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 Ended March 31, 2013

Commission	Registrant; State of Incorporation	IRS Employer
File Number	Address; and Telephone Number	Identification No.
001-01245	WISCONSIN ELECTRIC POWER COMPANY	39-0476280
	(A Wisconsin Corporation)
	231 West Michigan Street
	P.O. Box 2046
	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 [ ]                                Accelerated filer [ ]

                                 Non-accelerated filer [X] (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 (March 31, 2013):

Common Stock, $10 Par Value, 33,289,327 shares outstanding.

All of the common stock of Wisconsin Electric Power Company is owned by Wisconsin Energy Corporation.

Form 10-Q

WISCONSIN ELECTRIC POWER COMPANY

_________________________

FORM 10-Q REPORT FOR THE QUARTER ENDED MARCH 31, 2013

	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	20
3.	Quantitative and Qualitative Disclosures About Market Risk	28
4.	Controls and Procedures	28
	Part II -- Other Information
1.	Legal Proceedings	28
1A.	Risk Factors	29
5.	Other Information	29
6.	Exhibits	30
	Signatures	31

March 2013 2 Wisconsin Electric Power Company

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 Subsidiary and Affiliates
Bostco	Bostco LLC
We Power	W.E. Power, LLC
Wisconsin Energy	Wisconsin Energy Corporation
Wisconsin Gas	Wisconsin Gas LLC
Significant Assets
PIPP	Presque Isle Power Plant
PSGS	Paris Generating Station
VAPP	Valley Power Plant
Other Affiliates
ATC	American Transmission Company LLC
Federal and State Regulatory Agencies
DOE	United States Department of Energy
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
MPSC	Michigan Public Service Commission
PSCW	Public Service Commission of Wisconsin
SEC	Securities and Exchange Commission
WDNR	Wisconsin Department of Natural Resources
Environmental Terms
CAIR	Clean Air Interstate Rule
CSAPR	Cross-State Air Pollution Rule
NOV	Notice of Violation
SO2	Sulfur Dioxide
Other Terms and Abbreviations
AQCS	Air Quality Control System
Compensation Committee	Compensation Committee of the Board of Directors of Wisconsin Energy
Exchange Act	Securities Exchange Act of 1934, as amended
FTRs	Financial Transmission Rights
MISO	Midwest Independent Transmission System Operator, Inc.
NDAA	National Defense Authorization Act
OTC	Over-the-Counter
PTF	Power the Future
WPL	Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corp.
Measurements
Btu	British Thermal Unit(s)
Dth	Dekatherm(s) (One Dth equals one million Btu)
MW	Megawatt(s) (One MW equals one million Watts)
MWh	Megawatt-hour(s)

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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:
Watt	A measure of power production or usage
Accounting Terms
AFUDC	Allowance for Funds Used During Construction
ASU	Accounting Standards Update
GAAP	Generally Accepted Accounting Principles
OPEB	Other Post-Retirement Employee Benefits

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Form 10-Q

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

• Factors affecting utility operations such as catastrophic weather-related or terrorism-related damage; cyber-security threats and disruptions to our technology network; availability of electric generating facilities; unscheduled generation outages, or unplanned maintenance or repairs; unanticipated events causing scheduled generation outages to last longer than expected; unanticipated changes in fossil fuel, purchased power, coal supply, gas supply or water supply costs or availability due to higher demand, shortages, transportation problems or other developments; unanticipated changes in the cost or availability of materials needed to operate new environmental controls at our electric generating facilities or replace and/or repair our electric and gas distribution systems; nonperformance by electric energy or natural gas suppliers under existing power purchase or gas supply contracts; environmental incidents; electric transmission or gas pipeline system constraints; unanticipated organizational structure or key personnel changes; 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 future rate cases and negotiations, including recovery of costs associated with environmental compliance, renewable generation, transmission service, distribution system upgrades, fuel and the Midwest Independent Transmission System Operator, Inc. (MISO) Energy Markets.

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

• The ability to control costs and avoid construction delays during the development and construction of new environmental controls and renewable generation, as well as upgrades to our 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; cuts in funding of the U.S. Treasury Department's 1603 grant program for renewable energy projects under the National Defense Authorization Act (NDAA); electric and gas industry restructuring initiatives; transmission or distribution system operation and/or administration initiatives; any required changes in facilities or operations to reduce the risks or impacts of potential terrorist activities or cybersecurity threats; required approvals for new construction, and the siting approval process for new generation and transmission facilities and new pipeline construction; changes to the Federal Power Act and related regulations and enforcement thereof by the Federal Energy Regulatory Commission (FERC) and other regulatory agencies; changes in allocation of energy assistance, including state public benefits funds; changes in environmental, tax and other laws and regulations to which we are subject; changes in the application of

March 2013 5 Wisconsin Electric Power Company

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

existing laws and regulations; and changes in the interpretation or enforcement of permit conditions by the permitting agencies.

• Internal restructuring options that may be pursued by Wisconsin Energy Corporation (Wisconsin Energy).

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

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

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

• Inflation rates.

• The investment performance of Wisconsin Energy's pension and other post-retirement benefit trusts.

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

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

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

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

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

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

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

• Potential strategic business opportunities, including acquisitions and/or dispositions of assets or businesses, which we cannot ensure will be beneficial for us.

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

• 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, 2012.

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

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Form 10-Q

INTRODUCTION

Wisconsin Electric Power Company, a subsidiary of Wisconsin Energy, was incorporated in the state of Wisconsin in 1896. We maintain our principal executive offices in Milwaukee, Wisconsin. Unless qualified by their context when used in this document, the terms Wisconsin Electric, the Company, our, us or we refer to Wisconsin Electric Power Company and its subsidiary, Bostco LLC (Bostco).

We conduct our operations primarily in three reportable segments: an electric utility segment, a natural gas utility segment and a steam utility segment. We serve approximately 1,127,000 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 469,400 gas customers in Wisconsin and approximately 455 steam customers in metropolitan Milwaukee, Wisconsin. For further financial information about our reportable segments, see Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 7 --Segment Information in the Notes to Consolidated Condensed Financial Statements in this report.

Wisconsin Energy is also the parent company of Wisconsin Gas LLC (Wisconsin Gas), a natural gas distribution utility, which serves customers throughout Wisconsin; and W.E. Power, LLC (We Power), an unregulated company that was formed in 2001 to design, construct, own and lease to us the new generating capacity included in Wisconsin Energy's Power the Future (PTF) strategy, which is described further in this report and in our 2012 Annual Report on Form 10-K. We have combined common functions with Wisconsin Gas and operate under the trade name of "We Energies."

Bostco is our non-utility subsidiary that develops and invests in real estate. As of March 31, 2013, Bostco had $29.7 million of assets.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC. We have condensed or omitted some information and note disclosures normally included in financial statements prepared in accordance with GAAP pursuant to these rules and regulations. This Form 10-Q, including the financial statements contained herein, should be read in conjunction with our 2012 Annual Report on Form 10-K, including the financial statements and notes therein.

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Form 10-Q

PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED CONDENSED INCOME STATEMENTS
(Unaudited)
	Three Months Ended March 31
	2013		2012
	(Millions of Dollars)
Operating Revenues	$	1,004.6	$	946.6
Operating Expenses
Fuel and purchased power	272.3		255.1
Cost of gas sold	112.8		100.2
Other operation and maintenance	350.3		329.6
Depreciation and amortization	68.4		61.2
Property and revenue taxes	27.7		28.2
Total Operating Expenses	831.5		774.3
Operating Income	173.1		172.3
Equity in Earnings of Transmission Affiliate	14.7		13.7
Other Income, net	4.1		15.9
Interest Expense, net	31.9		25.2
Income Before Income Taxes	160.0		176.7
Income Tax Expense	55.3		60.8
Net Income	104.7		115.9
Preferred Stock Dividend Requirement	0.3		0.3
Earnings Available for Common Stockholder	$	104.4	$	115.6
The accompanying Notes to Consolidated Condensed Financial Statements are an integral part of these financial statements.

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Form 10-Q

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited)
	March 31, 2013			December 31, 2012
	(Millions of Dollars)
Assets
Property, Plant and Equipment
In service	$	9,633.8		$	9,568.9
Accumulated depreciation	(3,159.9		)	(3,117.0		)
	6,473.9			6,451.9
Construction work in progress	312.5			289.1
Leased facilities, net	2,348.0			2,340.2
Net Property, Plant and Equipment	9,134.4			9,081.2
Investments
Equity investment in transmission affiliate	336.7			332.6
Other	0.3			0.3
Total Investments	337.0			332.9
Current Assets
Cash and cash equivalents	24.1			34.1
Restricted cash	—			2.7
Accounts receivable, net	281.6			226.3
Accounts receivable from related parties	16.4			6.1
Accrued revenues	192.6			213.8
Materials, supplies and inventories	258.5			312.2
Prepayments and other	234.7			198.8
Total Current Assets	1,007.9			994.0
Deferred Charges and Other Assets
Regulatory assets	1,470.7			1,452.2
Other	138.0			162.3
Total Deferred Charges and Other Assets	1,608.7			1,614.5
Total Assets	$	12,088.0		$	12,022.6
Capitalization and Liabilities
Capitalization
Common equity	$	3,418.7		$	3,366.4
Preferred stock	30.4			30.4
Long-term debt	2,217.2			2,216.7
Capital lease obligations	2,728.8			2,703.1
Total Capitalization	8,395.1			8,316.6
Current Liabilities
Long-term debt and capital lease obligations due currently	362.3			357.0
Short-term debt	82.0			105.5
Subsidiary note payable to Wisconsin Energy	23.1			23.4
Accounts payable	200.9			306.8
Accounts payable to related parties	84.7			93.4
Accrued payroll and benefits	64.9			75.4
Other	139.1			110.2
Total Current Liabilities	957.0			1,071.7
Deferred Credits and Other Liabilities
Regulatory liabilities	589.7			600.3
Deferred income taxes - long-term	1,647.4			1,533.6
Pension and other benefit obligations	294.3			189.2
Other	204.5			311.2
Total Deferred Credits and Other Liabilities	2,735.9			2,634.3
Total Capitalization and Liabilities	$	12,088.0		$	12,022.6
The accompanying Notes to Consolidated Condensed Financial Statements are an integral part of these financial statements.

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Form 10-Q

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended March 31
	2013			2012
	(Millions of Dollars)
Operating Activities
Net income	$	104.7		$	115.9
Reconciliation to cash
Depreciation and amortization	70.9			63.4
Deferred income taxes and investment tax credits, net	64.3			58.1
Change in - Accounts receivable and accrued revenues	(50.3		)	36.2
Inventories	53.7			29.9
Other current assets	26.1			29.9
Accounts payable	(107.8		)	(61.0		)
Accrued income taxes, net	(18.6		)	(6.8		)
Other current liabilities	24.8			5.9
Other, net	17.5			(41.3		)
Cash Provided by Operating Activities	185.3			230.2
Investing Activities
Capital expenditures	(108.7		)	(117.1		)
Investment in transmission affiliate	(1.2		)	(2.3		)
Change in restricted cash	2.7			20.8
Other, net	(10.8		)	(12.1		)
Cash Used in Investing Activities	(118.0		)	(110.7		)
Financing Activities
Dividends paid on common stock	(60.0		)	(44.9		)
Dividends paid on preferred stock	(0.3		)	(0.3		)
Change in total short-term debt	(23.8		)	(70.5		)
Other, net	6.8			—
Cash Used in Financing Activities	(77.3		)	(115.7		)
Change in Cash and Cash Equivalents	(10.0		)	3.8
Cash and Cash Equivalents at Beginning of Period	34.1			12.7
Cash and Cash Equivalents at End of Period	$	24.1		$	16.5
The accompanying Notes to Consolidated Condensed Financial Statements are an integral part of these financial statements.

