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, 2014

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, 2014):

Common Stock, $.01 Par Value, 225,517,341 shares outstanding.

Form 10-Q

WISCONSIN ENERGY CORPORATION

_______________________

FORM 10-Q REPORT FOR THE QUARTER ENDED SEPTEMBER 30, 2014

	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	23
3.	Quantitative and Qualitative Disclosures About Market Risk	42
4.	Controls and Procedures	42
	Part II -- Other Information
1.	Legal Proceedings	42
1A.	Risk Factors	43
6.	Exhibits	45
	Signatures	46

September 2014 2 Wisconsin Energy Corporation

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
PIPP	Presque Isle Power Plant
PSGS	Paris Generating Station
PWGS 1	Port Washington Generating Station Unit 1
PWGS 2	Port Washington Generating Station Unit 2
VAPP	Valley Power Plant
Other Subsidiaries and Affiliates
ATC	American Transmission Company LLC
ERGSS	Elm Road Generating Station Supercritical, LLC
WECC	Wisconsin Energy Capital Corporation
Federal and State Regulatory Agencies
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
MDEQ	Michigan Department of Environmental Quality
MPSC	Michigan Public Service Commission
PSCW	Public Service Commission of Wisconsin
SEC	Securities and Exchange Commission
WDNR	Wisconsin Department of Natural Resources
Environmental Terms
BART	Best Available Retrofit Technology
BTA	Best Technology Available
CAIR	Clean Air Interstate Rule
CSAPR	Cross-State Air Pollution Rule
EM	Entrainment Mortality
GHG	Greenhouse Gas
IM	Impingement Mortality
MATS	Mercury and Air Toxics Standards
NAAQS	National Ambient Air Quality Standards
NOV	Notice of Violation
NOx	Nitrogen Oxide
PSD	Prevention of Significant Deterioration
SIP	State Implementation Plan
SO2	Sulfur Dioxide

September 2014 3 Wisconsin Energy Corporation

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:
Other Terms and Abbreviations
ARRs	Auction Revenue Rights
Bechtel	Bechtel Power Corporation
Compensation Committee	Compensation Committee of the Board of Directors
Exchange Act	Securities Exchange Act of 1934, as amended
Fitch	Fitch Ratings
FTRs	Financial Transmission Rights
HSR Act	Hart-Scott-Rodino Antitrust Improvements Act of 1976
Integrys	Integrys Energy Group, Inc.
Junior Notes	Wisconsin Energy's 2007 Series A Junior Subordinated Notes due 2067
LMP	Locational Marginal Price
Merger Agreement	Agreement and Plan of Merger, dated as of June 22, 2014, between Integrys and Wisconsin Energy Corporation
MISO	Midcontinent Independent System Operator, Inc.
MISO Energy Markets	MISO Energy and Operating Reserves Market
Moody's	Moody's Investors Service
OTC	Over-the-Counter
PTF	Power the Future
S&P	Standard and Poor's Ratings Services
SSR	System Support Resource
Treasury Grant	Section 1603 Renewable Energy Treasury Grant
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
OPEB	Other Post-Retirement Employee Benefits

September 2014 4 Wisconsin Energy Corporation

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, retail sales and customer growth, rate actions and related filings with the appropriate regulatory authorities, current and proposed environmental regulations and other regulatory matters and related estimated expenditures, on-going legal proceedings, dividend payout ratios, projections related to the pension and other post-retirement benefit plans, fuel costs, sources of electric energy supply, coal and gas deliveries, remediation costs, 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," "could," "estimates," "expects," "forecasts," "goals," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects," "seeks," "should," "targets," "will" 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 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; or collective bargaining agreements with union employees or work stoppages.

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

• Timing, resolution and impact of rate cases and negotiations.

• The impact across our service territories of the continued adoption of distributed generation by our electric customers, and our ability to design and implement an appropriate rate structure to mitigate these impacts.

• Increased competition in our electric and gas markets, including retail choice and alternative electric suppliers, and continued industry consolidation.

• Our ability to continue to mitigate the impact of Michigan customers switching to an alternative electric supplier.

• The ability to control costs and avoid construction delays during the development and construction of new electric generation facilities, as well as upgrades to our generation fleet and electric and natural gas distribution systems.

• The impact of recent and future federal, state and local legislative and regulatory changes, including any changes in rate-setting policies or procedures; regulatory initiatives regarding deregulation and restructuring of the electric and/or gas utility industry; 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 cyber security threats; the regulatory approval process for new generation and transmission

September 2014 5 Wisconsin Energy Corporation

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION -- (CONT'D) Form 10-Q

facilities and new pipeline construction; adoption of new, or changes in existing, environmental, federal and state energy, tax and other laws and regulations to which we may become, or are, subject; changes in allocation of energy assistance, including state public benefits funds; changes in the application or enforcement 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.

• Current and future litigation, regulatory investigations, proceedings or inquiries.

• 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.

• Inflation rates.

• 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, as well as the ability of ATC and the Duke-American Transmission Company to obtain the required approvals for their transmission projects.

• The effect of accounting pronouncements issued periodically by standard setting bodies.

• Advances in technology 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 expected timing and likelihood of completion of the proposed acquisition of Integrys Energy Group, Inc. (Integrys), including the timing, receipt and terms and conditions of any required shareholder, governmental and regulatory approvals of the proposed acquisition that could reduce anticipated benefits or cause the parties to abandon the acquisition, the ability to successfully integrate the businesses, the ability to secure necessary financing on favorable terms, and the risk that the credit ratings of the combined company or its subsidiaries may differ from what we expect.

• Incidents affecting the U.S. electric grid or operation of generating facilities.

• 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, 2013 as updated in Item 1A. Risk Factors in Part II of this report.

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

September 2014 6 Wisconsin Energy Corporation

Form 10-Q

INTRODUCTION

Wisconsin Energy Corporation (Wisconsin Energy) 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 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, which owns and leases to Wisconsin Electric the generating capacity included in our Power the Future (PTF) strategy. See Item1. Business and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2013 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 Generally Accepted Accounting Principles pursuant to these rules and regulations. This Form 10-Q, including the financial statements contained herein, should be read in conjunction with our 2013 Annual Report on Form 10-K, including the financial statements and notes therein.

September 2014 7 Wisconsin Energy Corporation

Form 10-Q

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
	2014		2013		2014		2013
	(Millions of Dollars, Except Per Share Amounts)
Operating Revenues	$	1,033.3	$	1,053.2	$	3,772.0	$	3,340.7
Operating Expenses
Fuel and purchased power	336.8		339.1		947.9		886.2
Cost of gas sold	70.6		61.6		788.0		446.9
Other operation and maintenance	249.4		268.1		780.8		821.6
Depreciation and amortization	103.3		96.9		305.3		289.1
Property and revenue taxes	30.6		29.5		91.5		88.4
Total Operating Expenses	790.7		795.2		2,913.5		2,532.2
Treasury Grant	3.5		—		10.1		—
Operating Income	246.1		258.0		868.6		808.5
Equity in Earnings of Transmission Affiliate	18.0		17.1		52.8		51.0
Other Income, net	2.9		5.1		12.1		15.3
Interest Expense, net	60.4		62.0		181.7		190.3
Income Before Income Taxes	206.6		218.2		751.8		684.5
Income Tax Expense	80.3		80.7		284.9		251.4
Net Income	$	126.3	$	137.5	$	466.9	$	433.1
Earnings Per Share
Basic	$	0.56	$	0.61	$	2.07	$	1.90
Diluted	$	0.56	$	0.60	$	2.05	$	1.88
Weighted Average Common Shares Outstanding (Millions)
Basic	225.5		226.8		225.6		228.0
Diluted	227.4		228.8		227.6		230.2
Dividends Per Share of Common Stock	$	0.39	$	0.3825	$	1.17	$	1.0625
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, 2014			December 31, 2013
	(Millions of Dollars)
Assets
Property, Plant and Equipment
In service	$	15,330.9		$	14,966.3
Accumulated depreciation	(4,449.2		)	(4,257.1		)
	10,881.7			10,709.2
Construction work in progress	209.6			149.6
Leased facilities, net	43.6			47.8
Net Property, Plant and Equipment	11,134.9			10,906.6
Investments
Equity investment in transmission affiliate	423.3			402.7
Other	32.6			36.1
Total Investments	455.9			438.8
Current Assets
Cash and cash equivalents	88.7			26.0
Accounts receivable, net	339.0			406.0
Accrued revenues	159.1			321.1
Materials, supplies and inventories	379.3			329.4
Current deferred tax asset, net	165.5			310.0
Prepayments and other	142.9			158.6
Total Current Assets	1,274.5			1,551.1
Deferred Charges and Other Assets
Regulatory assets	1,096.7			1,108.5
Goodwill	441.9			441.9
Other	321.0			322.5
Total Deferred Charges and Other Assets	1,859.6			1,872.9
Total Assets	$	14,724.9		$	14,769.4
Capitalization and Liabilities
Capitalization
Common equity	$	4,398.3		$	4,233.0
Preferred stock of subsidiary	30.4			30.4
Long-term debt	4,569.6			4,363.2
Total Capitalization	8,998.3			8,626.6
Current Liabilities
Long-term debt due currently	47.7			342.2
Short-term debt	475.8			537.4
Accounts payable	315.0			342.6
Accrued payroll and benefits	71.4			96.9
Other	155.7			177.3
Total Current Liabilities	1,065.6			1,496.4
Deferred Credits and Other Liabilities
Regulatory liabilities	839.0			879.1
Deferred income taxes - long-term	2,752.7			2,634.0
Deferred revenue, net	627.2			664.2
Pension and other benefit obligations	168.9			173.2
Other	273.2			295.9
Total Deferred Credits and Other Liabilities	4,661.0			4,646.4
Total Capitalization and Liabilities	$	14,724.9		$	14,769.4
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 STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months Ended September 30
	2014			2013
	(Millions of Dollars)
Operating Activities
Net income	$	466.9		$	433.1
Reconciliation to cash
Depreciation and amortization	312.9			297.6
Deferred income taxes and investment tax credits, net	258.5			219.8
Change in - Accounts receivable and accrued revenues	221.1			95.3
Inventories	(49.9		)	(6.9		)
Other current assets	37.2			40.6
Accounts payable	(27.7		)	(59.2		)
Accrued income taxes, net	(10.3		)	48.2
Other current liabilities	(36.8		)	(0.1		)
Other, net	(137.3		)	(18.1		)
Cash Provided by Operating Activities	1,034.6			1,050.3
Investing Activities
Capital expenditures	(513.0		)	(497.7		)
Cost of removal, net of salvage	(18.2		)	(27.8		)
Investment in transmission affiliate	(10.5		)	(7.9		)
Other, net	12.8			(11.4		)
Cash Used in Investing Activities	(528.9		)	(544.8		)
Financing Activities
Exercise of stock options	31.7			42.7
Purchase of common stock	(84.2		)	(187.9		)
Dividends paid on common stock	(264.0		)	(242.3		)
Issuance of long-term debt	250.0			251.0
Retirement of long-term debt	(322.0		)	(364.2		)
Change in short-term debt	(61.6		)	(32.8		)
Other, net	7.1			10.9
Cash Used in Financing Activities	(443.0		)	(522.6		)
Change in Cash and Cash Equivalents	62.7			(17.1		)
Cash and Cash Equivalents at Beginning of Period	26.0			35.6
Cash and Cash Equivalents at End of Period	$	88.7		$	18.5
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 2013 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, 2014 are not necessarily indicative of the results which may be expected for the entire fiscal year 2014 because of seasonal and other factors.

2 -- NEW ACCOUNTING PRONOUNCEMENTS

Revenue Recognition:   In May 2014, the Financial Accounting Standards Board and the International Accounting Standards Board issued their joint revenue recognition standard, Accounting Standards Update 2014-09, Revenue from Contracts with Customers. This guidance is effective for fiscal years and interim periods beginning after December 15, 2016, and can either be applied retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently assessing the effects this guidance may have on our consolidated financial statements.

3 -- ACQUISITION

On June 22, 2014, Wisconsin Energy and Integrys entered into an agreement and plan of merger (Merger Agreement) under which Wisconsin Energy will acquire Integrys. Integrys’ shareholders will receive 1.128 shares of Wisconsin Energy common stock and $18.58 in cash per Integrys share of common stock, with the total consideration valued at approximately $5.4 billion, based upon the value of our common stock as of September 30, 2014. The cash consideration will be financed through the issuance of approximately $1.5 billion of debt at the holding company level. The combined company will be named WEC Energy Group, Inc.

The acquisition is subject to several conditions, including, among others, approval of the shareholders of both Wisconsin Energy and Integrys, the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR Act), and the receipt of approvals from various government agencies, including the Federal Energy Regulatory Commission (FERC), Federal Communications Commission, Public Service Commission of Wisconsin (PSCW), Illinois Commerce Commission, Michigan Public Service Commission (MPSC) and Minnesota Public Utilities Commission. The status of these matters is as follows:

• On August 6, 2014, we filed applications for approval with the PSCW, Illinois Commerce Commission, MPSC and Minnesota Public Utilities Commission.

• On August 13, 2014, we filed an initial registration statement on Form S-4 with the SEC to register the stock consideration. On October 6, 2014, the Form S-4, which contains a joint proxy statement/prospectus for Wisconsin Energy and Integrys, was declared effective by the SEC. Meetings for Wisconsin Energy and Integrys shareholders to vote on the acquisition are scheduled for November 21, 2014.

• On August 15, 2014, we filed an application with the FERC.

• On September 24, 2014, we submitted our HSR Act filings, and on October 24, 2014, the United States Department of Justice closed its review of the transaction with no further action required. In addition, on October 24, 2014, the Federal Trade Commission granted early termination of the 30-day waiting period required by the HSR Act.

We anticipate the transaction closing in the second half of 2015.

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Form 10-Q

4 -- COMMON EQUITY

Stock Option Activity:   The following table identifies non-qualified stock options granted by the Compensation Committee of the Board of Directors (Compensation Committee):

	2014			2013
Non-qualified stock options granted year to date	899,500			1,418,560
Estimated fair value per non-qualified stock option	$	4.18		$	3.45
Assumptions used to value the options using a binomial option pricing model:
Risk-free interest rate	0.1% - 3.0%			0.1% - 1.9%
Dividend yield	3.8		%	3.7		%
Expected volatility	18.0		%	18.0		%
Expected forfeiture rate	2.0		%	2.0		%
Expected life (years)	5.8			5.9

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, 2014:

					Weighted-
					Average
			Weighted-		Remaining	Aggregate
	Number of		Average		Contractual Life	Intrinsic Value
Stock Options	Options		Exercise Price		(Years)	(Millions)
Outstanding as of July 1, 2014	8,169,393		$	28.87
Granted	—		$	—
Exercised	(597,641	)	$	23.69
Forfeited	—		$	—
Outstanding as of September 30, 2014	7,571,752		$	29.27
Outstanding as of January 1, 2014	8,089,710		$	26.84
Granted	899,500		$	41.03
Exercised	(1,400,263	)	$	22.66
Forfeited	(17,195	)	$	36.73
Outstanding as of September 30, 2014	7,571,752		$	29.27	5.6	$	103.9
Exercisable as of September 30, 2014	4,691,897		$	23.95	3.9	$	89.4

The intrinsic value of options exercised was $12.7 million and $30.2 million for the three and nine months ended September 30, 2014, and $1.9 million and $37.9 million for the same periods in 2013, respectively. Cash received from options exercised was $31.7 million and $42.7 million for the nine months ended September 30, 2014 and 2013, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was $12.1 million and $15.1 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 of 2014.

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Form 10-Q

The following table summarizes information about stock options outstanding as of September 30, 2014:

	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)
$17.10 to $21.11	1,663,372	$	20.70	3.6	1,663,372	$	20.70	3.6
$23.88 to $29.35	2,778,020	$	24.82	3.7	2,778,020	$	24.82	3.7
$34.88 to $41.03	3,130,360	$	37.78	8.3	250,505	$	35.83	7.6
	7,571,752	$	29.27	5.6	4,691,897	$	23.95	3.9

The following table summarizes information about our non-vested options during the three and nine months ended September 30, 2014:

			Weighted-Average
Non-Vested Stock Options	Number of Options		Fair Value
Non-vested as of July 1, 2014	2,916,245		$	3.65
Granted	—		$	—
Vested	(36,390	)	$	3.62
Forfeited	—		$	—
Non-vested as of September 30, 2014	2,879,855		$	3.65
Non-vested as of January 1, 2014	2,380,790		$	3.38
Granted	899,500		$	4.18
Vested	(383,240	)	$	3.26
Forfeited	(17,195	)	$	3.56
Non-vested as of September 30, 2014	2,879,855		$	3.65

As of September 30, 2014, total compensation costs related to non-vested stock options not yet recognized was approximately $3.0 million, which is expected to be recognized over the next 18 months on a weighted-average basis.

Restricted Shares:   The following restricted stock activity occurred during the three and nine months ended September 30, 2014:

			Weighted-Average
Restricted Shares	Number of Shares		Grant Date Fair Value
Outstanding as of July 1, 2014	156,768
Granted	—		$	—
Released	—		$	—
Forfeited	(1,289	)	$	38.61
Outstanding as of September 30, 2014	155,479
Outstanding as of January 1, 2014	150,698
Granted	71,504		$	40.96
Released	(63,509	)	$	33.02
Forfeited	(3,214	)	$	38.47
Outstanding as of September 30, 2014	155,479

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

September 2014 13 Wisconsin Energy Corporation

Form 10-Q

$2.7 million for the three and nine months ended September 30, 2014, and zero and $4.0 million for the same periods in 2013, respectively. The actual tax benefit realized for the tax deductions from released restricted shares was zero and $1.0 million for the three and nine months ended September 30, 2014, and zero and $1.3 million for the same periods in 2013, respectively.

As of September 30, 2014, total compensation cost related to restricted stock not yet recognized was approximately $3.5 million, which is expected to be recognized over the next 22 months on a weighted-average basis.

