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, 2012

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, 2012):

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, 2012

	TABLE OF CONTENTS
Item		Page
	Introduction	7
	Part I -- Financial Information
1.	Financial Statements
	Consolidated Condensed Income Statements	8
	Consolidated Condensed Balance Sheets	9
	Consolidated Condensed Statements of Cash Flows	10
	Notes to Consolidated Condensed Financial Statements	11
2.	Management's Discussion and Analysis of
	Financial Condition and Results of Operations	22
3.	Quantitative and Qualitative Disclosures About Market Risk	30
4.	Controls and Procedures	30
	Part II -- Other Information
1.	Legal Proceedings	31
1A.	Risk Factors	32
4.	Mine Safety Disclosures	32
5.	Other Information	32
6.	Exhibits	33
	Signatures	34

March 2012 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
OC 2	Oak Creek expansion Unit 2
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
IRS	Internal Revenue Service
MPSC	Michigan Public Service Commission
PSCW	Public Service Commission of Wisconsin
SEC	Securities and Exchange Commission
WDNR	Wisconsin Department of Natural Resources
Environmental Terms
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CO2	Carbon Dioxide
CSAPR	Cross-State Air Pollution Rule
MACT	Maximum Achievable Control Technology
MATS	Mercury and Air Toxics Standards
NOV	Notice of Violation
NOx	Nitrogen Oxide
SO2	Sulfur Dioxide
Other Terms and Abbreviations
AQCS	Air Quality Control System
Compensation Committee	Compensation Committee of the Board of Directors of Wisconsin Energy
ERISA	Employee Retirement Income Security Act of 1974
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
Plan	The Wisconsin Energy Corporation Retirement Account Plan
Point Beach	Point Beach Nuclear Power Plant

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Form 10-Q

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS
The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:
PTF	Power the Future
WPL	Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corp.
Measurements
Btu	British Thermal Unit(s)
Dth	Dekatherm(s) (One Dth equals one million Btu)
MW	Megawatt(s) (One MW equals one million Watts)
MWh	Megawatt-hour(s)
Watt	A measure of power production or usage
Accounting Terms
AFUDC	Allowance for Funds Used During Construction
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 (Exchange Act). These statements are based upon management's current expectations and are subject to risks and uncertainties that could cause our actual results to differ materially from those contemplated in the statements. Readers are cautioned not to place undue reliance on these forward-looking statements. Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of construction projects, regulatory matters, on-going legal proceedings, fuel costs, sources of electric energy supply, coal and gas deliveries, remediation costs, environmental and other capital expenditures, liquidity and capital resources and other matters. In some cases, forward-looking statements may be identified by reference to a future period or periods or by the use of forward-looking terminology such as "anticipates," "believes," "estimates," "expects," "forecasts," "goals," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects," "seeks," "should," "targets" or similar terms or variations of these terms.

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

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

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

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

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

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

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

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

March 2012 5 Wisconsin Electric Power Company

Form 10-Q

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

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

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

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

• 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.

• Foreign governmental, economic, political and currency risks.

• Other business or investment considerations that may be disclosed from time to time in our Securities and Exchange Commission (SEC) filings or in other publicly disseminated written documents, including the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2011.

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

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Form 10-Q

INTRODUCTION

Wisconsin 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 operating segments: an electric utility segment, a natural gas utility segment and a steam utility segment. We serve approximately 1,124,000 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 466,600 gas customers in Wisconsin and approximately 465 steam customers in metropolitan Milwaukee, Wisconsin. For further financial information about our business segments, see Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 9 --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 PTF strategy, which is described further in this report and in our 2011 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, 2012, Bostco had $34.5 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 2011 Annual Report on Form 10-K, including the financial statements and notes therein.

March 2012 7 Wisconsin Electric Power Company

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
	2012		2011
	(Millions of Dollars)
Operating Revenues	$	946.6	$	1,006.2
Operating Expenses
Fuel and purchased power	255.1		268.8
Cost of gas sold	100.2		146.2
Other operation and maintenance	329.6		355.4
Depreciation and amortization	61.2		54.4
Property and revenue taxes	28.2		26.1
Total Operating Expenses	774.3		850.9
Operating Income	172.3		155.3
Equity in Earnings of Transmission Affiliate	13.7		13.6
Other Income, net	15.9		12.3
Interest Expense, net	25.2		24.2
Income Before Income Taxes	176.7		157.0
Income Tax Expense	60.8		49.5
Net Income	115.9		107.5
Preferred Stock Dividend Requirement	0.3		0.3
Earnings Available for Common Stockholder	$	115.6	$	107.2
The accompanying Notes to Consolidated Condensed Financial Statements are an integral part of these financial statements.