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Form 10-Q

WISCONSIN ELECTRIC POWER COMPANY

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 2012 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 months ended March 31, 2013 are not necessarily indicative of the results which may be expected for the entire fiscal year 2013 because of seasonal and other factors.

2 -- NEW ACCOUNTING PRONOUNCEMENTS

Offsetting Assets and Liabilities: In December 2011, The Financial Accounting Standards Board issued Accounting Standards Update (ASU) 2011-11, Disclosures about Offsetting Assets and Liabilities. The guidance requires enhanced disclosures about derivatives. Both gross and net information related to eligible transactions is required under the guidance. This guidance is effective for fiscal years and interim periods beginning on or after January 1, 2013, and must be applied retrospectively. We adopted this guidance on January 1, 2013, and applied it retrospectively. See Note 5 -- Derivative Instruments for the enhanced disclosures.

3 -- COMMON EQUITY

Stock Option Activity:   During the first three months of 2013, the Compensation Committee of the Board of Directors of Wisconsin Energy (Compensation Committee) granted 1,365,970 Wisconsin Energy non-qualified stock options to our employees that had an estimated fair value of $3.45 per share. During the first three months of 2012, the Compensation Committee granted 903,865 Wisconsin Energy stock options to our employees that had an estimated fair value of $3.34 per share. The following assumptions were used to value the Wisconsin Energy options using a binomial option pricing model:

	2013		2012
Risk-free interest rate	0.1% - 1.9%		0.1% - 2.0%
Dividend yield	3.7	%	3.9	%
Expected volatility	18.0	%	19.0	%
Expected forfeiture rate	2.0	%	2.0	%
Expected life (years)	5.9		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 Wisconsin Energy's historical experience.

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Form 10-Q

The following is a summary of Wisconsin Energy stock option activity by our employees during the three months ended March 31, 2013:

					Weighted-
					Average
			Weighted-		Remaining	Aggregate
	Number of		Average		Contractual Life	Intrinsic Value
Stock Options	Options		Exercise Price		(Years)	(Millions)
Outstanding as of January 1, 2013	8,416,876		$	23.96
Granted	1,365,970		$	37.46
Exercised	(1,163,282	)	$	21.64
Forfeited	—		$	—
Outstanding as of March 31, 2013	8,619,564		$	26.42	5.9	$	142.0
Exercisable as of March 31, 2013	6,288,439		$	22.99	4.7	$	125.2

The intrinsic value of Wisconsin Energy options exercised by our employees was $22.0 million and $10.1 million for the three months ended March 31, 2013 and 2012, respectively. Cash received by Wisconsin Energy from exercises of its options by our employees was $25.2 million and $10.8 million for the three months ended March 31, 2013 and 2012, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was $8.8 million and zero, respectively.

The following table summarizes information about Wisconsin Energy stock options held by our employees and outstanding as of March 31, 2013:

	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)
$16.72  to  $21.11	2,546,319	$	20.14	4.3	2,546,319	$	20.14	4.3
$23.88  to  $29.35	3,803,410	$	24.65	5.0	3,503,330	$	24.25	4.7
$34.87  to  $37.46	2,269,835	$	36.43	9.4	238,790	$	34.91	8.8
	8,619,564	$	26.42	5.9	6,288,439	$	22.99	4.7

The following table summarizes information about our employees' non-vested Wisconsin Energy stock options during the three months ended March 31, 2013:

			Weighted-Average
Non-Vested Stock Options	Number of Options		Fair Value
Non-vested as of January 1, 2013	1,637,570		$	3.31
Granted	1,365,970		$	3.45
Vested	(672,415	)	$	3.33
Forfeited	—		$	—
Non-vested as of March 31, 2013	2,331,125		$	3.38

As of March 31, 2013, our total compensation costs related to non-vested Wisconsin Energy stock options held by our employees and not yet recognized was approximately $4.8 million, which is expected to be recognized over the next 22 months on a weighted-average basis.

Restricted Shares:   During the first three months of 2013, the Compensation Committee granted 53,055 Wisconsin Energy restricted shares to our officers and other key employees. These awards have a three-year vesting period, with one-third of the award vesting on each anniversary of the grant date. During the vesting period,

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restricted share recipients have voting rights and are entitled to dividends in the same manner as other shareholders.

The following restricted stock activity related to our employees occurred during the three months ended March 31, 2013:

			Weighted-Average
Restricted Shares	Number of Shares		Grant Date Fair Value
Outstanding as of January 1, 2013	126,392
Granted	53,055		$	37.71
Released	(59,820	)	$	28.63
Forfeited	(11,698	)	$	33.01
Outstanding as of March 31, 2013	107,929

Wisconsin Energy records the market value of the restricted stock awards on the date of grant and then we amortize our share of allocated expense over the vesting period of the awards. The intrinsic value of Wisconsin Energy restricted stock vesting and held by our employees was $2.4 million and $1.6 million for the three months ended March 31, 2013, and 2012, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same periods was $0.9 millionand zero for the three months ended March 31, 2013, and 2012, respectively.

As of March 31, 2013, total compensation cost related to our share of Wisconsin Energy restricted stock not yet recognized was approximately $3.3 million, which is expected to be recognized over the next 27 months on a weighted-average basis.

Performance Units:   In January 2013 and 2012, the Compensation Committee awarded 230,245 and 333,685 Wisconsin Energy performance units, respectively, to our officers and other key employees under the Wisconsin Energy Performance Unit Plan. Under the grants, the ultimate number of units which will be awarded is dependent upon the achievement of certain financial performance of Wisconsin Energy's common stock over a three-year period. Under the terms of the award, participants may earn between 0% and 175% of the base performance unit award. All grants are settled in cash. We are accruing our share of compensation costs over the three-year period based on our estimate of the final expected value of the award. Performance units earned as of December 31, 2012 and 2011 vested and were settled during the first quarter of 2013 and 2012, and had a total intrinsic value of $17.1 million and $26.1 million, respectively. The actual tax benefit realized for the tax deductions from the settlement of performance units was approximately $6.2 million and $9.6 million, respectively. As of March 31, 2013, total compensation cost related to our share of Wisconsin Energy performance units not yet recognized was approximately $19.1 million, which is expected to be recognized over the next 23 months on a weighted-average basis.

Restrictions:Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. In addition, under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy. See Note H -- Common Equity in our 2012 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.

4 -- 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,

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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 March 31, 2013
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	—	$	—	$	—	$	—
Derivatives	4.3		3.2		1.6		9.1
Total	$	4.3	$	3.2	$	1.6	$	9.1
Liabilities:
Derivatives	$	—	$	0.3	$	—	$	0.3
Total	$	—	$	0.3	$	—	$	0.3

Recurring Fair Value Measures	As of December 31, 2012
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	2.7	$	—	$	—	$	2.7
Derivatives	1.2		11.5		4.7		17.4
Total	$	3.9	$	11.5	$	4.7	$	20.1
Liabilities:
Derivatives	$	1.1	$	—	$	—	$	1.1
Total	$	1.1	$	—	$	—	$	1.1

We adopted ASU 2011-11, Disclosures about Offsetting Assets and Liabilities, on a retrospective basis. For additional information, see Note 2 -- New Accounting Pronouncements and Note 5 -- Derivative Instruments.

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Form 10-Q

Restricted cash consists of certificates of deposit and government backed interest bearing securities and represents the settlement we received from the United States Department of Energy (DOE) during the first quarter of 2011, which was returned, net of costs incurred, to customers. Derivatives reflect positions we hold in exchange-traded derivative contracts and OTC derivative contracts. Exchange-traded derivative contracts, which include futures and exchange-traded options, are generally based on unadjusted quoted prices in active markets and are classified within Level 1. Some OTC derivative contracts are valued using broker or dealer quotations, or market transactions in either the listed or OTC markets utilizing a mid-market pricing convention (the mid-point between bid and ask prices), as appropriate. In such cases, these derivatives are classified within Level 2. Certain OTC derivatives may utilize models to measure fair value. Generally, we use a similar model to value similar instruments. Valuation models utilize various inputs which include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs (i.e., inputs derived principally from or corroborated by observable market data by correlation or other means). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Certain OTC derivatives are in less active markets with a lower availability of pricing information which might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in Level 3.

The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy:

	2013			2012
	(Millions of Dollars)
Balance as of January 1	$	4.7		$	5.7
Realized and unrealized gains (losses)	—			—
Purchases	—			—
Issuances	—			—
Settlements	(3.1		)	(3.5		)
Transfers in and/or out of Level 3	—			—
Balance as of March 31	$	1.6		$	2.2
Change in unrealized gains (losses) relating to instruments still held as of March 31	$	—		$	—

Derivative instruments reflected in Level 3 of the hierarchy include MISO Financial Transmission Rights (FTRs) that are measured at fair value each reporting period using monthly or annual auction shadow prices from relevant auctions. Changes in fair value for Level 3 recurring items are recorded on our balance sheet. See Note 5 -- 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:

	March 31, 2013				December 31, 2012
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	27.6	$	30.4	$	26.0
Long-term debt, including current portion	$	2,537.0	$	2,866.6	$	2,537.0	$	2,900.8

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.

March 2013 15 Wisconsin Electric Power Company

Form 10-Q

5 -- 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. Our approach is non-speculative and designed to mitigate risk and protect against price volatility. Regulated hedging programs require prior approval by the Public Service Commission of Wisconsin (PSCW).

We record derivative instruments on the balance sheet as an asset or liability measured at its fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. As of March 31, 2013, we recognized $0.2 million in regulatory assets and $8.2 million in regulatory liabilities related to derivatives in comparison to $3.7 million in regulatory assets and $16.7 million in regulatory liabilities as of December 31, 2012.

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 $0.1 million is recorded in other deferred charges and other assets as of March 31, 2013, and the long-term portion of our derivative liabilities of $0.3 million is recorded in other deferred credits and other liabilities as of March 31, 2013. Our Consolidated Condensed Balance Sheets as of March 31, 2013 and December 31, 2012 include:

	March 31, 2013				December 31, 2012
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	3.9	$	—	$	1.2	$	1.1
Fuel Oil	0.5		—		0.4		—
FTRs	1.5		—		4.7		—
Coal	3.2		0.3		11.1		—
Total	$	9.1	$	0.3	$	17.4	$	1.1

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 March 31, 2013				Three Months Ended March 31, 2012
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)
Natural Gas	9.1 million Dth	$	(3.2	)	9.2 million Dth	$	(7.6	)
Fuel Oil	1.6 million gallons	0.1			1.7 million gallons	0.6
FTRs	5,343 MW	0.9			5,358 MW	0.6
Total		$	(2.2	)		$	(6.4	)

As of March 31, 2013 and December 31, 2012, we posted collateral of zero and $2.1 million, 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 March 31, 2013 and December 31, 2012.

