10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period EndedSeptember 30, 2012

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

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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer [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]

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date (September 30, 2012):

Common Stock, $.01 Par Value, 230,070,094 shares outstanding.

Form 10-Q

WISCONSIN ENERGY CORPORATION

_______________________

FORM 10-Q REPORT FOR THE QUARTER ENDED SEPTEMBER 30, 2012

	TABLE OF CONTENTS
Item		Page
	Introduction	7
	Part I -- Financial Information
1.	Financial Statements
	Consolidated Condensed Income Statements	8
	Consolidated Condensed Balance Sheets	9
	Consolidated Condensed Statements of Cash Flows	10
	Notes to Consolidated Condensed Financial Statements	11
2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	24
3.	Quantitative and Qualitative Disclosures About Market Risk	40
4.	Controls and Procedures	40
	Part II -- Other Information
1.	Legal Proceedings	40
1A.	Risk Factors	41
2.	Unregistered Sales of Equity Securities and Use of Proceeds	42
6.	Exhibits	42
	Signatures	43

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Form 10-Q

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 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
Federal and State Regulatory Agencies
CFTC	Commodity Futures Trading Commission
DOE	United States Department of Energy
DOJ	Wisconsin Department of Justice
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
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CSAPR	Cross-State Air Pollution Rule
MATS	Mercury and Air Toxics Standards
NOV	Notice of Violation
SO2	Sulfur Dioxide
Other Terms and Abbreviations
AQCS	Air Quality Control System
ARRs	Auction Revenue Rights
Compensation Committee	Compensation Committee of the Board of Directors
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act
ERISA	Employee Retirement Income Security Act of 1974
Exchange Act	Securities Exchange Act of 1934, as amended
FTRs	Financial Transmission Rights
Junior Notes	Wisconsin Energy's 2007 Series A Junior Subordinated Notes due 2067 issued in May 2007

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Form 10-Q

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:
LMP	Locational Marginal Price
MISO	Midwest Independent Transmission System Operator, Inc.
OTC	Over-the-Counter
Plan	The Wisconsin Energy Corporation Retirement Account Plan
Point Beach	Point Beach Nuclear Power Plant
PTF	Power the Future
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)
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
FASB	Financial Accounting Standards Board
GAAP	Generally Accepted Accounting Principles
OPEB	Other Post-Retirement Employee Benefits

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Form 10-Q

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, as amended (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.

• 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.

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Form 10-Q

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION -- (CONT'D)

• Current and future litigation, regulatory investigations, proceedings or inquiries, including FERC matters and Internal Revenue Service (IRS) audits and other tax matters.

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

• Other factors affecting our ability to access the capital markets, including general capital market conditions; our capitalization structure; market perceptions of the utility industry, us or 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, including rules recently adopted and/or proposed by the Commodity Futures Trading Commission (CFTC) that may impact our hedging activities and related costs, and those relating to disclosures regarding the use of conflict minerals.

• 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 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 our Annual Report on Form 10-K for the year ended December 31, 2011.

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.

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Form 10-Q

INTRODUCTION

Wisconsin Energy Corporation is a diversified holding company which conducts its operations primarily in two reportable segments: 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 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, which serves electric customers in Wisconsin and the Upper Peninsula of Michigan, gas customers in Wisconsin and steam customers in metropolitan Milwaukee, Wisconsin; and Wisconsin Gas, which serves gas customers in Wisconsin. Wisconsin Electric and Wisconsin Gas operate under the trade name of "We Energies."

Non-Utility Energy Segment:   Our non-utility energy segment consists primarily of We Power. We Power was formed in 2001 to design, construct, own and lease to Wisconsin Electric the new generating capacity included in our PTF strategy. See Item 1. Business and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2011 Annual Report on Form 10-K for more information on PTF.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC. We have condensed or omitted some information and note disclosures normally included in financial statements prepared in accordance with GAAP pursuant to these rules and regulations. This Form 10-Q, including the financial statements contained herein, should be read in conjunction with our 2011 Annual Report on Form 10-K, including the financial statements and notes therein.

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PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WISCONSIN ENERGY CORPORATION
CONSOLIDATED CONDENSED INCOME STATEMENTS
(Unaudited)
	Three Months Ended September 30				Nine Months Ended September 30
	2012		2011		2012		2011
	(Millions of Dollars, Except Per Share Amounts)
Operating Revenues	$	1,039.3	$	1,052.8	$	3,175.2	$	3,373.2
Operating Expenses
Fuel and purchased power	336.4		350.9		848.9		904.5
Cost of gas sold	55.5		69.2		368.0		533.4
Other operation and maintenance	244.6		296.9		798.8		909.3
Depreciation and amortization	91.8		82.6		269.7		246.2
Property and revenue taxes	30.4		28.9		90.9		85.5
Total Operating Expenses	758.7		828.5		2,376.3		2,678.9
Operating Income	280.6		224.3		798.9		694.3
Equity in Earnings of Transmission Affiliate	17.1		15.7		48.9		46.4
Other Income, net	9.0		16.2		33.6		43.1
Interest Expense, net	60.9		56.8		181.3		177.6
Income from Continuing Operations Before Income Taxes	245.8		199.4		700.1		606.2
Income Tax Expense	89.7		69.6		252.6		207.5
Income from Continuing Operations	156.1		129.8		447.5		398.7
Income from Discontinued Operations, Net of Tax	—		—		—		11.5
Net Income	$	156.1	$	129.8	$	447.5	$	410.2
Earnings Per Share (Basic)
Continuing operations	$	0.68	$	0.56	$	1.94	$	1.71
Discontinued operations	—		—		—		0.05
Total Earnings Per Share (Basic)	$	0.68	$	0.56	$	1.94	$	1.76
Earnings Per Share (Diluted)
Continuing operations	$	0.67	$	0.55	$	1.92	$	1.69
Discontinued operations	—		—		—		0.05
Total Earnings Per Share (Diluted)	$	0.67	$	0.55	$	1.92	$	1.74
Weighted Average Common Shares Outstanding (Millions)
Basic	230.4		232.2		230.4		233.2
Diluted	232.9		234.9		233.1		236.0
Dividends Per Share of Common Stock	$	0.30	$	0.26	$	0.90	$	0.78
The accompanying Notes to Consolidated Condensed Financial Statements are an integral part of these financial statements.

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Form 10-Q

WISCONSIN ENERGY CORPORATION
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited)
	September 30, 2012			December 31, 2011
	(Millions of Dollars)
Assets
Property, Plant and Equipment
In service	$	14,086.9		$	12,977.7
Accumulated depreciation	(3,972.4		)	(3,797.8		)
	10,114.5			9,179.9
Construction work in progress	269.4			921.3
Leased facilities, net	54.9			59.2
Net Property, Plant and Equipment	10,438.8			10,160.4
Investments
Equity investment in transmission affiliate	372.5			349.7
Other	36.4			43.6
Total Investments	408.9			393.3
Current Assets
Cash and cash equivalents	13.0			14.1
Restricted cash	9.5			45.5
Accounts receivable, net	298.6			349.4
Income taxes receivable	48.4			155.1
Accrued revenues	178.5			252.7
Materials, supplies and inventories	342.1			382.0
Prepayments and other	194.7			227.4
Total Current Assets	1,084.8			1,426.2
Deferred Charges and Other Assets
Regulatory assets	1,280.4			1,238.7
Goodwill	441.9			441.9
Other	179.9			201.6
Total Deferred Charges and Other Assets	1,902.2			1,882.2
Total Assets	$	13,834.7		$	13,862.1
Capitalization and Liabilities
Capitalization
Common equity	$	4,147.2		$	3,963.3
Preferred stock of subsidiary	30.4			30.4
Long-term debt	4,240.6			4,614.3
Total Capitalization	8,418.2			8,608.0
Current Liabilities
Long-term debt due currently	381.1			32.6
Short-term debt	453.2			669.9
Accounts payable	277.7			325.7
Accrued payroll and benefits	101.5			105.9
Other	173.5			230.4
Total Current Liabilities	1,387.0			1,364.5
Deferred Credits and Other Liabilities
Regulatory liabilities	872.9			902.0
Deferred income taxes - long-term	1,994.2			1,696.1
Deferred revenue, net	714.1			754.5
Pension and other benefit obligations	149.6			222.7
Other	298.7			314.3
Total Deferred Credits and Other Liabilities	4,029.5			3,889.6
Total Capitalization and Liabilities	$	13,834.7		$	13,862.1
The accompanying Notes to Consolidated Condensed Financial Statements are an integral part of these financial statements.

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WISCONSIN ENERGY CORPORATION
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months Ended September 30
	2012			2011
	(Millions of Dollars)
Operating Activities
Net income	$	447.5		$	410.2
Reconciliation to cash
Depreciation and amortization	278.2			248.9
Deferred income taxes and investment tax credits, net	249.6			215.9
Contributions to qualified benefit plans	(100.0		)	(257.4		)
Change in - Accounts receivable and accrued revenues	118.7			136.4
Inventories	39.9			11.1
Other current assets	50.6			(18.7		)
Accounts payable	(56.5		)	(41.8		)
Accrued income taxes, net	107.6			69.1
Other current liabilities	(15.3		)	27.1
Other, net	(127.9		)	26.8
Cash Provided by Operating Activities	992.4			827.6
Investing Activities
Capital expenditures	(477.5		)	(612.2		)
Investment in transmission affiliate	(13.1		)	(6.6		)
Proceeds from asset sales	3.0			38.5
Change in restricted cash	36.0			(37.2		)
Other, net	(39.8		)	(32.8		)
Cash Used in Investing Activities	(491.4		)	(650.3		)
Financing Activities
Exercise of stock options	45.3			34.4
Purchase of common stock	(105.0		)	(135.1		)
Dividends paid on common stock	(207.4		)	(182.0		)
Issuance of long-term debt	—			720.0
Retirement and repurchase of long-term debt	(18.3		)	(464.7		)
Change in short-term debt	(216.7		)	(161.2		)
Other, net	—			1.9
Cash Used in Financing Activities	(502.1		)	(186.7		)
Change in Cash and Cash Equivalents	(1.1		)	(9.4		)
Cash and Cash Equivalents at Beginning of Period	14.1			24.5
Cash and Cash Equivalents at End of Period	$	13.0		$	15.1
The accompanying Notes to Consolidated Condensed Financial Statements are an integral part of these financial statements.

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Form 10-Q

WISCONSIN ENERGY CORPORATION

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

(Unaudited)

1 -- GENERAL INFORMATION

Our accompanying unaudited consolidated condensed financial statements should be read in conjunction with Item 8, Financial Statements and Supplementary Data, in our 2011 Annual Report on Form 10-K. In the opinion of management, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of the results of operations, cash flows and financial position in the accompanying income statements, statements of cash flows and balance sheets. The results of operations for the three and nine months ended September 30, 2012 are not necessarily indicative of the results which may be expected for the entire fiscal year 2012 because of seasonal and other factors.

2 -- NEW ACCOUNTING PRONOUNCEMENTS

Presentation of Comprehensive Income:   In June 2011, the Financial Accounting Standards Board (FASB) issued guidance on the presentation of comprehensive income. 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. This guidance is effective for fiscal years and interim periods beginning after December 15, 2011 and must be applied retrospectively. We adopted this guidance on January 1, 2012, and it did not have any material impact on us.

Fair Value Measurement:   In May 2011, the FASB issued guidance amending existing guidance for measuring fair value and expanding required disclosures about fair value measurements. This guidance is effective for fiscal years and interim periods beginning after December 15, 2011 and must be applied prospectively. We adopted this guidance on January 1, 2012, and it did not have any material impact on us.

3 -- COMMON EQUITY

Stock Option Activity:   During the first nine months of 2012, the Compensation Committee of the Board of Directors (Compensation Committee) granted 938,770 non-qualified stock options that had an estimated fair value of $3.34 per share. During the first nine months of 2011, the Compensation Committee granted 458,180 non-qualified stock options that had an estimated fair value of $3.17 per share. The following assumptions were used to value the options using a binomial option pricing model:

	2012		2011
Risk-free interest rate	0.1% - 2.0%		0.2% - 3.4%
Dividend yield	3.9	%	3.9	%
Expected volatility	19.0	%	19.0	%
Expected forfeiture rate	2.0	%	2.0	%
Expected life (years)	5.9		5.5

The risk-free interest rate is based on the U.S. Treasury interest rate whose term is consistent with the expected life of the stock options. Dividend yield, expected volatility, expected forfeiture rate and expected life assumptions are based on our historical experience.

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The following is a summary of our stock option activity for the three and nine months ended September 30, 2012:

					Weighted-
					Average
			Weighted-		Remaining	Aggregate
	Number of		Average		Contractual Life	Intrinsic Value
Stock Options	Options		Exercise Price		(Years)	(Millions)
Outstanding as of July 1, 2012	9,571,531		$	23.42
Granted	—		$	—
Exercised	(370,020	)	$	17.89
Forfeited	—		$	—
Outstanding as of September 30, 2012	9,201,511		$	23.65
Outstanding as of January 1, 2012	10,638,750		$	21.65
Granted	938,770		$	34.88
Exercised	(2,368,289	)	$	19.11
Forfeited	(7,720	)	$	26.94
Outstanding as of September 30, 2012	9,201,511		$	23.65	5.4	$	129.0
Exercisable as of September 30, 2012	7,493,036		$	21.98	4.7	$	117.6

The intrinsic value of options exercised was $8.3 million and $42.1 million for the three and nine months ended September 30, 2012, and $3.6 million and $22.6 million for the same periods in 2011, respectively. Cash received from options exercised was $45.3 million and $34.4 million for the nine months ended September 30, 2012 and 2011, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was zero and approximately $9.0 million, respectively.

All outstanding stock options to purchase shares of common stock were included in the computation of diluted earnings per share during the third quarter and first nine months of 2012.

The following table summarizes information about stock options outstanding as of September 30, 2012:

	Options Outstanding				Options Exercisable
		Weighted-Average				Weighted-Average
				Remaining				Remaining
	Number of	Exercise		Contractual	Number of	Exercise		Contractual
Range of Exercise Prices	Options	Price		Life (Years)	Options	Price		Life (Years)
$12.71 to $19.74	1,874,519	$	18.29	2.6	1,874,519	$	18.29	2.6
$21.11 to $24.92	5,940,822	$	23.13	5.5	5,491,282	$	22.99	5.4
$29.35 to $34.88	1,386,170	$	33.09	8.9	127,235	$	32.67	8.9
	9,201,511	$	23.65	5.4	7,493,036	$	21.98	4.7

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The following table summarizes information about our non-vested options during the three and nine months ended September 30, 2012:

			Weighted-Average
Non-Vested Stock Options	Number of Options		Fair Value
Non-vested as of July 1, 2012	1,726,165		$	3.31
Granted	—		$	—
Vested	(17,690	)	$	3.31
Forfeited	—		$	—
Non-vested as of September 30, 2012	1,708,475		$	3.31
Non-vested as of January 1, 2012	3,103,770		$	3.78
Granted	938,770		$	3.34
Vested	(2,326,345	)	$	3.96
Forfeited	(7,720	)	$	3.25
Non-vested as of September 30, 2012	1,708,475		$	3.31

As of September 30, 2012, total compensation costs related to non-vested stock options not yet recognized was approximately $1.7 million, which is expected to be recognized over the next 18 months on a weighted-average basis.

Restricted Shares:   During the first nine months of 2012, the Compensation Committee granted 94,959 restricted shares to directors, officers and other key employees. 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 have voting rights and are entitled to dividends in the same manner as other shareholders.

The following restricted stock activity occurred during the three and nine months ended September 30, 2012:

			Weighted-Average
Restricted Shares	Number of Shares		Grant Date Fair Value
Outstanding as of July 1, 2012	194,697
Granted	—		$	—
Released	—		$	—
Forfeited	(1,213	)	$	31.35
Outstanding as of September 30, 2012	193,484
Outstanding as of January 1, 2012	192,558
Granted	94,959		$	34.46
Released	(88,422	)	$	30.65
Forfeited	(5,611	)	$	30.94
Outstanding as of September 30, 2012	193,484

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 zero and $3.3 million for the three and nine months ended September 30, 2012, and zero and $2.3 million for the same periods in 2011, respectively. The actual tax benefit realized for the tax deductions from released restricted shares was zero for the three and nine months ended September 30, 2012, and zero and $0.7 million for the same periods in 2011, respectively.

As of September 30, 2012, total compensation cost related to restricted stock not yet recognized was approximately $3.3 million, which is expected to be recognized over the next 22 months on a weighted-average basis.

Performance Units:   In January 2012 and 2011, the Compensation Committee granted 346,570 and 435,690 performance units, respectively, to officers and other key employees under the Wisconsin Energy Performance Unit

September 2012 13 Wisconsin Energy Corporation

Form 10-Q

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 period based on our estimate of the final expected value of the awards. Performance units earned as of December 31, 2011 and 2010 vested and were settled during the first quarter of 2012 and 2011, and had a total intrinsic value of $26.7 million and $12.6 million, respectively. The actual tax benefit realized for the tax deductions from the settlement of performance units was approximately $9.7 million and $4.3 million, respectively. As of September 30, 2012, total compensation cost related to performance units not yet recognized was approximately $18.4 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 us 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. See Note I -- Common Equity in our 2011 Annual Report on Form 10-K for additional information on these and other restrictions.

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

Comprehensive Income:   Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to owners.

There was no material other comprehensive income for the three and nine months ended September 30, 2012 or 2011.

