recorded the following Construction Work in Progress (CWIP) by segment as of December 31:

CWIP	2011		2010
	(Millions of Dollars)
Utility Energy	$	910.3	$	806.9
Non-Utility Energy	8.9		761.3
Other	2.1		1.7
Total	$	921.3	$	1,569.9

78 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

Allowance For Funds Used During Construction - Regulated:   AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC - Debt) used during plant construction, and a return on stockholders' capital (AFUDC - Equity) used for construction purposes. AFUDC - Debt is recorded as a reduction of interest expense, and AFUDC - Equity is recorded in Other Income and Deductions, net.

During 2009, Wisconsin Electric accrued AFUDC at a rate of 9.09% as authorized by the PSCW. Consistent with the PSCW's 2008 rate order, Wisconsin Electric accrued AFUDC on 50% of all utility CWIP projects except the Oak Creek AQCS project, which accrued AFUDC on 100% of CWIP. Wisconsin Electric's rates are set to provide a current return on CWIP that does not accrue AFUDC. Based on the 2010 PSCW rate order, effective January 1, 2010 Wisconsin Electric recorded AFUDC on 100% of CWIP associated with the Oak Creek AQCS project, the Edgewater Unit 5 Selective Catalytic Reduction project and the Glacier Hills Wind Park. Wisconsin Electric recorded AFUDC on 50% of all other electric, gas and steam utility CWIP. The AFUDC rate starting January 1, 2010 was 8.83%. This AFUDC accrual policy and rate for Wisconsin Electric continued through 2011 and will continue through 2012.

Wisconsin Electric is also accruing AFUDC on 100% of the biomass project.

During 2009, Wisconsin Gas accrued AFUDC at a rate of 10.80% on 50% of its CWIP as authorized by the PSCW in its 2008 rate order. Wisconsin Gas' rates are set to provide a current return on CWIP that does not accrue AFUDC. Based on the 2010 PSCW rate order, effective January 1, 2010 Wisconsin Gas recorded AFUDC on 50% of all CWIP using an AFUDC rate of 9.05%. This AFUDC accrual policy and rate for Wisconsin Gas continued through 2011 and will continue through 2012.

Our regulated segment recorded the following AFUDC for the years ended December 31:

	2011		2010		2009
	(Millions of Dollars)
AFUDC - Debt	$	24.7	$	13.5	$	6.7
AFUDC - Equity	$	59.4	$	32.5	$	16.0

Capitalized Interest and Carrying Costs - Non-Regulated Energy:   As part of the construction of the PTF electric generating units, we capitalized interest during construction. As allowed under the lease agreements, we were able to collect the carrying costs during the construction of the PTF generating units from our utility customers. The carrying costs that we collected during construction have been recorded as deferred revenue on our balance sheet and we are amortizing the deferred carrying costs to revenue over the individual lease terms. For further information on the accounting for capitalized interest and deferred carrying costs associated with the construction of our PTF power plants, see Note E.

Earnings per Common Share:   We compute basic earnings per common share by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net income attributed to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive securities include in-the-money stock options. The future issuance of shares underlying the outstanding stock options depends on whether the exercise prices of the stock options are less than the average market price of the common shares for the respective periods. Shares that are anti-dilutive are excluded from the calculation. All stock options outstanding during 2011 were included in the computation of diluted earnings per share. For 2010 and 2009, the calculation of diluted earnings per share excluded an immaterial number of out-of-the money stock options that had an anti-dilutive effect.

79 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

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

Materials, Supplies and Inventories	2011		2010
	(Millions of Dollars)
Fossil Fuel	$	169.2	$	182.4
Materials and Supplies	114.1		105.2
Natural Gas in Storage	98.7		91.5
Total	$	382.0	$	379.1

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

Regulatory Accounting:   The economic effects of regulation can result in regulated companies recording costs that have been or are expected to be allowed in the rate-making process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets on the balance sheet and expensed in the periods when they are reflected in rates. We defer regulatory assets pursuant to specific or generic orders issued by our regulators. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We expect to recover our outstanding regulatory assets in rates over a period of no longer than 20 years. Regulatory assets and liabilities that are expected to be amortized within one year are recorded as current on the balance sheet. For further information, see Note C.

Asset Retirement Obligations:   We record a liability for a legal ARO in the period in which it is incurred. When a new legal obligation is recorded, we capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. We accrete the liability to its present value each period and depreciate the capitalized cost over the useful life of the related asset. At the end of the asset's useful life, we settle the obligation for its recorded amount or incur a gain or loss. As it relates to our regulated operations, we apply regulatory accounting guidance and recognize regulatory assets or liabilities for the timing differences between when we recover legal AROs in rates and when we would recognize these costs. For further information, see Note F.

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

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

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

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

Goodwill:   Goodwill reflects the cost of an acquisition in excess of the fair values assigned to identifiable net assets acquired. As of December 31, 2011 and 2010, we had $441.9 million of goodwill recorded at the utility energy segment, which related to our acquisition of Wisconsin Gas in 2000.

Goodwill is not subject to amortization. However, it is subject to fair value-based rules for measuring impairment, and resulting write-downs, if any, are to be reflected in operating expense. Fair value is assessed by considering future discounted cash flows, a comparison of fair value based on public company trading multiples, and merger and acquisition transaction multiples for similar companies. This evaluation utilizes the information available under the circumstances, including reasonable and supportable assumptions and projections. We perform our annual impairment test as of August 31. There was no impairment to the recorded goodwill balance as of our annual 2011 impairment test date.

80 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

Impairment or Disposal of Long Lived Assets:   We carry property, equipment and goodwill related to businesses held for sale at the lower of cost or estimated fair value less cost to sell. As of December 31, 2011, we had no assets classified as Held for Sale. Long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that their carrying value may not be recoverable from the use and eventual disposition of the asset based on the remaining useful life. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset.

Investments:   We account for investments in other affiliated companies in which we do not maintain control using the equity method of accounting. We had a total ownership interest of approximately 26.2% in ATC as of December 31, 2011 and 2010. We are represented by one out of ten ATC board members, each of whom has one vote. Due to the voting requirements, no individual member has more than 10% of the voting control. For further information regarding such investments, see Note Q.

Income Taxes:   We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense.

Investment tax credits associated with regulated operations are deferred and amortized over the life of the assets. We file a consolidated Federal income tax return. Accordingly, we allocate Federal current tax expense benefits and credits to our subsidiaries based on their separate tax computations. For further information, see Note H.

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

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

Stock Options:   We estimate the fair value of stock options using the binomial pricing model. We report unearned stock-based compensation associated with non-vested restricted stock and performance share awards activity within Other Paid in Capital in our Consolidated Statements of Common Equity. We report excess tax benefits as a financing cash inflow. Historically, all stock options have been granted with an exercise price equal to the fair market value of the common stock on the date of grant and expire no later than 10 years from grant date. For a discussion of the impacts to our Consolidated Financial Statements, see Note I.

The fair value of our stock options was calculated using a binomial option-pricing model using the following weighted-average assumptions:

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

81 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

B -- RECENT ACCOUNTING PRONOUNCEMENTS

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

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

C -- REGULATORY ASSETS AND LIABILITIES

Our primary regulator, the PSCW, considers our regulatory assets and liabilities in two categories, escrowed and deferred. In escrow accounting we expense amounts that are included in rates. If actual costs exceed or are less than the amounts that are allowed in rates, the difference in cost is escrowed on the balance sheet as a regulatory asset or regulatory liability and the escrowed balance is considered in setting future rates. Under deferred cost accounting, we defer amounts to our balance sheet based upon orders or correspondence with our regulators. These deferred costs will be considered in future rate setting proceedings. As of December 31, 2011 and 2010, we had approximately $11.0 million and $16.5 million, respectively, of net regulatory assets that were not earning a return. These regulatory assets are expected to be recovered from customers over a period of one to five years.

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

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

82 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

	2011		2010
	(Millions of Dollars)
Regulatory Assets
Deferred unrecognized pension costs	$	647.8	$	542.6
Deferred income tax related	121.2		89.9
Escrowed electric transmission costs	118.3		138.0
Deferred unrecognized OPEB costs	102.9		85.7
Deferred plant related -- capital lease	73.2		77.1
Deferred environmental costs	48.5		56.7
Other, net	153.8		154.5
Total regulatory assets	$	1,265.7	$	1,144.5
Regulatory Liabilities
Deferred cost of removal obligations	$	728.2	$	723.9
Escrowed bad debt costs	69.0		18.5
Other, net	118.7		156.7
Total regulatory liabilities	$	915.9	$	899.1

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

D -- ASSET SALES, DIVESTITURES AND DISCONTINUED OPERATIONS

Edison Sault:   Effective May 4, 2010, we sold Edison Sault Electric Company (Edison Sault) to Cloverland Electric Cooperative for approximately $63.0 million. We reclassified the operations related to Edison Sault as discontinued operations in the accompanying Consolidated Income Statements. Discontinued Edison Sault operations had no significant impact on our Consolidated Statements of Cash Flows for the years ended December 31, 2010 and 2009. We retained Edison Sault's ownership interest in ATC.

Water Utility Operations:   Effective April 30, 2009, we sold our water utility to the City of Mequon, Wisconsin for approximately $14.5 million. We reclassified the water utility income as discontinued operations in the accompanying Consolidated Income Statements. Discontinued water operations had no material impact on the Consolidated Statement of Cash Flows for the year ended December 31, 2009.

The following table summarizes the net impacts of the discontinued operations on our earnings for the years ended December 31:

	2011		2010		2009
	(Millions of Dollars)
Income from Continuing Operations	$	512.8	$	454.4	$	375.7
Income from Discontinued Edison Sault operations, net of tax	—		0.7		1.5
Income from Discontinued Water operations, net of tax	—		—		0.3
Income from Discontinued other operations, net of tax (a)	13.4		1.4		4.9
Net Income	$	526.2	$	456.5	$	382.4

(a) Primarily relates to the favorable resolution of uncertain state and federal tax positions associated with our previously discontinued manufacturing business.

Edgewater Generating Unit 5:   On March 1, 2011, we sold our 25% interest in Edgewater Generating Unit 5 to WPL for our net book value, including working capital, of approximately $38 million. This transaction was treated as a sale of an asset.

83 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

E -- ACCOUNTING AND REPORTING FOR POWER THE FUTURE GENERATING UNITS

Background:   As part of our PTF strategy, our non-utility subsidiary, We Power, built four new generating units, PWGS 1, PWGS 2, OC 1 and OC 2, which are leased to our utility subsidiary, Wisconsin Electric, under long-term leases that have been approved by the PSCW. The leases are designed to recover the capital costs of the plant, including a return. PWGS 1, PWGS 2, OC 1 and OC 2 were placed in service in July 2005, May 2008, February 2010 and January 2011, respectively. The accompanying consolidated financial statements eliminate all intercompany transactions between We Power and Wisconsin Electric and reflect the cash inflows from Wisconsin Electric customers and the cash outflows to our vendors and suppliers.

The Oak Creek expansion includes common projects that benefit the existing units at this site as well as the new units. These projects include a coal handling facility and a water intake system, which were placed in service in November 2007 and January 2009, respectively.

During Construction:Under the terms of each lease, we collected in then current rates amounts representing our pre-tax cost of capital (debt and equity) associated with capital expenditures for our PTF units. Our pre-tax cost of capital was approximately 14%. The carrying costs that we collected in rates were recorded as deferred revenue and are amortized to revenue over the term of each lease. During the construction of our PTF units, we capitalized interest costs at an overall weighted-average pre-tax cost of interest, which was approximately 5% for the year ended December 31, 2010. Capitalized interest is included in the total cost of the PTF units.

Plant in Service:Now that the PTF units are in service, we expect to continue to recover in rates the lease costs which reflect the authorized cash construction costs of the units plus a return on the investment. The authorized cash costs were established by the PSCW. The authorized cash costs exclude capitalized interest since carrying costs were recovered during the construction of the units. The lease payments are expected to be levelized, except that OC 1 and OC 2 will be recovered on a levelized basis that has a one time 10.6% escalation after the first five years of the leases. The leases established a set return on equity component of 12.7% after tax. The interest component of the return under each lease was established at rates determined in accordance with the terms of each lease.

We recognize revenues (consisting of the lease payments included in rates and the amortization of the deferred revenue) on a levelized basis over the term of the lease. We depreciate the PTF assets over their estimated useful life.

F -- ASSET RETIREMENT OBLIGATIONS

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

	2011			2010
	(Millions of Dollars)
Balance as of January 1	$	52.6		$	57.9
Liabilities Incurred	0.6			—
Liabilities Settled	(2.2		)	(2.5		)
Accretion	3.0			3.1
Cash Flow Revisions	1.5			(5.9		)
Balance as of December 31	$	55.5		$	52.6

G -- VARIABLE INTEREST ENTITIES

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

84 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

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

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

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

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

H -- INCOME TAXES

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

Income Taxes	2011			2010			2009
	(Millions of Dollars)
Current tax expense (benefit)	$	(166.7	)	$	144.9		$	28.1
Deferred income taxes, net	434.8			108.6			191.2
Investment tax credit, net	(4.2		)	(3.6		)	(3.8		)
Total Income Tax Expense	$	263.9		$	249.9		$	215.5

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

	2011					2010					2009
				Effective					Effective					Effective
Income Tax Expense	Amount			Tax Rate		Amount			Tax Rate		Amount			Tax Rate
	(Millions of Dollars)
Expected tax at statutory federal tax rates	$	271.8		35.0	%	$	246.5		35.0	%	$	206.9		35.0	%
State income taxes net of federal tax benefit	40.1			5.2	%	35.8			5.1	%	31.8			5.4	%
AFUDC - Equity	(20.8		)	(2.7	)%	(11.4		)	(1.6	)%	(5.6		)	(0.9	)%
Domestic production activities deduction	(12.6		)	(1.6	)%	(12.6		)	(1.8	)%	(8.3		)	(1.4	)%
Production tax credits - wind	(8.7		)	(1.1	)%	(7.2		)	(1.0	)%	(7.1		)	(1.2	)%
Investment tax credit restored	(4.2		)	(0.5	)%	(3.6		)	(0.5	)%	(3.8		)	(0.6	)%
Other, net	(1.7		)	(0.3	)%	2.4			0.3	%	1.6			0.2	%
Total Income Tax Expense	$	263.9		34.0	%	$	249.9		35.5	%	$	215.5		36.5	%

85 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

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

Deferred Tax Assets	2011		2010
	(Millions of Dollars)
Current
Employee benefits and compensation	$	14.6	$	14.3
Other	57.1		33.5
Total Current Deferred Tax Assets	71.7		47.8
Non-current
Future federal tax benefits	328.5		—
Deferred revenues	279.7		305.9
Employee benefits and compensation	103.6		110.2
Property-related	28.3		30.3
Construction advances	25.4		118.3
Emission allowances	1.0		2.6
Other	34.0		30.8
Total Non-Current Deferred Tax Assets	800.5		598.1
Total Deferred Tax Assets	$	872.2	$	645.9

Deferred Tax Liabilities	2011		2010
	(Millions of Dollars)
Current
Prepaid items	$	50.1	$	46.9
Total Current Deferred Tax Liabilities	50.1		46.9
Non-current
Property-related	2,020.7		1,346.8
Employee benefits and compensation	232.8		179.5
Investment in transmission affiliate	129.2		112.4
Deferred transmission costs	47.4		53.1
Other	66.5		61.1
Total Non-current Deferred Tax Liabilities	2,496.6		1,752.9
Total Deferred Tax Liabilities	$	2,546.7	$	1,799.8
Consolidated Balance Sheet Presentation	2011		2010
Current Deferred Tax Asset	$	21.6	$	0.9
Non-Current Deferred Tax Liability	$	1,696.1	$	1,154.8

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

As of December 31, 2011, we had approximately $867.1 million and $25.0 million of net operating loss and tax credit carryforwards, respectively. The net operating loss and tax credit carryforwards resulted in deferred tax assets of $303.5 million and $25.0 million, respectively, as of December 31, 2011. The tax credit and net operating loss carryforwards begin to expire in 2029 and 2030, respectively. We anticipate that we will have future taxable income sufficient to utilize these deferred tax assets.

86 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

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

	2011			2010
	(Millions of Dollars)
Balance as of January 1	$	29.5		$	35.4
Additions based on tax positions related to the current year	—			0.8
Additions for tax positions of prior years	—			10.4
Reductions for tax positions of prior years	(13.9		)	(2.5		)
Reductions due to statute of limitations	(2.5		)	(0.3		)
Settlements during the period	(2.0		)	(14.3		)
Balance as of December 31	$	11.1		$	29.5

The amount of unrecognized tax benefits as of December 31, 2011 and 2010 excludes deferred tax assets related to uncertainty in income taxes of $11.0 million and $16.9 million, respectively. As of December 31, 2011 and 2010, the net amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was approximately $0.1 million and $2.3 million, respectively.

We recognize interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense. For the years ended December 31, 2011, 2010 and 2009, we recognized approximately $0.7 million, $4.1 million and $2.0 million, respectively, of accrued interest in the Consolidated Income Statements. For the year ended December 31, 2011, we recognized a benefit of $0.3 million in the Consolidated Income Statements related to a reduction of accrued penalties. For the years ended December 31, 2010 and 2009, we recognized no penalties in the Consolidated Income Statements. We had approximately $2.0 million and $8.2 million of interest accrued and zero and approximately $0.3 million of penalties accrued on the Consolidated Balance Sheets as of December 31, 2011 and 2010, respectively.

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

Our primary tax jurisdictions include Federal and the state of Wisconsin. Currently, the tax years of 2007 through 2011 are subject to Federal and Wisconsin examination.

I -- COMMON EQUITY

As of December 31, 2011 and 2010, we had 325,000,000 shares of common stock authorized under our charter, of which 230,486,804 and 233,771,194 common shares, respectively, were outstanding. All share-based compensation is currently fulfilled by purchases on the open market by our independent agents and do not dilute shareholders' ownership.

Share-Based Compensation Plans:   We have a plan that was approved by stockholders that enables us to provide a long-term incentive through equity interests in Wisconsin Energy to outside directors, selected officers and key employees of the Company. The plan provides for the granting of stock options, stock appreciation rights, restricted stock awards and performance shares. Awards may be paid in common stock, cash or a combination thereof. We utilize the straight-line attribution method for recognizing share-based compensation expense. Accordingly, for employee awards, equity classified share-based compensation cost is measured at the grant date based on the fair value of the award, and is recognized as expense over the requisite service period. There were no modifications to the terms of outstanding stock options during the period other than necessary adjustments as a result of our stock split.

87 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

The following table summarizes recorded pre-tax share-based compensation expense and the related tax benefit for share-based awards made to our employees and directors as of December 31:

	2011		2010		2009
	(Millions of Dollars)
Performance units	$	24.1	$	26.0	$	14.0
Stock options	2.6		7.6		10.8
Restricted stock	1.8		1.5		1.0
Share-based compensation expense	$	28.5	$	35.1	$	25.8
Related Tax Benefit	$	11.4	$	14.1	$	10.3

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

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

The following is a summary of our stock option activity during 2011:

Stock Options	Number of Options		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life (Years)	Aggregate Intrinsic Value (Millions)
Outstanding as of January 1, 2011	13,036,466		$	20.81
Granted	458,180		$	29.35
Exercised	(2,855,896	)	$	19.07
Forfeited	—		$	—
Outstanding as of December 31, 2011	10,638,750		$	21.65	5.4	$	141.6
Exercisable as of December 31, 2011	7,534,980		$	21.14	4.5	$	104.1

In January 2012, the Compensation Committee awarded 938,770 non-qualified stock options with an exercise price of $34.88 to our officers and key executives under its normal schedule of awarding long-term incentive compensation.

The intrinsic value of options exercised during the years ended December 31, 2011, 2010 and 2009 was $36.1 million, $62.1 million and $12.0 million, respectively. Cash received from options exercised during the years ended December 31, 2011, 2010 and 2009 was $54.4 million, $90.9 million and $17.0 million, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $14.3 million, $24.1 million and $4.8 million, respectively.

The following table summarizes information about stock options outstanding as of December 31, 2011:

	Options Outstanding				Options Exercisable
		Weighted-Average				Weighted-Average
Range of Exercise Prices	Number of Options	Exercise Price		Remaining Contractual Life (Years)	Number of Options	Exercise Price		Remaining Contractual Life (Years)
$11.52  to  $17.10	1,972,594	$	16.07	2.3	1,972,594	$	16.07	2.3
$19.74  to  $21.11	3,586,456	$	20.62	5.9	1,420,186	$	19.88	4.3
$23.88  to  $29.35	5,079,700	$	24.54	6.2	4,142,200	$	23.99	5.6
	10,638,750	$	21.65	5.4	7,534,980	$	21.14	4.5

88 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

The following table summarizes information about our non-vested options during 2011:

Non-Vested Stock Options	Number of Options		Weighted- Average Fair Value
Non-Vested as of January 1, 2011	5,272,570		$	4.27
Granted	458,180		$	3.17
Vested	(2,626,980	)	$	4.64
Forfeited	—		$	—
Non-Vested as of December 31, 2011	3,103,770		$	3.78

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

Restricted Shares:   The Compensation Committee has also approved restricted stock grants to certain key employees and directors. The following restricted stock activity occurred during 2011:

Restricted Shares	Number of Shares		Weighted-Average Market Price
Outstanding as of January 1, 2011	205,404
Granted	74,850		$	29.00
Released	(83,452	)	$	18.82
Forfeited	(4,244	)	$	26.62
Outstanding as of December 31, 2011	192,558

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

In January 2012, the Compensation Committee awarded 94,959 restricted shares to our directors, officers and other key employees under its normal schedule of awarding long-term incentive compensation. These awards have a three-year vesting period, and generally, one-third of the award vests on each anniversary of the grant date. During the vesting period, restricted share recipients also have voting rights and are entitled to dividends in the same manner as other shareholders.

We record the market value of the restricted stock awards on the date of grant and then we charge their value to expense over the vesting period of the awards. The intrinsic value of restricted stock vesting was $2.5 million, $2.3 million and $0.9 million for the years ended December 31, 2011, 2010, and 2009, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was $0.8 million, $0.7 million and $0.3 million, respectively.

As of December 31, 2011, total compensation cost related to restricted stock not yet recognized was approximately $2.4 million, which is expected to be recognized over the next 20 months on a weighted-average basis.

Performance Units:   In January 2011, 2010 and 2009, the Compensation Committee awarded 435,690, 555,830 and 666,440 performance units, respectively, to officers and other key employees under the Wisconsin Energy Performance Unit Plan. Under the grants, the ultimate number of units that will be awarded is dependent upon the achievement of certain financial performance of our stock over a three-year period. Under the terms of the award, participants may earn between 0% and 175% of the base performance unit award. All grants are settled in cash. We are accruing compensation costs over the three-year performance period based on our estimate of the final expected value of the awards. Performance units earned as of December 31, 2011, 2010 and 2009 vested and were settled during the first quarter of 2012, 2011 and 2010 and had a total intrinsic value of $26.7 million, $12.6 million and $9.8 million, respectively. The actual tax benefit realized for the tax deductions from the distribution of performance units was approximately $9.7 million, $4.3 million and $3.4 million, respectively.

89 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

In January 2012, the Compensation Committee awarded 346,570 performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

As of December 31, 2011, total compensation cost related to performance units not yet recognized was approximately $18.3 million, which is expected to be recognized over the next 19 months on a weighted-average basis.

Restrictions:Wisconsin Energy's ability as a holding company to pay common dividends primarily depends on the availability of funds received from its non-utility subsidiary, We Power, and its utility subsidiaries.

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

The January 2010 PSCW rate case order requires Wisconsin Electric and Wisconsin Gas to maintain capital structures that differ from GAAP as they reflect regulatory adjustments. Wisconsin Electric is required to maintain a common equity ratio range of between 48.5% and 53.5%, and Wisconsin Gas is required to maintain a capital structure which has a common equity range of between 45.0% and 50.0%. Wisconsin Electric and Wisconsin Gas must obtain PSCW approval if they pay dividends above the test year levels that would cause either company to fall below the authorized levels of common equity.

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

We have the option to defer interest payments on the Junior Notes, from time to time, for one or more periods of up to 10 consecutive years per period. During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.

As of December 31, 2011, the restricted net assets of consolidated and unconsolidated subsidiaries and our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method total approximately $3.5 billion. This amount exceeds 25% of our consolidated net assets as of December 31, 2011.

See Note K for discussion of certain financial covenants related to the bank back-up credit facilities of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas.

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

Common Stock Activity:  We do not expect to issue new shares under our various employee benefit plans and our dividend reinvestment and share purchase plan; rather, we instruct independent plan agents to purchase the shares in the open market. In that regard, no new shares of common stock were issued in 2011, 2010 or 2009.

During 2011, 2010 and 2009, our plan agents purchased 3.0 million shares at a cost of $93.9 million, 5.8 million shares at a cost of $156.6 million and 1.4 million shares at a cost of $29.6 million, respectively, to fulfill exercised stock options and restricted stock awards. In 2011, 2010 and 2009, we received proceeds of $54.4 million, $90.9 million and $17.0 million, respectively, related to the exercise of stock options.

In addition, on May 5, 2011, our Board of Directors authorized a share repurchase program for up to $300 million of our common stock through the end of 2013. The repurchase program does not obligate Wisconsin Energy to acquire any specific number of shares and may be suspended or terminated by the Board of Directors at any time. Through December 31, 2011, we repurchased approximately 3.2 million shares pursuant to this program at an average cost of $30.79 per share and a total cost of $100.0 million.

90 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

J -- LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

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

	(Millions of Dollars)
2012	$	20.3
2013	396.3
2014	322.4
2015	399.5
2016	27.4
Thereafter	3,375.5
Total	$	4,541.4

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

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

On April 1, 2011, we used cash and short-term borrowings to retire $450 million of long-term debt that matured.

In January 2011, we issued a total of $420 million in long-term debt ($205 million aggregate principal amount of 4.673% Series B Senior Notes due January 19, 2031 and $215 million aggregate principal amount of 5.848% Series B Senior Notes due January 19, 2041) and used the net proceeds to repay short-term debt incurred to finance the construction of OC 2 and for other corporate purposes. The Series B Senior Notes are secured by a collateral assignment of the leases between Elm Road Generating Station Supercritical, LLC (ERGSS) and Wisconsin Electric related to OC 2.

In February 2010, we issued a total of $530 million in long-term debt ($255 million aggregate principal amount of 5.209% Series A Senior Notes due February 11, 2030 and $275 million aggregate principal amount of 6.09% Series A Senior Notes due February 11, 2040) and used the net proceeds to repay debt incurred to finance the construction of OC 1. The Series A Senior Notes are secured by a collateral assignment of the leases between ERGSS and Wisconsin Electric related to OC 1.

During 2010, we retired $281.5 million of unsecured notes through the issuance of long-term and short-term debt.

During 2009, we issued $261.5 million of long-term debt, including $250 million of debentures under an existing shelf registration statement filed by Wisconsin Electric with the SEC in August 2007. The net proceeds were used to repay short-term debt and for other general corporate purposes.

Wisconsin Electric is the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amount of $147 million. In August 2009, Wisconsin Electric terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. Wisconsin Electric purchased the bonds at par plus accrued interest to the date of purchase. As of December 31, 2011 and 2010, the repurchased bonds were still outstanding, but were reported as a reduction in our consolidated long-term debt because they are held by Wisconsin Electric. Depending on market conditions and other factors, Wisconsin Electric may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.

In connection with our outstanding Junior Notes, we executed the RCC for the benefit of persons that buy, hold or sell a specified series of long-term indebtedness (covered debt). Our 6.20% Senior Notes due April 1, 2033 have been designated as the covered debt under the RCC. The RCC provides that we may not redeem, defease or purchase and our subsidiaries may not purchase any Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, during the 180 days prior to the date of redemption, defeasance or

91 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

purchase, we have received a specified amount of proceeds from the sale of qualifying securities.

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

We treat the long-term power purchase contract as an operating lease for rate-making purposes and we record our minimum lease payments as purchased power expense on the Consolidated Income Statements. We paid a total of $31.3 million and $30.2 million in lease payments during 2011 and 2010, respectively. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on our Consolidated Balance Sheets (see Regulatory Assets - Deferred plant related -- capital lease in Note C). Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to approximately $78.5 million during 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the capital lease was $132.4 million as of December 31, 2011, and will decrease to zero over the remaining life of the contract.

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

Capital Lease Assets	2011			2010
	(Millions of Dollars)
Leased Facilities
Long-term power purchase commitment	$	140.3		$	140.3
Accumulated amortization	(81.1		)	(75.5		)
Total Leased Facilities	$	59.2		$	64.8

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

	(Millions of Dollars)
2012	$	38.9
2013	40.4
2014	41.9
2015	43.5
2016	45.1
Thereafter	85.4
Total Minimum Lease Payments	295.2
Less:  Estimated Executory Costs	(74.9		)
Net Minimum Lease Payments	220.3
Less:  Interest	(87.9		)
Present Value of Net
Minimum Lease Payments	132.4
Less:  Due Currently	(12.4		)
	$	120.0

92 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

K -- SHORT-TERM DEBT

Short-term notes payable balances and their corresponding weighted-average interest rates as of December 31 consist of:

	2011				2010
			Interest				Interest
Short-Term Debt	Balance		Rate		Balance		Rate
	(Millions of Dollars, except for percentages)
Commercial paper	$	669.9	0.27	%	$	657.9	0.30	%

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

	2011			2010
	(Millions of Dollars, except for percentages)
Maximum Short-Term Debt Outstanding	$	717.3		$	821.0
Average Short-Term Debt Outstanding	$	505.1		$	528.7
Weighted-Average Interest Rate	0.25		%	0.32		%

Wisconsin Energy, Wisconsin Electric and Wisconsin Gas have entered into bank back-up credit facilities to maintain short-term credit liquidity which, among other terms, require the companies to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 70%, 65% and 65%, respectively.

As of December 31, 2011, we had approximately $1.2 billion of available undrawn lines under our bank back-up credit facilities and approximately $669.9 million of commercial paper outstanding that was supported by the available lines of credit. Our bank back-up credit facilities expire in December 2013.

The Wisconsin Energy, Wisconsin Electric and Wisconsin Gas bank back-up credit facilities contain customary covenants, including certain limitations on the respective companies' ability to sell assets. The credit facilities also contain customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, ERISA defaults and change of control. In addition, pursuant to the terms of Wisconsin Energy's credit agreement, Wisconsin Energy must ensure that certain of its subsidiaries comply with several of the covenants contained therein.

As of December 31, 2011, we were in compliance with all financial covenants.

L -- DERIVATIVE INSTRUMENTS

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

We record derivative instruments on the balance sheet as an asset or liability measured at its fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. We do not offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivatives executed with the same counterparty under the same master netting arrangement. As of December 31, 2011, we recognized $29.6 million in regulatory assets and $21.7 million in regulatory liabilities related to derivatives in comparison to $22.0 million in regulatory assets and $15.3 million in regulatory liabilities as

93 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

of December 31, 2010.

We record our current derivative assets on the balance sheet in other current assets and the current portion of the liabilities in other current liabilities. The long-term portion of our derivative assets of $2.5 million is recorded in other deferred charges and other assets, and the long-term portion of our derivative liabilities of $0.7 million is recorded in other long-term liabilities. Our Consolidated Balance Sheets as of December 31, 2011 and 2010 include:

	December 31, 2011				December 31, 2010
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	2.1	$	9.1	$	2.5	$	11.6
Fuel Oil	0.3		0.1		4.4		—
FTRs	5.7		—		5.9		—
Coal	12.5		—		2.9		—
Total	$	20.6	$	9.2	$	15.7	$	11.6

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

	2011				2010
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)
Natural Gas	71.8 million Dth	$	(33.4	)	83.2 million Dth	$	(43.8	)
Power	zero MWh	—			234,720 MWh	(0.5		)
Fuel Oil	13.0 million gallons	6.9			8.1 million gallons	(0.5		)
FTRs	23,718 MW	12.5			25,234 MW	19.2
Total		$	(14.0	)		$	(25.6	)

As of December 31, 2011 and 2010, we posted collateral of $11.9 million and $11.7 million, respectively, in our margin accounts. These amounts are recorded on the balance sheets in other current assets.

For the year ended December 31, 2011, we reclassified $0.2 million and for the years ended December 31, 2010 and 2009, we reclassified $0.4 million in treasury lock agreement settlement payments deferred in Accumulated Other Comprehensive Income, as an increase to Interest Expense. We estimate that during the next 12 months, $0.1 million will be reclassified from Accumulated Other Comprehensive Income as a reduction in earnings.

M -- FAIR VALUE MEASUREMENTS

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

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

94 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

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

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

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

Level 3 -- Pricing inputs include significant inputs that are generally less observable from objective sources. The inputs in the determination of fair value require significant management judgment or estimation. At each balance sheet date, we perform an analysis of all instruments subject to fair value reporting and include in Level 3 all instruments whose fair value is based on significant unobservable inputs.

In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, an instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the instrument.

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

Recurring Fair Value Measures	As of December 31, 2011
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	45.5	$	—	$	—	$	45.5
Derivatives	0.3		14.6		5.7		20.6
Total	$	45.8	$	14.6	$	5.7	$	66.1
Liabilities:
Derivatives	$	8.2	$	1.0	$	—	$	9.2
Total	$	8.2	$	1.0	$	—	$	9.2

Recurring Fair Value Measures	As of December 31, 2010
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	8.3	$	—	$	—	$	8.3
Derivatives	4.5		5.3		5.9		15.7
Total	$	12.8	$	5.3	$	5.9	$	24.0
Liabilities:
Derivatives	$	6.1	$	5.5	$	—	$	11.6
Total	$	6.1	$	5.5	$	—	$	11.6

Restricted cash consists of certificates of deposit and government backed interest bearing securities and represents (i) for 2010, the remaining funds to be distributed to customers resulting from the net proceeds received from the sale of Point Beach, and (ii) for 2011, the settlement we received from the DOE during the first quarter of 2011, which is being returned, net of costs incurred, to customers. Derivatives reflect positions we hold in exchange-traded derivative contracts and OTC derivative contracts. Exchange-traded derivative contracts, which include futures and exchange-traded options, are generally based on unadjusted quoted prices in active markets and are

95 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

classified within Level 1. Some OTC derivative contracts are valued using broker or dealer quotations, or market transactions in either the listed or OTC markets utilizing a mid-market pricing convention (the mid-point between bid and ask prices), as appropriate. In such cases, these derivatives are classified within Level 2. Certain OTC derivatives may utilize models to measure fair value. Generally, we use a similar model to value similar instruments. Valuation models utilize various inputs which include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs (i.e., inputs derived principally from or corroborated by observable market data by correlation or other means). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Certain OTC derivatives are in less active markets with a lower availability of pricing information which might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in Level 3.

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

	2011			2010
	(Millions of Dollars)
Balance as of January 1	$	5.9		$	5.8
Realized and unrealized gains (losses)	—			—
Purchases and issuances	16.1			17.9
Settlements	(16.3		)	(17.8		)
Transfers in and/or out of Level 3	—			—
Balance as of December 31	$	5.7		$	5.9
Change in unrealized gains (losses) relating to instruments still held as of December 31	$	—		$	—

Derivative instruments reflected in Level 3 of the hierarchy include MISO FTRs that are measured at fair value each reporting period using monthly or annual auction shadow prices from relevant auctions. Changes in fair value for Level 3 recurring items are recorded on our balance sheet. See Note L -- Derivative Instruments, for further information on the offset to regulatory assets and liabilities.

The carrying amount and estimated fair value of certain of our recorded financial instruments as of December 31 are as follows:

	2011				2010
	Carrying		Fair		Carrying		Fair
Financial Instruments	Amount		Value		Amount		Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	25.1	$	30.4	$	23.5
Long-term debt including current portion	$	4,541.4	$	5,179.9	$	4,288.0	$	4,578.0

The carrying value of net accounts receivable, accounts payable and short-term borrowings approximates fair value due to the short-term nature of these instruments. The fair value of our preferred stock is estimated based upon the quoted market value for the same or similar issues. The fair value of our long-term debt, including the current portion of long-term debt, but excluding capitalized leases and unamortized discount on debt, is estimated based upon quoted market value for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows.

96 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

N -- BENEFITS

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

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

We use a year-end measurement date to measure the funded status of all of our pension and OPEB plans. Due to the regulated nature of our business, we have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of our pension and OPEB plans qualify as a regulatory asset.

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

	Pension						OPEB
	2011			2010			2011			2010
	(Millions of Dollars)
Change in Benefit Obligation
Benefit Obligation at January 1	$	1,222.8		$	1,160.7		$	368.3		$	374.7
Service cost	15.9			23.7			10.4			11.2
Interest cost	67.6			68.4			20.8			21.2
Participants' contributions	—			—			11.6			6.5
Plan amendments	—			—			0.4			0.3
Actuarial loss (gain)	98.0			53.4			7.6			(23.8		)
Curtailments	—			—			—			(1.0		)
Gross benefits paid	(73.7		)	(83.4		)	(30.3		)	(21.8		)
Federal subsidy on benefits paid	N/A			N/A			0.9			1.0
Benefit Obligation at December 31	$	1,330.6		$	1,222.8		$	389.7		$	368.3
Change in Plan Assets
Fair Value at January 1	$	1,059.5		$	1,026.0		$	216.7		$	202.6
Actual earnings on plan assets	33.8			110.1			9.0			24.5
Employer contributions	242.9			6.8			48.4			4.9
Participants' contributions	—			—			11.6			6.5
Gross benefits paid	(73.7		)	(83.4		)	(30.3		)	(21.8		)
Fair Value at December 31	$	1,262.5		$	1,059.5		$	255.4		$	216.7
Net Liability	$	68.1		$	163.3		$	134.3		$	151.6

As of December 31, 2011, our qualified pension plans were over-funded by $24.4 million and our non-qualified pension plans were under-funded by $92.5 million. As of December 31, 2010, our qualified and non-qualified pension plans were under-funded by $71.7 million and $91.6 million, respectively.

97 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

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

	Pension				OPEB
	2011		2010		2011		2010
	(Millions of Dollars)
Other deferred charges	$	—	$	—	$	20.3	$	38.3
Other long-term liabilities	68.1		163.3		154.6		189.9
Net liability	$	68.1	$	163.3	$	134.3	$	151.6

The accumulated benefit obligation for all defined benefit plans was $1,329.4 million and $1,222.5 million as of December 31, 2011 and 2010, respectively.

The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31 and are recorded as a regulatory asset on our balance sheet:

	Pension				OPEB
	2011		2010		2011			2010
	(Millions of Dollars)
Net actuarial loss	$	633.4	$	521.0	$	108.1		$	98.9
Prior service costs (credits)	14.4		16.7		(6.1		)	(8.5		)
Transition obligation	—		—		0.3			0.6
Total	$	647.8	$	537.7	$	102.3		$	91.0

We estimate that 2012 periodic pension and OPEB costs will include the amortization of previously unrecognized benefit costs referred to above of $43.9 million and $5.5 million, respectively.

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

	Pension									OPEB
	2011			2010			2009			2011			2010			2009
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	15.9		$	23.7		$	23.3		$	10.4		$	11.2		$	8.7
Interest cost	67.6			68.4			72.3			20.8			21.2			20.5
Expected return on plan assets	(82.1		)	(78.2		)	(95.4		)	(16.9		)	(14.3		)	(13.6		)
Amortization of:
Transition obligation	—			—			—			0.3			0.3			0.3
Prior service cost (credit)	2.2			2.2			2.2			(1.9		)	(11.9		)	(12.6		)
Actuarial loss	34.0			26.8			18.9			6.2			10.8			8.9
Curtailment (gain)	—			—			—			—			(0.4		)	—
Net Periodic Benefit Cost	$	37.6		$	42.9		$	21.3		$	18.9		$	16.9		$	12.2

In addition to the costs above, in 2011 we recorded net pension costs of less than $0.04 per share related to the settlement of pension litigation. See Note R -- Commitments and Contingencies in this report. The charges were after considering insurance and reserves established in the prior year.

98 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

	Pension			OPEB
	2011	2010	2009	2011	2010	2009
Weighted-Average assumptions used to
determine benefit obligations as of Dec. 31
Discount rate	5.05%	5.60%	6.05%	5.20%	5.70%	5.75%
Rate of compensation increase	4.0%	4.0%	4.0%	N/A	N/A	N/A
Weighted-Average assumptions used to
determine net cost for year ended Dec. 31
Discount rate	5.60%	6.05%	6.50%	5.70%	5.75%	6.50%
Expected return on plan assets	7.25%	7.25%	8.25%	7.50%	7.50%	8.25%
Rate of compensation increase	4.0%	4.0%	4.0%	N/A	N/A	N/A

Assumed health care cost trend rates as of Dec. 31	2011	2010	2009
Health care cost trend rate assumed for next year (Pre 65 / Post 65)	8.0%/12%	7.5%/16%	7.5%/20%
Rate that the cost trend rate gradually adjusts to	5.0%	5.0%	5.0%
Year that the rate reaches the rate it is assumed to remain at (Pre 65 / Post 65)	2017/2017	2015/2016	2015/2016

The expected long-term rate of return on pension and OPEB plan assets was 7.25% and 7.50%, respectively, in 2011 and 2010. The expected long-term rate of return for all plan assets was 8.25% in 2009. We consult with our investment advisors on an annual basis to help us forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund.

A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	1% Increase		1% Decrease
	(Millions of Dollars)
Effect on
Post-retirement benefit obligation	$	31.9	$	(26.8	)
Total of service and interest cost components	$	3.8	$	(3.1	)

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

Plan Assets:   Current pension trust assets and amounts which are expected to be contributed to the trusts in the future are expected to be adequate to meet pension payment obligations to current and future retirees.

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

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

99 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

The following table summarizes the fair value of our pension plan assets by asset category within the fair value hierarchy (for further level information, see Note M):

	As of December 31, 2011
Asset Category - Pension	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	8.5	$	—	$	—	$	8.5
Equities:
U.S. Equity	455.1		—		—		455.1
International Equity	100.4		33.9		—		134.3
Fixed Income
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	76.9		502.8		—		579.7
International Bonds	40.9		44.0		—		84.9
Total	$	681.8	$	580.7	$	—	$	1,262.5

	As of December 31, 2010
Asset Category - Pension	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	21.1	$	—	$	—	$	21.1
Equities:
U.S. Equity	217.2		247.5		—		464.7
International Equity	81.1		21.6		—		102.7
Fixed Income
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	49.7		361.5		—		411.2
International Bonds	31.8		28.0		—		59.8
Total	$	400.9	$	658.6	$	—	$	1,059.5

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

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

	As of December 31, 2011
Asset Category - OPEB	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	2.4	$	—	$	—	$	2.4
Equities:
U.S. Equity	113.6		—		—		113.6
International Equity	32.1		2.3		—		34.4
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	8.2		83.0		—		91.2
International Bonds	8.7		5.1		—		13.8
Total	$	165.0	$	90.4	$	—	$	255.4

100 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

	As of December 31, 2010
Asset Category - OPEB	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	1.5	$	—	$	—	$	1.5
Equities:
U.S. Equity	41.6		80.1		—		121.7
International Equity	5.2		1.4		—		6.6
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	21.8		59.4		—		81.2
International Bonds	2.0		3.7		—		5.7
Total	$	72.1	$	144.6	—		$	216.7

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

Cash Flows:   

Employer	Pension
Contributions	Qualified		Non-Qualified		OPEB
	(Millions of Dollars)
2009	$	270.0	$	5.8	$	24.3
2010	$	—	$	6.8	$	4.9
2011	$	236.4	$	6.5	$	48.4

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

Year	Pension		Gross OPEB		Expected Medicare Part D Subsidy
	(Millions of Dollars)
2012	$	110.1	$	20.2	$	(0.9	)
2013	$	101.3	$	20.8	$	—
2014	$	104.4	$	22.2	$	—
2015	$	103.6	$	23.5	$	—
2016	$	103.9	$	24.7	$	—
2017-2021	$	535.2	$	136.4	$	—

Savings Plans:   We sponsor savings plans which allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. Under these plans, we expensed matching contributions of $14.1 million, $13.8 million and $14.1 million during 2011, 2010 and 2009, respectively.

Postemployment Benefits:   Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $15.3 million as of December 31, 2011.

101 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

O -- GUARANTEES

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

	Maximum Potential		Liability
	Future Payments	Outstanding	Recorded
	(Millions of Dollars)
Guarantees	$2.7	$0.1	$—
Letters of Credit	$1.6	$0.1	$—

We provide guarantees to support obligations of our affiliates to third parties under agreements and surety bonds. In the event our affiliates fail to perform, we would be responsible for the obligations.

Wisconsin Electric is subject to the potential retrospective premiums that could be assessed under its insurance program.

P -- SEGMENT REPORTING

Our operating segments as of December 31, 2011 include a utility energy segment and a non-utility energy segment. We have organized our operating segments based upon the regulatory environment in which our utility subsidiaries operate and on how management makes decisions and measures performance. The segments are managed separately because each business requires different technology and marketing strategies. The accounting policies of the reportable operating segments are the same as those described in Note A.

Our utility energy segment primarily includes our electric and natural gas utility operations. Our electric utility operation engages in the generation, distribution and sale of electric energy in southeastern (including metropolitan Milwaukee), east central and northern Wisconsin and in the Upper Peninsula of Michigan. Our natural gas utility operation is engaged in the purchase, distribution and sale of natural gas to retail customers and the transportation of customer-owned natural gas throughout Wisconsin. Our non-utility energy segment derives its revenues primarily from the ownership of electric power generating facilities for long-term lease to Wisconsin Electric.

Summarized financial information concerning our operating segments for each of the three years ended December 31, 2011 is shown in the following table. The segment information below includes income from discontinued operations as a result of the sale of Edison Sault in May 2010 and the water utility in April 2009.