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Form 10-Q

	March 31, 2013						December 31, 2012
	Derivative			Derivative			Derivative			Derivative
	Asset			Liability			Asset			Liability
	(Millions of Dollars)
Gross Amount Recognized on the Balance Sheet	$	11.9		$	0.3		$	19.2		$	1.9
Gross Amount Not Offset on Balance Sheet (a)	(0.1		)	(0.1		)	(0.5		)	(1.8		)
Net Amount	$	11.8		$	0.2		$	18.7		$	0.1

(a) Gross Amount Not Offset on Balance Sheet includes cash collateral posted of zero and $0.6 million as of March 31, 2013 and December 31, 2012, respectively.

6 -- BENEFITS

The components of our net periodic pension and Other Post-Retirement Employee Benefits (OPEB) costs for the three months ended March 31 were as follows:

	Pension Costs						OPEB Costs
	2013			2012			2013			2012
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	3.9		$	5.0		$	2.5		$	2.7
Interest cost	13.2			14.2			3.2			4.2
Expected return on plan assets	(19.3		)	(18.1		)	(3.6		)	(3.3		)
Amortization of:
Transition obligation	—			—			—			0.1
Prior service (credit)	0.5			0.5			(0.5		)	(0.5		)
Actuarial loss	10.4			7.3			0.4			1.2
Net Periodic Benefit Cost	$	8.7		$	8.9		$	2.0		$	4.4

During the first three months of 2013 and 2012, we made no contributions to our qualified benefit plans. Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates.

Postemployment Benefits:   Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $2.4 million as of March 31, 2013 and

December 31, 2012.

March 2013 17 Wisconsin Electric Power Company

Form 10-Q

7 -- SEGMENT INFORMATION

Summarized financial information concerning our reportable segments for the three months ended March 31, 2013 and 2012 is shown in the following table:

	Reportable Segments
	Electric		Gas		Steam		Total
	(Millions of Dollars)
Three Months Ended
March 31, 2013
Operating Revenues (a)	$	812.3	$	177.2	$	15.1	$	1,004.6
Operating Income	$	129.9	$	38.5	$	4.7	$	173.1
March 31, 2012
Operating Revenues (a)	$	777.3	$	156.7	$	12.6	$	946.6
Operating Income	$	143.6	$	26.7	$	2.0	$	172.3

(a) We account for all intersegment revenues at rates established by the PSCW. Intersegment revenues were not material.

8 -- 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 nine 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 $246.2 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 three months ended March 31, 2013 and 2012 were $12.5 million and $14.7 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contracts.

9 -- 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 our manufactured gas plant sites and related disposal sites, as well as our coal combustion product disposal/landfill sites, as discussed below. We

March 2013 18 Wisconsin Electric Power Company

Form 10-Q

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 we 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 $6 million to $18 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 March 31, 2013, we have established reserves of $7.2 million related to future remediation costs.

Historically, the PSCW has allowed Wisconsin utilities, including us, 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. (WPL) in connection with the sale of our interest in Edgewater Generating Unit 5.

10 -- SUPPLEMENTAL CASH FLOW INFORMATION

During the three months ended March 31, 2013, we paid $3.6 million in interest, net of amounts capitalized, and paid $2.0 million in income taxes, net of refunds. During the three months ended March 31, 2012, we paid $0.9 million in interest, capitalized $6.1 million of interest expense and paid $9.2 million in income taxes, net of refunds.

As of March 31, 2013 and 2012, the amount of accounts payable related to capital expenditures was $8.8 million and $12.5 million, respectively.

During the three months ended March 31, 2013 and 2012, our equity in earnings from ATC was $14.7 million and $13.7 million, respectively. During the three months ended March 31, 2013 and 2012, distributions received from ATC were $11.7 million and $11.3 million, respectively.

March 2013 19 Wisconsin Electric Power Company

Form 10-Q

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

                 AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS -- THREE MONTHS ENDED MARCH 31, 2013

Electric Utility Revenues and Sales

The following table compares electric utility operating revenues and MWh sales by customer class during the first quarter of 2013 with the first quarter of 2012, including favorable (better (B)) or unfavorable (worse (W)) variances:

	Electric Revenues							MWh Sales
Electric Utility Operations	2013		B (W)			2012		2013	B (W)		2012
	(Millions of Dollars)							(Thousands)
Customer Class
Residential	$	303.2	$	28.6		$	274.6	2,044.5	101.6		1,942.9
Small Commercial/Industrial	253.9		8.7			245.2		2,179.0	27.4		2,151.6
Large Commercial/Industrial	186.3		1.9			184.4		2,347.8	(96.5	)	2,444.3
Other - Retail	6.2		0.2			6.0		39.5	(0.9	)	40.4
Total Retail	749.6		39.4			710.2		6,610.8	31.6		6,579.2
Wholesale - Other	39.5		2.8			36.7		517.0	184.3		332.7
Resale - Utilities	17.3		0.3			17.0		559.9	(37.2	)	597.1
Other Operating Revenues	5.9		(7.5		)	13.4		—	—		—
Total	$	812.3	$	35.0		$	777.3	7,687.7	178.7		7,509.0
Weather -- Degree Days (a)
Heating (3,252 Normal)								3,471	861		2,610
(a) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year
moving average.

Our electric utility operating revenues increased by $35.0 million, or 4.5%, when compared to the first quarter of 2012. The most significant factors that caused a change in revenues were:

• Net retail pricing increases of $28.6 million ($43.8 million less $15.2 million related to Section 1603 bill credits), which is primarily related to our 2013 Wisconsin Rate Case. For information on the Section 1603 bill credits and the rate order in the 2013 rate case, see Results of Operations -- March 31, 2013 -- Section 1603 Renewable Energy Treasury Grant and Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters, respectively.

• Favorable weather that increased electric revenues by an estimated $21.5 million as compared to the first quarter of 2012.

• A $7.5 million decrease in other operating revenues, primarily driven by the amortization of $6.7 million in 2012 related to the settlement with the DOE. See Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters -- 2012 Fuel Recovery Request.

As measured by heating degree days, the first quarter of 2013 was 33.0% colder than the same period in 2012 and 6.7% colder than normal. We believe the colder winter weather was the primary reason for the 5.2% increase in residential sales. Sales to large commercial/industrial customers decreased by 3.9%, primarily because of the leap year in 2012 and a decrease in sales to the two iron ore mines in Michigan. Wholesale - Other sales increased by 55.4%; however, our related revenues increased by only $2.8 million, or 7.6%, due to a large increase in off-peak sales which are at significantly lower prices than on-peak sales.

Fuel and Purchased Power

Our fuel and purchased power costs increased by $17.2 million, or 6.7%, when compared to the first quarter of 2012. This increase was primarily caused by a 2.4% increase in total MWh sales and higher generating costs driven by an increase in natural gas prices as compared to the first quarter of 2012.

March 2013 20 Wisconsin Electric Power Company

Form 10-Q

Gas Utility Revenues, Gross Margin and Therm Deliveries

A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the first quarter of 2013 with the first quarter of 2012. 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 $20.5 million, or 13.1%, and cost of gas sold increased by $12.6 million, or 12.6%, due to the colder winter weather.

	Three Months Ended March 31
	2013		B (W)			2012
	(Millions of Dollars)
Gas Operating Revenues	$	177.2	$	20.5		$	156.7
Cost of Gas Sold	112.8		(12.6		)	100.2
Gross Margin	$	64.4	$	7.9		$	56.5

The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the first quarter of 2013 with the first quarter of 2012:

	Gross Margin						Therm Deliveries
Gas Utility Operations	2013		B (W)		2012		2013	B (W)	2012
	(Millions of Dollars)						(Millions)
Customer Class
Residential	$	43.7	$	5.5	$	38.2	174.3	44.5	129.8
Commercial/Industrial	15.3		2.0		13.3		92.8	19.8	73.0
Interruptible	0.2		0.1		0.1		2.2	0.5	1.7
Total Retail	59.2		7.6		51.6		269.3	64.8	204.5
Transported Gas	4.7		0.3		4.4		92.8	5.2	87.6
Other	0.5		—		0.5		—	—	—
Total	$	64.4	$	7.9	$	56.5	362.1	70.0	292.1
Weather -- Degree Days (a)
Heating (3,252 Normal)							3,471	861	2,610
(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 $7.9 million, or approximately 14.0%, when compared to the first quarter of 2012. We estimate that weather increased gas margins by approximately $13.0 million. As measured by heating degree days, the first quarter of 2013 was 33.0% colder than the same period in 2012 and 6.7% colder than normal. The first quarter of 2012 was significantly warmer than normal. Gas margins were reduced by approximately $4.6 million because of lower gas rates that became effective January 1, 2013. For information on this rate order, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters.

Other Operation and Maintenance Expense

Our other operation and maintenance expense increased by $20.7 million, or approximately 6.3%, when compared to the first quarter of 2012. This increase was primarily driven by the reinstatement of $37.5 million of regulatory amortizations, offset in part by continued cost control efforts across the utility and some timing impacts associated with the variation in weather between quarters.

Depreciation and Amortization Expense

Our depreciation and amortization expense increased by $7.2 million, or approximately 11.8%, when compared to the first quarter of 2012, primarily because of an overall increase in utility plant in service. The emission control equipment for units 5 and 6 of the Oak Creek Air Quality Control System (AQCS) project went into service in March

March 2013 21 Wisconsin Electric Power Company

Form 10-Q

2012, and for units 7 and 8 in September 2012. For additional information, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters -- Oak Creek Air Quality Control System.

Section 1603 Renewable Energy Treasury Grant

We expect to receive a treasury grant of approximately $72 million related to the construction of our biomass facility in Rothschild, Wisconsin. The PSCW took this grant into consideration when it set rates for our electric customers for the two years ending December 31, 2014. These rates became effective on January 1, 2013 and are reflected in the form of bill credits that reduce our revenues. We expect to recognize the treasury grant as income in the fourth quarter of 2013 when the plant is expected to be placed into service. At that time, we will also defer as a regulatory liability, the portion of the grant income that will be used to reduce rates in 2014. For the first three quarters of 2013, we will experience a mismatch between bill credits (lower revenues) and grant income. However, when the plant is placed into service in the fourth quarter, we will make an entry to record grant income to match the bill credits that have been provided to customers during 2013.

In addition, the PSCW approved escrow accounting treatment for the treasury grant. As a result, we expect to true-up any difference between the actual grant proceeds we receive and the estimated grant proceeds the PSCW used to set electric retail rates for 2013 and 2014.

Other Income, net

	Three Months Ended March 31
Other Income, net	2013			B (W)			2012
	(Millions of Dollars)
AFUDC - Equity	$	4.2		$	(10.5	)	$	14.7
Other	(0.1		)	(1.3		)	1.2
Other Income, net	$	4.1		$	(11.8	)	$	15.9

Other income, net decreased by $11.8 million, or approximately 74.2%, when compared to the first quarter of 2012. The decrease in AFUDC - Equity is primarily related to the Oak Creek AQCS project which emission control equipment went into service in March 2012 for units 5 and 6 and September 2012 for units 7 and 8.

Interest Expense, net

	Three Months Ended March 31
Interest Expense	2013		B (W)			2012
	(Millions of Dollars)
Gross Interest Costs	$	33.6	$	(2.3	)	$	31.3
Less: Capitalized Interest	1.7		(4.4		)	6.1
Interest Expense, net	$	31.9	$	(6.7	)	$	25.2

Our gross interest costs increased by $2.3 million, or approximately 7.3%, when compared to the first quarter of 2012 primarily because we issued $250 million of long-term debt in December 2012. Our capitalized interest decreased by $4.4 million primarily because of lower construction work in progress. As a result, our net interest expense increased by $6.7 million, or 26.6%, as compared to the first quarter of 2012.