Share Repurchase Program:   In May 2011, our Board of Directors authorized a share repurchase program that allows us to repurchase up to $300 million of our common stock through the end of 2013. Through September 30, 2012, we have repurchased $114.0 million of our common stock pursuant to this program at an average cost of $31.45 per share. The share 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. In addition, through our independent agents, we purchase shares on the open market to fulfill exercised stock options and restricted stock awards. The following table identifies the shares purchased by the Company in the following periods:

	Nine Months Ended September 30
	2012			2011
	Shares	Cost		Shares	Cost
	(In Millions)
Under May 2011 share repurchase program	0.4	$	14.0	2.5	$	75.0
To fulfill exercised stock options and restricted stock awards	2.5	91.0		1.9	60.1
Total	2.9	$	105.0	4.4	$	135.1

September 2012 14 Wisconsin Energy Corporation

Form 10-Q

4 -- ASSET SALES, DIVESTITURES AND DISCONTINUED OPERATIONS

The following table summarizes the net impacts of discontinued operations on our earnings for the three and nine months ended September 30:

	Three Months Ended September 30				Nine Months Ended September 30
	2012		2011		2012		2011
	(Millions of Dollars)
Income from Continuing Operations	$	156.1	$	129.8	$	447.5	$	398.7
Income from Discontinued Operations, Net of Tax (a)	—		—		—		11.5
Net Income	$	156.1	$	129.8	$	447.5	$	410.2
(a) During 2011, we reached a 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 Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corp. (WPL) for our net book value, including working capital, of approximately $38 million. This transaction was treated as a sale of an asset.

5 -- LONG-TERM DEBT

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.

In January 2011, we issued a total of $420 million of 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 Oak Creek expansion Unit 2 (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 and Wisconsin Electric related to OC 2.

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

As of September 30, 2012, we were in compliance with all financial covenants.

6 -- 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:

September 2012 15 Wisconsin Energy Corporation

Form 10-Q

Level 1 -- Pricing inputs are unadjusted quoted prices available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Instruments in this category consist of financial instruments such as exchange-traded derivatives, cash equivalents and restricted cash investments.

Level 2 -- Pricing inputs are other than quoted prices in active markets, which are either directly or indirectly observable as of the reporting date, and fair value is determined through the use of models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as Over-the-Counter (OTC) forwards and options.

Level 3 -- Pricing inputs include significant inputs that are generally less observable from objective sources. The inputs in the determination of fair value require significant management judgment or estimation. At each balance sheet date, we perform an analysis of all instruments subject to fair value reporting and include in Level 3 all instruments whose fair value is based on significant unobservable inputs.

In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, an instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the instrument.

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

Recurring Fair Value Measures	As of September 30, 2012
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	9.5	$	—	$	—	$	9.5
Derivatives	11.0		12.9		7.3		31.2
Total	$	20.5	$	12.9	$	7.3	$	40.7
Liabilities:
Derivatives	$	—	$	2.1	$	—	$	2.1
Total	$	—	$	2.1	$	—	$	2.1

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

Restricted cash consists of certificates of deposit and government backed interest bearing securities and represents the settlement we received from the United States Department of Energy (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,

September 2012 16 Wisconsin Energy Corporation

Form 10-Q

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:

	Three Months Ended September 30						Nine Months Ended September 30
	2012			2011			2012			2011
	(Millions of Dollars)
Beginning Balance	$	9.9		$	14.6		$	5.7		$	5.9
Realized and unrealized gains (losses)	—			—			—			—
Purchases	—			—			10.9			16.1
Issuances	—			—			—			—
Settlements	(2.6		)	(4.5		)	(9.3		)	(11.9		)
Transfers in and/or out of Level 3	—			—			—			—
Balance as of September 30	$	7.3		$	10.1		$	7.3		$	10.1
Change in unrealized gains (losses) relating to instruments still held as of September 30	$	—		$	—		$	—		$	—

Derivative instruments reflected in Level 3 of the hierarchy include MISO Financial Transmission Rights (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 7 -- Derivative Instruments for further information on the offset to regulatory assets and liabilities.

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

	September 30, 2012				December 31, 2011
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	26.3	$	30.4	$	25.1
Long-term debt, including current portion	$	4,523.2	$	5,256.8	$	4,541.4	$	5,179.9

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. Based on these assessments, the above items have been classified within Level 2.

7 -- 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 Public Service Commission of Wisconsin (PSCW).

September 2012 17 Wisconsin Energy Corporation

Form 10-Q

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 September 30, 2012, we recognized $3.0 million in regulatory assets and $23.0 million in regulatory liabilities related to derivatives in comparison to $29.6 million in regulatory assets and $21.7 million in regulatory liabilities as of December 31, 2011.

We record our current derivative assets on the balance sheet in prepayments and other current assets and the current portion of the liabilities in other current liabilities. The long-term portion of our derivative assets of $1.6 million is recorded in other deferred charges and other assets as of September 30, 2012, and the long-term portion of our derivative liabilities of $0.2 million is recorded in other deferred credits and other liabilities as of September 30, 2012. Our Consolidated Condensed Balance Sheets as of September 30, 2012 and

December 31, 2011 include:

	September 30, 2012				December 31, 2011
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	12.0	$	—	$	2.1	$	9.1
Fuel Oil	0.9		—		0.3		0.1
FTRs	7.3		—		5.7		—
Coal	11.0		2.1		12.5		—
Total	$	31.2	$	2.1	$	20.6	$	9.2

Our Consolidated Condensed 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) were as follows:

	Three Months Ended September 30, 2012				Three Months Ended September 30, 2011
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)
Natural Gas	17.2 million Dth	$	(5.3	)	15.7 million Dth	$	(10.5	)
Fuel Oil	1.7 million gallons	0.1			2.2 million gallons	2.4
FTRs	5,927 MW	2.9			5,896 MW	5.2
Total		$	(2.3	)		$	(2.9	)

	Nine Months Ended September 30, 2012				Nine Months Ended September 30, 2011
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)
Natural Gas	56.0 million Dth	$	(35.7	)	54.0 million Dth	$	(27.7	)
Fuel Oil	5.5 million gallons	1.5			8.8 million gallons	4.9
FTRs	16,581 MW	5.1			18,439 MW	10.5
Total		$	(29.1	)		$	(12.3	)

As of September 30, 2012 and December 31, 2011, we posted collateral of $0.4 million and $11.9 million, respectively, in our margin accounts. These amounts are recorded on the balance sheets in other current assets.

September 2012 18 Wisconsin Energy Corporation

Form 10-Q

8 -- BENEFITS

The components of our net periodic pension and Other Post-Retirement Employee Benefits (OPEB) costs for the three and nine months ended September 30 were as follows:

	Pension Costs
	Three Months Ended September 30						Nine Months Ended September 30
Benefit Plan Cost Components	2012			2011			2012			2011
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	5.5		$	4.0		$	16.3		$	11.9
Interest cost	16.4			16.9			49.2			50.7
Expected return on plan assets	(22.5		)	(20.5		)	(67.3		)	(61.6		)
Amortization of:
Prior service cost	0.5			0.6			1.7			1.7
Actuarial loss	10.2			8.4			30.4			25.5
Net Periodic Benefit Cost	$	10.1		$	9.4		$	30.3		$	28.2

	OPEB Costs
	Three Months Ended September 30						Nine Months Ended September 30
Benefit Plan Cost Components	2012			2011			2012			2011
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	2.6		$	2.6		$	7.8		$	7.8
Interest cost	5.1			5.2			15.3			15.6
Expected return on plan assets	(4.8		)	(4.3		)	(14.4		)	(12.7		)
Amortization of:
Transition obligation	—			—			0.2			0.2
Prior service (credit)	(0.5		)	(0.4		)	(1.4		)	(1.4		)
Actuarial loss	1.9			1.7			5.4			4.7
Net Periodic Benefit Cost	$	4.3		$	4.8		$	12.9		$	14.2

During the first nine months of 2012 and 2011, we contributed $100.0 million and $257.4 million, respectively, to our qualified benefit plans. Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates.

Postemployment Benefits:   Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $5.2 million as of September 30, 2012 and $15.3 million as of December 31, 2011.

September 2012 19 Wisconsin Energy Corporation

Form 10-Q

9 -- SEGMENT INFORMATION

Summarized financial information concerning our reportable segments for the three and nine months ended September 30, 2012 and 2011 is shown in the following table:

	Reportable Segments							Eliminations
	Energy				Corporate &			& Reconciling			Total
Three Months Ended	Utility		Non-Utility		Other (a)			Items			Consolidated
	(Millions of Dollars)
September 30, 2012
Operating Revenues (b)	$	1,023.3	$	112.6	$	0.3		$	(96.9	)	$	1,039.3
Other Operation and Maintenance	$	334.1	$	4.3	$	2.0		$	(95.8	)	$	244.6
Depreciation and Amortization	$	74.7	$	16.8	$	0.3		$	—		$	91.8
Operating Income (Loss)	$	191.0	$	91.5	$	(1.9	)	$	—		$	280.6
Equity in Earnings of Unconsolidated Affiliates	$	17.1	$	—	$	—		$	—		$	17.1
Interest Expense, Net	$	31.4	$	16.6	$	12.9		$	—		$	60.9
Income Tax Expense (Benefit)	$	65.6	$	29.2	$	(5.1	)	$	—		$	89.7
Income from Discontinued Operations, Net of Tax	$	—	$	—	$	—		$	—		$	—
Net Income (Loss)	$	119.8	$	45.8	$	156.1		$	(165.6	)	$	156.1
Capital Expenditures	$	161.2	$	1.8	$	0.5		$	—		$	163.5
September 30, 2011
Operating Revenues (b)	$	1,036.7	$	113.0	$	0.2		$	(97.1	)	$	1,052.8
Other Operation and Maintenance	$	387.0	$	4.9	$	1.0		$	(96.0	)	$	296.9
Depreciation and Amortization	$	64.1	$	18.3	$	0.2		$	—		$	82.6
Operating Income (Loss)	$	135.6	$	89.8	$	(1.1	)	$	—		$	224.3
Equity in Earnings of Unconsolidated Affiliates	$	15.7	$	—	$	(0.1	)	$	—		$	15.6
Interest Expense, Net	$	26.8	$	16.9	$	13.2		$	(0.1	)	$	56.8
Income Tax Expense (Benefit)	$	45.5	$	28.4	$	(4.3	)	$	—		$	69.6
Income from Discontinued Operations, Net of Tax	$	—	$	—	$	—		$	—		$	—
Net Income (Loss)	$	95.0	$	44.6	$	129.7		$	(139.5	)	$	129.8
Capital Expenditures	$	252.1	$	7.3	$	5.7		$	—		$	265.1

September 2012 20 Wisconsin Energy Corporation

Form 10-Q

	Reportable Segments							Eliminations
	Energy				Corporate &			& Reconciling			Total
Nine Months Ended	Utility		Non-Utility		Other (a)			Items			Consolidated
	(Millions of Dollars)
September 30, 2012
Operating Revenues (b)	$	3,132.2	$	332.2	$	0.9		$	(290.1	)	$	3,175.2
Other Operation and Maintenance	$	1,069.0	$	11.7	$	4.7		$	(286.6	)	$	798.8
Depreciation and Amortization	$	218.8	$	50.3	$	0.6		$	—		$	269.7
Operating Income (Loss)	$	533.2	$	270.2	$	(4.5	)	$	—		$	798.9
Equity in Earnings of Unconsolidated Affiliates	$	48.9	$	—	$	(0.1	)	$	—		$	48.8
Interest Expense, Net	$	92.6	$	50.1	$	38.9		$	(0.3	)	$	181.3
Income Tax Expense (Benefit)	$	182.6	$	87.2	$	(17.2	)	$	—		$	252.6
Income from Discontinued Operations, Net of Tax	$	—	$	—	$	—		$	—		$	—
Net Income (Loss)	$	338.7	$	133.2	$	448.0		$	(472.4	)	$	447.5
Capital Expenditures	$	468.2	$	5.6	$	3.7		$	—		$	477.5
September 30, 2011
Operating Revenues (b)	$	3,331.1	$	327.5	$	0.6		$	(286.0	)	$	3,373.2
Other Operation and Maintenance	$	1,176.7	$	11.5	$	3.8		$	(282.7	)	$	909.3
Depreciation and Amortization	$	191.4	$	54.3	$	0.5		$	—		$	246.2
Operating Income (Loss)	$	436.7	$	261.7	$	(4.1	)	$	—		$	694.3
Equity in Earnings of Unconsolidated Affiliates	$	46.4	$	—	$	(0.3	)	$	—		$	46.1
Interest Expense, Net	$	82.1	$	49.8	$	46.0		$	(0.3	)	$	177.6
Income Tax Expense (Benefit)	$	145.9	$	84.2	$	(22.6	)	$	—		$	207.5
Income from Discontinued Operations, Net of Tax	$	—	$	—	$	11.5		$	—		$	11.5
Net Income (Loss)	$	297.1	$	127.9	$	410.0		$	(424.8	)	$	410.2
Capital Expenditures	$	583.1	$	22.2	$	6.9		$	—		$	612.2

(a) Corporate & Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark LLC, as well as interest on corporate debt.

(b) An elimination for intersegment revenues is included in Operating Revenues. This elimination is primarily between WePower and Wisconsin Electric.

10 -- 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 that 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 less than one year. 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

September 2012 21 Wisconsin Energy Corporation

Form 10-Q

remaining term of approximately 10 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 $270.2 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 for the nine months ended September 30, 2012 and 2011 were $44.5 million and $51.0 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contracts.

11 -- COMMITMENTS AND CONTINGENCIES

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 Wisconsin Department of Natural Resources (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 September 30, 2012, 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.

Valley Power Plant Title V Air Permit:   The WDNR renewed Valley Power Plant's (VAPP) Title V operating permit in February 2011. The term of the permit is five years. Sierra Club and Clean Wisconsin requested and were granted an administrative hearing before the WDNR on certain conditions of the permit. The case has been stayed. In March 2011, the Sierra Club also petitioned the United States Environmental Protection Agency (EPA) for additional reductions and monitoring for particulate matter, and revisions to certain applicable requirements. No timeline has been set by the EPA to respond to that petition. In May 2012, the Sierra Club filed a notice of intent to bring suit to force the EPA to issue a response to that petition.

We believe that the permit was properly issued and that the plant is in compliance with all applicable regulations and standards. However, if as a result of either proceeding the permit is remanded to the WDNR, the plant will continue to operate under the previous operating permit.

We have made significant progress on the four voluntary goals we submitted in a December 2011 letter to the EPA. Through the end of the third quarter: (1) we achieved reductions in annual Sulfur Dioxide (SO₂) emissions from the plant to no more than 4,500 tons (a 65% decrease from 2001 emission levels); (2) the planned conversion of the plant from coal to natural gas would eliminate the requirement to meet the Mercury and Air Toxics Standards (MATS) rules and, therefore, the need for a dry sorbent injection system; (3) we held open houses and tours of VAPP 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) we announced plans for converting VAPP to natural gas fuel by the end of 2015, provided that we can obtain authorization from the PSCW to do so.

September 2012 22 Wisconsin Energy Corporation

Form 10-Q

Divested Assets:   Pursuant to the sale of the Point Beach Nuclear Power Plant (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.

Cash Balance Pension Plan:   In June 2009, a lawsuit was filed by Alan M. Downes, a former employee, against the Wisconsin Energy Corporation Retirement Account Plan (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. The court approved the settlement on April 3, 2012 and issued its written order on April 20, 2012. Substantially all payments to class members have been made pursuant to the settlement. We do not anticipate further charges as a result of the settlement.

Income Taxes:   During the first quarter of 2012, the IRS issued guidance applicable to taxpayers that have taken positions within prior year tax returns relating to the conversion of capitalized assets to repair expense. As a result of this guidance, we have decreased our unrecognized tax benefits by approximately $7.4 million, exclusive of accrued interest.

12 -- SUPPLEMENTAL CASH FLOW INFORMATION

During the nine months ended September 30, 2012, we paid $137.9 million in interest, net of amounts capitalized, and received $107.0 million in net refunds from income taxes. During the nine months ended September 30, 2011, we paid $138.1 million in interest, net of amounts capitalized, and received $62.7 million in net refunds from income taxes.

As of September 30, 2012 and 2011, the amount of accounts payable related to capital expenditures was $25.3 million and $19.2 million, respectively.

During the nine months ended September 30, 2012 and 2011, total amortization of deferred revenue was $41.2 million and $40.7 million, respectively.

During the nine months ended September 30, 2012 and 2011, our equity in earnings from ATC was $48.9 million and $46.4 million, respectively. During the nine months ended September 30, 2012 and 2011, distributions received from ATC were $39.0 million and $37.0 million, respectively.