	Operating Segments							Eliminations
	Energy				Corporate &			& Reconciling			Total
Year Ended	Utility		Non-Utility		Other (a)			Items			Consolidated
	(Millions of Dollars)
December 31, 2011
Operating Revenues (b)	$	4,431.5	$	435.1	$	0.9		$	(381.1	)	$	4,486.4
Depreciation and Amortization	$	257.0	$	72.5	$	0.7		$	—		$	330.2
Operating Income (Loss)	$	544.8	$	348.9	$	(6.4	)	$	—		$	887.3
Equity in Earnings of Unconsolidated Affiliates	$	62.5	$	—	$	(0.9	)	$	—		$	61.6
Interest Expense, Net	$	110.0	$	66.7	$	59.5		$	(0.4	)	$	235.8
Income Tax Expense (Benefit)	$	182.7	$	112.8	$	(31.6	)	$	—		$	263.9
Income from Discontinued Operations, Net of Tax	$	—	$	—	$	13.4		$	—		$	13.4
Net Income (Loss)	$	376.3	$	169.8	$	525.9		$	(545.8	)	$	526.2
Capital Expenditures	$	792.2	$	31.2	$	7.4		$	—		$	830.8
Total Assets (c)	$	13,433.5	$	2,949.0	$	4,694.8		$	(7,215.2	)	$	13,862.1

102 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

	Operating Segments							Eliminations
	Energy				Corporate &			& Reconciling			Total
Year Ended	Utility		Non-Utility		Other (a)			Items			Consolidated
	(Millions of Dollars)
December 31, 2010
Operating Revenues (b)	$	4,165.3	$	320.2	$	0.5		$	(283.5	)	$	4,202.5
Depreciation and Amortization	$	251.4	$	53.5	$	0.7		$	—		$	305.6
Operating Income (Loss)	$	564.0	$	252.4	$	(6.0	)	$	—		$	810.4
Equity in Earnings of Unconsolidated Affiliates	$	60.1	$	—	$	(0.2	)	$	—		$	59.9
Interest Expense, Net	$	117.2	$	40.3	$	52.8		$	(3.9	)	$	206.4
Income Tax Expense (Benefit)	$	192.1	$	84.9	$	(27.1	)	$	—		$	249.9
Income from Discontinued Operations, Net of Tax	$	0.7	$	—	$	1.4		$	—		$	2.1
Net Income (Loss)	$	354.2	$	128.4	$	456.4		$	(482.5	)	$	456.5
Capital Expenditures	$	687.0	$	109.3	$	1.9		$	—		$	798.2
Total Assets (c)	$	11,997.4	$	2,914.2	$	5,075.9		$	(6,927.7	)	$	13,059.8

December 31, 2009
Operating Revenues (b)	$	4,092.0	$	163.1	$	0.2		$	(154.4	)	$	4,100.9
Depreciation and Amortization	$	313.1	$	29.2	$	0.7		$	—		$	343.0
Operating Income (Loss)	$	550.9	$	120.1	$	(10.7	)	$	—		$	660.3
Equity in Earnings of Unconsolidated Affiliates	$	59.1	$	—	$	(0.2	)	$	—		$	58.9
Interest Expense, Net	$	117.5	$	14.7	$	54.3		$	(29.8	)	$	156.7
Income Tax Expense (Benefit)	$	186.7	$	43.4	$	(14.6	)	$	—		$	215.5
Income from Discontinued Operations, Net of Tax	$	1.8	$	—	$	4.9		$	—		$	6.7
Net Income (Loss)	$	334.2	$	63.8	$	382.3		$	(397.9	)	$	382.4
Capital Expenditures	$	547.0	$	253.2	$	14.4		$	—		$	814.6
Total Assets (c)	$	10,784.6	$	2,754.1	$	5,385.5		$	(6,226.3	)	$	12,697.9

(a) Corporate & Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark as well as interest on corporate debt.

(b) An elimination for intersegment revenues is included in Operating Revenues. This elimination is primarily between We Power and Wisconsin Electric.

(c) An elimination of $2,369.0 million, $1,785.9 million and $889.1 million is included in Total Assets as of December 31, 2011, 2010 and 2009, respectively, for all PTF-related activity between We Power and Wisconsin Electric.

Q -- RELATED PARTIES

We receive and/or provide certain services to other associated companies in which we have an equity investment.

American Transmission Company LLC:   As of December 31, 2011, we have a 26.2% interest in ATC. We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance and project management work for ATC, which are reimbursed to us by ATC. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while projects are under construction, including the new generating units constructed as part of our PTF strategy. ATC reimburses us for these costs when new generation is placed in service. As of December 31, 2011 and 2010, we had a receivable of $5.4 million and $3.8 million, respectively, for these items. During the years ended December 31, 2011, 2010 and 2009, our equity in earnings from ATC was $62.5 million, $60.1 million and $59.1 million, respectively. During the years ended December 31, 2011, 2010 and 2009, distributions received from ATC were $49.7 million, $49.3 million and $46.6 million, respectively.

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

103 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

Equity Investee	2011		2010		2009
	(Millions of Dollars)
Services Provided
–ATC	$	10.8	$	16.9	$	22.3
Services Received
–ATC	$	219.2	$	220.8	$	196.0

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

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

R -- COMMITMENTS AND CONTINGENCIES

Capital Expenditures:   We have made certain commitments in connection with 2012 capital expenditures. During 2012, we estimate that total capital expenditures will be approximately $740.2 million.

Operating Leases:   We enter into long-term purchase power contracts to meet a portion of our anticipated increase in future electric energy supply needs. These contracts expire at various times through 2018. Certain of these contracts were deemed to qualify as operating leases. In addition, we have various other operating leases including leases for coal cars.

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

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

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

Environmental Matters:   We periodically review our exposure for environmental remediation costs as evidence becomes available indicating that our liability has changed. Given current information, including the following, we believe that future costs in excess of the amounts accrued and/or disclosed on all presently known and quantifiable environmental contingencies will not be material to our financial position or results of operations.

We have a program of comprehensive environmental remediation planning for former manufactured gas plant sites and coal combustion product disposal sites. We perform ongoing assessments of manufactured gas plant sites and related disposal sites used by Wisconsin Electric and Wisconsin Gas, and coal combustion product disposal/landfill sites used by Wisconsin Electric, as discussed below. We are working with the WDNR in our investigation and remediation planning. At this time, we cannot estimate future remediation costs associated with these sites beyond

104 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

those described below.

Manufactured Gas Plant Sites:   We have identified several sites at which Wisconsin Electric, Wisconsin Gas, or a predecessor company historically owned or operated a manufactured gas plant. These sites have been substantially remediated or are at various stages of investigation, monitoring and remediation. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Based upon on-going analysis, we estimate that the future costs for detailed site investigation and future remediation costs may range from $21 million to $65 millionover the next ten years. This estimate is dependent upon several variables including, among other things, the extent of remediation, changes in technology and changes in regulation. As of December 31, 2011, we have established reserves of $37.5 million related to future remediation costs.

Historically, the PSCW has allowed Wisconsin utilities, including Wisconsin Electric and Wisconsin Gas, to defer the costs spent on the remediation of manufactured gas plant sites, and has allowed for these costs to be recovered in rates over five years. Accordingly, we have recorded a regulatory asset for remediation costs.

Coal Combustion Product Landfill Sites:   Wisconsin Electric aggressively seeks environmentally acceptable, beneficial uses for its coal combustion products. However, some coal combustion products have been, and to a small degree continue to be, managed in company-owned, licensed landfills. Some early designed and constructed landfills have at times required various levels of monitoring or remediation. Where Wisconsin Electric has become aware of these conditions, efforts have been made to define the nature and extent of any release, and work has been performed to address these conditions. During 2011, 2010 and 2009, Wisconsin Electric incurred $0.2 million, $0.4 million and $0.3 million respectively, in landfill remediation expenses. As of December 31, 2011, we have no reserves established related to coal combustion product landfill sites.

EPA - Consent Decree:   In April 2003, Wisconsin Electric reached a Consent Decree with the EPA, in which it agreed to significantly reduce air emissions from its coal-fired generating facilities. In July 2003, the Consent Decree was amended to include the state of Michigan, and in October 2007, the U.S. District Court for the Eastern District of Wisconsin approved and entered the amended Consent Decree. The Consent Decree was further amended in January 2012 to change the point of air monitoring at the Oak Creek Power Plant to accommodate the AQCS scheduled to begin service in 2012. The reductions are expected to be achieved by 2013 through a combination of installing new pollution control equipment, upgrading existing equipment and retiring certain older units. Through December 31, 2011, we have spent approximately $1.0 billion associated with the installation of air quality controls and have retired four coal units as part of our plan under the Consent Decree. The total cost of implementing this agreement is currently estimated to be approximately $1.1 billion over the ten year period ending 2013.

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

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

Oak Creek Construction Contract:   Bechtel, the contractor of the Oak Creek expansion under a fixed price contract, submitted claims to us on December 22, 2008 for cost and schedule relief related to the delay of the in-service dates for OC 1 and OC 2. These claims were asserted against Elm Road Services, LLC (ERS), the project

105 Wisconsin Energy Corporation

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

manager for the construction of the Oak Creek expansion and agent for the joint owners of OC 1 and OC 2. On October 30, 2009, Bechtel amended its claim to increase its request for cost relief and schedule relief. In its amended claim, Bechtel requested cost relief totaling approximately $517.5 million and schedule relief that would have resulted in approximately seven months of relief from liquidated damages beyond the guaranteed in-service date of September 29, 2009 for OC 1 and approximately four months of relief from liquidated damages beyond the guaranteed in-service date of September 29, 2010 for OC 2.

Bechtel's first claim was based on the alleged impact of severe weather and certain labor-related matters. Pursuant to its amended claim, Bechtel was requesting approximately $445.5 million in costs related to changed weather and labor conditions. Bechtel's second claim of approximately $72 million sought cost and schedule relief for the alleged effects of ERS-directed changes and delays allegedly caused by ERS prior to the issuance of the Full Notice to Proceed in July 2005. These claims, as well as claims submitted by ERS related to the rights of the parties under the construction contract and ERS counterclaims, had been submitted to binding arbitration.

Effective December 16, 2009, ERS and Bechtel entered into the Settlement Agreement that settled the claims between them regarding OC 1 and OC 2. Pursuant to the terms of this Settlement Agreement, ERS will pay to Bechtel $72 million to settle these claims payable upon the achievement of specific project milestones. As of December 31, 2011, Bechtel has received $67 million of the $72 million total settlement. The remaining milestone payments are tied to final acceptance of the units. In addition, Bechtel received 120 days of schedule relief for OC 1 and 60 days for OC 2. Therefore, the guaranteed in-service date of September 29, 2009 for OC 1 was extended to January 27, 2010, and the guaranteed in-service date of September 29, 2010 for OC 2 was extended to November 28, 2010. Bechtel subsequently received an additional 21 days of schedule relief for OC 2 as part of a change order signed concurrent with the turnover of OC 2. Therefore, the total schedule relief granted to Bechtel was 120 days for OC 1 and 81 days for OC 2.

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

Cash Balance Pension Plan:   In June 2009, a lawsuit was filed by Alan M. Downes, a former employee, against the Plan in the U.S. District Court for the Eastern District of Wisconsin. The complaint alleged that Plan participants who received a lump sum distribution under the Plan prior to their normal retirement age did not receive the full benefit to which they were entitled in violation of ERISA and were owed additional benefits, because the Plan failed to apply the correct interest crediting rate to project the cash balance account to their normal retirement age. In September 2010, the plaintiff filed a First Amended Class Action Complaint alleging additional claims under ERISA and adding Wisconsin Energy as a defendant.

In November 2011, we entered into a settlement agreement with the plaintiffs for $45.0 million, and the court promptly issued an order preliminarily approving the settlement. As part of the settlement agreement, we agreed to class certification for all similarly situated plaintiffs. The resolution of this matter resulted in a cost of less than $0.04 per share for 2011 after considering insurance and reserves established in the prior year. We do not anticipate further charges as a result of the settlement, other than certain process-related costs we expect to incur to implement the settlement. We expect the court to provide final approval of the settlement agreement in April 2012, and to pay additional benefits to class members promptly after receiving this approval.

S -- SUPPLEMENTAL CASH FLOW INFORMATION

During the year ended December 31, 2011, we paid $234.0 million in interest, net of amounts capitalized, and received $109.1 million in net refunds from income taxes. During the year ended December 31, 2010, we paid $198.0 million in interest, net of amounts capitalized, and $166.7 million in income taxes, net of refunds. During the year ended December 31, 2009, we paid $152.3 million in interest, net of amounts capitalized, and received $27.9 million in net refunds from income taxes.

As of December 31, 2011, 2010 and 2009, the amount of accounts payable related to capital expenditures was $16.7 million, $18.2 million and $14.7 million, respectively.

During the years ended December 31, 2011, 2010 and 2009, total amortization of deferred revenue was $54.4 million, $34.6 million and $8.0 million, respectively.

106 Wisconsin Energy Corporation

2011 Form 10-K

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Wisconsin Energy Corporation:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Wisconsin Energy Corporation and subsidiaries (the "Company") as of December 31, 2011 and 2010, and the related consolidated statements of income, common equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 Energy Corporation and subsidiaries 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 schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2012 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/DELOITTE & TOUCHE LLP

Milwaukee, Wisconsin

February 28, 2012

107 Wisconsin Energy Corporation

2011 Form 10-K

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Wisconsin Energy Corporation:

We have audited the internal control over financial reporting of Wisconsin Energy Corporation and subsidiaries (the "Company") as of December 31, 2011, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

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

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2011 of the Company and our report dated February 28, 2012 expressed an unqualified opinion on those financial statements and financial statement schedules.

/s/DELOITTE & TOUCHE LLP

Milwaukee, Wisconsin

February 28, 2012

108 Wisconsin Energy Corporation

2011 Form 10-K

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based upon such evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective (i) in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act and (ii) to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Management's Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of Wisconsin Energy Corporation's and subsidiaries' internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation, our management concluded that Wisconsin Energy Corporation's and subsidiaries' internal control over financial reporting was effective as of December 31, 2011.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of our financial statements has issued an attestation report on the effectiveness of Wisconsin Energy Corporation's and its subsidiaries' internal control over financial reporting as of December 31, 2011. Deloitte & Touche LLP's report is included in this report.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the fourth quarter of 2011 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

As we previously disclosed, James C. Fleming, Executive Vice President and General Counsel of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas, is retiring effective April 1, 2012. In connection with his retirement and in light of his many contributions to our success, on February 24, 2012, the Compensation Committee accelerated the vesting of all unvested shares of restricted stock awarded to Mr. Fleming, consisting of 5,825 shares, effective March 30, 2012.

109 Wisconsin Energy Corporation

2011 Form 10-K

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANT

The information under "Proposal 1: Election of Directors - Terms Expiring in 2013", "Section 16(a) Beneficial Ownership Reporting Compliance", "Corporate Governance - Frequently Asked Questions: What is the process used to identify director nominees and how do I recommend a nominee to the Corporate Governance Committee?", "Corporate Governance - Frequently Asked Questions: Are the Audit and Oversight, Corporate Governance and Compensation Committees comprised solely of independent directors?", "Corporate Governance - Frequently Asked Questions: Are all the members of the Audit Committee financially literate and does the committee have an 'audit committee financial expert'?" and "Committees of the Board of Directors - Audit and Oversight" in our Definitive Proxy Statement on Schedule 14A to be filed with the SEC for our Annual Meeting of Stockholders to be held May 3, 2012 (the "2012 Annual Meeting Proxy Statement") is incorporated herein by reference. Also see "Executive Officers of the Registrant" in Part I of this report.

We have adopted a written code of ethics, referred to as our Code of Business Conduct, that all of our directors, executive officers and employees, including the principal executive officer, principal financial officer and principal accounting officer, must comply with. We have posted our Code of Business Conduct on our website, www.wisconsinenergy.com. We have not provided any waiver to the Code for any director, executive officer or other employee. Any amendments to, or waivers for directors and executive officers from, the Code of Business Conduct will be disclosed on our website or in a current report on Form 8-K.

Our website, www.wisconsinenergy.com, also contains our Corporate Governance Guidelines and the charters of our Audit and Oversight, Corporate Governance and Compensation Committees.

Our Code of Business Conduct, Corporate Governance Guidelines and committee charters are also available without charge to any stockholder of record or beneficial owner of our common stock by writing to the corporate secretary, Susan H. Martin, at our principal business office, 231 West Michigan Street, P.O. Box 1331, Milwaukee, Wisconsin 53201.

ITEM 11. EXECUTIVE COMPENSATION

The information under "Compensation Discussion and Analysis", "Executive Officers' Compensation", "Director Compensation", "Committees of the Board of Directors - Compensation", "Compensation Committee Report", "Risk Analysis of Compensation Policies and Practices" and "Certain Relationships and Related Transactions - Compensation Committee Interlocks and Insider Participation" in the 2012 Annual Meeting Proxy Statement is incorporated herein by reference.

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

The security ownership information called for by Item 12 of Form 10-K is incorporated herein by reference to this information included under "WEC Common Stock Ownership" in the 2012 Annual Meeting Proxy Statement.

110 Wisconsin Energy Corporation

2011 Form 10-K

EQUITY COMPENSATION PLAN INFORMATION

The following table sets forth information about our equity compensation plans as of December 31, 2011:

	(a)		(b)		(c)
					Number of securities
	Number of securities to		Weighted-average		remaining available for
	be issued upon exercise		exercise price of		future issuance under equity
	of outstanding options,		outstanding options,		compensation plans (excluding
Plan Category	warrants and rights		warrants and rights		securities reflected in column (a))
Equity compensation plans approved by security holders	10,638,750	(1)	$	21.65	34,409,796
Equity compensation plans not approved by security holders	—		—		—
Total	10,638,750		$	21.65	34,409,796
(1) Represents options to purchase our common stock granted under our 1993 Omnibus Stock Incentive Plan,
amended and restated effective May 5, 2011.

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

The information under "Corporate Governance - Frequently Asked Questions: Who are the independent directors?", "Corporate Governance - Frequently Asked Questions: What are the Board's standards of independence", "Corporate Governance - Frequently Asked Questions: Are the Audit and Oversight, Corporate Governance and Compensation Committees comprised solely of independent directors?", "Corporate Governance - Frequently Asked Questions: Does the Company have policies and procedures in place to review and approve related party transactions?" and "Certain Relationships and Related Transactions" in the 2012 Annual Meeting Proxy Statement is incorporated herein by reference. A full description of the guidelines our Board uses to determine director independence is located in Appendix A of our Corporate Governance Guidelines, which can be found on our website, www.wisconsinenergy.com.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information regarding the fees paid to, and services performed by, our independent auditors and the pre-approval policy of our audit and oversight committee under "Independent Auditors' Fees and Services" in the 2012 Annual Meeting Proxy Statement is incorporated herein by reference.

111 Wisconsin Energy Corporation

2011 Form 10-K

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) 1. FINANCIAL STATEMENTS AND REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM INCLUDED IN PART II OF THIS REPORT

Description	Page in 10-K
Consolidated Income Statements for the three years ended December 31, 2011.	71
Consolidated Balance Sheets at December 31, 2011 and 2010.	72
Consolidated Statements of Cash Flows for the three years ended December 31, 2011.	74
Consolidated Statements of Common Equity for the three years ended December 31, 2011.	75
Consolidated Statements of Capitalization at December 31, 2011 and 2010.	76
Notes to Consolidated Financial Statements.	77
Reports of Independent Registered Public Accounting Firm.	107

2. FINANCIAL STATEMENT SCHEDULES INCLUDED IN PART IV OF THIS REPORT

Schedule I, Condensed Parent Company Financial Statements, including Income Statements and Cash Flows for the three years ended December 31, 2011 and Balance Sheets as of December 31, 2011 and 2010.

Schedule II, Valuation and Qualifying Accounts, for the three years ended December 31, 2011.

Other schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto.

3. EXHIBITS AND EXHIBIT INDEX

See the Exhibit Index included as the last part of this report, which is incorporated herein by reference. Each management contract and compensatory plan or arrangement required to be filed as an exhibit to this report is identified in the Exhibit Index by two asterisks (**) following the description of the exhibit.

112 Wisconsin Energy Corporation

2011 Form 10-K

WISCONSIN ENERGY CORPORATION

INCOME STATEMENTS

(Parent Company Only)

SCHEDULE I -- CONDENSED PARENT COMPANY

FINANCIAL STATEMENTS

	Year Ended December 31
	2011			2010			2009
	(Millions of Dollars)
Other Income, Net	$	2.7		$	4.2		$	24.2
Corporate Expense	4.8			4.0			8.9
Interest Expense	61.8			53.8			50.2
Loss before Taxes	(63.9		)	(53.6		)	(34.9		)
Income Tax Benefit	30.8			25.9			14.7
Loss after Taxes	(33.1		)	(27.7		)	(20.2		)
Equity in Subsidiaries' Continuing Operations	545.9			482.1			395.9
Income from Continuing Operations	512.8			454.4			375.7
Income from Discontinued Operations including Equity in Subsidiaries' Discontinued Operations	13.4			2.1			6.7
Net Income	$	526.2		$	456.5		$	382.4
See accompanying notes to condensed parent company financial statements.

113 Wisconsin Energy Corporation

2011 Form 10-K

WISCONSIN ENERGY CORPORATION

STATEMENTS OF CASH FLOWS

(Parent Company Only)

SCHEDULE I - CONDENSED PARENT COMPANY

FINANCIAL STATEMENTS - (Cont'd)

	Year Ended December 31
	2011			2010			2009
	(Millions of Dollars)
Operating Activities
Net income	$	526.2		$	456.5		$	382.4
Reconciliation to cash
Equity in subsidiaries' earnings	(545.9		)	(482.9		)	(397.7		)
Dividends and distributions from subsidiaries	995.5			305.3			225.2
Deferred income taxes, net	(350.9		)	(29.7		)	28.2
Accrued income taxes, net	363.4			41.9			(15.5		)
Change in - Other current assets	(0.1		)	11.5			8.1
Change in - Other current liabilities	8.9			3.0			(0.4		)
Change in - Accounts receivable	(18.7		)	477.2			1.7
Other, net	(10.2		)	(1.4		)	6.6
Cash Provided by Operating Activities	968.2			781.4			238.6
Investing Activities
Proceeds from asset sales	—			63.1			—
Capital contributions to associated companies	(36.5		)	(64.5		)	(108.9		)
Capitalized interest and other	2.4			(57.3		)	(42.7		)
Cash Used in Investing Activities	(34.1		)	(58.7		)	(151.6		)
Financing Activities
Exercise of stock options	54.4			90.9			17.0
Purchase of common stock	(193.9		)	(156.6		)	(29.6		)
Dividends paid on common stock	(242.0		)	(187.0		)	(157.8		)
Issuance of long-term debt	—			—			11.4
Retirement of long-term debt	(450.0		)	(281.5		)	—
Change in short-term debt	(116.5		)	(310.5		)	74.0
Change in notes payable due associated companies	3.9			106.1			(6.6		)
Other, net	9.9			15.8			3.4
Cash Used in Financing Activities	(934.2		)	(722.8		)	(88.2		)
Change in Cash and Cash Equivalents	(0.1		)	(0.1		)	(1.2		)
Cash and Cash Equivalents at Beginning of Year	0.6			0.7			1.9
Cash and Cash Equivalents at End of Year	$	0.5		$	0.6		$	0.7
See accompanying notes to condensed parent company financial statements.

114 Wisconsin Energy Corporation

2011 Form 10-K

WISCONSIN ENERGY CORPORATION

BALANCE SHEETS

(Parent Company Only)

SCHEDULE I - CONDENSED PARENT COMPANY

FINANCIAL STATEMENTS - (Cont'd)

	December 31
	2011		2010
	(Millions of Dollars)
Assets
Current Assets
Cash and cash equivalents	$	0.5	$	0.6
Accounts and notes receivable from associated companies	55.8		38.6
Prepaid taxes and other	2.2		93.8
Total Current Assets	58.5		133.0
Property and Investments
Investment in subsidiary companies	4,906.9		5,242.2
Other	2.6		70.3
Total Property and Investments	4,909.5		5,312.5
Deferred Charges and Other Assets	433.3		104.0
Total Assets	$	5,401.3	$	5,549.5
Liabilities and Equity
Current Liabilities
Long-term debt due currently	$	—	$	450.0
Short-term debt	146.5		263.0
Notes payable due associated companies	136.8		132.9
Accrued taxes and other	327.3		34.3
Total Current Liabilities	610.6		880.2
Long-term debt	693.6		692.9
Other Long-term liabilities	133.8		174.3
Stockholder's equity	3,963.3		3,802.1
Total Liabilities and Equity	$	5,401.3	$	5,549.5
See accompanying notes to condensed parent company financial statements.

115 Wisconsin Energy Corporation

2011 Form 10-K

WISCONSIN ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS

(Parent Company Only)

SCHEDULE I - CONDENSED PARENT COMPANY

FINANCIAL STATEMENTS - (Cont'd)

1.    For Parent Company only presentation, investment in subsidiaries are accounted for using the equity method. The condensed Parent Company financial statements and notes should be read in conjunction with the consolidated financial statements and notes of Wisconsin Energy Corporation appearing in this Annual Report on Form 10-K.

2.    Wisconsin Energy's ability as a holding company to pay common dividends primarily depends on the availability of funds received from the Parent Company's non-utility subsidiary, We Power, and its principal utility subsidiaries, Wisconsin Electric and Wisconsin Gas. During 2011, Wisconsin Electric and Wisconsin Gas collectively provided Wisconsin Energy with $272.6 million of dividends and distributions. We Power also provided Wisconsin Energy with $722.2 million of distributions during 2011, which includes the net proceeds from the issuance of $420 million of long-term debt in January 2011.

Various financing arrangements and regulatory requirements impose certain restrictions on the ability of the Parent Company's subsidiaries to transfer funds to the Parent Company in the form of cash dividends, loans or advances. In addition, under Wisconsin law, Wisconsin Electric and Wisconsin Gas are prohibited from loaning funds, either directly or indirectly, to the Parent Company.

Wisconsin Energy does not believe that these restrictions will materially affect the Parent Company's operations or limit any dividend payments in the foreseeable future.

3.    As of December 31, 2011, the maturities of the Parent Company long-term debt outstanding were as follows:

	(Millions of Dollars)
2012	$	—
2013	—
2014	—
2015	—
2016	—
Thereafter	700.0
Total	$	700.0

Wisconsin Energy amortizes debt premiums, discounts and debt issuance costs over the lives of the debt and includes the costs in interest expense.

During 2011, Wisconsin Energy used cash and short-term borrowings to retire $450 million of long-term debt that matured.

During 2010, Wisconsin Energy used cash and short-term borrowings to retire $281.5 million of unsecured notes.

During 2009, Wisconsin Energy issued $11.5 million of new notes and used the proceeds to repay short-term debt.

Wisconsin Energy's bank back-up credit facility contains customary covenants, including certain limitations on its ability to sell assets. The credit facility also contains customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, ERISA defaults and change of control. In addition, pursuant to the terms of the credit facility, Wisconsin Energy must ensure that certain of its subsidiaries comply with several of the covenants contained therein. In addition, Wisconsin Energy is required to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 70%.

116 Wisconsin Energy Corporation

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

As of December 31, 2011, Wisconsin Energy was in compliance with all covenants.

WECC is a subsidiary of Wisconsin Energy and has $80 million of long-term notes outstanding. In a Support Agreement between WECC and Wisconsin Energy, Wisconsin Energy agreed to make sufficient liquid asset contributions to WECC to permit WECC to service its debt obligations as they become due.

4.    Wisconsin Energy and certain of its subsidiaries enter into various guarantees to provide financial and performance assurance to third parties on behalf of affiliates. As of December 31, 2011, Wisconsin Energy had the following guarantees:

	Maximum				Liability
	Potential		Outstanding		Recorded
	Future		as of		as of
	Payments		Dec 31, 2011		Dec 31, 2011
	(Millions of Dollars)
Wisconsin Energy Guarantees
Utility	$	9.9	$	9.9	$	—
Non-Utility Energy	58.1		—		—
Other	0.3		—		—
Total	$	68.3	$	9.9	$	—
Letters of Credit	$	0.4	$	0.4	$	—

Utility guarantees support obligations of the utility segment under surety bonds, worker's compensation and agreements.

Wisconsin Energy's guarantees in support of its non-utility energy segment guaranty performance and payment obligations of We Power. The guarantees which support We Power are for obligations under purchase, construction and lease agreements with the utility segment and third parties.

Wisconsin Energy has a guarantee that supports an environmental indemnification obligation, which is unlimited, associated with the Minergy Neenah plant and indemnifications related to the post-closing obligations under the Minergy Neenah sale agreement which was effective September 7, 2006. Wisconsin Energy's other guarantees also support obligations to third parties under purchase and loan agreements and surety bonds. In the event the guarantee fails to perform, Wisconsin Energy would be responsible for the obligations.

5.    The carrying amount and estimated fair value of certain of our recorded financial instruments as of December 31 are as follows:

	2011				2010
	Carrying		Fair		Carrying		Fair
Financial Instruments	Amount		Value		Amount		Value
	(Millions of Dollars)
Long-term debt including current portion	$	700.0	$	750.8	$	1,150.0	$	1,217.4

The carrying value of net accounts receivable, accounts payable and short-term borrowings approximates fair value due to the short-term nature of these instruments. The fair value of our long-term debt, including the current portion of long-term debt, and unamortized discount on debt, is estimated based upon quoted market value for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the Parent Company's bond rating and the present value of future cash flows.

117 Wisconsin Energy Corporation

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS - (Cont'd) 2011 Form 10-K

6.    During the year ended December 31, 2011, Wisconsin Energy paid $57.7 million in interest, net of amounts capitalized, and received $114.6 million in refunds from income taxes. During the year ended December 31, 2010, Wisconsin Energy paid $43.5 million in interest, net of amounts capitalized, and received $1.0 million in refunds from income taxes. During the year ended December 31, 2009, Wisconsin Energy paid $45.2 million in interest, net of amounts capitalized, and received $36.0 million in refunds from income taxes.

118 Wisconsin Energy Corporation

2011 Form 10-K

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS

Allowance for Doubtful Accounts	Balance at Beginning of the Period		Expense		Deferral			Net Write-offs			Balance at End of the Period
	(Millions of Dollars)
December 31, 2011	$	58.1	$	85.8	$	(35.9	)	$	(46.3	)	$	61.7
December 31, 2010	$	57.9	$	86.2	$	(32.5	)	$	(53.5	)	$	58.1
December 31, 2009	$	48.8	$	54.6	$	12.9		$	(58.4	)	$	57.9

119 Wisconsin Energy Corporation

2011 Form 10-K

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.

		WISCONSIN ENERGY CORPORATION
	By	/s/GALE E. KLAPPA
Date:	February 28, 2012	Gale E. Klappa, Chairman of the Board, President
		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.

/s/GALE E. KLAPPA	February 28, 2012
Gale E. Klappa, Chairman of the Board, President and Chief
Executive Officer and Director -- Principal Executive Officer
/s/FREDERICK D. KUESTER	February 28, 2012
Frederick D. Kuester, Executive Vice President and Chief
Financial Officer -- Principal Financial Officer
/s/STEPHEN P. DICKSON	February 28, 2012
Stephen P. Dickson, Vice President and
Controller -- Principal Accounting Officer
/s/JOHN F. BERGSTROM	February 28, 2012
John F. Bergstrom, Director
/s/BARBARA L. BOWLES	February 28, 2012
Barbara L. Bowles, Director
/s/PATRICIA W. CHADWICK	February 28, 2012
Patricia W. Chadwick, Director
/s/ROBERT A. CORNOG	February 28, 2012
Robert A. Cornog, Director
/s/CURT S. CULVER	February 28, 2012
Curt S. Culver, Director
/s/THOMAS J. FISCHER	February 28, 2012
Thomas J. Fischer, Director
/s/ULICE PAYNE, JR.	February 28, 2012
Ulice Payne, Jr., Director
/s/MARY ELLEN STANEK	February 28, 2012
Mary Ellen Stanek, Director
/s/FREDERICK P. STRATTON, JR.	February 28, 2012
Frederick P. Stratton, Jr., Director

120 Wisconsin Energy Corporation

2011 Form 10-K

WISCONSIN ENERGY CORPORATION

(Commission File No. 001-09057)

EXHIBIT INDEX

to

Annual Report on Form 10-K

For the year ended December 31, 2011

The following exhibits are filed or furnished with or incorporated by reference in the report with respect to Wisconsin Energy Corporation. (An asterisk (*) indicates incorporation by reference pursuant to Exchange Act Rule 12b-32.)

Number	Exhibit
3	Articles of Incorporation and By-laws
	3.1*	Restated Articles of Incorporation of Wisconsin Energy Corporation, as amended and restated effective June 12, 1995. (Exhibit (3)-1 to Wisconsin Energy Corporation's 06/30/95 Form 10-Q.)
	3.2*	Bylaws of Wisconsin Energy Corporation, as amended to May 5, 2005. (Exhibit 3.2(b) to Wisconsin Energy Corporation's 12/31/04 Form 10-K.)
4	Instruments defining the rights of security holders, including indentures
	4.1*	Reference is made to Article III of the Restated Articles of Incorporation and the Bylaws of Wisconsin Energy Corporation. (Exhibits 3.1 and 3.2 herein.)
	4.2*	Replacement Capital Covenant, dated May 11, 2007, by Wisconsin Energy Corporation for the benefit of certain debtholders named therein. (Exhibit 4.2 to Wisconsin Energy Corporation's 05/08/07 Form 8-K.)
	Indentures and Securities Resolutions:
	4.3*	Indenture for Debt Securities of Wisconsin Electric Power Company (the "Wisconsin Electric Indenture"), dated December 1, 1995. (Exhibit (4)-1 under File No. 1-1245, Wisconsin Electric's 12/31/95 Form 10-K.)
	4.4*	Securities Resolution No. 1 of Wisconsin Electric under the Wisconsin Electric Indenture, dated December 5, 1995. (Exhibit (4)-2 under File No. 1-1245, Wisconsin Electric's 12/31/95 Form 10-K.)
	4.5*	Securities Resolution No. 2 of Wisconsin Electric under the Wisconsin Electric Indenture, dated November 12, 1996. (Exhibit 4.44 to Wisconsin Energy Corporation's 12/31/96 Form 10-K.)
	4.6*	Securities Resolution No. 3 of Wisconsin Electric under the Wisconsin Electric Indenture, dated May 27, 1998. (Exhibit (4)-1 under File No. 1-1245, Wisconsin Electric's 06/30/98 Form 10-Q.)
	4.7*	Securities Resolution No. 4 of Wisconsin Electric under the Wisconsin Electric Indenture, dated November 30, 1999. (Exhibit 4.46 under File No. 1-1245, Wisconsin Energy Corporation's/Wisconsin Electric's 12/31/99 Form 10-K.)

E-1 Wisconsin Energy Corporation

2011 Form 10-K

Number	Exhibit
	4.8*	Securities Resolution No. 5 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of May 1, 2003. (Exhibit 4.47 filed with Post-Effective Amendment No. 1 to Wisconsin Electric's Registration Statement on Form S-3 (File No. 333-101054), filed May 6, 2003.)
	4.9*	Securities Resolution No. 6 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of November 17, 2004. (Exhibit 4.48 filed with Post-Effective Amendment No. 1 to Wisconsin Electric's Registration Statement on Form S-3 (File No. 333-113414), filed November 23, 2004.)
	4.10*	Securities Resolution No. 7 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of November 2, 2006. (Exhibit 4.1 to Wisconsin Electric's 11/02/06 Form 8-K.)
	4.11*	Securities Resolution No. 8 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of September 25, 2008. (Exhibit 4.1 to Wisconsin Electric's 09/25/08 Form 8-K.)
	4.12*	Securities Resolution No. 9 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of December 8, 2008. (Exhibit 4.1 to Wisconsin Electric's 12/08/08 Form 8-K.)
	4.13*	Securities Resolution No. 10 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of December 8, 2009. (Exhibit 4.1 to Wisconsin Electric's 12/08/09 Form 8-K.)
	4.14*	Securities Resolution No. 11 of Wisconsin Electric under the Wisconsin Electric Indenture, dated as of September 7, 2011. (Exhibit 4.1 to Wisconsin Electric's 09/07/11 Form 8-K.)
	4.15*	Indenture for Debt Securities of Wisconsin Energy Corporation (the "Wisconsin Energy Indenture"), dated as of March 15, 1999. (Exhibit 4.46 to Wisconsin Energy Corporation's 03/25/99 Form 8-K.)
	4.16*	Securities Resolution No. 1 of Wisconsin Energy under the Wisconsin Energy Indenture, dated as of March 16, 1999. (Exhibit 4.47 to Wisconsin Energy Corporation's 03/25/99 Form 8-K.)
	4.17*	Securities Resolution No. 2 of Wisconsin Energy under the Wisconsin Energy Indenture, dated as of March 23, 2001. (Exhibit 4.1 to Wisconsin Energy Corporation's 03/31/01 Form 10-Q.)
	4.18*	Securities Resolution No. 3 of Wisconsin Energy under the Wisconsin Energy Indenture, dated as of November 13, 2001. (Exhibit 4.52 to Wisconsin Energy Corporation's 12/31/01 Form 10-K.)
	4.19*	Securities Resolution No. 4 of Wisconsin Energy under the Wisconsin Energy Indenture, dated as of March 17, 2003. (Exhibit 4.12 filed with Post-Effective Amendment No. 1 to Wisconsin Energy Corporation's Registration Statement on Form S-3 (File No. 333-69592), filed March 20, 2003.)
	4.20*	Securities Resolution No. 5 of Wisconsin Energy under the Wisconsin Energy Indenture, dated as of May 8, 2007. (Exhibit 4.1 to Wisconsin Energy Corporation's 05/08/07 Form 8-K.)

E-2 Wisconsin Energy Corporation

2011 Form 10-K

Number	Exhibit
		Certain agreements and instruments with respect to unregistered long-term debt not exceeding 10 percent of the total assets of the Registrant and its subsidiaries on a consolidated basis have been omitted as permitted by related instructions. The Registrant agrees pursuant to Item 601(b)(4) of Regulation S-K to furnish to the Securities and Exchange Commission, upon request, a copy of all such agreements and instruments.
10	Material Contracts
	10.1*	Asset Sale Agreement by and among Wisconsin Electric Power Company, FPL Energy Point Beach, LLC, as Buyer, and FPL Group Capital Inc., as Buyer's Parent, dated December 19, 2006 (the "Asset Sale Agreement"). (Exhibit 2.1 to Wisconsin Energy Corporation's 12/31/06 Form 10-K.)
	10.2*	Letter Agreement between Wisconsin Electric Power Company and FPL Energy Point Beach, LLC, dated May 24, 2007, which effectively amends the Asset Sale Agreement. (Exhibit 2.1 to Wisconsin Energy Corporation's 06/30/07 Form 10-Q.)
	10.3*	Letter Agreement between Wisconsin Electric Power Company, FPL Energy Point Beach, LLC and FPL Group Capital, Inc., dated September 28, 2007, which amends the Asset Sale Agreement. (Exhibit 2.3 to Wisconsin Energy Corporation's 09/28/07 Form 8-K.)
	10.4*	Wisconsin Energy Corporation Supplemental Pension Plan, effective as of January 1, 2005. (Exhibit 10.9 to Wisconsin Energy Corporation's 12/31/08 Form 10-K.)** See Note.
	10.5*	Service Agreement, dated April 25, 2000, between Wisconsin Electric Power Company and Wisconsin Gas Company (n/k/a Wisconsin Gas LLC). (Exhibit 10.32 to Wisconsin Energy Corporation's 12/31/00 Form 10-K.)
	10.6*	Service Agreement, dated December 29, 2000, between Wisconsin Electric Power Company and American Transmission Company LLC. (Exhibit 10.33 to Wisconsin Energy Corporation's 12/31/00 Form 10-K.)
	10.7*	Executive Deferred Compensation Plan of Wisconsin Energy Corporation, as amended and restated as of July 23, 2004 (including amendments approved effective as of November 2, 2005) (the "Legacy EDCP"). (Exhibit 10.2 to Wisconsin Energy Corporation's 09/30/05 Form 10-Q.)** See Note.
	10.8*	First Amendment to the Legacy EDCP, effective as of January 1, 2005. (Exhibit 10.12 to Wisconsin Energy Corporation's 12/31/08 Form 10-K.)** See Note.
	10.9	Wisconsin Energy Corporation Executive Deferred Compensation Plan, amended and restated effective as of September 8, 2009.** See Note.
	10.10*	Directors' Deferred Compensation Plan of Wisconsin Energy Corporation, as amended and restated as of May 1, 2004 (the "Legacy DDCP"). (Exhibit 10.3 to Wisconsin Energy Corporation's 06/30/04 Form 10-Q.)** See Note.
	10.11*	First Amendment to the Legacy DDCP, effective as of January 1, 2005. (Exhibit 10.15 to Wisconsin Energy Corporation's 12/31/08 Form 10-K.)** See Note.

E-3 Wisconsin Energy Corporation

2011 Form 10-K

Number	Exhibit
	10.12*	Wisconsin Energy Corporation Directors' Deferred Compensation Plan, effective as of January 1, 2005. (Exhibit 10.16 to Wisconsin Energy Corporation's 12/31/08 Form 10-K.)** See Note.
	10.13*	Wisconsin Energy Corporation Death Benefit Only Plan, as amended and restated as of July 22, 2010. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/10 Form 10-Q.) ** See Note.
	10.14*	Wisconsin Energy Corporation Short-Term Performance Plan, as amended and restated effective as of January 1, 2010. (Exhibit 10.1 to Wisconsin Energy Corporation's 12/03/09 Form 8-K.)** See Note.
	10.15*	Wisconsin Energy Corporation Amended and Restated Executive Severance Policy, effective as of January 1, 2008. (Exhibit 10.18 to Wisconsin Energy Corporation's 12/31/08 Form 10-K.)** See Note.
	10.16*	Restated Non-Qualified Trust Agreement by and between Wisconsin Energy Corporation and The Northern Trust Company dated February 11, 2004, regarding trust established to provide a source of funds to assist in meeting of the liabilities under various nonqualified deferred compensation plans made between Wisconsin Energy Corporation or its subsidiaries and various plan participants. (Exhibit 10.16 to Wisconsin Energy Corporation's 12/31/07 Form 10-K.)** See Note.
	10.17*	Affiliated Interest Agreement (Service Agreement), dated December 12, 2002, by and among Wisconsin Energy Corporation and its affiliates. (Exhibit 10.14 to Wisconsin Energy Corporation's 12/31/02 Form 10-K.)
	10.18*	Employment arrangement with Charles R. Cole, effective August 1, 1999. (Exhibit 10.3 to Wisconsin Energy Corporation's 12/31/00 Form 10-K.)** See Note.
	10.19*	Amendment of the employment arrangement with Charles R. Cole, dated December 11, 2008. (Exhibit 10.23 to Wisconsin Energy Corporation's 12/31/08 Form 10-K.)
	10.20*	Amended and Restated Senior Officer Employment and Non-Compete Agreement between Wisconsin Energy Corporation and Gale E. Klappa, dated as of December 29, 2008. (Exhibit 10.25 to Wisconsin Energy Corporation's 12/31/08 Form 10-K.)** See Note.
	10.21*	Amended and Restated Senior Officer Employment and Non-Compete Agreement between Wisconsin Energy Corporation and Allen L. Leverett, dated as of December 30, 2008. (Exhibit 10.26 to Wisconsin Energy Corporation's 12/31/08 Form 10-K.)** See Note.
	10.22*	Amended and Restated Senior Officer Employment and Non-Compete Agreement between Wisconsin Energy Corporation and Frederick D. Kuester, dated as of December 30, 2008. (Exhibit 10.27 to Wisconsin Energy Corporation's 12/31/08 Form 10-K.)** See Note.
	10.23*	Letter Agreement by and between Wisconsin Energy Corporation and James C. Fleming, dated as of November 23, 2005, which became effective January 3, 2006. (Exhibit 10.31 to Wisconsin Energy Corporation's 12/31/05 Form 10-K.)** See Note.

E-4 Wisconsin Energy Corporation

2011 Form 10-K

Number	Exhibit
	10.24*	Amendment to the Letter Agreement between Wisconsin Energy Corporation and James C. Fleming, dated December 23, 2008. (Exhibit 10.29 to Wisconsin Energy Corporation's 12/31/08 Form 10-K.)** See Note.
	10.25*	Amended and Restated Senior Officer, Change in Control, Severance and Non-Compete Agreement between Wisconsin Energy Corporation and Kristine A. Rappé, dated as of December 30, 2008. (Exhibit 10.30 to Wisconsin Energy Corporation's 12/31/08 Form 10-K.)** See Note.
	10.26*	Supplemental Pension Benefit Agreement between Wisconsin Energy Corporation and Stephen Dickson, effective May 23, 2001. (Exhibit 10.1 to Wisconsin Energy Corporation's 06/30/01 Form 10-Q.)** See Note.
	10.27*	Amendment to the Supplemental Pension Benefit Agreement between Wisconsin Energy Corporation and Stephen Dickson, dated December 29, 2008. (Exhibit 10.32 to Wisconsin Energy Corporation's 12/31/08 Form 10-K.)** See Note.
	10.28*	Amended and Restated Non-Compete and Special Severance Tax Protection Agreement between Wisconsin Energy Corporation and Stephen P. Dickson, effective as of January 1, 2008. (Exhibit 10.33 to Wisconsin Energy Corporation's 12/31/08 Form 10-K.)** See Note.
	10.29*	Letter Agreement by and between Wisconsin Energy Corporation and Robert Garvin, dated January 31, 2011. (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/11 Form 10-Q.)** See Note.
	10.30*	Letter Agreement by and between Wisconsin Energy Corporation and Joseph Kevin Fletcher, dated as of August 17, 2011. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/11 Form 10-Q.)** See Note.
	10.31*	1998 Revised forms of award agreements under 1993 Omnibus Stock Incentive Plan for non-qualified stock option awards to non-employee directors, restricted stock awards and option awards. (Exhibit 10.11 to Wisconsin Energy Corporation's 12/31/98 Form 10-K.)** See Note.
	10.32*	2001 Revised forms of award agreements under 1993 Omnibus Stock Incentive Plan for restricted stock awards, incentive stock option awards and non-qualified stock option awards. (Exhibit 10.3 to Wisconsin Energy Corporation's 03/31/01 Form 10-Q.)** See Note.
	10.33*	1993 Omnibus Stock Incentive Plan, amended and restated effective as of May 5, 2011, as approved by the stockholders at the 2011 annual meeting of stockholders. (Exhibit 10.1 to Wisconsin Energy Corporation's 06/30/11 Form 10-Q.)** See Note.
	10.34*	2005 Terms and Conditions Governing Non-Qualified Stock Option Award under 1993 Omnibus Stock Incentive Plan. (Exhibit 10.1 to Wisconsin Energy Corporation's 12/28/04 Form 8-K.)** See Note.
	10.35*	Terms and Conditions Governing Non-Qualified Stock Option Award under the 1993 Omnibus Stock Incentive Plan. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/07 Form 10-Q.)** See Note.