Income Tax Expense

For the first quarter of 2013, our effective tax rate was 34.6% compared to 34.4% for the first quarter of 2012. For additional information, see Note G -- Income Taxes in our 2012 Annual Report on Form 10-K. We expect our 2013 annual effective tax rate to be between 36% and 37%.

March 2013 22 Wisconsin Electric Power Company

Form 10-Q

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

The following summarizes our cash flows during the three months ended March 31:

	2013			2012
	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$	185.3		$	230.2
Investing Activities	$	(118.0	)	$	(110.7	)
Financing Activities	$	(77.3	)	$	(115.7	)

Operating Activities

Cash provided by operating activities decreased by $44.9 million during the first three months of 2013 as compared to the same period in 2012. The decrease is primarily because of higher working capital requirements. We experienced significantly colder weather when compared to the same period in 2012, resulting in higher accounts receivable and accrued revenues. Partially offsetting this decrease is higher depreciation expense and the end of the one year suspension of amortization expense authorized by the 2012 Wisconsin Rate Case.

Investing Activities

Cash used in investing activities increased by $7.3 million during the first three months of 2013 as compared to the same period in 2012. Our change in restricted cash decreased by $18.1 million which is related to the 2012 release of restricted cash through bill credits and reimbursements of costs associated with the DOE settlement. Our capital expenditures decreased by $8.4 million during the first three months of 2013 as compared to the same period in 2012, primarily because of the completion of the Oak Creek AQCS project, partially offset by the increased spending at the biomass plant.

Financing Activities

Cash used in financing activities decreased by $38.4 million during the first three months of 2013 as compared to the same period in 2012. Repayment of short-term debt was $46.7 million lower in 2013 as compared to the same period in 2012, primarily because of lower cash flows from operations and higher cash flows used in investing. This factor was partially offset by the payment of a $60 million dividend to Wisconsin Energy during the first three months of 2013 as compared to $44.9 million during the same period in 2012.

CAPITAL RESOURCES AND REQUIREMENTS

Liquidity

We anticipate meeting our capital requirements during the remainder of 2013 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, and equity contributions from our parent.

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 arrangement, access to capital markets and internally generated cash.

We maintain a bank back-up credit facility that provides liquidity support for our obligations with respect to commercial paper and for general corporate purposes.

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Form 10-Q

As of March 31, 2013, we had approximately $493.9 million of available, undrawn lines under our bank back-up credit facility, and approximately $82.0 million of commercial paper outstanding that was supported by the available lines of credit. During the first three months of 2013, our maximum commercial paper outstanding was $139.0 million with a weighted-average interest rate of 0.26%.

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 facility as of March 31, 2013:

Total Facility		Letters of Credit		Credit Available		Facility Expiration
(Millions of Dollars)
$	500.0	$	6.1	$	493.9	December 2017

We are the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amounts of $147 million. In August 2009, we terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We issued commercial paper to fund the purchase of the bonds. As of March 31, 2013, the repurchased bonds were still outstanding, but were reported as a reduction in our consolidated long-term debt because they are held by us. Depending on market conditions and other factors, we may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.

Bonus Depreciation Provisions

The American Taxpayer Relief Act of 2012 was signed into law on January 2, 2013, which extended the 50% bonus depreciation rules to include assets placed in service in 2013. These rules will apply to the biomass plant we are constructing in Rothschild, which is expected to be completed during the fourth quarter of 2013. As a result of the increased federal tax depreciation for 2013 and prior years, we do not anticipate making federal income tax payments for 2013.

Credit Rating Risk

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

Subject to other factors affecting the credit markets as a whole, we believe our current ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, security ratings reflect the views of the rating agencies only. An explanation of the significance of the ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell or hold securities. Any rating can be revised upward or 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 2012 Annual Report on Form 10-K for additional information related to our credit rating risk.

Capital Requirements

Capital Expenditures: Capital requirements during the remainder of 2013 are expected to be principally for capital expenditures relating to our electric and gas distribution systems and our biomass facility. We estimate that we will spend approximately $520 million on capital expenditures during 2013.

Off-Balance Sheet Arrangements:   We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support construction projects, commodity contracts and other payment obligations. We continue to believe that these agreements do not have, and are not reasonably likely to have, a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors. For further information, see Note 8 -- Variable Interest Entities in the Notes to Consolidated Condensed Financial Statements in this report.

March 2013 24 Wisconsin Electric Power Company

Form 10-Q

Contractual Obligations/Commercial Commitments:   Our total contractual obligations and other commercial commitments were approximately $27.9 billion as of March 31, 2013 and December 31, 2012.

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 2012 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, Wisconsin Energy's PTF strategy, rates and regulatory matters, electric system reliability, environmental matters, legal matters, industry restructuring and competition and other matters.

POWER THE FUTURE

All of the PTF units are in service and are positioned to provide a significant portion of our future generation needs. We are leasing the units from We Power under long-term leases. We are recovering the lease payments associated with Port Washington Generating Station Unit 1, Port Washington Generating Station Unit 2, Oak Creek expansion Unit 1, and Oak Creek expansion Unit 2 in our rates as authorized by the PSCW, the Michigan Public Service Commission (MPSC) and FERC.

As part of our 2013 Wisconsin Rate Case, the PSCW determined that 100% of the construction costs for the Oak Creek expansion units were prudently incurred by We Power, and approved the recovery in rates of more than 99.5% of these costs. In addition, the PSCW deferred the final decision regarding $24 million related to the Oak Creek expansion fuel flexibility project until a future rate proceeding. See Other Matters below for additional information about the fuel flexibility project.

See Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Item 7 of our 2012 Annual Report on Form 10-K for additional information on PTF.

RATES AND REGULATORY MATTERS

2013 Wisconsin Rate Case:On March 23, 2012, we initiated rate proceedings with the PSCW. On December 20, 2012, the PSCW approved the following rate adjustments:

• A net bill increase related to non-fuel costs for our Wisconsin retail electric customers of approximately $70 million (2.6%) for 2013. This amount reflects an offset of approximately $63 million (2.3%) related to the proceeds of a renewable energy cash grant we expect to receive under the NDAA upon completion of our biomass facility currently under construction. Absent this offset, the retail electric rate increase for non-fuel costs is approximately $133 million (4.8%) for 2013.

• Absent an adjustment for any remaining energy cash credits, an electric rate increase for our Wisconsin electric customers of approximately $28 million (1.0%) for 2014.

• Recovery of a forecasted increase in fuel costs of approximately $44 million (1.6%) for 2013. We will make an annual fuel cost filing, as required, for 2014.

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

• An increase of approximately $1.3 million (6.0%) for our Downtown Milwaukee (Valley) 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 our Milwaukee County steam utility customers.

These rate adjustments were effective January 1, 2013. In addition, the PSCW indicated that our allowed return on equity would remain at 10.4%. The PSCW also approved escrow accounting treatment for the energy cash grant.

2012 Fuel Recovery Request:In August 2011, we filed a $50 million rate increase request with the PSCW to recover forecasted increases in fuel and purchased power costs. The primary reasons for the increase were projected higher coal, coal transportation and purchased power costs. This filing was made under the new

March 2013 25 Wisconsin Electric Power Company

Form 10-Q

Wisconsin fuel rules which require annual fuel cost filings. In January 2012, the PSCW issued an order which provided for an increase in fuel costs of approximately $26 million, offset by approximately $26 million from the settlement with the DOE regarding the storage of spent nuclear fuel, resulting in no change in customer bills.

Renewable Energy Portfolio:   We are constructing a biomass-fueled power plant at Domtar Corporation's Rothschild, Wisconsin paper mill site. Wood waste and wood shavings will be used to produce approximately 50MW of renewable electricity and will also support Domtar's sustainable papermaking operations. Construction commenced in June 2011. We currently expect to invest between $245million and $255million, excluding AFUDC, in the plant. We are targeting completion of the facility by the end of 2013.

Oak Creek Air Quality Control System:   In July 2008, we received approval from the PSCW granting Wisconsin Electric authority to construct wet flue gas desulfurization and selective catalytic reduction facilities at Oak Creek Power Plant units 5-8. Construction of these emission controls began in late July 2008. In March 2012, the wet flue gas desulfurization and selective catalytic reduction equipment for units 5 and 6 was placed into commercial operation. In September 2012, the equipment for units 7 and 8 was placed into commercial operation. The final cost of completing this project was approximately $740 million ($900 million including AFUDC). The cost of constructing these facilities has been included in our previous estimates of the costs to implement the Consent Decree we entered into with the United States Environmental Protection Agency (EPA) in 2003.

See Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters in Item 7 of our 2012 Annual Report on Form 10-K for additional information regarding our rates and other regulatory matters.

ENVIRONMENTAL MATTERS

Air Quality

Sulfur Dioxide Standard:In June 2010, the EPA issued a new hourly Sulfur Dioxide (SO₂) National Ambient Air Quality Standard that became effective in August 2010. This standard, as modified, represented a significant change from the previous SO₂ standard. The implementation guidance for the new standard, among other things, required attainment designations to be based on modeling rather than monitoring. Traditionally, attainment designations were based on monitored data. The EPA has since withdrawn this implementation guidance, and has indicated it is going to propose new implementation guidance through a rulemaking in 2013.

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

If the new standard remains in place, we believe that we would not need to make significant capital expenditures at the majority of our generation units because of prior investments in pollution control equipment and technology. However, we believe that the new standard will require us to retrofit Presque Isle Power Plant (PIPP) in the Upper Peninsula of Michigan with additional environmental controls. In November 2012, we entered into a joint ownership agreement with Wolverine Power Supply Cooperative, Inc. whereby Wolverine will pay for the installation of air quality control systems at PIPP and will receive a minority ownership interest in the plant in return. This transaction is subject to the receipt of regulatory approvals from various state and federal regulatory agencies. We began submitting applications for regulatory approvals in February 2013, and received FERC and MPSC approval in April 2013. We expect to receive approval from the PSCW no later than the third quarter of 2013.

The new standard may also require us to make modifications at some of our smaller generation units.

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 and SO₂ that contribute to fine particulate matter and ozone non-attainment in downwind states through a proposed allocation scheme. Even with technical revisions to the rule by the EPA, PIPP may not have been allocated sufficient allowances to meet its obligations to operate and provide stability to the transmission system in the Upper Peninsula of Michigan. This situation could then put the plant at risk for certain penalties under the rule.

March 2013 26 Wisconsin Electric Power Company

Form 10-Q

The rule was scheduled to become effective January 1, 2012. However, we and a number of other parties sought judicial review of the rule, and in August 2012, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CSAPR, keeping the CAIR in effect. The EPA had requested the court to re-hear the case; however, in January 2013, the court denied the EPA's request. The EPA petitioned the United States Supreme Court to review the D.C. Circuit Court's decision.

Valley Power Plant Conversion:In August 2012, we announced plans to convert the fuel source for Valley Power Plant (VAPP) from coal to natural gas. We currently expect the cost of this conversion to be between $65 million and $70 million excluding AFUDC, and, subject to receipt of PSCW approval and a construction air permit from the WDNR, anticipate that the conversion will be completed by the end of 2015 or early 2016. We filed for a Certificate of Authority from the PSCW on April 26, 2013.