Performance Units:   In January 2014 and 2013, the Compensation Committee granted 233,735 and 239,120 performance units, respectively, to officers and other key employees under the Wisconsin Energy Performance Unit Plan. Performance units earned as of December 31, 2013 and 2012 vested and were settled during the first quarter of 2014 and 2013, and had a total intrinsic value of $14.8 million and $19.3 million, respectively. The actual tax benefit realized for the tax deductions from the settlement of performance units was approximately $5.3 million and $7.0 million, respectively. As of September 30, 2014, total compensation cost related to performance units not yet recognized was approximately $7.8 million, which is expected to be recognized over the next 26 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 H -- Common Equity in our 2013 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.

Share Repurchase Program:   In December 2013, our Board of Directors authorized a share repurchase program for the purchase of up to $300 million of our common stock through open market purchases or privately negotiated transactions from January 1, 2014 through the end of 2017. On June 22, 2014, in connection with the proposed acquisition of Integrys, the Board of Directors terminated this share repurchase program. For the nine months ended September 30, 2014, we repurchased $18.6 million of our common stock pursuant to the terminated program at an average cost of $43.66 per share. All of these shares were purchased during the first quarter of 2014. The previous share repurchase program authorized by our Board of Directors expired at the end of 2013. In addition, we have instructed our independent agents to purchase shares on the open market to fulfill exercised stock options and restricted stock awards. The following table identifies shares purchased in the following periods:

	Nine Months Ended September 30
	2014			2013
	Shares	Cost		Shares	Cost
	(In Millions)
Under share repurchase programs	0.4	$	18.6	2.5	$	103.0
To fulfill exercised stock options and restricted stock awards	1.5	65.6		2.1	84.9
Total	1.9	$	84.2	4.6	$	187.9

5 -- LONG-TERM DEBT

In May 2014, Wisconsin Electric issued $250 million of 4.25% Debentures due June 1, 2044. The debentures were issued under an existing shelf registration statement filed with the SEC in November 2013.

In April 2014, Wisconsin Electric retired $300 million of long-term debt that matured.

In September 2013, Wisconsin Gas used short-term borrowings to retire $45 million of long-term debt that matured.

September 2014 14 Wisconsin Energy Corporation

Form 10-Q

In June 2013, Wisconsin Electric issued $250 million of 1.70% Debentures due June 15, 2018. The debentures were issued under an existing shelf registration statement filed with the SEC in February 2011.

In May 2013, Wisconsin Electric retired $300 million of long-term debt that matured.

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:

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, 2014
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Derivatives	$	2.9	$	11.4	$	10.1	$	24.4
Total	$	2.9	$	11.4	$	10.1	$	24.4
Liabilities:
Derivatives	$	1.6	$	—	$	—	$	1.6
Total	$	1.6	$	—	$	—	$	1.6

September 2014 15 Wisconsin Energy Corporation

Form 10-Q

Recurring Fair Value Measures	As of December 31, 2013
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Derivatives	$	5.7	$	2.6	$	3.5	$	11.8
Total	$	5.7	$	2.6	$	3.5	$	11.8
Liabilities:
Derivatives	$	—	$	0.3	$	—	$	0.3
Total	$	—	$	0.3	$	—	$	0.3

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
	2014			2013			2014			2013
	(Millions of Dollars)
Beginning Balance	$	14.1		$	9.2		$	3.5		$	4.7
Realized and unrealized gains (losses)	—			—			—			—
Purchases	—			—			15.6			10.6
Issuances	—			—			—			—
Settlements	(4.0		)	(3.6		)	(9.0		)	(9.7		)
Transfers in and/or out of Level 3	—			—			—			—
Balance as of September 30	$	10.1		$	5.6		$	10.1		$	5.6
Change in unrealized gains (losses) relating to instruments still held as of September 30	$	—		$	—		$	—		$	—

Derivative instruments reflected in Level 3 of the hierarchy include Midcontinent Independent System Operator, Inc. (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.

September 2014 16 Wisconsin Energy Corporation

Form 10-Q

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

	September 30, 2014				December 31, 2013
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	25.4	$	30.4	$	26.0
Long-term debt, including current portion	$	4,554.7	$	4,979.7	$	4,626.7	$	4,911.8

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.

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 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. As of September 30, 2014, we recognized $2.5 million in regulatory assets and $21.5 million in regulatory liabilities related to derivatives in comparison to $0.3 million in regulatory assets and $9.6 million in regulatory liabilities as of December 31, 2013.

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 $1.7 million is recorded in other deferred charges and other assets as of September 30, 2014, and the long-term portion of our derivative liabilities of $0.1 million is recorded in other deferred credit and other liabilities as of September 30, 2014. Our Consolidated Condensed Balance Sheets as of September 30, 2014 and December 31, 2013 include:

	September 30, 2014				December 31, 2013
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	8.8	$	1.6	$	5.6	$	0.1
Fuel Oil	—		—		0.6		—
FTRs	10.1		—		3.5		—
Coal	5.5		—		2.1		0.2
Total	$	24.4	$	1.6	$	11.8	$	0.3

September 2014 17 Wisconsin Energy Corporation

Form 10-Q

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, 2014				Three Months Ended September 30, 2013
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)
Natural Gas	6.3 million Dth	$	(0.8	)	6.3 million Dth	$	(1.1	)
Fuel Oil	2.6 million gallons	—			2.5 million gallons	(0.1		)
FTRs	6.6 million MWh	2.0			6.9 million MWh	5.4
Total		$	1.2			$	4.2

	Nine Months Ended September 30, 2014			Nine Months Ended September 30, 2013
	Volume	Gains (Losses)		Volume	Gains (Losses)
		(Millions of Dollars)			(Millions of Dollars)
Natural Gas	31.1 million Dth	$	9.3	36.4 million Dth	$	(5.7	)
Fuel Oil	7.0 million gallons	0.6		6.2 million gallons	0.1
FTRs	19.7 million MWh	11.6		19.2 million MWh	11.0
Total		$	21.5		$	5.4

As of September 30, 2014 and December 31, 2013, we posted collateral of $1.8 million and zero, respectively, in our margin accounts. These amounts are recorded on the balance sheets in other current assets.

The fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. The table below shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on the balance sheet as of September 30, 2014 and December 31, 2013.

	September 30, 2014						December 31, 2013
	Derivative			Derivative			Derivative		Derivative
	Asset			Liability			Asset		Liability
	(Millions of Dollars)
Gross Amount Recognized on the Balance Sheet	$	24.4		$	1.6		$	11.8	$	0.3
Gross Amount Not Offset on Balance Sheet (a)	(0.6		)	(1.6		)	—		—
Net Amount	$	23.8		$	—		$	11.8	$	0.3

(a) Gross Amount Not Offset on Balance Sheet includes cash collateral posted of $1.0 million and zero as of September 30, 2014 and December 31, 2013, respectively.

September 2014 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	2014			2013			2014			2013
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	2.6		$	3.7		$	7.6		$	11.0
Interest cost	17.0			15.1			51.1			45.3
Expected return on plan assets	(24.7		)	(23.9		)	(74.0		)	(71.8		)
Amortization of:
Prior service cost	0.6			0.5			1.6			1.7
Actuarial loss	9.1			13.6			27.5			40.8
Net Periodic Benefit Cost	$	4.6		$	9.0		$	13.8		$	27.0

	OPEB Costs
	Three Months Ended September 30						Nine Months Ended September 30
Benefit Plan Cost Components	2014			2013			2014			2013
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	2.1		$	2.5		$	6.4		$	7.5
Interest cost	4.4			3.9			13.3			11.7
Expected return on plan assets	(5.9		)	(5.4		)	(17.8		)	(16.0		)
Amortization of:
Transition obligation	—			—			—			—
Prior service (credit)	(0.4		)	(0.5		)	(1.3		)	(1.5		)
Actuarial loss	0.3			1.0			0.9			2.8
Net Periodic Benefit Cost	$	0.5		$	1.5		$	1.5		$	4.5

We made no contributions to our qualified benefit plans during the first nine months of 2014 and 2013. 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 $4.2 million as of both September 30, 2014 and December 31, 2013.

September 2014 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, 2014 and 2013 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, 2014
Operating Revenues (b)	$	1,017.7	$	114.1	$	0.3		$	(98.8	)	$	1,033.3
Other Operation and Maintenance	$	337.4	$	3.5	$	6.0		$	(97.5	)	$	249.4
Depreciation and Amortization	$	86.3	$	17.0	$	—		$	—		$	103.3
Operating Income (Loss)	$	158.4	$	93.6	$	(5.9	)	$	—		$	246.1
Equity in Earnings of Unconsolidated Affiliates	$	18.0	$	—	$	—		$	—		$	18.0
Interest Expense, Net	$	32.1	$	16.1	$	12.4		$	(0.2	)	$	60.4
Income Tax Expense (Benefit)	$	55.0	$	30.4	$	(5.1	)	$	—		$	80.3
Net Income (Loss)	$	90.8	$	47.3	$	126.3		$	(138.1	)	$	126.3
Capital Expenditures	$	188.2	$	18.0	$	1.3		$	—		$	207.5
September 30, 2013
Operating Revenues (b)	$	1,037.2	$	114.2	$	0.4		$	(98.6	)	$	1,053.2
Other Operation and Maintenance	$	359.5	$	4.2	$	1.9		$	(97.5	)	$	268.1
Depreciation and Amortization	$	79.9	$	16.8	$	0.2		$	—		$	96.9
Operating Income (Loss)	$	166.6	$	93.2	$	(1.8	)	$	—		$	258.0
Equity in Earnings of Unconsolidated Affiliates	$	17.1	$	—	$	—		$	—		$	17.1
Interest Expense, Net	$	33.0	$	16.4	$	12.8		$	(0.2	)	$	62.0
Income Tax Expense (Benefit)	$	56.1	$	29.5	$	(4.9	)	$	—		$	80.7
Net Income (Loss)	$	99.3	$	47.4	$	137.4		$	(146.6	)	$	137.5
Capital Expenditures	$	178.1	$	10.4	$	1.9		$	—		$	190.4

September 2014 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, 2014
Operating Revenues (b)	$	3,729.6	$	335.8	$	0.9		$	(294.3	)	$	3,772.0
Other Operation and Maintenance	$	1,048.6	$	9.7	$	13.3		$	(290.8	)	$	780.8
Depreciation and Amortization	$	254.2	$	50.6	$	0.5		$	—		$	305.3
Operating Income (Loss)	$	606.3	$	275.5	$	(13.2	)	$	—		$	868.6
Equity in Earnings of Unconsolidated Affiliates	$	52.8	$	—	$	—		$	—		$	52.8
Interest Expense, Net	$	96.8	$	48.6	$	36.8		$	(0.5	)	$	181.7
Income Tax Expense (Benefit)	$	213.8	$	90.6	$	(19.5	)	$	—		$	284.9
Net Income (Loss)	$	356.5	$	136.8	$	466.7		$	(493.1	)	$	466.9
Capital Expenditures	$	481.5	$	27.7	$	3.8		$	—		$	513.0
September 30, 2013
Operating Revenues (b)	$	3,296.7	$	337.3	$	1.0		$	(294.3	)	$	3,340.7
Other Operation and Maintenance	$	1,097.7	$	10.6	$	4.1		$	(290.8	)	$	821.6
Depreciation and Amortization	$	238.2	$	50.3	$	0.6		$	—		$	289.1
Operating Income (Loss)	$	536.1	$	276.4	$	(4.0	)	$	—		$	808.5
Equity in Earnings of Unconsolidated Affiliates	$	51.0	$	—	$	—		$	—		$	51.0
Interest Expense, Net	$	103.1	$	49.4	$	38.2		$	(0.4	)	$	190.3
Income Tax Expense (Benefit)	$	179.9	$	90.1	$	(18.6	)	$	—		$	251.4
Net Income (Loss)	$	317.9	$	137.2	$	432.9		$	(454.9	)	$	433.1
Capital Expenditures	$	476.2	$	17.5	$	4.0		$	—		$	497.7

(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 a purchased power agreement which represents a variable interest. This agreement is for 236 MW of firm capacity from a gas-fired cogeneration facility and we account for it as a capital lease. The agreement includes no minimum energy requirements over the remaining term of approximately eight 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 $184.4 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under contracts considered variable interests for the nine months ended September 30, 2014 and

September 2014 21 Wisconsin Energy Corporation

Form 10-Q

2013 were $39.8 million and $37.8 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

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. 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 $19 million to $56 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, 2014, we have established reserves of $36.9 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.

Divested Assets:   Pursuant to the sale of the Point Beach Nuclear Power Plant, we agreed to indemnification provisions customary to transactions involving the sale of nuclear assets. We also provided customary indemnifications to Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corp., in connection with the sale of our interest in Edgewater Generating Unit 5.

12 -- SUPPLEMENTAL CASH FLOW INFORMATION

During the nine months ended September 30, 2014, we paid $143.4 million in interest, net of amounts capitalized, and paid $22.0 million in income taxes, net of refunds. During the nine months ended September 30, 2013, we paid $146.6 million in interest, net of amounts capitalized, and received $38.3 million in net refunds from income taxes.

As of September 30, 2014 and 2013, the amount of accounts payable related to capital expenditures was $4.9 million and $3.4 million, respectively.

During the nine months ended September 30, 2014 and 2013, total amortization of deferred revenue was $41.7 million and $42.7 million, respectively.

During the nine months ended September 30, 2014 and 2013, our equity in earnings from ATC was $52.8 million and $51.0 million, respectively. During the nine months ended September 30, 2014 and 2013, distributions received from ATC were $42.6 million and $40.5 million, respectively.

September 2014 22 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, 2014

CONSOLIDATED EARNINGS

The following table compares our operating income by business segment and our net income during the third quarter of 2014 with the third quarter of 2013, including favorable (better (B)) or unfavorable (worse (W)) variances:

	Three Months Ended September 30
	2014			B (W)			2013
	(Millions of Dollars, Except Per Share Amounts)
Utility Energy Segment	$	158.4		$	(8.2	)	$	166.6
Non-Utility Energy Segment	93.6			0.4			93.2
Corporate and Other	(5.9		)	(4.1		)	(1.8		)
Total Operating Income	246.1			(11.9		)	258.0
Equity in Earnings of Transmission Affiliate	18.0			0.9			17.1
Other Income, net	2.9			(2.2		)	5.1
Interest Expense, net	60.4			1.6			62.0
Income Before Income Taxes	206.6			(11.6		)	218.2
Income Tax Expense	80.3			0.4			80.7
Net Income	$	126.3		$	(11.2	)	$	137.5
Diluted Earnings Per Share	$	0.56		$	(0.04	)	$	0.60

UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Our utility energy segment contributed $158.4 million of operating income during the third quarter of 2014, a decrease of $8.2 million, or 4.9%, compared with the third quarter of 2013. The following table summarizes the operating income of this segment between the comparative quarters:

	Three Months Ended September 30
Utility Energy Segment	2014		B (W)			2013
	(Millions of Dollars)
Operating Revenues
Electric	$	880.1	$	(30.9	)	$	911.0
Gas	131.9		11.3			120.6
Other	5.7		0.1			5.6
Total Operating Revenues	1,017.7		(19.5		)	1,037.2
Operating Expenses
Fuel and Purchased Power	338.2		2.2			340.4
Cost of Gas Sold	70.6		(9.0		)	61.6
Other Operation and Maintenance	337.4		22.1			359.5
Depreciation and Amortization	86.3		(6.4		)	79.9
Property and Revenue Taxes	30.3		(1.1		)	29.2
Total Operating Expenses	862.8		7.8			870.6
Treasury Grant	3.5		3.5			—
Operating Income	$	158.4	$	(8.2	)	$	166.6

September 2014 23 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 2014 with the third quarter of 2013:

	Three Months Ended September 30
	Electric Revenues							MWh
Electric Utility Operations	2014		B (W)			2013		2014	B (W)		2013
	(Millions of Dollars)							(Thousands)
Customer Class
Residential	$	308.2	$	(24.5	)	$	332.7	2,033.8	(173.9	)	2,207.7
Small Commercial/Industrial	281.8		(6.1		)	287.9		2,343.9	(37.7	)	2,381.6
Large Commercial/Industrial	171.4		(28.8		)	200.2		1,981.0	(345.3	)	2,326.3
Other - Retail	5.3		(0.2		)	5.5		33.4	(1.2	)	34.6
Total Retail	766.7		(59.6		)	826.3		6,392.1	(558.1	)	6,950.2
Wholesale - Other	28.6		(4.0		)	32.6		353.9	(51.9	)	405.8
Resale - Utilities	62.7		17.3			45.4		1,963.7	533.5		1,430.2
Other Operating Revenues	20.9		14.5			6.4		—	—		—
Total	878.9		(31.8		)	910.7		8,709.7	(76.5	)	8,786.2
Electric Customer Choice (a)	1.2		0.9			0.3		595.4	394.9		200.5
Total, including electric customer choice	$	880.1	$	(30.9	)	$	911.0
Weather -- Degree Days (b)
Heating (121 Normal)								175	45		130
Cooling (548 Normal)								352	(188	)	540
(a) Represents distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.
(b) 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 decreased by $30.9 million, or 3.4%, when compared to the third quarter of 2013. The most significant factors that caused a change in revenues were:

• Cooler summer weather decreased electric revenues by an estimated $40.5 million.

• A $22.8 million decrease in large commercial/industrial sales because of the two iron ore mines switching to an alternative electric supplier in September 2013. See Factors Affecting Results, Liquidity and Capital Resources - Electric Transmission and Energy Markets - Restructuring in Michigan, for a discussion of the impact of industry restructuring in Michigan on our electric sales.

• A $17.3 million increase in sales for resale resulting from increased sales into the MISO Energy and Operating Reserves Market (MISO Energy Markets) as a result of Michigan's alternative electric supplier program.

• A $14.5 million increase in other operating revenues, primarily driven by the recognition of $12.6 million related to revenues under the System Support Resource (SSR) agreement with MISO. See Factors Affecting Results, Liquidity and Capital Resources - Electric Transmission and Energy Markets - Restructuring in Michigan, for a discussion of the SSR payments.

• Wisconsin net retail pricing increases of $10.9 million, which are primarily related to our 2013 Wisconsin Rate Case. For information on the rate order in the 2013 rate case and the 2014 fuel credits, see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters.