E-5 Wisconsin Energy Corporation

2011 Form 10-K

Number	Exhibit
	10.36*	Terms and Conditions Governing Restricted Stock Awards under the 1993 Omnibus Stock Incentive Plan, approved December 3, 2009. (Exhibit 10.3 to Wisconsin Energy Corporation's 12/03/09 Form 8-K.)** See Note.
	10.37*	Terms and Conditions Governing Restricted Stock Awards under the 1993 Omnibus Stock Incentive Plan, approved December 1, 2010. (Exhibit 10.1 to Wisconsin Energy Corporation's 12/01/10 Form 8-K.)** See Note.
	10.38*	Wisconsin Energy Corporation Terms and Conditions Governing Director Restricted Stock Award under the 1993 Omnibus Stock Incentive Plan, amended and restated effective May 5, 2011. (Exhibit 10.1 to Wisconsin Energy Corporation's 01/19/12 Form 8-K.)** See Note.
	10.39*	Wisconsin Energy Corporation Performance Unit Plan, amended and restated effective as of January 1, 2010. (Exhibit 10.2 to Wisconsin Energy Corporation's 12/03/09 Form 8-K.)** See Note.
	10.40*	Form of Award of Performance Units under the Wisconsin Energy Corporation Performance Unit Plan. (Exhibit 10.2 to Wisconsin Energy Corporation's 12/06/04 Form 8-K.)** See Note.
	10.41*	Port Washington I Facility Lease Agreement between Port Washington Generating Station, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of May 28, 2003. (Exhibit 10.7 to Wisconsin Electric Power Company's 06/30/03 Form 10-Q (File No. 001-01245).)
	10.42*	Port Washington II Facility Lease Agreement between Port Washington Generating Station, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of May 28, 2003. (Exhibit 10.8 to Wisconsin Electric Power Company's 06/30/03 Form 10-Q (File No. 001-01245).)
	10.43*	Elm Road I Facility Lease Agreement between Elm Road Generating Station Supercritical, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of November 9, 2004. (Exhibit 10.56 to Wisconsin Energy Corporation's 12/31/04 Form 10-K.)
	10.44*	Elm Road II Facility Lease Agreement between Elm Road Generating Station Supercritical, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of November 9, 2004. (Exhibit 10.57 to Wisconsin Energy Corporation's 12/31/04 Form 10-K.)
	10.45*	Point Beach Nuclear Plant Power Purchase Agreement between FPL Energy Point Beach, LLC and Wisconsin Electric Power Company, dated as of December 19, 2006 (the "PPA"). (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/08 Form 10-Q.)
	10.46*	Letter Agreement between Wisconsin Electric Power Company and FPL Energy Point Beach, LLC dated October 31, 2007, which amends the PPA. (Exhibit 10.45 to Wisconsin Energy Corporation's 12/31/07 Form 10-K.)
	Note:  Two asterisks (**) identify management contracts and executive compensation plans or arrangements required to be filed as exhibits pursuant to Item 15(b) of Form 10-K.

E-6 Wisconsin Energy Corporation

2011 Form 10-K

Number	Exhibit
21	Subsidiaries of the registrant
	21.1	Subsidiaries of Wisconsin Energy Corporation.
23	Consents of experts and counsel
	23.1	Deloitte & Touche LLP -- Milwaukee, WI, Consent of Independent Registered Public Accounting Firm.
31	Rule 13a-14(a) / 15d-14(a) Certifications
	31.1	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Section 1350 Certifications
	32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101	Interactive Data File

E-7 Wisconsin Energy Corporation

EX-10.9

Exhibit 10.9

WISCONSIN ENERGY CORPORATION

EXECUTIVE DEFERRED COMPENSATION PLAN

Amended and Restated Effective as of September 8, 2009

TABLE OF CONTENTS
			Page
INTRODUCTION			1
ARTICLE 1 DEFINITIONS			1
ARTICLE 2 ELIGIBILITY AND PARTICIPATION			7
	2.1	Selection by Committee	7
	2.2	Participation	7
	2.3	Enrollment Requirements	8
	2.4	Cessation of Participation	8
ARTICLE 3 DEFERRALS AND CONTRIBUTIONS			9
	3.1	Base Annual Salary	9
	3.2	Annual or Long-Term Performance Awards	9
	3.3	Restricted Stock	10
	3.4	Performance Shares or Units	10
	3.5	Dividend Equivalents	11
	3.6	Newly-Eligible Employees	11
	3.7	Annual Company Contribution Amount	11
	3.8	Company Matching Amount	12
ARTICLE 4 ACCOUNTS			13
	4.1	Establishment of Accounts	13
	4.2	Vesting	14
	4.3	Deemed Investments	15
	4.4	Taxes	17
ARTICLE 5 DISTRIBUTION OF ACCOUNT			17
	5.1	Time for Distribution	17
	5.2	In-Service Payout	18
	5.3	Benefits Upon Retirement	18
	5.4	Benefits Upon Separation from Service	18
	5.5	Benefits Upon Death	19
	5.6	Changes to Form of Payment	20
	5.7	Unforeseeable Emergency	21
	5.8	Change in Control	21
	5.9	Discretion to Accelerate Distribution	22
ARTICLE 6 LEAVE OF ABSENCE			22
ARTICLE 7 BENEFICIARY DESIGNATION			23
	7.1	Beneficiary	23
	7.2	Beneficiary Designation; Change	23
	7.3	Acknowledgment	23
	7.4	No Beneficiary Designation	23
	7.5	Doubt as to Beneficiary	23
	7.6	Discharge of Obligations	24

i

TABLE OF CONTENTS
(cont)
			Page
ARTICLE 8 TERMINATION, AMENDMENT OR MODIFICATION			24
	8.1	Termination	24
	8.2	Amendment	24
	8.3	Effect of Payment	25
ARTICLE 9 ADMINISTRATION			25
	9.1	Plan Administration	25
	9.2	Powers, Duties and Procedures	25
	9.3	Administration Upon Change In Control	26
	9.4	Agents	26
	9.5	Binding Effect of Decisions	26
	9.6	Indemnity of Committee	26
	9.7	Employer Information	27
	9.8	Coordination with Other Benefits	27
ARTICLE 10 CLAIMS PROCEDURES			27
	10.1	Presentation of Claim	27
	10.2	Decision on Initial Claim	27
	10.3	Right to Review	28
	10.4	Decision on Review	28
	10.5	Form of Notice and Decision	29
	10.6	Legal Action	29
ARTICLE 11 TRUST			29
	11.1	Establishment of the Trust	29
	11.2	Interrelationship of the Plan and the Trust	29
	11.3	Distributions From the Trust	29
ARTICLE 12 MISCELLANEOUS			29
	12.1	Status of Plan	29
	12.2	Unsecured General Creditor	30
	12.3	Employer's Liability	30
	12.4	Nonassignability	30
	12.5	Not a Contract of Employment	30
	12.6	Furnishing Information	30
	12.7	Receipt and Release	30
	12.8	Incompetent	31
	12.9	Governing Law and Severability	31
	12.10	Notices and Communications	31
	12.11	Successors	31
	12.12	Insurance	31
	12.13	Legal Fees To Enforce Rights After Change in Control	32
	12.14	Terms	32
	12.15	Headings	32

ii

WISCONSIN ENERGY CORPORATION

EXECUTIVE DEFERRED COMPENSATION PLAN

INTRODUCTION

Wisconsin Energy Corporation, a Wisconsin Corporation (the “Company”), previously established the Legacy Wisconsin Energy Corporation Executive Deferred Compensation Plan (previously named the Wisconsin Energy Corporation Executive Deferred Compensation Plan) (the “Legacy Plan”). The Company amended and restated the Legacy Plan effective July 23, 2004. The Company froze the Legacy Plan effective December 31, 2004 with respect to new deferrals such that all earned and vested amounts credited under the Legacy Plan are “grandfathered” within the meaning of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”) enacted under the American Jobs Creation Act of 2004.

Effective as of January 1, 2005, the Company established the Wisconsin Energy Corporation Executive Deferred Compensation Plan (the “Plan”), as set forth herein, to provide benefits to a select group of management and highly compensated employees who contribute materially to the continued growth, development and future business success of the Company and its subsidiaries, if any. The Plan shall be unfunded for tax purposes and for purposes of Title I of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”).

The Plan is intended to comply with the provisions of Code Section 409A, and any guidance and regulations issued thereunder. The Plan shall be interpreted and administered consistent with this intent and shall apply to all amounts deferred under the Plan on or after January 1, 2005. Such amounts include any amounts previously earned and deferred under the Legacy Plan but not vested as of December 31, 2004. Notwithstanding the foregoing, during the Code Section 409A transition period in effect from January 1, 2005 through December 31, 2008, the Company permitted distribution elections and changes consistent with IRS transition relief, the elections and changes of which are otherwise documented via completed election forms.

The Plan is hereby amended and restated effective as of September 8, 2009to generally require Participants to elect a percentage of various compensation items to be deferred to the Plan for each Plan Year, rather than allowing Participants to elect to defer a fixed dollar amount.

ARTICLE 1

DEFINITIONS

Whenever used herein, the following terms have the meanings set forth below, unless a different meaning is clearly required by the context:

1.1 “Account” shall mean a bookkeeping account established for the benefit of a Participant under Article 4 utilized solely to measure and determine the amounts credited under the Plan on behalf of a Participant or her Beneficiary. A Participant's Account may include one or more of the following sub-Accounts, as more fully described in Article 4.

(a) Company Contribution Account,

1

(b) Company Matching Account,

(c) Deferral Account,

(d) Dividend Deferral Account,

(e) Performance Share Account,

(f) Performance Unit Account, and

(g) Restricted Stock Account.

1.2 “Annual or Long-Term Performance Award” shall mean any compensation, in addition to Base Annual Salary relating to services performed during any Plan Year, whether or not paid in such Plan Year or included on the Form W-2 for such Plan Year, payable to a Participant under an Employer's annual performance award and cash incentive plans, including any long-term incentive plans as may be in existence from time to time, but excluding severance payments, non-qualified supplemental pension payments and any stock options or related gains, restricted stock, performance shares or units, dividends, dividend equivalents and any other equity-based award provided under a plan or arrangement of any Employer.

1.3 “Annual Company Contribution Amount” shall mean, for any one Plan Year, the amount determined in accordance with Section 3.7.

1.4 “Annual Deferral Amount” shall mean the portion of a Participant's Base Annual Salary and/or Annual or Long-Term Performance Award that a Participant elects to defer in accordance with Article 3 for any one Plan Year.

1.5 “Annual Installment Method” shall mean an annual installment payment over a specified number of years as further described in Sections 5.3 and 5.4. To determine the value of the Participant's Account balance for calculating an installment payment, the Participant's Account balance shall be valued as of the close of business on the last business day of the Plan Year preceding the Plan Year for which payment is to be made. Notwithstanding the foregoing, when determining the Account balance for calculating the first installment payment for a Participant who is a “specified employee” within the meaning of Code Section 409A subject to a payment delay pursuant to Section 5.3 or 5.4, the Participant's Account balance shall be valued as of the close of business on the last business day of the calendar quarter preceding the date the first payment is scheduled to occur. Each annual installment shall be calculated by multiplying the Account balance determined above, as the case may be, by a fraction, the numerator of which is one, and the denominator of which is the remaining number of annual payments due to the Participant. For example, if a 10-year Annual Installment Method is specified, the first payment shall be 1/10 of the Account balance, valued as described herein. The following Plan Year, the payment shall be 1/9 of the Account balance, valued as described herein.

1.6 “Base Annual Salary” shall mean the annual cash compensation relating to services performed during a Plan Year, whether or not paid in, or included on the Form W-2 for,

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such Plan Year, excluding severance payments, non-qualified supplemental pension payments, performance awards, bonuses, commissions, overtime, fringe benefits, relocation expenses, incentive payments, non-monetary awards, directors' fees and other fees, automobile and other allowances paid to an Eligible Employee for employment services rendered (whether or not such allowances are included in the Eligible Employee's gross income), stock options, restricted stock, performance shares or units, dividends, dividend equivalents and any other equity-based award provided under a plan or arrangement of an Employer. Base Annual Salary shall be calculated before it is deferred or contributed by the Eligible Employee under a qualified or non-qualified plan of an Employer and shall include amounts not otherwise included in the Eligible Employee's gross income under Code Sections 125, 132(f)(4), 402(e)(3), 402(h) or 403(b) pursuant to plans established by an Employer; provided, however, that all such amounts shall be included in Base Annual Salary only to the extent that the amount would have been payable in cash to the Eligible Employee had there been no such plan.

1.7 “Beneficiary” shall mean one or more persons, trusts, estates or other entities designated by the Participant in accordance with Article 7 that are entitled to receive benefits under this Plan upon the death of a Participant.

1.8 “Board” shall mean the board of directors of the Company.

1.9 “Change in Control” shall mean, with respect to the Company, the occurrence of any one of the following dates, interpreted consistent with Treasury Regulation Section‑1.409A‑3(i)(5).

(a) Change in Ownership. The date any one Person, or more than one Person Acting as a Group, acquires ownership of stock of the Company that, together with stock held by such Person or Group, constitutes more than 50% of the total fair market value or total voting power of the stock of the Company. Notwithstanding the foregoing, for purposes of this paragraph, if any one Person, or more than one Person Acting as a Group, is considered to own more than 50% of the total fair market value or total voting power of the stock of the Company, the acquisition of additional stock by the same Person or Persons is not considered to cause a Change in Control.

(b) Change in Effective Control.

(i) The date any one Person, or more than one Person Acting as a Group, acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person or Persons) ownership of stock of the Company possessing 30% or more of the total voting power of the stock of the Company. Notwithstanding the foregoing, for purposes of this subparagraph, if any one Person, or more than one Person Acting as a Group, is considered to effectively control the Company, the acquisition of additional control of the Company by the same Person or Persons is not considered to cause a Change in Control; or

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(ii) The date a majority of the members of the Company's Board is replaced during any 12-month period by directors whose appointment or election is not endorsed by a majority of the members of the Company's Board before the date of the appointment or election.

(c) Change in Ownership of a Substantial Portion of the Company's Assets. The date any one Person, or more than one Person Acting as a Group, acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person or Persons) assets from the Company that have a total gross fair market value equal to or more than 40% of the total gross fair market value of all of the assets of the Company immediately before such acquisition or acquisitions. For purposes of this paragraph (c), “gross fair market value” means the value of the assets of the Company, or the value of the assets being disposed of, determined without regard to any liabilities associated with such assets. Notwithstanding the foregoing, a transfer of assets is not treated as a Change in Control if the assets are transferred to:

(i) An entity that is controlled by the shareholders of the transferring corporation;

(ii) A shareholder of the Company (immediately before the asset transfer) in exchange for or with respect to its stock;

(iii) An entity, 50% or more of the total value or voting power of which is owned, directly or indirectly, by the Company;

(iv) A Person, or more than one Person Acting as a Group, that owns, directly or indirectly, 50% or more of the total value or voting power of all the outstanding stock of the Company; or

(v) An entity, at least 50% of the total value or voting power of which is owned, directly or indirectly, by a Person described in clause (iv).

(d) “Person” and “Acting as a Group.”

(i) For purposes of this Section, “Person” shall have the meaning set forth in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934, as amended.

(ii) For purposes of this Section, Persons shall be considered to be “Acting as a Group” if they are owners of a corporation that enter into a merger, consolidation, purchase or acquisition of stock, or similar business transaction with the Company. If a Person, including an entity, owns stock in both corporations that enter into a merger, consolidation, purchase or acquisition of stock, or similar transaction, such shareholder is considered to be Acting as a Group with the other shareholders only with respect to the ownership in that corporation before the transaction giving rise to the change and not with respect to the ownership interest in the

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other corporation. Notwithstanding the foregoing, Persons shall not be considered to be Acting as a Group solely because they purchase or own stock of the same corporation at the same time, or as a result of the same public offering.

1.10 “Code” shall mean the Internal Revenue Code of 1986, as amended from time to time.

1.11 “Committee” shall mean an internal administrative committee appointed by the CEO to administer the Plan in accordance with Article 9.

1.12 “Company” shall mean Wisconsin Energy Corporation, a Wisconsin corporation, and any successor to all or substantially all of the Company's assets or business.

1.13 “Company Matching Amount” shall mean, for any one Plan Year, the amount determined in accordance with Section 3.8.

1.14 “Election Form” shall mean the form or forms established from time to time by the Committee that a Participant completes, signs and returns to the Committee to make a deferral election, make or change a payment form election, and/or make or change an investment election. To the extent authorized by the Committee, such form may be electronic or set forth in some other media or format.

1.15 “Eligible Employee” shall mean an employee of an Employer who satisfies the eligibility requirements set forth in Article 2.

1.16 “Employer” shall mean the Company and/or any of its subsidiaries (now in existence or hereafter formed or acquired).

1.17 “Ending Valuation Date” shall mean the last business day of the Plan Year immediately preceding the Plan Year of distribution of a lump sum payment or final installment payment, as the case may be.

1.18 “ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended from time to time.

1.19 “401(k) Plan” shall mean all tax-qualified defined contribution retirement plans maintained by the Employer that permit employee elective deferral contributions in accordance with Code Section 401(k).

1.20 “In-Service Payout” shall mean distribution of all or a portion of an Annual Deferral Amount (including the related Company Matching Amount, if any), as of a specified date elected by a Participant.

1.21 “Measurement Funds” shall mean the hypothetical investment funds available under the Plan, as provided in Section 4.3, to determine the earnings and losses credited to a Participant's Account.

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1.22 “Participant” shall mean a current or former Eligible Employee who participates in the Plan in accordance with Article 2 and maintains an Account balance hereunder. A spouse or former spouse of a Participant shall not be treated as a Participant in the Plan or have an Account under the Plan, even if she has an interest in the Participant's Account as a result of applicable law or property settlements resulting from legal separation or divorce.

1.23 “Performance Shares” shall mean unvested shares with respect to Stock the amount of which vests based on achievement of certain performance criteria, all as determined under the applicable plan or arrangement of an Employer.

1.24 “Performance Share Amount” shall mean, for any grant of Performance Shares, the amount that would have been distributed to the Participant, but for an election to defer such amount under the Plan.

1.25 “Performance Units” shall mean unvested units representing the right to receive a cash payment whereby one unit has a value equal to one share of Stock, the amount of which vests based on achievement of certain performance criteria, all as determined and established pursuant to the applicable plan or arrangement of an Employer.

1.26 “Performance Unit Amount” shall mean, for any grant of Performance Units, the amount that would have been distributed to the Participant, but for an election to defer such amount under the Plan.

1.27 “Plan” shall mean the Wisconsin Energy Corporation Executive Deferred Compensation Plan, including any amendments adopted hereto.

1.28 “Plan Year” shall mean the calendar year.

1.29 “Restricted Stock” shall mean unvested shares of Stock which is restricted stock selected by the Compensation Committee, approved by the Board in its sole discretion, and awarded to the Participant under any Company stock incentive plan or arrangement.

1.30 “Restricted Stock Amount” shall mean, for any grant of Restricted Stock, the amount equal to the value of such Restricted Stock, calculated using the closing price for the Stock as of the day such Restricted Stock would otherwise vest (if a business day) or as of the next following business day.

1.31 “Retirement,” “Retire(s)” or “Retired” shall mean an Employee's Separation From Service on or after attaining age 55 for any reason other than a leave of absence or death.

1.32 “Separation from Service” shall mean the Participant's termination of employment with all Employers and other entities affiliated with the Company, voluntarily or involuntarily, for any reason other than on account of death, or as otherwise provided by the Department of Treasury in regulations promulgated under Code Section 409A. For purposes of the foregoing, whether an entity is affiliated with the Company shall be determined pursuant to the controlled group rules of Code Section 414, as modified by Code Section 409A. Unless the employment relationship is terminated earlier by the

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Employer or the Participant, the following shall apply for determining a Separation from Service for Code Section 409A only:

(a) Except as provided in paragraph (b), the Participant's employment relationship with the Employer shall be treated as continuing intact while the individual is on a military leave, sick leave or other bona fide leave of absence if the period of such leave does not exceed six months (or longer, if required by statute or contract). If the period of the leave exceeds six months and the Participant's right to reemployment is not provided either by statute or contract, the employment relationship is deemed to terminate on the first date immediately following such six-month period.

(b) Where a leave of absence is due to any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than six months, where such impairment causes the Participant to be unable to perform the duties of her position of employment or any substantially similar position of employment, the Participant's relationship with the Employer shall be treated as continuing intact for a period of 29 months and will be deemed to terminate on the first date immediately following such 29 month period.

1.33 “Stock” shall mean Wisconsin Energy Corporation common stock.

1.34 “Trust” shall mean the fund created by the Wisconsin Energy Corporation Rabbi Trust Agreement dated December 1, 2000 between the Company and The Northern Trust Company, and as amended from time to time.

1.35 “Unforeseeable Emergency” shall mean, as determined by the Committee in its sole discretion, a severe financial hardship to the Participant resulting from (i) an illness or accident of the Participant, the Participant's spouse, the Participant's Beneficiary, or the Participant's dependent (as defined in Code Section 152, without regard to Code Section 152(b)(1), (b)(2), and (d)(1)(B)), (ii) loss of the Participant's property due to casualty (including the need to rebuild a home following damage to a home not otherwise covered by insurance), or (iii) other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant.

ARTICLE 2

ELIGIBILITY AND PARTICIPATION

2.1 Selection by Committee. Participation in the Plan shall be limited to a select group of management and highly compensated employees of the Employer (as defined in ERISA Sections 201(2), 301(a)(3) and 401(a)(1)), as determined by the Committee in its sole discretion. From that group, the Committee shall select the Eligible Employees to participate in the Plan.The Committee may limit the types of deferrals (identified in Article 3) an Eligible Employee may make under the Plan.

2.2 Participation. To begin participation in the Plan, an Eligible Employee shall properly complete and timely submit an Election Form to the Committee in accordance with the

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Committee's rules. An Eligible Employee shall become a Participant on the first day on which a deferral of an elected amount is first credited to her Account. The Committee or its delegate may establish from time to time such other enrollment requirements as it determines in its sole discretion are necessary. Such Participant shall remain a Participant in the Plan until her Account balance is paid in full.

2.3 Enrollment Requirements. Election Forms shall be completed and filed with the Committee by the time periods set forth in Article 3 for the particular type of compensation elected for deferral or during such other enrollment period as the Committee determines in accordance with such Article. A Participant may change or revoke a deferral election any time before such election becomes irrevocable, which shall occur as of the applicable deadline specified in Article 3 unless the Committee establishes an earlier deadline. Unless the Committee determines otherwise, a new Election Form shall be required for each Plan Year in which a Participant wants to defer a type of compensation eligible for deferral. A Participant's Election Form shall specify the form of payment, which shall be paid at the times specified in Article 5. Beginning with the enrollment period held in 2008, the form of payment elected on the Participant's Election Form shall govern all amounts credited to her Account beginning in 2009 and shall apply to each subsequent Plan Year's deferrals, until changed on either a prospective or retroactive basis by the Participant pursuant to Section 5.6. Distribution elections made during the Code Section 409A transition period that relate to amounts deferred in Plan Years 2005, 2006, 2007 and 2008, as the case may be, shall be honored for such respective amounts, even if such amounts are not credited to a Participant's Account until a later Plan Year.

2.4 Cessation of Participation.

(a) The Committee shall have the sole discretionary authority to exclude a Participant from making further deferrals under the Plan with such exclusion becoming effective as of the first day of the immediately following Plan Year. Such Participant shall remain a Participant in the Plan until her Account balance is paid in full.

(b) Elective deferrals made by a Participant or Beneficiary who receives a distribution due to an Unforeseeable Emergency pursuant to Section 5.7 shall be cancelled due to such distribution if the Committee so decides in its discretion. In either event, the Participant (or Beneficiary, as applicable) shall remain a Participant in the Plan until her Account balance is paid in full.

(c) Notwithstanding anything in the Plan to the contrary, upon the earlier to occur of a Participant's Separation from Service or death, any outstanding deferral election shall be given effect to the extent any amounts covered by such election are paid after such event. Payment of deferred amounts shall be made pursuant to Article 5.

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ARTICLE 3

DEFERRALS AND CONTRIBUTIONS

3.1 Base Annual Salary.

(a) For each Plan Year, a Participant may elect to defer up to 75% (in whole percentage) of her Base Annual Salary. Notwithstanding the foregoing, the Committee, in its sole discretion, may permit a Participant to elect to defer a fixed dollar amount of her Base Annual Salary; however such amount may not exceed 75% of her Base Annual Salary payable for such Plan Year.

(b) A Participant's Election Form with respect to the deferral of Base Annual Salary shall be filed with the Committee before the beginning of each Plan Year in which the Base Annual Salary is earned.

(c) Subject to Section 2.3, such deferral elections shall be irrevocable as of the first day of the Plan Year to which the Election Form relates. Elections for Participants are separate and independent elections from an election to defer compensation under the 401(k) Plan.

3.2 Annual or Long-Term Performance Awards.

(a) For each Plan Year, a Participant may elect to defer up to 75% (in whole percentage) of her Annual or Long-Term Performance Award. Notwithstanding the foregoing, the Committee, in its sole discretion, may permit a Participant to elect to defer a fixed dollar amount of her Annual or Long-Term Performance Award; however, such amount may not exceed 75% of her Annual or Long-Term Performance Award payable for such Plan Year.

(b) A Participant's Election Form with respect to the deferral of an Annual or Long-Term Performance Award shall be filed with the Committee before the beginning of the Plan Year in which the Award is earned. Notwithstanding the foregoing, to the extent the Committee determines that an Annual or Long-Term Performance Award constitutes “performance based compensation” (within the meaning of Code Section 409A and regulations issued thereunder), the Committee may permit a Participant to file an Election Form with the Committee on or before a date that occurs no later than six months before the end of the performance period. In no event shall an Election Form for performance based compensation be filed when such compensation is readily ascertainable (within the meaning of Code Section 409A and regulations issued thereunder).

(c) Subject to Section 2.3, such deferral elections shall be irrevocable as of the first day of the Plan Year to which the Election Form relates or the deadline established by the Committee for performance-based compensation, as the case may be.

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3.3 Restricted Stock.

(a) For any grant of Restricted Stock, a Participant may elect to defer up to 100% (in whole percentage) of her Restricted Stock Amount, subject to such other terms or conditions as set forth in the plan or agreement under which such Restricted Stock was granted. Notwithstanding the foregoing, the Committee, in its sole discretion, may permit a Participant to elect to defer a fixed dollar amount of her Restricted Stock Amount.

(b) A Participant's Election Form with respect to the deferral of Restricted Stock Amounts shall be filed with the Committee before the beginning of the Plan Year in which the Restricted Stock is awarded, as determined under the terms of the plan or arrangement. Notwithstanding the foregoing, at the discretion of the Committee, an Election Form may be submitted within 30 days after the Restricted Stock is awarded, provided that the Restricted Stock's first vesting date is at least 12 months after the date the completed Election Form is delivered to and accepted by the Committee (taking into account any automatic vesting provisions upon certain terminations from employment that may occur before such 12 month period).

(c) Subject to Section 2.3, such deferral elections shall be irrevocable as of the first day of the Plan Year to which the Election Form relates, or the 30^th day after the Restricted Stock is awarded, as the case may be.

3.4 Performance Shares or Units.

(a) A Participant may elect to defer up to 100% (in whole percentage) of her Performance Share or Unit Amount, as the case may be, subject to such other terms or conditions as set forth in the plan or arrangement under which such Performance Shares were granted. Notwithstanding the foregoing, the Committee, in its sole discretion, may permit a Participant to elect to defer a fixed dollar amount of her Performance Share or Unit Amount.

(b) A Participant's Election Form with respect to the deferral of Performance Share Amounts or Performance Unit Amounts shall be filed with the Committee at the following times, determined at the Committee's discretion:

(i) Before the beginning of the Plan Year in which the Performance Shares or Performance Units are awarded, as determined under the terms of the plan or arrangement;

(ii) Within 30 days after the Performance Shares or Performance Units are awarded, provided that the Performance Shares' or Performance Units' first vesting date is at least 12 months from the date the completed Election Form is delivered to and accepted by the Committee (taking into account any automatic vesting provisions upon certain terminations from employment that may occur before such 12 month period); or

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(iii) A date that occurs no later than six months before the end of the performance period for such Award to the extent that the Committee determines that Performance Shares or Performance Units constitute “performance based compensation” (within the meaning of Code Section 409A and regulations issued thereunder). In no event shall an Election Form for performance based compensation be filed when such compensation is readily ascertainable (within the meaning of Code Section 409A and regulations issued thereunder).

(c) Subject to Section 2.3, such deferral elections shall be irrevocable as of: (i) the first day of the Plan Year to which the Election Form relates, (ii) the 30^th day after the Performance Share or Unit Award was granted, or (iii) the deadline established by the Committee for performance-based compensation, as the case may be.

3.5 Dividend Equivalents.

(a) A Participant may elect to defer up to 100% (in whole percentage) of the dividend equivalents on any unvested Performance Shares or Performance Units under a plan or arrangement of an Employer. Notwithstanding the foregoing, the Committee, in its sole discretion, may permit a Participant to elect to defer a fixed dollar amount of such dividend equivalents.

(b) If dividend equivalents on Performance Shares and Performance Units are earned and paid annually, a Participant's Election Form with respect to the deferral of such dividend equivalents shall be filed with the Committee before the beginning of the Plan Year in which the dividend equivalents to be deferred are otherwise earned and paid.

(c) Subject to Section 2.3, such deferral elections shall be irrevocable as of the first day of the Plan Year to which the Election Form relates.

3.6 Newly-Eligible Employees. Notwithstanding anything in the Plan to the contrary, a newly-Eligible Employee shall be given 30 days from the date she becomes eligible to participate in the Plan (as determined in accordance with plan aggregation rules set forth in Code Section 409A) to complete and submit an Election Form with respect to Base Annual Salary and Annual or Long-Term Performance Award, and such election shall apply only to amounts paid for services performed after the date on which the election is effective.

3.7 Annual Company Contribution Amount. For each Plan Year, an Employer, in its sole discretion, may, but is not required to, credit any amount it desires as an Annual Company Contribution Amount to the Company Contribution Account of one or more Eligible Employees. The Annual Company Contribution Amount credited to a Participant may be smaller or larger than the amount credited to any other Participant, and the amount credited to any Participant for a Plan Year may be zero, even though one or more other Participants receive an Annual Company Contribution Amount for that

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Plan Year. Crediting of an Annual Company Contribution Amount for one Plan Year does not guarantee an Annual Company Contribution Amount for subsequent Plan Years. Notwithstanding the foregoing, if any portion of the Annual Company Contribution Amounts credited to a Participant's Company Contribution Account under the Legacy Plan remains unvested as of December 31, 2004, such Amounts shall be treated as contributed under this Plan, and shall be subject to the terms and conditions set forth herein. Participants shall be permitted to make changes to payment form elections previously filed with respect to such amounts pursuant to Section 5.6(c).If a Participant Separates from Service for any reason other than Retirement or death before the last day of a Plan Year, any Annual Company Contribution Amount previously credited for that Plan Year shall be forfeited and become zero, unless the Employer in its sole discretion determines otherwise.

3.8 Company Matching Amount.A Company Matching Amount shall be made for any month in which Base Annual Salary and/or an Annual Performance Award is credited to a Participant's Account under this Plan. If no Base Annual Salary and/or Annual Performance Award is credited to a Participant's Account in a month, then no Company Matching Amount will be provided for such month.

(a) The Company Matching Amount shall be determined by using the “matching contribution formula” under the Wisconsin Energy Corporation Employee Retirement Savings Plan (the “ERSP”), regardless of the actual 401(k) Plan, if any, that applies to the Participant. Between January 1, 2005 and December 31, 2007 (inclusive), the matching contribution formula under the ERSP is 50% on 6% of eligible compensation. On and after January 1, 2008, the matching contribution formula under the ERSP is 100% on up to 1% of eligible compensation and 50% on the next 6% of eligible compensation. Such matching contribution formula is subject to change under the ERSP. In this regard, any amendment to the ERSP that makes such change shall be incorporated herein by reference effective as of the date of any such change.

(b) The formula for a Participant's Company Matching Amount is the applicable matching rate multiplied by “X.” For purposes of the formula, X is the difference between (i) and (ii):

(i) the result of the matching contribution formula calculated using the Participant's gross compensation for the month that is eligible under the relevant Employer 401(k) Plan determined before any reduction for deferrals of Base Annual Salary and Annual Performance Awards, if applicable, under this Plan and without regard to any Code limitations, and

(ii) the Participant's “Deemed Maximum Match” (“DMM”). The DMM for any Participant is equal to the result of the matching contribution formula calculated using the Participant's gross compensation for the month that is eligible for matching under the relevant Employer 401(k) Plan. For purposes of this clause (ii), such Participant's gross compensation shall first be reduced by Base Annual Salary and Annual Performance Award

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deferrals under this Plan. Further, for each month in which the DMM is calculated, it will be assumed that the Participant is contributing the necessary elective deferral amount to the relevant 401(k) Plan for such month so that the Participant would receive the maximum match under the ERSP. Notwithstanding the foregoing, when determining the DMM, the Plan will apply the relevant Code limitations, determined on an annual basis, including maximum Compensation that can be considered under Code Section 401(a)(17), and the maximum allowable elective deferral permitted under Code Section 402(g).

If the relevant 401(k) Plan does not operate on the calendar year, the Committee in its sole discretion shall determine how the Participant's Company Matching Amount shall be calculated. The Committee may modify the method of calculating the Company Matching Amount, as it determines necessary, in its sole discretion.

ARTICLE 4

ACCOUNTS

4.1 Establishment of Accounts. Bookkeeping accounts shall be established for each Participant to reflect the deferrals of amounts made for the Participant's benefit, together with adjustments for income, gains or losses attributable thereto, and any payments from the respective sub-Accounts. Accounts are established solely for the purpose of tracking deferrals made by Participants or contributions made by an Employer and any income adjustments thereto. The Accounts shall not be used to segregate assets for payment of any amounts deferred or allocated under the Plan, and shall not constitute or be treated as a trust fund of any kind. Unless the Committee determines otherwise, the Plan shall maintain and credit the following sub-Accounts:

(a) Company Contribution Account. The Annual Company Contribution Amount, if any, shall be credited to the Company Contribution Account as of the last day of the Plan Year, unless the Employer in its sole discretion determines otherwise.

(b) Company Matching Account. The Participant's Company Matching Amount shall be credited to the Company Matching Account no later than the end of the month following the month to which such amount relates.

(c) Deferral Account. The Participant's Deferral Account shall reflect a Participant's Annual Deferral Amounts credited on her behalf.

(i) Base Annual Salary deferrals shall be withheld from each regularly scheduled payroll, as adjusted from time to time for increases and decreases in Base Annual Salary, and credited to the Deferral Account as of the regularly scheduled payroll date or as soon as administratively feasible thereafter.

(ii) Annual or Long-Term Performance Award deferrals shall be withheld and credited to the Deferral Account at the time the Annual or Long-Term Performance Award would otherwise be paid to the Participant.

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(d) Dividend Deferral Account. Dividend equivalent deferrals shall be credited to the Dividend Deferral Account at the time the deferred dividend equivalents would otherwise have been paid in cash, but for the election to defer.

(e) Performance Share Account. Performance Share Amount deferrals shall be credited to the Performance Share Account as of the date the Performance Shares would otherwise be paid following vesting, as determined under the terms of the plan or arrangement pursuant to which the Performance Shares were granted, but for the election to defer.

(f) Performance Unit Account. Performance Unit Amount deferrals shall be credited to the Performance Unit Account as of the date the Performance Units would otherwise be paid following vesting, as determined under the terms of the plan or arrangement pursuant to which the Performance Units were granted, but for the election to defer.

(g) Restricted Stock Account. Restricted Stock Amount deferrals shall be credited to the Restricted Stock Account as of the date the Restricted Stock would otherwise vest under the terms of the plan or arrangement pursuant to which the Restricted Stock was granted, but for the election to defer.

4.2 Vesting. A Participant shall be vested and have a nonforfeitable right to the amounts credited to her Accounts, adjusted for deemed income, gains and losses attributable thereto, as follows:

(a) A Participant shall at all times be 100% vested and have a nonforfeitable right to amounts credited to her Company Matching Account, Deferral Account, Dividend Deferral Account, Performance Share Account, Performance Unit Account and Restricted Stock Account.

(b) A Participant shall be vested and have a nonforfeitable right to amounts credited, if any, in her Company Contribution Account in accordance with the vesting schedule, if any, set forth in her Election Form or other written agreement with such Participant. However, in the event of a Change in Control, amounts credited to a Participant's Company Contribution Account shall immediately become 100% vested.

Notwithstanding the foregoing, the vesting schedule for a Participant's Annual Company Contribution Amounts shall not be accelerated to the extent that the Committee determines that such acceleration would cause the deduction limitations of Code Section 280G to become effective. If all of a Participant's Annual Company Contribution Amounts are not vested pursuant to such a determination, the Participant may request independent verification of the Committee's calculations with respect to the application of Code Section 280G. In such case, the Committee shall provide to the Participant within 15 business days of such request an opinion (which need not be unqualified) of the Company's independent auditors, which opinion shall state that any limitation in

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the vested percentage hereunder is necessary to avoid the limits of Code Section 280G and contain supporting calculations. The cost of such opinion shall be paid by the Company.

4.3 Deemed Investments. Subject to paragraphs (b) and (h) below, and in accordance with, and subject to, the rules and procedures that are established from time to time by the Committee in its sole discretion, amounts shall be credited or debited to a Participant's Account in accordance with the following rules. The Committee's discretion includes the right to supersede the specific rights identified below, with or without retroactive effect:

(a) Measurement Funds. Amounts credited to each Participant's Account shall be deemed invested, in accordance with the Participant's directions, in one or more Measurement Funds that are available under the Plan. The hypothetical investment funds available under the Plan shall be those designated by the Committee, from time to time in its discretion, following recommendations by the WEC Investment Trust Policy Committee. Subject to paragraphs (b) and (h) below, a Participant may elect one or more of the following Measurement Funds for the purpose of crediting additional amounts to her Account: (i) any Measurement Fund selected by the Committee from time to time, (ii) the Prime Rate Fund (described as a mutual fund that is 100% invested in a hypothetical debt instrument which earns interest at an annualized interest rate equal to the “Prime Rate” as reported each business day by the Wall Street Journal, with interest deemed reinvested in additional units of such hypothetical debt instrument), or (iii) a Company Stock Measurement Fund (described as a mutual fund that is 100% invested in shares of Company Stock, with dividends deemed reinvested in additional shares of Company Stock).

Subject to paragraphs (b) and (h) below, the Committee may, in its sole discretion, discontinue, substitute or add a Measurement Fund, subject to such advance notice to Participants if the Committee determines, in its sole discretion, that such notice is necessary.

(b) Special Rule for Restricted Stock and Performance Share Amounts. Notwithstanding any provision of this Plan to the contrary, the Participant's Restricted Stock Amounts and Performance Share Amounts deferred under the Plan that would have otherwise been distributed in Stock shall be deemed invested in the Company Stock Measurement Fund at all times before distribution from this Plan. Further, the Participant's Restricted Stock and Performance Share Amounts shall be distributed from this Plan in the form of cash.

(c) Election of Measurement Funds. Subject to paragraphs (b) and (h), a Participant shall elect on her initial Election Form one or more Measurement Funds to be used to determine the additional amounts to be credited to her Account, unless changed pursuant to rules as the Committee shall determine, in its discretion, from time to time. However, subject to paragraphs (b) and (h) and any rules and procedures established from time to time by the Committee in its sole discretion, the Participant may elect, by submitting an Election Form to the Committee that is

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accepted by the Committee, to add or delete one or more Measurement Funds to be used to determine the additional amounts to be credited to her Account, or to change the portion of her Account allocated to each previously or newly elected Measurement Fund. Such rules may include, but are not limited to, rules and/or trading policies that govern the timing, frequency, and manner in which elections are made to allocate or reallocate deemed investment amounts among the Measurement Funds, and may be modified at any time and from time to time by the Committee in its sole discretion. If an election is made to change a Measurement Fund, it shall become effective and apply thereafter in accordance with the rules of the Committee for all subsequent periods in which the Participant participates in the Plan, unless changed in accordance with the previous provisions. All rights of a Participant or any other person to elect or change the Measurement Funds under this Section shall be deemed to have ceased as of the Ending Valuation Date and no adjustment in the value of an Account balance shall be considered for any purpose under the Plan after such Ending Valuation Date.

(d) Proportionate Allocation. In making any election described in paragraph (c) above, the Participant shall specify on the Election Form, in increments of 1%, the percentage of her Account balance to be allocated to a Measurement Fund (as if the Participant was making an investment in that Measurement Fund with that portion of her Account balance).

(e) Crediting or Debiting Method. The performance of each elected Measurement Fund (either positive or negative) shall be determined by the Committee, in its sole discretion, based on the performance of the Measurement Funds themselves. A Participant's Account shall be credited or debited on a periodic basis based on the performance of each Measurement Fund selected by the Participant, as determined by the Committee in its sole discretion, provided that no adjustment in the value of a Participant's Account balance shall be considered after the Ending Valuation Date.

(f) No Actual Investment. Notwithstanding any other provision of this Plan to the contrary, the Measurement Funds shall be used for measurement purposes only, and a Participant's election of any Measurement Fund, the allocation of her Account thereto, the calculation of additional amounts and the crediting or debiting of such amounts to a Participant's Account shall not be considered or construed in any manner as an actual investment of her Account balance in any such Measurement Fund. If the Employer or the trustee, in its sole discretion, decides to invest funds in any or all of the Measurement Funds, no Participant shall have any rights in or to such investments themselves. Notwithstanding the foregoing, a Participant's Account balance shall at all times be a bookkeeping entry only and shall not represent any investment made on her behalf by the Employer or the trustee; the Participant shall at all times remain an unsecured creditor of the Company.

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(g) Investment of Trust Assets. The trustee of the Trust shall be authorized, upon written instructions received from the Committee or an investment manager appointed by the Committee, to invest and reinvest the assets of the Trust in accordance with the applicable Trust Agreement, including the disposition of Stock and reinvestment of the proceeds in one or more investment vehicles designated by the Committee.

(h) Special Considerations for Participants Subject to Section 16 of the Securities Exchange Act of 1934. In order for any deferral election under this Plan by a Participant who is an officer subject to the reporting requirements and trading restrictions of Section 16 of the Securities Exchange Act of 1934 (“Section 16”) to conform to Section 16, the Participant shall consult with the Company's designated individual responsible for Section 16 reporting and compliance before making any election to move any part of her Account into or out of the Company Stock Measurement Fund. Any change of election to an alternative payout form made under Section 5.6 by such Participant may only be given effect if it is approved by the Compensation Committee or the Board. The Company reserves the right to impose such restrictions as it determines necessary, in its sole discretion, on any elections, transactions or other matters under this Plan relating to the Company Stock Measurement Fund to comply with or qualify for exemption under Section 16.

4.4 Taxes. A Participant's Employer shall withhold from a Participant's non-deferred compensation any employment taxes the Employer is required to withhold with respect to amounts deferred under the Plan at the times required under applicable regulations promulgated by the Department of the Treasury. To the extent not previously withheld, the Employer, or the trustee of the Trust, shall withhold from any payments made to a Participant under this Plan all federal, state and local income, employment and other taxes required to be withheld by the Employer, or the trustee of the Trust, in connection with such payments, in amounts and in a manner to be determined in the sole discretion of the Employer or the trustee of the Trust, as the case may be.

ARTICLE 5

DISTRIBUTION OF ACCOUNT

5.1 Time for Distribution. Except as otherwise provided in Section 5.7, distribution of a Participant's Account shall be made on the earliest to occur of:

(a) The date elected by a Participant under Section 5.2 with respect to an In-Service Payout;

(b) The date set forth in Section 5.3 with respect to the Participant's Retirement;

(c) The date set forth in Section 5.4 with respect to the Participant's Separation from Service;

(d) The date set forth in Section 5.5 with respect to the Participant's death; or

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(e) The date set forth in Section 5.8 with respect to a Separation from Service after a Change in Control.

Notwithstanding any other provision of the Plan to the contrary, in no event shall the distribution of any Account be accelerated to a time earlier than which it would otherwise have been paid, whether by amendment of the Plan, exercise of the Committee's discretion or otherwise, except as permitted by Section 5.9 or Treasury Regulations issued pursuant to Code Section 409A.