In June 2012, we received approval from the PSCW to replace and upgrade the Lincoln Arthur natural gas main, which has the capability to accommodate the increased natural gas required for the conversion of VAPP to natural gas. Construction began on the Lincoln Arthur natural gas main in March 2013.

Water Quality

Steam Electric Effluent Guidelines:These guidelines regulate waste water discharges from our power plant processes. On April 19, 2013, the EPA released a proposed rule to modify these guidelines. The rule compliance deadline is as soon as possible after July 1, 2017 with full compliance expected by July 1, 2022. After the promulgation of final rules, it is expected that the WDNR will need to modify Wisconsin's rules. We already meet many of the proposed requirements defined by EPA, and as a result believe we will be well positioned to comply with the proposed guidelines. There are several available options outlined in the proposed rule. The amount of additional costs we may need to incur to comply with the new guidelines, if any, will depend on which option(s) the EPA selects to incorporate into the final guidelines. We are still evaluating the proposed rule, and are currently unable to determine its impact on our facilities.

See Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7 of our 2012 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. We are scheduled to begin testing sub-bituminous coal in various combinations with bituminous coal in 2013 to identify any equipment limitations that should be considered prior to filing with the PSCW for a Certificate of Authority to make the fuel flexibility modifications. 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 Generation 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 us a Notice of Violation (NOV) on January 7, 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) until 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 that Units 1 and 4 will remain out of service until at least 2014. In addition, we may be subject to fines and penalties. In February 2013, the Sierra Club filed for a contested case hearing with the WDNR in connection with the administrative order.

March 2013 27 Wisconsin Electric Power Company

Form 10-Q

We continue to evaluate the impact, if any, that this outage may have on network reliability, and to determine whether we will need to find alternative sources of generation in the short-term to replace the generation from these units during the temporary outage.

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.

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, 2012. For information concerning market risk exposures at Wisconsin Electric Power Company, 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 2012 Annual Report on Form 10-K, as well as Note 4 -- Fair Value Measurements and Note 5 -- 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 2012 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.

Edgewater Generating Unit 5:In December2009, the EPA issued a NOV concerning several coal-fired power plants owned and operated by WPL, including Edgewater Generating Unit 5, of which we owned 25%. Due to our

March 2013 28 Wisconsin Electric Power Company

Form 10-Q

ownership interest at the time, we were named in the NOV. In March 2011, we sold our interest to WPL. Although we sold our interest, we retained our share of liability, if any, related to the NOV. The NOV alleged that certain maintenance projects at WPL's units, including Edgewater 5, were undertaken without obtaining air permits required by the Clean Air Act.

In September2010, the Sierra Club filed a complaint against WPL generally alleging air permitting and opacity violations at the Edgewater Generating Station. We were not a named party to this litigation.

On April 22, 2013, a complaintand consent decree were simultaneously lodged with the court in United States v Wisconsin Power and Light Company, Madison Gas and Electric Company, Wisconsin Electric Power Company and Wisconsin Public Service Corporation, Case No. 13-cv-00266.The consent decree, when entered by the court, will resolve all allegations in the NOV related to Edgewater 5 and the other coal fired power plants owned and operated by WPL, as well as the air permitting and opacity violations alleged by Sierra Club. Our share of the financial obligation associated with this consent decree is immaterial.

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 -- Rates and Regulatory Matters in Part I of this report for information concerning rate matters in the jurisdictions where we do business.

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors presented in our Annual Report on Form 10-K for the year ended December 31, 2012. See Item 1A. Risk Factors in our 2012 Annual Report on Form 10-K for a discussion of certain risk factors applicable to us.

ITEM 5. OTHER INFORMATION

Director Robert A. Cornog did not stand for re-election at either the 2013 Annual Meeting of Stockholders of Wisconsin Electric held on April 25, 2013 or the 2013 Annual Meeting of Stockholders of Wisconsin Energy held on May 2, 2013, at which time his term expired. Director Cornog has served on the Wisconsin Electric Board of Directors since 1994, the Wisconsin Energy Board of Directors since 1993 and the Wisconsin Gas Board of Directors since 2000. In consideration of his exemplary service and contributions to these Boards of Directors, on April 30, 2013, the Compensation Committee accelerated the vesting of all unvested shares of restricted stock of Wisconsin Energy awarded to Director Cornog, consisting of approximately 7,293 shares, effective May 2, 2013.

March 2013 29 Wisconsin Electric Power Company

Form 10-Q

ITEM 6. EXHIBITS

Exhibit No.
12	Statements re Computation of Ratios
12.1	Statement of Computation of Ratio of Earnings to Fixed Charges.
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

March 2013 30 Wisconsin Electric Power Company

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 ELECTRIC POWER COMPANY
		(Registrant)
		/s/STEPHEN P. DICKSON
Date:	May 2, 2013	Stephen P. Dickson, Vice President and Controller, Principal Accounting Officer and duly authorized officer

March 2013 31 Wisconsin Electric Power Company

EX-12.1

EXHIBIT 12.1

WISCONSIN ELECTRIC POWER COMPANY

STATEMENT OF COMPUTATION OF

RATIO OF EARNINGS TO FIXED CHARGES

(Unaudited)

	Three
	Months
	Ended			Twelve Months Ended
	3/31/2013			3/31/2013			12/31/2012			12/31/2011			12/31/2010			12/31/2009			12/31/2008
	(Millions of Dollars)
Pre-tax Income	$	157.0		$	531.2		$	548.5		$	485.2		$	470.8		$	435.3		$	439.4
Subtract:
Capitalized Interest	(1.7		)	(10.1		)	(14.5		)	(24.7		)	(13.5		)	(6.6		)	(3.0		)
Earnings Before Adding Fixed Charges (a)	155.3			521.1			534.0			460.5			457.3			428.7			436.4
Fixed Charges
Interest Expense	33.6			130.0			127.7			118.9			115.0			106.9			89.6
Estimated Interest Component of Rentals	35.3			141.2			141.1			141.3			107.1			65.6			57.6
Total Fixed Charges as Defined (b)	68.9			271.2			268.8			260.2			222.1			172.5			147.2
Total Earnings as Defined	$	224.2		$	792.3		$	802.8		$	720.7		$	679.4		$	601.2		$	583.6
Ratio of Earnings to Fixed Charges	3.3x			2.9x			3.0x			2.8x			3.1x			3.5x			4.0x
(a) Earnings before adding fixed charges is determined by starting with pre-tax income (less undistributed equity in earnings of unconsolidated affiliates)
and subtracting capitalized interest.
(b) Fixed Charges consist of interest charges on our long-term debt and short-term borrowings (including a representative portion of lease expense),
capitalized interest and amortization of debt expense.

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 Electric Power Company;

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: May 2, 2013

/s/GALE E. KLAPPA

Gale E. Klappa

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

EX-31.2

Exhibit 31.2

Certification Pursuant to

Rule 13a-14(a) or 15d-14(a),

as Adopted Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

I, J. Patrick Keyes, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Wisconsin Electric Power Company;

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: May 2, 2013

/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 Electric Power Company (the "Company") on Form 10-Q for the period ended March 31, 2013, as filed with the Securities and Exchange Commission on May 2, 2013 (the "Report"), I, Gale E. Klappa, Chairman, President and Chief Executive Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/GALE E. KLAPPA

Gale E. Klappa

Chairman, President and Chief Executive Officer

May 2, 2013

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 Electric Power Company (the "Company") on Form 10-Q for the period ended March 31, 2013, as filed with the Securities and Exchange Commission on May 2, 2013 (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

May 2, 2013

XML

Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
Benefits (Textuals) [Abstract]
Pension and Other Postretirement Benefit Contributions	$ 0	$ 0
Estimated liability of Postemployment benefits	2.4		2.4
Pension Plans, Defined Benefit [Member]
Net Periodic Benefit Cost
Service cost	3.9	5.0
Interest cost	13.2	14.2
Expected return on plan assets	(19.3)	(18.1)
Amortization of:
Prior service cost (credit)	0.5	0.5
Actuarial loss	10.4	7.3
Net Periodic Benefit Cost	8.7	8.9
Other Postretirement Benefit Plans, Defined Benefit [Member]
Net Periodic Benefit Cost
Service cost	2.5	2.7
Interest cost	3.2	4.2
Expected return on plan assets	(3.6)	(3.3)
Amortization of:
Transition obligation	0	0.1
Prior service cost (credit)	(0.5)	(0.5)
Actuarial loss	0.4	1.2
Net Periodic Benefit Cost	$ 2.0	$ 4.4

XML

Common Equity 5 (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
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%
Tax Benefit from Stock Options Exercised	$ 8.8	$ 0
Minimum percentage award based on performance unit	0.00
Maximum percentage award based on performance unit	1.75
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	2.4	1.6
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	126,392
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	53,055
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(59,820)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(11,698)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	107,929
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 37.71
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 28.63
Share Based Compensation Arrangement By Share Based Payment Awards Equity Instruments Other Than Options Forfeited In Period Weighted Average Grant Date Fair Value	$ 33.01
Tax Benefit from Stock Options Exercised	0.9	0
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	3.3
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	27 months
Performance units [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	17.1	26.1
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	230,245	333,685
Tax Benefit from Stock Options Exercised	6.2	9.6
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 19.1
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	23 months

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Supplemental Cash Flow Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Supplemental Cash Flow Information (Textuals)
Interest paid, net of amounts capitalized	$ 3.6
Income taxes paid, net of refunds	2.0	9.2
Interest Paid		0.9
Interest Costs Capitalized		6.1
Accounts payable related to capital expenditures	8.8	12.5
Income (Loss) from Equity Method Investments	14.7	13.7
Distributions from transmission affiliate	$ 11.7	$ 11.3

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Derivative Instruments

3 Months Ended

Mar. 31, 2013

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. Our approach is non-speculative and designed to mitigate risk and protect against price volatility. Regulated hedging programs require prior approval by the Public Service Commission of Wisconsin (PSCW).

We record derivative instruments on the balance sheet as an asset or liability measured at its fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. As of March 31, 2013, we recognized $0.2 million in regulatory assets and $8.2 million in regulatory liabilities related to derivatives in comparison to $3.7 million in regulatory assets and $16.7 million in regulatory liabilities as of December 31, 2012.

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 $0.1 million is recorded in other deferred charges and other assets as of March 31, 2013, and the long-term portion of our derivative liabilities of $0.3 million is recorded in other deferred credits and other liabilities as of March 31, 2013. Our Consolidated Condensed Balance Sheets as of March 31, 2013 and December 31, 2012 include:

	March 31, 2013				December 31, 2012
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	3.9	$	—	$	1.2	$	1.1
Fuel Oil	0.5		—		0.4		—
FTRs	1.5		—		4.7		—
Coal	3.2		0.3		11.1		—
Total	$	9.1	$	0.3	$	17.4	$	1.1

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 March 31, 2013				Three Months Ended March 31, 2012
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)
Natural Gas	9.1 million Dth	$	(3.2	)	9.2 million Dth	$	(7.6	)
Fuel Oil	1.6 million gallons	0.1			1.7 million gallons	0.6
FTRs	5,343 MW	0.9			5,358 MW	0.6
Total		$	(2.2	)		$	(6.4	)

As of March 31, 2013 and December 31, 2012, we posted collateral of zero and $2.1 million, 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 March 31, 2013 and December 31, 2012.