As measured by cooling degree days, the third quarter of 2014 was 34.8% cooler than the same period in 2013 and 35.8% cooler than normal. We believe the cooler weather was the primary driver of reduced sales to our residential and small commercial/industrial customers. Sales to large commercial/industrial customers decreased by 14.8%, primarily because of the loss of the two iron ore mines in Michigan as retail electric customers. If the sales to the mines are excluded, sales to our large commercial/industrial customers decreased 2.3%.

September 2014 24 Wisconsin Energy Corporation

Form 10-Q

Fuel and Purchased Power

Our fuel and purchased power costs decreased by $2.2 million, or 0.6%, when compared to the third quarter of 2013. This decrease was primarily caused by a 0.9% decrease in total MWh sales, which was partially offset by higher generating costs driven by an increase in natural gas prices as compared to the third quarter of 2013.

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 2014 with the third quarter of 2013. 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 increased by $11.3 million, or 9.4%. Cost of gas sold increased by $9.0 million, or 14.6%, because of an increase in the average cost of delivered gas.

	Three Months Ended September 30
	2014		B (W)			2013
	(Millions of Dollars)
Gas Operating Revenues	$	131.9	$	11.3		$	120.6
Cost of Gas Sold	70.6		(9.0		)	61.6
Gross Margin	$	61.3	$	2.3		$	59.0

The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the third quarter of 2014 with the third quarter of 2013:

	Three Months Ended September 30
	Gross Margin						Therms
Gas Utility Operations	2014		B (W)		2013		2014	B (W)		2013
	(Millions of Dollars)						(Millions)
Customer Class
Residential	$	38.1	$	0.7	$	37.4	50.4	3.2		47.2
Commercial/Industrial	9.8		0.4		9.4		35.6	2.3		33.3
Interruptible	0.3		—		0.3		2.5	(0.3	)	2.8
Total Retail	48.2		1.1		47.1		88.5	5.2		83.3
Transported Gas	11.7		0.8		10.9		229.2	(6.8	)	236.0
Other Operating	1.4		0.4		1.0		—	—		—
Total	$	61.3	$	2.3	$	59.0	317.7	(1.6	)	319.3
Weather -- Degree Days (a)
Heating (121 Normal)							175	45		130
(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 $2.3 million, or approximately 3.9%, when compared to the third quarter of 2013.

Other Operation and Maintenance Expense

Our other operation and maintenance expense decreased by $22.1 million, or approximately 6.1%, when compared to the third quarter of 2013. This decrease was primarily driven by lower benefit costs.

September 2014 25 Wisconsin Energy Corporation

Form 10-Q

Depreciation and Amortization Expense

Our depreciation and amortization expense increased by $6.4 million, or approximately 8.0%, when compared to the third quarter of 2013 primarily because of an overall increase in utility plant in service. Our new biomass plant went into service in November 2013.

Treasury Grant

In December 2013, we filed an application with the United States Treasury for a Section 1603 Renewable Energy Treasury Grant (Treasury Grant) related to the construction of our biomass facility. In December 2013, we recognized income related to the Treasury Grant and we deferred as a regulatory liability the grant proceeds that would be returned to customers subsequent to December 31, 2013. In connection with our Wisconsin retail electric rates that became effective January 1, 2013, our Wisconsin retail electric customers began receiving bill credits for the expected grant proceeds plus the related tax benefits. We began to record grant income when the biomass facility was placed into service in the fourth quarter of 2013.

In June 2014, we received approximately $76.2 million related to the Treasury Grant. The PSCW approved escrow accounting for the Treasury Grant and the proceeds we received that exceeded the amounts originally included in rates will be returned to customers in future rate proceedings.

As noted above, our Wisconsin retail electric customers are currently receiving bill credits related to the Treasury Grant plus related tax benefits. During 2014, we are recognizing Treasury Grant income to match the bill credits related to the grant that our Wisconsin retail electric customers are receiving.

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 Oak Creek expansion Unit 2 (OC 2)).

This segment primarily reflects the lease revenues on these 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
	2014		B (W)			2013
	(Millions of Dollars)
Operating Revenues	$	114.1	$	(0.1	)	$	114.2
Operation and Maintenance Expense	3.5		0.7			4.2
Depreciation Expense	17.0		(0.2		)	16.8
Operating Income	$	93.6	$	0.4		$	93.2

CORPORATE AND OTHER CONTRIBUTION TO OPERATING INCOME

Corporate and other affiliates had an operating loss of $5.9 million for the three months ended September 30, 2014 as compared to a loss of $1.8 million for the same period in 2013. The increase in operating loss is primarily attributable to approximately $3.6 million of external costs related to the acquisition of Integrys.

September 2014 26 Wisconsin Energy Corporation

Form 10-Q

CONSOLIDATED OTHER INCOME, NET

	Three Months Ended September 30
	2014		B (W)			2013
	(Millions of Dollars)
AFUDC - Equity	$	1.6	$	(3.6	)	$	5.2
Gain on Property Sales	1.2		$	0.9		0.3
Other, net	0.1		0.5			(0.4		)
Other Income, net	$	2.9	$	(2.2	)	$	5.1

Other income, net decreased by $2.2 million, or approximately 43.1%, when compared to the third quarter of 2013. The decrease in AFUDC - Equity is primarily related to the biomass plant going into service in November 2013.

CONSOLIDATED INTEREST EXPENSE, NET

	Three Months Ended September 30
	2014		B (W)			2013
	(Millions of Dollars)
Gross Interest Costs	$	61.2	$	3.4		$	64.6
Less: Capitalized Interest	0.8		(1.8		)	2.6
Interest Expense, net	$	60.4	$	1.6		$	62.0

Our gross interest costs decreased by $3.4 million, or approximately 5.3%, when compared to the third quarter of 2013 primarily due to lower debt levels and lower average interest rates. Our capitalized interest decreased by $1.8 million primarily because of lower construction work in progress as the biomass plant went into service in November 2013. As a result, our net interest expense decreased by $1.6 million, or 2.6%, as compared to the third quarter of 2013.

CONSOLIDATED INCOME TAX EXPENSE

For the third quarter of 2014, our effective tax rate applicable to continuing operations was 38.9% compared to 37.0% for the third quarter of 2013. This increase in our effective tax rate was primarily due to non-deductible acquisition related expenses, reduced tax benefits associated with Treasury Grant income and decreased AFUDC - Equity. For additional information, see Note G -- Income Taxes in our 2013 Annual Report on Form 10-K.

September 2014 27 Wisconsin Energy Corporation

Form 10-Q

RESULTS OF OPERATIONS -- NINE MONTHS ENDED SEPTEMBER 30, 2014

CONSOLIDATED EARNINGS

The following table compares our operating income by business segment and our net income during the first nine months of 2014 with the first nine months of 2013, including favorable (better (B)) or unfavorable (worse (W)) variances:

	Nine Months Ended September 30
	2014			B (W)			2013
	(Millions of Dollars, Except Per Share Amounts)
Utility Energy Segment	$	606.3		$	70.2		$	536.1
Non-Utility Energy Segment	275.5			(0.9		)	276.4
Corporate and Other	(13.2		)	(9.2		)	(4.0		)
Total Operating Income	868.6			60.1			808.5
Equity in Earnings of Transmission Affiliate	52.8			1.8			51.0
Other Income, net	12.1			(3.2		)	15.3
Interest Expense, net	181.7			8.6			190.3
Income Before Income Taxes	751.8			67.3			684.5
Income Tax Expense	284.9			(33.5		)	251.4
Net Income	$	466.9		$	33.8		$	433.1
Diluted Earnings Per Share	$	2.05		$	0.17		$	1.88

UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Our utility energy segment contributed $606.3 million of operating income during the first nine months of 2014, an increase of $70.2 million, or 13.1%, compared with the first nine months of 2013. The following table summarizes the operating income of this segment between the comparative periods:

	Nine Months Ended September 30
Utility Energy Segment	2014		B (W)			2013
	(Millions of Dollars)
Operating Revenues
Electric	$	2,579.6	$	63.1		$	2,516.5
Gas	1,117.7		366.1			751.6
Other	32.3		3.7			28.6
Total Operating Revenues	3,729.6		432.9			3,296.7
Operating Expenses
Fuel and Purchased Power	951.8		(61.7		)	890.1
Cost of Gas Sold	788.0		(341.1		)	446.9
Other Operation and Maintenance	1,048.6		49.1			1,097.7
Depreciation and Amortization	254.2		(16.0		)	238.2
Property and Revenue Taxes	90.8		(3.1		)	87.7
Total Operating Expenses	3,133.4		(372.8		)	2,760.6
Treasury Grant	10.1		10.1			—
Operating Income	$	606.3	$	70.2		$	536.1

September 2014 28 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 first nine months of 2014 with the first nine months of 2013:

	Nine Months Ended September 30
	Electric Revenues							MWh
Electric Utility Operations	2014		B (W)			2013		2014	B (W)		2013
	(Millions of Dollars)							(Thousands)
Customer Class
Residential	$	902.4	$	(10.7	)	$	913.1	5,977.1	(126.5	)	6,103.6
Small Commercial/Industrial	798.4		0.4			798.0		6,682.3	(17.8	)	6,700.1
Large Commercial/Industrial	485.5		(80.9		)	566.4		5,628.6	(1,257.0	)	6,885.6
Other - Retail	16.8		(0.2		)	17.0		107.6	(2.0	)	109.6
Total Retail	2,203.1		(91.4		)	2,294.5		18,395.6	(1,403.3	)	19,798.9
Wholesale - Other	102.3		(7.0		)	109.3		1,430.0	(14.7	)	1,444.7
Resale - Utilities	211.0		119.5			91.5		4,891.0	2,010.1		2,880.9
Other Operating Revenues	59.2		38.3			20.9		—	—		—
Total	2,575.6		59.4			2,516.2		24,716.6	592.1		24,124.5
Electric Customer Choice (a)	4.0		3.7			0.3		1,824.1	1,623.6		200.5
Total, including electric customer choice	$	2,579.6	$	63.1		$	2,516.5
Weather -- Degree Days (b)
Heating (4,320 Normal)								5,184	554		4,630
Cooling (722 Normal)								460	(218	)	678
(a) Represents distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.
(b) 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 $63.1 million, or 2.5%, when compared to the first nine months of 2013. The most significant factors that caused a change in revenues were:

• A $119.5 million increase in sales for resale because of increased sales into the MISO Energy Markets as a result of Michigan's alternative electric supplier program and increased availability of our generating units.

• A $78.4 million decrease in large commercial/industrial sales because of the two iron ore mines switching to an alternative electric supplier in September 2013.

• A $38.3 million increase in other operating revenues, primarily driven by the recognition of $34.4 million related to revenues under the SSR agreement with MISO.

• Wisconsin net retail pricing increases of $29.1 million, which are primarily related to our 2013 Wisconsin Rate Case.

• Cooler summer weather decreased electric revenues by an estimated $27.8 million.

Cooling degree days decreased 32.2% during the first nine months of 2014 as compared to the same period in 2013 due to mild second and third quarters that reduced the cooling load. The unfavorable impact of the cool summer weather was partially offset by the cold winter weather. Residential sales decreased by 2.1%, primarily because of weather. Sales to large commercial/industrial customers decreased by 18.3%, primarily because of the loss of the two iron ore mines in Michigan. If the mines are excluded, sales to our large commercial/industrial customers decreased 1.1% compared to 2013.

September 2014 29 Wisconsin Energy Corporation

Form 10-Q

Fuel and Purchased Power

Our fuel and purchased power costs increased by $61.7 million, or 6.9%, when compared to the first nine months of 2013. This increase was primarily caused by a 2.5% increase in total MWh sales and higher generating costs driven by an increase in 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 2014 with the first nine months of 2013. 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 increased by $366.1 million, or 48.7%, and cost of gas sold increased by $341.1 million, or 76.3%, due to colder weather and an increase in the commodity cost of natural gas.

	Nine Months Ended September 30
	2014		B (W)			2013
	(Millions of Dollars)
Gas Operating Revenues	$	1,117.7	$	366.1		$	751.6
Cost of Gas Sold	788.0		(341.1		)	446.9
Gross Margin	$	329.7	$	25.0		$	304.7

The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the first nine months of 2014 with the first nine months of 2013:

	Nine Months Ended September 30
	Gross Margin						Therms
Gas Utility Operations	2014		B (W)		2013		2014	B (W)	2013
	(Millions of Dollars)						(Millions)
Customer Class
Residential	$	209.4	$	13.4	$	196.0	636.8	69.0	567.8
Commercial/Industrial	73.6		8.1		65.5		382.6	50.4	332.2
Interruptible	1.3		—		1.3		13.0	0.1	12.9
Total Retail	284.3		21.5		262.8		1,032.4	119.5	912.9
Transported Gas	39.8		2.4		37.4		781.8	4.1	777.7
Other	5.6		1.1		4.5		—	—	—
Total	$	329.7	$	25.0	$	304.7	1,814.2	123.6	1,690.6
Weather -- Degree Days (a)
Heating (4,320 Normal)							5,184	554	4,630
(a) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year
moving average.

Our gas margin increased by $25.0 million, or approximately 8.2%, when compared to the first nine months of 2013. This increase primarily relates to an increase in sales volumes as a result of colder weather during the first nine months of 2014 that increased heating loads. We estimate that weather increased gas margins by approximately $17.2 million. As measured by heating degree days, the first nine months of 2014 were 12.0% colder than the same period in 2013 and 20.0% colder than normal.

Other Operation and Maintenance Expense

Our other operation and maintenance expense decreased by $49.1 million, or approximately 4.5%, when compared to the first nine months of 2013. This decrease was primarily driven by lower benefit costs.

September 2014 30 Wisconsin Energy Corporation

Form 10-Q

Depreciation and Amortization Expense

Our depreciation and amortization expense increased by $16.0 million, or approximately 6.7%, when compared to the first nine months of 2013 primarily because of an overall increase in utility plant in service. Our new biomass plant went into service in November 2013.

Treasury Grant

For a discussion of the impact of the Treasury Grant on our results of operations, see Results of Operations -- Three Months Ended September 30, 2014 -- Treasury Grant.

NON-UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

This segment reflects the lease revenues associated with PWGS 1, PWGS 2, OC 1 and OC 2, 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
	2014		B (W)			2013
	(Millions of Dollars)
Operating Revenues	$	335.8	$	(1.5	)	$	337.3
Operation and Maintenance Expense	9.7		0.9			10.6
Depreciation Expense	50.6		(0.3		)	50.3
Operating Income	$	275.5	$	(0.9	)	$	276.4

Non-utility energy segment operating income decreased by $0.9 million, or approximately 0.3%, when compared to the first nine months of 2013. The decrease in operating revenues is primarily related to the one-time entries during 2013 to recognize final approved construction costs for the Oak Creek expansion as part of the 2013 Wisconsin Rate Case.

CORPORATE AND OTHER CONTRIBUTION TO OPERATING INCOME

Corporate and other affiliates had an operating loss of $13.2 million for the nine months ended September 30, 2014 as compared to a loss of $4.0 million for the same period in 2013. The increase in operating loss is primarily attributable to approximately $8.6 million of external costs related to the acquisition of Integrys.

CONSOLIDATED OTHER INCOME, NET

	Nine Months Ended September 30
	2014		B (W)			2013
	(Millions of Dollars)
AFUDC - Equity	$	3.9	$	(10.2	)	$	14.1
Gain on Property Sales	6.8		6.0			0.8
Other, net	1.4		1.0			0.4
Other Income, net	$	12.1	$	(3.2	)	$	15.3

Other income, net decreased by $3.2 million, or approximately 20.9%, when compared to the first nine months of 2013. The decrease in AFUDC - Equity is primarily related to the biomass plant going into service in November 2013.

September 2014 31 Wisconsin Energy Corporation

Form 10-Q

CONSOLIDATED INTEREST EXPENSE, NET

	Nine Months Ended September 30
	2014		B (W)			2013
	(Millions of Dollars)
Gross Interest Costs	$	183.8	$	13.6		$	197.4
Less: Capitalized Interest	2.1		(5.0		)	7.1
Interest Expense, net	$	181.7	$	8.6		$	190.3

Our gross interest costs decreased by $13.6 million, or approximately 6.9%, when compared to the first nine months of 2013 primarily due to lower debt levels and lower average interest rates. Our capitalized interest decreased by $5.0 million primarily because of lower construction work in progress as the biomass plant went into service in November 2013. As a result, our net interest expense decreased by $8.6 million, or 4.5%, as compared to the first nine months of 2013.

CONSOLIDATED INCOME TAX EXPENSE

For the first nine months of 2014, our effective tax rate applicable to continuing operations was 37.9% compared to 36.7% for the first nine months of 2013. This increase in our effective tax rate was primarily due to reduced tax benefits associated with Treasury Grant income and decreased AFUDC - Equity. For additional information, see Note G -- Income Taxes in our 2013 Annual Report on Form 10-K. We expect our 2014 annual effective tax rate to be between 37.5% and 38.5%.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

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

	2014			2013
	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$	1,034.6		$	1,050.3
Investing Activities	$	(528.9	)	$	(544.8	)
Financing Activities	$	(443.0	)	$	(522.6	)

Operating Activities

Cash provided by operating activities decreased by $15.7 million during the first nine months of 2014 as compared to the same period in 2013. This decrease was primarily because of state income tax payments, changes in natural gas in storage and an increase in deferred regulatory assets. Partially offsetting these negative drivers were increases in net income and non-cash charges related to depreciation and deferred income taxes during the first nine months of 2014 as compared to the same period in 2013.

Investing Activities

Cash used in investing activities decreased by $15.9 million during the first nine months of 2014 as compared to the same period in 2013. Cost of removal, net of salvage decreased approximately $9.6 million during the first nine months of 2014 as compared to the same period in 2013. In addition, other, net increased by $24.2 million because of several smaller items, including an increase in proceeds from asset sales associated with Wispark. These factors were partially offset by a $15.3 million increase in capital expenditures during the first nine months of 2014 as compared to the same period in 2013, primarily because of starting conversion of the fuel source for Valley Power Plant (VAPP) from coal to natural gas.