March 2012 8 Wisconsin Electric Power Company

Form 10-Q

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited)
	March 31, 2012			December 31, 2011
	(Millions of Dollars)
Assets
Property, Plant and Equipment
In service	$	8,908.0		$	8,416.2
Accumulated depreciation	(3,001.8		)	(2,964.7		)
	5,906.2			5,451.5
Construction work in progress	523.5			902.4
Leased facilities, net	2,413.6			2,428.2
Net Property, Plant and Equipment	8,843.3			8,782.1
Investments
Equity investment in transmission affiliate	312.2			307.5
Other	0.2			0.2
Total Investments	312.4			307.7
Current Assets
Cash and cash equivalents	16.5			12.7
Restricted cash	24.7			45.5
Accounts receivable, net	287.2			274.2
Accounts receivable from related parties	19.2			36.5
Accrued revenues	162.5			200.5
Materials, supplies and inventories	289.3			319.2
Prepayments and other	251.2			281.4
Total Current Assets	1,050.6			1,170.0
Deferred Charges and Other Assets
Regulatory assets	1,314.3			1,236.2
Other	150.8			165.3
Total Deferred Charges and Other Assets	1,465.1			1,401.5
Total Assets	$	11,671.4		$	11,661.3
Capitalization and Liabilities
Capitalization
Common equity	$	3,248.4		$	3,177.1
Preferred stock	30.4			30.4
Long-term debt	2,268.1			2,267.6
Capital lease obligations	2,720.8			2,716.5
Total Capitalization	8,267.7			8,191.6
Current Liabilities
Long-term debt and capital lease obligations due currently	42.6			37.9
Short-term debt	281.5			352.0
Subsidiary note payable to Wisconsin Energy	26.8			26.8
Accounts payable	200.1			265.2
Accounts payable to related parties	94.5			94.6
Accrued payroll and vacation	51.8			73.2
Other	187.3			173.4
Total Current Liabilities	884.6			1,023.1
Deferred Credits and Other Liabilities
Regulatory liabilities	655.5			658.1
Deferred income taxes - long-term	1,362.6			1,284.0
Pension and other benefit obligations	280.9			278.8
Other	220.1			225.7
Total Deferred Credits and Other Liabilities	2,519.1			2,446.6
Total Capitalization and Liabilities	$	11,671.4		$	11,661.3
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
	2012			2011
	(Millions of Dollars)
Operating Activities
Net income	$	115.9		$	107.5
Reconciliation to cash
Depreciation and amortization	63.4			56.4
Deferred income taxes and investment tax credits, net	58.1			56.8
Contributions to qualified benefit plans	—			(107.1		)
Change in - Accounts receivable and accrued revenues	36.2			(8.5		)
Inventories	29.9			47.6
Other current assets	29.9			24.8
Accounts payable	(61.0		)	(29.8		)
Accrued income taxes, net	(6.8		)	(18.8		)
Other current liabilities	5.9			24.6
Other, net	(41.3		)	56.2
Cash Provided by Operating Activities	230.2			209.7
Investing Activities
Capital expenditures	(117.1		)	(112.5		)
Investment in transmission affiliate	(2.3		)	(2.3		)
Proceeds from asset sales	2.7			38.3
Change in restricted cash	20.8			(37.2		)
Other, net	(14.8		)	(12.0		)
Cash Used in Investing Activities	(110.7		)	(125.7		)
Financing Activities
Dividends paid on common stock	(44.9		)	(44.9		)
Dividends paid on preferred stock	(0.3		)	(0.3		)
Change in total short-term debt	(70.5		)	(53.0		)
Other, net	—			2.3
Cash Used in Financing Activities	(115.7		)	(95.9		)
Change in Cash and Cash Equivalents	3.8			(11.9		)
Cash and Cash Equivalents at Beginning of Period	12.7			23.3
Cash and Cash Equivalents at End of Period	$	16.5		$	11.4
The accompanying Notes to Consolidated Condensed Financial Statements are an integral part of these financial statements.