September 2012 23 Wisconsin Energy Corporation

Form 10-Q

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS -- THREE MONTHS ENDED SEPTEMBER 30, 2012

CONSOLIDATED EARNINGS

The following table compares our operating income by business segment and our net income during the third quarter of 2012 with the third quarter of 2011, including favorable (better (B)) or unfavorable (worse (W)) variances:

	Three Months Ended September 30
	2012			B (W)			2011
	(Millions of Dollars)
Utility Energy Segment	$	191.0		$	55.4		$	135.6
Non-Utility Energy Segment	91.5			1.7			89.8
Corporate and Other	(1.9		)	(0.8		)	(1.1		)
Total Operating Income	280.6			56.3			224.3
Equity in Earnings of Transmission Affiliate	17.1			1.4			15.7
Other Income, net	9.0			(7.2		)	16.2
Interest Expense, net	60.9			(4.1		)	56.8
Income from Continuing Operations Before Income Taxes	245.8			46.4			199.4
Income Tax Expense	89.7			(20.1		)	69.6
Income from Continuing Operations	$	156.1		$	26.3		$	129.8
Diluted Earnings Per Share from Continuing Operations	$	0.67		$	0.12		$	0.55

UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Our utility energy segment contributed $191.0 million of operating income during the third quarter of 2012, an increase of $55.4 million, or 40.9%, compared with the third quarter of 2011. The following table summarizes the operating income of this segment between the comparative quarters:

	Three Months Ended September 30
Utility Energy Segment	2012		B (W)			2011
	(Millions of Dollars)
Operating Revenues
Electric	$	901.2	$	1.0		$	900.2
Gas	116.7		(13.6		)	130.3
Other	5.4		(0.8		)	6.2
Total Operating Revenues	1,023.3		(13.4		)	1,036.7
Operating Expenses
Fuel and Purchased Power	337.7		14.4			352.1
Cost of Gas Sold	55.5		13.7			69.2
Other Operation and Maintenance	334.1		52.9			387.0
Depreciation and Amortization	74.7		(10.6		)	64.1
Property and Revenue Taxes	30.3		(1.6		)	28.7
Total Operating Expenses	832.3		68.8			901.1
Operating Income	$	191.0	$	55.4		$	135.6

September 2012 24 Wisconsin Energy Corporation

Form 10-Q

Electric Utility Revenues and Sales

The following table compares electric utility operating revenues and MWh sales by customer class during the third quarter of 2012 with the third quarter of 2011:

	Three Months Ended September 30
	Electric Revenues							MWh Sales
Electric Utility Operations	2012		B (W)			2011		2012	B (W)		2011
	(Millions of Dollars)							(Thousands)
Customer Class
Residential	$	340.2	$	0.4		$	339.8	2,422.5	(28.6	)	2,451.1
Small Commercial/Industrial	284.2		5.2			279.0		2,456.3	16.6		2,439.7
Large Commercial/Industrial	200.7		(8.9		)	209.6		2,486.1	(225.5	)	2,711.6
Other - Retail	5.4		0.1			5.3		34.6	(1.1	)	35.7
Total Retail	830.5		(3.2		)	833.7		7,399.5	(238.6	)	7,638.1
Wholesale - Other	40.0		1.5			38.5		411.7	(76.2	)	487.9
Resale - Utilities	17.8		(3.1		)	20.9		596.3	70.9		525.4
Other Operating Revenues	12.9		5.8			7.1		—	—		—
Total	$	901.2	$	1.0		$	900.2	8,407.5	(243.9	)	8,651.4
Weather -- Degree Days (a)
Heating (126 Normal)								138	(18	)	156
Cooling (526 Normal)								735	62		673
(a) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year
moving average.

Our electric utility operating revenues increased by $1.0 million, or 0.1%, when compared to the third quarter of 2011.

We estimate favorable summer weather increased revenues by approximately $31 million in our Residential and Small Commercial/Industrial customer classes in 2012 compared to normal weather conditions. By comparison, we estimate that favorable weather in 2011 increased revenues for these customer classes by approximately $28 million compared to normal weather conditions.

Sales to the Large Commercial/Industrial customer class decreased by 8.3% in 2012 compared to 2011. Large Commercial/Industrial revenues decreased by approximately $8.9 million compared to 2011. We estimate that our revenues were reduced by approximately $15 million because of the planned outage at an iron ore mine of our largest customer, and the conversion to self-generation of two other large customers. If sales to the mines and the two customers that added self-generation are excluded, our MWh sales to Large Commercial/Industrial customers increased by 0.6%.

In addition, our retail revenues increased by approximately $13 million in 2012 because of rate increases in Michigan and favorable fuel recoveries in Wisconsin. Other Operating Revenues increased by approximately $5.8 million driven by the $8 million of amortization related to the DOE settlement used to offset an increase in fuel costs authorized by the PSCW. For additional information on the 2012 Michigan rate case and the DOE settlement, see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters and -- Nuclear Operations, respectively.

Fuel and Purchased Power

Our fuel and purchased power costs decreased by $14.4 million, or 4.1%, when compared to the third quarter of 2011. This decrease was primarily caused by a 2.8% decrease in total MWh sales and a reduction in our average cost of fuel and purchased power because of lower natural gas prices.

September 2012 25 Wisconsin Energy Corporation

Form 10-Q

Gas Utility Revenues, Gross Margin and Therm Deliveries

A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the third quarter of 2012 with the third quarter of 2011. We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under gas cost recovery mechanisms. Between the comparative periods, total gas operating revenues decreased by $13.6 million, or 10.4%, and cost of gas sold decreased by $13.7 million, or 19.8%.

	Three Months Ended September 30
	2012		B (W)			2011
	(Millions of Dollars)
Gas Operating Revenues	$	116.7	$	(13.6	)	$	130.3
Cost of Gas Sold	55.5		13.7			69.2
Gross Margin	$	61.2	$	0.1		$	61.1

The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the third quarter of 2012 with the third quarter of 2011:

	Three Months Ended September 30
	Gross Margin							Therm Deliveries
Gas Utility Operations	2012		B (W)			2011		2012	B (W)		2011
	(Millions of Dollars)							(Millions)
Customer Class
Residential	$	37.9	$	(0.3	)	$	38.2	46.2	(2.1	)	48.3
Commercial/Industrial	10.2		(0.1		)	10.3		33.1	(0.2	)	33.3
Interruptible	0.3		—			0.3		2.3	—		2.3
Total Retail	48.4		(0.4		)	48.8		81.6	(2.3	)	83.9
Transported Gas	11.8		0.7			11.1		269.7	69.4		200.3
Other	1.0		(0.2		)	1.2		—	—		—
Total	$	61.2	$	0.1		$	61.1	351.3	67.1		284.2
Weather -- Degree Days (a)
Heating (126 Normal)								138	(18	)	156
(a) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year
moving average.

Our gas margin is seasonal and is primarily driven by the heating needs of our customers. The third quarter gas margin is historically the lowest of the year because of the lack of heating load. Our gas margin increased by $0.1 million, or approximately 0.2%, when compared to the third quarter of 2011.

Other Operation and Maintenance Expense

Our other operation and maintenance expense decreased by $52.9 million, or approximately 13.7%, when compared to the third quarter of 2011. This decrease, which we expect to continue through the remainder of the year, is primarily due to the one year suspension of $148 million 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.

Depreciation and Amortization Expense

Our depreciation and amortization expense increased by $10.6 million, or approximately 16.5%, when compared to the third quarter of 2011 primarily because of an overall increase in utility plant in service. The Glacier Hills Wind Park went into service in December 2011. In addition, the emission control equipment for units 5 and 6 of the Oak

September 2012 26 Wisconsin Energy Corporation

Form 10-Q

Creek Air Quality Control System (AQCS) project went into service in March 2012, and for units 7 and 8 in September 2012. For additional information, see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters -- Oak Creek Air Quality Control System.

NON-UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Our non-utility energy segment consists primarily of our PTF units (Port Washington Generating Station Unit 1 (PWGS 1), Port Washington Generating Station Unit 2 (PWGS 2), Oak Creek expansion Unit 1 (OC 1) and OC 2).

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

	Three Months Ended September 30
	2012		B (W)			2011
	(Millions of Dollars)
Operating Revenues	$	112.6	$	(0.4	)	$	113.0
Operation and Maintenance Expense	4.3		0.6			4.9
Depreciation Expense	16.8		1.5			18.3
Operating Income	$	91.5	$	1.7		$	89.8

CONSOLIDATED OTHER INCOME, NET

	Three Months Ended September 30
	2012		B (W)			2011
	(Millions of Dollars)
AFUDC - Equity	$	8.9	$	(7.1	)	$	16.0
Other, net	0.1		(0.1		)	0.2
Other Income, net	$	9.0	$	(7.2	)	$	16.2

Other income, net decreased by $7.2 million, or approximately 44.4%, when compared to the third quarter of 2011. The decrease in AFUDC - Equity is primarily related to the Glacier Hills Wind Park, which went into service in December 2011, as well as the Oak Creek AQCS project which emission control equipment went into service in March 2012 for units 5 and 6 and September 2012 for units 7 and 8. For additional information, see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters -- Oak Creek Air Quality Control System.

CONSOLIDATED INTEREST EXPENSE, NET

	Three Months Ended September 30
	2012		B (W)			2011
	(Millions of Dollars)
Gross Interest Costs	$	65.0	$	(1.3	)	$	63.7
Less: Capitalized Interest	4.1		(2.8		)	6.9
Interest Expense, net	$	60.9	$	(4.1	)	$	56.8

Our gross interest costs increased by $1.3 million, or approximately 2.0%, when compared to the third quarter of 2011 primarily because of the issuance of $300 million of long-term debt by Wisconsin Electric in September 2011.

September 2012 27 Wisconsin Energy Corporation

Form 10-Q

Our capitalized interest decreased by $2.8 million primarily because of lower construction work in progress. As a result, our net interest expense increased by $4.1 million, or 7.2%, as compared to the third quarter of 2011.

CONSOLIDATED INCOME TAX EXPENSE

For the third quarter of 2012, our effective tax rate applicable to continuing operations was 36.5% compared to 34.9% for the third quarter of 2011, primarily due to a decrease in the projected 2012 annual tax benefits associated with AFUDC - Equity. For additional information, see Note H -- Income Taxes in our 2011 Annual Report on Form 10-K.

RESULTS OF OPERATIONS -- NINE MONTHS ENDED SEPTEMBER 30, 2012

CONSOLIDATED EARNINGS

The following table compares our operating income by business segment and our net income during the first nine months of 2012 with the first nine months of 2011, including favorable (better (B)) or unfavorable (worse (W)) variances:

	Nine Months Ended September 30
	2012			B (W)			2011
	(Millions of Dollars)
Utility Energy Segment	$	533.2		$	96.5		$	436.7
Non-Utility Energy Segment	270.2			8.5			261.7
Corporate and Other	(4.5		)	(0.4		)	(4.1		)
Total Operating Income	798.9			104.6			694.3
Equity in Earnings of Transmission Affiliate	48.9			2.5			46.4
Other Income, net	33.6			(9.5		)	43.1
Interest Expense, net	181.3			(3.7		)	177.6
Income from Continuing Operations Before Income Taxes	700.1			93.9			606.2
Income Tax Expense	252.6			(45.1		)	207.5
Income from Continuing Operations	$	447.5		$	48.8		$	398.7
Diluted Earnings Per Share from Continuing Operations	$	1.92		$	0.23		$	1.69
Diluted Earnings Per Share from Discontinued Operations	$	—		$	(0.05	)	$	0.05

UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Our utility energy segment contributed $533.2 million of operating income during the first nine months of 2012, an increase of $96.5 million, or 22.1%, compared with the first nine months of 2011. The following table summarizes the operating income of this segment between the comparative periods:

September 2012 28 Wisconsin Energy Corporation

Form 10-Q

	Nine Months Ended September 30
Utility Energy Segment	2012		B (W)			2011
	(Millions of Dollars)
Operating Revenues
Electric	$	2,451.1	$	11.7		$	2,439.4
Gas	656.3		(206.5		)	862.8
Other	24.8		(4.1		)	28.9
Total Operating Revenues	3,132.2		(198.9		)	3,331.1
Operating Expenses
Fuel and Purchased Power	852.8		55.3			908.1
Cost of Gas Sold	368.0		165.4			533.4
Other Operation and Maintenance	1,069.0		107.7			1,176.7
Depreciation and Amortization	218.8		(27.4		)	191.4
Property and Revenue Taxes	90.4		(5.6		)	84.8
Total Operating Expenses	2,599.0		295.4			2,894.4
Operating Income	$	533.2	$	96.5		$	436.7

Electric Utility Revenues and Sales

The following table compares electric utility operating revenues and MWh sales by customer class during the first nine months of 2012 with the first nine months of 2011:

	Nine Months Ended September 30
	Electric Revenues							MWh Sales
Electric Utility Operations	2012		B (W)			2011		2012	B (W)		2011
	(Millions of Dollars)							(Thousands)
Customer Class
Residential	$	891.7	$	9.1		$	882.6	6,354.0	37.3		6,316.7
Small Commercial/Industrial	779.1		13.0			766.1		6,777.3	73.7		6,703.6
Large Commercial/Industrial	569.0		(12.6		)	581.6		7,339.7	(247.7	)	7,587.4
Other - Retail	16.6		—			16.6		111.2	0.6		110.6
Total Retail	2,256.4		9.5			2,246.9		20,582.2	(136.1	)	20,718.3
Wholesale - Other	112.3		(2.1		)	114.4		1,113.1	(379.7	)	1,492.8
Resale - Utilities	43.2		(10.4		)	53.6		1,392.1	(139.5	)	1,531.6
Other Operating Revenues	39.2		14.7			24.5		—	—		—
Total	$	2,451.1	$	11.7		$	2,439.4	23,087.4	(655.3	)	23,742.7
Weather -- Degree Days (a)
Heating (4,385 Normal)								3,513	(1,124	)	4,637
Cooling (686 Normal)								1,041	255		786
(a) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year
moving average.

Our electric utility operating revenues increased by $11.7 million, or 0.5%, when compared to the first nine months of 2011.

We estimate favorable weather increased revenues by approximately $39 million in our Residential and Small Commercial/Industrial customer classes in 2012 compared to normal weather conditions. By comparison, we estimate that favorable weather in 2011 increased revenues for these customer classes by approximately $23 million compared to normal weather conditions.

Sales to the Large Commercial/Industrial customer class decreased by 3.3% in 2012 compared to 2011. Large Commercial/Industrial revenues decreased by approximately $12.6 million compared to 2011. We estimate that our

September 2012 29 Wisconsin Energy Corporation

Form 10-Q

revenues were reduced by approximately $23 million because of the planned outage at an iron ore mine of our largest customer, and the conversion to self-generation of two other large customers. If sales to the mines and the two customers that added self-generation are excluded, our MWh sales to Large Commercial/Industrial customers increased by 1.7%.

In addition, our retail revenues increased by approximately $9 million in 2012 because of rate increases in Michigan and favorable fuel recoveries in Wisconsin. Other Operating Revenues increased by approximately $14.7 million driven by the $22 million of amortization related to the DOE settlement used to offset an increase in fuel costs authorized by the PSCW.

Fuel and Purchased Power

Our fuel and purchased power costs decreased by $55.3 million, or 6.1%, when compared to the first nine months of 2011. This decrease was primarily caused by a 2.8% decrease in total MWh sales and a reduction in our average cost of fuel and purchased power because of lower natural gas prices.

Gas Utility Revenues, Gross Margin and Therm Deliveries

A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the first nine months of 2012 with the first nine months of 2011. We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under gas cost recovery mechanisms. Between the comparative periods, total gas operating revenues decreased by $206.5 million, or 23.9%, and cost of gas sold decreased by $165.4 million, or 31.0%, due to the significantly warmer weather, which resulted in lower therm deliveries, and a decline in the commodity cost of natural gas.

	Nine Months Ended September 30
	2012		B (W)			2011
	(Millions of Dollars)
Gas Operating Revenues	$	656.3	$	(206.5	)	$	862.8
Cost of Gas Sold	368.0		165.4			533.4
Gross Margin	$	288.3	$	(41.1	)	$	329.4

The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the first nine months of 2012 with the first nine months of 2011:

	Nine Months Ended September 30
	Gross Margin							Therm Deliveries
Gas Utility Operations	2012		B (W)			2011		2012	B (W)		2011
	(Millions of Dollars)							(Millions)
Customer Class
Residential	$	184.5	$	(26.5	)	$	211.0	436.9	(119.1	)	556.0
Commercial/Industrial	59.4		(13.4		)	72.8		254.2	(73.0	)	327.2
Interruptible	1.2		(0.2		)	1.4		9.9	(1.9	)	11.8
Total Retail	245.1		(40.1		)	285.2		701.0	(194.0	)	895.0
Transported Gas	38.6		(0.3		)	38.9		876.9	209.5		667.4
Other	4.6		(0.7		)	5.3		—	—		—
Total	$	288.3	$	(41.1	)	$	329.4	1,577.9	15.5		1,562.4
Weather -- Degree Days (a)
Heating (4,385 Normal)								3,513	(1,124	)	4,637
(a) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year
moving average.

September 2012 30 Wisconsin Energy Corporation

Form 10-Q

Our gas margin decreased by $41.1 million, or approximately 12.5%, when compared to the first nine months of 2011. This decrease primarily relates to a decrease in sales volumes as a result of warmer weather during the first nine months of 2012 that decreased heating loads. As measured by heating degree days, the first nine months of 2012 were 24.2% warmer than the same period in 2011 and 19.9% warmer than normal. Transported gas volumes for the first nine months of 2012 increased by 31.4% as compared to the same period in 2011. Virtually all of the volume increase related to gas used in electric generation, which has a small impact on margin. This margin increase was more than offset by a reduction in transportation volumes delivered to higher margin classes that are more weather sensitive than our large transport customers.

Other Operation and Maintenance Expense

Our other operation and maintenance expense decreased by $107.7 million, or approximately 9.2%, when compared to the first nine months of 2011, primarily due to the one year suspension of $148 million of amortization expense on certain regulatory assets as authorized under our 2012 Wisconsin Rate Case.

Depreciation and Amortization Expense

Our depreciation and amortization expense increased by $27.4 million, or approximately 14.3%, when compared to the first nine months of 2011 primarily because of an overall increase in utility plant in service. The Glacier Hills Wind Park went into service in December 2011. In addition, the emission control equipment for units 5 and 6 of the Oak Creek AQCS project went into service in March 2012, and for units 7 and 8 in September 2012.