September 2014 32 Wisconsin Energy Corporation

Form 10-Q

Financing Activities

Cash used in financing activities decreased by $79.6 million during the first nine months of 2014 as compared to the same period in 2013. During the first nine months of 2014, we repurchased $84.2 million of common stock as compared to $187.9 million during the same period in 2013. See Note 4 -- Common Equity for additional information on share repurchases. This decrease was partially offset by an increase in the repayment of short-term debt and increased dividends paid on our common stock. During the first nine months of 2014, we repaid $28.8 million more short-term debt as compared to the first nine months of 2013. Our quarterly common stock dividend increased by 12.5% and 2.0% in the third quarter of 2013 and first quarter of 2014, respectively, resulting in an increase of dividends paid on common stock of $21.7 million in the first nine months of 2014 as compared to the same period last year.

CAPITAL RESOURCES AND REQUIREMENTS

Liquidity

We anticipate meeting our capital requirements during the remainder of 2014 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, 2014, we had approximately $1.2 billion of available, undrawn lines under our bank back-up credit facilities, and approximately $475.8 million of commercial paper outstanding on a consolidated basis that was supported by the available lines of credit. During the first nine months of 2014, our maximum commercial paper outstanding was $721.4 million with a weighted-average interest rate of 0.18%.

We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. The following table summarizes such facilities as of September 30, 2014:

Company	Total Facility		Letters of Credit		Credit Available		Facility Expiration
	(Millions of Dollars)
Wisconsin Energy	$	400.0	$	0.1	$	399.9	December 2017
Wisconsin Electric	$	500.0	$	5.1	$	494.9	December 2017
Wisconsin Gas	$	350.0	$	—	$	350.0	December 2017

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

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The following table shows our capitalization structure as of September 30, 2014, 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 due 2067 (Junior Notes):

Capitalization Structure	Actual			Adjusted
	(Millions of Dollars)
Common Equity	$	4,398.3		$	4,648.3
Preferred Stock of Subsidiary	30.4			30.4
Long-Term Debt (including current maturities)	4,617.3			4,367.3
Short-Term Debt	475.8			475.8
Total Capitalization	$	9,521.8		$	9,521.8
Total Debt	$	5,093.1		$	4,843.1
Ratio of Debt to Total Capitalization	53.5		%	50.9		%

Included in Long-Term Debt on our Consolidated Condensed Balance Sheet as of September 30, 2014 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, 2014, the repurchased bonds were still outstanding, but were not reported as 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.

In August 2014, Fitch Ratings (Fitch) affirmed the ratings of Wisconsin Electric, Wisconsin Gas and Elm Road Generating Station Supercritical (ERGSS). Fitch also affirmed the stable ratings outlook for these companies. In June 2014, Fitch placed the ratings of Wisconsin Energy and Wisconsin Energy Capital Corporation (WECC) on Rating Watch Negative.

In June 2014, Standard and Poor's Ratings Services (S&P) affirmed the ratings of Wisconsin Energy, Wisconsin Electric, Wisconsin Gas and WECC. S&P affirmed the stable ratings outlook for Wisconsin Electric and Wisconsin Gas, and revised the ratings outlook from stable to negative for Wisconsin Energy and WECC.

In June 2014, Moody's Investors Service (Moody's) affirmed the ratings of Wisconsin Energy, Wisconsin Electric, Wisconsin Gas, ERGSS and WECC. Moody's affirmed the stable ratings outlook for Wisconsin Electric, Wisconsin Gas and ERGSS, and revised the ratings outlook for Wisconsin Energy and WECC from stable to negative.

The change in outlooks for Wisconsin Energy and WECC relates to the proposed acquisition of Integrys.

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

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 2013 Annual Report on Form 10-K for additional information related to our credit rating risk.

Capital Requirements

Acquisition of Integrys:   On June 22, 2014, we entered into an agreement to acquire Integrys for approximately $5.4 billion, based upon the value of our common stock at September 30, 2014. Integrys shareholders will receive 1.128 shares of Wisconsin Energy common stock and $18.58 in cash per share of Integrys common stock. The proposed acquisition is scheduled to close in the second half of 2015, and is subject to the receipt of various approvals. We expect to finance the acquisition through the issuance of approximately $1.5 billion of debt at the holding company and approximately 91 million shares of Wisconsin Energy common stock.

Capital Expenditures:   Capital requirements during the remainder of 2014 are expected to be principally for capital expenditures in our utility operations relating to our electric and gas distribution systems. We estimate that we will spend approximately $711.0 million on consolidated capital expenditures during 2014.

Common Stock Matters:   In December 2013, our Board of Directors authorized a share repurchase program for up to $300 million of our common stock from January 1, 2014 through the end of 2017. Through September 30, 2014, we acquired approximately 0.4 million shares in the open market at a cost of $18.6 million pursuant to this program. All of these shares were purchased during the first quarter of 2014. On June 22, 2014, in connection with the proposed acquisition of Integrys, the Board of Directors terminated this share repurchase program.

In addition, on January 16, 2014, our Board of Directors increased our quarterly common stock dividend to $0.39 per share, up approximately 2.0%, from $0.3825 per share, effective with the first quarter 2014 dividend payment. This equates to an annual dividend of $1.56 per share.

Prior to closing the proposed acquisition of Integrys, we plan to continue our current dividend policy, which would provide for a 7-8% annual increase in the dividend. At closing, we expect a further dividend increase for our shareholders to reflect the dividend policy of the combined company. In future years after closing, the projected payout target for the combined company will be 65-70 percent of earnings.

Off-Balance Sheet Arrangements:   We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support construction projects, commodity contracts and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors. For 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 $21.7 billion as of September 30, 2014 compared with $22.2 billion as of December 31, 2013.

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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 2013 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 have been placed into service and are positioned to provide a significant portion of our future generation needs.

As part of our 2013 Wisconsin Rate Case, the PSCW determined that 100% of the construction costs for our Oak Creek expansion units were prudently incurred, and approved the recovery in rates of more than 99.5% of these costs.

We Power assigned its warranty rights to Wisconsin Electric upon turnover of each of the Oak Creek expansion units. The warranty claim for costs incurred to repair steam turbine corrosion damage identified on both units was scheduled to go to arbitration in October 2013, but we entered into a settlement agreement with Bechtel Power Corporation (Bechtel) in June 2013 resolving the claim, as well as several other warranty claims. This settlement did not have a material impact to our financial statements. Bechtel and Wisconsin Electric resolved an additional warranty claim in April 2014 which also did not have a material impact. The parties continue to work through one remaining item.

See Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Item 7 of our 2013 Annual Report on Form 10-K for additional information on PTF.

UTILITY RATES AND REGULATORY MATTERS

2015 Wisconsin Rate Case:   On May 30, 2014, Wisconsin Electric and Wisconsin Gas applied to the PSCW for a biennial review of costs and rates.

Wisconsin Electric and Wisconsin Gas engaged in settlement discussions related to this review, facilitated by PSCW Staff, with the Citizens Utility Board, the Wisconsin Industrial Energy Group and the Wisconsin Paper Council. As a result of these discussions, Wisconsin Electric, Wisconsin Gas and the three customer groups have agreed on the following:

• Wisconsin Electric is requesting a rate increase of $41.5 million (1.43%), excluding fuel, for its Wisconsin retail electric customers in 2015; or $52.3 million (1.81%) when including estimated fuel costs for 2015. This increase reflects an offset of $26.2 million (0.91%) related to bill credits. Other than the expiration of the bill credits, no adjustment to electric base rates would be made in 2016.

• Wisconsin Electric is requesting a rate decrease of $10.7 million (2.39%) for its natural gas customers in 2015, with no rate adjustment in 2016.

• Wisconsin Electric is requesting rate increases in 2015 of $0.5 million (2.10%) and $0.8 million (4.56%) for its downtown Milwaukee and Milwaukee County steam customers, respectively, with no rate adjustments in 2016.

• Wisconsin Gas is requesting rate increases of $21.1 million (3.27%) and $21.4 million (3.32%) in 2015 and 2016, respectively, for its natural gas customers.

In addition, the parties have agreed that the authorized return on equity for Wisconsin Electric and Wisconsin Gas should be set at 10.2% and 10.3%, respectively. The agreement between the parties calls for the Wisconsin Gas financial common equity component to increase to an average of 49.5% compared to the current 47.5%, while Wisconsin Electric's equity component will remain the same.

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

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2013 Wisconsin Rate Case:In March 2012, Wisconsin Electric and Wisconsin Gas initiated rate proceedings with the PSCW. In December 2012, the PSCW approved the following rate adjustments:

• A net bill increase related to non-fuel costs for Wisconsin Electric's Wisconsin retail electric customers of approximately $70 million (2.6%) for 2013. This amount reflects an offset of approximately $63 million (2.3%) of bill credits related to the proceeds of the Treasury Grant, including related tax benefits. Absent this offset, the retail electric rate increase for non-fuel costs was approximately $133 million (4.8%) for 2013.

• An electric rate increase for Wisconsin Electric's Wisconsin electric customers of approximately $28 million (1.0%) for 2014, and a $45 million (1.6%) reduction in bill credits.

• Recovery of a forecasted increase in fuel costs of approximately $44 million (1.6%) for 2013.

• A rate decrease of approximately $8 million (1.9%) for Wisconsin Electric's natural gas customers for 2013, with no rate adjustment in 2014. The Wisconsin Electric rates reflect a $6.4 million reduction in bad debt expense.

• A rate decrease of approximately $34 million (5.5%) for Wisconsin Gas' natural gas customers for 2013, with no rate adjustment in 2014. The Wisconsin Gas rates reflect a $43.8 million reduction in bad debt expense.

• An increase of approximately $1.3 million (6.0%) for Wisconsin Electric's downtown Milwaukee steam utility customers for 2013 and another $1.3 million (6.0%) in 2014.

• An increase of approximately $1 million (7.0%) in 2013 and $1 million (6.0%) in 2014 for Wisconsin Electric's Milwaukee County steam utility customers.

These rate adjustments were effective January 1, 2013. In addition, the PSCW indicated that Wisconsin Electric's and Wisconsin Gas' allowed return on equity would remain at 10.4% and 10.5%, respectively. The PSCW also approved escrow accounting treatment for the Treasury Grant.

2014 Fuel Cost Plan Request:In July 2013, Wisconsin Electric filed its 2014 fuel cost plan with the PSCW requesting authority to decrease Wisconsin retail electric customers' rates approximately $36 million in the form of a fuel credit primarily related to a reduction in delivered coal costs. The plan was approved by the PSCW on December 20, 2013.

Renewable Energy Portfolio:   Wisconsin Electric constructed a 50 MW biomass facility at Domtar Corporation's Rothschild, Wisconsin paper mill site that went into commercial operation in November 2013. Wood waste and wood shavings are used to produce renewable electricity and will also support Domtar's sustainable papermaking operations. The final cost of completing this project was $269.0 million, excluding AFUDC.

Western Gas Lateral:   We are projecting the need for additional capacity for our natural gas distribution network in the western part of Wisconsin to address reliability and meet customer demand. We filed an application with the PSCW seeking approval to construct a new natural gas lateral in March 2013. We received the final written order approving the project on July 18, 2014. The anticipated cost of the initial phase of this project is approximately

$175 million to $185 million, excluding AFUDC. We are targeting completion of this phase of the project in late 2015.

See Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters in Item 7 of our 2013 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 were completed for the period of June 1, 2014 through May 31, 2015. The resulting ARR valuation and the secured FTRs are expected to mitigate our transmission congestion risk for that period.

Restructuring in Michigan:   Under Michigan law, our retail customers may choose an alternative electric supplier to provide power supply service. The law limits customer choice to 10% of our Michigan retail load. The two iron ore mines are excluded from this cap. When a customer switches to an alternative electric supplier, we continue to provide distribution and customer service functions for the customer.

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The mines, which were served on an interruptible tariff rate, switched to an alternative electric supplier in September 2013. In addition, other smaller retail customers have switched to an alternative electric supplier.

We have taken, and will continue to take, multiple steps to mitigate the financial impacts associated with the loss of these customers. In August 2013, we filed a request with MISO to suspend the operation of all five units at Presque Isle Power Plant (PIPP) located in the Upper Peninsula of Michigan. In October 2013, MISO informed us that the operation of all units is necessary to maintain reliability in the Upper Peninsula of Michigan.

On January 30, 2014, we entered into an SSR agreement with MISO to recover costs for operating and maintaining the units. The agreement was effective February 1, 2014, has a one year term, and specifies monthly payments to Wisconsin Electric of $4.4 million to cover fixed costs. The agreement also provides for the payment of our variable costs to operate and maintain the plant. MISO filed the SSR agreement with FERC on January 31, 2014, and on April 1, 2014, FERC conditionally accepted the agreement as filed, subject to further review and FERC order. We began receiving SSR payments from MISO in the second quarter retroactive to the agreement's effective date of February 1, 2014.

In addition, we issued a request for proposals regarding the potential purchase of PIPP in January 2014. We did not receive any proposals by the March 3, 2014 deadline. Based upon our evaluation and the lack of interest to purchase the plant, on April 15, 2014, we filed a request with MISO to retire PIPP effective October 15, 2014. On May 28, 2014, MISO informed us that they had determined the operation of all five units at PIPP is necessary for reliability purposes; therefore, the units will continue to be designated as SSR units, unless an alternative solution is identified through the stakeholder planning process.

We entered into a new SSR agreement with MISO, effective October 15, 2014, that would cover the operating costs of PIPP through December 2015. The new SSR agreement also includes, among other things, costs to comply with the Mercury and Air Toxic Standards (MATS) and a return on and of our investment in the plant. The new agreement is based on projected costs and is subject to a true-up mechanism. The estimated monthly payments under this agreement are approximately $8.1 million. The new SSR agreement is subject to FERC approval and is expected to replace the prior SSR agreement.

MISO, subject to direction from the FERC, is responsible for allocating the SSR costs to various market participants within the MISO footprint. Several interested parties, including the PSCW and the MPSC, have filed complaints with the FERC regarding the allocation of SSR costs among the different jurisdictions. On October 9, 2014, we filed a request with the FERC to hold in abeyance the change in the allocation of SSR costs among the different jurisdictions until the affected parties have further discussion regarding this issue.

See Factors Affecting Results, Liquidity and Capital Resources - Industry Restructuring and Competition in Item 7 of our 2013 Form 10-K for additional information regarding the impact of industry restructuring in Michigan, as well as information regarding other restructuring matters and MISO.

ENVIRONMENTAL MATTERS

Air Quality

National Ambient Air Quality Standards

8-hour Ozone Standards:  In April 2004, the United States Environmental Protection Agency (EPA) designated 10 counties in southeastern Wisconsin as non-attainment areas for the 1997 8-hour ozone ambient air quality standard. The EPA has since redesignated all of these counties to attainment. In 2008, the EPA issued an additional, more stringent 8-hour ozone standard, and made final attainment designations for this revised standard in 2012. In April 2012 and May 2012, the EPA designated Sheboygan County and the eastern portion of Kenosha County, respectively, as 2008 8-hour ozone standard non-attainment areas. The net result of all of these actions is that construction permitting for all of our Wisconsin power plants, except the Pleasant Prairie Power Plant, is expected to be subject to less stringent permitting requirements. In addition, modifications to these facilities should no longer be required to obtain emission offsets. So long as eastern Kenosha County remains an ozone non-attainment area, the Pleasant Prairie Power Plant will continue to be subject to more stringent permitting requirements and offset provisions.

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In January2010, the EPA announced its decision to further lower the 2008 8-hour ozone standard. However, in September 2011, President Obama requested the EPA to delay the reconsideration of the 8-hour ozone standard. In January 2014, environmental groups petitioned the U.S. District Court for the Northern District of California to order the EPA to propose a new ozone standard by the end of 2014 and to finalize the standard by October 2015. We expect the EPA to lower the 8-hour ozone standard from its current level. The impact, if any, of a revised standard will depend on how much it is lowered, but could result in widespread areas of the country not being able to meet the new standard.

Sulfur Dioxide Standard:   In June 2010, the EPA issued a new 1-Hour Sulfur Dioxide (SO₂) National Ambient Air Quality Standard (NAAQS) that became effective in August 2010. This standard represents a significant change from the previous SO₂ standard, and NAAQS in general, since attainment designations were to be based primarily on modeling rather than monitoring. Typically, attainment designations are based on monitored data. The EPA has since issued two technical assistance documents for comment in 2013, and in May 2014, issued the proposed Data Requirements Rule that would establish procedures and timelines for implementation of the standard. The proposed rule describes the EPA's plans for allowing the states to use either monitoring or modeling to make designations.

We filed comments on the proposed rule with the EPA in July 2014, and proposed a special reliability exclusion for PIPP which would recognize our request to retire the facility, and would exclude it from further modeling or monitoring requirements and subsequent emission reductions. As proposed, the rule affords state agencies latitude in rule implementation. States would have the option of modeling or monitoring to show attainment (subject to EPA approval for this selection). If the state chooses modeling and the sources in an area do not make reductions by 2017, and as a consequence the area is classified as non-attainment, then they would have to make emission reductions by 2023. Alternatively, if a state opted out of modeling and instead chose monitoring, and subsequently monitored non-attainment, then it would face a 2026 compliance date. A non-attainment designation could have negative impacts for a localized geographic area, including permitting constraints for the subject source and for other new or existing sources in the area.

We believe our fleet (with the exception of PIPP) is well positioned to meet this regulation once it is finalized. If PIPP is still operating in the 2021-2022 timeframe, it will likely need additional SO₂ reductions in order to comply with the standard.

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. We currently anticipate that only PIPP will require modifications, and are planning for the addition of a dry sorbent injection system for further control of mercury and acid gases at the plant to comply with MATS. In April 2013, we received a one year MATS compliance extension through April 16, 2016 from the Michigan Department of Environmental Quality (MDEQ).

Cross-State Air Pollution Rule: In August 2011, the EPA issued 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 (NO_X) and SO₂ that contribute to fine particulate matter and ozone non-attainment in downwind states through a proposed allocation plan. 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 PIPP and increase the number of allowances issued to the states of Michigan and Wisconsin. We and a number of other parties sought judicial review of the rule. In April 2014, the United States Supreme Court issued a decision largely upholding the rule and remanding it for further proceedings consistent with the Court's order. On October 23, 2014, the U.S. Court of Appeals for the D.C. Circuit issued a decision that clears the way for the EPA to begin implementing CSAPR in 2015. In light of this decision and further proceedings by the appellate court, we are re-evaluating the rule and availability of allowances in Michigan for PIPP to meet its obligations to operate and provide stability to the transmission system in the Upper Peninsula of Michigan. We also expect to have excess allowances available to sell from our Wisconsin power plants.