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Form 10-Q

WISCONSIN 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 2011 Annual Report on Form 10-K. In the opinion of management, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of the results of operations, cash flows and financial position in the accompanying income statements, statements of cash flows and balance sheets. The results of operations for the three months ended March 31, 2012 are not necessarily indicative of the results which may be expected for the entire fiscal year 2012 because of seasonal and other factors.

2 -- NEW ACCOUNTING PRONOUNCEMENTS

Presentation of Comprehensive Income:   In June 2011, the Financial Accounting Standards Board (FASB) issued guidance on the presentation of comprehensive income. This guidance eliminates the option of presenting components of other comprehensive income as part of the statement of changes in stockholders' equity. The guidance gives entities the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. In December 2011, the FASB issued an amendment to indefinitely defer one of the requirements contained in its June 2011 final standard. That requirement called for reclassification adjustments from accumulated other comprehensive income to be measured and presented by income statement line item in net income and also in other comprehensive income. This guidance, including the related deferral, is effective for fiscal years and interim periods beginning after December 15, 2011 and must be applied retrospectively. We adopted this guidance on January 1, 2012, and it did not have any material impact on us.

Fair Value Measurement:   In May 2011, the FASB issued guidance amending existing guidance for measuring fair value and for disclosing information about fair value measurements. Under the new guidance, required disclosures are expanded, particularly for fair value measurements that are categorized within Level 3 of the fair value hierarchy, for which quantitative information about the unobservable inputs, the valuation processes used by the entity, and the sensitivity of the measurement to the unobservable inputs will be required. Entities are also required to disclose the categorization, by level of the fair value hierarchy, of items that are not measured at fair value in the balance sheets but for which the fair value is required to be disclosed. This guidance is effective for fiscal years and interim periods beginning after December 15, 2011 and must be applied prospectively. We adopted this guidance on January 1, 2012, and it did not have any material impact on us.

3 -- COMMON EQUITY

Share-Based Compensation Expense:   For additional information on share-based compensation, including Wisconsin Energy stock options, restricted stock and performance units, see Note H -- Common Equity in our 2011 Annual Report on Form 10-K. We utilize the straight-line attribution method for recognizing share-based compensation expense. Accordingly, for employee awards, equity classified share-based compensation cost is measured at the grant date based on the fair value of the award and is recognized as expense over the requisite service period. There were no modifications to the terms of outstanding Wisconsin Energy stock options held by our employees during the period.

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Form 10-Q

The following table summarizes recorded pre-tax share-based compensation expense and the related tax benefit for Wisconsin Energy share-based awards made to our employees:

	Three Months Ended March 31
	2012		2011
	(Millions of Dollars)
Performance units	$	10.3	$	1.0
Stock options	0.7		0.6
Restricted stock	0.6		0.3
Share-based compensation expense	$	11.6	$	1.9
Related tax benefit	$	4.6	$	0.7

Stock Option Activity:   During the first three months of 2012, the Compensation Committee of the Board of Directors of Wisconsin Energy (Compensation Committee) granted 903,865 Wisconsin Energy non-qualified stock options to our employees that had an estimated fair value of $3.34 per share. During the first three months of 2011, the Compensation Committee granted 435,370 Wisconsin Energy stock options to our employees that had an estimated fair value of $3.17 per share. The following assumptions were used to value the Wisconsin Energy options using a binomial option pricing model:

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

The risk-free interest rate is based on the U.S. Treasury interest rate whose term is consistent with the expected life of the stock options. Dividend yield, expected volatility, expected forfeiture rate and expected life assumptions are based on 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, 2012:

					Weighted-
					Average
			Weighted-		Remaining	Aggregate
	Number of		Average		Contractual Life	Intrinsic Value
Stock Options	Options		Exercise Price		(Years)	(Millions)
Outstanding as of January 1, 2012	9,907,526		$	21.76
Granted	903,865		$	34.88
Exercised	(600,723	)	$	17.98
Forfeited	—		$	—
Outstanding as of March 31, 2012	10,210,668		$	23.15	5.7	$	122.9
Exercisable as of March 31, 2012	8,548,803		$	21.63	5.1	$	115.9

The intrinsic value of Wisconsin Energy options exercised by our employees was $10.1 million and $8.2 million for the three months ended March 31, 2012 and 2011, respectively. Cash received by Wisconsin Energy from exercises of its options by our employees was $10.8 million and $12.2 million for the three months ended March 31, 2012 and 2011, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was zero and approximately $3.3 million, respectively.