5.2 In-Service Payout. A Participant may irrevocably select, on her Election Form, a Plan Year to receive a lump sum In‑Service Payout of all or part of an Annual Deferral Amount (including Company Matching Amounts thereto). The earliest Plan Year in which a Participant can elect an In-Service Payout is the third Plan Year after the Plan Year in which the deferral actually occurs. For example, an election to defer Base Annual Salary in December 2004 that is actually deferred in 2005 may be distributed no earlier than in 2008. Payment shall be made during the first 90 days of the Plan Year elected for distribution.

5.3 Benefits Upon Retirement. Upon a Participant's Retirement, the Participant's Account shall be paid or begin to be paid during the first 90 days of the Plan Year following the Plan Year of the Participant's Retirement. Notwithstanding the foregoing, distributions made to “specified employees” (determined pursuant to Treasury Regulation Section 1.409A-1(i)) upon Retirement shall be paid or begin to be paid no earlier than the first day of the seventh month following the Participant's Retirement, unless the Participant dies during such six-month period in which case Section 5.5 shall apply. Subsequent installment payments shall be made thereafter during the first 90 days of the Plan Year in which the installment is due.

Payment shall be made in such form as determined below, taking into account any changes to an elected form of payment pursuant to Section 5.6.

(a) A Participant's Account balance shall be paid in a lump sum if:

(i) timely elected by the Participant pursuant to the Plan,

(ii) the Participant's Account balance at the time of Retirement is $10,000 or less even if the Participant elected an installment payment form, or

(iii) no valid payment election is in effect when distribution is to be made.

(b) Subject to paragraph (a)(ii) and Section 5.8, a Participant may elect to receive payment of her Account balance in any number of installments up to ten. The amount of each installment shall be determined using the Annual Installment Method.

5.4 Benefits Upon Separation from Service. Upon a Participant's Separation from Service for any reason other than Retirement or death, the Participant's Account shall be paid or begin to be paid during the first 90 days of the Plan Year following the Plan Year of the

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Participant's Separation from Service. Notwithstanding the foregoing, distributions made to “specified employees” (determined pursuant to Treasury Regulation Section 1.409A‑1(i)) upon such separation shall be paid or begin to be paid no earlier than the first day of the seventh month following the Participant's Separation from Service unless the Participant dies during such six-month period in which case Section 5.5 shall apply. If an Annual Installment Method is in effect, subsequent installment payments shall be made thereafter during the first 90 days of the Plan Year in which the installment is due.

Payment shall be made in such form as determined below, taking into account any changes to an elected form of payment pursuant to Section 5.6.

(a) A Participant's Account balance shall be paid in a lump sum if:

(i) timely elected by the Participant pursuant to the Plan,

(ii) the Participant's Account balance at the time of Separation from Service is $25,000 or less even if the Participant elected an installment payment form, or

(iii) no valid payment election is in effect when distribution is to be made.

(b) Subject to paragraph (a)(ii) and Section 5.8, a Participant may elect to receive payment of her Account balance in five installments. The amount of each installment shall be determined using the Annual Installment Method.

5.5 Benefits Upon Death. Upon the Participant's death, the Plan Administrator shall pay to the Participant's Beneficiary a benefit equal to the remaining balance in the Participant's Account. Payment shall be made in accordance with the provisions below.

(a) Death While In Pay Status. If the Participant dies after commencing an installment form of payment, but before the entire benefit is paid in full, the Participant's unpaid installment payments shall continue to be paid to the Participant's Beneficiary over the remaining number of years as that benefit would have been paid to the Participant had the Participant survived. In the event a Participant dies after a Separation from Service, but before actual payment is made or begins, this paragraph shall apply and payment to the Participant's Beneficiary shall be paid or begin to be paid at the same time as if the Participant had survived.

(b) Death While Actively Employed. If a Participant dies while actively employed, the Participant's Account shall be paid or begin to be paid to the Participant's Beneficiary during the first 90 days of the Plan Year following the Plan Year of the Participant's death, regardless of whether the Participant is a specified employee. Payment shall be made in such form as determined below, taking into account any changes to an elected form of payment pursuant to Section 5.6.

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(i) A Participant's Account balance shall be paid to her Beneficiary in a lump sum if:

(A) timely elected by the Participant pursuant to the Plan,

(B) the Participant's Account balance at the time of death $25,000 or less even if the Participant elected an installment payment form, or

(C) no valid payment election is in effect when distribution is to be made.

(ii) Subject to clause (i)(B), a Participant may elect payment of her Account balance upon death in any number of installments up to ten. The amount of each installment shall be determined using the Annual Installment Method.

5.6 Changes to Form of Payment.

(a) Prospective Changes.A Participant may select an alternate form of payment for amounts not yet subject to an irrevocable election in accordance with the rules for filing elections in Section 2.3 and Article 3.

(b) Retroactive Changes. A Participant may elect to change the form of payment for amounts that are subject to a deferral election that is irrevocable:

(i) A Participant who has elected a lump sum distribution may later change such election to an installment payment, provided the first installment payment shall be deferred to a date that is at least five years after the date the lump sum distribution would otherwise have been made.

(ii) A Participant who has an installment election in effect may change such election to a lump sum payment, provided the lump sum payment shall be deferred to a date that is at least five years after the date the initial installment payment would otherwise have commenced.

(iii) A Participant who has an installment election for payment upon Retirement, may change the number of installments, provided that the first installment payment shall be deferred to a date that is at least five years after the date the initial installment payment would otherwise have commenced.

Any such election changes pursuant to this paragraph shall be completed in accordance with Committee rules and must be made at least 12 months before the event triggering distribution occurs. Therefore, if the event triggering distribution occurs before such 12 month period has elapsed, then the election to change the payment form shall not take effect. Notwithstanding anything in this paragraph (b) to the contrary, the five-year delay described above shall not apply to changes in the form of payment upon death.

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(c) Changes Pursuant to §409A Transition Relief.Notwithstanding the foregoing provisions of this Section, on or before December 31, 2008, Participants may make changes to payment form elections previously filed with respect to amounts deferred under the Plan that relate to Plan Years 2005, 2006, 2007 and 2008 consistent with transition relief provided by the Department of the Treasury in Notice 2006-79, Notice 2007-86 and proposed regulations promulgated under Code Section 409A. If a Participant makes such a change, then the last election validly in effect as of December 31, 2008 shall be treated as the “initial” election for purposes of applying the rules set forth in paragraph (b).

5.7 Unforeseeable Emergency. A Participant may request that all or a portion of her Account be distributed in a lump sum at any time by submitting a written request to the Committee demonstrating that she has suffered an Unforeseeable Emergency, and that the distribution is necessary to alleviate the financial hardship created by the Unforeseeable Emergency.

(a) The Committee shall have the sole discretionary authority to determine whether a Participant has suffered an Unforeseeable Emergency, which shall be determined based on the relevant facts and circumstances of each case. In making such a determination, no distribution pursuant to this Section shall be made to the extent that such Unforeseeable Emergency is or may be relieved through reimbursement or compensation by insurance or otherwise, or by liquidation of the Participant's assets (unless such liquidation itself would cause a severe financial hardship), or by the cessation of deferrals under the Plan. In this regard, all deferral elections scheduled for the remainder of the Plan Year in which such distribution is made shall be cancelled. If a Participant's outstanding deferral election is cancelled, a Participant shall be required to make a new election pursuant to Articles 2 and 3 to resume active participation in the Plan.

(b) Upon a finding that the Participant has suffered an Unforeseeable Emergency, the Committee shall distribute to the Participant the lesser of (i) the portion of her Account that is necessary to satisfy the Unforeseeable Emergency, plus taxes attributable thereto or (ii) the Account balance. Distributions made pursuant to this Section shall be made within 90 days after the Committee has reviewed and approved the request.

5.8 Change in Control. Notwithstanding any other provision of the Plan to the contrary, in the event a Participant incurs a Separation from Service within 18 months after a Change in Control, the Employer shall distribute the Participant's entire Account in a lump sum payment within 90 days after such Separation, except in the case of any individual who has previously filed a special written irrevocable deferral election form under a special written contract with an Employer (including, without limitation, the senior officer change in control, severance and non-compete agreements currently in effect) electing not to receive such an immediate lump sum but instead to be paid on another basis.Notwithstanding the foregoing, distributions made to “specified employees” (determined pursuant to Treasury Regulation Section 1.409A-1(i)) upon Separation from Service shall be paid or begin to be paid no earlier than the first day of the seventh month following the

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Participant's Separation from Service, unless the Participant dies during such six-month period in which case Section 5.5 shall apply.

5.9 Discretion to Accelerate Distribution.

(a) The Committee shall have the discretion to make a distribution, or accelerate the time or schedule of payment, from a Participant's Account if payment is required for:

(i) FICA, FUTA and/or the corresponding withholding provisions of applicable state and local taxes with respect to compensation deferred under the Plan. Any such distribution shall not exceed the aggregate of such tax withholding and shall reduce the Participant's Account balance to the extent of such distributions; or

(ii) payment of state, local or foreign tax obligations arising from participation in the Plan that apply to an amount deferred under the Plan and FUTA resulting from such payment. Any such payment shall not exceed the amount of such taxes due as a result of Plan participation.

(b) The Committee or a Plan representative is authorized to accelerate the time or schedule of a payment under the Plan to an individual other than the Participant, or to make a payment under the Plan to an individual other than the Participant, to the extent necessary to fulfill a domestic relations order (as defined in Code Section 414(p)(1)(B)). Payment to an alternate payee under a domestic relations order shall be made in a lump sum within 90 days after the Committee or Plan representative approves such order.

(c) The Committee shall have the discretion to accelerate the time or schedule of a payment under the Plan if the Plan fails to meet the requirements of Code Section 409A and regulations promulgated thereunder, provided that any such payment does not exceed the amount required to be included in income as a result of such failure.

ARTICLE 6

LEAVE OF ABSENCE

If a Participant is authorized by an Employer to take a paid or unpaid bona fide leave of absence for any reason, the employment relationship is treated as continuing intact and deferral elections shall remain in force if the period of such leave does not exceed six months, or longer, so long as the Participant retains a right to reemployment under an applicable statute or by contract. If the Participant is on a leave of absence during the time for filing Election Forms, the Participant shall be permitted to complete an Election Form for the upcoming Plan Year. Upon return from leave, deferrals shall occur pursuant to the Election Form in effect for that Plan Year. If no election was made for the Plan Year in which the Participant returns from leave, no deferral shall be withheld.

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If the leave of absence exceeds six months and the Participant does not retain a right to reemployment under an applicable statute or by contract, the Participant shall be deemed to have incurred a Separation from Service as of the first date immediately following such six-month period. Notwithstanding the foregoing, where a leave of absence is due to any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than six months, where such impairment causes the Participant to be unable to perform the duties of her position of employment or any substantially similar position of employment, the Participant's relationship with the Employer shall be treated as continuing intact for a period of up to 29 months, unless earlier terminated by the Employer or Participant. In this event, the Participant's Account shall be distributed pursuant to Section 5.3 or 5.4, as applicable.

ARTICLE 7

BENEFICIARY DESIGNATION

7.1 Beneficiary. Each Participant may, at any time, designate one or more Beneficiaries (both primary as well as contingent) to receive any benefits payable under the Plan upon her death. The Beneficiary designated under this Plan may be the same as or different from the Beneficiary designation under any other plan of an Employer in which the Participant participates.

7.2 Beneficiary Designation; Change. A Participant shall designate her Beneficiary by completing and signing a beneficiary designation form established by the Committee or its delegate, and returning it to the Committee or its designated agent. A Participant may change her Beneficiary designation by completing, signing and otherwise complying with the terms of the beneficiary designation form and the Committee's rules and procedures, as in effect from time to time. Upon the acceptance by the Committee of a new beneficiary designation form, all Beneficiary designations previously filed shall be canceled. The Committee shall rely on the last completed beneficiary designation form filed by the Participant and accepted by the Committee before her death.

7.3 Acknowledgment. No Beneficiary designation or change in Beneficiary designation shall be effective until accepted by the Committee or a Plan representative.

7.4 No Beneficiary Designation. If a Participant fails to designate a Beneficiary as provided in this Article 7 or, if all designated Beneficiaries predecease the Participant or die before complete distribution of the Participant's Account, then the Participant's designated Beneficiary shall be deemed to be her surviving spouse. If the Participant has no surviving spouse, but was survived by a designated Beneficiary who was receiving benefits or was entitled to receive distribution under this Plan but died before a complete distribution of the Participant's Account, the remaining benefits shall be paid to such designated Beneficiary's estate. If the Participant leaves no surviving spouse and was not survived by a designated Beneficiary as provided in the foregoing sentence, the Participant's Account shall be paid to the Participant's estate.

7.5 Doubt as to Beneficiary. If the Committee has any doubt as to the proper Beneficiary to receive payments under this Plan, the Committee may, in its sole discretion, require the

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Participant's Employer to withhold such payments until the matter is resolved to the Committee's satisfaction.

7.6 Discharge of Obligations. The complete payment of benefits under the Plan to a Beneficiary shall fully and completely discharge all Employers and the Committee from all further obligations under this Plan with respect to the Participant, and the Participant's Election Form shall terminate upon such full payment of benefits.

ARTICLE 8

TERMINATION, AMENDMENT OR MODIFICATION

8.1 Termination.

(a) Although each Employer anticipates that it will continue the Plan for an indefinite period of time, there is no guarantee that an Employer will continue the Plan or will not terminate the Plan at any time in the future. Accordingly, each Employer reserves the right to discontinue its participation in the Plan and/or to terminate the Plan at any time with respect to all of its participating Eligible Employees, by action of its Board of Directors or Compensation Committee. Upon the termination of the Plan with respect to any Employer, any elections to defer compensation under the Plan of Participants who are employed by that Employer shall terminate as of the last day of the Plan Year containing the termination date. The termination of the Plan shall not reduce the amount of any benefit to which the Participant or Beneficiary is entitled to receive under the Plan as of the termination date. Except as provided in paragraph (b) below, Account balances shall be maintained under the Plan until such amounts would otherwise have been distributed in accordance with the terms of the Plan and Participants' validly filed payment elections.

(b) Notwithstanding any provision in the Plan to the contrary, upon termination of the Plan, the Board of Directors or Compensation Committee reserves the discretion to accelerate distribution of Participants' Account (including those Participants in pay status pursuant to an installment election) in accordance with regulations promulgated by the Department of the Treasury under Code Section 409A.

8.2 Amendment. The Company may, in its sole discretion, amend or modify the Plan at any time, in whole or in part, by action of its Board, Compensation Committee or the Committee; provided, however, that no amendment shall decrease the amount of any Participant's Account as of the date of the amendment. Further, during the pendency of a Potential Change in Control (as defined below) and at all times following a Change in Control, no amendment or modification may be made which in any way adversely affects the interests of any Participant with respect to amounts credited to such Participant's Account as of the date of the amendment. A “Potential Change in Control” shall be deemed to have occurred if one of the following events occurs:

(a) The Company enters into an agreement, the consummation of which would result in the occurrence of a Change in Control;

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(b) The Company or any Person publicly announces an intention to take or to consider taking actions which, if consummated, would constitute a Change in Control;

(c) Any Person becomes the Beneficial Owner (within the meaning of Rule 13d-3 under the Securities Exchange Act of 1934, as amended), directly or indirectly, of Stock representing 15% or more of either the then outstanding shares of stock of the Company or the combined voting power of the Company's then outstanding Stock (not including the Stock beneficially owned by such Person or any Stock acquired directly from the Company or its affiliates); or

(d) The Board adopts a resolution to the effect that, for purposes of this Plan, a Potential Change in Control has occurred.

Except as otherwise noted, the capitalized terms in the above definition have the same meaning as set forth in Section 1.9. The Company's power to amend or modify the Plan includes the power to suspend or freeze participation in the Plan, provided such suspension or freeze does not cause a prohibited acceleration of compensation under Code Section 409A. In such circumstance, the Company may, in its sole discretion, re-institute the ability of any Participant or group of Participants to make deferrals under Article 3 at any time, provided such action is taken consistent with Code Section 409A. Such action may be taken by the Company's Board of Directors, the Compensation Committee or the Committee referred to in Article 9 below.

8.3 Effect of Payment. The full payment of the Participant's Account under any provision of the Plan shall completely discharge the Plan's and Employer's obligations to the Participant and her Beneficiaries under this Plan and the Participant's Election Forms shall terminate.

ARTICLE 9

ADMINISTRATION

9.1 Plan Administration. Except as otherwise provided in this Article 9, the Plan shall be administered by the Committee. Members of the Committee may be Participants under this Plan. Any individual serving on the Committee who is a Participant shall not vote or act on any matter relating solely to himself or herself. The Chief Executive Officer may not act on any matter involving such officer's own participation in the Plan. All references to the Committee shall be deemed to include reference to the Chief Executive Officer.

9.2 Powers, Duties and Procedures. The Committee (or the Chief Executive Officer if such individual chooses to so act) shall have full and complete discretionary authority to (i) make, amend, interpret and enforce all appropriate rules and regulations for the administration of the Plan, and (ii) decide or resolve any and all questions including interpretations of the Plan, as may arise in connection with the claims procedures set forth in Article 10 or otherwise with regard to the Plan. The Committee shall have complete control and authority to determine the rights and benefits of all claims, demands

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and actions arising out of the provisions of the Plan of any Participant or Beneficiary or other person having or claiming to have any interest under the Plan. When making a determination or calculation, the Committee may rely on information furnished by a Participant or the Employer. Benefits under the Plan shall be paid only if the Committee decides in its sole discretion that the Participant or Beneficiary is entitled to them. The Committee or the Chief Executive Officer may delegate such powers and duties as it determines for the efficient administration of the Plan.

9.3 Administration Upon Change In Control. For purposes of this Plan, the Company shall be the “Administrator” at all times before a Change in Control. Upon and after a Change in Control, the Administrator shall be an independent third party selected by the individual who, at any time before such event, was the Company's Chief Executive Officer or, if there is no such officer or such officer does not act, by the Company's then highest ranking officer (the “Appointing Officer”). Upon a Change in Control, the Administrator shall have full and complete discretionary power to determine all questions arising in connection with the administration of the Plan and the interpretation of the Plan and Trust including, but not limited to, benefit entitlement determinations. Upon and after a Change in Control, the Company shall (i) pay all reasonable administrative expenses and fees of the Administrator, (ii) indemnify the Administrator against any costs, expenses and liabilities (including, without limitation, attorney's fees) of whatever kind and nature which may be imposed on, asserted against or incurred by the Administrator in connection with the performance of the duties hereunder, except with respect to matters resulting from the gross negligence or willful misconduct of the Administrator or its employees or agents, and (iii) supply full and timely information to the Administrator on all matters relating to the Plan, the Trust, the Participants and their Beneficiaries, the Account balances of the Participants, including the dates of Retirement, Disability, death or Separation from Service and such other pertinent information as the Administrator may reasonably require. Upon and after a Change in Control, the Administrator may be terminated (and a replacement appointed) only by an Appointing Officer. Upon and after a Change in Control, the Administrator may not be terminated by the Company.

9.4 Agents. In the administration of this Plan, the Committee may, from time to time, employ agents and delegate to them such administrative duties as it sees fit (including acting through a duly appointed representative) and may from time to time consult with counsel who may be counsel to an Employer.

9.5 Binding Effect of Decisions. Notwithstanding any other provision of the Plan to the contrary, the Committee or its delegate shall have complete discretion to interpret the Plan and to decide all matters under the Plan. Any such interpretation shall be final, conclusive and binding on all Participants, Beneficiaries and any person claiming under or through any Participant, in the absence of clear and convincing evidence that the Committee acted arbitrarily and capriciously.

9.6 Indemnity of Committee. All Employers shall indemnify and hold harmless the members of the Committee, and any other employee to whom the duties of the Committee may be delegated, and the Administrator, as defined in Section 9.2, against

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any and all claims, losses, damages, expenses or liabilities arising from any action or failure to act with respect to this Plan, except in the case of willful misconduct by the Committee, any of its members or any such employee or the Administrator.

9.7 Employer Information. To enable the Committee and/or Administrator to perform its functions, each Employer shall supply full and timely information to the Committee on all matters relating to the compensation of its Participants, the dates of the Retirement, disability, death or Separation from Service and such other pertinent information as the Committee may reasonably require.

9.8 Coordination with Other Benefits. The benefits provided to a Participant and the Beneficiary under the Plan are in addition to any other benefits available to such Participant under any other plan or program for employees of an Employer. The Plan shall supplement and shall not supersede, modify or amend any other such plan or program except as may otherwise be expressly provided.

ARTICLE 10

CLAIMS PROCEDURES

10.1 Presentation of Claim. Any Participant or Beneficiary (such Participant or Beneficiary being referred to below as a “Claimant”) may deliver to the Committee a written claim for benefits. If such a claim relates to the contents of a notice received by the Claimant, the claim must be made within 90 days after such notice was received by the Claimant. All other claims shall be made within 180 days of the date on which the event that caused the claim to arise occurred. The claim shall state with particularity the determination desired by the Claimant. A claim shall be considered to have been made when a written communication made by the Claimant or the Claimant's representative is received by the Committee.

10.2 Decision on Initial Claim. The Committee shall consider a Claimant's claim and provide written notice to the Claimant of any denial within a reasonable time, but no later than 90 days after receipt of the claim. If an extension of time beyond the initial 90-day period for processing is required, written notice of the extension shall be provided to the Claimant before the initial 90-day period expires indicating the special circumstances requiring an extension of time and the date by which the Committee expects to render a final decision. In no event shall the period, as extended, exceed 180 days. If the Committee denies, in whole or in part, the claim, the notice shall set forth in a manner calculated to be understood by the Claimant:

(i) The specific reasons for the denial of the claim, or any part thereof;

(ii) Specific references to pertinent Plan provisions upon which such denial was based;

(iii) A description of any additional material or information necessary for the Claimant to perfect the claim, and an explanation of why such material or information is necessary; and

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(iv) An explanation of the claim review procedure set forth in Section 10.3 below, which explanation shall also include a statement of the Claimant's right to bring a civil action under ERISA Section 502(a) following a denial of the claim upon review.

10.3 Right to Review. A Claimant is entitled to appeal any claim that has been denied in whole or in part. To do so, the Claimant must submit a written request for review with the Committee within 60 days after receiving a notice from the Committee that a claim has been denied, in whole or in part. Absent receipt by the Committee of a written request for review within such 60-day period, the claim shall be deemed to be conclusively denied. The Claimant (or the Claimant's duly authorized representative) may:

(a) Review and/or receive copies of, upon request and free of charge, all documents, records, and other information relevant to the Claimant's claim;

(b) Submit written comments, documents, records or other information relating to her claim, which the Committee shall take into account in considering the claim on review, without regard to whether such information was submitted or considered in the initial review of the claim; and/or

(c) Request a hearing, which the Committee, in its sole discretion, may grant.

If a Claimant requests to review and/or receive copies of relevant information pursuant to paragraph (a) above before filing a written request for review, the 60-day period for submitting the written request for review will be tolled during the period beginning on the date the Claimant makes such request and ending on the date the Claimant reviews or receives such relevant information.

10.4 Decision on Review. The Committee shall render its decision on review promptly, and not later than 60 days after it receives a written request for review of the denial, unless a hearing is held or other special circumstances require additional time. In such case, the Committee will notify the Claimant, before the expiration of the initial 60-day period and in writing, of the need for additional time, the reason the additional time is necessary, and the date (no later than 60 days after expiration of the initial 60-day period) by which the Committee expects to render its decision on review. Notwithstanding the foregoing, if the Committee determines that an extension of the initial 60-day period is required due to the Claimant's failure to submit information necessary for the Committee to decide the claim, the time period by which the Committee must make its determination on review shall be tolled from the date on which the notification of the extension is sent to the Claimant until the date on which the Claimant responds to the request for additional information. The decision on review shall be written in a manner calculated to be understood by the Claimant, and shall contain:

(a) Specific reasons for the decision;

(b) Specific references to the pertinent Plan provisions upon which the decision was based;

28

(c) A statement that the Claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records or other information relevant (within the meaning of Department of Labor Regulation Section 2560.503-1(m)(8)) to the Claimant's claim;

(d) A statement of the Claimant's right to bring a civil action under ERISA Section 502(a) following a wholly or partially denied claim for benefits; and

(e) Such other matters as the Committee deems relevant.

10.5 Form of Notice and Decision. Any notice or decision by the Committee under this Article 10 may be furnished electronically in accordance with Department of Labor Regulation Section 2520.104b-(1)(c)(i), (iii) and (iv).

10.6 Legal Action. Any final decision by the Committee shall be binding on all parties. A Claimant's compliance with the foregoing provisions of this Article 10 is a mandatory prerequisite to a Claimant's right to commence any legal action with respect to any claim for benefits under this Plan. Any such legal action must be initiated no later than 180 days after the Committee renders its final decision. If a final determination of the Committee is challenged in court, such determination shall not be subject to de novo review and shall not be overturned unless proven to be arbitrary and capricious based on the evidence considered by the Committee at the time of such determination.

ARTICLE 11

TRUST

11.1 Establishment of the Trust. The Company shall establish the Trust and each Employer shall contribute such amounts to the Trust from time to time as it deems desirable.

11.2 Interrelationship of the Plan and the Trust. The provisions of the Plan shall govern the rights of a Participant to receive distributions pursuant to the Plan. The provisions of the Trust shall govern the rights of the Employers, Participants and the creditors of the Employers to the assets transferred to the Trust. Each Employer shall at all times remain liable to carry out its obligations under the Plan.

11.3 Distributions From the Trust. Each Employer's obligations under the Plan may be satisfied with Trust assets distributed pursuant to the terms of the Trust, and any such distribution shall reduce the Employer's obligations under this Plan.

ARTICLE 12

MISCELLANEOUS

12.1 Status of Plan. The Plan is intended to be a plan that is not qualified within the meaning of Code Section 401(a) and that is unfunded for tax purposes and “is maintained by an employer primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees” (within the meaning of ERISA). The Plan shall be administered and interpreted in a manner consistent with that intent.

29

12.2 Unsecured General Creditor. Participants and their Beneficiaries, heirs, successors and assigns shall have no legal or equitable rights, interests or claims in any property or assets of an Employer, Company or of any other person and nothing in the Plan shall be construed to give any employee or any other person such rights. The Plan constitutes a mere promise by the Company or Employer to make payments in accordance with the terms of the Plan and Participants and Beneficiaries shall have the status of general unsecured creditors solely of the Employer employing the Participant.

12.3 Employer's Liability. The liability of an Employer for the payment of benefits shall be defined only by the Plan and any Election Forms, as entered into between the Employer and a Participant. An Employer shall have no obligation to a Participant under the Plan except as expressly provided in the Plan.

12.4 Nonassignability. Neither a Participant nor any other person shall have any right to commute, sell, assign, transfer, pledge, anticipate, mortgage or otherwise encumber, transfer, hypothecate, alienate or convey in advance of actual receipt, the amounts, if any, payable hereunder, or any part thereof, which are, and all rights to which are expressly declared to be, unassignable and non-transferable to the maximum extent allowed by law. No part of the amounts payable shall, before actual payment, be subject to seizure, attachment, garnishment or sequestration for the payment of any debts, judgments, alimony or separate maintenance owed by a Participant or any other person, nor shall any part of the same, to the maximum extent allowed by law, be transferable by operation of law in the event of a Participant's or any other person's bankruptcy or insolvency or, except as provided in Section 5.9(b), be transferable to a spouse as a result of a property settlement or otherwise.

12.5 Not a Contract of Employment. The terms and conditions of this Plan shall not be deemed to constitute a contract of employment between any Employer and the Participant. Such employment is hereby acknowledged to be an “at will” employment relationship that can be terminated at any time for any reason, or no reason, with or without cause, and with or without notice, unless expressly provided in a written employment agreement between an Employer and a Participant. Nothing in this Plan shall be deemed to give a Participant the right to be retained in the service of any Employer as an employee, or to interfere with the right of any Employer to discipline or discharge the Participant at any time, with or without cause, or to modify the Base Salary or Annual or Long-Term Performance Award at any time.

12.6 Furnishing Information. A Participant or Beneficiary shall cooperate with the Committee by furnishing any and all information requested by the Committee and take such other actions as may be requested in order to facilitate the administration of the Plan and the payments of benefits hereunder.

12.7 Receipt and Release. Any payment to any Participant or Beneficiary in accordance with the provisions of the Plan shall, to the extent thereof, be in full satisfaction of all claims against the Employer, the Committee and a trustee (if any) under the Plan, and the Committee may require such Participant or Beneficiary, as a condition precedent to such payment, to execute a receipt and release to such effect.

30

12.8 Incompetent. If any Participant or Beneficiary is determined by the Committee, in its sole discretion, to be incompetent by reason of physical or mental disability (including minority) or is determined to be incapable of handling disposition of that person's property, the Committee may direct payment of such benefit to the guardian, legal representative or person having the care and custody of such minor, incompetent or incapable person. In such circumstance, the Committee, the Employer or a trustee (if any) shall have no responsibility to follow the application of such funds. The Committee may require proof of minority, incompetence, incapacity or guardianship, as it may deem appropriate prior to distribution of the benefit. Any payment of a benefit shall be a payment for the Account of the Participant and the Participant's Beneficiary, as the case may be, and shall be a complete discharge of any liability under the Plan for such payment amount.

12.9 Governing Law and Severability. To the extent not preempted by ERISA, the provisions of this Plan shall be construed, administered and interpreted according to the internal laws of the State of Wisconsin without regard to its conflicts of laws principles. If any provisions is held by a court of competent jurisdiction to be invalid or unenforceable, the remaining provisions hereof shall continue to be fully effective.

12.10 Notices and Communications. All notices, statements, reports and other communications from the Committee to any employee, Participant, Beneficiary or other person required or permitted under the Plan shall be deemed to have been duly given when personally delivered to, when transmitted via facsimile or other electronic media or when mailed overnight or by first-class mail, postage prepaid and addressed to, such employee, Participant, Beneficiary or other person at his or her last known address on the Employer's or Company's records. All elections, designations, requests, notices, instructions and other communications from a Participant, Beneficiary or other person to the Committee required or permitted under the Plan shall be in such form as is prescribed from time to time by the Committee, and shall be mailed by first-class mail, transmitted via facsimile or other electronic media or delivered to such location as shall be specified by the Committee. Such communication shall be deemed to have been given and delivered only upon actual receipt by the Committee at such location.

12.11 Successors. The provisions of this Plan shall bind and inure to the benefit of the Participant's Employer and its successors and assigns and the Participant and the Participant's designated Beneficiaries.

12.12 Insurance. An Employer, on its own behalf or on behalf of the trustee of the Trust, and, in its sole discretion, may apply for and procure insurance on the life of the Participant, in such amounts and in such forms as the Employer may choose. The Employer or the trustee of the Trust, as the case may be, shall be the sole owner and beneficiary of any such insurance. The Participant shall have no interest whatsoever in any such policy or policies, and at the request of the Employer shall submit to medical examinations and supply such information and execute such documents as may be required by the insurance company or companies to whom the Employer has applied for insurance. The Participant may elect not to be insured.

31

12.13 Legal Fees To Enforce Rights After Change in Control. The Employer is aware that upon the occurrence of a Change in Control, the Board (which might then be composed of new members) or a shareholder of the Employer, or of any successor corporation, might then cause or attempt to cause the Employer or such successor to refuse to comply with its obligations under the Plan and might cause or attempt to cause the Employer to institute, or may institute, litigation seeking to deny Participants the benefits intended under the Plan. In these circumstances, the purpose of the Plan could be frustrated. Accordingly, if, following a Change in Control, it should appear to any Participant that the Employer or any successor corporation has failed to comply with any of its obligations under the Plan or any agreement thereunder or, if the Employer or any other person takes any action to declare the Plan void or unenforceable or institutes any litigation or other legal action designed to deny, diminish or to recover from any Participant the benefits intended to be provided, then the Employer irrevocably authorizes such Participant to retain counsel of her choice at the expense of the Employer (who shall be jointly and severally liable for all reasonable fees of such counsel) to represent such Participant in connection with the initiation or defense of any litigation or other legal action, whether by or against the Employer or any director, officer, shareholder or other person affiliated with the Employer or any successor thereto in any jurisdiction. If paid by the Participant, the Employer shall reimburse such legal fees no later than December 31^st of the year following the year in which the expense was incurred.

12.14 Terms. Whenever any words are used herein in the feminine, they shall be construed as though they were in the masculine in all cases where they would so apply; and whenever any words are used herein in the singular or in the plural, they shall be construed as though they were used in the plural or the singular, as the case may be, in all cases where they would so apply.

12.15 Headings. Headings and subheadings in the Plan are inserted for convenience only and shall not control or affect the meaning or construction of any of its provisions.

* * *

IN WITNESS WHEREOF, a duly authorized Committee member has executed the Plan, as amended and restated, effective as of September 8, 2009.

WISCONSIN ENERGY CORPORATION
By:	/s/ Lisa R. George
Date:	September 8, 2009

32

EX-21.1

Exhibit 21.1

WISCONSIN ENERGY CORPORATION

SUBSIDIARIES AS OF DECEMBER 31, 2011

The following table includes the subsidiaries of Wisconsin Energy Corporation, a diversified holding company incorporated in the state of Wisconsin, as well as the percent of ownership, as of December 31, 2011:

	State of
	Incorporation	Percent
Subsidiary (a)	or Organization	Ownership
Wisconsin Electric Power Company	Wisconsin	100%
ATC Management Inc.	Wisconsin	26.24%
American Transmission Company LLC	Wisconsin	23.04%
Bostco LLC	Wisconsin	100%
Wisconsin Gas LLC	Wisconsin	100%
ATC Holding LLC	Wisconsin	100%
American Transmission Company LLC	Wisconsin	3.20%
W.E. Power, LLC	Wisconsin	100%
Elm Road Generating Station Supercritical, LLC	Wisconsin	100%
Elm Road Services, LLC	Wisconsin	100%
Port Washington Generating Station, LLC	Wisconsin	100%
Wisvest LLC	Wisconsin	100%
Wispark LLC	Wisconsin	100%
CenterPoint Wispark Land Company LLC	Wisconsin	32.95%
2825 Four Mile Road LLC	Wisconsin	100%
Wisconsin Energy Capital Corporation	Wisconsin	100%

(a) Omits the names of certain subsidiaries, which if considered in the aggregate as a single subsidiary, would not constitute a "significant subsidiary" as of December 31, 2011. Indirectly owned subsidiaries are listed under the subsidiaries through which Wisconsin Energy Corporation holds ownership.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-177575 on Form S-3 and Registration Statement Nos. 333-65356, 333-161151 and 333-177572 on Form S-8 of our reports dated February 28, 2012, relating to the consolidated financial statements and financial statement schedules of Wisconsin Energy Corporation and subsidiaries, and the effectiveness of Wisconsin Energy Corporation and subsidiaries' internal control over financial reporting, appearing in this Annual Report on Form 10-K of Wisconsin Energy Corporation and subsidiaries for the year ended December 31, 2011.

/s/DELOITTE & TOUCHE LLP

Milwaukee, Wisconsin

February 28, 2012

EX-31.1

Exhibit 31.1

Certification Pursuant to

Rule 13a-14(a) or 15d-14(a),

as Adopted Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

I, Gale E. Klappa, certify that:

1. I have reviewed this annual report on Form 10-K of Wisconsin Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 28, 2012

/s/GALE E. KLAPPA

Gale E. Klappa

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

EX-31.2

Exhibit 31.2

Certification Pursuant to

Rule 13a-14(a) or 15d-14(a),

as Adopted Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

I, Frederick D. Kuester, certify that:

1. I have reviewed this annual report on Form 10-K of Wisconsin Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 28, 2012

/s/FREDERICK D. KUESTER

Frederick D. Kuester

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-32.1

Exhibit 32.1

Certification Pursuant to

18 U.S.C. Section 1350,

As Adopted Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Wisconsin Energy Corporation (the "Company") on Form 10-K for the period ended December 31, 2011, as filed with the Securities and Exchange Commission on February 28, 2012 (the "Report"), I, Gale E. Klappa, Chairman, President and Chief Executive Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/GALE E. KLAPPA 

Gale E. Klappa

Chairman, President and Chief Executive Officer

February 28, 2012

EX-32.2

Exhibit 32.2

Certification Pursuant to

18 U.S.C. Section 1350,

As Adopted Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Wisconsin Energy Corporation (the "Company") on Form 10-K for the period ended December 31, 2011, as filed with the Securities and Exchange Commission on February 28, 2012 (the "Report"), I, Frederick D. Kuester, Executive Vice President and Chief Financial Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/FREDERICK D. KUESTER

Frederick D. Kuester

Executive Vice President and Chief Financial Officer

February 28, 2012

XML

Short-Term Debt (Tables)

12 Months Ended

Dec. 31, 2011

Short-Term Debt (Tables) [Abstract]

Short-term notes payable balances and their corresponding weighted-average interest rates

Short-term notes payable balances and their corresponding weighted-average interest rates as of December 31 consist of:

	2011				2010
			Interest				Interest
Short-Term Debt	Balance		Rate		Balance		Rate
	(Millions of Dollars, except for percentages)
Commercial paper	$	669.9	0.27	%	$	657.9	0.30	%

Commercial paper

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

	2011			2010
	(Millions of Dollars, except for percentages)
Maximum Short-Term Debt Outstanding	$	717.3		$	821.0
Average Short-Term Debt Outstanding	$	505.1		$	528.7
Weighted-Average Interest Rate	0.25		%	0.32		%

XML

Accounting and Reporting for Power the Future Generating Units (Details)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Accounting and Reporting for Power the Future Generating Units (Textuals)
New generating units built	4
Pre-tax cost of capital used for current rates	14.00%
Weighted-average pre-tax cost of interest for capitalized interest		5.00%
Lease return on equity component, after tax	12.70%
OC 1 [Member]
Public Utility Property Plant And Equipment [Line Items]
One time escalation of lease payments expected to be levelized	10.60%
Years before one time escalation of lease payments	first five years
OC 2 [Member]
Public Utility Property Plant And Equipment [Line Items]
One time escalation of lease payments expected to be levelized	10.60%
Years before one time escalation of lease payments	first five years

XML

Summary of Significant Accounting Policies (Details 1)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Schedule of Equity Method Investments [Line Items]
Percentage of equity method investment	50.00%
ATC [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of equity method investment	26.20%	26.20%
Voting rights in ATC board members	one out of ten
Number of votes with each member of ATC	1
Maximum voting control for individual member in ATC	10.00%

XML

Fair Value Measurements (Details 1) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Fair value of derivatives classified as Level 3 in the fair value hierarchy
Change in unrealized gains (losses) relating to instruments still held as of December 31	$ 0	$ 0
Derivative [Member]
Fair value of derivatives classified as Level 3 in the fair value hierarchy
Balance	5.9	5.8
Realized and unrealized gains (losses)	0	0
Purchases and issuances	16.1	17.9
Settlements	(16.3)	(17.8)
Transfers in and/or out of Level 3	0	0
Balance	$ 5.7	$ 5.9

XML

Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Change in Asset Retirement Obligations
Balance as of January 1	$ 52.6	$ 57.9
Liabilities incurred	0.6	0
Liabilities settled	(2.2)	(2.5)
Accretion	3.0	3.1
Cash Flow Revisions	1.5	(5.9)
Balance as of December 31	$ 55.5	$ 52.6

XML

Commitments and Contingencies (Details) (USD $)		12 Months Ended									105 Months Ended	129 Months Ended		12 Months Ended
	Dec. 31, 2011	Dec. 31, 2011 Capital Expenditures [Member]	Dec. 31, 2011 Manufactured Gas Plant Sites [Member]	Dec. 31, 2011 Coal combustion product landfill sites [Member]	Dec. 31, 2010 Coal combustion product landfill sites [Member]	Dec. 31, 2009 Coal combustion product landfill sites [Member]	Dec. 31, 2011 Bechtel, contractor of the Oak Creek expansion [Member]	Dec. 31, 2011 Bechtel's first claim [Member]	Dec. 31, 2011 Bechtel's second claim [Member]	Dec. 31, 2011 EPA - Consent Decree [Member]	Dec. 31, 2011 EPA - Consent Decree [Member]	Dec. 31, 2013 EPA - Consent Decree [Member]	Dec. 08, 2011 Valley Power Plant [Member] T	Dec. 31, 2011 Cash Balance Pension Plan [Member]
Commitment and Contingencies (Textuals) [Abstract]
Estimated total capital expenditures commitment amount		$ 740,200,000
Reserves related to future remediation costs			37,500,000
Expense related to environmental remediation				200,000	400,000	300,000					1,000,000,000
Reserves related to landfill sites				0
Loss Contingency, Damages Sought, Value							517,500,000	445,500,000	72,000,000
Payments for legal settlements									67,000,000
Loss contingency, settlement agreement, terms							The remaining milestone payments are tied to final acceptance of the units. In addition, Bechtel received 120 days of schedule relief for OC 1 and 60 days for OC 2. Therefore, the guaranteed in-service date of September 29, 2009 for OC 1 was extended to January 27, 2010, and the guaranteed in-service date of September 29, 2010 for OC 2 was extended to November 28, 2010. Bechtel subsequently received an additional 21 days of schedule relief for OC 2 as part of a change order signed concurrent with the turnover of OC 2. Therefore, the total schedule relief granted to Bechtel was 120 days for OC 1 and 81 days for OC 2.
Future minimum payments for the next five years and thereafter for our operating lease contracts
2012	16,300,000
2013	6,500,000
2014	3,900,000
2015	4,000,000
2016	3,700,000
Thereafter	29,000,000
Total	63,400,000
Commitments and Contingencies (Textuals) [Abstract]
Estimated future detailed site investigation and remediation costs, minimum			21,000,000
Estimated Future detailed site investigation and remediation costs, maximum			65,000,000
Period for future costs of detailed site investigation and remediation costs			over the next ten years
Expense related to environmental remediation				200,000	400,000	300,000					1,000,000,000
Number of coal units retired										4	4
Estimated Future Environmental Remediation Expense												$ 1,100,000,000
Responsibility for amounts paid under the settlement agreement in percentage							85.00%
Period to recover remediation cost of manufactured gas plant sites			5
Period of Total cost related to installation of air quality controls and retirement of coal units under consent decree										10
Loss Contingency, Settlement Agreement, Consideration														In November 2011, we entered into a settlement agreement with the plaintiffs for $45.0 million, and the court promptly issued an order preliminarily approving the settlement. As part of the settlement agreement, we agreed to class certification for all similarly situated plaintiffs.
Loss Contingency Range Of Possible Loss, Per Share, Maximum														$ 0.04
Target Annual Sulfur Dioxide Emissions Threshold													4,500
Target Reduction in Sulfur Dioxide Emissions, As a Percent													65.00%

XML

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies (Tables) [Abstract]

Future minimum payments for the next five years and thereafter for our operating lease contracts

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

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

XML

Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2011

Regulatory Assets and Liabilities (Tables) [Abstract]

Regulatory assets and liabilities

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

	2011		2010
	(Millions of Dollars)
Regulatory Assets
Deferred unrecognized pension costs	$	647.8	$	542.6
Deferred income tax related	121.2		89.9
Escrowed electric transmission costs	118.3		138.0
Deferred unrecognized OPEB costs	102.9		85.7
Deferred plant related -- capital lease	73.2		77.1
Deferred environmental costs	48.5		56.7
Other, net	153.8		154.5
Total regulatory assets	$	1,265.7	$	1,144.5
Regulatory Liabilities
Deferred cost of removal obligations	$	728.2	$	723.9
Escrowed bad debt costs	69.0		18.5
Other, net	118.7		156.7
Total regulatory liabilities	$	915.9	$	899.1

XML

Supplemental Cash Flow Information (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Supplemental Cash Flow Information (Textuals)
Interest paid, net of amounts capitalized	$ 234.0	$ 198.0	$ 152.3
Income taxes paid, net of refunds	(109.1)	166.7	(27.9)
Accounts payable related to capital expenditures	16.7	18.2	14.7
Amortization of deferred revenue	$ 54.4	$ 34.6	$ 8.0

XML

Benefits (Details 1) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Amounts recognized in Consolidated Balance Sheets
Other long-term liabilities	$ 222,700,000	$ 353,200,000
Information for pension plans with an accumulated benefit obligation in excess of fair value of assets
Accumulated benefit obligation	1,329,400,000	1,222,500,000
Pension Plans [Member]
Change in Plan Assets
Fair Value at January 1	1,059,500,000	1,026,000,000
Actual earnings (loss) on plan assets	33,800,000	110,100,000
Employer contributions	242,900,000	6,800,000
Participants' contributions	0	0
Gross benefits paid	(73,700,000)	(83,400,000)
Fair Value at December 31	1,262,500,000	1,059,500,000
Amounts recognized in Consolidated Balance Sheets
Other deferred charges	0	0
Other long-term liabilities	68,100,000	163,300,000
Net Liability	68,100,000	163,300,000
Amounts not yet been recognized in net periodic benefit cost
Net actuarial loss	633,400,000	521,000,000
Prior service costs (credits)	14,400,000	16,700,000
Transition obligation	0	0
Total	647,800,000	537,700,000
OPEB [Member]
Change in Plan Assets
Fair Value at January 1	216,700,000	202,600,000
Actual earnings (loss) on plan assets	9,000,000	24,500,000
Employer contributions	48,400,000	4,900,000	24,300,000
Participants' contributions	11,600,000	6,500,000
Gross benefits paid	(30,300,000)	(21,800,000)
Fair Value at December 31	255,400,000	216,700,000	202,600,000
Amounts recognized in Consolidated Balance Sheets
Other deferred charges	20,300,000	38,300,000
Other long-term liabilities	154,600,000	189,900,000
Net Liability	134,300,000	151,600,000
Amounts not yet been recognized in net periodic benefit cost
Net actuarial loss	108,100,000	98,900,000
Prior service costs (credits)	(6,100,000)	(8,500,000)
Transition obligation	300,000	600,000
Total	$ 102,300,000	$ 91,000,000