Clean Air Visibility Rule:   The EPA issued the Clean Air Visibility Rule in June 2005 to address Regional Haze, or regionally-impaired visibility caused by multiple sources over a wide area. The rule defines Best Available Retrofit Technology (BART) requirements for electric generating units and how BART will be addressed in the 28 states

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subject to the EPA's CAIR. The pollutants from power plants that reduce visibility include fine particulate matter or compounds that contribute to fine particulate formation, NO_X, SO₂ and ammonia.

In June 2012, the EPA promulgated a Federal Implementation Plan that approves reliance on the CSAPR to satisfy electric generating unit BART requirements for NO_X and SO₂. In December 2012, the EPA approved the remainder of Michigan's regional haze State Implementation Plan (SIP).

In August 2012, the EPA approved Wisconsin's regional haze SIP, which also relies on the CSAPR to satisfy electric generating unit BART requirements for NO_X and SO₂.

The U.S. Supreme Court decision in April 2014 that upheld the CSAPR allows for the final regional haze rulemaking activities and requirements for NO_X and SO₂ to proceed. We believe we will be well positioned to meet the Clean Air Visibility rule based on air quality control system additions that are already in place or planned for our generating facilities.

Valley Power Plant Conversion:In August 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 $65 million and $70 million, excluding AFUDC. We filed for a Certificate of Authority from the PSCW in April 2013, and received final written approval in March 2014. Construction is underway with the conversion of two boilers scheduled for completion in 2014, and the remaining two boilers scheduled for completion in 2015.

Greenhouse Gas (GHG) Regulations:   The EPA issued proposed guidelines relating to GHG emissions from existing generating units on June 18, 2014, and has announced plans to issue final rules by June 2015. The EPA also published proposed performance standards for modified and reconstructed generating units. The proposed guidelines seek to attain state-specific GHG rate reductions by 2030, and require states to submit plans as early as June 30, 2016. Single states requesting a one year extension would be required to submit plans by June 30, 2017, and states that are part of a multi-state plan that request a two year extension would be required to submit plans by June 30, 2018. The EPA is seeking GHG rate reductions in Wisconsin of 34% and in Michigan of 31% by 2030, with interim reduction goals beginning in 2020 of 30% and 27% respectively, with compliance determined by averaging reductions over the ten year period of 2020 to 2029. The proposed program consists of building blocks that include a combination of power plant efficiency improvements, increased reliance on combined cycle gas units, adding new renewable energy resources, and increased demand side management. We are in the process of reviewing the proposed guidelines to determine the potential impacts to our operations, but the guidelines as currently proposed could result in significant additional compliance costs, including capital expenditures, impact how we operate our existing fossil fueled power plants and biomass facility, and could have a material adverse impact on our operating costs.

In June 2014, in Utility Air Regulatory Group v. EPA, the U.S. Supreme Court struck down a portion of the EPA’s program for permitting GHG emissions under the Prevention of Significant Deterioration (PSD) and Title V programs. The Court held that a facility’s GHG emissions alone cannot trigger a requirement to obtain a permit and that the EPA did not have the authority to “tailor” the statutory permitting thresholds. The Court also upheld those portions of the EPA’s program that provide for implementation of GHG emissions limits based on the application of Best Available Control Technology for facilities already subject to PSD or Title V permitting requirements for other pollutants. We do not expect that this decision will have a material impact on our facilities.

Water Quality

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

The EPA proposed a new Phase II rule in 2011, and issued the final Phase II rule on May 16, 2014. The new rule will apply to all of our existing generating facilities with cooling water intake structures, except for the Oak Creek expansion units, which were permitted under the Phase I rules.

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The new rule allows facility owners to select from seven options available to meet the impingement mortality (IM) reduction standard. BTA determinations will be made over the next several years by the WDNR and MDEQ, subject to EPA oversight, when facility permits are reissued. Based upon our assessment, we believe that the existing technologies at our generating facilities will allow us to demonstrate that, other than VAPP, all of our facilities satisfy the IM BTA standard. We plan to install fish protection screens at VAPP that we expect will meet the IM BTA standard.

The BTA determinations for entrainment mortality (EM) reduction will be made by the WDNR and MDEQ on a case-by-case basis. The new rule requires state permitting agencies to determine EM BTA on a site-specific basis taking into consideration several factors. Because the entrainment reduction standard is a site-specific determination, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new requirements.

See Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7 of our 2013 Annual Report on Form 10-K for additional information regarding environmental matters affecting our operations.

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. Market forces have resulted in a significant price differential between bituminous and sub-bituminous coals. We received a new air construction permit from the WDNR to modify the Oak Creek expansion units for potential future use of sub-bituminous coal. In 2013, we began testing various combinations of sub-bituminous coal and bituminous coal to identify any equipment limitations, and making equipment modifications to the units. On July 7, 2014, we filed an application requesting the PSCW to approve $25 million of additional capital for plant modifications that will enable testing of up to 100% Powder River Basin (sub-bituminous) coal. In February 2013, the Sierra Club and the Midwest Environmental Defense Center filed a petition for a contested case hearing with the WDNR to challenge the issuance of the air construction permit. The WDNR has granted that petition, but a hearing has not yet been scheduled.

Paris Generating Station Units 1 and 4 Temporary Outage: Between 2000 and 2002, we replaced the blades on the four Paris Generating Station (PSGS) combustion turbine generators with blades that were approximately 7% more efficient. Although the work was performed as routine maintenance that we did not believe required a construction permit at the time and the plant has not been operated to use the potential additional capacity, the WDNR has indicated that it now considers this maintenance to be a modification requiring a construction permit. The WDNR issued a Notice of Violation (NOV) to Wisconsin Electric in January 2013 alleging violations of the new source review rules and certain Wisconsin environmental rules. At the same time, the WDNR also issued an administrative order that prohibits us from operating PSGS Units 1 and 4 until the earlier of: (1) Units 1 and 4 achieve the applicable NO_X emission rates; (2) the Wisconsin regulations are revised so that Units 1 and 4 can achieve the emission limits or are no longer subject to the limits; (3) the alleged modification is resolved through a consent decree; or (4) a court decides that the blade replacement project was not a major modification. We are presently evaluating alternative approaches to return these peaking units to service, and expect Units 1 and 4 to remain out of service until at least the first half of 2015. In December 2013, Act 91 was signed into law in Wisconsin, creating a process by which the EPA and WDNR may revise the regulations applicable to Units 1 and 4 and allow those units to restart.

In February 2013, the Sierra Club filed for a contested case hearing with the WDNR in connection with the administrative order. The WDNR has granted that petition, but a hearing has not yet been scheduled. In addition, in May 2013, the WDNR referred the matter to the Wisconsin Department of Justice for alleged violations of air management statutes and rules. In June 2014, we settled with the Department of Justice and paid $50,000 in costs and penalties.

Pursuant to the terms of the administrative order with the WDNR, we received an “after the fact” permit in connection with the work we completed in 2000 and 2002. On October 24, 2014, the Sierra Club filed for a contested case hearing with the WDNR challenging this permit.

PSGS Units 2 and 3 remain available for operation because the turbine blade maintenance on these units occurred prior to a rule change in 2001.

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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, 2013. 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 2013 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 2013 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

Paris Generating Station:See Factors Affecting Results, Liquidity and Capital Resources -- Other Matters for information concerning a NOV issued in connection with the replacement of certain turbine blades as part of maintenance performed on Units 1 and 4 at PSGS.

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.

September 2014 42 Wisconsin Energy Corporation

Form 10-Q

OTHER MATTERS

Litigation Relating to the Acquisition of Integrys:Since the announcement of the acquisition, Integrys and its board of directors, along with Wisconsin Energy, have been named as defendants in ten separate purported class action lawsuits filed in Brown County, Wisconsin (three of the cases -- Rubin v. Integrys, et al., Blachor v. Integrys, et al., and Albera v. Integrys, et al.), Milwaukee County, Wisconsin (two of the cases -- Amo v. Integrys, et al. and Inman v. Integrys, et al.), Cook County, Illinois (two of the cases - Taxman v. Integrys, et al. and Curley v. Integrys, et al.), and the federal court for the Northern District of Illinois (three of the cases - Steiner v. Integrys, et al., Tri-State Joint Fund v. Integrys, et al., and Collison v. Integrys, et al.). In the Tri-State Joint Fund case, Wisconsin Energy’s CEO was also named as a defendant. The cases were brought on behalf of proposed classes consisting of shareholders of Integrys. The complaints allege, among other things, that the Integrys board members breached their fiduciary duties by failing to maximize the value to be received by Integrys’ shareholders, that Wisconsin Energy aided and abetted the breaches of fiduciary duty, and that the joint proxy statement/prospectus contains material misstatements and omissions. The complaints seek, among other things, (a) to enjoin defendants from consummating the acquisition; (b) rescission of the Merger Agreement; and (c) to direct the defendants to exercise their fiduciary duties to obtain the highest value possible for the Integrys shareholders. The Brown County and Cook County cases have been dismissed in favor of the Milwaukee County actions. Wisconsin Energy believes the cases have no merit and intends to defend the actions vigorously.

ITEM 1A. RISK FACTORS

We are subject to a variety of risks, many of which are beyond our control, that may adversely affect our business, financial condition and results of operations. We have identified a number of these risk factors in Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2013, which risk factors are incorporated herein by reference. Other than as set forth below, there have been no material changes to these risk factors. You should carefully consider all of these risk factors, as well as the other information included in this report and other documents filed by us with the SEC from time to time, when making an investment decision.

Risks Related to Our Pending Acquisition of Integrys

We may be unable to satisfy the conditions or obtain the approvals required to complete the acquisition of Integrys or such approvals may contain material restrictions or conditions.

Completion of the acquisition of Integrys is subject to numerous conditions, including approval of the shareholders of both Wisconsin Energy and Integrys, the approval of various government agencies and the expiration or termination of the waiting period under the HSR Act. We cannot provide assurance that we will obtain all required consents or approvals, or that the regulatory consents or approvals will not impose conditions on the completion, or require changes to the terms, of the acquisition, including restrictions on the business, operations or financial performance of the combined company. These conditions or changes could also delay or materially and adversely affect the business results and financial condition of the combined company.

The acquisition of Integrys may not be completed, which may have an adverse effect on our share price and future business and financial results.

Failure to complete the acquisition of Integrys could negatively affect Wisconsin Energy's share price, as well as our future business and financial results. If the Merger Agreement is terminated under specified circumstances set forth in the Merger Agreement, we may be required to pay Integrys a termination fee of $175 million. In addition, we must pay our own costs related to the acquisition including, among others, legal, accounting, advisory, financing fees, filing and printing costs, whether the acquisition is completed or not. For these and other reasons, a failure to complete the acquisition could materially and adversely affect our business, financial results and share price.

While the acquisition of Integrys is pending, we are subject to business uncertainties and contractual restrictions that could materially adversely affect our operations and the future of our business.

The Merger Agreement includes restrictions on the conduct of our business prior to the completion of the acquisition of Integrys, generally requiring us to conduct our business in the ordinary course and subjecting us to a variety of specified limitations absent Integrys’ prior written consent. We may find that these and other contractual arrangements in the Merger Agreement may delay or prevent us from or limit our ability to respond effectively to

September 2014 43 Wisconsin Energy Corporation

Form 10-Q

competitive pressures, industry developments and future business opportunities that may arise during such period, even if our management thinks they may be advisable. The pendency of the acquisition may also divert management’s attention and our resources from ongoing business and operations. If any of these effects were to occur, it could materially and adversely affect our operations and the future of our business, regardless of whether the acquisition is completed.

If completed, the acquisition of Integrys may not achieve its intended results.

We entered into the Merger Agreement with the expectation that the acquisition of Integrys would result in various benefits. If the acquisition is completed, achieving the anticipated benefits will be subject to a number of uncertainties, including whether Wisconsin Energy's and Integrys' businesses can be integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could adversely affect our business, financial results and share price.

Risks Related to Legislation and Regulation

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

The regulation of GHG emissions continues to be a top priority for the President's administration. In June 2013, the President issued a presidential memorandum instructing the EPA to, among other things, issue rules pertaining to GHG emissions from both new and existing plants.

In June 2012, the U.S. Court of Appeals for the D.C. Circuit upheld the EPA's authority to regulate GHG emissions. The EPA is pursuing regulation of GHG emissions using its existing authority under the Clean Air Act. In September 2013, the EPA withdrew its 2012 proposed New Source Performance Standards GHG emissions rule, and issued new proposed rules with GHG limits for new fossil fueled power plants. The rule would not apply to certain natural gas fueled peaking plants, biomass units or oil fueled stationary combustion turbines.

With respect to existing generating units, the EPA issued a proposed rule on June 18, 2014, and is expected to issue a final rule by June 2015. The proposed rule would require states to submit SIPs as early as June 30, 2016. Single states requesting a one year extension would be required to submit SIPs by June 30, 2017, and states that are part of a multi-state plan that request a two year extension would be required to submit SIPs by June 30, 2018. We are in the process of reviewing the proposed rule to determine the potential impacts to our operations. We expect that these regulations as currently proposed would impact how we operate our existing facilities, particularly our fossil fueled power plants and biomass facility, and could have a material adverse impact on our operating costs.

Legislation to regulate GHG emissions and establish renewable and efficiency standards has also been considered on the state level. Both Wisconsin and Michigan have adopted renewable portfolio standards and energy optimization (efficiency) targets.

Despite a United States Supreme Court decision where the Court ruled that the plaintiffs in the litigation did not have standing to claim nuisance under federal common law due to the release of GHG into the atmosphere by the defendants, states and environmental groups have lawsuits pending against electric utilities and others to force reductions in GHG emissions based upon their contribution to the alleged public nuisance of climate change.

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

A decrease in the return on equity earned by participants in MISO could have a negative impact on our results of operations.

On June 19, 2014, FERC issued an order revising its methodology for determining the base return on equity for jurisdictional electric utilities, including transmission owners. FERC expects its new methodology will narrow the

September 2014 44 Wisconsin Energy Corporation

Form 10-Q

"zone" of reasonable returns on equity. FERC also indicated that it will continue its policy that an electric utility's total return on equity is limited to the zone of reasonableness. FERC has set a complaint against MISO and the transmission owners participating in MISO challenging the owners' 12.38% base return on equity for hearing. There is a risk that FERC would reduce the allowed return on equity ATC receives as a transmission owning member of MISO, which ultimately could reduce our earnings with respect to our investment in ATC.

ITEM 6. EXHIBITS

Exhibit No.
2	Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
2.1	Agreement and Plan of Merger, dated as of June 22, 2014, by and between Wisconsin Energy and Integrys. (Exhibit 2.1 to Wisconsin Energy's 06/22/2014 Form 8-K.)
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 2014 45 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:	October 31, 2014	Stephen P. Dickson, Vice President and Controller, Principal Accounting Officer and duly authorized officer

September 2014 46 Wisconsin Energy Corporation

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: October 31, 2014

/s/GALE E. KLAPPA

Gale E. Klappa

Chairman 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: October 31, 2014

/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, 2014, as filed with the Securities and Exchange Commission on October 31, 2014 (the "Report"), I, Gale E. Klappa, Chairman 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 and Chief Executive Officer

October 31, 2014

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, 2014, as filed with the Securities and Exchange Commission on October 31, 2014 (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

October 31, 2014

XML

Variable Interest Entities (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Variable Interest Entities (Textuals)
Power capacity under capital lease (MW)	236
Capital Lease Agreement With Vie Remaining Term In Years	8 years
Total payments over remaining terms of the agreement	$ 184.4
Total capacity and lease payments	$ 39.8	$ 37.8

XML

Derivative Instruments (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Derivative asset	$ 24,400,000		$ 24,400,000		$ 11,800,000
Derivative liability	1,600,000		1,600,000		300,000
Gains (losses)	1,200,000	4,200,000	21,500,000	5,400,000
Derivative Instruments (Textuals)
Collateral in margin accounts	1,800,000		1,800,000		0
Other Deferred Charges and Other Assets [Member]
Derivatives, Fair Value [Line Items]
Long-term portion of derivative assets	1,700,000		1,700,000
Other Deferred Credits and Other Liabilities [Member]
Derivatives, Fair Value [Line Items]
Long-term portion of derivative liabilities	100,000		100,000
Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Derivative asset	8,800,000		8,800,000		5,600,000
Derivative liability	1,600,000		1,600,000		100,000
Volume of derivative instruments	6.3 million Dth	6.3 million Dth	31.1 million Dth	36.4 million Dth
Gains (losses)	(800,000)	(1,100,000)	9,300,000	(5,700,000)
Fuel Oil [Member]
Derivatives, Fair Value [Line Items]
Derivative asset	0		0		600,000
Derivative liability	0		0		0
Volume of derivative instruments	2.6 million gallons	2.5 million gallons	7.0 million gallons	6.2 million gallons
Gains (losses)	0	(100,000)	600,000	100,000
Ftrs [Member]
Derivatives, Fair Value [Line Items]
Derivative asset	10,100,000		10,100,000		3,500,000
Derivative liability	0		0		0
Volume of derivative instruments	6.6 million MWh	6.9 million MWh	19.7 million MWh	19.2 million MWh
Gains (losses)	2,000,000	5,400,000	11,600,000	11,000,000
Coal [Member]
Derivatives, Fair Value [Line Items]
Derivative asset	5,500,000		5,500,000		2,100,000
Derivative liability	$ 0		$ 0		$ 200,000

XML

Common Equity Common Equity 2 (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
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	7,571,752		7,571,752
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 29.27		$ 29.27
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number	4,691,897		4,691,897
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 23.95		$ 23.95
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value	$ 12.7	$ 1.9	$ 30.2	$ 37.9
Exercise of stock options			31.7	42.7
Employee Service Share-based Compensation, Tax Benefit Realized from Exercise of Stock Options			12.1	15.1
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	8,169,393		8,089,710
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period	0		899,500	1,418,560
Share Based Compensation Arrangement By Share Based Payment Award Options Grant In Period Weighted Average Exercise Price	$ 0.00		$ 41.03
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period	(597,641)		(1,400,263)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period	0		(17,195)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	7,571,752		7,571,752
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 28.87		$ 26.84
Share Based Compensation Arrangement By Share Based Payment Awards Options Exercises In Period Weighted Average Exercise Price	$ 23.69		$ 22.66
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price	$ 0.00		$ 36.73
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 29.27		$ 29.27
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range Outstanding Options Weighted Average Remaining Contractual Period			5 years 7 months
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value	103.9		103.9
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number	4,691,897		4,691,897
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 23.95		$ 23.95
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Weighted Average Remaining Contractual Term			3 years 11 months
Share Based Compensation Arrangement by Share Based Payments Award, Options Exercisable, Intrinsic Value	$ 89.4		$ 89.4

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, 2014	Dec. 31, 2013	Sep. 30, 2014 Pension Plan [Member]	Sep. 30, 2013 Pension Plan [Member]	Sep. 30, 2014 Pension Plan [Member]	Sep. 30, 2013 Pension Plan [Member]	Sep. 30, 2014 Other Postretirement Benefit Plan [Member]	Sep. 30, 2013 Other Postretirement Benefit Plan [Member]	Sep. 30, 2014 Other Postretirement Benefit Plan [Member]	Sep. 30, 2013 Other Postretirement Benefit Plan [Member]
Net Periodic Benefit Cost
Service cost			$ 2.6	$ 3.7	$ 7.6	$ 11.0	$ 2.1	$ 2.5	$ 6.4	$ 7.5
Interest cost			17.0	15.1	51.1	45.3	4.4	3.9	13.3	11.7
Expected return on plan assets			(24.7)	(23.9)	(74.0)	(71.8)	(5.9)	(5.4)	(17.8)	(16.0)
Amortization of:
Transition obligation							0	0	0	0
Prior service cost (credit)			0.6	0.5	1.6	1.7	(0.4)	(0.5)	(1.3)	(1.5)
Actuarial loss			9.1	13.6	27.5	40.8	0.3	1.0	0.9	2.8
Net Periodic Benefit Cost			4.6	9.0	13.8	27.0	0.5	1.5	1.5	4.5
Benefits (Textuals) [Abstract]
Pension and Other Postretirement Benefit Contributions	0
Estimated liability of Postemployment benefits	$ 4.2	$ 4.2

XML

Long Term Debt

9 Months Ended

Sep. 30, 2014

Long-term Debt, Unclassified [Abstract]

LONG TERM DEBT

LONG-TERM DEBT

In May 2014, Wisconsin Electric issued $250 million of 4.25% Debentures due June 1, 2044. The debentures were issued under an existing shelf registration statement filed with the SEC in November 2013.