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The following table summarizes information about Wisconsin Energy stock options held by our employees and outstanding as of March 31, 2012:

	Options Outstanding				Options Exercisable
		Weighted-Average				Weighted-Average
				Remaining				Remaining
	Number of	Exercise		Contractual	Number of	Exercise		Contractual
Range of Exercise Prices	Options	Price		Life (Years)	Options	Price		Life (Years)
$12.71  to  $19.74	2,511,871	$	18.01	3.0	2,511,871	$	18.01	3.0
$21.11  to  $24.92	6,365,992	$	23.09	6.0	5,928,982	$	22.96	5.9
$29.35  to  $34.88	1,332,805	$	33.10	9.4	107,950	$	32.67	9.4
	10,210,668	$	23.15	5.7	8,548,803	$	21.63	5.1

The following table summarizes information about our employees' non-vested Wisconsin Energy stock options during the three months ended March 31, 2012:

			Weighted-Average
Non-Vested Stock Options	Number of Options		Fair Value
Non-vested as of January 1, 2012	2,953,580		$	3.78
Granted	903,865		$	3.34
Vested	(2,195,580	)	$	3.96
Forfeited	—		$	—
Non-vested as of March 31, 2012	1,661,865		$	3.31

As of March 31, 2012, our total compensation costs related to non-vested Wisconsin Energy stock options held by our employees and not yet recognized was approximately $3.0 million, which is expected to be recognized over the next 19 months on a weighted-average basis.

Restricted Shares:   During the first three months of 2012, the Compensation Committee granted 71,496 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, 2012:

			Weighted-Average
Restricted Shares	Number of Shares		Grant Date Fair Value
Outstanding as of January 1, 2012	115,946
Granted	71,496		$	34.46
Released	(42,430	)	$	27.33
Forfeited	(4,222	)	$	25.82
Outstanding as of March 31, 2012	140,790

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 $1.6 million and $1.3 million for the three months ended March 31, 2012 and 2011, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same periods was zero and $0.5 million for the three months ended March 31, 2012 and 2011, respectively.

As of March 31, 2012, total compensation cost related to our share of Wisconsin Energy restricted stock not yet

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recognized was approximately $3.5 million, which is expected to be recognized over the next 27 months on a weighted-average basis.

Performance Units:   In January 2012 and 2011, the Compensation Committee awarded 333,685 and 413,990 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, 2011 and 2010 vested and were settled during the first quarter of 2012 and 2011, and had a total intrinsic value of $26.1 million and $12.1 million, respectively. The actual tax benefit realized for the tax deductions from the settlement of performance units was approximately $9.6 million and $4.2 million, respectively. As of March 31, 2012, total compensation cost related to our share of Wisconsin Energy performance units not yet recognized was approximately $24.8 million, which is expected to be recognized over the next 22 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 2011 Annual Report on Form 10-K for additional information on these and other restrictions.

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

Comprehensive Income:   Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to owners. There was no other comprehensive income for the three months ended March 31, 2012 and 2011.

4 -- LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

On January 12, 2011, Oak Creek expansion Unit 2 (OC 2) was placed into service. We have care, custody and control of OC 2 and will operate and maintain it over the 30 year life of the lease. As a result of the commercial operation of OC 2, in January 2011, we recorded an additional capital lease asset and capital lease obligation related to the Oak Creek expansion totaling approximately $650 million. The lease payments are expected to be recovered through our rates, as supported by the Wisconsin 2001 Leased Generation Law. The total obligation under the capital leases for the Oak Creek expansion was approximately $2.0 billion as of March 31, 2012 and will decrease to zero over the remaining life of the contract.

5 -- DIVESTITURES

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

6 -- FAIR VALUE MEASUREMENTS

Fair value measurements require enhanced disclosures about assets and liabilities that are measured and reported at fair value and establish a hierarchal disclosure framework which prioritizes and ranks the level of observable inputs used in measuring fair value.

Fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. Accordingly, we also utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The

March 2012 14 Wisconsin Electric Power Company

Form 10-Q

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, 2012
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	24.7	$	—	$	—	$	24.7
Derivatives	0.9		10.8		2.2		13.9
Total	$	25.6	$	10.8	$	2.2	$	38.6
Liabilities:
Derivatives	$	6.5	$	0.1	$	—	$	6.6
Total	$	6.5	$	0.1	$	—	$	6.6

Recurring Fair Value Measures	As of December 31, 2011
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	45.5	$	—	$	—	$	45.5
Derivatives	0.3		13.2		5.7		19.2
Total	$	45.8	$	13.2	$	5.7	$	64.7
Liabilities:
Derivatives	$	4.3	$	0.4	$	—	$	4.7
Total	$	4.3	$	0.4	$	—	$	4.7

Restricted cash consists of certificates of deposit and government backed interest bearing securities and represents the settlement we received from the United States Department of Energy (DOE) during the first quarter of 2011, which is being returned, net of costs incurred, to customers. Derivatives reflect positions we hold in exchange-traded derivative contracts and OTC derivative contracts. Exchange-traded derivative contracts, which include

March 2012 15 Wisconsin Electric Power Company

Form 10-Q

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:

	2012			2011
	(Millions of Dollars)
Balance as of January 1	$	5.7		$	5.9
Realized and unrealized gains (losses)	—			—
Purchases	—			—
Issuances	—			—
Settlements	(3.5		)	(3.8		)
Transfers in and/or out of Level 3	—			—
Balance as of March 31	$	2.2		$	2.1
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 7 -- Derivative Instruments for further information on the offset to regulatory assets and liabilities.

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

	March 31, 2012				December 31, 2011
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	25.0	$	30.4	$	25.1
Long-term debt, including current portion	$	2,287.0	$	2,599.7	$	2,287.0	$	2,669.0

The carrying value of net accounts receivable, accounts payable and short-term borrowings approximates fair value due to the short-term nature of these instruments. The fair value of our preferred stock is estimated based upon the quoted market value for the same or similar issues. The fair value of our long-term debt, including the current portion of long-term debt, but excluding capitalized leases and unamortized discount on debt, is estimated based upon quoted market value for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows. Based on these assessments, the above items have been classified within Level 2.

7 -- DERIVATIVE INSTRUMENTS

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

March 2012 16 Wisconsin Electric Power Company

Form 10-Q

the Public Service Commission of Wisconsin (PSCW).

We record derivative instruments on the balance sheet as an asset or liability measured at its fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. We do not offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivatives executed with the same counterparty under the same master netting arrangement. As of

March 31, 2012, we recognized $13.7 million in regulatory assets and $14.8 million in regulatory liabilities related to derivatives in comparison to $14.1 million in regulatory assets and $20.3 million in regulatory liabilities as of December 31, 2011.

We record our current derivative assets on the balance sheet in prepayments and other current assets and the current portion of the liabilities in other current liabilities. We had no long-term portion of derivative assets as of March 31, 2012, and the long-term portion of our derivative liabilities of $0.2 million is recorded in other deferred credits and other liabilities as of March 31, 2012. Our Consolidated Condensed Balance Sheets as of March 31, 2012 and December 31, 2011 include:

	March 31, 2012				December 31, 2011
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	1.0	$	6.6	$	0.7	$	4.6
Fuel Oil	0.9		—		0.3		0.1
FTRs	2.2		—		5.7		—
Coal	9.8		—		12.5		—
Total	$	13.9	$	6.6	$	19.2	$	4.7

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, 2012				Three Months Ended March 31, 2011
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)
Natural Gas	9.2 million Dth	$	(7.6	)	8.8 million Dth	$	(4.9	)
Fuel Oil	1.7 million gallons	0.6			3.2 million gallons	0.4
FTRs	5,358 MW	0.6			6,352 MW	3.8
Total		$	(6.4	)		$	(0.7	)

As of March 31, 2012 and December 31, 2011, we posted collateral of $8.3 million and $6.4 million, respectively, in our margin accounts. These amounts are recorded on the balance sheets in prepayments and other current assets.