NON-UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

The table below reflects nine months of earnings in 2012 and 2011 for PWGS 1, PWGS 2, OC 1 and the common facilities for the Oak Creek expansion. It also reflects nine months of earnings in 2012 and approximately eight and a half months of earnings in 2011 for OC 2. This segment reflects the lease revenues on the new units as well as the depreciation expense. The operating and maintenance costs associated with the plants are the responsibility of Wisconsin Electric and are recorded in the utility segment.

	Nine Months Ended September 30
	2012		B (W)			2011
	(Millions of Dollars)
Operating Revenues	$	332.2	$	4.7		$	327.5
Operation and Maintenance Expense	11.7		(0.2		)	11.5
Depreciation Expense	50.3		4.0			54.3
Operating Income (Loss)	$	270.2	$	8.5		$	261.7

CONSOLIDATED OTHER INCOME, NET

	Nine Months Ended September 30
	2012		B (W)			2011
	(Millions of Dollars)
AFUDC - Equity	$	31.7	$	(9.9	)	$	41.6
Other, net	1.9		0.4			1.5
Other Income, net	$	33.6	$	(9.5	)	$	43.1

Other income, net decreased by $9.5 million, or approximately 22.0%, when compared to the first nine months of 2011. The decrease in AFUDC - Equity is primarily related to the Glacier Hills Wind Park, which went into service in December 2011, as well as the Oak Creek AQCS project which emission control equipment went into service in March 2012 for units 5 and 6 and September 2012 for units 7 and 8.

September 2012 31 Wisconsin Energy Corporation

Form 10-Q

CONSOLIDATED INTEREST EXPENSE, NET

	Nine Months Ended September 30
	2012		B (W)			2011
	(Millions of Dollars)
Gross Interest Costs	$	195.4	$	1.3		$	196.7
Less: Capitalized Interest	14.1		(5.0		)	19.1
Interest Expense, net	$	181.3	$	(3.7	)	$	177.6

Our gross interest costs decreased by $1.3 million, or approximately 0.7%, when compared to the first nine months of 2011 primarily because we retired $450 million of long-term debt in April 2011. This decrease was partially offset by increased interest costs associated with the issuance of $300 million of long-term debt by Wisconsin Electric in September 2011. Our capitalized interest decreased by $5.0 million primarily because of lower construction work in progress. As a result, our net interest expense increased by $3.7 million, or 2.1%, as compared to the first nine months of 2011.

CONSOLIDATED INCOME TAX EXPENSE

For the first nine months of 2012, our effective tax rate applicable to continuing operations was 36.1% compared to 34.2% for the first nine months of 2011, primarily due to a decrease in the projected 2012 annual tax benefits associated with AFUDC - Equity. For additional information, see Note H -- Income Taxes in our 2011 Annual Report on Form 10-K. We expect our 2012 annual effective tax rate to be between 35.5% and 36.5%.

DISCONTINUED OPERATIONS

During 2011, we reached a favorable resolution of uncertain state and federal tax positions associated with our previously discontinued manufacturing business.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

The following summarizes our cash flows from continuing operations during the nine months ended September 30:

	2012			2011
	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$	992.4		$	827.6
Investing Activities	$	(491.4	)	$	(650.3	)
Financing Activities	$	(502.1	)	$	(186.7	)

Operating Activities

Cash provided by operating activities increased by $164.8 million during the first nine months of 2012 as compared to the same period in 2011. Increases in cash provided by operating activities are attributed to higher net income, higher depreciation expense and lower contributions to our benefit plans. In September 2012, we contributed $100.0 million to our qualified benefits plans, compared to $257.4 million during the first nine months of 2011. In addition, our non-cash charges related to the amortization of certain regulatory assets and liabilities was $111.0 million lower in the first nine months of 2012 as compared to the first nine months in 2011 because the PSCW allowed us to suspend these amortizations in 2012.

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Investing Activities

Cash used in investing activities declined by $158.9 million during the first nine months of 2012 as compared to the same period in 2011. Our capital expenditures decreased by $134.7 million during the first nine months of 2012 as compared to the same period in 2011, primarily because of decreased spending on the Oak Creek AQCS project. During the first nine months of 2011, we received proceeds from asset sales totaling $38.5 million, which primarily relates to the sale of our interest in Edgewater Generating Unit 5, as compared to proceeds of $3.0 million during the first nine months of 2012. Finally, changes in restricted cash improved our cash from investing activities by $73.2 million. In 2011, we received $45.5 million in proceeds from the settlement with the DOE. The proceeds were treated as restricted cash, which was recorded as cash used in investing activities. In 2012, we released $36.0 million of the proceeds through bill credits and the reimbursement of costs.

Financing Activities

Cash used in financing activities increased by $315.4 million during the first nine months of 2012 as compared to the same period in 2011. During the first nine months of 2011, we issued $720.0 million of long-term debt, of which $420 million related to the commercial operation of OC 2 and $300 million was issued by Wisconsin Electric. During the same period, we retired $450 million of long-term debt that matured. We did not issue any long-term debt during the first nine months of 2012. In January 2012, our Board of Directors approved a 15.4% increase in the quarterly common stock dividend effective with the first quarter 2012 dividend payment. In addition, during the first nine months of 2012, we repurchased $14.0 million of common stock under our May 2011 share repurchase program and $91.0 million of common stock to fulfill exercised stock options and restricted stock awards. During the first nine months of 2011, we repurchased $75.0 million of common stock under our May 2011 share repurchase program and $60.1 million of common stock to fulfill exercised stock options and restricted stock awards.

CAPITAL RESOURCES AND REQUIREMENTS

Working Capital

As of September 30, 2012, our current liabilities exceeded our current assets by approximately $302.2 million. We do not expect this to have any impact on our liquidity because we believe we have adequate back-up lines of credit in place, as well as access to the capital markets to finance our construction program and to refinance current maturities of long-term debt. We expect to issue long-term debt during the fourth quarter, depending on market conditions and other factors.

Liquidity

We anticipate meeting our capital requirements during the remainder of 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 September 30, 2012, we had approximately $1.2 billion of available, undrawn lines under our bank back-up credit facilities, and approximately $453.2 million of commercial paper outstanding on a consolidated basis that was supported by the available lines of credit. During the first nine months of 2012, our maximum commercial paper outstanding was $669.9 million with a weighted-average interest rate of 0.28%.

We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate

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credit facilities to support our operations. The following table summarizes such facilities as of September 30, 2012:

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

The following table shows our capitalization structure as of September 30, 2012, as well as an adjusted capitalization structure that we believe is consistent with the manner in which the rating agencies currently view Wisconsin Energy's 2007 Series A Junior Subordinated notes (Junior Notes):

Capitalization Structure	Actual			Adjusted
	(Millions of Dollars)
Common Equity	$	4,147.2		$	4,397.2
Preferred Stock of Subsidiary	30.4			30.4
Long-Term Debt (including current maturities)	4,621.7			4,371.7
Short-Term Debt	453.2			453.2
Total Capitalization	$	9,252.5		$	9,252.5
Total Debt	$	5,074.9		$	4,824.9
Ratio of Debt to Total Capitalization	54.8		%	52.1		%

Included in Long-Term Debt on our Consolidated Condensed Balance Sheet as of September 30, 2012 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.

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 September 30, 2012, 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.

Credit Rating Risk

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.

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, security ratings reflect the views of the rating agencies only. An explanation of the significance of the 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

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downward or withdrawn at any time by a rating agency.

See Capital Resources and Requirements -- Credit Rating Risk in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2011 Annual Report on Form 10-K for additional information related to our credit rating risk.

Capital Requirements

Capital Expenditures:   Capital requirements during the remainder of 2012 are expected to be principally for capital expenditures in our utility operations relating to our electric and gas distribution systems and our biomass facility. We estimate that we will spend approximately $740 million on consolidated capital expenditures during 2012.

Common Stock Matters:   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 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 September 30, 2012, we have acquired approximately 3.6 million shares in the open market at a cost of $114.0 million pursuant to this program. For additional information regarding the share repurchases, see Part II, Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds.

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% of earnings 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.

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 continue to believe that these agreements do not have, and are not reasonably likely to have, a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors. For further information, see Note 10 -- Variable Interest Entities in the Notes to Consolidated Condensed Financial Statements in this report.

Contractual Obligations/Commercial Commitments:   Our total contractual obligations and other commercial commitments were approximately $21.5 billion as of September 30, 2012 compared with $22.2 billion as of December 31, 2011.

FACTORS AFFECTING RESULTS, LIQUIDITY AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity and capital resources. The following discussion should be read together with the information under the heading "Factors Affecting Results, Liquidity and Capital Resources" in Item 7 of our 2011 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, our PTF strategy, utility rates and regulatory matters, electric system reliability, environmental matters, legal matters, industry restructuring and competition and other matters.

POWER THE FUTURE

All of the PTF units are in service and are positioned to provide a significant portion of our future generation needs. We are recovering our costs in these units through lease payments associated with PWGS 1, PWGS 2, OC 1 and OC 2 that are billed from We Power to Wisconsin Electric and then recovered in Wisconsin Electric's rates as authorized by the PSCW, the Michigan Public Service Commission (MPSC) and FERC. See Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Item 7 of our 2011 Annual Report on Form 10-K for additional information on PTF.

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UTILITY RATES AND REGULATORY MATTERS

2013 Wisconsin Rate Case:   On March 23, 2012, Wisconsin Electric and Wisconsin Gas initiated rate proceedings with the PSCW. Wisconsin Electric has asked the PSCW to approve a net bill increase related to non-fuel costs for its Wisconsin retail electric customers of approximately $99.3 million (3.6%) for 2013. This proposed increase reflects an offset to the revenue requirement of approximately $73.3 million related to the proceeds of a renewable energy cash grant we expect to receive under the National Defense Authorization Act upon completion of our biomass facility currently under construction. Wisconsin Electric's proposed plan, if approved by the PSCW, would return the proceeds from the cash grant to customers in the form of bill credits.

Absent the bill credits, the total electric rate increase requested by Wisconsin Electric is approximately $172.6 million (6.2%) for 2013. Wisconsin Electric is requesting an additional increase in electric rates of approximately $37.4 million in 2014, which would result in a 3.6% net bill increase for its Wisconsin retail electric customers. Wisconsin Electric also filed its fuel cost plan for 2013 with the PSCW as required by the Wisconsin fuel rules.

For its natural gas customers, Wisconsin Electric requested a rate decrease of approximately $1.2 million (0.2%) for 2013 with no rate adjustment for 2014. In addition, Wisconsin Electric requested rate increases of approximately $1.3 million (6.0%) for its Valley steam utility customers in 2013 and 2014, and approximately $1.0 million (7.0%) and $1.0 million (6.0%) for its Milwaukee County steam utility customers in 2013 and 2014, respectively.

Wisconsin Gas has asked the PSCW to approve a rate decrease for its natural gas customers of approximately $15.9 million (2.3%) for 2013, with no rate adjustment for 2014.

We anticipate a final written order from the PSCW by the end of the year.

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 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 (see 2013 Wisconsin Rate Case above).

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

We received a final written order from the PSCW on November 3, 2011. For information related to the proceeding to establish a 2012 fuel cost plan, see 2012 Fuel Recovery Request below.

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. Pursuant to Michigan law, we self-implemented a $5.7 million interim electric base rate increase in January 2012. This increase was 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. The MPSC approved a total increase in electric base rates of $9.2 million annually, effective June 27, 2012, and authorized a 10.1% return on equity.

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 were 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

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the settlement with the DOE regarding the storage of spent nuclear fuel, resulting in no change in customer bills.

2010 Wisconsin Rate Case:   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. In September 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.

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.

Renewable Energy Portfolio:   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. We are targeting completion of the facility by the end of 2013.

On July 27, 2012, we signed an agreement with NextEra Energy Resources to buy the Montfort Wind Energy Center for $27 million, subject to PSCW and FERC approval. We anticipate approval and closing of the sale by the end of 2012. We currently have a long-term power purchase agreement for 85% of the energy from the site.

Oak Creek Air Quality Control System:   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. In March 2012, the wet flue gas desulfurization and selective catalytic reduction equipment for units 5 and 6 was placed into commercial operation. On September 4, 2012, the equipment for units 7 and 8 was placed into commercial operation. The final cost of completing this project is approximately $740 million ($900 million including AFUDC).

See Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters in Item 7 of our 2011 Annual Report on Form 10-K for additional information regarding our utility rates and other regulatory matters.

ELECTRIC TRANSMISSION AND ENERGY MARKETS

As part of MISO, a market-based platform was developed for valuing transmission congestion premised upon the Locational Marginal Price (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 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, 2012 through May 31, 2013. The resulting ARR valuation and the secured FTRs should mitigate our transmission congestion risk for that period.

ENVIRONMENTAL MATTERS

Air Quality

Mercury and Other Hazardous Air Pollutants:   In December 2011, the EPA issued the final 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 capital

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cost to comply with this rule will be approximately $8 million to $12.5 million. Based upon our review of the rules and plans to convert the VAPP from coal to natural gas fuel, we currently anticipate that only the Presque Isle Power Plant will require modifications. We believe that our clean air strategy, including the environmental upgrades that have been constructed and that are currently under construction at our other coal-fired plants, positions those other plants well to meet the rule's requirements.

Cross-State Air Pollution Rule:   In August 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 Nitrogen Oxide and SO₂ that contribute to fine particulate matter and ozone non-attainment in downwind states through a proposed allocation scheme. In February 2012, the EPA issued final technical revisions to the rule and issued a draft final rule which together 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 August 21, 2012, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CSAPR, keeping the CAIR in effect. The EPA has requested the court to re-hear the case.

Climate Change:   Federal, state, regional and international authorities have undertaken efforts to limit greenhouse gas emissions. The regulation of greenhouse gas emissions through legislation and regulation has been, and continues to be, a focus of the President and his administration. Although legislation that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards and/or energy efficiency standards failed to pass in the U.S. Congress, we expect such legislation to be considered in the future. Any mandatory restrictions on our Carbon Dioxide 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.

In March 2012, the EPA, using its existing authority under the Clean Air Act (CAA), proposed new source performance standards pertaining to greenhouse gas emissions from certain new power plants, including coal-fueled plants, based on the performance of combined cycle natural gas-fueled generating plants. We believe this rule effectively prohibits new conventional coal-fueled power plants. In June 2012, the U. S. Court of Appeals for the District of Columbia Circuit upheld the EPA's authority to regulate greenhouse gas emissions.

We expect the EPA to attempt to address performance standards for reconstructed and modified generating units in a future rule. Any such rule may impact our ability to do maintenance or modify our existing facilities. Depending on the extent of rate recovery and other factors, these anticipated future 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 our 2011 Annual Report on Form 10-K.

Valley Power Plant Conversion:   On August 17, 2012, we announced plans to convert the fuel source for VAPP from coal to natural gas. We currently expect the cost of this conversion to be between $60 and $65 million and, subject to receipt of PSCW approval and a construction air permit from the WDNR, anticipate that the conversion will be completed no later than 2016. We expect to file for a Certificate of Authority from the PSCW during the second quarter of 2013.

In June 2012, we received approval from the PSCW to replace and upgrade the Lincoln Arthur natural gas main, which has the capability to accommodate the increased natural gas required for the conversion of VAPP to natural gas.

See Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7 of our 2011 Annual Report on Form 10-K for additional information regarding environmental matters affecting our operations.

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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 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. The court approved the settlement on April 3, 2012 and issued its written order on April 20, 2012. Substantially all payments to class members have been made pursuant to the settlement. We do not anticipate further charges as a result of the settlement.

NUCLEAR OPERATIONS

Used Nuclear Fuel Storage and Disposal:  The Nuclear Waste Policy Act established the Nuclear Waste Fund, which is composed of payments made by the generators and owners of nuclear plants. Wisconsin Electric owned Point Beach through September 2007 and placed approximately $215.2 million into this fund. Effective January 31, 1998, the DOE failed to meet its contractual obligation to begin removing used fuel from Point Beach. Wisconsin Electric filed a complaint in November 2000 against the DOE in the Court of Federal Claims for failure to begin performance. 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 rate order in our 2012 Michigan rate case.

OTHER MATTERS

Oak Creek Expansion Fuel Flexibility Project:   The Oak Creek expansion units were designed and permitted to use bituminous coal from the Eastern United States rather than sub-bituminous coal. Market forces have resulted in a significant price differential between bituminous and sub-bituminous coals. We have applied for a new air permit from the WDNR to modify the Oak Creek expansion units for potential future use of sub-bituminous coal. Upon receiving an air permit, we intend to begin testing sub-bituminous coal in various combinations with bituminous coal to identify any equipment limitations that should be considered prior to filing with the PSCW for a Certificate of Authority to make the fuel flexibility modifications.

Regulation of Derivatives and Swap Transactions:   The Dodd-Frank Act, enacted in July 2010, provides for the regulation of derivatives and grants the CFTC expanded regulatory authority over derivative and swap transactions. The CFTC has promulgated numerous regulations that will impose additional requirements on the use of derivatives and swap transactions for us and our counterparties, which could affect both the use and cost of these instruments. Several of the rules still need to be finalized, pending the CFTC's requests for further comments on certain interim rules, interpretations and proposed exemptions, and requests for clarifications by several interested parties. Although we cannot be certain of the impact of these new rules on us until these matters are fully resolved, we currently do not expect it to be material.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes related to market risk from the disclosures presented in our Annual Report on Form 10-K for the year ended December 31, 2011. For information concerning market risk exposures at Wisconsin Energy Corporation, see Item 7. 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 Part II of our 2011 Annual Report on Form 10-K, as well as Note 6 -- Fair Value Measurements and Note 7 -- Derivative Instruments in the Notes to Consolidated Condensed Financial Statements in this report.

ITEM 4. 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.