In April 2014, Wisconsin Electric retired $300 million of long-term debt that matured.

In September 2013, Wisconsin Gas used short-term borrowings to retire $45 million of long-term debt that matured.

In June 2013, Wisconsin Electric issued $250 million of 1.70% Debentures due June 15, 2018. The debentures were issued under an existing shelf registration statement filed with the SEC in February 2011.

In May 2013, Wisconsin Electric retired $300 million of long-term debt that matured.

XML

Long Term Debt (Details) (USD $) In Millions, unless otherwise specified		9 Months Ended			9 Months Ended
	Sep. 30, 2014 Wis Elec Debenture due June 1, 2044 [Member]	Sep. 30, 2014 Wis Elec Debentures due April 1, 2014 [Member]	Sep. 30, 2013 Wisc Gas Debentures Due Sept 15 2013 [Domain]	Sep. 30, 2013 Wis Elec Debenture due June, 15 2018 [Domain]	Sep. 30, 2013 Wis Elec Debentures due May 15 2013 [Domain]
Long Term Debt (Textuals)
Issuance of long-term debt	$ 250			$ 250
Interest rate on long-term debt	4.25%			1.70%
Retirement of long-term debt		$ 300	$ 45		$ 300

XML

Common Equity Common Equity 5 (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Repurchased During Period, Shares			1,900,000	4,600,000
Stock Repurchased During Period, Value			$ 84,200,000	$ 187,900,000
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 Repurchase Plan, 2013 [Member] [Domain]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Repurchase Program, Authorized Amount	300,000,000		300,000,000
Treasury Stock Acquired, Average Cost Per Share			$ 43.66
Stock Repurchased During Period, Shares			400,000
Stock Repurchased During Period, Value			18,600,000
Share Repurchase Plan, 2011 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Repurchased During Period, Shares				2,500,000
Stock Repurchased During Period, Value				103,000,000
Restricted stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value	0	0	2,700,000	4,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	156,768		150,698
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	0		71,504
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	0		(63,509)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(1,289)		(3,214)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	155,479		155,479
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		$ 40.96
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		$ 33.02
Share Based Compensation Arrangement By Share Based Payment Awards Equity Instruments Other Than Options Forfeited In Period Weighted Average Grant Date Fair Value	$ 38.61		$ 38.47
Tax Benefit from Stock Options Exercised	0	0	1,000,000	1,300,000.00
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	3,500,000		3,500,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition			22 months
Share Repurchases to Fulfill Exercised Stock Options and Restricted Stock Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Repurchased During Period, Shares			1,500,000	2,100,000
Stock Repurchased During Period, Value			$ 65,600,000	$ 84,900,000

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Fair Value Measurements Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement Captions [Line Items]
Fair Value, Assets Measured on Recurring Basis, Derivative Financial Instruments, Assets	$ 2.9	$ 5.7
Fair Value Assets Measured on Recurring Basis Total Assets	2.9	5.7
Fair Value, Liabilities Measured on Recurring Basis, Derivative Financial Instruments, Liabilities	1.6	0
Fair Value Liabilities Measured on Recurring Basis Total Liabilities	1.6	0
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement Captions [Line Items]
Fair Value, Assets Measured on Recurring Basis, Derivative Financial Instruments, Assets	11.4	2.6
Fair Value Assets Measured on Recurring Basis Total Assets	11.4	2.6
Fair Value, Liabilities Measured on Recurring Basis, Derivative Financial Instruments, Liabilities	0	0.3
Fair Value Liabilities Measured on Recurring Basis Total Liabilities	0	0.3
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement Captions [Line Items]
Fair Value, Assets Measured on Recurring Basis, Derivative Financial Instruments, Assets	10.1	3.5
Fair Value Assets Measured on Recurring Basis Total Assets	10.1	3.5
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]
Fair Value, Assets Measured on Recurring Basis, Derivative Financial Instruments, Assets	24.4	11.8
Fair Value Assets Measured on Recurring Basis Total Assets	24.4	11.8
Fair Value, Liabilities Measured on Recurring Basis, Derivative Financial Instruments, Liabilities	1.6	0.3
Fair Value Liabilities Measured on Recurring Basis Total Liabilities	$ 1.6	$ 0.3

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Fair Value Measurements, Derivatives (Details) (Derivative [Member], USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Derivative [Member]
Fair value of derivatives classified as Level 3 in the fair value hierarchy
Beginning Balance	$ 14.1	$ 9.2	$ 3.5	$ 4.7
Realized and unrealized gains (losses)	0	0	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases	0	0	15.6	10.6
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	(4.0)	(3.6)	(9.0)	(9.7)
Transfers in and/or out of Level 3	0	0	0	0
Ending Balance	10.1	5.6	10.1	5.6
Change in unrealized gains (losses) relating to instruments still held as of period end	$ 0	$ 0	$ 0	$ 0

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Common Equity

9 Months Ended

Sep. 30, 2014

Stockholders' Equity Note [Abstract]

COMMON EQUITY

COMMON EQUITY

Stock Option Activity:   The following table identifies non-qualified stock options granted by the Compensation Committee of the Board of Directors (Compensation Committee):

	2014			2013
Non-qualified stock options granted year to date	899,500			1,418,560
Estimated fair value per non-qualified stock option	$	4.18		$	3.45
Assumptions used to value the options using a binomial option pricing model:
Risk-free interest rate	0.1% - 3.0%			0.1% - 1.9%
Dividend yield	3.8		%	3.7		%
Expected volatility	18.0		%	18.0		%
Expected forfeiture rate	2.0		%	2.0		%
Expected life (years)	5.8			5.9

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, 2014:

					Weighted-
					Average
			Weighted-		Remaining	Aggregate
	Number of		Average		Contractual Life	Intrinsic Value
Stock Options	Options		Exercise Price		(Years)	(Millions)
Outstanding as of July 1, 2014	8,169,393		$	28.87
Granted	—		$	—
Exercised	(597,641	)	$	23.69
Forfeited	—		$	—
Outstanding as of September 30, 2014	7,571,752		$	29.27
Outstanding as of January 1, 2014	8,089,710		$	26.84
Granted	899,500		$	41.03
Exercised	(1,400,263	)	$	22.66
Forfeited	(17,195	)	$	36.73
Outstanding as of September 30, 2014	7,571,752		$	29.27	5.6	$	103.9
Exercisable as of September 30, 2014	4,691,897		$	23.95	3.9	$	89.4

The intrinsic value of options exercised was $12.7 million and $30.2 million for the three and nine months ended September 30, 2014, and $1.9 million and $37.9 million for the same periods in 2013, respectively. Cash received from options exercised was $31.7 million and $42.7 million for the nine months ended September 30, 2014 and 2013, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was $12.1 million and $15.1 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 of 2014.

The following table summarizes information about stock options outstanding as of September 30, 2014:

	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)
$17.10 to $21.11	1,663,372	$	20.70	3.6	1,663,372	$	20.70	3.6
$23.88 to $29.35	2,778,020	$	24.82	3.7	2,778,020	$	24.82	3.7
$34.88 to $41.03	3,130,360	$	37.78	8.3	250,505	$	35.83	7.6
	7,571,752	$	29.27	5.6	4,691,897	$	23.95	3.9

The following table summarizes information about our non-vested options during the three and nine months ended September 30, 2014:

			Weighted-Average
Non-Vested Stock Options	Number of Options		Fair Value
Non-vested as of July 1, 2014	2,916,245		$	3.65
Granted	—		$	—
Vested	(36,390	)	$	3.62
Forfeited	—		$	—
Non-vested as of September 30, 2014	2,879,855		$	3.65
Non-vested as of January 1, 2014	2,380,790		$	3.38
Granted	899,500		$	4.18
Vested	(383,240	)	$	3.26
Forfeited	(17,195	)	$	3.56
Non-vested as of September 30, 2014	2,879,855		$	3.65

As of September 30, 2014, total compensation costs related to non-vested stock options not yet recognized was approximately $3.0 million, which is expected to be recognized over the next 18 months on a weighted-average basis.

Restricted Shares:   The following restricted stock activity occurred during the three and nine months ended September 30, 2014:

			Weighted-Average
Restricted Shares	Number of Shares		Grant Date Fair Value
Outstanding as of July 1, 2014	156,768
Granted	—		$	—
Released	—		$	—
Forfeited	(1,289	)	$	38.61
Outstanding as of September 30, 2014	155,479
Outstanding as of January 1, 2014	150,698
Granted	71,504		$	40.96
Released	(63,509	)	$	33.02
Forfeited	(3,214	)	$	38.47
Outstanding as of September 30, 2014	155,479

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 $2.7 million for the three and nine months ended September 30, 2014, and zero and $4.0 million for the same periods in 2013, respectively. The actual tax benefit realized for the tax deductions from released restricted shares was zero and $1.0 million for the three and nine months ended September 30, 2014, and zero and $1.3 million for the same periods in 2013, respectively.

As of September 30, 2014, total compensation cost related to restricted stock not yet recognized was approximately $3.5 million, which is expected to be recognized over the next 22 months on a weighted-average basis.

Performance Units:   In January 2014 and 2013, the Compensation Committee granted 233,735 and 239,120 performance units, respectively, to officers and other key employees under the Wisconsin Energy Performance Unit Plan. Performance units earned as of December 31, 2013 and 2012 vested and were settled during the first quarter of 2014 and 2013, and had a total intrinsic value of $14.8 million and $19.3 million, respectively. The actual tax benefit realized for the tax deductions from the settlement of performance units was approximately $5.3 million and $7.0 million, respectively. As of September 30, 2014, total compensation cost related to performance units not yet recognized was approximately $7.8 million, which is expected to be recognized over the next 26 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 H -- Common Equity in our 2013 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.

Share Repurchase Program:   In December 2013, our Board of Directors authorized a share repurchase program for the purchase of up to $300 million of our common stock through open market purchases or privately negotiated transactions from January 1, 2014 through the end of 2017. On June 22, 2014, in connection with the proposed acquisition of Integrys, the Board of Directors terminated this share repurchase program. For the nine months ended September 30, 2014, we repurchased $18.6 million of our common stock pursuant to the terminated program at an average cost of $43.66 per share. All of these shares were purchased during the first quarter of 2014. The previous share repurchase program authorized by our Board of Directors expired at the end of 2013. In addition, we have instructed our independent agents to purchase shares on the open market to fulfill exercised stock options and restricted stock awards. The following table identifies shares purchased in the following periods:

	Nine Months Ended September 30
	2014			2013
	Shares	Cost		Shares	Cost
	(In Millions)
Under share repurchase programs	0.4	$	18.6	2.5	$	103.0
To fulfill exercised stock options and restricted stock awards	1.5	65.6		2.1	84.9
Total	1.9	$	84.2	4.6	$	187.9

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Fair Value Measurements, Financial Instruments (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
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	4,554.7	4,626.7
Estimate of Fair Value, Fair Value Disclosure [Member]
Financial Instruments
Preferred stock of subsidiary	25.4	26.0
Long-term debt including current portion	$ 4,979.7	$ 4,911.8

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Commitments and Contingencies (Details) (Manufactured Gas Plant Sites [Member], USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Manufactured Gas Plant Sites [Member]
Commitments and Contingencies [Line Items]
Loss Contingency, Range of Possible Loss, Minimum	$ 19
Loss Contingency, Range of Possible Loss, Maximum	56
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	$ 36.9

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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, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Operating Revenues	$ 1,033.3	$ 1,053.2	$ 3,772.0	$ 3,340.7
Operating Expenses
Fuel and purchased power	336.8	339.1	947.9	886.2
Cost of gas sold	70.6	61.6	788.0	446.9
Other operation and maintenance	249.4	268.1	780.8	821.6
Depreciation and amortization	103.3	96.9	305.3	289.1
Property and revenue taxes	30.6	29.5	91.5	88.4
Total Operating Expenses	790.7	795.2	2,913.5	2,532.2
Revenue from Grants	3.5	0	10.1	0
Operating Income	246.1	258.0	868.6	808.5
Income (Loss) from Equity Method Investments	18.0	17.1	52.8	51.0
Other Income, net	2.9	5.1	12.1	15.3
Interest Expense, net	60.4	62.0	181.7	190.3
Income from Continuing Operations Before Income Taxes	206.6	218.2	751.8	684.5
Income Tax Expense	80.3	80.7	284.9	251.4
Net Income	126.3	137.5	466.9	433.1
Earnings Per Share (Basic)
Continuing operations	$ 0.56	$ 0.61	$ 2.07	$ 1.90
Earnings Per Share (Diluted)
Continuing operations	$ 0.56	$ 0.60	$ 2.05	$ 1.88
Weighted Average Common Shares Outstanding (Millions)
Basic	225.5	226.8	225.6	228.0
Diluted	227.4	228.8	227.6	230.2
Dividends Per Share of Common Stock	$ 0.39	$ 0.3825	$ 1.17	$ 1.0625
Transmission Affiliate [Member]
Operating Expenses
Income (Loss) from Equity Method Investments	$ 18.0	$ 17.1	$ 52.8	$ 51.0

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New Accounting Pronouncements

9 Months Ended

Sep. 30, 2014

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Description of New Accounting Pronouncements Not yet Adopted [Text Block]

NEW ACCOUNTING PRONOUNCEMENTS

Revenue Recognition:   In May 2014, the Financial Accounting Standards Board and the International Accounting Standards Board issued their joint revenue recognition standard, Accounting Standards Update 2014-09, Revenue from Contracts with Customers. This guidance is effective for fiscal years and interim periods beginning after December 15, 2016, and can either be applied retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently assessing the effects this guidance may have on our consolidated financial statements.

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Derivative Instruments Derivative Instruments (Details 2) (Derivative [Member], USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Derivative [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities related to derivatives	$ 21.5	$ 9.6

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Acquisition (Details) (USD $) In Billions, except Share data, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Business Combinations [Abstract]
Business Acquisition, Date of Acquisition Agreement	Jun. 22, 2014
Number of WEC shares per Integrys share	1.128
Cash per share of Integrys common stock	$ 18.58
Total Value of cash and common stock consideration of acquisition	$ 5.4
Estimate of acquisition-related debt	$ 1.5

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Derivative Instruments Derivative Instruments (Details 3) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	$ 1,800,000	$ 0
Derviative Instrument by Counterparty, Gross Amount Recognized on Balance Sheet [Member]
Derivative [Line Items]
Derivative Assets	24,400,000	11,800,000
Derivative Liabilities	1,600,000	300,000
Derviative Instrument by Counterparty, Gross Amount Not Offset on Balance Sheet [Member] [Member]
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	1,000,000	0
Derivative Assets	(600,000)	0
Derivative Liabilities	(1,600,000)	0
Derviative Instrument by Counterparty, Net Amount [Member]
Derivative [Line Items]
Derivative Assets	23,800,000	11,800,000
Derivative Liabilities	$ 0	$ 300,000

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Common Equity Common Equity 1 (Details) (USD $)	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2013
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		3.80%	3.70%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate		18.00%	18.00%
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 10 months	5 years 11 months
Employee Stock Option [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	899,500	1,418,560
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 4.18	$ 3.45
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%	0.10%
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		3.00%	1.90%

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Acquisition

9 Months Ended

Sep. 30, 2014

Business Combinations [Abstract]

Mergers, Acquisitions and Dispositions Disclosures [Text Block]

ACQUISITION

On June 22, 2014, Wisconsin Energy and Integrys entered into an agreement and plan of merger (Merger Agreement) under which Wisconsin Energy will acquire Integrys. Integrys’ shareholders will receive 1.128 shares of Wisconsin Energy common stock and $18.58 in cash per Integrys share of common stock, with the total consideration valued at approximately $5.4 billion, based upon the value of our common stock as of September 30, 2014. The cash consideration will be financed through the issuance of approximately $1.5 billion of debt at the holding company level. The combined company will be named WEC Energy Group, Inc.