	March 31, 2013						December 31, 2012
	Derivative			Derivative			Derivative			Derivative
	Asset			Liability			Asset			Liability
	(Millions of Dollars)
Gross Amount Recognized on the Balance Sheet	$	11.9		$	0.3		$	19.2		$	1.9
Gross Amount Not Offset on Balance Sheet (a)	(0.1		)	(0.1		)	(0.5		)	(1.8		)
Net Amount	$	11.8		$	0.2		$	18.7		$	0.1

(a) Gross Amount Not Offset on Balance Sheet includes cash collateral posted of zero and $0.6 million as of March 31, 2013 and December 31, 2012, respectively.

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Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Derivative asset	$ 9.1		$ 17.4
Derivative liability	0.3		1.1
Gains (losses)	(2.2)	(6.4)
Derivative Instruments (Textuals)
Collateral in margin accounts	0		2.1
Other Deferred Charges and Other Assets [Member]
Derivatives, Fair Value [Line Items]
Long-term portion of derivative assets	0.1
Other Deferred Credits and Other Liabilities [Member]
Derivatives, Fair Value [Line Items]
Long-term portion of derivative liabilities	0.3
Natural Gas [Member]
Derivatives, Fair Value [Line Items]
Derivative asset	3.9		1.2
Derivative liability	0		1.1
Volume of derivative instruments	9.1 million Dth	9.2 million Dth
Gains (losses)	(3.2)	(7.6)
Fuel Oil [Member]
Derivatives, Fair Value [Line Items]
Derivative asset	0.5		0.4
Derivative liability	0		0
Volume of derivative instruments	1.6 million gallons	1.7 million gallons
Gains (losses)	0.1	0.6
Ftrs [Member]
Derivatives, Fair Value [Line Items]
Derivative asset	1.5		4.7
Derivative liability	0		0
Volume of derivative instruments	5,343 MW	5,358 MW
Gains (losses)	0.9	0.6
Coal [Member]
Derivatives, Fair Value [Line Items]
Derivative asset	3.2		11.1
Derivative liability	$ 0.3		$ 0

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Fair Value Measurements, Financial Instruments (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Financial Instruments
Preferred stock	$ 30.4	$ 30.4
Carrying (Reported) Amount, Fair Value Disclosure [Member]
Financial Instruments
Preferred stock	30.4	30.4
Long-term debt including current portion	2,537.0	2,537.0
Estimate of Fair Value, Fair Value Disclosure [Member]
Financial Instruments
Preferred stock	27.6	26.0
Long-term debt including current portion	$ 2,866.6	$ 2,900.8

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Derivative Instruments (Details 1) (Derivative [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Derivative [Member]
Regulatory Assets [Line Items]
Regulatory assets related to derivatives	$ 0.2	$ 3.7

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Derivative Instruments (Details 2) (Derivative [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Derivative [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities related to derivatives	$ 8.2	$ 16.7

XML

Fair Value Measurements

3 Months Ended

Mar. 31, 2013

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 March 31, 2013
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	—	$	—	$	—	$	—
Derivatives	4.3		3.2		1.6		9.1
Total	$	4.3	$	3.2	$	1.6	$	9.1
Liabilities:
Derivatives	$	—	$	0.3	$	—	$	0.3
Total	$	—	$	0.3	$	—	$	0.3

Recurring Fair Value Measures	As of December 31, 2012
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	2.7	$	—	$	—	$	2.7
Derivatives	1.2		11.5		4.7		17.4
Total	$	3.9	$	11.5	$	4.7	$	20.1
Liabilities:
Derivatives	$	1.1	$	—	$	—	$	1.1
Total	$	1.1	$	—	$	—	$	1.1

We adopted ASU 2011-11, Disclosures about Offsetting Assets and Liabilities, on a retrospective basis. For additional information, see Note 2 -- New Accounting Pronouncements and Note 5 -- Derivative Instruments.

Restricted cash consists of certificates of deposit and government backed interest bearing securities and represents the settlement we received from the United States Department of Energy (DOE) during the first quarter of 2011, which was returned, net of costs incurred, to customers. Derivatives reflect positions we hold in exchange-traded derivative contracts and OTC derivative contracts. Exchange-traded derivative contracts, which include futures and exchange-traded options, are generally based on unadjusted quoted prices in active markets and are classified within Level 1. Some OTC derivative contracts are valued using broker or dealer quotations, or market transactions in either the listed or OTC markets utilizing a mid-market pricing convention (the mid-point between bid and ask prices), as appropriate. In such cases, these derivatives are classified within Level 2. Certain OTC derivatives may utilize models to measure fair value. Generally, we use a similar model to value similar instruments. Valuation models utilize various inputs which include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs (i.e., inputs derived principally from or corroborated by observable market data by correlation or other means). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Certain OTC derivatives are in less active markets with a lower availability of pricing information which might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in Level 3.

The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy:

	2013			2012
	(Millions of Dollars)
Balance as of January 1	$	4.7		$	5.7
Realized and unrealized gains (losses)	—			—
Purchases	—			—
Issuances	—			—
Settlements	(3.1		)	(3.5		)
Transfers in and/or out of Level 3	—			—
Balance as of March 31	$	1.6		$	2.2
Change in unrealized gains (losses) relating to instruments still held as of March 31	$	—		$	—

Derivative instruments reflected in Level 3 of the hierarchy include MISO Financial Transmission Rights (FTRs) that are measured at fair value each reporting period using monthly or annual auction shadow prices from relevant auctions. Changes in fair value for Level 3 recurring items are recorded on our balance sheet. See Note 5 -- 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:

	March 31, 2013				December 31, 2012
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	27.6	$	30.4	$	26.0
Long-term debt, including current portion	$	2,537.0	$	2,866.6	$	2,537.0	$	2,900.8

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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Derivative Instruments Derivative Instruments (Details 3) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	$ 0	$ 2.1
Derviative Instrument by Counterparty, Gross Amount Recognized on Balance Sheet [Member]
Derivative [Line Items]
Derivative Assets	11.9	19.2
Derivative Liabilities	0.3	1.9
Derviative Instrument by Counterparty, Gross Amount Not Offset on Balance Sheet [Member] [Member]
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value	0	0.6
Derivative Assets	(0.1)	(0.5)
Derivative Liabilities	(0.1)	(1.8)
Derviative Instrument by Counterparty, Net Amount [Member]
Derivative [Line Items]
Derivative Assets	11.8	18.7
Derivative Liabilities	$ 0.2	$ 0.1

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Consolidated Condensed Income Statements (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Operating Revenues	$ 1,004.6	$ 946.6
Operating Expenses
Fuel and purchased power	272.3	255.1
Cost of gas sold	112.8	100.2
Other operation and maintenance	350.3	329.6
Depreciation and amortization	68.4	61.2
Property and revenue taxes	27.7	28.2
Total Operating Expenses	831.5	774.3
Operating Income	173.1	172.3
Equity in earnings of transmission affiliate	14.7	13.7
Other Income, net	4.1	15.9
Interest Expense, net	31.9	25.2
Income Before Income Taxes	160.0	176.7
Income Tax Expense	55.3	60.8
Net Income	104.7	115.9
Preferred Stock Dividend Requirement	0.3	0.3
Earnings Available for Common Stockholder	$ 104.4	$ 115.6

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New Accounting Pronouncements

3 Months Ended

Mar. 31, 2013

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncements [Text Block]

NEW ACCOUNTING PRONOUNCEMENTS

Offsetting Assets and Liabilities: In December 2011, The Financial Accounting Standards Board issued Accounting Standards Update (ASU) 2011-11, Disclosures about Offsetting Assets and Liabilities. The guidance requires enhanced disclosures about derivatives. Both gross and net information related to eligible transactions is required under the guidance. This guidance is effective for fiscal years and interim periods beginning on or after January 1, 2013, and must be applied retrospectively. We adopted this guidance on January 1, 2013, and applied it retrospectively. See Note 5 -- Derivative Instruments for the enhanced disclosures.

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Variable Interest Entities (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Variable Interest Entity [Line Items]
Power capacity under capital lease (MW)	236
Capital Lease Agreement With Vie Remaining Term In Years	9
Total payments over remaining terms of the agreement	$ 246.2
Total capacity and lease payments	$ 12.5	$ 14.7

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Common Equity 2 (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	8,619,564
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 26.42
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number	6,288,439
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 22.99
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Weighted Average Remaining Contractual Term	4 years 8 months
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value	$ 22.0	$ 10.1
Proceeds from Stock Options Exercised	25.2	10.8
Tax Benefit from Stock Options Exercised	8.8	0
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	8,416,876
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period	1,365,970	903,865
Share Based Compensation Arrangement By Share Based Payment Award Options Grant In Period Weighted Average Exercise Price	$ 37.46
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period	(1,163,282)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	8,619,564
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 23.96
Share Based Compensation Arrangement By Share Based Payment Awards Options Exercises In Period Weighted Average Exercise Price	$ 21.64
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price	$ 0.00
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 26.42
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range Outstanding Options Weighted Average Remaining Contractual Period	5 years 11 months
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value	142.0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number	6,288,439
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 22.99
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Weighted Average Remaining Contractual Term	4 years 8 months
Share Based Compensation Arrangement by Share Based Payments Award, Options Exercisable, Intrinsic Value	$ 125.2

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Commitments and Contingencies (Details) (Manufactured Gas Plant Sites [Member], USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Manufactured Gas Plant Sites [Member]
Commitments and Contingencies [Line Items]
Loss Contingency, Range of Possible Loss, Minimum	$ 6
Loss Contingency, Range of Possible Loss, Maximum	18
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	$ 7.2

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Common Equity 4 (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 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	8,619,564
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 26.42
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	23 months
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 19.1
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	1,637,570
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period	1,365,970
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested in Period	(672,415)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	2,331,125
Non-vested options outstanding beginning balance, weighted average fair value	$ 3.31
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 3.45
Share Based Compensation Arrangements By Share Based Payment Awards Options Vested In Period Weighted Average Fair Value	$ 3.33
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Intrinsic Value	$ 0.00
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 3.38
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	22 months
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 4.8

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Common Equity

3 Months Ended

Mar. 31, 2013

Stockholders' Equity Note [Abstract]

COMMON EQUITY

COMMON EQUITY

Stock Option Activity:   During the first three months of 2013, the Compensation Committee of the Board of Directors of Wisconsin Energy (Compensation Committee) granted 1,365,970 Wisconsin Energy non-qualified stock options to our employees that had an estimated fair value of $3.45 per share. During the first three months of 2012, the Compensation Committee granted 903,865 Wisconsin Energy stock options to our employees that had an estimated fair value of $3.34 per share. The following assumptions were used to value the Wisconsin Energy options using a binomial option pricing model:

	2013		2012
Risk-free interest rate	0.1% - 1.9%		0.1% - 2.0%
Dividend yield	3.7	%	3.9	%
Expected volatility	18.0	%	19.0	%
Expected forfeiture rate	2.0	%	2.0	%
Expected life (years)	5.9		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 Wisconsin Energy's historical experience.