Internal Control Over Financial Reporting:   There has not been any change in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the fiscal quarter to which this report relates that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The following should be read in conjunction with Item 3. Legal Proceedings in Part I of our 2011 Annual Report on Form 10-K.

In addition to those legal proceedings discussed in our reports to the SEC, 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 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

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 new AQCS, was a former ravine that had been filled with coal ash prior to the advent of landfill regulations.

A mixture of soil, coal ash and water, along with several trailers, vehicles and other construction materials from the AQCS construction site, slid down the bluff to the shoreline area. Some of these materials 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 were removed from the area, and construction equipment and related materials were removed from Lake Michigan. The clean-up work was completed, and the bluff was stabilized for the winter. Bluff reconstruction resumed in July 2012 following WDNR plan approvals and is approximately 95% complete. Work continues on construction of the storm water collection basin, which we expect to be completed by the end of November 2012.

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We consulted with nearby water utilities and they indicated that there were no 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.

The WDNR issued a Notice of Violation (NOV) along with its investigative findings on March 1, 2012, and an enforcement conference was held with representatives of Wisconsin Electric on March 7, 2012. The NOV involved the north surface water detention basin and a related permit condition. A June 20, 2012 letter from the WDNR rescinded the March 1, 2012 NOV, but alleged non-compliance with certain environmental regulations. We responded to the letter as requested. In late July, the WDNR referred the matter to the Wisconsin Department of Justice (DOJ) for alleged violations of storm water and solid waste statutes and rules. We anticipate the DOJ will seek fines or penalties from us as a result of this incident.

In addition, in November 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.

UTILITY RATES AND REGULATORY MATTERS

See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters in Part I of this report for information concerning rate matters in the jurisdictions where Wisconsin Electric and Wisconsin Gas do business.

OTHER MATTERS

See Factors Affecting Results, Liquidity and Capital Resources -- Legal Matters in Item 2 of this report for information regarding a lawsuit filed against the Plan.

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors presented in our Annual Report on Form 10-K for the year ended December 31, 2011. See Item 1A. Risk Factors in our 2011 Annual Report on Form 10-K for a discussion of certain risk factors applicable to us.

September 2012 41 Wisconsin Energy Corporation

Form 10-Q

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table sets forth information regarding the purchases of our equity securities made by or on behalf of us or any affiliated purchaser (as defined in Exchange Act Rule 10b-18) during the three months ended September 30, 2012:

ISSUER PURCHASES OF EQUITY SECURITIES

2012	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (a)	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
					(Millions of Dollars)
July 1 - July 31	—	$	—	—	$	200.0
August 1 - August 31	—	$	—	—	$	200.0
September 1 - September 30	375,770	$	37.15	375,770	$	186.0
Total	375,770	$	37.15	375,770
(a) 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.

ITEM 6. EXHIBITS

Exhibit No.
10	Material Contracts
10.1	Terms of Employment for J. Patrick Keyes.
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

September 2012 42 Wisconsin Energy Corporation

Form 10-Q

SIGNATURES

Pursuant to the requirements 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
		(Registrant)
		/s/STEPHEN P. DICKSON
Date:	November 2, 2012	Stephen P. Dickson, Vice President and Controller, Principal Accounting Officer and duly authorized officer

September 2012 43 Wisconsin Energy Corporation

EX-10.1

Exhibit 10.1

NAME	J. Patrick Keyes
POSITION	Executive VP & Chief Financial Officer
BASE SALARY	$	485,000
2012 STPP AWARD*
Target Award (75%)	$	363,750
2013 LONG-TERM EQUITY AWARD**
Theoretical Value	$	906,950
TOTAL VALUE OF PAY PROGRAM*	$	1,755,700
* Reflects post-promotion value
** Estimated value: Reflects post-promotion award based on today's market. This award consists of stock options, restricted stock,
and performance units.
Note: Mr. Keyes is entitled to participate in the company's pension plan and other retirement plans. In addition, Mr. Keyes is eligible for
an executive financial planning benefit, executive life insurance and executive annual physical benefit on a basis commensurate with
other Executive Vice Presidents of the company.

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 quarterly report on Form 10-Q 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: November 2, 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, J. Patrick Keyes, certify that:

1. I have reviewed this quarterly report on Form 10-Q 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: November 2, 2012

/s/J. PATRICK KEYES

J. Patrick Keyes

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 Quarterly Report of Wisconsin Energy Corporation (the "Company") on Form 10-Q for the period ended September 30, 2012, as filed with the Securities and Exchange Commission on November 2, 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

November 2, 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 Quarterly Report of Wisconsin Energy Corporation (the "Company") on Form 10-Q for the period ended September 30, 2012, as filed with the Securities and Exchange Commission on November 2, 2012 (the "Report"), I, J. Patrick Keyes, 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/J. PATRICK KEYES

J. Patrick Keyes

Executive Vice President and Chief Financial Officer

November 2, 2012

XML

Variable Interest Entities (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012 Years	Sep. 30, 2011
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 Agreements with Vie, Remaining Term, In Years	1
Power capacity under capital lease (MW)	236
Capital Lease Agreement With Vie Remaining Term In Years	10
Total payments over remaining terms of the two agreements	$ 270.2
Total capacity and lease payments	$ 44.5	$ 51.0

XML

Fair Value Measurements, Financial Instruments (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Financial Instruments
Preferred stock of subsidiary	$ 30.4	$ 30.4
Carrying (Reported) Amount, Fair Value Disclosure [Member]
Financial Instruments
Preferred stock of subsidiary	30.4	30.4
Long-term debt including current portion	4,523.2	4,541.4
Estimate of Fair Value, Fair Value Disclosure [Member]
Financial Instruments
Preferred stock of subsidiary	26.3	25.1
Long-term debt including current portion	$ 5,256.8	$ 5,179.9

XML

Common Equity Common Equity 2 (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended		3 Months Ended	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012 Stock options [Member]	Sep. 30, 2012 Stock options [Member]	Sep. 30, 2011 Stock options [Member]	Mar. 31, 2012 Stock options [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number						10,638,750		9,571,531
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period					0	938,770	458,180
Share Based Compensation Arrangement By Share Based Payment Award Options Grant In Period Weighted Average Exercise Price					$ 0.00	$ 34.88
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period					(370,020)	(2,368,289)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period					0	(7,720)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	9,201,511		9,201,511		9,201,511	9,201,511		9,571,531
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price						$ 21.65		$ 23.42
Share Based Compensation Arrangement By Share Based Payment Awards Options Exercises In Period Weighted Average Exercise Price					$ 17.89	$ 19.11
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price					$ 0.00	$ 26.94
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 23.65		$ 23.65		$ 23.65	$ 23.65		$ 23.42
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range Outstanding Options Weighted Average Remaining Contractual Period						5 years 5 months
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value					$ 129.0	$ 129.0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number	7,493,036		7,493,036		7,493,036	7,493,036
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 21.98		$ 21.98		$ 21.98	$ 21.98
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Weighted Average Remaining Contractual Term			4 years 8 months			4 years 8 months
Share Based Compensation Arrangement by Share Based Payments Award, Options Exercisable, Intrinsic Value					117.6	117.6
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value	8.3	3.6	42.1	22.6
Exercise of stock options			45.3	34.4
Tax Benefit from Stock Options Exercised			$ 0	$ 9.0

XML

Benefits (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended			3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011	Sep. 30, 2012 Pension Plans, Defined Benefit [Member]	Sep. 30, 2011 Pension Plans, Defined Benefit [Member]	Sep. 30, 2012 Pension Plans, Defined Benefit [Member]	Sep. 30, 2011 Pension Plans, Defined Benefit [Member]	Sep. 30, 2012 Other Postretirement Benefit Plans, Defined Benefit [Member]	Sep. 30, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member]	Sep. 30, 2012 Other Postretirement Benefit Plans, Defined Benefit [Member]	Sep. 30, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member]
Net Periodic Benefit Cost
Service cost				$ 5.5	$ 4.0	$ 16.3	$ 11.9	$ 2.6	$ 2.6	$ 7.8	$ 7.8
Interest cost				16.4	16.9	49.2	50.7	5.1	5.2	15.3	15.6
Expected return on plan assets				(22.5)	(20.5)	(67.3)	(61.6)	(4.8)	(4.3)	(14.4)	(12.7)
Amortization of:
Transition obligation								0	0	0.2	0.2
Prior service cost (credit)				0.5	0.6	1.7	1.7	(0.5)	(0.4)	(1.4)	(1.4)
Actuarial loss				10.2	8.4	30.4	25.5	1.9	1.7	5.4	4.7
Net Periodic Benefit Cost				10.1	9.4	30.3	28.2	4.3	4.8	12.9	14.2
Benefits (Textuals) [Abstract]
Pension and Other Postretirement Benefit Contributions	100.0	257.4
Estimated liability of Postemployment benefits	$ 5.2		$ 15.3

XML

Long Term Debt

9 Months Ended

Sep. 30, 2012

Long-term Debt, Unclassified [Abstract]

LONG TERM DEBT

LONG-TERM DEBT

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.

In January 2011, we issued a total of $420 million of 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 Oak Creek expansion Unit 2 (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 and Wisconsin Electric related to OC 2.

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

As of September 30, 2012, we were in compliance with all financial covenants.

XML

Asset Sales, Divestitures and Discontinued Operations (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income (Loss) from Continuing Operations Attributable to Parent	$ 156.1	$ 129.8	$ 447.5	$ 398.7
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	0	0	0	11.5
Net Income (Loss) Attributable to Parent	156.1	129.8	447.5	410.2
Asset Sales, Divestitures and Discontinued Operations (Textuals)
Ownership percentage in Edgewater Generating Unit 5 sold				25.00%
Proceeds from the sale of interest in Edgewater Generating Unit				$ 38

XML

Common Equity Common Equity 5 (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended				12 Months Ended	3 Months Ended		9 Months Ended			9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012 Share Repurchase Plan, 2011 [Member]	Sep. 30, 2011 Share Repurchase Plan, 2011 [Member]	Dec. 31, 2011 Share Repurchase Plan, 2011 [Member]	Sep. 30, 2012 Restricted stock [Member]	Sep. 30, 2011 Restricted stock [Member]	Sep. 30, 2012 Restricted stock [Member]	Sep. 30, 2011 Restricted stock [Member]	Mar. 31, 2012 Restricted stock [Member]	Sep. 30, 2012 Share Repurchases to Fulfill Exercised Stock Options and Restricted Stock Awards [Member]	Sep. 30, 2011 Share Repurchases to Fulfill Exercised Stock Options and Restricted Stock Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Other Comprehensive Income (Loss), Net of Tax	$ 0	$ 0	$ 0	$ 0
Stock Repurchase Program, Authorized Amount					300
Treasury Stock Acquired, Average Cost Per Share							$ 31.45
Stock Repurchased During Period, Shares			2,900,000	4,400,000	400,000	2,500,000							2,500,000	1,900,000
Stock Repurchased During Period, Value			105.0	135.1	14.0	75.0	114.0						91.0	60.1
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number										192,558		194,697
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period								0		94,959
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period								0		(88,422)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period								(1,213)		(5,611)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number								193,484		193,484		194,697
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value								$ 0.00		$ 34.46
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value								$ 0.00		$ 30.65
Share Based Compensation Arrangement By Share Based Payment Awards Equity Instruments Other Than Options Forfeited In Period Weighted Average Grant Date Fair Value								$ 31.35		$ 30.94
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period			3 years
Share Based Compensation Arrangement By Share Based Payment Award Award Percentage To Vest Each Year After Grant Date			33.00%
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Intrinsic Value								0	0	3.3	2.3
Tax Benefit from Stock Options Exercised			0	9.0				0	0	0	0.7
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized								$ 3.3		$ 3.3
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition										22 months

XML

Long Term Debt (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Long Term Debt (Textuals)
Issuance of long-term debt	$ 0	$ 720.0
Extinguishment of Debt, Amount		450
Wis Elec Debentures due September 15 2021 [Member]
Long Term Debt (Textuals)
Issuance of long-term debt		300.0
Interest rate on Long Term Debt		2.95%
Series B [Member]
Long Term Debt (Textuals)
Issuance of long-term debt		420.0
Series B Senior Notes due January 19 2031 [Member]
Long Term Debt (Textuals)
Issuance of long-term debt		205.0
Interest rate on Long Term Debt		4.673%
Series B Senior Notes due January 19 2041 [Member]
Long Term Debt (Textuals)
Issuance of long-term debt		$ 215.0
Interest rate on Long Term Debt		5.848%

XML

Fair Value Measurements Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement Captions [Line Items]
Restricted Cash	$ 9.5	$ 45.5
Fair Value, Assets Measured on Recurring Basis, Derivative Financial Instruments, Assets	11.0	0.3
Fair Value Assets Measured on Recurring Basis Total Assets	20.5	45.8
Fair Value, Liabilities Measured on Recurring Basis, Derivative Financial Instruments, Liabilities	0	8.2
Fair Value Liabilities Measured on Recurring Basis Total Liabilities	0	8.2
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement Captions [Line Items]
Restricted Cash	0	0
Fair Value, Assets Measured on Recurring Basis, Derivative Financial Instruments, Assets	12.9	14.6
Fair Value Assets Measured on Recurring Basis Total Assets	12.9	14.6
Fair Value, Liabilities Measured on Recurring Basis, Derivative Financial Instruments, Liabilities	2.1	1.0
Fair Value Liabilities Measured on Recurring Basis Total Liabilities	2.1	1.0
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement Captions [Line Items]
Restricted Cash	0	0
Fair Value, Assets Measured on Recurring Basis, Derivative Financial Instruments, Assets	7.3	5.7
Fair Value Assets Measured on Recurring Basis Total Assets	7.3	5.7
Fair Value, Liabilities Measured on Recurring Basis, Derivative Financial Instruments, Liabilities	0	0
Fair Value Liabilities Measured on Recurring Basis Total Liabilities	0	0
Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement Captions [Line Items]
Restricted Cash	9.5	45.5
Fair Value, Assets Measured on Recurring Basis, Derivative Financial Instruments, Assets	31.2	20.6
Fair Value Assets Measured on Recurring Basis Total Assets	40.7	66.1
Fair Value, Liabilities Measured on Recurring Basis, Derivative Financial Instruments, Liabilities	2.1	9.2
Fair Value Liabilities Measured on Recurring Basis Total Liabilities	$ 2.1	$ 9.2

XML

Asset Sales, Divestitures and Discontinued Operations

9 Months Ended

Sep. 30, 2012

Discontinued Operations and Divestitures [Abstract]

ASSET SALES, DIVESTITURES AND DISCONTINUED OPERATIONS

ASSET SALES, DIVESTITURES AND DISCONTINUED OPERATIONS

The following table summarizes the net impacts of discontinued operations on our earnings for the three and nine months ended September 30:

	Three Months Ended September 30				Nine Months Ended September 30
	2012		2011		2012		2011
	(Millions of Dollars)
Income from Continuing Operations	$	156.1	$	129.8	$	447.5	$	398.7
Income from Discontinued Operations, Net of Tax (a)	—		—		—		11.5
Net Income	$	156.1	$	129.8	$	447.5	$	410.2
(a) During 2011, we reached a 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 Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corp. (WPL) for our net book value, including working capital, of approximately $38 million. This transaction was treated as a sale of an asset.

XML

Fair Value Measurements, Derivatives (Details) (Derivative [Member], USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Mar. 31, 2012	Mar. 31, 2011
Derivative [Member]
Fair value of derivatives classified as Level 3 in the fair value hierarchy
Beginning Balance			$ 5.7	$ 5.9	$ 9.9	$ 14.6
Realized and unrealized gains (losses)	0	0	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases	0	0	10.9	16.1
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales	0	0	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements	(2.6)	(4.5)	(9.3)	(11.9)
Transfers in and/or out of Level 3	0	0	0	0
Ending Balance	7.3	10.1	7.3	10.1	9.9	14.6
Change in unrealized gains (losses) relating to instruments still held as of period end	$ 0	$ 0	$ 0	$ 0

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Commitments and Contingencies (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	9 Months Ended			12 Months Ended
	Sep. 30, 2012	Sep. 30, 2012 Manufactured Gas Plant Sites [Member]	Sep. 30, 2012 Valley Power Plant [Member] T	Dec. 31, 2011 Cash Balance Pension Plan [Member]
Commitments and Contingencies [Line Items]
Loss Contingency, Range of Possible Loss, Minimum		$ 21
Loss Contingency, Range of Possible Loss, Maximum		65
Period for future costs of detailed site investigation and remediation costs		over the next ten years
Accrual for Environmental Loss Contingencies, Provision for New Losses		37.5
Target Annual Sulfur Dioxide Emissions Threshold			4,500
Target Reduction in Sulfur Dioxide Emissions, As a Percent			65.00%
Loss Contingency, Settlement Agreement, Consideration				45.0
Loss Contingency, Settlement Agreement, Terms				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
Unrecognized Tax Benefits, Period Increase (Decrease)	$ (7.4)

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Consolidated Condensed Income Statements (Unaudited) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Operating Revenues	$ 1,039.3	$ 1,052.8	$ 3,175.2	$ 3,373.2
Operating Expenses
Fuel and purchased power	336.4	350.9	848.9	904.5
Cost of gas sold	55.5	69.2	368.0	533.4
Other operation and maintenance	244.6	296.9	798.8	909.3
Depreciation and amortization	91.8	82.6	269.7	246.2
Property and revenue taxes	30.4	28.9	90.9	85.5
Total Operating Expenses	758.7	828.5	2,376.3	2,678.9
Operating Income	280.6	224.3	798.9	694.3
Income (Loss) from Equity Method Investments	17.1	15.6	48.8	46.1
Other Income, net	9.0	16.2	33.6	43.1
Interest Expense, net	60.9	56.8	181.3	177.6
Income from Continuing Operations Before Income Taxes	245.8	199.4	700.1	606.2
Income Tax Expense	89.7	69.6	252.6	207.5
Income from Continuing Operations	156.1	129.8	447.5	398.7
Income (Loss) from Discontinued Operations, Net of Tax	0	0	0	11.5
Net Income	156.1	129.8	447.5	410.2
Earnings Per Share (Basic)
Continuing operations	$ 0.68	$ 0.56	$ 1.94	$ 1.71
Discontinued operations	$ 0.00	$ 0.00	$ 0.00	$ 0.05
Total Earnings Per Share (Basic)	$ 0.68	$ 0.56	$ 1.94	$ 1.76
Earnings Per Share (Diluted)
Continuing operations	$ 0.67	$ 0.55	$ 1.92	$ 1.69
Discontinued operations	$ 0.00	$ 0.00	$ 0.00	$ 0.05
Total Earnings Per Share (Diluted)	$ 0.67	$ 0.55	$ 1.92	$ 1.74
Weighted Average Common Shares Outstanding (Millions)
Basic	230.4	232.2	230.4	233.2
Diluted	232.9	234.9	233.1	236.0
Dividends Per Share of Common Stock	$ 0.30	$ 0.26	$ 0.90	$ 0.78
Transmission Affiliate [Member]
Operating Expenses
Income (Loss) from Equity Method Investments	$ 17.1	$ 15.7	$ 48.9	$ 46.4

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New Accounting Pronouncements

9 Months Ended

Sep. 30, 2012

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

NEW ACCOUNTING PRONOUNCEMENTS

NEW ACCOUNTING PRONOUNCEMENTS

Presentation of Comprehensive Income:   In June 2011, the Financial Accounting Standards Board (FASB) issued guidance on the presentation of comprehensive income. 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. This guidance is effective for fiscal years and interim periods beginning after December 15, 2011 and must be applied retrospectively. We adopted this guidance on January 1, 2012, and it did not have any material impact on us.