The acquisition is subject to several conditions, including, among others, approval of the shareholders of both Wisconsin Energy and Integrys, the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR Act), and the receipt of approvals from various government agencies, including the Federal Energy Regulatory Commission (FERC), Federal Communications Commission, Public Service Commission of Wisconsin (PSCW), Illinois Commerce Commission, Michigan Public Service Commission (MPSC) and Minnesota Public Utilities Commission. The status of these matters is as follows:

• On August 6, 2014, we filed applications for approval with the PSCW, Illinois Commerce Commission, MPSC and Minnesota Public Utilities Commission.

• On August 13, 2014, we filed an initial registration statement on Form S-4 with the SEC to register the stock consideration. On October 6, 2014, the Form S-4, which contains a joint proxy statement/prospectus for Wisconsin Energy and Integrys, was declared effective by the SEC. Meetings for Wisconsin Energy and Integrys shareholders to vote on the acquisition are scheduled for November 21, 2014.

• On August 15, 2014, we filed an application with the FERC.

• On September 24, 2014, we submitted our HSR Act filings, and on October 24, 2014, the United States Department of Justice closed its review of the transaction with no further action required. In addition, on October 24, 2014, the Federal Trade Commission granted early termination of the 30-day waiting period required by the HSR Act.

We anticipate the transaction closing in the second half of 2015.

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Consolidated Condensed Balance Sheets (Unaudited) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Property, Plant and Equipment
In service	$ 15,330.9	$ 14,966.3
Accumulated depreciation	(4,449.2)	(4,257.1)
Property, Plant and Equipment in Service, Net	10,881.7	10,709.2
Construction work in progress	209.6	149.6
Leased facilities, net	43.6	47.8
Net Property, Plant and Equipment	11,134.9	10,906.6
Investments
Equity investment in transmission affiliate	423.3	402.7
Other	32.6	36.1
Total Investments	455.9	438.8
Current Assets
Cash and cash equivalents	88.7	26.0
Accounts receivable, net	339.0	406.0
Accrued revenues	159.1	321.1
Materials, supplies and inventories	379.3	329.4
Current deferred tax asset, net	165.5	310.0
Prepayments and other	142.9	158.6
Total Current Assets	1,274.5	1,551.1
Deferred Charges and Other Assets
Regulatory assets	1,096.7	1,108.5
Goodwill	441.9	441.9
Other	321.0	322.5
Total Deferred Charges and Other Assets	1,859.6	1,872.9
Total Assets	14,724.9	14,769.4
Capitalization
Common equity	4,398.3	4,233.0
Preferred stock of subsidiary	30.4	30.4
Long-term debt	4,569.6	4,363.2
Total Capitalization	8,998.3	8,626.6
Current Liabilities
Long-term debt due currently	47.7	342.2
Short-term debt	475.8	537.4
Accounts payable	315.0	342.6
Accrued payroll and benefits	71.4	96.9
Other	155.7	177.3
Total Current Liabilities	1,065.6	1,496.4
Deferred Credits and Other Liabilities
Regulatory liabilities	839.0	879.1
Deferred income taxes - long-term	2,752.7	2,634.0
Deferred revenue, net	627.2	664.2
Pension and other benefit obligations	168.9	173.2
Other	273.2	295.9
Total Deferred Credits and Other Liabilities	4,661.0	4,646.4
Total Capitalization and Liabilities	$ 14,724.9	$ 14,769.4

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Common Equity (Tables)

9 Months Ended

Sep. 30, 2014

Common Equity (Tables) [Abstract]

Shares Repurchased [Table Text Block]

	Nine Months Ended September 30
	2014			2013
	Shares	Cost		Shares	Cost
	(In Millions)
Under share repurchase programs	0.4	$	18.6	2.5	$	103.0
To fulfill exercised stock options and restricted stock awards	1.5	65.6		2.1	84.9
Total	1.9	$	84.2	4.6	$	187.9

Assumptions for valuing options using binomial option pricing model

	2014			2013
Non-qualified stock options granted year to date	899,500			1,418,560
Estimated fair value per non-qualified stock option	$	4.18		$	3.45
Assumptions used to value the options using a binomial option pricing model:
Risk-free interest rate	0.1% - 3.0%			0.1% - 1.9%
Dividend yield	3.8		%	3.7		%
Expected volatility	18.0		%	18.0		%
Expected forfeiture rate	2.0		%	2.0		%
Expected life (years)	5.8			5.9

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, 2014	8,169,393		$	28.87
Granted	—		$	—
Exercised	(597,641	)	$	23.69
Forfeited	—		$	—
Outstanding as of September 30, 2014	7,571,752		$	29.27
Outstanding as of January 1, 2014	8,089,710		$	26.84
Granted	899,500		$	41.03
Exercised	(1,400,263	)	$	22.66
Forfeited	(17,195	)	$	36.73
Outstanding as of September 30, 2014	7,571,752		$	29.27	5.6	$	103.9
Exercisable as of September 30, 2014	4,691,897		$	23.95	3.9	$	89.4

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)
$17.10 to $21.11	1,663,372	$	20.70	3.6	1,663,372	$	20.70	3.6
$23.88 to $29.35	2,778,020	$	24.82	3.7	2,778,020	$	24.82	3.7
$34.88 to $41.03	3,130,360	$	37.78	8.3	250,505	$	35.83	7.6
	7,571,752	$	29.27	5.6	4,691,897	$	23.95	3.9

Non-vested options

			Weighted-Average
Non-Vested Stock Options	Number of Options		Fair Value
Non-vested as of July 1, 2014	2,916,245		$	3.65
Granted	—		$	—
Vested	(36,390	)	$	3.62
Forfeited	—		$	—
Non-vested as of September 30, 2014	2,879,855		$	3.65
Non-vested as of January 1, 2014	2,380,790		$	3.38
Granted	899,500		$	4.18
Vested	(383,240	)	$	3.26
Forfeited	(17,195	)	$	3.56
Non-vested as of September 30, 2014	2,879,855		$	3.65

Restricted stock activity

			Weighted-Average
Restricted Shares	Number of Shares		Grant Date Fair Value
Outstanding as of July 1, 2014	156,768
Granted	—		$	—
Released	—		$	—
Forfeited	(1,289	)	$	38.61
Outstanding as of September 30, 2014	155,479
Outstanding as of January 1, 2014	150,698
Granted	71,504		$	40.96
Released	(63,509	)	$	33.02
Forfeited	(3,214	)	$	38.47
Outstanding as of September 30, 2014	155,479

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Document and Entity Information Document (USD $) In Billions, except Share data, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Jun. 30, 2014
Entity Information [Line Items]
Entity Registrant Name	WISCONSIN ENERGY CORP
Entity Central Index Key	0000783325
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding	225,517,341
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float		$ 10.6

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2014

Fair Value Measurements (Tables) [Abstract]

Financial assets and liabilities by level within the fair value hierarchy

Recurring Fair Value Measures	As of September 30, 2014
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Derivatives	$	2.9	$	11.4	$	10.1	$	24.4
Total	$	2.9	$	11.4	$	10.1	$	24.4
Liabilities:
Derivatives	$	1.6	$	—	$	—	$	1.6
Total	$	1.6	$	—	$	—	$	1.6

Recurring Fair Value Measures	As of December 31, 2013
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Derivatives	$	5.7	$	2.6	$	3.5	$	11.8
Total	$	5.7	$	2.6	$	3.5	$	11.8
Liabilities:
Derivatives	$	—	$	0.3	$	—	$	0.3
Total	$	—	$	0.3	$	—	$	0.3

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

	Three Months Ended September 30						Nine Months Ended September 30
	2014			2013			2014			2013
	(Millions of Dollars)
Beginning Balance	$	14.1		$	9.2		$	3.5		$	4.7
Realized and unrealized gains (losses)	—			—			—			—
Purchases	—			—			15.6			10.6
Issuances	—			—			—			—
Settlements	(4.0		)	(3.6		)	(9.0		)	(9.7		)
Transfers in and/or out of Level 3	—			—			—			—
Balance as of September 30	$	10.1		$	5.6		$	10.1		$	5.6
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, 2014				December 31, 2013
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	25.4	$	30.4	$	26.0
Long-term debt, including current portion	$	4,554.7	$	4,979.7	$	4,626.7	$	4,911.8

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Consolidated Condensed Statements of Cash Flows (Unaudited) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Operating Activities
Net Income	$ 466.9	$ 433.1
Reconciliation to cash
Depreciation and amortization	312.9	297.6
Deferred income taxes and investment tax credits, net	258.5	219.8
Contributions to qualified benefit plans	0
Change in -
Accounts receivable and accrued revenues	221.1	95.3
Inventories	(49.9)	(6.9)
Other current assets	37.2	40.6
Accounts payable	(27.7)	(59.2)
Accrued income taxes, net	(10.3)	48.2
Other current liabilities	(36.8)	(0.1)
Other, net	(137.3)	(18.1)
Cash Provided by Operating Activities	1,034.6	1,050.3
Investing Activities
Capital expenditures	(513.0)	(497.7)
Cost of Removal, Net of Salvage	(18.2)	(27.8)
Investment in transmission affiliate	(10.5)	(7.9)
Other, net	12.8	(11.4)
Cash Used in Investing Activities	(528.9)	(544.8)
Financing Activities
Exercise of stock options	31.7	42.7
Purchase of common stock	(84.2)	(187.9)
Dividends paid on common stock	(264.0)	(242.3)
Issuance of long-term debt	250.0	251.0
Retirement of long-term debt	(322.0)	(364.2)
Change in short-term debt	(61.6)	(32.8)
Other, net	7.1	10.9
Cash Used in Financing Activities	(443.0)	(522.6)
Change in Cash and Cash Equivalents	62.7	(17.1)
Cash and Cash Equivalents at Beginning of Period	26.0	35.6
Cash and Cash Equivalents at End of Period	$ 88.7	$ 18.5

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Benefits

9 Months Ended

Sep. 30, 2014

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	2014			2013			2014			2013
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	2.6		$	3.7		$	7.6		$	11.0
Interest cost	17.0			15.1			51.1			45.3
Expected return on plan assets	(24.7		)	(23.9		)	(74.0		)	(71.8		)
Amortization of:
Prior service cost	0.6			0.5			1.6			1.7
Actuarial loss	9.1			13.6			27.5			40.8
Net Periodic Benefit Cost	$	4.6		$	9.0		$	13.8		$	27.0

	OPEB Costs
	Three Months Ended September 30						Nine Months Ended September 30
Benefit Plan Cost Components	2014			2013			2014			2013
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	2.1		$	2.5		$	6.4		$	7.5
Interest cost	4.4			3.9			13.3			11.7
Expected return on plan assets	(5.9		)	(5.4		)	(17.8		)	(16.0		)
Amortization of:
Transition obligation	—			—			—			—
Prior service (credit)	(0.4		)	(0.5		)	(1.3		)	(1.5		)
Actuarial loss	0.3			1.0			0.9			2.8
Net Periodic Benefit Cost	$	0.5		$	1.5		$	1.5		$	4.5

We made no contributions to our qualified benefit plans during the first nine months of 2014 and 2013. 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 $4.2 million as of both September 30, 2014 and December 31, 2013.

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Derivative Instruments

9 Months Ended

Sep. 30, 2014

Derivative Instruments and Hedges, Assets [Abstract]

DERIVATIVE INSTRUMENTS

DERIVATIVE INSTRUMENTS

We utilize derivatives as part of our risk management program to manage the volatility and costs of purchased power, generation and natural gas purchases for the benefit of our customers and shareholders. Our approach is non-speculative and designed to mitigate risk and protect against price volatility. Regulated hedging programs require prior approval by the PSCW.

We record derivative instruments on the balance sheet as an asset or liability measured at its fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. As of September 30, 2014, we recognized $2.5 million in regulatory assets and $21.5 million in regulatory liabilities related to derivatives in comparison to $0.3 million in regulatory assets and $9.6 million in regulatory liabilities as of December 31, 2013.

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 $1.7 million is recorded in other deferred charges and other assets as of September 30, 2014, and the long-term portion of our derivative liabilities of $0.1 million is recorded in other deferred credit and other liabilities as of September 30, 2014. Our Consolidated Condensed Balance Sheets as of September 30, 2014 and December 31, 2013 include:

	September 30, 2014				December 31, 2013
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	8.8	$	1.6	$	5.6	$	0.1
Fuel Oil	—		—		0.6		—
FTRs	10.1		—		3.5		—
Coal	5.5		—		2.1		0.2
Total	$	24.4	$	1.6	$	11.8	$	0.3

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, 2014				Three Months Ended September 30, 2013
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)
Natural Gas	6.3 million Dth	$	(0.8	)	6.3 million Dth	$	(1.1	)
Fuel Oil	2.6 million gallons	—			2.5 million gallons	(0.1		)
FTRs	6.6 million MWh	2.0			6.9 million MWh	5.4
Total		$	1.2			$	4.2

	Nine Months Ended September 30, 2014			Nine Months Ended September 30, 2013
	Volume	Gains (Losses)		Volume	Gains (Losses)
		(Millions of Dollars)			(Millions of Dollars)
Natural Gas	31.1 million Dth	$	9.3	36.4 million Dth	$	(5.7	)
Fuel Oil	7.0 million gallons	0.6		6.2 million gallons	0.1
FTRs	19.7 million MWh	11.6		19.2 million MWh	11.0
Total		$	21.5		$	5.4

As of September 30, 2014 and December 31, 2013, we posted collateral of $1.8 million and zero, respectively, in our margin accounts. These amounts are recorded on the balance sheets in other current assets.

The fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. The table below shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on the balance sheet as of September 30, 2014 and December 31, 2013.

	September 30, 2014						December 31, 2013
	Derivative			Derivative			Derivative		Derivative
	Asset			Liability			Asset		Liability
	(Millions of Dollars)
Gross Amount Recognized on the Balance Sheet	$	24.4		$	1.6		$	11.8	$	0.3
Gross Amount Not Offset on Balance Sheet (a)	(0.6		)	(1.6		)	—		—
Net Amount	$	23.8		$	—		$	11.8	$	0.3

(a) Gross Amount Not Offset on Balance Sheet includes cash collateral posted of $1.0 million and zero as of September 30, 2014 and December 31, 2013, respectively.

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Common Equity (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Performance units [Member]
Common Equity (Textuals) [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period			233,735	239,120
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value			$ 14,800,000	$ 19,300,000
Tax Benefit from Stock Options Exercised			5,300,000	7,000,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	7,800,000		7,800,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition			26 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		71,504
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value	0	0	2,700,000	4,000,000
Tax Benefit from Stock Options Exercised	0	0	1,000,000	1,300,000.00
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 3,500,000		$ 3,500,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition			22 months

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2014

Derivative Instruments (Tables) [Abstract]

Derivative instruments in balance sheet

	September 30, 2014				December 31, 2013
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	8.8	$	1.6	$	5.6	$	0.1
Fuel Oil	—		—		0.6		—
FTRs	10.1		—		3.5		—
Coal	5.5		—		2.1		0.2
Total	$	24.4	$	1.6	$	11.8	$	0.3

Derivative instruments' estimated notional volumes and gain (losses)

	Three Months Ended September 30, 2014				Three Months Ended September 30, 2013
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)
Natural Gas	6.3 million Dth	$	(0.8	)	6.3 million Dth	$	(1.1	)
Fuel Oil	2.6 million gallons	—			2.5 million gallons	(0.1		)
FTRs	6.6 million MWh	2.0			6.9 million MWh	5.4
Total		$	1.2			$	4.2

	Nine Months Ended September 30, 2014			Nine Months Ended September 30, 2013
	Volume	Gains (Losses)		Volume	Gains (Losses)
		(Millions of Dollars)			(Millions of Dollars)
Natural Gas	31.1 million Dth	$	9.3	36.4 million Dth	$	(5.7	)
Fuel Oil	7.0 million gallons	0.6		6.2 million gallons	0.1
FTRs	19.7 million MWh	11.6		19.2 million MWh	11.0
Total		$	21.5		$	5.4

Offsetting Assets and Liabilities [Table Text Block]

	September 30, 2014						December 31, 2013
	Derivative			Derivative			Derivative		Derivative
	Asset			Liability			Asset		Liability
	(Millions of Dollars)
Gross Amount Recognized on the Balance Sheet	$	24.4		$	1.6		$	11.8	$	0.3
Gross Amount Not Offset on Balance Sheet (a)	(0.6		)	(1.6		)	—		—
Net Amount	$	23.8		$	—		$	11.8	$	0.3

(a) Gross Amount Not Offset on Balance Sheet includes cash collateral posted of $1.0 million and zero as of September 30, 2014 and December 31, 2013, respectively.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2014

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. 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 $19 million to $56 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, 2014, we have established reserves of $36.9 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.

Divested Assets:   Pursuant to the sale of the Point Beach Nuclear Power Plant, we agreed to indemnification provisions customary to transactions involving the sale of nuclear assets. We also provided customary indemnifications to Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corp., in connection with the sale of our interest in Edgewater Generating Unit 5.