The following is a summary of Wisconsin Energy stock option activity by our employees during the three months ended March 31, 2013:

					Weighted-
					Average
			Weighted-		Remaining	Aggregate
	Number of		Average		Contractual Life	Intrinsic Value
Stock Options	Options		Exercise Price		(Years)	(Millions)
Outstanding as of January 1, 2013	8,416,876		$	23.96
Granted	1,365,970		$	37.46
Exercised	(1,163,282	)	$	21.64
Forfeited	—		$	—
Outstanding as of March 31, 2013	8,619,564		$	26.42	5.9	$	142.0
Exercisable as of March 31, 2013	6,288,439		$	22.99	4.7	$	125.2

The intrinsic value of Wisconsin Energy options exercised by our employees was $22.0 million and $10.1 million for the three months ended March 31, 2013 and 2012, respectively. Cash received by Wisconsin Energy from exercises of its options by our employees was $25.2 million and $10.8 million for the three months ended March 31, 2013 and 2012, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was $8.8 million and zero, respectively.

The following table summarizes information about Wisconsin Energy stock options held by our employees and outstanding as of March 31, 2013:

	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)
$16.72  to  $21.11	2,546,319	$	20.14	4.3	2,546,319	$	20.14	4.3
$23.88  to  $29.35	3,803,410	$	24.65	5.0	3,503,330	$	24.25	4.7
$34.87  to  $37.46	2,269,835	$	36.43	9.4	238,790	$	34.91	8.8
	8,619,564	$	26.42	5.9	6,288,439	$	22.99	4.7

The following table summarizes information about our employees' non-vested Wisconsin Energy stock options during the three months ended March 31, 2013:

			Weighted-Average
Non-Vested Stock Options	Number of Options		Fair Value
Non-vested as of January 1, 2013	1,637,570		$	3.31
Granted	1,365,970		$	3.45
Vested	(672,415	)	$	3.33
Forfeited	—		$	—
Non-vested as of March 31, 2013	2,331,125		$	3.38

As of March 31, 2013, our total compensation costs related to non-vested Wisconsin Energy stock options held by our employees and not yet recognized was approximately $4.8 million, which is expected to be recognized over the next 22 months on a weighted-average basis.

Restricted Shares:   During the first three months of 2013, the Compensation Committee granted 53,055 Wisconsin Energy restricted shares to our officers and other key employees. These awards have a three-year vesting period, with one-third of the award vesting on each anniversary of the grant date. During the vesting period, restricted share recipients have voting rights and are entitled to dividends in the same manner as other shareholders.

The following restricted stock activity related to our employees occurred during the three months ended March 31, 2013:

			Weighted-Average
Restricted Shares	Number of Shares		Grant Date Fair Value
Outstanding as of January 1, 2013	126,392
Granted	53,055		$	37.71
Released	(59,820	)	$	28.63
Forfeited	(11,698	)	$	33.01
Outstanding as of March 31, 2013	107,929

Wisconsin Energy records the market value of the restricted stock awards on the date of grant and then we amortize our share of allocated expense over the vesting period of the awards. The intrinsic value of Wisconsin Energy restricted stock vesting and held by our employees was $2.4 million and $1.6 million for the three months ended March 31, 2013, and 2012, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same periods was $0.9 millionand zero for the three months ended March 31, 2013, and 2012, respectively.

As of March 31, 2013, total compensation cost related to our share of Wisconsin Energy restricted stock not yet recognized was approximately $3.3 million, which is expected to be recognized over the next 27 months on a weighted-average basis.

Performance Units:   In January 2013 and 2012, the Compensation Committee awarded 230,245 and 333,685 Wisconsin Energy performance units, respectively, to our officers and other key employees under the Wisconsin Energy Performance Unit Plan. Under the grants, the ultimate number of units which will be awarded is dependent upon the achievement of certain financial performance of Wisconsin Energy's common stock over a three-year period. Under the terms of the award, participants may earn between 0% and 175% of the base performance unit award. All grants are settled in cash. We are accruing our share of compensation costs over the three-year period based on our estimate of the final expected value of the award. Performance units earned as of December 31, 2012 and 2011 vested and were settled during the first quarter of 2013 and 2012, and had a total intrinsic value of $17.1 million and $26.1 million, respectively. The actual tax benefit realized for the tax deductions from the settlement of performance units was approximately $6.2 million and $9.6 million, respectively. As of March 31, 2013, total compensation cost related to our share of Wisconsin Energy performance units not yet recognized was approximately $19.1 million, which is expected to be recognized over the next 23 months on a weighted-average basis.

Restrictions:Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. In addition, under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy. See Note H -- Common Equity in our 2012 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.

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Consolidated Condensed Balance Sheets (Unaudited) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment
In service	$ 9,633.8	$ 9,568.9
Accumulated depreciation	(3,159.9)	(3,117.0)
Property, Plant and Equipment in Service, Net	6,473.9	6,451.9
Construction work in progress	312.5	289.1
Leased facilities, net	2,348.0	2,340.2
Net Property, Plant and Equipment	9,134.4	9,081.2
Investments
Equity investment in transmission affiliate	336.7	332.6
Other	0.3	0.3
Total Investments	337.0	332.9
Current Assets
Cash and cash equivalents	24.1	34.1
Restricted cash	0	2.7
Accounts receivable, net	281.6	226.3
Accounts receivable from related parties	16.4	6.1
Accrued revenues	192.6	213.8
Materials, supplies and inventories	258.5	312.2
Prepayments and other	234.7	198.8
Total Current Assets	1,007.9	994.0
Deferred Charges and Other Assets
Regulatory assets	1,470.7	1,452.2
Other	138.0	162.3
Total Deferred Charges and Other Assets	1,608.7	1,614.5
Total Assets	12,088.0	12,022.6
Capitalization
Common equity	3,418.7	3,366.4
Preferred stock	30.4	30.4
Long-term debt	2,217.2	2,216.7
Capital lease obligations	2,728.8	2,703.1
Total Capitalization	8,395.1	8,316.6
Current Liabilities
Long-term debt and capital lease obligations due currently	362.3	357.0
Short-term debt	82.0	105.5
Subsidiary note payable to Wisconsin Energy	23.1	23.4
Accounts payable	200.9	306.8
Accounts payable to related parties	84.7	93.4
Accrued payroll and benefits	64.9	75.4
Other	139.1	110.2
Total Current Liabilities	957.0	1,071.7
Deferred Credits and Other Liabilities
Regulatory liabilities	589.7	600.3
Deferred income taxes - long term	1,647.4	1,533.6
Pension and other benefit obligations	294.3	189.2
Other	204.5	311.2
Total Deferred Credits and Other Liabilities	2,735.9	2,634.3
Total Capitalization and Liabilities	$ 12,088.0	$ 12,022.6

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Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2013

Derivative Instruments (Tables) [Abstract]

Derivative instruments in balance sheet

	March 31, 2013				December 31, 2012
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	3.9	$	—	$	1.2	$	1.1
Fuel Oil	0.5		—		0.4		—
FTRs	1.5		—		4.7		—
Coal	3.2		0.3		11.1		—
Total	$	9.1	$	0.3	$	17.4	$	1.1

Derivative instruments' estimated notional volumes and gain (losses)

	Three Months Ended March 31, 2013				Three Months Ended March 31, 2012
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)
Natural Gas	9.1 million Dth	$	(3.2	)	9.2 million Dth	$	(7.6	)
Fuel Oil	1.6 million gallons	0.1			1.7 million gallons	0.6
FTRs	5,343 MW	0.9			5,358 MW	0.6
Total		$	(2.2	)		$	(6.4	)

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Document and Entity Information Document (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Jun. 30, 2012
Entity Information [Line Items]
Entity Registrant Name	WISCONSIN ELECTRIC POWER CO
Entity Central Index Key	0000107815
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding	33,289,327
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float		$ 26.1

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Benefits (Tables)

3 Months Ended

Mar. 31, 2013

Benefits (Tables) [Abstract]

Components of net periodic pension and OPEB costs

	Pension Costs						OPEB Costs
	2013			2012			2013			2012
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	3.9		$	5.0		$	2.5		$	2.7
Interest cost	13.2			14.2			3.2			4.2
Expected return on plan assets	(19.3		)	(18.1		)	(3.6		)	(3.3		)
Amortization of:
Transition obligation	—			—			—			0.1
Prior service (credit)	0.5			0.5			(0.5		)	(0.5		)
Actuarial loss	10.4			7.3			0.4			1.2
Net Periodic Benefit Cost	$	8.7		$	8.9		$	2.0		$	4.4

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Consolidated Condensed Statements of Cash Flows (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Operating Activities
Net Income	$ 104.7	$ 115.9
Reconciliation to cash
Depreciation and amortization	70.9	63.4
Deferred income taxes and investment tax credits, net	64.3	58.1
Contributions to qualified benefit plans	0	0
Change In
Accounts receivable and accrued revenues	(50.3)	36.2
Inventories	53.7	29.9
Other current assets	26.1	29.9
Accounts payable	(107.8)	(61.0)
Accrued income taxes, net	(18.6)	(6.8)
Other current liabilities	24.8	5.9
Other, net	17.5	(41.3)
Cash Provided by Operating Activities	185.3	230.2
Investing Activities
Capital expenditures	(108.7)	(117.1)
Investment in transmission affiliate	(1.2)	(2.3)
Change in restricted cash	2.7	20.8
Other, net	(10.8)	(12.1)
Cash Used in Investing Activities	(118.0)	(110.7)
Financing Activities
Dividends paid on common stock	(60.0)	(44.9)
Dividends paid on preferred stock	(0.3)	(0.3)
Change in total short-term debt	(23.8)	(70.5)
Other, net	6.8	0
Cash Used in Financing Activities	(77.3)	(115.7)
Change in Cash and Cash Equivalents	(10.0)	3.8
Cash and Cash Equivalents at Beginning of Period	34.1	12.7
Cash and Cash Equivalents at End of Period	$ 24.1	$ 16.5

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Variable Interest Entities

3 Months Ended

Mar. 31, 2013

Variable Interest Entities [Abstract]

Variable Interest Entities Disclosure [Text Block]

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 nine 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 $246.2 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 three months ended March 31, 2013 and 2012 were $12.5 million and $14.7 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contracts.

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Segment Information

3 Months Ended

Mar. 31, 2013

Segment Information [Abstract]

Segment Information [Text Block]

SEGMENT INFORMATION

Summarized financial information concerning our reportable segments for the three months ended March 31, 2013 and 2012 is shown in the following table:

	Reportable Segments
	Electric		Gas		Steam		Total
	(Millions of Dollars)
Three Months Ended
March 31, 2013
Operating Revenues (a)	$	812.3	$	177.2	$	15.1	$	1,004.6
Operating Income	$	129.9	$	38.5	$	4.7	$	173.1
March 31, 2012
Operating Revenues (a)	$	777.3	$	156.7	$	12.6	$	946.6
Operating Income	$	143.6	$	26.7	$	2.0	$	172.3

(a) We account for all intersegment revenues at rates established by the PSCW. Intersegment revenues were not material.