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Income Taxes (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Summary of income tax expense
Current tax expense (benefit)	$ (166,700,000)	$ 144,900,000	$ 28,100,000
Deferred income taxes, net	434,800,000	108,600,000	191,200,000
Investment tax credit, net	(4,200,000)	(3,600,000)	(3,800,000)
Total Income Tax Expense, Amount	263,900,000	249,900,000	215,500,000
The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable U.S. statutory federal income tax rate to income before income taxes as a result of the following:
Expected tax at statutory federal tax rates, Amount	271,800,000	246,500,000	206,900,000
Expected tax at statutory federal tax rates, Effective Tax Rate	35.00%	35.00%	35.00%
State income taxes net of federal tax benefit, Amount	40,100,000	35,800,000	31,800,000
State income taxes net of federal tax benefit, Effective Tax Rate	5.20%	5.10%	5.40%
Domestic production activities deduction, Amount	(12,600,000)	(12,600,000)	(8,300,000)
Domestic production activities deduction, Effective Tax Rate	(1.60%)	(1.80%)	(1.40%)
AFUDC - Equity, Amount	(20,800,000)	(11,400,000)	(5,600,000)
AFUDC - Equity, Effective Tax Rate	(2.70%)	(1.60%)	(0.90%)
Production tax credits - wind, Amount	(8,700,000)	(7,200,000)	(7,100,000)
Production tax credits - wind, Effective Tax Rate	(1.10%)	(1.00%)	(1.20%)
Investment tax credit restored, Amount	(4,200,000)	(3,600,000)	(3,800,000)
Investment tax credit restored, Effective Tax Rate	(0.50%)	(0.50%)	(0.60%)
Other, net, Amount	(1,700,000)	2,400,000	1,600,000
Other, net, Effective Tax Rate	(0.30%)	0.30%	0.20%
Total Income Tax Expense, Amount	263,900,000	249,900,000	215,500,000
Total Income Tax Expense, Effective Tax Rate	34.00%	35.50%	36.50%
Current
Employee benefits and compensation	14,600,000	14,300,000
Other	57,100,000	33,500,000
Total Current Deferred Tax Assets	71,700,000	47,800,000
Non-current
Deferred Tax Assets, Future Federal Tax Benefits	328,500,000	0
Deferred revenues	279,700,000	305,900,000
Employee benefits and compensation	103,600,000	110,200,000
Property-related	28,300,000	30,300,000
Construction advances	25,400,000	118,300,000
Emission allowances	1,000,000	2,600,000
Other	34,000,000	30,800,000
Total Non-current Deferred Tax Assets	800,500,000	598,100,000
Total Deferred Tax Assets	872,200,000	645,900,000
Current
Prepaid items	50,100,000	46,900,000
Total Current Deferred Tax Liabilities	50,100,000	46,900,000
Non-current
Property-related	2,020,700,000	1,346,800,000
Employee benefits and compensation	232,800,000	179,500,000
Investment in transmission affiliate	129,200,000	112,400,000
Deferred transmission costs	47,400,000	53,100,000
Other	66,500,000	61,100,000
Total Non-current Deferred Tax Liabilities	2,496,600,000	1,752,900,000
Total Deferred Tax Liabilities	2,546,700,000	1,799,800,000
Consolidated Balance Sheet Presentation
Current Deferred Tax Asset	21,600,000	900,000
Non-Current Deferred Tax Liability	1,696,100,000	1,154,800,000
Reconciliation of the beginning and ending amount of unrecognized tax benefits
Balance, January 1	29,500,000	35,400,000
Additions based on tax positions related to the current year	0	800,000
Additions for tax positions of prior years	0	10,400,000
Reductions for tax positions of prior years	(13,900,000)	(2,500,000)
Reductions due to statute of limitations	(2,500,000)	(300,000)
Settlements during the period	(2,000,000)	(14,300,000)
Balance, December 31	11,100,000	29,500,000	35,400,000
Income Taxes (Textuals)
Deferred tax assets valuation allowance	11,000,000	16,900,000
Net amount of unrecognized tax benefits having impact on the effective tax rate for continuing operations	100,000	2,300,000
Accrued interest in the Consolidated Income Statements	700,000	4,100,000	2,000,000
Accrued penalties in the Consolidated Income Statements	300,000	0	0
Accrued interest on the Consolidated Balance Sheets	2,000,000	8,200,000
Accrued penalties on the Consolidated Balance Sheets	0	300,000
Operating Loss Carryforwards	867,100,000
Deferred Tax Assets, Operating Loss Carryforwards	303,500,000
Tax Credit Carryforward, Amount	25,000,000
Tax Credit Carryforward, Deferred Tax Asset	$ 25,000,000

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Segment Reporting (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Financial information of reportable operating segments
Operating Revenues	$ 4,486.4	[1]	$ 4,202.5	[1]	$ 4,100.9	[1]
Depreciation and Amortization	330.2		305.6		343.0
Operating Income (Loss)	887.3		810.4		660.3
Equity in Earnings of Unconsolidated Affiliates	61.6		59.9		58.9
Interest Expense, net	235.8		206.4		156.7
Income Tax Expense (Benefit)	263.9		249.9		215.5
Income from Discontinued Operations, Net of Tax	13.4		2.1		6.7
Net Income (Loss)	526.2		456.5		382.4
Capital Expenditures	830.8		798.2		814.6
Total Assets	13,862.1	[2]	13,059.8	[2]	12,697.9	[2]
Utility Energy [Member]
Financial information of reportable operating segments
Operating Revenues	4,431.5	[1]	4,165.3	[1]	4,092.0	[1]
Depreciation and Amortization	257.0		251.4		313.1
Operating Income (Loss)	544.8		564.0		550.9
Equity in Earnings of Unconsolidated Affiliates	62.5		60.1		59.1
Interest Expense, net	110.0		117.2		117.5
Income Tax Expense (Benefit)	182.7		192.1		186.7
Income from Discontinued Operations, Net of Tax	0		0.7		1.8
Net Income (Loss)	376.3		354.2		334.2
Capital Expenditures	792.2		687.0		547.0
Total Assets	13,433.5	[2]	11,997.4	[2]	10,784.6	[2]
Non-Utility Energy [Member]
Financial information of reportable operating segments
Operating Revenues	435.1	[1]	320.2	[1]	163.1	[1]
Depreciation and Amortization	72.5		53.5		29.2
Operating Income (Loss)	348.9		252.4		120.1
Equity in Earnings of Unconsolidated Affiliates	0		0		0
Interest Expense, net	66.7		40.3		14.7
Income Tax Expense (Benefit)	112.8		84.9		43.4
Income from Discontinued Operations, Net of Tax	0		0		0
Net Income (Loss)	169.8		128.4		63.8
Capital Expenditures	31.2		109.3		253.2
Total Assets	2,949.0	[2]	2,914.2	[2]	2,754.1	[2]
Corporate and Other [Member]
Financial information of reportable operating segments
Operating Revenues	0.9	[1],[3]	0.5	[1],[3]	0.2	[1],[3]
Depreciation and Amortization	0.7	[3]	0.7	[3]	0.7	[3]
Operating Income (Loss)	(6.4)	[3]	(6.0)	[3]	(10.7)	[3]
Equity in Earnings of Unconsolidated Affiliates	(0.9)	[3]	(0.2)	[3]	(0.2)	[3]
Interest Expense, net	59.5	[3]	52.8	[3]	54.3	[3]
Income Tax Expense (Benefit)	(31.6)	[3]	(27.1)	[3]	(14.6)	[3]
Income from Discontinued Operations, Net of Tax	13.4	[3]	1.4	[3]	4.9	[3]
Net Income (Loss)	525.9	[3]	456.4	[3]	382.3	[3]
Capital Expenditures	7.4	[3]	1.9	[3]	14.4	[3]
Total Assets	4,694.8	[2],[3]	5,075.9	[2],[3]	5,385.5	[2],[3]
Reconciling Items [Member]
Financial information of reportable operating segments
Operating Revenues	(381.1)	[1]	(283.5)	[1]	(154.4)	[1]
Depreciation and Amortization	0		0		0
Operating Income (Loss)	0		0		0
Equity in Earnings of Unconsolidated Affiliates	0		0		0
Interest Expense, net	(0.4)		(3.9)		(29.8)
Income Tax Expense (Benefit)	0		0		0
Income from Discontinued Operations, Net of Tax	0		0		0
Net Income (Loss)	(545.8)		(482.5)		(397.9)
Capital Expenditures	0		0		0
Total Assets	(7,215.2)	[2]	(6,927.7)	[2]	(6,226.3)	[2]
Elimination [Member]
Financial information of reportable operating segments
Total Assets	$ 2,369.0		$ 1,785.9		$ 889.1

[1] An elimination for intersegment revenues is included in Operating Revenues. This elimination is primarily between We Power and Wisconsin Electric.

[2] An elimination of $2,369.0 million, $1,785.9 million and $889.1 million is included in Total Assets as of December 31, 2011, 2010 and 2009, respectively, for all PTF-related activity between We Power and Wisconsin Electric.

[3] Corporate & Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark as well as interest on corporate debt.

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Condensed Parent Company Financial Statements (Details 6) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Financial Instruments
Long-term debt including current portion, carrying value	$ 4,541.4	$ 4,288.0
Long-term debt including current portion, fair value	5,179.9	4,578.0
Carrying Amount [Member] | Wisconsin Energy Corporation [Member]
Financial Instruments
Long-term debt including current portion, carrying value	700.0	1,150.0
Fair Value [Member] | Wisconsin Energy Corporation [Member]
Financial Instruments
Long-term debt including current portion, fair value	$ 750.8	$ 1,217.4

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Condensed Parent Company Financial Statements (Details 1) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009		Dec. 31, 2008
Current Assets
Cash and cash equivalents	$ 14.1		$ 24.5		$ 20.2		$ 31.7
Prepaid taxes and other	140.3		125.6
Total Current Assets	1,426.2		1,331.1
Property and Investments
Investment in subsidiary companies	349.7		330.5
Other	201.6		218.9
Total Deferred Charges and Other Assets	1,882.2		1,750.9
Total Assets	13,862.1	[1]	13,059.8	[1]	12,697.9	[1]
Current Liabilities
Short-term debt	669.9		657.9
Other	230.4		186.1
Total Current Liabilities	1,364.5		1,721.1
Long-term debt	4,614.3		3,932.0
Other Long-term liabilities	314.3		376.9
Stockholder's equity	3,963.3		3,802.1		3,566.9		3,336.9
Total Capitalization and Liabilities	13,862.1		13,059.8
Wisconsin Energy Corporation [Member]
Current Assets
Cash and cash equivalents	0.5		0.6		0.7		1.9
Accounts and notes receivable from associated companies	55.8		38.6
Prepaid taxes and other	2.2		93.8
Total Current Assets	58.5		133.0
Property and Investments
Investment in subsidiary companies	4,906.9		5,242.2
Other	2.6		70.3
Total Property and Investments	4,909.5		5,312.5
Total Deferred Charges and Other Assets	433.3		104.0
Total Assets	5,401.3		5,549.5
Current Liabilities
Long-term debt due currently	0		450.0
Short-term debt	146.5		263.0
Notes payable due associated companies	136.8		132.9
Other	327.3		34.3
Total Current Liabilities	610.6		880.2
Long-term debt	693.6		692.9
Other Long-term liabilities	133.8		174.3
Stockholder's equity	3,963.3		3,802.1
Total Capitalization and Liabilities	$ 5,401.3		$ 5,549.5

[1] An elimination of $2,369.0 million, $1,785.9 million and $889.1 million is included in Total Assets as of December 31, 2011, 2010 and 2009, respectively, for all PTF-related activity between We Power and Wisconsin Electric.

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Valuation and Qualifying Accounts (Details) (Allowance for Doubtful Accounts [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Allowance for Doubtful Accounts [Member]
Valuation and Qualifying Accounts
Balance at Beginning of the Period	$ 58.1	$ 57.9	$ 48.8
Expense	85.8	86.2	54.6
Deferral	(35.9)	(32.5)	12.9
Net Write-offs	(46.3)	(53.5)	(58.4)
Balance at End of the Period	$ 61.7	$ 58.1	$ 57.9

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Related Parties (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Related Party Transaction [Line Items]
Income (Loss) from Equity Method Investments, Net of Dividends or Distributions	$ 62.5	$ 60.1	$ 59.1
Distributions from transmission affiliate	49.7	49.3	46.6
American Transmission Company [Member]
Provided and received services from the associated companies
Services Received, -ATC	219.2	220.8	196.0
Receivable and payable balances with ATC
Services Provided, -ATC	5.4	3.8
Services Received, -ATC	18.1	18.5
Related Parties (Textuals) [Abstract]
Equity interest in ATC	26.20%
Services [Member] | American Transmission Company [Member]
Provided and received services from the associated companies
Services Provided, -ATC	10.8	16.9	22.3
Receivable and payable balances with ATC
Services Provided, -ATC	$ 0.7	$ 0.9

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Fair Value Measurements (Details 2) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Financial Instruments
Preferred Stock	$ 30.4	$ 30.4
Long-term debt including current portion, carrying value	4,541.4	4,288.0
Long-term debt including current portion, fair value	5,179.9	4,578.0
Fair Value [Member]
Financial Instruments
Preferred Stock	25.1	23.5
Carrying Amount [Member]
Financial Instruments
Preferred Stock	$ 30.4	$ 30.4

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Segment Reporting

12 Months Ended

Dec. 31, 2011

Segment Reporting [Abstract]

SEGMENT REPORTING

SEGMENT REPORTING

Our operating segments as of December 31, 2011 include a utility energy segment and a non-utility energy segment. We have organized our operating segments based upon the regulatory environment in which our utility subsidiaries operate and on how management makes decisions and measures performance. The segments are managed separately because each business requires different technology and marketing strategies. The accounting policies of the reportable operating segments are the same as those described in Note A.

Our utility energy segment primarily includes our electric and natural gas utility operations. Our electric utility operation engages in the generation, distribution and sale of electric energy in southeastern (including metropolitan Milwaukee), east central and northern Wisconsin and in the Upper Peninsula of Michigan. Our natural gas utility operation is engaged in the purchase, distribution and sale of natural gas to retail customers and the transportation of customer-owned natural gas throughout Wisconsin. Our non-utility energy segment derives its revenues primarily from the ownership of electric power generating facilities for long-term lease to Wisconsin Electric.

Summarized financial information concerning our operating segments for each of the three years ended December 31, 2011 is shown in the following table. The segment information below includes income from discontinued operations as a result of the sale of Edison Sault in May 2010 and the water utility in April 2009.

	Operating Segments							Eliminations
	Energy				Corporate &			& Reconciling			Total
Year Ended	Utility		Non-Utility		Other (a)			Items			Consolidated
	(Millions of Dollars)
December 31, 2011
Operating Revenues (b)	$	4,431.5	$	435.1	$	0.9		$	(381.1	)	$	4,486.4
Depreciation and Amortization	$	257.0	$	72.5	$	0.7		$	—		$	330.2
Operating Income (Loss)	$	544.8	$	348.9	$	(6.4	)	$	—		$	887.3
Equity in Earnings of Unconsolidated Affiliates	$	62.5	$	—	$	(0.9	)	$	—		$	61.6
Interest Expense, Net	$	110.0	$	66.7	$	59.5		$	(0.4	)	$	235.8
Income Tax Expense (Benefit)	$	182.7	$	112.8	$	(31.6	)	$	—		$	263.9
Income from Discontinued Operations, Net of Tax	$	—	$	—	$	13.4		$	—		$	13.4
Net Income (Loss)	$	376.3	$	169.8	$	525.9		$	(545.8	)	$	526.2
Capital Expenditures	$	792.2	$	31.2	$	7.4		$	—		$	830.8
Total Assets (c)	$	13,433.5	$	2,949.0	$	4,694.8		$	(7,215.2	)	$	13,862.1

	Operating Segments							Eliminations
	Energy				Corporate &			& Reconciling			Total
Year Ended	Utility		Non-Utility		Other (a)			Items			Consolidated
	(Millions of Dollars)
December 31, 2010
Operating Revenues (b)	$	4,165.3	$	320.2	$	0.5		$	(283.5	)	$	4,202.5
Depreciation and Amortization	$	251.4	$	53.5	$	0.7		$	—		$	305.6
Operating Income (Loss)	$	564.0	$	252.4	$	(6.0	)	$	—		$	810.4
Equity in Earnings of Unconsolidated Affiliates	$	60.1	$	—	$	(0.2	)	$	—		$	59.9
Interest Expense, Net	$	117.2	$	40.3	$	52.8		$	(3.9	)	$	206.4
Income Tax Expense (Benefit)	$	192.1	$	84.9	$	(27.1	)	$	—		$	249.9
Income from Discontinued Operations, Net of Tax	$	0.7	$	—	$	1.4		$	—		$	2.1
Net Income (Loss)	$	354.2	$	128.4	$	456.4		$	(482.5	)	$	456.5
Capital Expenditures	$	687.0	$	109.3	$	1.9		$	—		$	798.2
Total Assets (c)	$	11,997.4	$	2,914.2	$	5,075.9		$	(6,927.7	)	$	13,059.8

December 31, 2009
Operating Revenues (b)	$	4,092.0	$	163.1	$	0.2		$	(154.4	)	$	4,100.9
Depreciation and Amortization	$	313.1	$	29.2	$	0.7		$	—		$	343.0
Operating Income (Loss)	$	550.9	$	120.1	$	(10.7	)	$	—		$	660.3
Equity in Earnings of Unconsolidated Affiliates	$	59.1	$	—	$	(0.2	)	$	—		$	58.9
Interest Expense, Net	$	117.5	$	14.7	$	54.3		$	(29.8	)	$	156.7
Income Tax Expense (Benefit)	$	186.7	$	43.4	$	(14.6	)	$	—		$	215.5
Income from Discontinued Operations, Net of Tax	$	1.8	$	—	$	4.9		$	—		$	6.7
Net Income (Loss)	$	334.2	$	63.8	$	382.3		$	(397.9	)	$	382.4
Capital Expenditures	$	547.0	$	253.2	$	14.4		$	—		$	814.6
Total Assets (c)	$	10,784.6	$	2,754.1	$	5,385.5		$	(6,226.3	)	$	12,697.9

(a) Corporate & Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark as well as interest on corporate debt.

(b) An elimination for intersegment revenues is included in Operating Revenues. This elimination is primarily between We Power and Wisconsin Electric.

(c) An elimination of $2,369.0 million, $1,785.9 million and $889.1 million is included in Total Assets as of December 31, 2011, 2010 and 2009, respectively, for all PTF-related activity between We Power and Wisconsin Electric.

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Summary of Significant Accounting Policies (Details 3) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fuel Cost Tolerance Range Set by Regulators, Percent	2.00%
Regulatory liabilities	$ 915.9	$ 899.1
Fair value of stock options
Dividend yield	3.90%	3.70%	3.00%
Expected volatility	19.00%	20.30%	25.90%
Expected life (years)	5.5	5.9	6.2
Expected forfeiture rate	2.00%	2.00%	2.00%
Weighted average fair value of our stock options granted	$ 3.17	$ 3.36	$ 4.01
Other Income and Deductions, Net
AFUDC - Equity	59.4	32.5	16.0
Gain on Property Sales	2.4	4.4	1.7
Other, net	0.9	3.3	10.8
Other Income and Deductions, net	62.7	40.2	28.5
Allowance For Funds Used During Construction
AFUDC - Debt	24.7	13.5	6.7
AFUDC - Equity	59.4	32.5	16.0
Inventories
Fossil Fuel	169.2	182.4
Materials and Supplies	114.1	105.2
Natural Gas in Storage	98.7	91.5
Total	382.0	379.1
Summary Of Significant Accounting Policies (Additional) (Textuals) [Abstract]
Symmetrical Fuel Cost Tolerance Range Set By Regulatory Authority	Our retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchased power costs. Beginning in January 2011, the electric fuel rules in Wisconsin allow us to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel costs that are outside of the symmetrical fuel cost tolerance, which the PSCW set at plus or minus 2% of the approved fuel cost plan. The deferred amounts are subject to an excess revenues test. Our retail gas rates include monthly adjustments which permit the recovery or refund of actual purchased gas costs. We defer any difference between actual gas costs incurred (adjusted for a sharing mechanism) and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year. For information regarding revenue recognition for We Power, see Note E.
Depreciation percentage of average depreciable utility plant	2.80%	2.80%	3.70%
Maximum duration to recover outstanding regulatory assets	20
Maximum regulatory current assets and current liabilities amortization period	1
Impairment charges related to goodwill	0
Long-lived assets held for sale	$ 0
Expiry period for stock options granted	no later than 10 years from grant date
Maximum [Member]
Fair value of stock options
Risk-free interest rate	3.40%	3.90%	2.50%
Minimum [Member]
Fair value of stock options
Risk-free interest rate	0.20%	0.20%	0.30%

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Benefits (Tables)

12 Months Ended

Dec. 31, 2011

Benefits (Tables) [Abstract]

Details about pension and OPEB plans

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

	Pension						OPEB
	2011			2010			2011			2010
	(Millions of Dollars)
Change in Benefit Obligation
Benefit Obligation at January 1	$	1,222.8		$	1,160.7		$	368.3		$	374.7
Service cost	15.9			23.7			10.4			11.2
Interest cost	67.6			68.4			20.8			21.2
Participants' contributions	—			—			11.6			6.5
Plan amendments	—			—			0.4			0.3
Actuarial loss (gain)	98.0			53.4			7.6			(23.8		)
Curtailments	—			—			—			(1.0		)
Gross benefits paid	(73.7		)	(83.4		)	(30.3		)	(21.8		)
Federal subsidy on benefits paid	N/A			N/A			0.9			1.0
Benefit Obligation at December 31	$	1,330.6		$	1,222.8		$	389.7		$	368.3
Change in Plan Assets
Fair Value at January 1	$	1,059.5		$	1,026.0		$	216.7		$	202.6
Actual earnings on plan assets	33.8			110.1			9.0			24.5
Employer contributions	242.9			6.8			48.4			4.9
Participants' contributions	—			—			11.6			6.5
Gross benefits paid	(73.7		)	(83.4		)	(30.3		)	(21.8		)
Fair Value at December 31	$	1,262.5		$	1,059.5		$	255.4		$	216.7
Net Liability	$	68.1		$	163.3		$	134.3		$	151.6

Amounts recognized in Consolidated Balance Sheets

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

	Pension				OPEB
	2011		2010		2011		2010
	(Millions of Dollars)
Other deferred charges	$	—	$	—	$	20.3	$	38.3
Other long-term liabilities	68.1		163.3		154.6		189.9
Net liability	$	68.1	$	163.3	$	134.3	$	151.6

Amounts not yet been recognized in net periodic benefit cost

The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31 and are recorded as a regulatory asset on our balance sheet:

	Pension				OPEB
	2011		2010		2011			2010
	(Millions of Dollars)
Net actuarial loss	$	633.4	$	521.0	$	108.1		$	98.9
Prior service costs (credits)	14.4		16.7		(6.1		)	(8.5		)
Transition obligation	—		—		0.3			0.6
Total	$	647.8	$	537.7	$	102.3		$	91.0

Components of net periodic pension and OPEB costs

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

	Pension									OPEB
	2011			2010			2009			2011			2010			2009
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	15.9		$	23.7		$	23.3		$	10.4		$	11.2		$	8.7
Interest cost	67.6			68.4			72.3			20.8			21.2			20.5
Expected return on plan assets	(82.1		)	(78.2		)	(95.4		)	(16.9		)	(14.3		)	(13.6		)
Amortization of:
Transition obligation	—			—			—			0.3			0.3			0.3
Prior service cost (credit)	2.2			2.2			2.2			(1.9		)	(11.9		)	(12.6		)
Actuarial loss	34.0			26.8			18.9			6.2			10.8			8.9
Curtailment (gain)	—			—			—			—			(0.4		)	—
Net Periodic Benefit Cost	$	37.6		$	42.9		$	21.3		$	18.9		$	16.9		$	12.2

In addition to the costs above, in 2011 we recorded net pension costs of less than $0.04 per share related to the settlement of pension litigation. See Note R -- Commitments and Contingencies in this report. The charges were after considering insurance and reserves established in the prior year.

	Pension			OPEB
	2011	2010	2009	2011	2010	2009
Weighted-Average assumptions used to
determine benefit obligations as of Dec. 31
Discount rate	5.05%	5.60%	6.05%	5.20%	5.70%	5.75%
Rate of compensation increase	4.0%	4.0%	4.0%	N/A	N/A	N/A
Weighted-Average assumptions used to
determine net cost for year ended Dec. 31
Discount rate	5.60%	6.05%	6.50%	5.70%	5.75%	6.50%
Expected return on plan assets	7.25%	7.25%	8.25%	7.50%	7.50%	8.25%
Rate of compensation increase	4.0%	4.0%	4.0%	N/A	N/A	N/A

Assumed health care cost trend rates as of Dec. 31	2011	2010	2009
Health care cost trend rate assumed for next year (Pre 65 / Post 65)	8.0%/12%	7.5%/16%	7.5%/20%
Rate that the cost trend rate gradually adjusts to	5.0%	5.0%	5.0%
Year that the rate reaches the rate it is assumed to remain at (Pre 65 / Post 65)	2017/2017	2015/2016	2015/2016

A one-percentage-point change in assumed health care cost trend rates effects

A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	1% Increase		1% Decrease
	(Millions of Dollars)
Effect on
Post-retirement benefit obligation	$	31.9	$	(26.8	)
Total of service and interest cost components	$	3.8	$	(3.1	)

Summary of fair value of plan assets by asset category within fair value hierarchy

The following table summarizes the fair value of our pension plan assets by asset category within the fair value hierarchy (for further level information, see Note M):

	As of December 31, 2011
Asset Category - Pension	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	8.5	$	—	$	—	$	8.5
Equities:
U.S. Equity	455.1		—		—		455.1
International Equity	100.4		33.9		—		134.3
Fixed Income
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	76.9		502.8		—		579.7
International Bonds	40.9		44.0		—		84.9
Total	$	681.8	$	580.7	$	—	$	1,262.5

	As of December 31, 2010
Asset Category - Pension	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	21.1	$	—	$	—	$	21.1
Equities:
U.S. Equity	217.2		247.5		—		464.7
International Equity	81.1		21.6		—		102.7
Fixed Income
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	49.7		361.5		—		411.2
International Bonds	31.8		28.0		—		59.8
Total	$	400.9	$	658.6	$	—	$	1,059.5

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

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

	As of December 31, 2011
Asset Category - OPEB	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	2.4	$	—	$	—	$	2.4
Equities:
U.S. Equity	113.6		—		—		113.6
International Equity	32.1		2.3		—		34.4
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	8.2		83.0		—		91.2
International Bonds	8.7		5.1		—		13.8
Total	$	165.0	$	90.4	$	—	$	255.4

	As of December 31, 2010
Asset Category - OPEB	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	1.5	$	—	$	—	$	1.5
Equities:
U.S. Equity	41.6		80.1		—		121.7
International Equity	5.2		1.4		—		6.6
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	21.8		59.4		—		81.2
International Bonds	2.0		3.7		—		5.7
Total	$	72.1	$	144.6	—		$	216.7

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

Employer contributions to defined benefit plan

Cash Flows:   

Employer	Pension
Contributions	Qualified		Non-Qualified		OPEB
	(Millions of Dollars)
2009	$	270.0	$	5.8	$	24.3
2010	$	—	$	6.8	$	4.9
2011	$	236.4	$	6.5	$	48.4

Expected benefit payments in future

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

Year	Pension		Gross OPEB		Expected Medicare Part D Subsidy
	(Millions of Dollars)
2012	$	110.1	$	20.2	$	(0.9	)
2013	$	101.3	$	20.8	$	—
2014	$	104.4	$	22.2	$	—
2015	$	103.6	$	23.5	$	—
2016	$	103.9	$	24.7	$	—
2017-2021	$	535.2	$	136.4	$	—

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Guarantees (Details) (USD $)	Dec. 31, 2011
Guarantees to provide financial and performance assurance to third parties
Guarantees, Maximum Potential Future Payments	$ 2,700,000
Guarantees, Outstanding	100,000
Guarantees, Liability Recorded	0
Financial Standby Letter of Credit [Member]
Guarantees to provide financial and performance assurance to third parties
Guarantees, Maximum Potential Future Payments	1,600,000
Guarantees, Outstanding	100,000
Guarantees, Liability Recorded	$ 0

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Common Equity (Tables)

12 Months Ended

Dec. 31, 2011

Common Equity (Tables) [Abstract]

Recorded pre-tax share-based compensation expense and related tax benefit for share-based awards made to employees and directors

The following table summarizes recorded pre-tax share-based compensation expense and the related tax benefit for share-based awards made to our employees and directors as of December 31:

	2011		2010		2009
	(Millions of Dollars)
Performance units	$	24.1	$	26.0	$	14.0
Stock options	2.6		7.6		10.8
Restricted stock	1.8		1.5		1.0
Share-based compensation expense	$	28.5	$	35.1	$	25.8
Related Tax Benefit	$	11.4	$	14.1	$	10.3

Stock option activity

The following is a summary of our stock option activity during 2011:

Stock Options	Number of Options		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life (Years)	Aggregate Intrinsic Value (Millions)
Outstanding as of January 1, 2011	13,036,466		$	20.81
Granted	458,180		$	29.35
Exercised	(2,855,896	)	$	19.07
Forfeited	—		$	—
Outstanding as of December 31, 2011	10,638,750		$	21.65	5.4	$	141.6
Exercisable as of December 31, 2011	7,534,980		$	21.14	4.5	$	104.1

Stock options outstanding

The following table summarizes information about stock options outstanding as of December 31, 2011:

	Options Outstanding				Options Exercisable
		Weighted-Average				Weighted-Average
Range of Exercise Prices	Number of Options	Exercise Price		Remaining Contractual Life (Years)	Number of Options	Exercise Price		Remaining Contractual Life (Years)
$11.52  to  $17.10	1,972,594	$	16.07	2.3	1,972,594	$	16.07	2.3
$19.74  to  $21.11	3,586,456	$	20.62	5.9	1,420,186	$	19.88	4.3
$23.88  to  $29.35	5,079,700	$	24.54	6.2	4,142,200	$	23.99	5.6
	10,638,750	$	21.65	5.4	7,534,980	$	21.14	4.5

Non-vested options

The following table summarizes information about our non-vested options during 2011:

Non-Vested Stock Options	Number of Options		Weighted- Average Fair Value
Non-Vested as of January 1, 2011	5,272,570		$	4.27
Granted	458,180		$	3.17
Vested	(2,626,980	)	$	4.64
Forfeited	—		$	—
Non-Vested as of December 31, 2011	3,103,770		$	3.78

Restricted stock activity

Restricted Shares:   The Compensation Committee has also approved restricted stock grants to certain key employees and directors. The following restricted stock activity occurred during 2011:

Restricted Shares	Number of Shares		Weighted-Average Market Price
Outstanding as of January 1, 2011	205,404
Granted	74,850		$	29.00
Released	(83,452	)	$	18.82
Forfeited	(4,244	)	$	26.62
Outstanding as of December 31, 2011	192,558

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Regulatory Assets and Liabilities (Details 1) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 915.9	$ 899.1
Regulatory Assets and Liabilities (Textuals)
Regulatory assets and liabilities, current expected to be amortization period	within one year
Deferred cost of removal obligations [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	728.2	723.9
Escrowed Bad Debt Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	69.0	18.5
Other, net [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 118.7	$ 156.7

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Derivative Instruments (Details 2) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Regulatory Liabilities [Line Items]
Regulatory liabilities related to derivatives	$ 915.9	$ 899.1
Derivative [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities related to derivatives	$ 21.7	$ 15.3

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Common Equity (Details 3) (USD $)	1 Months Ended	12 Months Ended
	Jan. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Non-vested options
Outstanding, Shares, Beginning Balance	10,638,750.0
Outstanding, Weighted-Average Exercise Price, Beginning	$ 21.65
Granted, shares	938,770
Granted, Weighted-Average Exercise Price		$ 3.17	$ 3.36	$ 4.01
Outstanding, Shares, Ending Balance		10,638,750.0
Outstanding, Weighted-Average Exercise Price, Ending		$ 21.65
Non-Vested Options [Member]
Non-vested options
Outstanding, Shares, Beginning Balance		5,272,570.0
Outstanding, Weighted-Average Exercise Price, Beginning		$ 4.27
Granted, shares		458,180.0
Granted, Weighted-Average Exercise Price		$ 3.17
Vested, shares		(2,626,980.0)
Vested, Weighted-Average Exercise Price		$ 4.64
Forfeited, shares		0.0
Forfeited, Weighted-Average Exercise Price		$ 0.00
Outstanding, Shares, Ending Balance		3,103,770.0
Outstanding, Weighted-Average Exercise Price, Ending		$ 3.78

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Summary Of Significant Accounting Policies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Public Utility Property Plant And Equipment [Line Items]
Regulatory liabilities	915.9	899.1
Percentage of AFUDC for biomass project	100.00%
PWGS 1 [Member]
Public Utility Property Plant And Equipment [Line Items]
Depreciation over an estimated useful life	10 to 45 years
PWGS 2 [Member]
Public Utility Property Plant And Equipment [Line Items]
Depreciation over an estimated useful life	10 to 45 years
OC 1 [Member]
Public Utility Property Plant And Equipment [Line Items]
Depreciation over an estimated useful life	10 to 55 years
OC 2 [Member]
Public Utility Property Plant And Equipment [Line Items]
Depreciation over an estimated useful life	10 to 55 years
Wisconsin Electric [Member]
Public Utility Property Plant And Equipment [Line Items]
Interest rate on accrued AFUDC	8.83%	8.83%	9.09%
Percentage of specific Wisconsin Electric CWIP project which accrue AFUDC	100.00%	100.00%	100.00%
Percentage of all Wisconsin Electric utility CWIP projects except specific project which accrue AFUDC	50.00%	50.00%	50.00%
Wisconsin Gas [Member]
Public Utility Property Plant And Equipment [Line Items]
Interest rate on accrued AFUDC	9.05%	9.05%	10.80%
Percentage of Wisconsin Gas CWIP projects which accrued AFUDC	50.00%	50.00%	50.00%
Asset Retirement Obligation Costs [Member]
Public Utility Property Plant And Equipment [Line Items]
Regulatory liabilities	728.2	723.9

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Consolidated Statements of Capitalization (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Debentures (unsecured), 4.50% due 2013 [Member]
Debt instrument stated interest rate (percentage)	4.50%	4.50%
Debentures (unsecured), 6.60% due 2013 [Member]
Debt instrument stated interest rate (percentage)	6.60%	6.60%
Debentures (unsecured), 6.00% due 2014 [Member]
Debt instrument stated interest rate (percentage)	6.00%	6.00%
Debentures (unsecured), 5.20% due 2015 [Member]
Debt instrument stated interest rate (percentage)	5.20%	5.20%
Debentures (unsecured), 6.25% due 2015 [Member]
Debt instrument stated interest rate (percentage)	6.25%	6.25%
Debentures (unsecured), 4.25% due 2019 [Member]
Debt instrument stated interest rate (percentage)	4.25%	4.25%
Debentures (unsecured) 2.95% due 2021 [Member]
Debt instrument stated interest rate (percentage)	2.95%	2.95%
Debentures (unsecured), 6-1/2% due 2028 [Member]
Debt instrument stated interest rate (percentage)	6.50%	6.50%
Debentures (unsecured), 5.625% due 2033 [Member]
Debt instrument stated interest rate (percentage)	5.625%	5.625%
Debentures (unsecured), 5.90% due 2035 [Member]
Debt instrument stated interest rate (percentage)	5.90%	5.90%
Debentures (unsecured), 5.70% due 2036 [Member]
Debt instrument stated interest rate (percentage)	5.70%	5.70%
Debentures (unsecured), 6-7/8% due 2095 [Member]
Debt instrument stated interest rate (percentage)	6.875%	6.875%
Notes (secured, nonrecourse), 4.81% effective rate due 2030 [Member]
Debt instrument stated interest rate (percentage)	4.81%	4.81%
Notes (secured, nonrecourse), 4.91% due 2010-2030 [Member]
Debt instrument stated interest rate (percentage)	4.91%	4.91%
Notes (secured, nonrecourse), 5.209% due 2010-2030 [Member]
Debt instrument stated interest rate (percentage)	5.209%	5.209%
Notes (secured, nonrecourse), 4.673% due 2011-2031 [Member]
Debt instrument stated interest rate (percentage)	4.673%	4.673%
Notes (secured, nonrecourse), 6.00% due 2011-2033 [Member]
Debt instrument stated interest rate (percentage)	6.00%	6.00%
Notes (secured, nonrecourse), 6.09% due 2030-2040 [Member]
Debt instrument stated interest rate (percentage)	6.09%	6.09%
Notes (secured, nonrecourse), 5.848% due 2031-2041 [Member]
Debt instrument stated interest rate (percentage)	5.848%	5.848%
Notes (unsecured), 6.50% due 2011 [Member]
Debt instrument stated interest rate (percentage)	6.50%	6.50%
Notes (unsecured), 6.51% due 2013 [Member]
Debt instrument stated interest rate (percentage)	6.51%	6.51%
Notes (unsecured), 6.94% due 2028 [Member]
Debt instrument stated interest rate (percentage)	6.94%	6.94%
Notes (unsecured), 0.504% variable rate due 2016 [Member]
Long-term debt, percentage bearing variable interest rate	0.504%	0.504%
Notes (unsecured), 0.504% variable rate due 2030 [Member]
Long-term debt, percentage bearing variable interest rate	0.504%	0.504%
Notes (unsecured), 6.20% due 2033 [Member]
Debt instrument stated interest rate (percentage)	6.20%	6.20%
Junior Notes (unsecured), 6.25% due 2067 [Member]
Debt instrument stated interest rate (percentage)	6.25%	6.25%
Wisconsin Energy Corporation [Member]
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	15,000,000	15,000,000
Preferred stock, shares outstanding	0	0
Wisconsin Electric [Member]
Preferred stock, par value	$ 25	$ 25
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, shares outstanding	0	0
Six Per Cent. Preferred Stock [Member] | Wisconsin Electric [Member]
Preferred stock, par value	$ 100	$ 100
Preferred stock, shares authorized	45,000	45,000
Preferred stock, shares outstanding	44,498	44,498
Preferred stock dividend rate, percentage	6.00%	6.00%
Serial preferred stock, 3.60% Series Redeemable [Member] | Wisconsin Electric [Member]
Preferred stock, par value	$ 100	$ 100
Preferred stock, shares authorized	2,286,500	2,286,500
Preferred stock, shares outstanding	260,000	260,000
Preferred stock dividend rate, percentage	3.60%	3.60%
Preferred stock, redeemable per share	$ 101	$ 101

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Common Equity (Details 4) (USD $)	1 Months Ended	12 Months Ended							1 Months Ended	8 Months Ended
	Jan. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2011 Stock options [Member]	Dec. 31, 2011 Share Repurchases to Fulfill Exercised Stock Options and Restricted Stock Awards [Member]	Dec. 31, 2010 Share Repurchases to Fulfill Exercised Stock Options and Restricted Stock Awards [Member]	Dec. 31, 2009 Share Repurchases to Fulfill Exercised Stock Options and Restricted Stock Awards [Member]	May 31, 2011 Share Repurchase Plan, 2011 [Member]	Dec. 31, 2011 Share Repurchase Plan, 2011 [Member]
Common Equity (Textuals)
Common stock shares, Authorized		325,000,000	325,000,000
Common stock shares, Outstanding		230,486,804	233,771,194
Stock options awarded under long-term incentive compensation	938,770				458,180.0
Exercise price of non qualified stock options	$ 34.88
Intrinsic value of options exercised		$ 36,100,000	$ 62,100,000	$ 12,000,000
Exercise price of the stock option on the grant date		no less than 100% of the common stock's fair market value
Mimimum period after grant that stock options can be exercised					6 months
Option grants vesting period in years					3 years
Expiration of options from time of grant					10 years
Minimum percentage award based on performance unit		0.00
Maximum percentage award based on performance unit		1.75
Shares Purchased by agents from open market						3,000,000	5,800,000	1,400,000
Amount paid for Shares Purchased by agents from open market		193,900,000	156,600,000	29,600,000		93,900,000	156,600,000	29,600,000
Exercise of stock options		54,400,000	90,900,000	17,000,000		54,400,000	90,900,000	17,000,000
Maximum period to defer interest payments on the Junior Notes		We have the option to defer interest payments on the Junior Notes, from time to time, for one or more periods of up to 10 consecutive years per period. During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.
Ability to declare common dividends limited to Percentage of Net Income by Wisconsin Electric		limited to 75% or 50%
Wisconsin Electric's common stock equity to total capitalization		is less than 25% and 20%
3.60% Serial Preferred Stock		3.60%
Maximum percentage of equity method investment		50.00%
Equity method investment		3,500,000,000
Percentage of equity method investment exceeding consolidated net assets		25.00%
Stock Repurchase Program, Authorized Amount									300,000,000
Stock Repurchased and Retired During Period, Shares										3,200,000
Treasury Stock Acquired, Average Cost Per Share										$ 30.79
Treasury Stock, Value, Acquired, Cost Method										$ 100,000,000

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Guarantees (Tables)

12 Months Ended

Dec. 31, 2011

Guarantees (Tables) [Abstract]

Guarantees to provide financial and performance assurance to third parties

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

	Maximum Potential		Liability
	Future Payments	Outstanding	Recorded
	(Millions of Dollars)
Guarantees	$2.7	$0.1	$—
Letters of Credit	$1.6	$0.1	$—

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Schedule I -- Condensed Parent Company Financial Statements

12 Months Ended

Dec. 31, 2011

Schedule I -- Condensed Parent Company Financial Statements [Abstract]

SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS

WISCONSIN ENERGY CORPORATION

INCOME STATEMENTS

(Parent Company Only)

SCHEDULE I -- CONDENSED PARENT COMPANY

FINANCIAL STATEMENTS

	Year Ended December 31
	2011			2010			2009
	(Millions of Dollars)
Other Income, Net	$	2.7		$	4.2		$	24.2
Corporate Expense	4.8			4.0			8.9
Interest Expense	61.8			53.8			50.2
Loss before Taxes	(63.9		)	(53.6		)	(34.9		)
Income Tax Benefit	30.8			25.9			14.7
Loss after Taxes	(33.1		)	(27.7		)	(20.2		)
Equity in Subsidiaries' Continuing Operations	545.9			482.1			395.9
Income from Continuing Operations	512.8			454.4			375.7
Income from Discontinued Operations including Equity in Subsidiaries' Discontinued Operations	13.4			2.1			6.7
Net Income	$	526.2		$	456.5		$	382.4
See accompanying notes to condensed parent company financial statements.

WISCONSIN ENERGY CORPORATION

STATEMENTS OF CASH FLOWS

(Parent Company Only)

SCHEDULE I - CONDENSED PARENT COMPANY

FINANCIAL STATEMENTS - (Cont'd)

	Year Ended December 31
	2011			2010			2009
	(Millions of Dollars)
Operating Activities
Net income	$	526.2		$	456.5		$	382.4
Reconciliation to cash
Equity in subsidiaries' earnings	(545.9		)	(482.9		)	(397.7		)
Dividends and distributions from subsidiaries	995.5			305.3			225.2
Deferred income taxes, net	(350.9		)	(29.7		)	28.2
Accrued income taxes, net	363.4			41.9			(15.5		)
Change in - Other current assets	(0.1		)	11.5			8.1
Change in - Other current liabilities	8.9			3.0			(0.4		)
Change in - Accounts receivable	(18.7		)	477.2			1.7
Other, net	(10.2		)	(1.4		)	6.6
Cash Provided by Operating Activities	968.2			781.4			238.6
Investing Activities
Proceeds from asset sales	—			63.1			—
Capital contributions to associated companies	(36.5		)	(64.5		)	(108.9		)
Capitalized interest and other	2.4			(57.3		)	(42.7		)
Cash Used in Investing Activities	(34.1		)	(58.7		)	(151.6		)
Financing Activities
Exercise of stock options	54.4			90.9			17.0
Purchase of common stock	(193.9		)	(156.6		)	(29.6		)
Dividends paid on common stock	(242.0		)	(187.0		)	(157.8		)
Issuance of long-term debt	—			—			11.4
Retirement of long-term debt	(450.0		)	(281.5		)	—
Change in short-term debt	(116.5		)	(310.5		)	74.0
Change in notes payable due associated companies	3.9			106.1			(6.6		)
Other, net	9.9			15.8			3.4
Cash Used in Financing Activities	(934.2		)	(722.8		)	(88.2		)
Change in Cash and Cash Equivalents	(0.1		)	(0.1		)	(1.2		)
Cash and Cash Equivalents at Beginning of Year	0.6			0.7			1.9
Cash and Cash Equivalents at End of Year	$	0.5		$	0.6		$	0.7
See accompanying notes to condensed parent company financial statements.

WISCONSIN ENERGY CORPORATION

BALANCE SHEETS

(Parent Company Only)

SCHEDULE I - CONDENSED PARENT COMPANY

FINANCIAL STATEMENTS - (Cont'd)

	December 31
	2011		2010
	(Millions of Dollars)
Assets
Current Assets
Cash and cash equivalents	$	0.5	$	0.6
Accounts and notes receivable from associated companies	55.8		38.6
Prepaid taxes and other	2.2		93.8
Total Current Assets	58.5		133.0
Property and Investments
Investment in subsidiary companies	4,906.9		5,242.2
Other	2.6		70.3
Total Property and Investments	4,909.5		5,312.5
Deferred Charges and Other Assets	433.3		104.0
Total Assets	$	5,401.3	$	5,549.5
Liabilities and Equity
Current Liabilities
Long-term debt due currently	$	—	$	450.0
Short-term debt	146.5		263.0
Notes payable due associated companies	136.8		132.9
Accrued taxes and other	327.3		34.3
Total Current Liabilities	610.6		880.2
Long-term debt	693.6		692.9
Other Long-term liabilities	133.8		174.3
Stockholder's equity	3,963.3		3,802.1
Total Liabilities and Equity	$	5,401.3	$	5,549.5
See accompanying notes to condensed parent company financial statements.