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Segment Information

9 Months Ended

Sep. 30, 2014

Segment Information [Abstract]

SEGMENT INFORMATION

SEGMENT INFORMATION

Summarized financial information concerning our reportable segments for the three and nine months ended September 30, 2014 and 2013 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, 2014
Operating Revenues (b)	$	1,017.7	$	114.1	$	0.3		$	(98.8	)	$	1,033.3
Other Operation and Maintenance	$	337.4	$	3.5	$	6.0		$	(97.5	)	$	249.4
Depreciation and Amortization	$	86.3	$	17.0	$	—		$	—		$	103.3
Operating Income (Loss)	$	158.4	$	93.6	$	(5.9	)	$	—		$	246.1
Equity in Earnings of Unconsolidated Affiliates	$	18.0	$	—	$	—		$	—		$	18.0
Interest Expense, Net	$	32.1	$	16.1	$	12.4		$	(0.2	)	$	60.4
Income Tax Expense (Benefit)	$	55.0	$	30.4	$	(5.1	)	$	—		$	80.3
Net Income (Loss)	$	90.8	$	47.3	$	126.3		$	(138.1	)	$	126.3
Capital Expenditures	$	188.2	$	18.0	$	1.3		$	—		$	207.5
September 30, 2013
Operating Revenues (b)	$	1,037.2	$	114.2	$	0.4		$	(98.6	)	$	1,053.2
Other Operation and Maintenance	$	359.5	$	4.2	$	1.9		$	(97.5	)	$	268.1
Depreciation and Amortization	$	79.9	$	16.8	$	0.2		$	—		$	96.9
Operating Income (Loss)	$	166.6	$	93.2	$	(1.8	)	$	—		$	258.0
Equity in Earnings of Unconsolidated Affiliates	$	17.1	$	—	$	—		$	—		$	17.1
Interest Expense, Net	$	33.0	$	16.4	$	12.8		$	(0.2	)	$	62.0
Income Tax Expense (Benefit)	$	56.1	$	29.5	$	(4.9	)	$	—		$	80.7
Net Income (Loss)	$	99.3	$	47.4	$	137.4		$	(146.6	)	$	137.5
Capital Expenditures	$	178.1	$	10.4	$	1.9		$	—		$	190.4

	Reportable Segments							Eliminations
	Energy				Corporate &			& Reconciling			Total
Nine Months Ended	Utility		Non-Utility		Other (a)			Items			Consolidated
	(Millions of Dollars)
September 30, 2014
Operating Revenues (b)	$	3,729.6	$	335.8	$	0.9		$	(294.3	)	$	3,772.0
Other Operation and Maintenance	$	1,048.6	$	9.7	$	13.3		$	(290.8	)	$	780.8
Depreciation and Amortization	$	254.2	$	50.6	$	0.5		$	—		$	305.3
Operating Income (Loss)	$	606.3	$	275.5	$	(13.2	)	$	—		$	868.6
Equity in Earnings of Unconsolidated Affiliates	$	52.8	$	—	$	—		$	—		$	52.8
Interest Expense, Net	$	96.8	$	48.6	$	36.8		$	(0.5	)	$	181.7
Income Tax Expense (Benefit)	$	213.8	$	90.6	$	(19.5	)	$	—		$	284.9
Net Income (Loss)	$	356.5	$	136.8	$	466.7		$	(493.1	)	$	466.9
Capital Expenditures	$	481.5	$	27.7	$	3.8		$	—		$	513.0
September 30, 2013
Operating Revenues (b)	$	3,296.7	$	337.3	$	1.0		$	(294.3	)	$	3,340.7
Other Operation and Maintenance	$	1,097.7	$	10.6	$	4.1		$	(290.8	)	$	821.6
Depreciation and Amortization	$	238.2	$	50.3	$	0.6		$	—		$	289.1
Operating Income (Loss)	$	536.1	$	276.4	$	(4.0	)	$	—		$	808.5
Equity in Earnings of Unconsolidated Affiliates	$	51.0	$	—	$	—		$	—		$	51.0
Interest Expense, Net	$	103.1	$	49.4	$	38.2		$	(0.4	)	$	190.3
Income Tax Expense (Benefit)	$	179.9	$	90.1	$	(18.6	)	$	—		$	251.4
Net Income (Loss)	$	317.9	$	137.2	$	432.9		$	(454.9	)	$	433.1
Capital Expenditures	$	476.2	$	17.5	$	4.0		$	—		$	497.7

(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, 2014

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 a purchased power agreement which represents a variable interest. This agreement is for 236 MW of firm capacity from a gas-fired cogeneration facility and we account for it as a capital lease. The agreement includes no minimum energy requirements over the remaining term of approximately eight 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 $184.4 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under contracts considered variable interests for the nine months ended September 30, 2014 and 2013 were $39.8 million and $37.8 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

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Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 2014

Supplemental Cash Flow Information [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

SUPPLEMENTAL CASH FLOW INFORMATION

During the nine months ended September 30, 2014, we paid $143.4 million in interest, net of amounts capitalized, and paid $22.0 million in income taxes, net of refunds. During the nine months ended September 30, 2013, we paid $146.6 million in interest, net of amounts capitalized, and received $38.3 million in net refunds from income taxes.

As of September 30, 2014 and 2013, the amount of accounts payable related to capital expenditures was $4.9 million and $3.4 million, respectively.

During the nine months ended September 30, 2014 and 2013, total amortization of deferred revenue was $41.7 million and $42.7 million, respectively.

During the nine months ended September 30, 2014 and 2013, our equity in earnings from ATC was $52.8 million and $51.0 million, respectively. During the nine months ended September 30, 2014 and 2013, distributions received from ATC were $42.6 million and $40.5 million, respectively.

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Derivative Instruments Derivative Instruments (Details 1) (Derivative [Member], USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Derivative [Member]
Regulatory Assets [Line Items]
Regulatory assets related to derivatives	$ 2.5	$ 0.3

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2014

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, 2014
Operating Revenues (b)	$	1,017.7	$	114.1	$	0.3		$	(98.8	)	$	1,033.3
Other Operation and Maintenance	$	337.4	$	3.5	$	6.0		$	(97.5	)	$	249.4
Depreciation and Amortization	$	86.3	$	17.0	$	—		$	—		$	103.3
Operating Income (Loss)	$	158.4	$	93.6	$	(5.9	)	$	—		$	246.1
Equity in Earnings of Unconsolidated Affiliates	$	18.0	$	—	$	—		$	—		$	18.0
Interest Expense, Net	$	32.1	$	16.1	$	12.4		$	(0.2	)	$	60.4
Income Tax Expense (Benefit)	$	55.0	$	30.4	$	(5.1	)	$	—		$	80.3
Net Income (Loss)	$	90.8	$	47.3	$	126.3		$	(138.1	)	$	126.3
Capital Expenditures	$	188.2	$	18.0	$	1.3		$	—		$	207.5
September 30, 2013
Operating Revenues (b)	$	1,037.2	$	114.2	$	0.4		$	(98.6	)	$	1,053.2
Other Operation and Maintenance	$	359.5	$	4.2	$	1.9		$	(97.5	)	$	268.1
Depreciation and Amortization	$	79.9	$	16.8	$	0.2		$	—		$	96.9
Operating Income (Loss)	$	166.6	$	93.2	$	(1.8	)	$	—		$	258.0
Equity in Earnings of Unconsolidated Affiliates	$	17.1	$	—	$	—		$	—		$	17.1
Interest Expense, Net	$	33.0	$	16.4	$	12.8		$	(0.2	)	$	62.0
Income Tax Expense (Benefit)	$	56.1	$	29.5	$	(4.9	)	$	—		$	80.7
Net Income (Loss)	$	99.3	$	47.4	$	137.4		$	(146.6	)	$	137.5
Capital Expenditures	$	178.1	$	10.4	$	1.9		$	—		$	190.4

	Reportable Segments							Eliminations
	Energy				Corporate &			& Reconciling			Total
Nine Months Ended	Utility		Non-Utility		Other (a)			Items			Consolidated
	(Millions of Dollars)
September 30, 2014
Operating Revenues (b)	$	3,729.6	$	335.8	$	0.9		$	(294.3	)	$	3,772.0
Other Operation and Maintenance	$	1,048.6	$	9.7	$	13.3		$	(290.8	)	$	780.8
Depreciation and Amortization	$	254.2	$	50.6	$	0.5		$	—		$	305.3
Operating Income (Loss)	$	606.3	$	275.5	$	(13.2	)	$	—		$	868.6
Equity in Earnings of Unconsolidated Affiliates	$	52.8	$	—	$	—		$	—		$	52.8
Interest Expense, Net	$	96.8	$	48.6	$	36.8		$	(0.5	)	$	181.7
Income Tax Expense (Benefit)	$	213.8	$	90.6	$	(19.5	)	$	—		$	284.9
Net Income (Loss)	$	356.5	$	136.8	$	466.7		$	(493.1	)	$	466.9
Capital Expenditures	$	481.5	$	27.7	$	3.8		$	—		$	513.0
September 30, 2013
Operating Revenues (b)	$	3,296.7	$	337.3	$	1.0		$	(294.3	)	$	3,340.7
Other Operation and Maintenance	$	1,097.7	$	10.6	$	4.1		$	(290.8	)	$	821.6
Depreciation and Amortization	$	238.2	$	50.3	$	0.6		$	—		$	289.1
Operating Income (Loss)	$	536.1	$	276.4	$	(4.0	)	$	—		$	808.5
Equity in Earnings of Unconsolidated Affiliates	$	51.0	$	—	$	—		$	—		$	51.0
Interest Expense, Net	$	103.1	$	49.4	$	38.2		$	(0.4	)	$	190.3
Income Tax Expense (Benefit)	$	179.9	$	90.1	$	(18.6	)	$	—		$	251.4
Net Income (Loss)	$	317.9	$	137.2	$	432.9		$	(454.9	)	$	433.1
Capital Expenditures	$	476.2	$	17.5	$	4.0		$	—		$	497.7

(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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Common Equity Common Equity 3 (Details) (USD $)	9 Months Ended
	Sep. 30, 2014
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	7,571,752
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 29.27
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Outstanding Options, Weighted Average Remaining Contractual Term	5 years 7 months
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number	4,691,897
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 23.95
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Weighted Average Remaining Contractual Term	3 years 11 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	1,663,372
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 20.70
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Outstanding Options, Weighted Average Remaining Contractual Term	3 years 7 months
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Number of Exercisable Options	1,663,372
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 20.70
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Weighted Average Remaining Contractual Term	3 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	$ 21.11
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	$ 17.10
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	2,778,020
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 24.82
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Outstanding Options, Weighted Average Remaining Contractual Term	3 years 8 months
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Number of Exercisable Options	2,778,020
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 24.82
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Weighted Average Remaining Contractual Term	3 years 8 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	$ 29.35
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	$ 23.88
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	3,130,360
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 37.78
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Outstanding Options, Weighted Average Remaining Contractual Term	8 years 3 months
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Number of Exercisable Options	250,505
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 35.83
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Weighted Average Remaining Contractual Term	7 years 7 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	$ 41.03
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	$ 34.88

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Supplemental Cash Flow Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Supplemental Cash Flow Information (Textuals)
Interest paid, net of amounts capitalized			$ 143.4	$ 146.6
Proceeds from Income Tax Refunds				38.3
Income Taxes Paid, Net			22.0
Accounts payable related to capital expenditures	4.9	3.4	4.9	3.4
Amortization of deferred revenue			41.7	42.7
Income (Loss) from Equity Method Investments	18.0	17.1	52.8	51.0
Distributions from transmission affiliate			42.6	40.5
Transmission Affiliate [Member]
Supplemental Cash Flow Information (Textuals)
Income (Loss) from Equity Method Investments	$ 18.0	$ 17.1	$ 52.8	$ 51.0

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General Information

9 Months Ended

Sep. 30, 2014

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 2013 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, 2014 are not necessarily indicative of the results which may be expected for the entire fiscal year 2014 because of seasonal and other factors.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2014

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, 2014
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Derivatives	$	2.9	$	11.4	$	10.1	$	24.4
Total	$	2.9	$	11.4	$	10.1	$	24.4
Liabilities:
Derivatives	$	1.6	$	—	$	—	$	1.6
Total	$	1.6	$	—	$	—	$	1.6

Recurring Fair Value Measures	As of December 31, 2013
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Derivatives	$	5.7	$	2.6	$	3.5	$	11.8
Total	$	5.7	$	2.6	$	3.5	$	11.8
Liabilities:
Derivatives	$	—	$	0.3	$	—	$	0.3
Total	$	—	$	0.3	$	—	$	0.3

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
	2014			2013			2014			2013
	(Millions of Dollars)
Beginning Balance	$	14.1		$	9.2		$	3.5		$	4.7
Realized and unrealized gains (losses)	—			—			—			—
Purchases	—			—			15.6			10.6
Issuances	—			—			—			—
Settlements	(4.0		)	(3.6		)	(9.0		)	(9.7		)
Transfers in and/or out of Level 3	—			—			—			—
Balance as of September 30	$	10.1		$	5.6		$	10.1		$	5.6
Change in unrealized gains (losses) relating to instruments still held as of September 30	$	—		$	—		$	—		$	—

Derivative instruments reflected in Level 3 of the hierarchy include Midcontinent Independent System Operator, Inc. (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, 2014				December 31, 2013
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	25.4	$	30.4	$	26.0
Long-term debt, including current portion	$	4,554.7	$	4,979.7	$	4,626.7	$	4,911.8

The carrying value of net accounts receivable, accounts payable and short-term borrowings approximates fair value due to the short-term nature of these instruments. The fair value of our preferred stock is estimated based upon the quoted market value for the same or similar issues. The fair value of our long-term debt, including the current portion of long-term debt, but excluding capitalized leases and unamortized discount on debt, is estimated based upon quoted market value for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows.

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Common Equity Common Equity 4 (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014
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	7,571,752	7,571,752
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 29.27	$ 29.27
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		26 months
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 7.8	$ 7.8
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	2,916,245	2,380,790
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period	0	899,500
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested in Period	(36,390)	(383,240)
Share Based Compensation Arrangements By Share Based Payment Awards Options Vested In Period Weighted Average Fair Value Per Share	$ 3.62	$ 3.26
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period	0	(17,195)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	2,879,855	2,879,855
Non-vested options outstanding beginning balance, weighted average fair value	$ 3.65	$ 3.38
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 0.00	$ 4.18
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Intrinsic Value	$ 0.00	$ (3.56)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 3.65	$ 3.65
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	$ 3.0	$ 3.0

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Segment Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Financial information of reportable operating segments
Operating Revenues	$ 1,033.3	[1]	$ 1,053.2	[1]	$ 3,772.0	[1]	$ 3,340.7	[1]
Other operation and maintenance	249.4		268.1		780.8		821.6
Depreciation and Amortization	103.3		96.9		305.3		289.1
Operating Income (Loss)	246.1		258.0		868.6		808.5
Equity in Earnings of Unconsolidated Affiliates	18.0		17.1		52.8		51.0
Interest Expense, net	60.4		62.0		181.7		190.3
Income Tax Expense (Benefit)	80.3		80.7		284.9		251.4
Net Income (Loss)	126.3		137.5		466.9		433.1
Capital Expenditures	207.5		190.4		513.0		497.7
Reportable Operating Segments Energy Utility [Member]
Financial information of reportable operating segments
Operating Revenues	1,017.7	[1]	1,037.2	[1]	3,729.6	[1]	3,296.7	[1]
Other operation and maintenance	337.4		359.5		1,048.6		1,097.7
Depreciation and Amortization	86.3		79.9		254.2		238.2
Operating Income (Loss)	158.4		166.6		606.3		536.1
Equity in Earnings of Unconsolidated Affiliates	18.0		17.1		52.8		51.0
Interest Expense, net	32.1		33.0		96.8		103.1
Income Tax Expense (Benefit)	55.0		56.1		213.8		179.9
Net Income (Loss)	90.8		99.3		356.5		317.9
Capital Expenditures	188.2		178.1		481.5		476.2
Reportable Operating Segments Energy Non Utility [Member]
Financial information of reportable operating segments
Operating Revenues	114.1	[1]	114.2	[1]	335.8	[1]	337.3	[1]
Other operation and maintenance	3.5		4.2		9.7		10.6
Depreciation and Amortization	17.0		16.8		50.6		50.3
Operating Income (Loss)	93.6		93.2		275.5		276.4
Equity in Earnings of Unconsolidated Affiliates	0		0		0		0
Interest Expense, net	16.1		16.4		48.6		49.4
Income Tax Expense (Benefit)	30.4		29.5		90.6		90.1
Net Income (Loss)	47.3		47.4		136.8		137.2
Capital Expenditures	18.0		10.4		27.7		17.5
Corporate and Other [Member]
Financial information of reportable operating segments
Operating Revenues	0.3	[1],[2]	0.4	[1],[2]	0.9	[1],[2]	1.0	[1],[2]
Other operation and maintenance	6.0	[2]	1.9	[2]	13.3	[2]	4.1	[2]
Depreciation and Amortization	0	[2]	0.2	[2]	0.5	[2]	0.6	[2]
Operating Income (Loss)	(5.9)	[2]	(1.8)	[2]	(13.2)	[2]	(4.0)	[2]
Equity in Earnings of Unconsolidated Affiliates	0	[2]	0	[2]	0	[2]	0	[2]
Interest Expense, net	12.4	[2]	12.8	[2]	36.8	[2]	38.2	[2]
Income Tax Expense (Benefit)	(5.1)	[2]	(4.9)	[2]	(19.5)	[2]	(18.6)	[2]
Net Income (Loss)	126.3	[2]	137.4	[2]	466.7	[2]	432.9	[2]
Capital Expenditures	1.3	[2]	1.9	[2]	3.8	[2]	4.0	[2]
Eliminations and Reconciling Items [Member]
Financial information of reportable operating segments
Operating Revenues	(98.8)	[1]	(98.6)	[1]	(294.3)	[1]	(294.3)	[1]
Other operation and maintenance	(97.5)		(97.5)		(290.8)		(290.8)
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	(0.2)		(0.2)		(0.5)		(0.4)
Income Tax Expense (Benefit)	0		0		0		0
Net Income (Loss)	(138.1)		(146.6)		(493.1)		(454.9)
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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Benefits (Tables)

9 Months Ended

Sep. 30, 2014

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	2014			2013			2014			2013
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	2.6		$	3.7		$	7.6		$	11.0
Interest cost	17.0			15.1			51.1			45.3
Expected return on plan assets	(24.7		)	(23.9		)	(74.0		)	(71.8		)
Amortization of:
Prior service cost	0.6			0.5			1.6			1.7
Actuarial loss	9.1			13.6			27.5			40.8
Net Periodic Benefit Cost	$	4.6		$	9.0		$	13.8		$	27.0

	OPEB Costs
	Three Months Ended September 30						Nine Months Ended September 30
Benefit Plan Cost Components	2014			2013			2014			2013
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	2.1		$	2.5		$	6.4		$	7.5
Interest cost	4.4			3.9			13.3			11.7
Expected return on plan assets	(5.9		)	(5.4		)	(17.8		)	(16.0		)
Amortization of:
Transition obligation	—			—			—			—
Prior service (credit)	(0.4		)	(0.5		)	(1.3		)	(1.5		)
Actuarial loss	0.3			1.0			0.9			2.8
Net Periodic Benefit Cost	$	0.5		$	1.5		$	1.5		$	4.5