Fair Value Measurement:   In May 2011, the FASB issued guidance amending existing guidance for measuring fair value and expanding required disclosures about fair value measurements. This guidance is effective for fiscal years and interim periods beginning after December 15, 2011 and must be applied prospectively. We adopted this guidance on January 1, 2012, and it did not have any material impact on us.

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Derivative Instruments Derivative Instruments (Details 1) (Derivative [Member], USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Derivative [Member]
Regulatory Assets [Line Items]
Regulatory assets related to derivatives	$ 3.0	$ 29.6

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2012

Segment Information (Tables) [Abstract]

Financial information of reportable operating segments

	Reportable Segments							Eliminations
	Energy				Corporate &			& Reconciling			Total
Three Months Ended	Utility		Non-Utility		Other (a)			Items			Consolidated
	(Millions of Dollars)
September 30, 2012
Operating Revenues (b)	$	1,023.3	$	112.6	$	0.3		$	(96.9	)	$	1,039.3
Other Operation and Maintenance	$	334.1	$	4.3	$	2.0		$	(95.8	)	$	244.6
Depreciation and Amortization	$	74.7	$	16.8	$	0.3		$	—		$	91.8
Operating Income (Loss)	$	191.0	$	91.5	$	(1.9	)	$	—		$	280.6
Equity in Earnings of Unconsolidated Affiliates	$	17.1	$	—	$	—		$	—		$	17.1
Interest Expense, Net	$	31.4	$	16.6	$	12.9		$	—		$	60.9
Income Tax Expense (Benefit)	$	65.6	$	29.2	$	(5.1	)	$	—		$	89.7
Income from Discontinued Operations, Net of Tax	$	—	$	—	$	—		$	—		$	—
Net Income (Loss)	$	119.8	$	45.8	$	156.1		$	(165.6	)	$	156.1
Capital Expenditures	$	161.2	$	1.8	$	0.5		$	—		$	163.5
September 30, 2011
Operating Revenues (b)	$	1,036.7	$	113.0	$	0.2		$	(97.1	)	$	1,052.8
Other Operation and Maintenance	$	387.0	$	4.9	$	1.0		$	(96.0	)	$	296.9
Depreciation and Amortization	$	64.1	$	18.3	$	0.2		$	—		$	82.6
Operating Income (Loss)	$	135.6	$	89.8	$	(1.1	)	$	—		$	224.3
Equity in Earnings of Unconsolidated Affiliates	$	15.7	$	—	$	(0.1	)	$	—		$	15.6
Interest Expense, Net	$	26.8	$	16.9	$	13.2		$	(0.1	)	$	56.8
Income Tax Expense (Benefit)	$	45.5	$	28.4	$	(4.3	)	$	—		$	69.6
Income from Discontinued Operations, Net of Tax	$	—	$	—	$	—		$	—		$	—
Net Income (Loss)	$	95.0	$	44.6	$	129.7		$	(139.5	)	$	129.8
Capital Expenditures	$	252.1	$	7.3	$	5.7		$	—		$	265.1

	Reportable Segments							Eliminations
	Energy				Corporate &			& Reconciling			Total
Nine Months Ended	Utility		Non-Utility		Other (a)			Items			Consolidated
	(Millions of Dollars)
September 30, 2012
Operating Revenues (b)	$	3,132.2	$	332.2	$	0.9		$	(290.1	)	$	3,175.2
Other Operation and Maintenance	$	1,069.0	$	11.7	$	4.7		$	(286.6	)	$	798.8
Depreciation and Amortization	$	218.8	$	50.3	$	0.6		$	—		$	269.7
Operating Income (Loss)	$	533.2	$	270.2	$	(4.5	)	$	—		$	798.9
Equity in Earnings of Unconsolidated Affiliates	$	48.9	$	—	$	(0.1	)	$	—		$	48.8
Interest Expense, Net	$	92.6	$	50.1	$	38.9		$	(0.3	)	$	181.3
Income Tax Expense (Benefit)	$	182.6	$	87.2	$	(17.2	)	$	—		$	252.6
Income from Discontinued Operations, Net of Tax	$	—	$	—	$	—		$	—		$	—
Net Income (Loss)	$	338.7	$	133.2	$	448.0		$	(472.4	)	$	447.5
Capital Expenditures	$	468.2	$	5.6	$	3.7		$	—		$	477.5
September 30, 2011
Operating Revenues (b)	$	3,331.1	$	327.5	$	0.6		$	(286.0	)	$	3,373.2
Other Operation and Maintenance	$	1,176.7	$	11.5	$	3.8		$	(282.7	)	$	909.3
Depreciation and Amortization	$	191.4	$	54.3	$	0.5		$	—		$	246.2
Operating Income (Loss)	$	436.7	$	261.7	$	(4.1	)	$	—		$	694.3
Equity in Earnings of Unconsolidated Affiliates	$	46.4	$	—	$	(0.3	)	$	—		$	46.1
Interest Expense, Net	$	82.1	$	49.8	$	46.0		$	(0.3	)	$	177.6
Income Tax Expense (Benefit)	$	145.9	$	84.2	$	(22.6	)	$	—		$	207.5
Income from Discontinued Operations, Net of Tax	$	—	$	—	$	11.5		$	—		$	11.5
Net Income (Loss)	$	297.1	$	127.9	$	410.0		$	(424.8	)	$	410.2
Capital Expenditures	$	583.1	$	22.2	$	6.9		$	—		$	612.2

(a) Corporate & Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark LLC, as well as interest on corporate debt.

(b) An elimination for intersegment revenues is included in Operating Revenues. This elimination is primarily between WePower and Wisconsin Electric.

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Derivative Instruments Derivative Instruments (Details 2) (Derivative [Member], USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Derivative [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities related to derivatives	$ 23.0	$ 21.7

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Common Equity Common Equity 1 (Details) (USD $)	3 Months Ended	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2012	Sep. 30, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate		3.90%	3.90%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate		19.00%	19.00%
Share Based Compensation Arrangement By Share Based Payment Award Fair Value Assumptions Expected Forfeiture Rate		2.00%	2.00%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term		5 years 11 months	5 years 6 months
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures	0	938,770	458,180
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 3.34	$ 3.17
Lower Range [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate		0.10%	0.20%
Upper Range [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate		2.00%	3.40%

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Common Equity

9 Months Ended

Sep. 30, 2012

Stockholders' Equity Note [Abstract]

COMMON EQUITY

COMMON EQUITY

Stock Option Activity:   During the first nine months of 2012, the Compensation Committee of the Board of Directors (Compensation Committee) granted 938,770 non-qualified stock options that had an estimated fair value of $3.34 per share. During the first nine months of 2011, the Compensation Committee granted 458,180 non-qualified stock options that had an estimated fair value of $3.17 per share. The following assumptions were used to value the options using a binomial option pricing model:

	2012		2011
Risk-free interest rate	0.1% - 2.0%		0.2% - 3.4%
Dividend yield	3.9	%	3.9	%
Expected volatility	19.0	%	19.0	%
Expected forfeiture rate	2.0	%	2.0	%
Expected life (years)	5.9		5.5

The risk-free interest rate is based on the U.S. Treasury interest rate whose term is consistent with the expected life of the stock options. Dividend yield, expected volatility, expected forfeiture rate and expected life assumptions are based on our historical experience.

The following is a summary of our stock option activity for the three and nine months ended September 30, 2012:

					Weighted-
					Average
			Weighted-		Remaining	Aggregate
	Number of		Average		Contractual Life	Intrinsic Value
Stock Options	Options		Exercise Price		(Years)	(Millions)
Outstanding as of July 1, 2012	9,571,531		$	23.42
Granted	—		$	—
Exercised	(370,020	)	$	17.89
Forfeited	—		$	—
Outstanding as of September 30, 2012	9,201,511		$	23.65
Outstanding as of January 1, 2012	10,638,750		$	21.65
Granted	938,770		$	34.88
Exercised	(2,368,289	)	$	19.11
Forfeited	(7,720	)	$	26.94
Outstanding as of September 30, 2012	9,201,511		$	23.65	5.4	$	129.0
Exercisable as of September 30, 2012	7,493,036		$	21.98	4.7	$	117.6

The intrinsic value of options exercised was $8.3 million and $42.1 million for the three and nine months ended September 30, 2012, and $3.6 million and $22.6 million for the same periods in 2011, respectively. Cash received from options exercised was $45.3 million and $34.4 million for the nine months ended September 30, 2012 and 2011, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was zero and approximately $9.0 million, respectively.

All outstanding stock options to purchase shares of common stock were included in the computation of diluted earnings per share during the third quarter and first nine months of 2012.

The following table summarizes information about stock options outstanding as of September 30, 2012:

	Options Outstanding				Options Exercisable
		Weighted-Average				Weighted-Average
				Remaining				Remaining
	Number of	Exercise		Contractual	Number of	Exercise		Contractual
Range of Exercise Prices	Options	Price		Life (Years)	Options	Price		Life (Years)
$12.71 to $19.74	1,874,519	$	18.29	2.6	1,874,519	$	18.29	2.6
$21.11 to $24.92	5,940,822	$	23.13	5.5	5,491,282	$	22.99	5.4
$29.35 to $34.88	1,386,170	$	33.09	8.9	127,235	$	32.67	8.9
	9,201,511	$	23.65	5.4	7,493,036	$	21.98	4.7

The following table summarizes information about our non-vested options during the three and nine months ended September 30, 2012:

			Weighted-Average
Non-Vested Stock Options	Number of Options		Fair Value
Non-vested as of July 1, 2012	1,726,165		$	3.31
Granted	—		$	—
Vested	(17,690	)	$	3.31
Forfeited	—		$	—
Non-vested as of September 30, 2012	1,708,475		$	3.31
Non-vested as of January 1, 2012	3,103,770		$	3.78
Granted	938,770		$	3.34
Vested	(2,326,345	)	$	3.96
Forfeited	(7,720	)	$	3.25
Non-vested as of September 30, 2012	1,708,475		$	3.31

As of September 30, 2012, total compensation costs related to non-vested stock options not yet recognized was approximately $1.7 million, which is expected to be recognized over the next 18 months on a weighted-average basis.

Restricted Shares:   During the first nine months of 2012, the Compensation Committee granted 94,959 restricted shares to directors, officers and other key employees. 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 have voting rights and are entitled to dividends in the same manner as other shareholders.

The following restricted stock activity occurred during the three and nine months ended September 30, 2012:

			Weighted-Average
Restricted Shares	Number of Shares		Grant Date Fair Value
Outstanding as of July 1, 2012	194,697
Granted	—		$	—
Released	—		$	—
Forfeited	(1,213	)	$	31.35
Outstanding as of September 30, 2012	193,484
Outstanding as of January 1, 2012	192,558
Granted	94,959		$	34.46
Released	(88,422	)	$	30.65
Forfeited	(5,611	)	$	30.94
Outstanding as of September 30, 2012	193,484

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 zero and $3.3 million for the three and nine months ended September 30, 2012, and zero and $2.3 million for the same periods in 2011, respectively. The actual tax benefit realized for the tax deductions from released restricted shares was zero for the three and nine months ended September 30, 2012, and zero and $0.7 million for the same periods in 2011, respectively.

As of September 30, 2012, total compensation cost related to restricted stock not yet recognized was approximately $3.3 million, which is expected to be recognized over the next 22 months on a weighted-average basis.

Performance Units:   In January 2012 and 2011, the Compensation Committee granted 346,570 and 435,690 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 period based on our estimate of the final expected value of the awards. Performance units earned as of December 31, 2011 and 2010 vested and were settled during the first quarter of 2012 and 2011, and had a total intrinsic value of $26.7 million and $12.6 million, respectively. The actual tax benefit realized for the tax deductions from the settlement of performance units was approximately $9.7 million and $4.3 million, respectively. As of September 30, 2012, total compensation cost related to performance units not yet recognized was approximately $18.4 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 us 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. See Note I -- Common Equity in our 2011 Annual Report on Form 10-K for additional information on these and other restrictions.

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

Comprehensive Income:   Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to owners.

There was no material other comprehensive income for the three and nine months ended September 30, 2012 or 2011.

Share Repurchase Program:   In May 2011, our Board of Directors authorized a share repurchase program that allows us to repurchase up to $300 million of our common stock through the end of 2013. Through September 30, 2012, we have repurchased $114.0 million of our common stock pursuant to this program at an average cost of $31.45 per share. The share 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. In addition, through our independent agents, we purchase shares on the open market to fulfill exercised stock options and restricted stock awards. The following table identifies the shares purchased by the Company in the following periods:

	Nine Months Ended September 30
	2012			2011
	Shares	Cost		Shares	Cost
	(In Millions)
Under May 2011 share repurchase program	0.4	$	14.0	2.5	$	75.0
To fulfill exercised stock options and restricted stock awards	2.5	91.0		1.9	60.1
Total	2.9	$	105.0	4.4	$	135.1

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Consolidated Condensed Balance Sheets (Unaudited) (USD $) In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2011
Property, Plant and Equipment
In service	$ 14,086.9	$ 12,977.7
Accumulated depreciation	(3,972.4)	(3,797.8)
Property, Plant and Equipment in Service, Net	10,114.5	9,179.9
Construction work in progress	269.4	921.3
Leased facilities, net	54.9	59.2
Net Property, Plant and Equipment	10,438.8	10,160.4
Investments
Equity investment in transmission affiliate	372.5	349.7
Other	36.4	43.6
Total Investments	408.9	393.3
Current Assets
Cash and cash equivalents	13.0	14.1
Restricted cash	9.5	45.5
Accounts receivable, net	298.6	349.4
Income taxes receivable	48.4	155.1
Accrued revenues	178.5	252.7
Materials, supplies and inventories	342.1	382.0
Prepayments and other	194.7	227.4
Total Current Assets	1,084.8	1,426.2
Deferred Charges and Other Assets
Regulatory assets	1,280.4	1,238.7
Goodwill	441.9	441.9
Other	179.9	201.6
Total Deferred Charges and Other Assets	1,902.2	1,882.2
Total Assets	13,834.7	13,862.1
Capitalization
Common equity	4,147.2	3,963.3
Preferred stock of subsidiary	30.4	30.4
Long-term debt	4,240.6	4,614.3
Total Capitalization	8,418.2	8,608.0
Current Liabilities
Long-term debt due currently	381.1	32.6
Short-term debt	453.2	669.9
Accounts payable	277.7	325.7
Accrued payroll and benefits	101.5	105.9
Other	173.5	230.4
Total Current Liabilities	1,387.0	1,364.5
Deferred Credits and Other Liabilities
Regulatory liabilities	872.9	902.0
Deferred income taxes - long-term	1,994.2	1,696.1
Deferred revenue, net	714.1	754.5
Pension and other benefit obligations	149.6	222.7
Other	298.7	314.3
Total Deferred Credits and Other Liabilities	4,029.5	3,889.6
Total Capitalization and Liabilities	$ 13,834.7	$ 13,862.1

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Common Equity (Tables)

9 Months Ended

Sep. 30, 2012

Common Equity (Tables) [Abstract]

Shares Repurchased [Table Text Block]

	Nine Months Ended September 30
	2012			2011
	Shares	Cost		Shares	Cost
	(In Millions)
Under May 2011 share repurchase program	0.4	$	14.0	2.5	$	75.0
To fulfill exercised stock options and restricted stock awards	2.5	91.0		1.9	60.1
Total	2.9	$	105.0	4.4	$	135.1

Assumptions for valuing options using binomial option pricing model

	2012		2011
Risk-free interest rate	0.1% - 2.0%		0.2% - 3.4%
Dividend yield	3.9	%	3.9	%
Expected volatility	19.0	%	19.0	%
Expected forfeiture rate	2.0	%	2.0	%
Expected life (years)	5.9		5.5