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Common Equity 3 (Details) (USD $)	3 Months Ended
	Mar. 31, 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	8,619,564
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 26.42
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Outstanding Options, Weighted Average Remaining Contractual Term	5 years 11 months
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number	6,288,439
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 22.99
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Weighted Average Remaining Contractual Term	4 years 8 months
Exercise Price, Range One [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Number of Outstanding Options	2,546,319
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 20.14
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Outstanding Options, Weighted Average Remaining Contractual Term	4 years 4 months
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Number of Exercisable Options	2,546,319
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 20.14
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Weighted Average Remaining Contractual Term	4 years 4 months
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	$ 16.72
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 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	3,803,410
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 24.65
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Outstanding Options, Weighted Average Remaining Contractual Term	5 years 0 months
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Number of Exercisable Options	3,503,330
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 24.25
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Weighted Average Remaining Contractual Term	4 years 8 months
Exercise Price, Range 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 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 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	2,269,835
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 36.43
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Outstanding Options, Weighted Average Remaining Contractual Term	9 years 5 months
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Number of Exercisable Options	238,790
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 34.91
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Exercisable Options, Weighted Average Remaining Contractual Term	8 years 10 months
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	$ 34.87
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	$ 37.46

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2013

Segment Reporting Information [Line Items]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

	Reportable Segments
	Electric		Gas		Steam		Total
	(Millions of Dollars)
Three Months Ended
March 31, 2013
Operating Revenues (a)	$	812.3	$	177.2	$	15.1	$	1,004.6
Operating Income	$	129.9	$	38.5	$	4.7	$	173.1
March 31, 2012
Operating Revenues (a)	$	777.3	$	156.7	$	12.6	$	946.6
Operating Income	$	143.6	$	26.7	$	2.0	$	172.3

(a) We account for all intersegment revenues at rates established by the PSCW. Intersegment revenues were not material.

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Common Equity (Tables)

3 Months Ended

Mar. 31, 2013

Stockholders' Equity Note [Abstract]

Assumptions for valuing options using binomial option pricing model

	2013		2012
Risk-free interest rate	0.1% - 1.9%		0.1% - 2.0%
Dividend yield	3.7	%	3.9	%
Expected volatility	18.0	%	19.0	%
Expected forfeiture rate	2.0	%	2.0	%
Expected life (years)	5.9		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 January 1, 2013	8,416,876		$	23.96
Granted	1,365,970		$	37.46
Exercised	(1,163,282	)	$	21.64
Forfeited	—		$	—
Outstanding as of March 31, 2013	8,619,564		$	26.42	5.9	$	142.0
Exercisable as of March 31, 2013	6,288,439		$	22.99	4.7	$	125.2

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)
$16.72  to  $21.11	2,546,319	$	20.14	4.3	2,546,319	$	20.14	4.3
$23.88  to  $29.35	3,803,410	$	24.65	5.0	3,503,330	$	24.25	4.7
$34.87  to  $37.46	2,269,835	$	36.43	9.4	238,790	$	34.91	8.8
	8,619,564	$	26.42	5.9	6,288,439	$	22.99	4.7

Non-vested options

			Weighted-Average
Non-Vested Stock Options	Number of Options		Fair Value
Non-vested as of January 1, 2013	1,637,570		$	3.31
Granted	1,365,970		$	3.45
Vested	(672,415	)	$	3.33
Forfeited	—		$	—
Non-vested as of March 31, 2013	2,331,125		$	3.38

Restricted stock activity

			Weighted-Average
Restricted Shares	Number of Shares		Grant Date Fair Value
Outstanding as of January 1, 2013	126,392
Granted	53,055		$	37.71
Released	(59,820	)	$	28.63
Forfeited	(11,698	)	$	33.01
Outstanding as of March 31, 2013	107,929

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies [Text Block]

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 our manufactured gas plant sites and related disposal sites, as well as our coal combustion product disposal/landfill sites, as discussed below. We are working with the Wisconsin Department of Natural Resources (WDNR) in our investigation and remediation planning. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

Manufactured Gas Plant Sites:   We have identified several sites at which we 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 $6 million to $18 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 March 31, 2013, we have established reserves of $7.2 million related to future remediation costs.

Historically, the PSCW has allowed Wisconsin utilities, including us, 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. (WPL) in connection with the sale of our interest in Edgewater Generating Unit 5.

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Supplemental Cash Flow Information

3 Months Ended

Mar. 31, 2013

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

During the three months ended March 31, 2013, we paid $3.6 million in interest, net of amounts capitalized, and paid $2.0 million in income taxes, net of refunds. During the three months ended March 31, 2012, we paid $0.9 million in interest, capitalized $6.1 million of interest expense and paid $9.2 million in income taxes, net of refunds.

As of March 31, 2013 and 2012, the amount of accounts payable related to capital expenditures was $8.8 million and $12.5 million, respectively.

During the three months ended March 31, 2013 and 2012, our equity in earnings from ATC was $14.7 million and $13.7 million, respectively. During the three months ended March 31, 2013 and 2012, distributions received from ATC were $11.7 million and $11.3 million, respectively.

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2013

Fair Value Measurements (Tables) [Abstract]

Financial assets and liabilities by level within the fair value hierarchy

Recurring Fair Value Measures	As of March 31, 2013
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	—	$	—	$	—	$	—
Derivatives	4.3		3.2		1.6		9.1
Total	$	4.3	$	3.2	$	1.6	$	9.1
Liabilities:
Derivatives	$	—	$	0.3	$	—	$	0.3
Total	$	—	$	0.3	$	—	$	0.3

Recurring Fair Value Measures	As of December 31, 2012
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	2.7	$	—	$	—	$	2.7
Derivatives	1.2		11.5		4.7		17.4
Total	$	3.9	$	11.5	$	4.7	$	20.1
Liabilities:
Derivatives	$	1.1	$	—	$	—	$	1.1
Total	$	1.1	$	—	$	—	$	1.1

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

	2013			2012
	(Millions of Dollars)
Balance as of January 1	$	4.7		$	5.7
Realized and unrealized gains (losses)	—			—
Purchases	—			—
Issuances	—			—
Settlements	(3.1		)	(3.5		)
Transfers in and/or out of Level 3	—			—
Balance as of March 31	$	1.6		$	2.2
Change in unrealized gains (losses) relating to instruments still held as of March 31	$	—		$	—

Carrying amount and estimated fair value of certain financial instruments

	March 31, 2013				December 31, 2012
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	27.6	$	30.4	$	26.0
Long-term debt, including current portion	$	2,537.0	$	2,866.6	$	2,537.0	$	2,900.8

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Segment Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Segment Reporting Information [Line Items]
Operating Revenues	$ 1,004.6	[1]	$ 946.6	[1]
Operating Income (Loss)	173.1		172.3
Reportable Operating Segment Electric [Member]
Segment Reporting Information [Line Items]
Operating Revenues	812.3	[1]	777.3	[1]
Operating Income (Loss)	129.9		143.6
Reportable Operating Segment Gas [Member]
Segment Reporting Information [Line Items]
Operating Revenues	177.2	[1]	156.7	[1]
Operating Income (Loss)	38.5		26.7
Reportable Operating Segment Steam [Member]
Segment Reporting Information [Line Items]
Operating Revenues	15.1	[1]	12.6	[1]
Operating Income (Loss)	$ 4.7		$ 2.0

[1] We account for all intersegment revenues at rates established by the PSCW. Intersegment revenues were not material.

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Common Equity 1 (Details) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
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	3.70%	3.90%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	18.00%	19.00%
Share Based Compensation Arrangement By Share Based Payment Award Fair Value Assumptions Expected Forfeiture Rate	2.00%	2.00%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	5 years 11 months	5 years 11 months
Stock options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures	1,365,970	903,865
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value	3.45	3.34
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	1.90%	2.00%

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Fair Value Measurements Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement Captions [Line Items]
Restricted Cash	$ 0	$ 2.7
Fair Value, Assets Measured on Recurring Basis, Derivative Financial Instruments, Assets	4.3	1.2
Fair Value Assets Measured on Recurring Basis Total Assets	4.3	3.9
Fair Value, Liabilities Measured on Recurring Basis, Derivative Financial Instruments, Liabilities	0	1.1
Fair Value Liabilities Measured on Recurring Basis Total Liabilities	0	1.1
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement Captions [Line Items]
Restricted Cash	0	0
Fair Value, Assets Measured on Recurring Basis, Derivative Financial Instruments, Assets	3.2	11.5
Fair Value Assets Measured on Recurring Basis Total Assets	3.2	11.5
Fair Value, Liabilities Measured on Recurring Basis, Derivative Financial Instruments, Liabilities	0.3	0
Fair Value Liabilities Measured on Recurring Basis Total Liabilities	0.3	0
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement Captions [Line Items]
Restricted Cash	0	0
Fair Value, Assets Measured on Recurring Basis, Derivative Financial Instruments, Assets	1.6	4.7
Fair Value Assets Measured on Recurring Basis Total Assets	1.6	4.7
Fair Value, Liabilities Measured on Recurring Basis, Derivative Financial Instruments, Liabilities	0	0
Fair Value Liabilities Measured on Recurring Basis Total Liabilities	0	0
Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement Captions [Line Items]
Restricted Cash	0	2.7
Fair Value, Assets Measured on Recurring Basis, Derivative Financial Instruments, Assets	9.1	17.4
Fair Value Assets Measured on Recurring Basis Total Assets	9.1	20.1
Fair Value, Liabilities Measured on Recurring Basis, Derivative Financial Instruments, Liabilities	0.3	1.1
Fair Value Liabilities Measured on Recurring Basis Total Liabilities	$ 0.3	$ 1.1

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General Information

3 Months Ended

Mar. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

General Information [Text Block]

GENERAL INFORMATION

Our accompanying unaudited consolidated condensed financial statements should be read in conjunction with Item 8, Financial Statements and Supplementary Data, in our 2012 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 months ended March 31, 2013 are not necessarily indicative of the results which may be expected for the entire fiscal year 2013 because of seasonal and other factors.

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Benefits

3 Months Ended

Mar. 31, 2013

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 months ended March 31 were as follows:

	Pension Costs						OPEB Costs
	2013			2012			2013			2012
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	3.9		$	5.0		$	2.5		$	2.7
Interest cost	13.2			14.2			3.2			4.2
Expected return on plan assets	(19.3		)	(18.1		)	(3.6		)	(3.3		)
Amortization of:
Transition obligation	—			—			—			0.1
Prior service (credit)	0.5			0.5			(0.5		)	(0.5		)
Actuarial loss	10.4			7.3			0.4			1.2
Net Periodic Benefit Cost	$	8.7		$	8.9		$	2.0		$	4.4

During the first three months of 2013 and 2012, we made no contributions to our qualified benefit plans. Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates.

Postemployment Benefits:   Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $2.4 million as of March 31, 2013 and

December 31, 2012.

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Fair Value Measurements, Derivatives (Details) (Derivative [Member], USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Derivative [Member]
Fair value of derivatives classified as Level 3 in the fair value hierarchy
Beginning Balance	$ 4.7	$ 5.7
Realized and unrealized gains (losses)	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements	(3.1)	(3.5)
Transfers in and/or out of Level 3	0	0
Ending Balance	1.6	2.2
Change in unrealized gains (losses) relating to instruments still held as of period end	$ 0	$ 0

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Common Equity (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Common Equity (Textuals) [Abstract]
Minimum percentage award based on performance unit	0.00
Maximum percentage award based on performance unit	1.75
Tax Benefit from Stock Options Exercised	$ 8.8	$ 0
Other Comprehensive Income (Loss), Net of Tax	0	0
Performance units [Member]
Common Equity (Textuals) [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	230,245	333,685
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value	17.1	26.1
Tax Benefit from Stock Options Exercised	6.2	9.6
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	19.1
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	23 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	53,055
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value	2.4	1.6
Tax Benefit from Stock Options Exercised	0.9	0
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 3.3
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	27 months