WISCONSIN ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS

(Parent Company Only)

SCHEDULE I - CONDENSED PARENT COMPANY

FINANCIAL STATEMENTS - (Cont'd)

1.    For Parent Company only presentation, investment in subsidiaries are accounted for using the equity method. The condensed Parent Company financial statements and notes should be read in conjunction with the consolidated financial statements and notes of Wisconsin Energy Corporation appearing in this Annual Report on Form 10-K.

2.    Wisconsin Energy's ability as a holding company to pay common dividends primarily depends on the availability of funds received from the Parent Company's non-utility subsidiary, We Power, and its principal utility subsidiaries, Wisconsin Electric and Wisconsin Gas. During 2011, Wisconsin Electric and Wisconsin Gas collectively provided Wisconsin Energy with $272.6 million of dividends and distributions. We Power also provided Wisconsin Energy with $722.2 million of distributions during 2011, which includes the net proceeds from the issuance of $420 million of long-term debt in January 2011.

Various financing arrangements and regulatory requirements impose certain restrictions on the ability of the Parent Company's subsidiaries to transfer funds to the Parent Company in the form of cash dividends, loans or advances. In addition, under Wisconsin law, Wisconsin Electric and Wisconsin Gas are prohibited from loaning funds, either directly or indirectly, to the Parent Company.

Wisconsin Energy does not believe that these restrictions will materially affect the Parent Company's operations or limit any dividend payments in the foreseeable future.

3.    As of December 31, 2011, the maturities of the Parent Company long-term debt outstanding were as follows:

	(Millions of Dollars)
2012	$	—
2013	—
2014	—
2015	—
2016	—
Thereafter	700.0
Total	$	700.0

Wisconsin Energy amortizes debt premiums, discounts and debt issuance costs over the lives of the debt and includes the costs in interest expense.

During 2011, Wisconsin Energy used cash and short-term borrowings to retire $450 million of long-term debt that matured.

During 2010, Wisconsin Energy used cash and short-term borrowings to retire $281.5 million of unsecured notes.

During 2009, Wisconsin Energy issued $11.5 million of new notes and used the proceeds to repay short-term debt.

Wisconsin Energy's bank back-up credit facility contains customary covenants, including certain limitations on its ability to sell assets. The credit facility also contains customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, ERISA defaults and change of control. In addition, pursuant to the terms of the credit facility, Wisconsin Energy must ensure that certain of its subsidiaries comply with several of the covenants contained therein. In addition, Wisconsin Energy is required to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 70%.

As of December 31, 2011, Wisconsin Energy was in compliance with all covenants.

WECC is a subsidiary of Wisconsin Energy and has $80 million of long-term notes outstanding. In a Support Agreement between WECC and Wisconsin Energy, Wisconsin Energy agreed to make sufficient liquid asset contributions to WECC to permit WECC to service its debt obligations as they become due.

4.    Wisconsin Energy and certain of its subsidiaries enter into various guarantees to provide financial and performance assurance to third parties on behalf of affiliates. As of December 31, 2011, Wisconsin Energy had the following guarantees:

	Maximum				Liability
	Potential		Outstanding		Recorded
	Future		as of		as of
	Payments		Dec 31, 2011		Dec 31, 2011
	(Millions of Dollars)
Wisconsin Energy Guarantees
Utility	$	9.9	$	9.9	$	—
Non-Utility Energy	58.1		—		—
Other	0.3		—		—
Total	$	68.3	$	9.9	$	—
Letters of Credit	$	0.4	$	0.4	$	—

Utility guarantees support obligations of the utility segment under surety bonds, worker's compensation and agreements.

Wisconsin Energy's guarantees in support of its non-utility energy segment guaranty performance and payment obligations of We Power. The guarantees which support We Power are for obligations under purchase, construction and lease agreements with the utility segment and third parties.

Wisconsin Energy has a guarantee that supports an environmental indemnification obligation, which is unlimited, associated with the Minergy Neenah plant and indemnifications related to the post-closing obligations under the Minergy Neenah sale agreement which was effective September 7, 2006. Wisconsin Energy's other guarantees also support obligations to third parties under purchase and loan agreements and surety bonds. In the event the guarantee fails to perform, Wisconsin Energy would be responsible for the obligations.

5.    The carrying amount and estimated fair value of certain of our recorded financial instruments as of December 31 are as follows:

	2011				2010
	Carrying		Fair		Carrying		Fair
Financial Instruments	Amount		Value		Amount		Value
	(Millions of Dollars)
Long-term debt including current portion	$	700.0	$	750.8	$	1,150.0	$	1,217.4

The carrying value of net accounts receivable, accounts payable and short-term borrowings approximates fair value due to the short-term nature of these instruments. The fair value of our long-term debt, including the current portion of long-term debt, and unamortized discount on debt, is estimated based upon quoted market value for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the Parent Company's bond rating and the present value of future cash flows.

6.    During the year ended December 31, 2011, Wisconsin Energy paid $57.7 million in interest, net of amounts capitalized, and received $114.6 million in refunds from income taxes. During the year ended December 31, 2010, Wisconsin Energy paid $43.5 million in interest, net of amounts capitalized, and received $1.0 million in refunds from income taxes. During the year ended December 31, 2009, Wisconsin Energy paid $45.2 million in interest, net of amounts capitalized, and received $36.0 million in refunds from income taxes.

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2011

Supplemental Cash Flow Information [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

SUPPLEMENTAL CASH FLOW INFORMATION

During the year ended December 31, 2011, we paid $234.0 million in interest, net of amounts capitalized, and received $109.1 million in net refunds from income taxes. During the year ended December 31, 2010, we paid $198.0 million in interest, net of amounts capitalized, and $166.7 million in income taxes, net of refunds. During the year ended December 31, 2009, we paid $152.3 million in interest, net of amounts capitalized, and received $27.9 million in net refunds from income taxes.

As of December 31, 2011, 2010 and 2009, the amount of accounts payable related to capital expenditures was $16.7 million, $18.2 million and $14.7 million, respectively.

During the years ended December 31, 2011, 2010 and 2009, total amortization of deferred revenue was $54.4 million, $34.6 million and $8.0 million, respectively.

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Variable Interest Entities (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 Megawatt Years	Dec. 31, 2010	Dec. 31, 2009
Variable Interest Entities (Textuals)
Number of tolling and purchased power agreements with third parties which represent variable interests	2
Number of operating leases with VIEs	1
Operating lease agreement with VIE remaining term in years	1.5
Power capacity from a gas-fired cogeneration facility under capital lease (MW)	236
Capital lease agreement with VIE remaining term in years	11
Total payments over remaining terms of the two agreements	$ 309.5
Total capacity and minimum lease payments	$ 65.9	$ 64.2	$ 62.2

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Segment Reporting (Tables)

12 Months Ended

Dec. 31, 2011

Segment Reporting (Tables) [Abstract]

Financial information of reportable operating segments

Summarized financial information concerning our operating segments for each of the three years ended December 31, 2011 is shown in the following table. The segment information below includes income from discontinued operations as a result of the sale of Edison Sault in May 2010 and the water utility in April 2009.

	Operating Segments							Eliminations
	Energy				Corporate &			& Reconciling			Total
Year Ended	Utility		Non-Utility		Other (a)			Items			Consolidated
	(Millions of Dollars)
December 31, 2011
Operating Revenues (b)	$	4,431.5	$	435.1	$	0.9		$	(381.1	)	$	4,486.4
Depreciation and Amortization	$	257.0	$	72.5	$	0.7		$	—		$	330.2
Operating Income (Loss)	$	544.8	$	348.9	$	(6.4	)	$	—		$	887.3
Equity in Earnings of Unconsolidated Affiliates	$	62.5	$	—	$	(0.9	)	$	—		$	61.6
Interest Expense, Net	$	110.0	$	66.7	$	59.5		$	(0.4	)	$	235.8
Income Tax Expense (Benefit)	$	182.7	$	112.8	$	(31.6	)	$	—		$	263.9
Income from Discontinued Operations, Net of Tax	$	—	$	—	$	13.4		$	—		$	13.4
Net Income (Loss)	$	376.3	$	169.8	$	525.9		$	(545.8	)	$	526.2
Capital Expenditures	$	792.2	$	31.2	$	7.4		$	—		$	830.8
Total Assets (c)	$	13,433.5	$	2,949.0	$	4,694.8		$	(7,215.2	)	$	13,862.1

	Operating Segments							Eliminations
	Energy				Corporate &			& Reconciling			Total
Year Ended	Utility		Non-Utility		Other (a)			Items			Consolidated
	(Millions of Dollars)
December 31, 2010
Operating Revenues (b)	$	4,165.3	$	320.2	$	0.5		$	(283.5	)	$	4,202.5
Depreciation and Amortization	$	251.4	$	53.5	$	0.7		$	—		$	305.6
Operating Income (Loss)	$	564.0	$	252.4	$	(6.0	)	$	—		$	810.4
Equity in Earnings of Unconsolidated Affiliates	$	60.1	$	—	$	(0.2	)	$	—		$	59.9
Interest Expense, Net	$	117.2	$	40.3	$	52.8		$	(3.9	)	$	206.4
Income Tax Expense (Benefit)	$	192.1	$	84.9	$	(27.1	)	$	—		$	249.9
Income from Discontinued Operations, Net of Tax	$	0.7	$	—	$	1.4		$	—		$	2.1
Net Income (Loss)	$	354.2	$	128.4	$	456.4		$	(482.5	)	$	456.5
Capital Expenditures	$	687.0	$	109.3	$	1.9		$	—		$	798.2
Total Assets (c)	$	11,997.4	$	2,914.2	$	5,075.9		$	(6,927.7	)	$	13,059.8

December 31, 2009
Operating Revenues (b)	$	4,092.0	$	163.1	$	0.2		$	(154.4	)	$	4,100.9
Depreciation and Amortization	$	313.1	$	29.2	$	0.7		$	—		$	343.0
Operating Income (Loss)	$	550.9	$	120.1	$	(10.7	)	$	—		$	660.3
Equity in Earnings of Unconsolidated Affiliates	$	59.1	$	—	$	(0.2	)	$	—		$	58.9
Interest Expense, Net	$	117.5	$	14.7	$	54.3		$	(29.8	)	$	156.7
Income Tax Expense (Benefit)	$	186.7	$	43.4	$	(14.6	)	$	—		$	215.5
Income from Discontinued Operations, Net of Tax	$	1.8	$	—	$	4.9		$	—		$	6.7
Net Income (Loss)	$	334.2	$	63.8	$	382.3		$	(397.9	)	$	382.4
Capital Expenditures	$	547.0	$	253.2	$	14.4		$	—		$	814.6
Total Assets (c)	$	10,784.6	$	2,754.1	$	5,385.5		$	(6,226.3	)	$	12,697.9

(a) Corporate & Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark as well as interest on corporate debt.

(b) An elimination for intersegment revenues is included in Operating Revenues. This elimination is primarily between We Power and Wisconsin Electric.

(c) An elimination of $2,369.0 million, $1,785.9 million and $889.1 million is included in Total Assets as of December 31, 2011, 2010 and 2009, respectively, for all PTF-related activity between We Power and Wisconsin Electric.

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Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2011

Valuation and Qualifying Accounts [Abstract]

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS

SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS

Allowance for Doubtful Accounts	Balance at Beginning of the Period		Expense		Deferral			Net Write-offs			Balance at End of the Period
	(Millions of Dollars)
December 31, 2011	$	58.1	$	85.8	$	(35.9	)	$	(46.3	)	$	61.7
December 31, 2010	$	57.9	$	86.2	$	(32.5	)	$	(53.5	)	$	58.1
December 31, 2009	$	48.8	$	54.6	$	12.9		$	(58.4	)	$	57.9

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies (Policies) [Abstract]

General

General:Our consolidated financial statements include the accounts of Wisconsin Energy Corporation (Wisconsin Energy, the Company, our, we or us), a diversified holding company, as well as our subsidiaries in the following operating segments:

• Utility Energy Segment -- Consisting of Wisconsin Electric and Wisconsin Gas, engaged primarily in the generation of electricity and the distribution of electricity and natural gas; and

• Non-Utility Energy Segment -- Consisting primarily of We Power, engaged principally in the design, development, construction and ownership of electric power generating facilities for long-term lease to Wisconsin Electric.

Our Corporate and Other segment includes Wispark, which develops and invests in real estate. We have also eliminated all intercompany transactions and balances within this segment from the consolidated financial statements.

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

Reclassifications

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

On January 20, 2011, our Board of Directors approved a two-for-one stock split of our common stock, which was effected through a stock dividend. New shares were distributed on March 1, 2011 to stockholders of record at the close of business on February 14, 2011. All share and per share information has been restated for all periods presented to reflect this stock split.

Revenues

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

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

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

For information regarding revenue recognition for We Power, see Note E.

Accounting For MISO Energy Transactions

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

Property and Depreciation

Property and Depreciation:We record property, plant and equipment at cost. Cost includes material, labor, overheads and capitalized interest. Utility property also includes AFUDC - Equity. Additions to and significant replacements of property are charged to property, plant and equipment at cost; minor items are charged to maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.

We recorded the following property in service by segment as of December 31:

Property In Service	2011		2010
	(Millions of Dollars)
Utility Energy	$	9,817.7	$	9,221.1
Non-Utility Energy	3,067.5		2,283.4
Other	92.5		86.3
Total	$	12,977.7	$	11,590.8

Our utility depreciation rates are certified by the PSCW and MPSC and include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 2.8% in 2011 and 2010, and 3.7% in 2009.

PWGS 1, PWGS 2, OC 1 and OC 2 are being depreciated over the estimated useful life of the various property components. The components have useful lives of between 10 to 45 years for PWGS 1 and PWGS 2, and 10 to 55 years for OC 1 and OC 2.

Our regulated utilities collect in their rates amounts representing future removal costs for many assets that do not have an associated Asset Retirement Obligation (ARO). We record a regulatory liability on our balance sheet for the estimated amounts we have collected in rates for future removal costs less amounts we have spent in removal activities. This regulatory liability was $728.2 million as of December 31, 2011 and $723.9 million as of December 31, 2010.

We recorded the following Construction Work in Progress (CWIP) by segment as of December 31:

CWIP	2011		2010
	(Millions of Dollars)
Utility Energy	$	910.3	$	806.9
Non-Utility Energy	8.9		761.3
Other	2.1		1.7
Total	$	921.3	$	1,569.9

Allowance For Funds Used During Construction - Regulated

Allowance For Funds Used During Construction - Regulated:   AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC - Debt) used during plant construction, and a return on stockholders' capital (AFUDC - Equity) used for construction purposes. AFUDC - Debt is recorded as a reduction of interest expense, and AFUDC - Equity is recorded in Other Income and Deductions, net.

During 2009, Wisconsin Electric accrued AFUDC at a rate of 9.09% as authorized by the PSCW. Consistent with the PSCW's 2008 rate order, Wisconsin Electric accrued AFUDC on 50% of all utility CWIP projects except the Oak Creek AQCS project, which accrued AFUDC on 100% of CWIP. Wisconsin Electric's rates are set to provide a current return on CWIP that does not accrue AFUDC. Based on the 2010 PSCW rate order, effective January 1, 2010 Wisconsin Electric recorded AFUDC on 100% of CWIP associated with the Oak Creek AQCS project, the Edgewater Unit 5 Selective Catalytic Reduction project and the Glacier Hills Wind Park. Wisconsin Electric recorded AFUDC on 50% of all other electric, gas and steam utility CWIP. The AFUDC rate starting January 1, 2010 was 8.83%. This AFUDC accrual policy and rate for Wisconsin Electric continued through 2011 and will continue through 2012.

Wisconsin Electric is also accruing AFUDC on 100% of the biomass project.

During 2009, Wisconsin Gas accrued AFUDC at a rate of 10.80% on 50% of its CWIP as authorized by the PSCW in its 2008 rate order. Wisconsin Gas' rates are set to provide a current return on CWIP that does not accrue AFUDC. Based on the 2010 PSCW rate order, effective January 1, 2010 Wisconsin Gas recorded AFUDC on 50% of all CWIP using an AFUDC rate of 9.05%. This AFUDC accrual policy and rate for Wisconsin Gas continued through 2011 and will continue through 2012.

Capitalized Interest And Carrying Costs - Non Regulated Energy

Capitalized Interest and Carrying Costs - Non-Regulated Energy:   As part of the construction of the PTF electric generating units, we capitalized interest during construction. As allowed under the lease agreements, we were able to collect the carrying costs during the construction of the PTF generating units from our utility customers. The carrying costs that we collected during construction have been recorded as deferred revenue on our balance sheet and we are amortizing the deferred carrying costs to revenue over the individual lease terms. For further information on the accounting for capitalized interest and deferred carrying costs associated with the construction of our PTF power plants, see Note E.

Earning per Common Share

Earnings per Common Share:   We compute basic earnings per common share by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net income attributed to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive securities include in-the-money stock options. The future issuance of shares underlying the outstanding stock options depends on whether the exercise prices of the stock options are less than the average market price of the common shares for the respective periods. Shares that are anti-dilutive are excluded from the calculation. All stock options outstanding during 2011 were included in the computation of diluted earnings per share. For 2010 and 2009, the calculation of diluted earnings per share excluded an immaterial number of out-of-the money stock options that had an anti-dilutive effect.

Materials, Supplies and Inventories

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

Materials, Supplies and Inventories	2011		2010
	(Millions of Dollars)
Fossil Fuel	$	169.2	$	182.4
Materials and Supplies	114.1		105.2
Natural Gas in Storage	98.7		91.5
Total	$	382.0	$	379.1

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

Regulatory Accounting

Regulatory Accounting:   The economic effects of regulation can result in regulated companies recording costs that have been or are expected to be allowed in the rate-making process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets on the balance sheet and expensed in the periods when they are reflected in rates. We defer regulatory assets pursuant to specific or generic orders issued by our regulators. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We expect to recover our outstanding regulatory assets in rates over a period of no longer than 20 years. Regulatory assets and liabilities that are expected to be amortized within one year are recorded as current on the balance sheet. For further information, see Note C.

Asset Retirement Obligations

Asset Retirement Obligations:   We record a liability for a legal ARO in the period in which it is incurred. When a new legal obligation is recorded, we capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. We accrete the liability to its present value each period and depreciate the capitalized cost over the useful life of the related asset. At the end of the asset's useful life, we settle the obligation for its recorded amount or incur a gain or loss. As it relates to our regulated operations, we apply regulatory accounting guidance and recognize regulatory assets or liabilities for the timing differences between when we recover legal AROs in rates and when we would recognize these costs. For further information, see Note F.

Derivative Financial Instruments

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

Cash and Cash Equivalents

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

Restricted Cash

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

Margin Accounts

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

Goodwill

Goodwill:   Goodwill reflects the cost of an acquisition in excess of the fair values assigned to identifiable net assets acquired. As of December 31, 2011 and 2010, we had $441.9 million of goodwill recorded at the utility energy segment, which related to our acquisition of Wisconsin Gas in 2000.

Goodwill is not subject to amortization. However, it is subject to fair value-based rules for measuring impairment, and resulting write-downs, if any, are to be reflected in operating expense. Fair value is assessed by considering future discounted cash flows, a comparison of fair value based on public company trading multiples, and merger and acquisition transaction multiples for similar companies. This evaluation utilizes the information available under the circumstances, including reasonable and supportable assumptions and projections. We perform our annual impairment test as of August 31. There was no impairment to the recorded goodwill balance as of our annual 2011 impairment test date.

Impairment or Disposal of Long Lived Assets

Impairment or Disposal of Long Lived Assets:   We carry property, equipment and goodwill related to businesses held for sale at the lower of cost or estimated fair value less cost to sell. As of December 31, 2011, we had no assets classified as Held for Sale. Long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that their carrying value may not be recoverable from the use and eventual disposition of the asset based on the remaining useful life. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset.

Investments

Investments:   We account for investments in other affiliated companies in which we do not maintain control using the equity method of accounting. We had a total ownership interest of approximately 26.2% in ATC as of December 31, 2011 and 2010. We are represented by one out of ten ATC board members, each of whom has one vote. Due to the voting requirements, no individual member has more than 10% of the voting control. For further information regarding such investments, see Note Q.

Income Taxes

Income Taxes:   We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense.

Investment tax credits associated with regulated operations are deferred and amortized over the life of the assets. We file a consolidated Federal income tax return. Accordingly, we allocate Federal current tax expense benefits and credits to our subsidiaries based on their separate tax computations. For further information, see Note H.

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

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

Stock Options

Stock Options:   We estimate the fair value of stock options using the binomial pricing model. We report unearned stock-based compensation associated with non-vested restricted stock and performance share awards activity within Other Paid in Capital in our Consolidated Statements of Common Equity. We report excess tax benefits as a financing cash inflow. Historically, all stock options have been granted with an exercise price equal to the fair market value of the common stock on the date of grant and expire no later than 10 years from grant date. For a discussion of the impacts to our Consolidated Financial Statements, see Note I.

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Consolidated Statements of Capitalization (USD $) In Millions, unless otherwise specified	Dec. 31, 2011		Dec. 31, 2010
Common Equity	$ 3,963.3		$ 3,802.1
Preferred Stock	30.4		30.4
Obligations under capital leases	132.4		141.9
Unamortized discount, net and other	(26.9)		(24.5)
Long-term debt due currently	(32.6)		(473.4)
Total Long-Term Debt	4,614.3		3,932.0
Total Capitalization	8,608.0		7,764.5
Debentures (unsecured), 4.50% due 2013 [Member]
Long-Term debt, Unsecured	300.0		300.0
Debentures (unsecured), 6.60% due 2013 [Member]
Long-Term debt, Unsecured	45.0		45.0
Debentures (unsecured), 6.00% due 2014 [Member]
Long-Term debt, Unsecured	300.0		300.0
Debentures (unsecured), 5.20% due 2015 [Member]
Long-Term debt, Unsecured	125.0		125.0
Debentures (unsecured), 6.25% due 2015 [Member]
Long-Term debt, Unsecured	250.0		250.0
Debentures (unsecured), 4.25% due 2019 [Member]
Long-Term debt, Unsecured	250.0		250.0
Debentures (unsecured) 2.95% due 2021 [Member]
Long-Term debt, Unsecured	300.0		0
Debentures (unsecured), 6-1/2% due 2028 [Member]
Long-Term debt, Unsecured	150.0		150.0
Debentures (unsecured), 5.625% due 2033 [Member]
Long-Term debt, Unsecured	335.0		335.0
Debentures (unsecured), 5.90% due 2035 [Member]
Long-Term debt, Unsecured	90.0		90.0
Debentures (unsecured), 5.70% due 2036 [Member]
Long-Term debt, Unsecured	300.0		300.0
Debentures (unsecured), 6-7/8% due 2095 [Member]
Long-Term debt, Unsecured	100.0		100.0
Notes (secured, nonrecourse), 4.81% effective rate due 2030 [Member]
Long-Term debt, Secured	2.0		2.0
Notes (secured, nonrecourse), 4.91% due 2011-2030 [Member]
Long-Term debt, Secured	131.2		135.4
Notes (secured, nonrecourse), 5.209% due 2011-2030 [Member]
Long-Term debt, Secured	245.4		251.9
Notes (secured, nonrecourse), 4.673% due 2011-2031 [Member]
Long-Term debt, Secured	202.3		0
Notes (secured, nonrecourse), 6.00% due 2011-2033 [Member]
Long-Term debt, Secured	145.5		148.7
Notes (secured, nonrecourse), 6.09% due 2030-2040 [Member]
Long-Term debt, Secured	275.0		275.0
Notes (secured, nonrecourse), 5.848% due 2031-2041 [Member]
Long-Term debt, Secured	215.0		0
Notes (unsecured), 6.50% due 2011 [Member]
Long-Term debt, Unsecured	0		450.0
Notes (unsecured), 6.51% due 2013 [Member]
Long-Term debt, Unsecured	30.0		30.0
Notes (unsecured), 6.94% due 2028 [Member]
Long-Term debt, Unsecured	50.0		50.0
Notes (unsecured), 0.504% variable rate due 2016 [Member]
Long-Term debt, Unsecured	67.0	[1]	67.0	[1]
Notes (unsecured), 0.504% variable rate due 2030 [Member]
Long-Term debt, Unsecured	80.0	[1]	80.0	[1]
Notes (unsecured), 6.20% due 2033 [Member]
Long-Term debt, Unsecured	200.0		200.0
Junior Notes (unsecured), 6.25% due 2067 [Member]
Long-Term debt, Unsecured	500.0		500.0
Wisconsin Energy Corporation [Member]
Preferred Stock	0		0
Wisconsin Electric [Member]
Long-Term debt, Unsecured	147.0		147.0
Six Per Cent. Preferred Stock [Member] | Wisconsin Electric [Member]
Preferred Stock	4.4		4.4
Serial preferred stock, 3.60% Series Redeemable [Member] | Wisconsin Electric [Member]
Preferred Stock	26.0		26.0
Serial preferred stock, $25 par value; authorized 5,000,000 shares; none outstanding [Member] | Wisconsin Electric [Member]
Preferred Stock	$ 0		$ 0

[1] Variable interest rate as of December 31, 2011.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies (Tables) [Abstract]

Other Income and Deductions, Net

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

Other Income and Deductions, net	2011		2010		2009
	(Millions of Dollars)
AFUDC - Equity	$	59.4	$	32.5	$	16.0
Gain on Property Sales	2.4		4.4		1.7
Other, net	0.9		3.3		10.8
Total Other Income and Deductions, net	$	62.7	$	40.2	$	28.5

Property In Service By Segment

We recorded the following property in service by segment as of December 31:

Property In Service	2011		2010
	(Millions of Dollars)
Utility Energy	$	9,817.7	$	9,221.1
Non-Utility Energy	3,067.5		2,283.4
Other	92.5		86.3
Total	$	12,977.7	$	11,590.8

Construction Work in Progress (CWIP) by segment

We recorded the following Construction Work in Progress (CWIP) by segment as of December 31:

CWIP	2011		2010
	(Millions of Dollars)
Utility Energy	$	910.3	$	806.9
Non-Utility Energy	8.9		761.3
Other	2.1		1.7
Total	$	921.3	$	1,569.9

Allowance For Funds Used During Construction

Our regulated segment recorded the following AFUDC for the years ended December 31:

	2011		2010		2009
	(Millions of Dollars)
AFUDC - Debt	$	24.7	$	13.5	$	6.7
AFUDC - Equity	$	59.4	$	32.5	$	16.0

Inventories

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

Materials, Supplies and Inventories	2011		2010
	(Millions of Dollars)
Fossil Fuel	$	169.2	$	182.4
Materials and Supplies	114.1		105.2
Natural Gas in Storage	98.7		91.5
Total	$	382.0	$	379.1

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

Fair value of stock options

The fair value of our stock options was calculated using a binomial option-pricing model using the following weighted-average assumptions:

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

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Condensed Parent Company Financial Statements (Details 3) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011
Parent Company long-term debt outstanding
2012	$ 20.3
2013	396.3
2014	322.4
2015	399.5
2016	27.4
Thereafter	3,375.5
Total	4,541.4
Wisconsin Energy Corporation [Member]
Parent Company long-term debt outstanding
2012	0
2013	0
2014	0
2015	0
2016	0
Thereafter	700.0
Total	$ 700.0

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Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2011

Derivative Instruments (Tables) [Abstract]

Derivative instruments in balance sheet

We record our current derivative assets on the balance sheet in other current assets and the current portion of the liabilities in other current liabilities. The long-term portion of our derivative assets of $2.5 million is recorded in other deferred charges and other assets, and the long-term portion of our derivative liabilities of $0.7 million is recorded in other long-term liabilities. Our Consolidated Balance Sheets as of December 31, 2011 and 2010 include:

	December 31, 2011				December 31, 2010
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	2.1	$	9.1	$	2.5	$	11.6
Fuel Oil	0.3		0.1		4.4		—
FTRs	5.7		—		5.9		—
Coal	12.5		—		2.9		—
Total	$	20.6	$	9.2	$	15.7	$	11.6

Derivative instruments' estimated notional volumes and gain (losses)

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

	2011				2010
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)
Natural Gas	71.8 million Dth	$	(33.4	)	83.2 million Dth	$	(43.8	)
Power	zero MWh	—			234,720 MWh	(0.5		)
Fuel Oil	13.0 million gallons	6.9			8.1 million gallons	(0.5		)
FTRs	23,718 MW	12.5			25,234 MW	19.2
Total		$	(14.0	)		$	(25.6	)

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Asset Sales, Divestitures And Discontinued Operations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Net impacts of the discontinued operations on earnings
Income from Continuing Operations	$ 512.8		$ 454.4		$ 375.7
Income from Discontinued Operations, Net of Tax	13.4		2.1		6.7
Net Income	526.2		456.5		382.4
Asset Sales, Divestitures and Discontinued Operations (Textuals) [Abstract]
Ownership percentage in Edgewater Generating Unit 5 sold	25.00%
Proceeds From Sale Of Interest In Unit	38
Edison Sault [Member]
Net impacts of the discontinued operations on earnings
Income from Discontinued Operations, Net of Tax	0		0.7		1.5
Income Statement Balance Sheet and Additional Disclosures By Disposal Groups Including Discontinued Operations (Textuals) [Abstract]
Proceeds from sale of unit of operations			63.0
Other Operations [Member]
Net impacts of the discontinued operations on earnings
Income from Discontinued Operations, Net of Tax	13.4	[1]	1.4	[1]	4.9	[1]
Water Utility Operations [Member]
Net impacts of the discontinued operations on earnings
Income from Discontinued Operations, Net of Tax	0		0		0.3
Income Statement Balance Sheet and Additional Disclosures By Disposal Groups Including Discontinued Operations (Textuals) [Abstract]
Proceeds from sale of unit of operations					$ 14.5

[1] Primarily relates to the favorable resolution of uncertain state and federal tax positions associated with our previously discontinued manufacturing business.

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Benefits (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Pension Plans [Member]
Change in Benefit Obligation
Benefit Obligation at January 1	$ 1,222.8	$ 1,160.7
Service cost	15.9	23.7	23.3
Interest cost	67.6	68.4	72.3
Participants' contributions	0	0
Plan amendments	0	0
Actuarial loss (gain)	98.0	53.4
Curtailments	0	0
Gross benefits paid	(73.7)	(83.4)
Benefit Obligation at December 31	1,330.6	1,222.8	1,160.7
OPEB [Member]
Change in Benefit Obligation
Benefit Obligation at January 1	368.3	374.7
Service cost	10.4	11.2	8.7
Interest cost	20.8	21.2	20.5
Participants' contributions	11.6	6.5
Plan amendments	0.4	0.3
Actuarial loss (gain)	7.6	(23.8)
Curtailments	0	(1.0)
Gross benefits paid	(30.3)	(21.8)
Federal subsidy on benefits paid	0.9	1.0
Benefit Obligation at December 31	$ 389.7	$ 368.3	$ 374.7

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Consolidated Income Statements (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating Revenues	$ 4,486.4	$ 4,202.5	$ 4,100.9
Operating Expenses
Fuel and purchased power	1,169.7	1,099.9	1,059.7
Cost of gas sold	728.7	751.5	912.0
Other operation and maintenance	1,256.8	1,327.5	1,246.1
Depreciation and amortization	330.2	305.6	343.0
Property and revenue taxes	113.7	106.0	110.5
Total Operating Expenses	3,599.1	3,590.5	3,671.3
Amortization of Gain	0	198.4	230.7
Operating Income	887.3	810.4	660.3
Equity in Earnings of Transmission Affiliate	62.5	60.1	59.1
Other Income and Deductions, net	62.7	40.2	28.5
Interest Expense, net	235.8	206.4	156.7
Income (Loss) from Continuing Operations Before Income Taxes	776.7	704.3	591.2
Income Tax Expense	263.9	249.9	215.5
Income from Continuing Operations	512.8	454.4	375.7
Income from Discontinued Operations, Net of Tax	13.4	2.1	6.7
Net Income	$ 526.2	$ 456.5	$ 382.4
Earnings Per Share (Basic)
Continuing Operations	$ 2.20	$ 1.94	$ 1.61
Discontinued Operations	$ 0.06	$ 0.01	$ 0.03
Total Earnings Per Share (Basic)	$ 2.26	$ 1.95	$ 1.64
Earnings Per Share (Diluted)
Continuing Operations	$ 2.18	$ 1.92	$ 1.59
Discontinued Operations	$ 0.06	$ 0.01	$ 0.03
Total Earnings Per Share (Diluted)	$ 2.24	$ 1.93	$ 1.62
Weighted Average Common Shares Outstanding (Millions)
Basic	232.6	233.8	233.8
Diluted	235.4	236.7	235.9

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Related Parties (Tables)

12 Months Ended

Dec. 31, 2011

Related Parties (Tables) [Abstract]

Provided and received services from the associated companies

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

Equity Investee	2011		2010		2009
	(Millions of Dollars)
Services Provided
–ATC	$	10.8	$	16.9	$	22.3
Services Received
–ATC	$	219.2	$	220.8	$	196.0

Receivable and payable balances with ATC

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

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

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Consolidated Statements of Common Equity (USD $) In Millions, unless otherwise specified	Total	Common Stock [Member]	Other Paid In Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Stock Options Exercisable [Member]
Beginning - Balance at Dec. 31, 2008	$ 3,336.9	$ 2.3	$ 751.2	$ 2,584.2	$ (0.9)	$ 0.1
Net income	382.4			382.4
Other comprehensive income
Hedging, net	0.4				0.4
Comprehensive income	382.8	0	0	382.4	0.4	0
Common stock cash dividends of $0.675, $0.80 and $1.04 per share for Year ended 2009, 2010 and 2011, respectively	(157.8)			(157.8)
Exercise of stock options	17.0		17.0
Purchase of common stock	(29.6)		(29.6)
Tax benefit from share based compensation	6.3		6.3
Stock-based compensation and other	11.3		11.4	0		(0.1)
Ending - Balance at Dec. 31, 2009	3,566.9	2.3	756.3	2,808.8	(0.5)	0
Net income	456.5			456.5
Other comprehensive income
Hedging, net	0.4				0.4
Comprehensive income	456.9	0	0	456.5	0.4	0
Common stock cash dividends of $0.675, $0.80 and $1.04 per share for Year ended 2009, 2010 and 2011, respectively	(187.0)			(187.0)
Exercise of stock options	90.9		90.9
Purchase of common stock	(156.6)		(156.6)
Tax benefit from share based compensation	21.9		21.9
Stock-based compensation and other	9.1		9.1
Ending - Balance at Dec. 31, 2010	3,802.1	2.3	721.6	3,078.3	(0.1)	0
Net income	526.2			526.2
Other comprehensive income
Hedging, net	0.2				0.2
Comprehensive income	526.4	0	0	526.2	0.2	0
Common stock cash dividends of $0.675, $0.80 and $1.04 per share for Year ended 2009, 2010 and 2011, respectively	(242.0)			(242.0)
Exercise of stock options	54.4		54.4
Purchase of common stock	(193.9)		(193.9)
Tax benefit from share based compensation	11.9		11.9
Stock-based compensation and other	4.4		4.4
Ending - Balance at Dec. 31, 2011	$ 3,963.3	$ 2.3	$ 598.4	$ 3,362.5	$ 0.1	$ 0

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Common Equity (Details 1) (USD $) In Millions, except Share data, unless otherwise specified	1 Months Ended	12 Months Ended
	Jan. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Stock option activity
Outstanding, Shares, Beginning Balance	10,638,750.0
Outstanding, Weighted-Average Exercise Price, Beginning	$ 21.65
Granted, shares	938,770.0
Granted, Weighted-Average Exercise Price		$ 3.17	$ 3.36	$ 4.01
Outstanding, Shares, Ending Balance		10,638,750.0
Outstanding, Weighted-Average Exercise Price, Ending		$ 21.65
Outstanding, Weighted-Average Remaining Contractual Life (Years)		5.4
Exercisable, shares		7,534,980.0
Exercisable, Weighted-Average Exercise Price		$ 21.14
Exercisable, Weighted-Average Remaining Contractual Life (Years)		4.5
Stock options [Member]
Stock option activity
Outstanding, Shares, Beginning Balance		13,036,466.0
Outstanding, Weighted-Average Exercise Price, Beginning		$ 20.81
Granted, shares		458,180.0
Granted, Weighted-Average Exercise Price		$ 29.35
Exercised, shares		(2,855,896.0)
Exercised, Weighted-Average Exercise Price		$ 19.07
Forfeited, shares		0.0
Forfeited, Weighted-Average Exercise Price		$ 0.00
Outstanding, Shares, Ending Balance		10,638,750.0
Outstanding, Weighted-Average Exercise Price, Ending		$ 21.65
Outstanding, Weighted-Average Remaining Contractual Life (Years)		5.4
Outstanding, Aggregate Intrinsic Value		$ 141.6
Exercisable, shares		7,534,980.0
Exercisable, Weighted-Average Exercise Price		$ 21.14
Exercisable, Weighted-Average Remaining Contractual Life (Years)		4.5
Exercisable, Aggregate Intrinsic Value		$ 104.1

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligations (Tables) [Abstract]

Change in Asset Retirement Obligations

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

	2011			2010
	(Millions of Dollars)
Balance as of January 1	$	52.6		$	57.9
Liabilities Incurred	0.6			—
Liabilities Settled	(2.2		)	(2.5		)
Accretion	3.0			3.1
Cash Flow Revisions	1.5			(5.9		)
Balance as of December 31	$	55.5		$	52.6

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Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Derivatives Fair Value [Line Items]
Derivative, Asset	$ 20.6	$ 15.7
Derivative, Liability	9.2	11.6
Gains (losses)	(14.0)	(25.6)
Other Deferred Charges and Other Assets [Member]
Derivatives Fair Value [Line Items]
Long-term portion of derivative assets	2.5
Other Long-Term Liabilities [Member]
Derivatives Fair Value [Line Items]
Long-term portion of derivative liabilities	0.7
Power [Member]
Derivatives Fair Value [Line Items]
Volume	zero MWh	234,720 MWh
Gains (losses)	0	(0.5)
FTRs [Member]
Derivatives Fair Value [Line Items]
Derivative, Asset	5.7	5.9
Derivative, Liability	0	0
Volume	23,718 MW	25,234 MW
Gains (losses)	12.5	19.2
Coal [Member]
Derivatives Fair Value [Line Items]
Derivative, Asset	12.5	2.9
Derivative, Liability	0	0
Fuel Oil [Member]
Derivatives Fair Value [Line Items]
Derivative, Asset	0.3	4.4
Derivative, Liability	0.1	0
Volume	13.0 million gallons	8.1 million gallons
Gains (losses)	6.9	(0.5)
Natural Gas [Member]
Derivatives Fair Value [Line Items]
Derivative, Asset	2.1	2.5
Derivative, Liability	9.1	11.6
Volume	71.8 million Dth	83.2 million Dth
Gains (losses)	$ (33.4)	$ (43.8)

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Fair Value Measurements

12 Months Ended

Dec. 31, 2011

Fair Value Measurements [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

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

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

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

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

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

Level 3 -- Pricing inputs include significant inputs that are generally less observable from objective sources. The inputs in the determination of fair value require significant management judgment or estimation. At each balance sheet date, we perform an analysis of all instruments subject to fair value reporting and include in Level 3 all instruments whose fair value is based on significant unobservable inputs.

In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, an instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the instrument.

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

Recurring Fair Value Measures	As of December 31, 2011
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	45.5	$	—	$	—	$	45.5
Derivatives	0.3		14.6		5.7		20.6
Total	$	45.8	$	14.6	$	5.7	$	66.1
Liabilities:
Derivatives	$	8.2	$	1.0	$	—	$	9.2
Total	$	8.2	$	1.0	$	—	$	9.2

Recurring Fair Value Measures	As of December 31, 2010
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	8.3	$	—	$	—	$	8.3
Derivatives	4.5		5.3		5.9		15.7
Total	$	12.8	$	5.3	$	5.9	$	24.0
Liabilities:
Derivatives	$	6.1	$	5.5	$	—	$	11.6
Total	$	6.1	$	5.5	$	—	$	11.6

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

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

	2011			2010
	(Millions of Dollars)
Balance as of January 1	$	5.9		$	5.8
Realized and unrealized gains (losses)	—			—
Purchases and issuances	16.1			17.9
Settlements	(16.3		)	(17.8		)
Transfers in and/or out of Level 3	—			—
Balance as of December 31	$	5.7		$	5.9
Change in unrealized gains (losses) relating to instruments still held as of December 31	$	—		$	—

Derivative instruments reflected in Level 3 of the hierarchy include MISO FTRs that are measured at fair value each reporting period using monthly or annual auction shadow prices from relevant auctions. Changes in fair value for Level 3 recurring items are recorded on our balance sheet. See Note L -- Derivative Instruments, for further information on the offset to regulatory assets and liabilities.

The carrying amount and estimated fair value of certain of our recorded financial instruments as of December 31 are as follows:

	2011				2010
	Carrying		Fair		Carrying		Fair
Financial Instruments	Amount		Value		Amount		Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	25.1	$	30.4	$	23.5
Long-term debt including current portion	$	4,541.4	$	5,179.9	$	4,288.0	$	4,578.0

The carrying value of net accounts receivable, accounts payable and short-term borrowings approximates fair value due to the short-term nature of these instruments. The fair value of our preferred stock is estimated based upon the quoted market value for the same or similar issues. The fair value of our long-term debt, including the current portion of long-term debt, but excluding capitalized leases and unamortized discount on debt, is estimated based upon quoted market value for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Income Taxes (Tables) [Abstract]

Summary of income tax expense

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

Income Taxes	2011			2010			2009
	(Millions of Dollars)
Current tax expense (benefit)	$	(166.7	)	$	144.9		$	28.1
Deferred income taxes, net	434.8			108.6			191.2
Investment tax credit, net	(4.2		)	(3.6		)	(3.8		)
Total Income Tax Expense	$	263.9		$	249.9		$	215.5

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

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

	2011					2010					2009
				Effective					Effective					Effective
Income Tax Expense	Amount			Tax Rate		Amount			Tax Rate		Amount			Tax Rate
	(Millions of Dollars)
Expected tax at statutory federal tax rates	$	271.8		35.0	%	$	246.5		35.0	%	$	206.9		35.0	%
State income taxes net of federal tax benefit	40.1			5.2	%	35.8			5.1	%	31.8			5.4	%
AFUDC - Equity	(20.8		)	(2.7	)%	(11.4		)	(1.6	)%	(5.6		)	(0.9	)%
Domestic production activities deduction	(12.6		)	(1.6	)%	(12.6		)	(1.8	)%	(8.3		)	(1.4	)%
Production tax credits - wind	(8.7		)	(1.1	)%	(7.2		)	(1.0	)%	(7.1		)	(1.2	)%
Investment tax credit restored	(4.2		)	(0.5	)%	(3.6		)	(0.5	)%	(3.8		)	(0.6	)%
Other, net	(1.7		)	(0.3	)%	2.4			0.3	%	1.6			0.2	%
Total Income Tax Expense	$	263.9		34.0	%	$	249.9		35.5	%	$	215.5		36.5	%

Components of deferred income taxes classified as net current assets and net long-term liabilities

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

Deferred Tax Assets	2011		2010
	(Millions of Dollars)
Current
Employee benefits and compensation	$	14.6	$	14.3
Other	57.1		33.5
Total Current Deferred Tax Assets	71.7		47.8
Non-current
Future federal tax benefits	328.5		—
Deferred revenues	279.7		305.9
Employee benefits and compensation	103.6		110.2
Property-related	28.3		30.3
Construction advances	25.4		118.3
Emission allowances	1.0		2.6
Other	34.0		30.8
Total Non-Current Deferred Tax Assets	800.5		598.1
Total Deferred Tax Assets	$	872.2	$	645.9

Deferred Tax Liabilities	2011		2010
	(Millions of Dollars)
Current
Prepaid items	$	50.1	$	46.9
Total Current Deferred Tax Liabilities	50.1		46.9
Non-current
Property-related	2,020.7		1,346.8
Employee benefits and compensation	232.8		179.5
Investment in transmission affiliate	129.2		112.4
Deferred transmission costs	47.4		53.1
Other	66.5		61.1
Total Non-current Deferred Tax Liabilities	2,496.6		1,752.9
Total Deferred Tax Liabilities	$	2,546.7	$	1,799.8
Consolidated Balance Sheet Presentation	2011		2010
Current Deferred Tax Asset	$	21.6	$	0.9
Non-Current Deferred Tax Liability	$	1,696.1	$	1,154.8

Reconciliation of the beginning and ending amount of unrecognized tax benefits

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

	2011			2010
	(Millions of Dollars)
Balance as of January 1	$	29.5		$	35.4
Additions based on tax positions related to the current year	—			0.8
Additions for tax positions of prior years	—			10.4
Reductions for tax positions of prior years	(13.9		)	(2.5		)
Reductions due to statute of limitations	(2.5		)	(0.3		)
Settlements during the period	(2.0		)	(14.3		)
Balance as of December 31	$	11.1		$	29.5

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Guarantees

12 Months Ended

Dec. 31, 2011

Guarantees [Abstract]

GUARANTEES

GUARANTEES

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

	Maximum Potential		Liability
	Future Payments	Outstanding	Recorded
	(Millions of Dollars)
Guarantees	$2.7	$0.1	$—
Letters of Credit	$1.6	$0.1	$—

We provide guarantees to support obligations of our affiliates to third parties under agreements and surety bonds. In the event our affiliates fail to perform, we would be responsible for the obligations.

Wisconsin Electric is subject to the potential retrospective premiums that could be assessed under its insurance program.