Stock option activity

					Weighted-
					Average
			Weighted-		Remaining	Aggregate
	Number of		Average		Contractual Life	Intrinsic Value
Stock Options	Options		Exercise Price		(Years)	(Millions)
Outstanding as of July 1, 2012	9,571,531		$	23.42
Granted	—		$	—
Exercised	(370,020	)	$	17.89
Forfeited	—		$	—
Outstanding as of September 30, 2012	9,201,511		$	23.65
Outstanding as of January 1, 2012	10,638,750		$	21.65
Granted	938,770		$	34.88
Exercised	(2,368,289	)	$	19.11
Forfeited	(7,720	)	$	26.94
Outstanding as of September 30, 2012	9,201,511		$	23.65	5.4	$	129.0
Exercisable as of September 30, 2012	7,493,036		$	21.98	4.7	$	117.6

Stock options outstanding

	Options Outstanding				Options Exercisable
		Weighted-Average				Weighted-Average
				Remaining				Remaining
	Number of	Exercise		Contractual	Number of	Exercise		Contractual
Range of Exercise Prices	Options	Price		Life (Years)	Options	Price		Life (Years)
$12.71 to $19.74	1,874,519	$	18.29	2.6	1,874,519	$	18.29	2.6
$21.11 to $24.92	5,940,822	$	23.13	5.5	5,491,282	$	22.99	5.4
$29.35 to $34.88	1,386,170	$	33.09	8.9	127,235	$	32.67	8.9
	9,201,511	$	23.65	5.4	7,493,036	$	21.98	4.7

Non-vested options

			Weighted-Average
Non-Vested Stock Options	Number of Options		Fair Value
Non-vested as of July 1, 2012	1,726,165		$	3.31
Granted	—		$	—
Vested	(17,690	)	$	3.31
Forfeited	—		$	—
Non-vested as of September 30, 2012	1,708,475		$	3.31
Non-vested as of January 1, 2012	3,103,770		$	3.78
Granted	938,770		$	3.34
Vested	(2,326,345	)	$	3.96
Forfeited	(7,720	)	$	3.25
Non-vested as of September 30, 2012	1,708,475		$	3.31

Restricted stock activity

			Weighted-Average
Restricted Shares	Number of Shares		Grant Date Fair Value
Outstanding as of July 1, 2012	194,697
Granted	—		$	—
Released	—		$	—
Forfeited	(1,213	)	$	31.35
Outstanding as of September 30, 2012	193,484
Outstanding as of January 1, 2012	192,558
Granted	94,959		$	34.46
Released	(88,422	)	$	30.65
Forfeited	(5,611	)	$	30.94
Outstanding as of September 30, 2012	193,484

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

XML

Document and Entity Information (USD $) In Billions, except Share data, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Jun. 30, 2012
Entity Information [Line Items]
Entity Registrant Name	WISCONSIN ENERGY CORP
Entity Central Index Key	0000783325
Document Type	10-Q
Document Period End Date	Sep. 30, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q3
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		$ 9.1
Entity Common Stock, Shares Outstanding (actual number of shares)	230,070,094

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Asset Sales, Divestitures and Discontinued Operations (Tables)

9 Months Ended

Sep. 30, 2012

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Net Impacts Of Discontinued Operations On Earnings [Table Text Block]

	Three Months Ended September 30				Nine Months Ended September 30
	2012		2011		2012		2011
	(Millions of Dollars)
Income from Continuing Operations	$	156.1	$	129.8	$	447.5	$	398.7
Income from Discontinued Operations, Net of Tax (a)	—		—		—		11.5
Net Income	$	156.1	$	129.8	$	447.5	$	410.2
(a) During 2011, we reached a favorable resolution of uncertain state and federal tax positions associated with our
previously discontinued manufacturing business.

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Consolidated Condensed Statements of Cash Flows (Unaudited) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Operating Activities
Net Income	$ 447.5	$ 410.2
Reconciliation to cash
Depreciation and amortization	278.2	248.9
Deferred income taxes and investment tax credits, net	249.6	215.9
Contributions to qualified benefit plans	(100.0)	(257.4)
Change in -
Accounts receivable and accrued revenues	118.7	136.4
Inventories	39.9	11.1
Other current assets	50.6	(18.7)
Accounts payable	(56.5)	(41.8)
Accrued income taxes, net	107.6	69.1
Other current liabilities	(15.3)	27.1
Other, net	(127.9)	26.8
Cash Provided by Operating Activities	992.4	827.6
Investing Activities
Capital expenditures	(477.5)	(612.2)
Investment in transmission affiliate	(13.1)	(6.6)
Proceeds from asset sales	3.0	38.5
Change in restricted cash	36.0	(37.2)
Other, net	(39.8)	(32.8)
Cash Used in Investing Activities	(491.4)	(650.3)
Financing Activities
Exercise of stock options	45.3	34.4
Purchase of common stock	(105.0)	(135.1)
Dividends paid on common stock	(207.4)	(182.0)
Issuance of long-term debt	0	720.0
Retirement and repurchase of long-term debt	(18.3)	(464.7)
Change in short-term debt	(216.7)	(161.2)
Other, net	0	1.9
Cash Used in Financing Activities	(502.1)	(186.7)
Change in Cash and Cash Equivalents	(1.1)	(9.4)
Cash and Cash Equivalents at Beginning of Period	14.1	24.5
Cash and Cash Equivalents at End of Period	$ 13.0	$ 15.1

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Benefits

9 Months Ended

Sep. 30, 2012

General Discussion of Pension and Other Postretirement Benefits [Abstract]

BENEFITS

BENEFITS

The components of our net periodic pension and Other Post-Retirement Employee Benefits (OPEB) costs for the three and nine months ended September 30 were as follows:

	Pension Costs
	Three Months Ended September 30						Nine Months Ended September 30
Benefit Plan Cost Components	2012			2011			2012			2011
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	5.5		$	4.0		$	16.3		$	11.9
Interest cost	16.4			16.9			49.2			50.7
Expected return on plan assets	(22.5		)	(20.5		)	(67.3		)	(61.6		)
Amortization of:
Prior service cost	0.5			0.6			1.7			1.7
Actuarial loss	10.2			8.4			30.4			25.5
Net Periodic Benefit Cost	$	10.1		$	9.4		$	30.3		$	28.2

	OPEB Costs
	Three Months Ended September 30						Nine Months Ended September 30
Benefit Plan Cost Components	2012			2011			2012			2011
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	2.6		$	2.6		$	7.8		$	7.8
Interest cost	5.1			5.2			15.3			15.6
Expected return on plan assets	(4.8		)	(4.3		)	(14.4		)	(12.7		)
Amortization of:
Transition obligation	—			—			0.2			0.2
Prior service (credit)	(0.5		)	(0.4		)	(1.4		)	(1.4		)
Actuarial loss	1.9			1.7			5.4			4.7
Net Periodic Benefit Cost	$	4.3		$	4.8		$	12.9		$	14.2

During the first nine months of 2012 and 2011, we contributed $100.0 million and $257.4 million, respectively, to our qualified benefit plans. Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates.

Postemployment Benefits:   Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $5.2 million as of September 30, 2012 and $15.3 million as of December 31, 2011.

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Derivative Instruments

9 Months Ended

Sep. 30, 2012

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 Public Service Commission of Wisconsin (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 September 30, 2012, we recognized $3.0 million in regulatory assets and $23.0 million in regulatory liabilities related to derivatives in comparison to $29.6 million in regulatory assets and $21.7 million in regulatory liabilities as of December 31, 2011.

We record our current derivative assets on the balance sheet in prepayments and other current assets and the current portion of the liabilities in other current liabilities. The long-term portion of our derivative assets of $1.6 million is recorded in other deferred charges and other assets as of September 30, 2012, and the long-term portion of our derivative liabilities of $0.2 million is recorded in other deferred credits and other liabilities as of September 30, 2012. Our Consolidated Condensed Balance Sheets as of September 30, 2012 and

December 31, 2011 include:

	September 30, 2012				December 31, 2011
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	12.0	$	—	$	2.1	$	9.1
Fuel Oil	0.9		—		0.3		0.1
FTRs	7.3		—		5.7		—
Coal	11.0		2.1		12.5		—
Total	$	31.2	$	2.1	$	20.6	$	9.2

Our Consolidated Condensed 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) were as follows:

	Three Months Ended September 30, 2012				Three Months Ended September 30, 2011
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)
Natural Gas	17.2 million Dth	$	(5.3	)	15.7 million Dth	$	(10.5	)
Fuel Oil	1.7 million gallons	0.1			2.2 million gallons	2.4
FTRs	5,927 MW	2.9			5,896 MW	5.2
Total		$	(2.3	)		$	(2.9	)

	Nine Months Ended September 30, 2012				Nine Months Ended September 30, 2011
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)
Natural Gas	56.0 million Dth	$	(35.7	)	54.0 million Dth	$	(27.7	)
Fuel Oil	5.5 million gallons	1.5			8.8 million gallons	4.9
FTRs	16,581 MW	5.1			18,439 MW	10.5
Total		$	(29.1	)		$	(12.3	)

As of September 30, 2012 and December 31, 2011, we posted collateral of $0.4 million and $11.9 million, respectively, in our margin accounts. These amounts are recorded on the balance sheets in other current assets.

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Common Equity (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Common Equity (Textuals) [Abstract]
Minimum percentage award based on performance unit			0.00
Maximum percentage award based on performance unit			1.75
Tax Benefit from Stock Options Exercised			$ 0	$ 9.0
Other Comprehensive Income (Loss), Net of Tax	0	0	0	0
Performance units [Member]
Common Equity (Textuals) [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period			346,570	435,690
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Intrinsic Value			26.7	12.6
Tax Benefit from Stock Options Exercised			9.7	4.3
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	18.4		18.4
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition			19 months
Restricted stock [Member]
Common Equity (Textuals) [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	0		94,959
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Intrinsic Value	0	0	3.3	2.3
Tax Benefit from Stock Options Exercised	0	0	0	0.7
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 3.3		$ 3.3
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition			22 months

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2012

Fair Value Measurements (Tables) [Abstract]

Financial assets and liabilities by level within the fair value hierarchy

Recurring Fair Value Measures	As of September 30, 2012
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	9.5	$	—	$	—	$	9.5
Derivatives	11.0		12.9		7.3		31.2
Total	$	20.5	$	12.9	$	7.3	$	40.7
Liabilities:
Derivatives	$	—	$	2.1	$	—	$	2.1
Total	$	—	$	2.1	$	—	$	2.1

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

Fair value of derivatives classified as Level 3 in the fair value hierarchy

	Three Months Ended September 30						Nine Months Ended September 30
	2012			2011			2012			2011
	(Millions of Dollars)
Beginning Balance	$	9.9		$	14.6		$	5.7		$	5.9
Realized and unrealized gains (losses)	—			—			—			—
Purchases	—			—			10.9			16.1
Issuances	—			—			—			—
Settlements	(2.6		)	(4.5		)	(9.3		)	(11.9		)
Transfers in and/or out of Level 3	—			—			—			—
Balance as of September 30	$	7.3		$	10.1		$	7.3		$	10.1
Change in unrealized gains (losses) relating to instruments still held as of September 30	$	—		$	—		$	—		$	—

Carrying amount and estimated fair value of certain financial instruments

	September 30, 2012				December 31, 2011
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	26.3	$	30.4	$	25.1
Long-term debt, including current portion	$	4,523.2	$	5,256.8	$	4,541.4	$	5,179.9

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2012

Commitments and Contingencies [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

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 Wisconsin Department of Natural Resources (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 September 30, 2012, 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.

Valley Power Plant Title V Air Permit:   The WDNR renewed Valley Power Plant's (VAPP) Title V operating permit in February 2011. The term of the permit is five years. Sierra Club and Clean Wisconsin requested and were granted an administrative hearing before the WDNR on certain conditions of the permit. The case has been stayed. In March 2011, the Sierra Club also petitioned the United States Environmental Protection Agency (EPA) for additional reductions and monitoring for particulate matter, and revisions to certain applicable requirements. No timeline has been set by the EPA to respond to that petition. In May 2012, the Sierra Club filed a notice of intent to bring suit to force the EPA to issue a response to that petition.

We believe that the permit was properly issued and that the plant is in compliance with all applicable regulations and standards. However, if as a result of either proceeding the permit is remanded to the WDNR, the plant will continue to operate under the previous operating permit.

We have made significant progress on the four voluntary goals we submitted in a December 2011 letter to the EPA. Through the end of the third quarter: (1) we achieved reductions in annual Sulfur Dioxide (SO₂) emissions from the plant to no more than 4,500 tons (a 65% decrease from 2001 emission levels); (2) the planned conversion of the plant from coal to natural gas would eliminate the requirement to meet the Mercury and Air Toxics Standards (MATS) rules and, therefore, the need for a dry sorbent injection system; (3) we held open houses and tours of VAPP 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) we announced plans for converting VAPP to natural gas fuel by the end of 2015, provided that we can obtain authorization from the PSCW to do so.

Divested Assets:   Pursuant to the sale of the Point Beach Nuclear Power Plant (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.

Cash Balance Pension Plan:   In June 2009, a lawsuit was filed by Alan M. Downes, a former employee, against the Wisconsin Energy Corporation Retirement Account Plan (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. The court approved the settlement on April 3, 2012 and issued its written order on April 20, 2012. Substantially all payments to class members have been made pursuant to the settlement. We do not anticipate further charges as a result of the settlement.

Income Taxes:   During the first quarter of 2012, the IRS issued guidance applicable to taxpayers that have taken positions within prior year tax returns relating to the conversion of capitalized assets to repair expense. As a result of this guidance, we have decreased our unrecognized tax benefits by approximately $7.4 million, exclusive of accrued interest.

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Segment Information

9 Months Ended

Sep. 30, 2012

Segment Information [Abstract]

SEGMENT INFORMATION

SEGMENT INFORMATION

Summarized financial information concerning our reportable segments for the three and nine months ended September 30, 2012 and 2011 is shown in the following table:

	Reportable Segments							Eliminations
	Energy				Corporate &			& Reconciling			Total
Three Months Ended	Utility		Non-Utility		Other (a)			Items			Consolidated
	(Millions of Dollars)
September 30, 2012
Operating Revenues (b)	$	1,023.3	$	112.6	$	0.3		$	(96.9	)	$	1,039.3
Other Operation and Maintenance	$	334.1	$	4.3	$	2.0		$	(95.8	)	$	244.6
Depreciation and Amortization	$	74.7	$	16.8	$	0.3		$	—		$	91.8
Operating Income (Loss)	$	191.0	$	91.5	$	(1.9	)	$	—		$	280.6
Equity in Earnings of Unconsolidated Affiliates	$	17.1	$	—	$	—		$	—		$	17.1
Interest Expense, Net	$	31.4	$	16.6	$	12.9		$	—		$	60.9
Income Tax Expense (Benefit)	$	65.6	$	29.2	$	(5.1	)	$	—		$	89.7
Income from Discontinued Operations, Net of Tax	$	—	$	—	$	—		$	—		$	—
Net Income (Loss)	$	119.8	$	45.8	$	156.1		$	(165.6	)	$	156.1
Capital Expenditures	$	161.2	$	1.8	$	0.5		$	—		$	163.5
September 30, 2011
Operating Revenues (b)	$	1,036.7	$	113.0	$	0.2		$	(97.1	)	$	1,052.8
Other Operation and Maintenance	$	387.0	$	4.9	$	1.0		$	(96.0	)	$	296.9
Depreciation and Amortization	$	64.1	$	18.3	$	0.2		$	—		$	82.6
Operating Income (Loss)	$	135.6	$	89.8	$	(1.1	)	$	—		$	224.3
Equity in Earnings of Unconsolidated Affiliates	$	15.7	$	—	$	(0.1	)	$	—		$	15.6
Interest Expense, Net	$	26.8	$	16.9	$	13.2		$	(0.1	)	$	56.8
Income Tax Expense (Benefit)	$	45.5	$	28.4	$	(4.3	)	$	—		$	69.6
Income from Discontinued Operations, Net of Tax	$	—	$	—	$	—		$	—		$	—
Net Income (Loss)	$	95.0	$	44.6	$	129.7		$	(139.5	)	$	129.8
Capital Expenditures	$	252.1	$	7.3	$	5.7		$	—		$	265.1

	Reportable Segments							Eliminations
	Energy				Corporate &			& Reconciling			Total
Nine Months Ended	Utility		Non-Utility		Other (a)			Items			Consolidated
	(Millions of Dollars)
September 30, 2012
Operating Revenues (b)	$	3,132.2	$	332.2	$	0.9		$	(290.1	)	$	3,175.2
Other Operation and Maintenance	$	1,069.0	$	11.7	$	4.7		$	(286.6	)	$	798.8
Depreciation and Amortization	$	218.8	$	50.3	$	0.6		$	—		$	269.7
Operating Income (Loss)	$	533.2	$	270.2	$	(4.5	)	$	—		$	798.9
Equity in Earnings of Unconsolidated Affiliates	$	48.9	$	—	$	(0.1	)	$	—		$	48.8
Interest Expense, Net	$	92.6	$	50.1	$	38.9		$	(0.3	)	$	181.3
Income Tax Expense (Benefit)	$	182.6	$	87.2	$	(17.2	)	$	—		$	252.6
Income from Discontinued Operations, Net of Tax	$	—	$	—	$	—		$	—		$	—
Net Income (Loss)	$	338.7	$	133.2	$	448.0		$	(472.4	)	$	447.5
Capital Expenditures	$	468.2	$	5.6	$	3.7		$	—		$	477.5
September 30, 2011
Operating Revenues (b)	$	3,331.1	$	327.5	$	0.6		$	(286.0	)	$	3,373.2
Other Operation and Maintenance	$	1,176.7	$	11.5	$	3.8		$	(282.7	)	$	909.3
Depreciation and Amortization	$	191.4	$	54.3	$	0.5		$	—		$	246.2
Operating Income (Loss)	$	436.7	$	261.7	$	(4.1	)	$	—		$	694.3
Equity in Earnings of Unconsolidated Affiliates	$	46.4	$	—	$	(0.3	)	$	—		$	46.1
Interest Expense, Net	$	82.1	$	49.8	$	46.0		$	(0.3	)	$	177.6
Income Tax Expense (Benefit)	$	145.9	$	84.2	$	(22.6	)	$	—		$	207.5
Income from Discontinued Operations, Net of Tax	$	—	$	—	$	11.5		$	—		$	11.5
Net Income (Loss)	$	297.1	$	127.9	$	410.0		$	(424.8	)	$	410.2
Capital Expenditures	$	583.1	$	22.2	$	6.9		$	—		$	612.2

(a) Corporate & Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark LLC, as well as interest on corporate debt.

(b) An elimination for intersegment revenues is included in Operating Revenues. This elimination is primarily between WePower and Wisconsin Electric.

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Variable Interest Entities

9 Months Ended

Sep. 30, 2012

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 that 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 less than one year. 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 approximately 10 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 $270.2 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 for the nine months ended September 30, 2012 and 2011 were $44.5 million and $51.0 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contracts.

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Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 2012

Supplemental Cash Flow Information [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

SUPPLEMENTAL CASH FLOW INFORMATION

During the nine months ended September 30, 2012, we paid $137.9 million in interest, net of amounts capitalized, and received $107.0 million in net refunds from income taxes. During the nine months ended September 30, 2011, we paid $138.1 million in interest, net of amounts capitalized, and received $62.7 million in net refunds from income taxes.

As of September 30, 2012 and 2011, the amount of accounts payable related to capital expenditures was $25.3 million and $19.2 million, respectively.

During the nine months ended September 30, 2012 and 2011, total amortization of deferred revenue was $41.2 million and $40.7 million, respectively.

During the nine months ended September 30, 2012 and 2011, our equity in earnings from ATC was $48.9 million and $46.4 million, respectively. During the nine months ended September 30, 2012 and 2011, distributions received from ATC were $39.0 million and $37.0 million, respectively.

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Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011
Derivatives, Fair Value [Line Items]
Derivative asset	$ 31.2		$ 31.2		$ 20.6
Derivative liability	2.1		2.1		9.2
Gains (losses)	(2.3)	(2.9)	(29.1)	(12.3)
Derivative Instruments (Textuals)
Collateral in margin accounts	0.4		0.4		11.9
Other Deferred Charges and Other Assets [Member]
Derivatives, Fair Value [Line Items]
Long-term portion of derivative assets	1.6		1.6
Other Deferred Credits and Other Liabilities [Member]
Derivatives, Fair Value [Line Items]
Long-term portion of derivative liabilities	0.2		0.2
Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Derivative asset	12.0		12.0		2.1
Derivative liability	0		0		9.1
Volume of derivative instruments	17.2 million Dth	15.7 million Dth	56.0 million Dth	54.0 million Dth
Gains (losses)	(5.3)	(10.5)	(35.7)	(27.7)
Fuel Oil [Member]
Derivatives, Fair Value [Line Items]
Derivative asset	0.9		0.9		0.3
Derivative liability	0		0		0.1
Volume of derivative instruments	1.7 million gallons	2.2 million gallons	5.5 million gallons	8.8 million gallons
Gains (losses)	0.1	2.4	1.5	4.9
Ftrs [Member]
Derivatives, Fair Value [Line Items]
Derivative asset	7.3		7.3		5.7
Derivative liability	0		0		0
Volume of derivative instruments	5,927 MW	5,896 MW	16,581 MW	18,439 MW
Gains (losses)	2.9	5.2	5.1	10.5
Coal [Member]
Derivatives, Fair Value [Line Items]
Derivative asset	11.0		11.0		12.5
Derivative liability	$ 2.1		$ 2.1		$ 0

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Benefits (Tables)

9 Months Ended

Sep. 30, 2012

Benefits (Tables) [Abstract]

Components of net periodic pension and OPEB costs

	Pension Costs
	Three Months Ended September 30						Nine Months Ended September 30
Benefit Plan Cost Components	2012			2011			2012			2011
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	5.5		$	4.0		$	16.3		$	11.9
Interest cost	16.4			16.9			49.2			50.7
Expected return on plan assets	(22.5		)	(20.5		)	(67.3		)	(61.6		)
Amortization of:
Prior service cost	0.5			0.6			1.7			1.7
Actuarial loss	10.2			8.4			30.4			25.5
Net Periodic Benefit Cost	$	10.1		$	9.4		$	30.3		$	28.2

	OPEB Costs
	Three Months Ended September 30						Nine Months Ended September 30
Benefit Plan Cost Components	2012			2011			2012			2011
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	2.6		$	2.6		$	7.8		$	7.8
Interest cost	5.1			5.2			15.3			15.6
Expected return on plan assets	(4.8		)	(4.3		)	(14.4		)	(12.7		)
Amortization of:
Transition obligation	—			—			0.2			0.2
Prior service (credit)	(0.5		)	(0.4		)	(1.4		)	(1.4		)
Actuarial loss	1.9			1.7			5.4			4.7
Net Periodic Benefit Cost	$	4.3		$	4.8		$	12.9		$	14.2

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Common Equity Common Equity 3 (Details) (USD $)	9 Months Ended
	Sep. 30, 2012
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	9,201,511
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 23.65
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Outstanding Options, Weighted Average Remaining Contractual Term	5 years 5 months
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number	7,493,036
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 21.98
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Weighted Average Remaining Contractual Term	4 years 8 months
Exercise Price, Range One [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Number of Outstanding Options	1,874,519
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 18.29
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Outstanding Options, Weighted Average Remaining Contractual Term	2 years 7 months
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Number of Exercisable Options	1,874,519
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 18.29
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Weighted Average Remaining Contractual Term	2 years 7 months
Exercise Price, Range One [Member] | Maximum [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 19.74
Exercise Price, Range One [Member] | Minimum [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 12.71
Exercise Price, Range Two [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Number of Outstanding Options	5,940,822
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 23.13
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Outstanding Options, Weighted Average Remaining Contractual Term	5 years 6 months
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Number of Exercisable Options	5,491,282
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 22.99
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Weighted Average Remaining Contractual Term	5 years 5 months
Exercise Price, Range Two [Member] | Maximum [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 24.92
Exercise Price, Range Two [Member] | Minimum [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 21.11
Exercise Price, Range Three [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Number of Outstanding Options	1,386,170
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 33.09
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Outstanding Options, Weighted Average Remaining Contractual Term	8 years 11 months
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Number of Exercisable Options	127,235
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 32.67
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Weighted Average Remaining Contractual Term	8 years 11 months
Exercise Price, Range Three [Member] | Maximum [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 34.88
Exercise Price, Range Three [Member] | Minimum [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 29.35

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Supplemental Cash Flow Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
Supplemental Cash Flow Information (Textuals)
Interest paid, net of amounts capitalized			$ 137.9	$ 138.1
Net refunds from income taxes			107.0	62.7
Accounts payable related to capital expenditures	25.3	19.2	25.3	19.2
Amortization of deferred revenue			(41.2)	(40.7)
Income (Loss) from Equity Method Investments	17.1	15.6	48.8	46.1
Distributions from transmission affiliate			39.0	37.0
Transmission Affiliate [Member]
Supplemental Cash Flow Information (Textuals)
Income (Loss) from Equity Method Investments	$ 17.1	$ 15.7	$ 48.9	$ 46.4

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General Information

9 Months Ended

Sep. 30, 2012

Organization, Consolidation and Presentation of Financial Statements [Abstract]

GENERAL INFORMATION

GENERAL INFORMATION

Our accompanying unaudited consolidated condensed financial statements should be read in conjunction with Item 8, Financial Statements and Supplementary Data, in our 2011 Annual Report on Form 10-K. In the opinion of management, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of the results of operations, cash flows and financial position in the accompanying income statements, statements of cash flows and balance sheets. The results of operations for the three and nine months ended September 30, 2012 are not necessarily indicative of the results which may be expected for the entire fiscal year 2012 because of seasonal and other factors.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2012

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 -- Pricing inputs are unadjusted quoted prices available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Instruments in this category consist of financial instruments such as exchange-traded derivatives, cash equivalents and restricted cash investments.

Level 2 -- Pricing inputs are other than quoted prices in active markets, which are either directly or indirectly observable as of the reporting date, and fair value is determined through the use of models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as Over-the-Counter (OTC) forwards and options.

Level 3 -- Pricing inputs include significant inputs that are generally less observable from objective sources. The inputs in the determination of fair value require significant management judgment or estimation. At each balance sheet date, we perform an analysis of all instruments subject to fair value reporting and include in Level 3 all instruments whose fair value is based on significant unobservable inputs.

In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, an instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the instrument.

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

Recurring Fair Value Measures	As of September 30, 2012
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	9.5	$	—	$	—	$	9.5
Derivatives	11.0		12.9		7.3		31.2
Total	$	20.5	$	12.9	$	7.3	$	40.7
Liabilities:
Derivatives	$	—	$	2.1	$	—	$	2.1
Total	$	—	$	2.1	$	—	$	2.1

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

Restricted cash consists of certificates of deposit and government backed interest bearing securities and represents the settlement we received from the United States Department of Energy (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:

	Three Months Ended September 30						Nine Months Ended September 30
	2012			2011			2012			2011
	(Millions of Dollars)
Beginning Balance	$	9.9		$	14.6		$	5.7		$	5.9
Realized and unrealized gains (losses)	—			—			—			—
Purchases	—			—			10.9			16.1
Issuances	—			—			—			—
Settlements	(2.6		)	(4.5		)	(9.3		)	(11.9		)
Transfers in and/or out of Level 3	—			—			—			—
Balance as of September 30	$	7.3		$	10.1		$	7.3		$	10.1
Change in unrealized gains (losses) relating to instruments still held as of September 30	$	—		$	—		$	—		$	—

Derivative instruments reflected in Level 3 of the hierarchy include MISO Financial Transmission Rights (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 7 -- Derivative Instruments for further information on the offset to regulatory assets and liabilities.

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

	September 30, 2012				December 31, 2011
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	26.3	$	30.4	$	25.1
Long-term debt, including current portion	$	4,523.2	$	5,256.8	$	4,541.4	$	5,179.9

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. Based on these assessments, the above items have been classified within Level 2.

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Common Equity Common Equity 4 (Details) (USD $)	3 Months Ended	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2012	Mar. 31, 2012
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	9,201,511	9,201,511
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 23.65	$ 23.65
Performance units [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition		19 months
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 18,400,000	$ 18,400,000
Non Vested Options [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number		3,103,770	1,726,165
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period	0	938,770
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested in Period	17,690	2,326,345
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period	0	(7,720)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	1,708,475	1,708,475	1,726,165
Non-vested options outstanding beginning balance, weighted average fair value		$ 3.78	$ 3.31
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 0.00	$ 3.34
Share Based Compensation Arrangements By Share Based Payment Awards Options Vested In Period Weighted Average Fair Value	3.31	3.96
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Intrinsic Value	$ 0.00	$ (3.25)
Non-vested options outstanding ending balance, weighted average fair value	$ 3.31	$ 3.31	$ 3.31
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 3.31	$ 3.31
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition		18 months
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 1,700,000	$ 1,700,000

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Segment Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2012		Sep. 30, 2011		Sep. 30, 2012		Sep. 30, 2011
Financial information of reportable operating segments
Operating Revenues	$ 1,039.3	[1]	$ 1,052.8	[1]	$ 3,175.2	[1]	$ 3,373.2	[1]
Other operation and maintenance	244.6		296.9		798.8		909.3
Depreciation and Amortization	91.8		82.6		269.7		246.2
Operating Income (Loss)	280.6		224.3		798.9		694.3
Equity in Earnings of Unconsolidated Affiliates	17.1		15.6		48.8		46.1
Interest Expense, net	60.9		56.8		181.3		177.6
Income Tax Expense (Benefit)	89.7		69.6		252.6		207.5
Income (Loss) from Discontinued Operations, Net of Tax	0		0		0		11.5
Net Income (Loss)	156.1		129.8		447.5		410.2
Capital Expenditures	163.5		265.1		477.5		612.2
Reportable Operating Segments Energy Utility [Member]
Financial information of reportable operating segments
Operating Revenues	1,023.3	[1]	1,036.7	[1]	3,132.2	[1]	3,331.1	[1]
Other operation and maintenance	334.1		387.0		1,069.0		1,176.7
Depreciation and Amortization	74.7		64.1		218.8		191.4
Operating Income (Loss)	191.0		135.6		533.2		436.7
Equity in Earnings of Unconsolidated Affiliates	17.1		15.7		48.9		46.4
Interest Expense, net	31.4		26.8		92.6		82.1
Income Tax Expense (Benefit)	65.6		45.5		182.6		145.9
Income (Loss) from Discontinued Operations, Net of Tax	0		0		0		0
Net Income (Loss)	119.8		95.0		338.7		297.1
Capital Expenditures	161.2		252.1		468.2		583.1
Reportable Operating Segments Energy Non Utility [Member]
Financial information of reportable operating segments
Operating Revenues	112.6	[1]	113.0	[1]	332.2	[1]	327.5	[1]
Other operation and maintenance	4.3		4.9		11.7		11.5
Depreciation and Amortization	16.8		18.3		50.3		54.3
Operating Income (Loss)	91.5		89.8		270.2		261.7
Equity in Earnings of Unconsolidated Affiliates	0		0		0		0
Interest Expense, net	16.6		16.9		50.1		49.8
Income Tax Expense (Benefit)	29.2		28.4		87.2		84.2
Income (Loss) from Discontinued Operations, Net of Tax	0		0		0		0
Net Income (Loss)	45.8		44.6		133.2		127.9
Capital Expenditures	1.8		7.3		5.6		22.2
Corporate and Other [Member]
Financial information of reportable operating segments
Operating Revenues	0.3	[1],[2]	0.2	[1],[2]	0.9	[1],[2]	0.6	[1],[2]
Other operation and maintenance	2.0	[2]	1.0	[2]	4.7	[2]	3.8	[2]
Depreciation and Amortization	0.3	[2]	0.2	[2]	0.6	[2]	0.5	[2]
Operating Income (Loss)	(1.9)	[2]	(1.1)	[2]	(4.5)	[2]	(4.1)	[2]
Equity in Earnings of Unconsolidated Affiliates	0	[2]	(0.1)	[2]	(0.1)	[2]	(0.3)	[2]
Interest Expense, net	12.9	[2]	13.2	[2]	38.9	[2]	46.0	[2]
Income Tax Expense (Benefit)	(5.1)	[2]	(4.3)	[2]	(17.2)	[2]	(22.6)	[2]
Income (Loss) from Discontinued Operations, Net of Tax	0	[2]	0	[2]	0	[2]	11.5	[2]
Net Income (Loss)	156.1	[2]	129.7	[2]	448.0	[2]	410.0	[2]
Capital Expenditures	0.5	[2]	5.7	[2]	3.7	[2]	6.9	[2]
Eliminations and Reconciling Items [Member]
Financial information of reportable operating segments
Operating Revenues	(96.9)	[1]	(97.1)	[1]	(290.1)	[1]	(286.0)	[1]
Other operation and maintenance	(95.8)		(96.0)		(286.6)		(282.7)
Depreciation and Amortization	0		0		0		0
Operating Income (Loss)	0		0		0		0
Equity in Earnings of Unconsolidated Affiliates	0		0		0		0
Interest Expense, net	0		(0.1)		(0.3)		(0.3)
Income Tax Expense (Benefit)	0		0		0		0
Income (Loss) from Discontinued Operations, Net of Tax	0		0		0		0
Net Income (Loss)	(165.6)		(139.5)		(472.4)		(424.8)
Capital Expenditures	$ 0		$ 0		$ 0		$ 0

[1] An elimination for intersegment revenues is included in Operating Revenues. This elimination is primarily between We Power and Wisconsin Electric.

[2] Corporate & Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark LLC, as well as interest on corporate debt.

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2012

Derivative Instruments (Tables) [Abstract]

Derivative instruments in balance sheet

	September 30, 2012				December 31, 2011
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	12.0	$	—	$	2.1	$	9.1
Fuel Oil	0.9		—		0.3		0.1
FTRs	7.3		—		5.7		—
Coal	11.0		2.1		12.5		—
Total	$	31.2	$	2.1	$	20.6	$	9.2

Derivative instruments' estimated notional volumes and gain (losses)

	Three Months Ended September 30, 2012				Three Months Ended September 30, 2011
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)
Natural Gas	17.2 million Dth	$	(5.3	)	15.7 million Dth	$	(10.5	)
Fuel Oil	1.7 million gallons	0.1			2.2 million gallons	2.4
FTRs	5,927 MW	2.9			5,896 MW	5.2
Total		$	(2.3	)		$	(2.9	)

	Nine Months Ended September 30, 2012				Nine Months Ended September 30, 2011
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)
Natural Gas	56.0 million Dth	$	(35.7	)	54.0 million Dth	$	(27.7	)
Fuel Oil	5.5 million gallons	1.5			8.8 million gallons	4.9
FTRs	16,581 MW	5.1			18,439 MW	10.5
Total		$	(29.1	)		$	(12.3	)