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Derivative Instruments (Details 3) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
DERIVATIVE INSTRUMENTS [Abstract]
Collateral in margin accounts	$ 11.9	$ 11.7
Reclassification in treasury lock agreement settlement payments deferred in Accumulated Other Comprehensive Income as increase to interest Expense	0.2	0.4	0.4
Reclassification from Accumulated Other Comprehensive Income as a reduction in earnings	$ 0.1

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Consolidated Statements of Common Equity (Parenthetical) (Retained Earnings [Member], USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Retained Earnings [Member]
Common stock cash dividends per share	$ 1.04	$ 0.80	$ 0.675

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Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Dec. 31, 2011		Dec. 31, 2010
Property, Plant and Equipment
In service	$ 12,977.7		$ 11,590.8
Accumulated depreciation	(3,797.8)		(3,624.0)
In service, net	9,179.9		7,966.8
Construction work in progress	921.3		1,569.9
Leased facilities, net	59.2		64.8
Net Property, Plant and Equipment	10,160.4		9,601.5
Investments
Equity investment in transmission affiliate	349.7		330.5
Other	43.6		45.8
Total Investments	393.3		376.3
Current Assets
Cash and cash equivalents	14.1		24.5
Restricted cash	45.5		8.3
Accounts receivable, net of allowance for doubtful accounts of $61.7 and $58.1	349.4		344.6
Income taxes receivable	155.1		83.7
Accrued revenues	252.7		280.3
Materials, supplies and inventories	382.0		379.1
Prepayments	140.3		125.6
Other	87.1		85.0
Total Current Assets	1,426.2		1,331.1
Deferred Charges and Other Assets
Regulatory assets	1,238.7		1,090.1
Goodwill	441.9		441.9
Other	201.6		218.9
Total Deferred Charges and Other Assets	1,882.2		1,750.9
Total Assets	13,862.1	[1]	13,059.8	[1]
Capitalization
Common equity	3,963.3		3,802.1
Preferred stock of subsidiary	30.4		30.4
Long-term debt	4,614.3		3,932.0
Total Capitalization	8,608.0		7,764.5
Current Liabilities
Long-term debt due currently	32.6		473.4
Short-term debt	669.9		657.9
Accounts payable	325.7		315.4
Accrued payroll and vacation	105.9		88.3
Other	230.4		186.1
Total Current Liabilities	1,364.5		1,721.1
Deferred Credits and Other Liabilities
Regulatory liabilities	902.0		883.8
Deferred income taxes - long-term	1,696.1		1,154.8
Deferred revenue, net	754.5		805.5
Pension and other benefit obligations	222.7		353.2
Other long-term liabilities	314.3		376.9
Total Deferred Credits and Other Liabilities	3,889.6		3,574.2
Commitments and Contingencies (Note R)
Total Capitalization and Liabilities	$ 13,862.1		$ 13,059.8

[1] An elimination of $2,369.0 million, $1,785.9 million and $889.1 million is included in Total Assets as of December 31, 2011, 2010 and 2009, respectively, for all PTF-related activity between We Power and Wisconsin Electric.

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Income Taxes

12 Months Ended

Dec. 31, 2011

Income Tax Expense (Benefit) [Abstract]

INCOME TAXES

INCOME TAXES

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

Income Taxes	2011			2010			2009
	(Millions of Dollars)
Current tax expense (benefit)	$	(166.7	)	$	144.9		$	28.1
Deferred income taxes, net	434.8			108.6			191.2
Investment tax credit, net	(4.2		)	(3.6		)	(3.8		)
Total Income Tax Expense	$	263.9		$	249.9		$	215.5

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

	2011					2010					2009
				Effective					Effective					Effective
Income Tax Expense	Amount			Tax Rate		Amount			Tax Rate		Amount			Tax Rate
	(Millions of Dollars)
Expected tax at statutory federal tax rates	$	271.8		35.0	%	$	246.5		35.0	%	$	206.9		35.0	%
State income taxes net of federal tax benefit	40.1			5.2	%	35.8			5.1	%	31.8			5.4	%
AFUDC - Equity	(20.8		)	(2.7	)%	(11.4		)	(1.6	)%	(5.6		)	(0.9	)%
Domestic production activities deduction	(12.6		)	(1.6	)%	(12.6		)	(1.8	)%	(8.3		)	(1.4	)%
Production tax credits - wind	(8.7		)	(1.1	)%	(7.2		)	(1.0	)%	(7.1		)	(1.2	)%
Investment tax credit restored	(4.2		)	(0.5	)%	(3.6		)	(0.5	)%	(3.8		)	(0.6	)%
Other, net	(1.7		)	(0.3	)%	2.4			0.3	%	1.6			0.2	%
Total Income Tax Expense	$	263.9		34.0	%	$	249.9		35.5	%	$	215.5		36.5	%

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

Deferred Tax Assets	2011		2010
	(Millions of Dollars)
Current
Employee benefits and compensation	$	14.6	$	14.3
Other	57.1		33.5
Total Current Deferred Tax Assets	71.7		47.8
Non-current
Future federal tax benefits	328.5		—
Deferred revenues	279.7		305.9
Employee benefits and compensation	103.6		110.2
Property-related	28.3		30.3
Construction advances	25.4		118.3
Emission allowances	1.0		2.6
Other	34.0		30.8
Total Non-Current Deferred Tax Assets	800.5		598.1
Total Deferred Tax Assets	$	872.2	$	645.9

Deferred Tax Liabilities	2011		2010
	(Millions of Dollars)
Current
Prepaid items	$	50.1	$	46.9
Total Current Deferred Tax Liabilities	50.1		46.9
Non-current
Property-related	2,020.7		1,346.8
Employee benefits and compensation	232.8		179.5
Investment in transmission affiliate	129.2		112.4
Deferred transmission costs	47.4		53.1
Other	66.5		61.1
Total Non-current Deferred Tax Liabilities	2,496.6		1,752.9
Total Deferred Tax Liabilities	$	2,546.7	$	1,799.8
Consolidated Balance Sheet Presentation	2011		2010
Current Deferred Tax Asset	$	21.6	$	0.9
Non-Current Deferred Tax Liability	$	1,696.1	$	1,154.8

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

As of December 31, 2011, we had approximately $867.1 million and $25.0 million of net operating loss and tax credit carryforwards, respectively. The net operating loss and tax credit carryforwards resulted in deferred tax assets of $303.5 million and $25.0 million, respectively, as of December 31, 2011. The tax credit and net operating loss carryforwards begin to expire in 2029 and 2030, respectively. We anticipate that we will have future taxable income sufficient to utilize these deferred tax assets.

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

	2011			2010
	(Millions of Dollars)
Balance as of January 1	$	29.5		$	35.4
Additions based on tax positions related to the current year	—			0.8
Additions for tax positions of prior years	—			10.4
Reductions for tax positions of prior years	(13.9		)	(2.5		)
Reductions due to statute of limitations	(2.5		)	(0.3		)
Settlements during the period	(2.0		)	(14.3		)
Balance as of December 31	$	11.1		$	29.5

The amount of unrecognized tax benefits as of December 31, 2011 and 2010 excludes deferred tax assets related to uncertainty in income taxes of $11.0 million and $16.9 million, respectively. As of December 31, 2011 and 2010, the net amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was approximately $0.1 million and $2.3 million, respectively.

We recognize interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense. For the years ended December 31, 2011, 2010 and 2009, we recognized approximately $0.7 million, $4.1 million and $2.0 million, respectively, of accrued interest in the Consolidated Income Statements. For the year ended December 31, 2011, we recognized a benefit of $0.3 million in the Consolidated Income Statements related to a reduction of accrued penalties. For the years ended December 31, 2010 and 2009, we recognized no penalties in the Consolidated Income Statements. We had approximately $2.0 million and $8.2 million of interest accrued and zero and approximately $0.3 million of penalties accrued on the Consolidated Balance Sheets as of December 31, 2011 and 2010, respectively.

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

Our primary tax jurisdictions include Federal and the state of Wisconsin. Currently, the tax years of 2007 through 2011 are subject to Federal and Wisconsin examination.

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Document and Entity Information (USD $) In Billions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Jan. 31, 2012	Jun. 30, 2011
Document and Entity Information [Abstract]
Entity Registrant Name	WISCONSIN ENERGY CORP
Entity Central Index Key	0000783325
Document Type	10-K
Document Period End Date	Dec. 31, 2011
Amendment Flag	false
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 7.3
Entity Common Stock, Shares Outstanding (actual number of shares)		230,461,537

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Common Equity

12 Months Ended

Dec. 31, 2011

Stockholders' Equity Note [Abstract]

COMMON EQUITY

COMMON EQUITY

As of December 31, 2011 and 2010, we had 325,000,000 shares of common stock authorized under our charter, of which 230,486,804 and 233,771,194 common shares, respectively, were outstanding. All share-based compensation is currently fulfilled by purchases on the open market by our independent agents and do not dilute shareholders' ownership.

Share-Based Compensation Plans:   We have a plan that was approved by stockholders that enables us to provide a long-term incentive through equity interests in Wisconsin Energy to outside directors, selected officers and key employees of the Company. The plan provides for the granting of stock options, stock appreciation rights, restricted stock awards and performance shares. Awards may be paid in common stock, cash or a combination thereof. We utilize the straight-line attribution method for recognizing share-based compensation expense. Accordingly, for employee awards, equity classified share-based compensation cost is measured at the grant date based on the fair value of the award, and is recognized as expense over the requisite service period. There were no modifications to the terms of outstanding stock options during the period other than necessary adjustments as a result of our stock split.

The following table summarizes recorded pre-tax share-based compensation expense and the related tax benefit for share-based awards made to our employees and directors as of December 31:

	2011		2010		2009
	(Millions of Dollars)
Performance units	$	24.1	$	26.0	$	14.0
Stock options	2.6		7.6		10.8
Restricted stock	1.8		1.5		1.0
Share-based compensation expense	$	28.5	$	35.1	$	25.8
Related Tax Benefit	$	11.4	$	14.1	$	10.3

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

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

The following is a summary of our stock option activity during 2011:

Stock Options	Number of Options		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life (Years)	Aggregate Intrinsic Value (Millions)
Outstanding as of January 1, 2011	13,036,466		$	20.81
Granted	458,180		$	29.35
Exercised	(2,855,896	)	$	19.07
Forfeited	—		$	—
Outstanding as of December 31, 2011	10,638,750		$	21.65	5.4	$	141.6
Exercisable as of December 31, 2011	7,534,980		$	21.14	4.5	$	104.1

In January 2012, the Compensation Committee awarded 938,770 non-qualified stock options with an exercise price of $34.88 to our officers and key executives under its normal schedule of awarding long-term incentive compensation.

The intrinsic value of options exercised during the years ended December 31, 2011, 2010 and 2009 was $36.1 million, $62.1 million and $12.0 million, respectively. Cash received from options exercised during the years ended December 31, 2011, 2010 and 2009 was $54.4 million, $90.9 million and $17.0 million, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $14.3 million, $24.1 million and $4.8 million, respectively.

The following table summarizes information about stock options outstanding as of December 31, 2011:

	Options Outstanding				Options Exercisable
		Weighted-Average				Weighted-Average
Range of Exercise Prices	Number of Options	Exercise Price		Remaining Contractual Life (Years)	Number of Options	Exercise Price		Remaining Contractual Life (Years)
$11.52  to  $17.10	1,972,594	$	16.07	2.3	1,972,594	$	16.07	2.3
$19.74  to  $21.11	3,586,456	$	20.62	5.9	1,420,186	$	19.88	4.3
$23.88  to  $29.35	5,079,700	$	24.54	6.2	4,142,200	$	23.99	5.6
	10,638,750	$	21.65	5.4	7,534,980	$	21.14	4.5

The following table summarizes information about our non-vested options during 2011:

Non-Vested Stock Options	Number of Options		Weighted- Average Fair Value
Non-Vested as of January 1, 2011	5,272,570		$	4.27
Granted	458,180		$	3.17
Vested	(2,626,980	)	$	4.64
Forfeited	—		$	—
Non-Vested as of December 31, 2011	3,103,770		$	3.78

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

Restricted Shares:   The Compensation Committee has also approved restricted stock grants to certain key employees and directors. The following restricted stock activity occurred during 2011:

Restricted Shares	Number of Shares		Weighted-Average Market Price
Outstanding as of January 1, 2011	205,404
Granted	74,850		$	29.00
Released	(83,452	)	$	18.82
Forfeited	(4,244	)	$	26.62
Outstanding as of December 31, 2011	192,558

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

In January 2012, the Compensation Committee awarded 94,959 restricted shares to our directors, officers and other key employees under its normal schedule of awarding long-term incentive compensation. These awards have a three-year vesting period, and generally, one-third of the award vests on each anniversary of the grant date. During the vesting period, restricted share recipients also have voting rights and are entitled to dividends in the same manner as other shareholders.

We record the market value of the restricted stock awards on the date of grant and then we charge their value to expense over the vesting period of the awards. The intrinsic value of restricted stock vesting was $2.5 million, $2.3 million and $0.9 million for the years ended December 31, 2011, 2010, and 2009, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same years was $0.8 million, $0.7 million and $0.3 million, respectively.

As of December 31, 2011, total compensation cost related to restricted stock not yet recognized was approximately $2.4 million, which is expected to be recognized over the next 20 months on a weighted-average basis.

Performance Units:   In January 2011, 2010 and 2009, the Compensation Committee awarded 435,690, 555,830 and 666,440 performance units, respectively, to officers and other key employees under the Wisconsin Energy Performance Unit Plan. Under the grants, the ultimate number of units that will be awarded is dependent upon the achievement of certain financial performance of our stock over a three-year period. Under the terms of the award, participants may earn between 0% and 175% of the base performance unit award. All grants are settled in cash. We are accruing compensation costs over the three-year performance period based on our estimate of the final expected value of the awards. Performance units earned as of December 31, 2011, 2010 and 2009 vested and were settled during the first quarter of 2012, 2011 and 2010 and had a total intrinsic value of $26.7 million, $12.6 million and $9.8 million, respectively. The actual tax benefit realized for the tax deductions from the distribution of performance units was approximately $9.7 million, $4.3 million and $3.4 million, respectively.

In January 2012, the Compensation Committee awarded 346,570 performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.

As of December 31, 2011, total compensation cost related to performance units not yet recognized was approximately $18.3 million, which is expected to be recognized over the next 19 months on a weighted-average basis.

Restrictions:Wisconsin Energy's ability as a holding company to pay common dividends primarily depends on the availability of funds received from its non-utility subsidiary, We Power, and its utility subsidiaries.

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

The January 2010 PSCW rate case order requires Wisconsin Electric and Wisconsin Gas to maintain capital structures that differ from GAAP as they reflect regulatory adjustments. Wisconsin Electric is required to maintain a common equity ratio range of between 48.5% and 53.5%, and Wisconsin Gas is required to maintain a capital structure which has a common equity range of between 45.0% and 50.0%. Wisconsin Electric and Wisconsin Gas must obtain PSCW approval if they pay dividends above the test year levels that would cause either company to fall below the authorized levels of common equity.

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

We have the option to defer interest payments on the Junior Notes, from time to time, for one or more periods of up to 10 consecutive years per period. During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.

As of December 31, 2011, the restricted net assets of consolidated and unconsolidated subsidiaries and our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method total approximately $3.5 billion. This amount exceeds 25% of our consolidated net assets as of December 31, 2011.

See Note K for discussion of certain financial covenants related to the bank back-up credit facilities of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas.

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

Common Stock Activity:  We do not expect to issue new shares under our various employee benefit plans and our dividend reinvestment and share purchase plan; rather, we instruct independent plan agents to purchase the shares in the open market. In that regard, no new shares of common stock were issued in 2011, 2010 or 2009.

During 2011, 2010 and 2009, our plan agents purchased 3.0 million shares at a cost of $93.9 million, 5.8 million shares at a cost of $156.6 million and 1.4 million shares at a cost of $29.6 million, respectively, to fulfill exercised stock options and restricted stock awards. In 2011, 2010 and 2009, we received proceeds of $54.4 million, $90.9 million and $17.0 million, respectively, related to the exercise of stock options.

In addition, on May 5, 2011, our Board of Directors authorized a share repurchase program for up to $300 million of our common stock through the end of 2013. The repurchase program does not obligate Wisconsin Energy to acquire any specific number of shares and may be suspended or terminated by the Board of Directors at any time. Through December 31, 2011, we repurchased approximately 3.2 million shares pursuant to this program at an average cost of $30.79 per share and a total cost of $100.0 million.

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Condensed Parent Company Financial Statements (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Condensed Parent Company Income Statement
Other Income, Net	$ 62.7	$ 40.2	$ 28.5
Interest Expense, net	235.8	206.4	156.7
Income (Loss) from Continuing Operations Before Income Taxes	776.7	704.3	591.2
Income Tax Benefit	(263.9)	(249.9)	(215.5)
Income from Continuing Operations	512.8	454.4	375.7
Income from Discontinued Operations, Net of Tax	13.4	2.1	6.7
Net Income	526.2	456.5	382.4
Subsidiaries [Member]
Condensed Parent Company Income Statement
Income from Continuing Operations	545.9	482.1	395.9
Income from Discontinued Operations, Net of Tax	13.4	2.1	6.7
Wisconsin Energy Corporation [Member]
Condensed Parent Company Income Statement
Other Income, Net	2.7	4.2	24.2
Corporate Expense	4.8	4.0	8.9
Interest Expense, net	61.8	53.8	50.2
Income (Loss) from Continuing Operations Before Income Taxes	(63.9)	(53.6)	(34.9)
Income Tax Benefit	30.8	25.9	14.7
Income from Continuing Operations	(33.1)	(27.7)	(20.2)
Net Income	$ 526.2	$ 456.5	$ 382.4

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Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Current Assets
Allowance on accounts receivable	$ 61.7	$ 58.1

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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2011

Regulatory Assets and Liabilities Disclosure [Abstract]

REGULATORY ASSETS AND LIABILITIES

REGULATORY ASSETS AND LIABILITIES

Our primary regulator, the PSCW, considers our regulatory assets and liabilities in two categories, escrowed and deferred. In escrow accounting we expense amounts that are included in rates. If actual costs exceed or are less than the amounts that are allowed in rates, the difference in cost is escrowed on the balance sheet as a regulatory asset or regulatory liability and the escrowed balance is considered in setting future rates. Under deferred cost accounting, we defer amounts to our balance sheet based upon orders or correspondence with our regulators. These deferred costs will be considered in future rate setting proceedings. As of December 31, 2011 and 2010, we had approximately $11.0 million and $16.5 million, respectively, of net regulatory assets that were not earning a return. These regulatory assets are expected to be recovered from customers over a period of one to five years.

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

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

	2011		2010
	(Millions of Dollars)
Regulatory Assets
Deferred unrecognized pension costs	$	647.8	$	542.6
Deferred income tax related	121.2		89.9
Escrowed electric transmission costs	118.3		138.0
Deferred unrecognized OPEB costs	102.9		85.7
Deferred plant related -- capital lease	73.2		77.1
Deferred environmental costs	48.5		56.7
Other, net	153.8		154.5
Total regulatory assets	$	1,265.7	$	1,144.5
Regulatory Liabilities
Deferred cost of removal obligations	$	728.2	$	723.9
Escrowed bad debt costs	69.0		18.5
Other, net	118.7		156.7
Total regulatory liabilities	$	915.9	$	899.1

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

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Recent Accounting Pronouncements

12 Months Ended

Dec. 31, 2011

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

RECENT ACCOUNTING PRONOUNCEMENTS

RECENT ACCOUNTING PRONOUNCEMENTS

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

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

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Benefits

12 Months Ended

Dec. 31, 2011

General Discussion of Pension and Other Postretirement Benefits [Abstract]

BENEFITS

BENEFITS

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

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

We use a year-end measurement date to measure the funded status of all of our pension and OPEB plans. Due to the regulated nature of our business, we have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of our pension and OPEB plans qualify as a regulatory asset.

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

	Pension						OPEB
	2011			2010			2011			2010
	(Millions of Dollars)
Change in Benefit Obligation
Benefit Obligation at January 1	$	1,222.8		$	1,160.7		$	368.3		$	374.7
Service cost	15.9			23.7			10.4			11.2
Interest cost	67.6			68.4			20.8			21.2
Participants' contributions	—			—			11.6			6.5
Plan amendments	—			—			0.4			0.3
Actuarial loss (gain)	98.0			53.4			7.6			(23.8		)
Curtailments	—			—			—			(1.0		)
Gross benefits paid	(73.7		)	(83.4		)	(30.3		)	(21.8		)
Federal subsidy on benefits paid	N/A			N/A			0.9			1.0
Benefit Obligation at December 31	$	1,330.6		$	1,222.8		$	389.7		$	368.3
Change in Plan Assets
Fair Value at January 1	$	1,059.5		$	1,026.0		$	216.7		$	202.6
Actual earnings on plan assets	33.8			110.1			9.0			24.5
Employer contributions	242.9			6.8			48.4			4.9
Participants' contributions	—			—			11.6			6.5
Gross benefits paid	(73.7		)	(83.4		)	(30.3		)	(21.8		)
Fair Value at December 31	$	1,262.5		$	1,059.5		$	255.4		$	216.7
Net Liability	$	68.1		$	163.3		$	134.3		$	151.6

As of December 31, 2011, our qualified pension plans were over-funded by $24.4 million and our non-qualified pension plans were under-funded by $92.5 million. As of December 31, 2010, our qualified and non-qualified pension plans were under-funded by $71.7 million and $91.6 million, respectively.

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

	Pension				OPEB
	2011		2010		2011		2010
	(Millions of Dollars)
Other deferred charges	$	—	$	—	$	20.3	$	38.3
Other long-term liabilities	68.1		163.3		154.6		189.9
Net liability	$	68.1	$	163.3	$	134.3	$	151.6

The accumulated benefit obligation for all defined benefit plans was $1,329.4 million and $1,222.5 million as of December 31, 2011 and 2010, respectively.

The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31 and are recorded as a regulatory asset on our balance sheet:

	Pension				OPEB
	2011		2010		2011			2010
	(Millions of Dollars)
Net actuarial loss	$	633.4	$	521.0	$	108.1		$	98.9
Prior service costs (credits)	14.4		16.7		(6.1		)	(8.5		)
Transition obligation	—		—		0.3			0.6
Total	$	647.8	$	537.7	$	102.3		$	91.0

We estimate that 2012 periodic pension and OPEB costs will include the amortization of previously unrecognized benefit costs referred to above of $43.9 million and $5.5 million, respectively.

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

	Pension									OPEB
	2011			2010			2009			2011			2010			2009
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	15.9		$	23.7		$	23.3		$	10.4		$	11.2		$	8.7
Interest cost	67.6			68.4			72.3			20.8			21.2			20.5
Expected return on plan assets	(82.1		)	(78.2		)	(95.4		)	(16.9		)	(14.3		)	(13.6		)
Amortization of:
Transition obligation	—			—			—			0.3			0.3			0.3
Prior service cost (credit)	2.2			2.2			2.2			(1.9		)	(11.9		)	(12.6		)
Actuarial loss	34.0			26.8			18.9			6.2			10.8			8.9
Curtailment (gain)	—			—			—			—			(0.4		)	—
Net Periodic Benefit Cost	$	37.6		$	42.9		$	21.3		$	18.9		$	16.9		$	12.2

In addition to the costs above, in 2011 we recorded net pension costs of less than $0.04 per share related to the settlement of pension litigation. See Note R -- Commitments and Contingencies in this report. The charges were after considering insurance and reserves established in the prior year.

	Pension			OPEB
	2011	2010	2009	2011	2010	2009
Weighted-Average assumptions used to
determine benefit obligations as of Dec. 31
Discount rate	5.05%	5.60%	6.05%	5.20%	5.70%	5.75%
Rate of compensation increase	4.0%	4.0%	4.0%	N/A	N/A	N/A
Weighted-Average assumptions used to
determine net cost for year ended Dec. 31
Discount rate	5.60%	6.05%	6.50%	5.70%	5.75%	6.50%
Expected return on plan assets	7.25%	7.25%	8.25%	7.50%	7.50%	8.25%
Rate of compensation increase	4.0%	4.0%	4.0%	N/A	N/A	N/A

Assumed health care cost trend rates as of Dec. 31	2011	2010	2009
Health care cost trend rate assumed for next year (Pre 65 / Post 65)	8.0%/12%	7.5%/16%	7.5%/20%
Rate that the cost trend rate gradually adjusts to	5.0%	5.0%	5.0%
Year that the rate reaches the rate it is assumed to remain at (Pre 65 / Post 65)	2017/2017	2015/2016	2015/2016

The expected long-term rate of return on pension and OPEB plan assets was 7.25% and 7.50%, respectively, in 2011 and 2010. The expected long-term rate of return for all plan assets was 8.25% in 2009. We consult with our investment advisors on an annual basis to help us forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund.

A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	1% Increase		1% Decrease
	(Millions of Dollars)
Effect on
Post-retirement benefit obligation	$	31.9	$	(26.8	)
Total of service and interest cost components	$	3.8	$	(3.1	)

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

Plan Assets:   Current pension trust assets and amounts which are expected to be contributed to the trusts in the future are expected to be adequate to meet pension payment obligations to current and future retirees.

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

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

The following table summarizes the fair value of our pension plan assets by asset category within the fair value hierarchy (for further level information, see Note M):

	As of December 31, 2011
Asset Category - Pension	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	8.5	$	—	$	—	$	8.5
Equities:
U.S. Equity	455.1		—		—		455.1
International Equity	100.4		33.9		—		134.3
Fixed Income
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	76.9		502.8		—		579.7
International Bonds	40.9		44.0		—		84.9
Total	$	681.8	$	580.7	$	—	$	1,262.5

	As of December 31, 2010
Asset Category - Pension	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	21.1	$	—	$	—	$	21.1
Equities:
U.S. Equity	217.2		247.5		—		464.7
International Equity	81.1		21.6		—		102.7
Fixed Income
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	49.7		361.5		—		411.2
International Bonds	31.8		28.0		—		59.8
Total	$	400.9	$	658.6	$	—	$	1,059.5

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

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

	As of December 31, 2011
Asset Category - OPEB	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	2.4	$	—	$	—	$	2.4
Equities:
U.S. Equity	113.6		—		—		113.6
International Equity	32.1		2.3		—		34.4
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	8.2		83.0		—		91.2
International Bonds	8.7		5.1		—		13.8
Total	$	165.0	$	90.4	$	—	$	255.4

	As of December 31, 2010
Asset Category - OPEB	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Cash and Cash Equivalents	$	1.5	$	—	$	—	$	1.5
Equities:
U.S. Equity	41.6		80.1		—		121.7
International Equity	5.2		1.4		—		6.6
Fixed Income:
Short, Intermediate and Long-term Bonds (a)
U.S. Bonds	21.8		59.4		—		81.2
International Bonds	2.0		3.7		—		5.7
Total	$	72.1	$	144.6	—		$	216.7

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

Cash Flows:   

Employer	Pension
Contributions	Qualified		Non-Qualified		OPEB
	(Millions of Dollars)
2009	$	270.0	$	5.8	$	24.3
2010	$	—	$	6.8	$	4.9
2011	$	236.4	$	6.5	$	48.4

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

Year	Pension		Gross OPEB		Expected Medicare Part D Subsidy
	(Millions of Dollars)
2012	$	110.1	$	20.2	$	(0.9	)
2013	$	101.3	$	20.8	$	—
2014	$	104.4	$	22.2	$	—
2015	$	103.6	$	23.5	$	—
2016	$	103.9	$	24.7	$	—
2017-2021	$	535.2	$	136.4	$	—

Savings Plans:   We sponsor savings plans which allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. Under these plans, we expensed matching contributions of $14.1 million, $13.8 million and $14.1 million during 2011, 2010 and 2009, respectively.

Postemployment Benefits:   Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $15.3 million as of December 31, 2011.

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Long-Term Debt and Capital Lease Obligations

12 Months Ended

Dec. 31, 2011

Long-term Debt and Capital Lease Obligations [Abstract]

LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

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

	(Millions of Dollars)
2012	$	20.3
2013	396.3
2014	322.4
2015	399.5
2016	27.4
Thereafter	3,375.5
Total	$	4,541.4

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

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

On April 1, 2011, we used cash and short-term borrowings to retire $450 million of long-term debt that matured.

In January 2011, we issued a total of $420 million in long-term debt ($205 million aggregate principal amount of 4.673% Series B Senior Notes due January 19, 2031 and $215 million aggregate principal amount of 5.848% Series B Senior Notes due January 19, 2041) and used the net proceeds to repay short-term debt incurred to finance the construction of OC 2 and for other corporate purposes. The Series B Senior Notes are secured by a collateral assignment of the leases between Elm Road Generating Station Supercritical, LLC (ERGSS) and Wisconsin Electric related to OC 2.

In February 2010, we issued a total of $530 million in long-term debt ($255 million aggregate principal amount of 5.209% Series A Senior Notes due February 11, 2030 and $275 million aggregate principal amount of 6.09% Series A Senior Notes due February 11, 2040) and used the net proceeds to repay debt incurred to finance the construction of OC 1. The Series A Senior Notes are secured by a collateral assignment of the leases between ERGSS and Wisconsin Electric related to OC 1.

During 2010, we retired $281.5 million of unsecured notes through the issuance of long-term and short-term debt.

During 2009, we issued $261.5 million of long-term debt, including $250 million of debentures under an existing shelf registration statement filed by Wisconsin Electric with the SEC in August 2007. The net proceeds were used to repay short-term debt and for other general corporate purposes.

Wisconsin Electric is the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amount of $147 million. In August 2009, Wisconsin Electric terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. Wisconsin Electric purchased the bonds at par plus accrued interest to the date of purchase. As of December 31, 2011 and 2010, the repurchased bonds were still outstanding, but were reported as a reduction in our consolidated long-term debt because they are held by Wisconsin Electric. Depending on market conditions and other factors, Wisconsin Electric may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.

In connection with our outstanding Junior Notes, we executed the RCC for the benefit of persons that buy, hold or sell a specified series of long-term indebtedness (covered debt). Our 6.20% Senior Notes due April 1, 2033 have been designated as the covered debt under the RCC. The RCC provides that we may not redeem, defease or purchase and our subsidiaries may not purchase any Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, during the 180 days prior to the date of redemption, defeasance or purchase, we have received a specified amount of proceeds from the sale of qualifying securities.

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

We treat the long-term power purchase contract as an operating lease for rate-making purposes and we record our minimum lease payments as purchased power expense on the Consolidated Income Statements. We paid a total of $31.3 million and $30.2 million in lease payments during 2011 and 2010, respectively. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on our Consolidated Balance Sheets (see Regulatory Assets - Deferred plant related -- capital lease in Note C). Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to approximately $78.5 million during 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the capital lease was $132.4 million as of December 31, 2011, and will decrease to zero over the remaining life of the contract.

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

Capital Lease Assets	2011			2010
	(Millions of Dollars)
Leased Facilities
Long-term power purchase commitment	$	140.3		$	140.3
Accumulated amortization	(81.1		)	(75.5		)
Total Leased Facilities	$	59.2		$	64.8

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

	(Millions of Dollars)
2012	$	38.9
2013	40.4
2014	41.9
2015	43.5
2016	45.1
Thereafter	85.4
Total Minimum Lease Payments	295.2
Less:  Estimated Executory Costs	(74.9		)
Net Minimum Lease Payments	220.3
Less:  Interest	(87.9		)
Present Value of Net
Minimum Lease Payments	132.4
Less:  Due Currently	(12.4		)
	$	120.0

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Condensed Parent Company Financial Statements (Details 4) (USD $)	Dec. 31, 2011
Various guarantees to provide financial and performance assurance to third parties on behalf of affiliates
Guarantees, Maximum Potential Future Payments	$ 2,700,000
Guarantees, Outstanding	100,000
Liability	0
Wisconsin Energy Corporation [Member]
Various guarantees to provide financial and performance assurance to third parties on behalf of affiliates
Guarantees, Maximum Potential Future Payments	68,300,000
Guarantees, Outstanding	9,900,000
Liability	0
Letters of Credit [Member] | Wisconsin Energy Corporation [Member]
Various guarantees to provide financial and performance assurance to third parties on behalf of affiliates
Guarantees, Maximum Potential Future Payments	400,000
Guarantees, Outstanding	400,000
Liability	0
Utility Energy [Member] | Wisconsin Energy Corporation [Member]
Various guarantees to provide financial and performance assurance to third parties on behalf of affiliates
Guarantees, Maximum Potential Future Payments	9,900,000
Guarantees, Outstanding	9,900,000
Liability	0
Non-Utility Energy [Member] | Wisconsin Energy Corporation [Member]
Various guarantees to provide financial and performance assurance to third parties on behalf of affiliates
Guarantees, Maximum Potential Future Payments	58,100,000
Guarantees, Outstanding	0
Liability	0
Corporate and Other [Member] | Wisconsin Energy Corporation [Member]
Various guarantees to provide financial and performance assurance to third parties on behalf of affiliates
Guarantees, Maximum Potential Future Payments	300,000
Guarantees, Outstanding	0
Liability	$ 0

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligation [Abstract]

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS

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

	2011			2010
	(Millions of Dollars)
Balance as of January 1	$	52.6		$	57.9
Liabilities Incurred	0.6			—
Liabilities Settled	(2.2		)	(2.5		)
Accretion	3.0			3.1
Cash Flow Revisions	1.5			(5.9		)
Balance as of December 31	$	55.5		$	52.6

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Common Equity (Details 2) (USD $)	Dec. 31, 2011
Stock options outstanding
Options Outstanding, Number, Total	10,638,750.0
Options Outstanding, Weighted-Average Exercise Price	$ 21.65
Options Outstanding, Weighted-Average Remaining Contractual Life (Years)	5.4
Options Exercisable, Number, Total	7,534,980.0
Options Exercisable, Weighted-Average Exercise Price	$ 21.14
Options Exercisable, Weighted-Average Remaining Contractual Life (Years)	4.5
Range of Exercise Prices, $11.52 to $17.10 [Member]
Stock options outstanding
Options Outstanding, Number, Total	1,972,594.0
Options Outstanding, Weighted-Average Exercise Price	$ 16.07
Options Outstanding, Weighted-Average Remaining Contractual Life (Years)	2.3
Options Exercisable, Number, Total	1,972,594.0
Options Exercisable, Weighted-Average Exercise Price	$ 16.07
Options Exercisable, Weighted-Average Remaining Contractual Life (Years)	2.3
Range of Exercise Prices, $11.52 to $17.10 [Member] | Maximum [Member]
Stock options outstanding
Options Outstanding, Weighted-Average Exercise Price	$ 17.1
Range of Exercise Prices, $11.52 to $17.10 [Member] | Minimum [Member]
Stock options outstanding
Options Outstanding, Weighted-Average Exercise Price	$ 11.52
Range of Exercise Prices, $19.74 to $21.11 [Member]
Stock options outstanding
Options Outstanding, Number, Total	3,586,456.0
Options Outstanding, Weighted-Average Exercise Price	$ 20.62
Options Outstanding, Weighted-Average Remaining Contractual Life (Years)	5.9
Options Exercisable, Number, Total	1,420,186.0
Options Exercisable, Weighted-Average Exercise Price	$ 19.88
Options Exercisable, Weighted-Average Remaining Contractual Life (Years)	4.3
Range of Exercise Prices, $19.74 to $21.11 [Member] | Maximum [Member]
Stock options outstanding
Options Outstanding, Weighted-Average Exercise Price	$ 21.11
Range of Exercise Prices, $19.74 to $21.11 [Member] | Minimum [Member]
Stock options outstanding
Options Outstanding, Weighted-Average Exercise Price	$ 19.74
Range of Exercise Prices, $23.88 to $29.35 [Member]
Stock options outstanding
Options Outstanding, Number, Total	5,079,700.0
Options Outstanding, Weighted-Average Exercise Price	$ 24.54
Options Outstanding, Weighted-Average Remaining Contractual Life (Years)	6.2
Options Exercisable, Number, Total	4,142,200.0
Options Exercisable, Weighted-Average Exercise Price	$ 23.99
Options Exercisable, Weighted-Average Remaining Contractual Life (Years)	5.6
Range of Exercise Prices, $23.88 to $29.35 [Member] | Maximum [Member]
Stock options outstanding
Options Outstanding, Weighted-Average Exercise Price	$ 29.35
Range of Exercise Prices, $23.88 to $29.35 [Member] | Minimum [Member]
Stock options outstanding
Options Outstanding, Weighted-Average Exercise Price	$ 23.88

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Asset Sales, Divestitures and Discontinued Operations

12 Months Ended

Dec. 31, 2011

Asset Sales Divestitures and Discontinued Operations [Abstract]

ASSET SALES, DIVESTITURES AND DISCONTINUED OPERATIONS

ASSET SALES, DIVESTITURES AND DISCONTINUED OPERATIONS

Edison Sault:   Effective May 4, 2010, we sold Edison Sault Electric Company (Edison Sault) to Cloverland Electric Cooperative for approximately $63.0 million. We reclassified the operations related to Edison Sault as discontinued operations in the accompanying Consolidated Income Statements. Discontinued Edison Sault operations had no significant impact on our Consolidated Statements of Cash Flows for the years ended December 31, 2010 and 2009. We retained Edison Sault's ownership interest in ATC.

Water Utility Operations:   Effective April 30, 2009, we sold our water utility to the City of Mequon, Wisconsin for approximately $14.5 million. We reclassified the water utility income as discontinued operations in the accompanying Consolidated Income Statements. Discontinued water operations had no material impact on the Consolidated Statement of Cash Flows for the year ended December 31, 2009.

The following table summarizes the net impacts of the discontinued operations on our earnings for the years ended December 31:

	2011		2010		2009
	(Millions of Dollars)
Income from Continuing Operations	$	512.8	$	454.4	$	375.7
Income from Discontinued Edison Sault operations, net of tax	—		0.7		1.5
Income from Discontinued Water operations, net of tax	—		—		0.3
Income from Discontinued other operations, net of tax (a)	13.4		1.4		4.9
Net Income	$	526.2	$	456.5	$	382.4

(a) Primarily relates to the favorable resolution of uncertain state and federal tax positions associated with our previously discontinued manufacturing business.

Edgewater Generating Unit 5:   On March 1, 2011, we sold our 25% interest in Edgewater Generating Unit 5 to WPL for our net book value, including working capital, of approximately $38 million. This transaction was treated as a sale of an asset.

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Accounting and Reporting for Power the Future Generating Units

12 Months Ended

Dec. 31, 2011

Accounting and Reporting for Power the Future Generating Units [Abstract]

ACCOUNTING AND REPORTING FOR POWER THE FUTURE GENERATING UNITS

ACCOUNTING AND REPORTING FOR POWER THE FUTURE GENERATING UNITS

Background:   As part of our PTF strategy, our non-utility subsidiary, We Power, built four new generating units, PWGS 1, PWGS 2, OC 1 and OC 2, which are leased to our utility subsidiary, Wisconsin Electric, under long-term leases that have been approved by the PSCW. The leases are designed to recover the capital costs of the plant, including a return. PWGS 1, PWGS 2, OC 1 and OC 2 were placed in service in July 2005, May 2008, February 2010 and January 2011, respectively. The accompanying consolidated financial statements eliminate all intercompany transactions between We Power and Wisconsin Electric and reflect the cash inflows from Wisconsin Electric customers and the cash outflows to our vendors and suppliers.

The Oak Creek expansion includes common projects that benefit the existing units at this site as well as the new units. These projects include a coal handling facility and a water intake system, which were placed in service in November 2007 and January 2009, respectively.

During Construction:Under the terms of each lease, we collected in then current rates amounts representing our pre-tax cost of capital (debt and equity) associated with capital expenditures for our PTF units. Our pre-tax cost of capital was approximately 14%. The carrying costs that we collected in rates were recorded as deferred revenue and are amortized to revenue over the term of each lease. During the construction of our PTF units, we capitalized interest costs at an overall weighted-average pre-tax cost of interest, which was approximately 5% for the year ended December 31, 2010. Capitalized interest is included in the total cost of the PTF units.

Plant in Service:Now that the PTF units are in service, we expect to continue to recover in rates the lease costs which reflect the authorized cash construction costs of the units plus a return on the investment. The authorized cash costs were established by the PSCW. The authorized cash costs exclude capitalized interest since carrying costs were recovered during the construction of the units. The lease payments are expected to be levelized, except that OC 1 and OC 2 will be recovered on a levelized basis that has a one time 10.6% escalation after the first five years of the leases. The leases established a set return on equity component of 12.7% after tax. The interest component of the return under each lease was established at rates determined in accordance with the terms of each lease.

We recognize revenues (consisting of the lease payments included in rates and the amortization of the deferred revenue) on a levelized basis over the term of the lease. We depreciate the PTF assets over their estimated useful life.

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Variable Interest Entities

12 Months Ended

Dec. 31, 2011

Variable Interest Entities [Abstract]

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

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

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

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

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

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

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Short-Term Debt (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Short-Term Debt (Textuals) [Abstract]
Undrawn lines under bank back-up credit facilities	$ 1,200,000,000
Short-term debt outstanding supported by the available lines of credit	669,900,000
Wisconsin Energy Corporation [Member]
Short-Term Debt (Textuals) [Abstract]
Minimum total funded debt to capitalization ratio	70.00%
Wisconsin Electric [Member]
Short-Term Debt (Textuals) [Abstract]
Minimum total funded debt to capitalization ratio	65.00%
Wisconsin Gas [Member]
Short-Term Debt (Textuals) [Abstract]
Minimum total funded debt to capitalization ratio	65.00%
Commercial Paper [Member]
Short-term notes payable balances and their corresponding weighted-average interest rates
Commercial paper, balance	669,900,000	657,900,000
Commercial paper, weighted-average interest rate	0.27%	0.30%
Commercial paper [Abstract]
Maximum Short-Term Debt Outstanding	717,300,000	821,000,000
Average Short-Term Debt Outstanding	$ 505,100,000	$ 528,700,000
Weighted-Average Interest Rate	0.25%	0.32%

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Condensed Parent Company Financial Statements (Details 5) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Condensed Parent Company Financial Statements (Textuals) [Abstract]
Issuance of new notes and the proceeds used to repay short-term debt	$ 466.6	$ 291.7	$ 221.1
Issuance of Junior Notes	720.0	530.0	261.5
Restriction under RCC	The RCC provides that we may not redeem, defease or purchase and our subsidiaries may not purchase any Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, during the 180 days prior to the date of redemption, defeasance or purchase, we have received a specified amount of proceeds from the sale of qualifying securities.
Interest paid, net of amounts capitalized	234.0	198.0	152.3
Wisconsin Energy Corporation [Member]
Condensed Parent Company Financial Statements (Textuals) [Abstract]
Extinguishment of Debt, Amount	450
Long-term notes outstanding of WECC	80
Issuance of new notes and the proceeds used to repay short-term debt	450.0	281.5	0
Proceeds from Notes Payable			11.5
Minimum Total Funded Debt to Capitalization Ratio, As a Percent	70.00%
Issuance of Junior Notes	0	0	11.4
Interest paid, net of amounts capitalized	57.7	43.5	45.2
Refunds from income taxes	114.6	1.0	36.0
Wisconsin Electric and Wisconsin Gas [Member]
Condensed Parent Company Financial Statements (Textuals) [Abstract]
Dividends and distributions from subsidiaries	273
We Power [Member]
Condensed Parent Company Financial Statements (Textuals) [Abstract]
Dividends and distributions from subsidiaries	$ 722
Notes (unsecured), 6.20% due 2033 [Member]
Condensed Parent Company Financial Statements (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate	6.20%	6.20%
Junior Notes (unsecured), 6.25% due 2067 [Member]
Condensed Parent Company Financial Statements (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate	6.25%	6.25%
Notes (unsecured), 6.50% due 2011 [Member]
Condensed Parent Company Financial Statements (Textuals) [Abstract]
Debt instrument interest rate stated percentage rate	6.50%	6.50%

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Derivative Instruments (Details 1) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Regulatory Assets [Line Items]
Regulatory assets related to derivatives	$ 1,265.7	$ 1,144.5
Derivative [Member]
Regulatory Assets [Line Items]
Regulatory assets related to derivatives	$ 29.6	$ 22.0

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Long-Term Debt and Capital Lease Obligations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 Megawatt	Dec. 31, 2010	Dec. 31, 2009
Long-term debt outstanding maturities and sinking fund requirements
2012	$ 20.3
2013	396.3
2014	322.4
2015	399.5
2016	27.4
Thereafter	3,375.5
Total	4,541.4
Summary of capitalized leased facilities
Long-term power purchase commitment	140.3	140.3
Accumulated amortization	(81.1)	(75.5)
Total Leased Facilities	59.2	64.8
Future minimum lease payments under capital lease and present value of net minimum lease payments
2012	38.9
2013	40.4
2014	41.9
2015	43.5
2016	45.1
Thereafter	85.4
Total Minimum Lease Payments	295.2
Less: Estimated Executory Costs	(74.9)
Net Minimum Lease Payments	220.3
Less: Interest	(87.9)
Present Value of Net Minimum Lease Payments	132.4
Less: Due Currently	(12.4)
Future minimum lease payments under our capital lease and the present value of our net minimum lease payments	120.0
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Issuance of long-term debt	720.0	530.0	261.5
Restriction under RCC	The RCC provides that we may not redeem, defease or purchase and our subsidiaries may not purchase any Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, during the 180 days prior to the date of redemption, defeasance or purchase, we have received a specified amount of proceeds from the sale of qualifying securities.
Retirement of unsecured notes		281.5
Power capacity from a gas-fired cogeneration facility under capital lease (MW)	236
Total operating lease payment	31.3	30.2
Increase in regulatory asset due to minimum lease payment			78.5
Regulatory asset value at the end of life of contract	0
Total capital lease obligation	132.4	141.9
Capital lease obligation at the end of life of contract	0
Wis Elec Debentures due September 15 2021 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Issuance of long-term debt	300.0
Debt instrument interest rate stated percentage rate	2.95%
Series B [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Issuance of long-term debt	420.0
Series B Senior Notes due January 19 2031 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Issuance of long-term debt	205.0
Debt instrument interest rate stated percentage rate	4.673%
Series B Senior Notes due January 19 2041 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Issuance of long-term debt	215.0
Debt instrument interest rate stated percentage rate	5.848%
Series A [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Issuance of long-term debt		530.0
Notes (secured, nonrecourse), 5.209% due 2011-2030 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Issuance of long-term debt		255.0
Secured Long-term Debt, Noncurrent	245.4	251.9
Debt instrument interest rate stated percentage rate	5.209%	5.209%
Notes (secured, nonrecourse), 6.09% due 2030-2040 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Issuance of long-term debt		275.0
Secured Long-term Debt, Noncurrent	275.0	275.0
Debt instrument interest rate stated percentage rate	6.09%	6.09%
Debentures (unsecured), 4.25% due 2019 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Issuance of long-term debt			250.0
Unsecured Long-term Debt, Noncurrent	250.0	250.0
Debt instrument interest rate stated percentage rate	4.25%	4.25%
Notes (unsecured), 6.20% due 2033 [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Unsecured Long-term Debt, Noncurrent	200.0	200.0
Debt instrument interest rate stated percentage rate	6.20%	6.20%
Wisconsin Electric [Member]
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract]
Number of series of tax-exempt pollution control refunding bonds	2
Unsecured Long-term Debt, Noncurrent	$ 147.0	$ 147.0
Period of Power purchase contract with an unaffiliated independent power producer	25
Power capacity from a gas-fired cogeneration facility under capital lease (MW)	236
Minimum energy requirement in gas-fired cogeneration facility	0
Power purchase contract expiration year	Dec. 31, 2022
Power purchase contract expected future renewable period	10

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Asset Sales, Divestitures And Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2011

Asset Sales, Divestitures And Discontinued Operations (Tables) [Abstract]

Net impacts of the discontinued operations on earnings

The following table summarizes the net impacts of the discontinued operations on our earnings for the years ended December 31:

	2011		2010		2009
	(Millions of Dollars)
Income from Continuing Operations	$	512.8	$	454.4	$	375.7
Income from Discontinued Edison Sault operations, net of tax	—		0.7		1.5
Income from Discontinued Water operations, net of tax	—		—		0.3
Income from Discontinued other operations, net of tax (a)	13.4		1.4		4.9
Net Income	$	526.2	$	456.5	$	382.4

(a) Primarily relates to the favorable resolution of uncertain state and federal tax positions associated with our previously discontinued manufacturing business.

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Regulatory Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Regulatory Assets
Total regulatory assets	$ 1,265.7	$ 1,144.5
Net regulatory assets	11.0	16.5
Net regulatory assets not earning return, period of recovery	one to five years
Recovery period of specific regulatory assets	8
Regulatory liability current expected to be amortization period	within one year
Minimum [Member]
Regulatory Assets
Regulatory assets, expected recovery period (in years)	1
Maximum [Member]
Regulatory Assets
Regulatory assets, expected recovery period (in years)	5
Deferred unrecognized pension costs [Member]
Regulatory Assets
Total regulatory assets	647.8	542.6
Deferred income tax related [Member]
Regulatory Assets
Total regulatory assets	121.2	89.9
Escrowed electric transmission costs [Member]
Regulatory Assets
Total regulatory assets	118.3	138.0
Deferred unrecognized OPEB costs [Member]
Regulatory Assets
Total regulatory assets	102.9	85.7
Deferred plant related -- capital lease [Member]
Regulatory Assets
Total regulatory assets	73.2	77.1
Deferred environmental costs [Member]
Regulatory Assets
Total regulatory assets	48.5	56.7
Other, net [Member]
Regulatory Assets
Total regulatory assets	$ 153.8	$ 154.5

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Derivative Instruments

12 Months Ended

Dec. 31, 2011

Derivative Instruments and Hedges, Assets [Abstract]

DERIVATIVE INSTRUMENTS

DERIVATIVE INSTRUMENTS

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

We record derivative instruments on the balance sheet as an asset or liability measured at its fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. We do not offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivatives executed with the same counterparty under the same master netting arrangement. As of December 31, 2011, we recognized $29.6 million in regulatory assets and $21.7 million in regulatory liabilities related to derivatives in comparison to $22.0 million in regulatory assets and $15.3 million in regulatory liabilities as of December 31, 2010.

We record our current derivative assets on the balance sheet in other current assets and the current portion of the liabilities in other current liabilities. The long-term portion of our derivative assets of $2.5 million is recorded in other deferred charges and other assets, and the long-term portion of our derivative liabilities of $0.7 million is recorded in other long-term liabilities. Our Consolidated Balance Sheets as of December 31, 2011 and 2010 include:

	December 31, 2011				December 31, 2010
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	2.1	$	9.1	$	2.5	$	11.6
Fuel Oil	0.3		0.1		4.4		—
FTRs	5.7		—		5.9		—
Coal	12.5		—		2.9		—
Total	$	20.6	$	9.2	$	15.7	$	11.6

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

	2011				2010
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)
Natural Gas	71.8 million Dth	$	(33.4	)	83.2 million Dth	$	(43.8	)
Power	zero MWh	—			234,720 MWh	(0.5		)
Fuel Oil	13.0 million gallons	6.9			8.1 million gallons	(0.5		)
FTRs	23,718 MW	12.5			25,234 MW	19.2
Total		$	(14.0	)		$	(25.6	)

As of December 31, 2011 and 2010, we posted collateral of $11.9 million and $11.7 million, respectively, in our margin accounts. These amounts are recorded on the balance sheets in other current assets.

For the year ended December 31, 2011, we reclassified $0.2 million and for the years ended December 31, 2010 and 2009, we reclassified $0.4 million in treasury lock agreement settlement payments deferred in Accumulated Other Comprehensive Income, as an increase to Interest Expense. We estimate that during the next 12 months, $0.1 million will be reclassified from Accumulated Other Comprehensive Income as a reduction in earnings.

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Related Parties

12 Months Ended

Dec. 31, 2011

Related Party Transaction, Due from (to) Related Party [Abstract]

RELATED PARTIES

RELATED PARTIES

We receive and/or provide certain services to other associated companies in which we have an equity investment.

American Transmission Company LLC:   As of December 31, 2011, we have a 26.2% interest in ATC. We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance and project management work for ATC, which are reimbursed to us by ATC. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while projects are under construction, including the new generating units constructed as part of our PTF strategy. ATC reimburses us for these costs when new generation is placed in service. As of December 31, 2011 and 2010, we had a receivable of $5.4 million and $3.8 million, respectively, for these items. During the years ended December 31, 2011, 2010 and 2009, our equity in earnings from ATC was $62.5 million, $60.1 million and $59.1 million, respectively. During the years ended December 31, 2011, 2010 and 2009, distributions received from ATC were $49.7 million, $49.3 million and $46.6 million, respectively.

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

Equity Investee	2011		2010		2009
	(Millions of Dollars)
Services Provided
–ATC	$	10.8	$	16.9	$	22.3
Services Received
–ATC	$	219.2	$	220.8	$	196.0

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

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

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Summary of Significant Accounting Policies (Details 2) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Property in Service by Segment
Property In Service	$ 12,977.7	$ 11,590.8
Construction Work in Progress (CWIP) by segment
Construction Work in Progress (CWIP)	921.3	1,569.9
Goodwill related to acquisition of Wisconsin Gas	441.9	441.9
Utility Energy [Member]
Property in Service by Segment
Property In Service	9,817.7	9,221.1
Construction Work in Progress (CWIP) by segment
Construction Work in Progress (CWIP)	910.3	806.9
Non-Utility Energy [Member]
Property in Service by Segment
Property In Service	3,067.5	2,283.4
Construction Work in Progress (CWIP) by segment
Construction Work in Progress (CWIP)	8.9	761.3
Corporate and Other [Member]
Property in Service by Segment
Property In Service	92.5	86.3
Construction Work in Progress (CWIP) by segment
Construction Work in Progress (CWIP)	$ 2.1	$ 1.7

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2011

Fair Value Measurements (Tables) [Abstract]

Financial assets and liabilities by level within the fair value hierarchy

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

Recurring Fair Value Measures	As of December 31, 2011
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	45.5	$	—	$	—	$	45.5
Derivatives	0.3		14.6		5.7		20.6
Total	$	45.8	$	14.6	$	5.7	$	66.1
Liabilities:
Derivatives	$	8.2	$	1.0	$	—	$	9.2
Total	$	8.2	$	1.0	$	—	$	9.2

Recurring Fair Value Measures	As of December 31, 2010
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	8.3	$	—	$	—	$	8.3
Derivatives	4.5		5.3		5.9		15.7
Total	$	12.8	$	5.3	$	5.9	$	24.0
Liabilities:
Derivatives	$	6.1	$	5.5	$	—	$	11.6
Total	$	6.1	$	5.5	$	—	$	11.6

Fair value of derivatives classified as Level 3 in the fair value hierarchy

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

	2011			2010
	(Millions of Dollars)
Balance as of January 1	$	5.9		$	5.8
Realized and unrealized gains (losses)	—			—
Purchases and issuances	16.1			17.9
Settlements	(16.3		)	(17.8		)
Transfers in and/or out of Level 3	—			—
Balance as of December 31	$	5.7		$	5.9
Change in unrealized gains (losses) relating to instruments still held as of December 31	$	—		$	—

Carrying amount and estimated fair value of certain financial instruments

The carrying amount and estimated fair value of certain of our recorded financial instruments as of December 31 are as follows:

	2011				2010
	Carrying		Fair		Carrying		Fair
Financial Instruments	Amount		Value		Amount		Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	25.1	$	30.4	$	23.5
Long-term debt including current portion	$	4,541.4	$	5,179.9	$	4,288.0	$	4,578.0

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Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating Activities
Net income	$ 526.2	$ 456.5	$ 382.4
Reconciliation to cash
Depreciation and amortization	336.4	317.4	346.9
Amortization of gain	0	(198.4)	(230.7)
Deferred income taxes and investment tax credits, net	430.6	104.9	187.4
Deferred revenue	3.5	100.8	201.7
Contributions to qualified benefit plans	(277.4)	0	(289.3)
Change in -
Accounts receivable and accrued revenues	30.1	(50.4)	111.1
Inventories	(2.9)	(1.0)	(34.6)
Other current assets	(20.5)	14.1	24.8
Accounts payable	11.8	21.3	(119.1)
Accrued income taxes, net	(87.4)	(42.7)	43.4
Deferred costs, net	25.9	25.9	46.2
Other current liabilities	44.1	22.0	(11.7)
Other, net	(27.0)	40.0	(29.6)
Cash Provided by Operating Activities	993.4	810.4	628.9
Investing Activities
Capital expenditures	(830.8)	(798.2)	(814.6)
Investment in transmission affiliate	(6.6)	(5.2)	(25.9)
Proceeds from asset sales	41.5	68.7	16.8
Change in restricted cash	(37.2)	186.2	192.0
Other, net	(59.4)	(85.0)	(104.4)
Cash Used in Investing Activities	(892.5)	(633.5)	(736.1)
Financing Activities
Exercise of stock options	54.4	90.9	17.0
Purchase of common stock	(193.9)	(156.6)	(29.6)
Dividends paid on common stock	(242.0)	(187.0)	(157.8)
Issuance of long-term debt	720.0	530.0	261.5
Retirement and repurchase of long-term debt	(466.6)	(291.7)	(221.1)
Change in short-term debt	12.0	(167.2)	222.8
Other, net	4.8	9.0	2.9
Cash (Used in) Provided by Financing Activities	(111.3)	(172.6)	95.7
Change in Cash and Cash Equivalents	(10.4)	4.3	(11.5)
Cash and Cash Equivalents at Beginning of Year	24.5	20.2	31.7
Cash and Cash Equivalents at End of Year	$ 14.1	$ 24.5	$ 20.2

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General:Our consolidated financial statements include the accounts of Wisconsin Energy Corporation (Wisconsin Energy, the Company, our, we or us), a diversified holding company, as well as our subsidiaries in the following operating segments:

• Utility Energy Segment -- Consisting of Wisconsin Electric and Wisconsin Gas, engaged primarily in the generation of electricity and the distribution of electricity and natural gas; and

• Non-Utility Energy Segment -- Consisting primarily of We Power, engaged principally in the design, development, construction and ownership of electric power generating facilities for long-term lease to Wisconsin Electric.

Our Corporate and Other segment includes Wispark, which develops and invests in real estate. We have also eliminated all intercompany transactions and balances within this segment from the consolidated financial statements.

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

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

On January 20, 2011, our Board of Directors approved a two-for-one stock split of our common stock, which was effected through a stock dividend. New shares were distributed on March 1, 2011 to stockholders of record at the close of business on February 14, 2011. All share and per share information has been restated for all periods presented to reflect this stock split.

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

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

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

For information regarding revenue recognition for We Power, see Note E.

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

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

Other Income and Deductions, net	2011		2010		2009
	(Millions of Dollars)
AFUDC - Equity	$	59.4	$	32.5	$	16.0
Gain on Property Sales	2.4		4.4		1.7
Other, net	0.9		3.3		10.8
Total Other Income and Deductions, net	$	62.7	$	40.2	$	28.5

Property and Depreciation:We record property, plant and equipment at cost. Cost includes material, labor, overheads and capitalized interest. Utility property also includes AFUDC - Equity. Additions to and significant replacements of property are charged to property, plant and equipment at cost; minor items are charged to maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.

We recorded the following property in service by segment as of December 31:

Property In Service	2011		2010
	(Millions of Dollars)
Utility Energy	$	9,817.7	$	9,221.1
Non-Utility Energy	3,067.5		2,283.4
Other	92.5		86.3
Total	$	12,977.7	$	11,590.8

Our utility depreciation rates are certified by the PSCW and MPSC and include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 2.8% in 2011 and 2010, and 3.7% in 2009.

PWGS 1, PWGS 2, OC 1 and OC 2 are being depreciated over the estimated useful life of the various property components. The components have useful lives of between 10 to 45 years for PWGS 1 and PWGS 2, and 10 to 55 years for OC 1 and OC 2.

Our regulated utilities collect in their rates amounts representing future removal costs for many assets that do not have an associated Asset Retirement Obligation (ARO). We record a regulatory liability on our balance sheet for the estimated amounts we have collected in rates for future removal costs less amounts we have spent in removal activities. This regulatory liability was $728.2 million as of December 31, 2011 and $723.9 million as of December 31, 2010.

We recorded the following Construction Work in Progress (CWIP) by segment as of December 31:

CWIP	2011		2010
	(Millions of Dollars)
Utility Energy	$	910.3	$	806.9
Non-Utility Energy	8.9		761.3
Other	2.1		1.7
Total	$	921.3	$	1,569.9

Allowance For Funds Used During Construction - Regulated:   AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC - Debt) used during plant construction, and a return on stockholders' capital (AFUDC - Equity) used for construction purposes. AFUDC - Debt is recorded as a reduction of interest expense, and AFUDC - Equity is recorded in Other Income and Deductions, net.

During 2009, Wisconsin Electric accrued AFUDC at a rate of 9.09% as authorized by the PSCW. Consistent with the PSCW's 2008 rate order, Wisconsin Electric accrued AFUDC on 50% of all utility CWIP projects except the Oak Creek AQCS project, which accrued AFUDC on 100% of CWIP. Wisconsin Electric's rates are set to provide a current return on CWIP that does not accrue AFUDC. Based on the 2010 PSCW rate order, effective January 1, 2010 Wisconsin Electric recorded AFUDC on 100% of CWIP associated with the Oak Creek AQCS project, the Edgewater Unit 5 Selective Catalytic Reduction project and the Glacier Hills Wind Park. Wisconsin Electric recorded AFUDC on 50% of all other electric, gas and steam utility CWIP. The AFUDC rate starting January 1, 2010 was 8.83%. This AFUDC accrual policy and rate for Wisconsin Electric continued through 2011 and will continue through 2012.

Wisconsin Electric is also accruing AFUDC on 100% of the biomass project.

During 2009, Wisconsin Gas accrued AFUDC at a rate of 10.80% on 50% of its CWIP as authorized by the PSCW in its 2008 rate order. Wisconsin Gas' rates are set to provide a current return on CWIP that does not accrue AFUDC. Based on the 2010 PSCW rate order, effective January 1, 2010 Wisconsin Gas recorded AFUDC on 50% of all CWIP using an AFUDC rate of 9.05%. This AFUDC accrual policy and rate for Wisconsin Gas continued through 2011 and will continue through 2012.

Our regulated segment recorded the following AFUDC for the years ended December 31:

	2011		2010		2009
	(Millions of Dollars)
AFUDC - Debt	$	24.7	$	13.5	$	6.7
AFUDC - Equity	$	59.4	$	32.5	$	16.0

Capitalized Interest and Carrying Costs - Non-Regulated Energy:   As part of the construction of the PTF electric generating units, we capitalized interest during construction. As allowed under the lease agreements, we were able to collect the carrying costs during the construction of the PTF generating units from our utility customers. The carrying costs that we collected during construction have been recorded as deferred revenue on our balance sheet and we are amortizing the deferred carrying costs to revenue over the individual lease terms. For further information on the accounting for capitalized interest and deferred carrying costs associated with the construction of our PTF power plants, see Note E.

Earnings per Common Share:   We compute basic earnings per common share by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net income attributed to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive securities include in-the-money stock options. The future issuance of shares underlying the outstanding stock options depends on whether the exercise prices of the stock options are less than the average market price of the common shares for the respective periods. Shares that are anti-dilutive are excluded from the calculation. All stock options outstanding during 2011 were included in the computation of diluted earnings per share. For 2010 and 2009, the calculation of diluted earnings per share excluded an immaterial number of out-of-the money stock options that had an anti-dilutive effect.

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

Materials, Supplies and Inventories	2011		2010
	(Millions of Dollars)
Fossil Fuel	$	169.2	$	182.4
Materials and Supplies	114.1		105.2
Natural Gas in Storage	98.7		91.5
Total	$	382.0	$	379.1

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

Regulatory Accounting:   The economic effects of regulation can result in regulated companies recording costs that have been or are expected to be allowed in the rate-making process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets on the balance sheet and expensed in the periods when they are reflected in rates. We defer regulatory assets pursuant to specific or generic orders issued by our regulators. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We expect to recover our outstanding regulatory assets in rates over a period of no longer than 20 years. Regulatory assets and liabilities that are expected to be amortized within one year are recorded as current on the balance sheet. For further information, see Note C.

Asset Retirement Obligations:   We record a liability for a legal ARO in the period in which it is incurred. When a new legal obligation is recorded, we capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. We accrete the liability to its present value each period and depreciate the capitalized cost over the useful life of the related asset. At the end of the asset's useful life, we settle the obligation for its recorded amount or incur a gain or loss. As it relates to our regulated operations, we apply regulatory accounting guidance and recognize regulatory assets or liabilities for the timing differences between when we recover legal AROs in rates and when we would recognize these costs. For further information, see Note F.

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

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

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

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

Goodwill:   Goodwill reflects the cost of an acquisition in excess of the fair values assigned to identifiable net assets acquired. As of December 31, 2011 and 2010, we had $441.9 million of goodwill recorded at the utility energy segment, which related to our acquisition of Wisconsin Gas in 2000.

Goodwill is not subject to amortization. However, it is subject to fair value-based rules for measuring impairment, and resulting write-downs, if any, are to be reflected in operating expense. Fair value is assessed by considering future discounted cash flows, a comparison of fair value based on public company trading multiples, and merger and acquisition transaction multiples for similar companies. This evaluation utilizes the information available under the circumstances, including reasonable and supportable assumptions and projections. We perform our annual impairment test as of August 31. There was no impairment to the recorded goodwill balance as of our annual 2011 impairment test date.

Impairment or Disposal of Long Lived Assets:   We carry property, equipment and goodwill related to businesses held for sale at the lower of cost or estimated fair value less cost to sell. As of December 31, 2011, we had no assets classified as Held for Sale. Long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that their carrying value may not be recoverable from the use and eventual disposition of the asset based on the remaining useful life. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset.

Investments:   We account for investments in other affiliated companies in which we do not maintain control using the equity method of accounting. We had a total ownership interest of approximately 26.2% in ATC as of December 31, 2011 and 2010. We are represented by one out of ten ATC board members, each of whom has one vote. Due to the voting requirements, no individual member has more than 10% of the voting control. For further information regarding such investments, see Note Q.

Income Taxes:   We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense.

Investment tax credits associated with regulated operations are deferred and amortized over the life of the assets. We file a consolidated Federal income tax return. Accordingly, we allocate Federal current tax expense benefits and credits to our subsidiaries based on their separate tax computations. For further information, see Note H.

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

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

Stock Options:   We estimate the fair value of stock options using the binomial pricing model. We report unearned stock-based compensation associated with non-vested restricted stock and performance share awards activity within Other Paid in Capital in our Consolidated Statements of Common Equity. We report excess tax benefits as a financing cash inflow. Historically, all stock options have been granted with an exercise price equal to the fair market value of the common stock on the date of grant and expire no later than 10 years from grant date. For a discussion of the impacts to our Consolidated Financial Statements, see Note I.

The fair value of our stock options was calculated using a binomial option-pricing model using the following weighted-average assumptions:

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

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Common Equity (Details) (USD $) In Millions, except Share data, unless otherwise specified	1 Months Ended				12 Months Ended
	Jan. 31, 2012	Jan. 31, 2011	Jan. 31, 2010	Jan. 31, 2009	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Recorded pre-tax share-based compensation expense and related tax benefit for share-based awards made to employees and directors
Share-based compensation expense					$ 28.5	$ 35.1	$ 25.8
Related Tax Benefit					11.4	14.1	10.3
Common Equity (Textuals)
Actual tax benefit realized for the tax deductions from option exercises/settlement					14.3	24.1	4.8
Stock options [Member]
Recorded pre-tax share-based compensation expense and related tax benefit for share-based awards made to employees and directors
Share-based compensation expense					2.6	7.6	10.8
Common Equity (Textuals)
Restricted stock vesting period in years					3 years
Performance units [Member]
Recorded pre-tax share-based compensation expense and related tax benefit for share-based awards made to employees and directors
Share-based compensation expense					24.1	26.0	14.0
Restricted stock activity
Granted, Number of Shares	346,570.0	435,690.0	555,830.0	666,440.0
Common Equity (Textuals)
Unrecognized total compensation costs related share based compensation					18.3
Intrinsic Value					26.7	12.6	9.8
Actual tax benefit realized for the tax deductions from option exercises/settlement					9.7	4.3	3.4
Months, on a weighted-average basis, expected for recognizing total compensation costs related to performance units					19
Period of accrual for costs related to performance units (in years)					3 years
Restricted stock [Member]
Recorded pre-tax share-based compensation expense and related tax benefit for share-based awards made to employees and directors
Share-based compensation expense					1.8	1.5	1.0
Restricted stock activity
Outstanding	192,558.0	205,404.0			205,404.0
Granted, Number of Shares	94,959.0				74,850.0
Granted, Weighted-Average Market Price					$ 29.00
Released, Number of Shares					(83,452.0)
Released, Weighted-Average Market Price					$ 18.82
Forfeited, Number of Shares					(4,244.0)
Forfeited, Weighted-Average Market Price					$ 26.62
Outstanding					192,558.0	205,404.0
Common Equity (Textuals)
Unrecognized total compensation costs related share based compensation					2.4
Restricted stock vesting period in years	3				10
Intrinsic Value					2.5	2.3	0.9
Actual tax benefit realized for the tax deductions from option exercises/settlement					0.8	0.7	0.3
Months, on a weighted-average basis, expected for recognizing total compensation costs related to restricted stock options					20
Non-Vested Options [Member]
Common Equity (Textuals)
Unrecognized total compensation costs related share based compensation					$ 0.6
Months, on a weighted-average basis, expected for recognizing total compensation costs related to non-vested stock options					19
Maximum [Member]
Common Equity (Textuals)
Requirement to maintain common equity ratio by Wisconsin Electric		53.50%
Requirement to maintain common equity ratio by Wisconsin Gas		50.00%
Minimum [Member]
Common Equity (Textuals)
Requirement to maintain common equity ratio by Wisconsin Electric		48.50%
Requirement to maintain common equity ratio by Wisconsin Gas		45.00%

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Condensed Parent Company Financial Statements (Details 2) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating Activities
Net income	$ 526.2	$ 456.5	$ 382.4
Reconciliation to cash
Equity in susidiaries' earnings	(62.5)	(60.1)	(59.1)
Deferred income taxes, net	434.8	108.6	191.2
Accrued income taxes, net	(87.4)	(42.7)	43.4
Other current assets	(20.5)	14.1	24.8
Other current liabilities	44.1	22.0	(11.7)
Accounts receivable and accrued revenues	30.1	(50.4)	111.1
Other, net	(27.0)	40.0	(29.6)
Cash Provided by Operating Activities	993.4	810.4	628.9
Investing Activities
Proceeds from asset sales	41.5	68.7	16.8
Capital contributions to associated companies	(6.6)	(5.2)	(25.9)
Cash Used in Investing Activities	(892.5)	(633.5)	(736.1)
Financing Activities
Exercise of stock options	54.4	90.9	17.0
Purchase of common stock	(193.9)	(156.6)	(29.6)
Dividends paid on common stock	(242.0)	(187.0)	(157.8)
Issuance of long-term debt	720.0	530.0	261.5
Retirement and repurchase of long-term debt	(466.6)	(291.7)	(221.1)
Change in short-term debt	12.0	(167.2)	222.8
Other, net	4.8	9.0	2.9
Cash (Used in) Provided by Financing Activities	(111.3)	(172.6)	95.7
Change in Cash and Cash Equivalents	(10.4)	4.3	(11.5)
Cash and Cash Equivalents at Beginning of Year	24.5	20.2	31.7
Cash and Cash Equivalents at End of Year	14.1	24.5	20.2
Wisconsin Energy Corporation [Member]
Operating Activities
Net income	526.2	456.5	382.4
Reconciliation to cash
Equity in susidiaries' earnings	(545.9)	(482.9)	(397.7)
Dividends and distributions from subsidiaries	995.5	305.3	225.2
Deferred income taxes, net	(350.9)	(29.7)	28.2
Accrued income taxes, net	363.4	41.9	(15.5)
Other current assets	(0.1)	11.5	8.1
Other current liabilities	8.9	3.0	(0.4)
Accounts receivable and accrued revenues	(18.7)	477.2	1.7
Other, net	(10.2)	(1.4)	6.6
Cash Provided by Operating Activities	968.2	781.4	238.6
Investing Activities
Proceeds from asset sales	0	63.1	0
Capital contributions to associated companies	(36.5)	(64.5)	(108.9)
Capitalized interest and other	2.4	(57.3)	(42.7)
Cash Used in Investing Activities	(34.1)	(58.7)	(151.6)
Financing Activities
Exercise of stock options	54.4	90.9	17.0
Purchase of common stock	(193.9)	(156.6)	(29.6)
Dividends paid on common stock	(242.0)	(187.0)	(157.8)
Issuance of long-term debt	0	0	11.4
Retirement and repurchase of long-term debt	(450.0)	(281.5)	0
Change in short-term debt	(116.5)	(310.5)	74.0
Change in notes payable due associated companies	3.9	106.1	(6.6)
Other, net	9.9	15.8	3.4
Cash (Used in) Provided by Financing Activities	(934.2)	(722.8)	(88.2)
Change in Cash and Cash Equivalents	(0.1)	(0.1)	(1.2)
Cash and Cash Equivalents at Beginning of Year	0.6	0.7	1.9
Cash and Cash Equivalents at End of Year	$ 0.5	$ 0.6	$ 0.7

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Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Assets:
Restricted Cash	$ 45.5	$ 8.3
Derivative, Asset	20.6	15.7
Total	66.1	24.0
Liabilities:
Derivatives	9.2	11.6
Total	9.2	11.6
Fair Value, Inputs, Level 1 [Member]
Assets:
Restricted Cash	45.5	8.3
Derivative, Asset	0.3	4.5
Total	45.8	12.8
Liabilities:
Derivatives	8.2	6.1
Total	8.2	6.1
Fair Value, Inputs, Level 2 [Member]
Assets:
Restricted Cash	0	0
Derivative, Asset	14.6	5.3
Total	14.6	5.3
Liabilities:
Derivatives	1.0	5.5
Total	1.0	5.5
Fair Value, Inputs, Level 3 [Member]
Assets:
Restricted Cash	0	0
Derivative, Asset	5.7	5.9
Total	5.7	5.9
Liabilities:
Derivatives	0	0
Total	$ 0	$ 0

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

Capital Expenditures:   We have made certain commitments in connection with 2012 capital expenditures. During 2012, we estimate that total capital expenditures will be approximately $740.2 million.

Operating Leases:   We enter into long-term purchase power contracts to meet a portion of our anticipated increase in future electric energy supply needs. These contracts expire at various times through 2018. Certain of these contracts were deemed to qualify as operating leases. In addition, we have various other operating leases including leases for coal cars.

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

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

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

Environmental Matters:   We periodically review our exposure for environmental remediation costs as evidence becomes available indicating that our liability has changed. Given current information, including the following, we believe that future costs in excess of the amounts accrued and/or disclosed on all presently known and quantifiable environmental contingencies will not be material to our financial position or results of operations.

We have a program of comprehensive environmental remediation planning for former manufactured gas plant sites and coal combustion product disposal sites. We perform ongoing assessments of manufactured gas plant sites and related disposal sites used by Wisconsin Electric and Wisconsin Gas, and coal combustion product disposal/landfill sites used by Wisconsin Electric, as discussed below. We are working with the WDNR in our investigation and remediation planning. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

Manufactured Gas Plant Sites:   We have identified several sites at which Wisconsin Electric, Wisconsin Gas, or a predecessor company historically owned or operated a manufactured gas plant. These sites have been substantially remediated or are at various stages of investigation, monitoring and remediation. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Based upon on-going analysis, we estimate that the future costs for detailed site investigation and future remediation costs may range from $21 million to $65 millionover the next ten years. This estimate is dependent upon several variables including, among other things, the extent of remediation, changes in technology and changes in regulation. As of December 31, 2011, we have established reserves of $37.5 million related to future remediation costs.

Historically, the PSCW has allowed Wisconsin utilities, including Wisconsin Electric and Wisconsin Gas, to defer the costs spent on the remediation of manufactured gas plant sites, and has allowed for these costs to be recovered in rates over five years. Accordingly, we have recorded a regulatory asset for remediation costs.

Coal Combustion Product Landfill Sites:   Wisconsin Electric aggressively seeks environmentally acceptable, beneficial uses for its coal combustion products. However, some coal combustion products have been, and to a small degree continue to be, managed in company-owned, licensed landfills. Some early designed and constructed landfills have at times required various levels of monitoring or remediation. Where Wisconsin Electric has become aware of these conditions, efforts have been made to define the nature and extent of any release, and work has been performed to address these conditions. During 2011, 2010 and 2009, Wisconsin Electric incurred $0.2 million, $0.4 million and $0.3 million respectively, in landfill remediation expenses. As of December 31, 2011, we have no reserves established related to coal combustion product landfill sites.

EPA - Consent Decree:   In April 2003, Wisconsin Electric reached a Consent Decree with the EPA, in which it agreed to significantly reduce air emissions from its coal-fired generating facilities. In July 2003, the Consent Decree was amended to include the state of Michigan, and in October 2007, the U.S. District Court for the Eastern District of Wisconsin approved and entered the amended Consent Decree. The Consent Decree was further amended in January 2012 to change the point of air monitoring at the Oak Creek Power Plant to accommodate the AQCS scheduled to begin service in 2012. The reductions are expected to be achieved by 2013 through a combination of installing new pollution control equipment, upgrading existing equipment and retiring certain older units. Through December 31, 2011, we have spent approximately $1.0 billion associated with the installation of air quality controls and have retired four coal units as part of our plan under the Consent Decree. The total cost of implementing this agreement is currently estimated to be approximately $1.1 billion over the ten year period ending 2013.

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

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

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

Bechtel's first claim was based on the alleged impact of severe weather and certain labor-related matters. Pursuant to its amended claim, Bechtel was requesting approximately $445.5 million in costs related to changed weather and labor conditions. Bechtel's second claim of approximately $72 million sought cost and schedule relief for the alleged effects of ERS-directed changes and delays allegedly caused by ERS prior to the issuance of the Full Notice to Proceed in July 2005. These claims, as well as claims submitted by ERS related to the rights of the parties under the construction contract and ERS counterclaims, had been submitted to binding arbitration.

Effective December 16, 2009, ERS and Bechtel entered into the Settlement Agreement that settled the claims between them regarding OC 1 and OC 2. Pursuant to the terms of this Settlement Agreement, ERS will pay to Bechtel $72 million to settle these claims payable upon the achievement of specific project milestones. As of December 31, 2011, Bechtel has received $67 million of the $72 million total settlement. The remaining milestone payments are tied to final acceptance of the units. In addition, Bechtel received 120 days of schedule relief for OC 1 and 60 days for OC 2. Therefore, the guaranteed in-service date of September 29, 2009 for OC 1 was extended to January 27, 2010, and the guaranteed in-service date of September 29, 2010 for OC 2 was extended to November 28, 2010. Bechtel subsequently received an additional 21 days of schedule relief for OC 2 as part of a change order signed concurrent with the turnover of OC 2. Therefore, the total schedule relief granted to Bechtel was 120 days for OC 1 and 81 days for OC 2.

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

Cash Balance Pension Plan:   In June 2009, a lawsuit was filed by Alan M. Downes, a former employee, against the Plan in the U.S. District Court for the Eastern District of Wisconsin. The complaint alleged that Plan participants who received a lump sum distribution under the Plan prior to their normal retirement age did not receive the full benefit to which they were entitled in violation of ERISA and were owed additional benefits, because the Plan failed to apply the correct interest crediting rate to project the cash balance account to their normal retirement age. In September 2010, the plaintiff filed a First Amended Class Action Complaint alleging additional claims under ERISA and adding Wisconsin Energy as a defendant.

In November 2011, we entered into a settlement agreement with the plaintiffs for $45.0 million, and the court promptly issued an order preliminarily approving the settlement. As part of the settlement agreement, we agreed to class certification for all similarly situated plaintiffs. The resolution of this matter resulted in a cost of less than $0.04 per share for 2011 after considering insurance and reserves established in the prior year. We do not anticipate further charges as a result of the settlement, other than certain process-related costs we expect to incur to implement the settlement. We expect the court to provide final approval of the settlement agreement in April 2012, and to pay additional benefits to class members promptly after receiving this approval.

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Benefits (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Defined Benefit Plan Disclosure [Line Items]
Matching contributions under Savings Plans		$ 14,100,000	$ 13,800,000	$ 14,100,000
Weighted-Average assumptions used to determine net cost for year ended Dec. 31
Expected return on plan assets				8.25%
A one-percentage-point change in assumed health care cost trend rates effects
1% Increase, in assumed health care cost trend rates, Effect on, Post-retirement benefit obligation		31,900,000
1% Decrease, in assumed health care cost trend rates, Effect on, Post-retirement benefit obligation		(26,800,000)
1% Increase, in assumed health care cost trend rates, Effect on, Total of service and interest cost components		3,800,000
1% Decrease, in assumed health care cost trend rates, Effect on, Total of service and interest cost components		(3,100,000)
Benefits (Textuals) [Abstract]
Accumulated benefit obligation for all defined benefit plans		1,329,400,000	1,222,500,000
Health care cost trend rate up to specified age		65
Health care cost trend rate post specified age		65
Current pension plan target asset allocation in equity investments		45.00%
Current pension plan target asset allocation in fixed income investments		55.00%
Other Post-Retirement Employee Benefits target asset allocation in equity investments		60.00%
Other Post-Retirement Employee Benefits target asset allocation in fixed income investments		40.00%
Matching contributions under Savings Plans		14,100,000	13,800,000	14,100,000
Postemployment benefits liability		15,300,000
Pension, Qualified [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Funded Status of Plan		24,400,000	(71,700,000)
Pension, Non-Qualified [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Funded Status of Plan		(92,500,000)	(91,600,000)
Pension Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Amortization of Previously Unrecognized Benefit Costs	43,900,000
Net Periodic Benefit Cost
Service cost		15,900,000	23,700,000	23,300,000
Interest cost		67,600,000	68,400,000	72,300,000
Expected return on plan assets		(82,100,000)	(78,200,000)	(95,400,000)
Amortization of:
Transition obligation		0	0	0
Prior service cost (credit)		2,200,000	2,200,000	2,200,000
Actuarial loss		34,000,000	26,800,000	18,900,000
Curtailment (gain)		0	0	0
Net Periodic Benefit Cost		37,600,000	42,900,000	21,300,000
Weighted-Average assumptions used to determine benefit obligations as of Dec. 31
Discount rate		5.05%	5.60%	6.05%
Rate of compensation increase		4.00%	4.00%	4.00%
Weighted-Average assumptions used to determine net cost for year ended Dec. 31
Discount rate		5.60%	6.05%	6.50%
Expected return on plan assets		7.25%	7.25%	8.25%
Rate of compensation increase		4.00%	4.00%	4.00%
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		1,262,500,000	1,059,500,000	1,026,000,000
Employer contributions to defined benefit plan
Employer contributions		242,900,000	6,800,000
Expected benefit payments in future
2012		110,100,000
2013		101,300,000
2014		104,400,000
2015		103,600,000
2016		103,900,000
2017-2021		535,200,000
Pension Plans [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		681,800,000	400,900,000
Pension Plans [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		580,700,000	658,600,000
Pension Plans [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		0	0
Pension Plans [Member] | Cash And Cash Equivalents [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		8,500,000	21,100,000
Pension Plans [Member] | Cash And Cash Equivalents [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		8,500,000	21,100,000
Pension Plans [Member] | Cash And Cash Equivalents [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		0	0
Pension Plans [Member] | Cash And Cash Equivalents [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		0	0
Pension Plans [Member] | U.S. Equity [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		455,100,000	464,700,000
Pension Plans [Member] | U.S. Equity [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		455,100,000	217,200,000
Pension Plans [Member] | U.S. Equity [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		0	247,500,000
Pension Plans [Member] | U.S. Equity [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		0	0
Pension Plans [Member] | International Equity [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		134,300,000	102,700,000
Pension Plans [Member] | International Equity [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		100,400,000	81,100,000
Pension Plans [Member] | International Equity [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		33,900,000	21,600,000
Pension Plans [Member] | International Equity [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		0	0
Pension Plans [Member] | U.S. Bonds [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		579,700,000	411,200,000
Pension Plans [Member] | U.S. Bonds [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		76,900,000	49,700,000
Pension Plans [Member] | U.S. Bonds [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		502,800,000	361,500,000
Pension Plans [Member] | U.S. Bonds [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		0	0
Pension Plans [Member] | International Bonds [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		84,900,000	59,800,000
Pension Plans [Member] | International Bonds [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		40,900,000	31,800,000
Pension Plans [Member] | International Bonds [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		44,000,000	28,000,000
Pension Plans [Member] | International Bonds [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		0	0
OPEB [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Amortization of Previously Unrecognized Benefit Costs	5,500,000
Net Periodic Benefit Cost
Service cost		10,400,000	11,200,000	8,700,000
Interest cost		20,800,000	21,200,000	20,500,000
Expected return on plan assets		(16,900,000)	(14,300,000)	(13,600,000)
Amortization of:
Transition obligation		300,000	300,000	300,000
Prior service cost (credit)		(1,900,000)	(11,900,000)	(12,600,000)
Actuarial loss		6,200,000	10,800,000	8,900,000
Curtailment (gain)		0	(400,000)	0
Net Periodic Benefit Cost		18,900,000	16,900,000	12,200,000
Weighted-Average assumptions used to determine benefit obligations as of Dec. 31
Discount rate		5.20%	5.70%	5.75%
Weighted-Average assumptions used to determine net cost for year ended Dec. 31
Discount rate		5.70%	5.75%	6.50%
Expected return on plan assets		7.50%	7.50%	8.25%
Assumed health care cost trend rates as of Dec. 31
Health care cost trend rate assumed for next year, Pre 65		0.08	0.075	0.075
Health care cost trend rate assumed for next year, Post 65		0.12	0.16	0.20
Rate that the cost trend rate gradually adjusts to		0.050	0.050	0.050
Year that the rate reaches the rate it is assumed to remain at (Pre 65 / Post 65)		2017/2017	2015/2016	2015/2016
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		255,400,000	216,700,000	202,600,000
Employer contributions to defined benefit plan
Employer contributions		48,400,000	4,900,000	24,300,000
Expected benefit payments in future
2012		20,200,000
2013		20,800,000
2014		22,200,000
2015		23,500,000
2016		24,700,000
2017-2021		136,400,000
OPEB [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		165,000,000	72,100,000
OPEB [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		90,400,000	144,600,000
OPEB [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		0	0
OPEB [Member] | Cash And Cash Equivalents [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		2,400,000	1,500,000
OPEB [Member] | Cash And Cash Equivalents [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		2,400,000	1,500,000
OPEB [Member] | Cash And Cash Equivalents [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		0	0
OPEB [Member] | Cash And Cash Equivalents [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		0	0
OPEB [Member] | U.S. Equity [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		113,600,000	121,700,000
OPEB [Member] | U.S. Equity [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		113,600,000	41,600,000
OPEB [Member] | U.S. Equity [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		0	80,100,000
OPEB [Member] | U.S. Equity [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		0	0
OPEB [Member] | International Equity [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		34,400,000	6,600,000
OPEB [Member] | International Equity [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		32,100,000	5,200,000
OPEB [Member] | International Equity [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		2,300,000	1,400,000
OPEB [Member] | International Equity [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		0	0
OPEB [Member] | U.S. Bonds [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		91,200,000	81,200,000
OPEB [Member] | U.S. Bonds [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		8,200,000	21,800,000
OPEB [Member] | U.S. Bonds [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		83,000,000	59,400,000
OPEB [Member] | U.S. Bonds [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		0	0
OPEB [Member] | International Bonds [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		13,800,000	5,700,000
OPEB [Member] | International Bonds [Member] | Fair Value, Inputs, Level 1 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		8,700,000	2,000,000
OPEB [Member] | International Bonds [Member] | Fair Value, Inputs, Level 2 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		5,100,000	3,700,000
OPEB [Member] | International Bonds [Member] | Fair Value, Inputs, Level 3 [Member]
Summary of fair value of pension plan assets by asset category within the fair value hierarchy
Fair value of our pension plan assets		0	0
Expected Medicare Part D Subsidy [Member]
Expected benefit payments in future
2012		(900,000)
2013		0
2014		0
2015		0
2016		0
2017-2021		0
Pension, Qualified [Member] | Pension Plans [Member]
Employer contributions to defined benefit plan
Employer contributions		236,400,000	0	270,000,000
Pension, Non-Qualified [Member] | Pension Plans [Member]
Employer contributions to defined benefit plan
Employer contributions		$ 6,500,000	$ 6,800,000	$ 5,800,000
Cash Balance Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Loss Contingency Range Of Possible Loss, Per Share, Maximum		$ 0.04

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Long-Term Debt and Capital Lease Obligations (Tables)

12 Months Ended

Dec. 31, 2011

Long-Term Debt and Capital Lease Obligations (Tables) [Abstract]

Long-term debt outstanding maturities and sinking fund requirements

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

	(Millions of Dollars)
2012	$	20.3
2013	396.3
2014	322.4
2015	399.5
2016	27.4
Thereafter	3,375.5
Total	$	4,541.4

Summary of capitalized leased facilities

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

Capital Lease Assets	2011			2010
	(Millions of Dollars)
Leased Facilities
Long-term power purchase commitment	$	140.3		$	140.3
Accumulated amortization	(81.1		)	(75.5		)
Total Leased Facilities	$	59.2		$	64.8

Future minimum lease payments under capital lease and present value of net minimum lease payments

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

	(Millions of Dollars)
2012	$	38.9
2013	40.4
2014	41.9
2015	43.5
2016	45.1
Thereafter	85.4
Total Minimum Lease Payments	295.2
Less:  Estimated Executory Costs	(74.9		)
Net Minimum Lease Payments	220.3
Less:  Interest	(87.9		)
Present Value of Net
Minimum Lease Payments	132.4
Less:  Due Currently	(12.4		)
	$	120.0

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Short-Term Debt

12 Months Ended

Dec. 31, 2011

Short-term Debt [Abstract]

SHORT-TERM DEBT

SHORT-TERM DEBT

Short-term notes payable balances and their corresponding weighted-average interest rates as of December 31 consist of:

	2011				2010
			Interest				Interest
Short-Term Debt	Balance		Rate		Balance		Rate
	(Millions of Dollars, except for percentages)
Commercial paper	$	669.9	0.27	%	$	657.9	0.30	%

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

	2011			2010
	(Millions of Dollars, except for percentages)
Maximum Short-Term Debt Outstanding	$	717.3		$	821.0
Average Short-Term Debt Outstanding	$	505.1		$	528.7
Weighted-Average Interest Rate	0.25		%	0.32		%

Wisconsin Energy, Wisconsin Electric and Wisconsin Gas have entered into bank back-up credit facilities to maintain short-term credit liquidity which, among other terms, require the companies to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 70%, 65% and 65%, respectively.

As of December 31, 2011, we had approximately $1.2 billion of available undrawn lines under our bank back-up credit facilities and approximately $669.9 million of commercial paper outstanding that was supported by the available lines of credit. Our bank back-up credit facilities expire in December 2013.

The Wisconsin Energy, Wisconsin Electric and Wisconsin Gas bank back-up credit facilities contain customary covenants, including certain limitations on the respective companies' ability to sell assets. The credit facilities also contain customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, ERISA defaults and change of control. In addition, pursuant to the terms of Wisconsin Energy's credit agreement, Wisconsin Energy must ensure that certain of its subsidiaries comply with several of the covenants contained therein.

As of December 31, 2011, we were in compliance with all financial covenants.