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Form 10-Q

8 -- 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
Benefit Plan Cost Components	2012			2011
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	5.0		$	4.1
Interest cost	14.2			14.5
Expected return on plan assets	(18.1		)	(16.1		)
Amortization of:
Prior service cost	0.5			0.5
Actuarial loss	7.3			5.8
Net Periodic Benefit Cost	$	8.9		$	8.8

	OPEB Costs
Benefit Plan Cost Components	2012			2011
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	2.7		$	2.7
Interest cost	4.2			4.3
Expected return on plan assets	(3.3		)	(2.8		)
Amortization of:
Transition obligation	0.1			0.1
Prior service (credit)	(0.5		)	(0.5		)
Actuarial loss	1.2			1.0
Net Periodic Benefit Cost	$	4.4		$	4.8

During the first quarter of 2011, we contributed $107.1 million 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 $3.3 million as of March 31, 2012 and

$12.2 million as of December 31, 2011.

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Form 10-Q

9 -- SEGMENT INFORMATION

Summarized financial information concerning our operating segments for the three months ended March 31, 2012 and 2011 is shown in the following table:

	Operating Segments
	Electric		Gas		Steam		Total
	(Millions of Dollars)
Three Months Ended
March 31, 2012
Operating Revenues (a)	$	777.3	$	156.7	$	12.6	$	946.6
Operating Income (Loss)	$	143.6	$	26.7	$	2.0	$	172.3
March 31, 2011
Operating Revenues (a)	$	776.6	$	214.4	$	15.2	$	1,006.2
Operating Income (Loss)	$	113.9	$	36.5	$	4.9	$	155.3

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

10 -- VARIABLE INTEREST ENTITIES

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

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

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

We also have a purchased power agreement for 236 MW of firm capacity from a gas-fired cogeneration facility, which we account for as a capital lease. The agreement includes no minimum energy requirements over the remaining term of approximately 10 years. We have examined the risks of the entity including operations and maintenance, dispatch, financing, fuel costs and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity and there is no residual guarantee associated with the purchased power agreement.

We have approximately $296.7 million of required payments over the remaining term of these agreements. We believe that the required lease payments under these contracts will continue to be recoverable in rates. Total capacity and lease payments under these contracts for the three months ended March 31, 2012 and 2011 were $14.7 million and $15.0 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contracts.

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Form 10-Q

11 -- COMMITMENTS AND CONTINGENCIES

Environmental Matters:   We periodically review our exposure for environmental remediation costs as evidence becomes available indicating that our liability has changed. Given current information, including the following, we believe that future costs in excess of the amounts accrued and/or disclosed on all presently known and quantifiable environmental contingencies will not be material to our financial position or results of operations.

We have a program of comprehensive environmental remediation planning for former manufactured gas plant sites and coal-combustion product disposal sites. We perform ongoing assessments of 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. We have substantially completed planned remediation activities at some of these sites and certain other sites 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 $19 million over 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, 2012, we have established reserves of $6.4 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.

Valley Power Plant Title V Air Permit:   The WDNR renewed Valley Power Plant's (VAPP) Title V operating permit in February 2011. The term of the permit is five years. Sierra Club and Clean Wisconsin requested and were granted an administrative hearing before the WDNR on certain conditions of the permit. We filed a motion for partial summary judgment in that proceeding on March 22, 2012. If the case proceeds to hearing, it would be held in early 2013. The Sierra Club petitioned the United States Environmental Protection Agency (EPA) for additional reductions and monitoring for particulate matter, and revisions to certain applicable requirements. No timeline has been set by the EPA to respond to that petition.

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

We filed an application with the PSCW in December 2011 for authority to replace and upgrade the Lincoln Arthur natural gas main, which would also have the capability to accommodate the increased natural gas required if VAPP were to convert from coal to natural gas. Clean Wisconsin has requested intervenor status in the PSCW process.

We also submitted a letter to the EPA in December 2011 with four voluntary goals which include: (1) reducing annual Sulfur Dioxide (SO₂) emissions from the plant to no more than 4,500 tons (a 65% decrease from 2001 emission levels); (2) installing a dry sorbent injection system that is needed to meet the utility Maximum Achievable Control Technology (MACT) rules earlier than the rules require if the installation would provide a direct economic benefit to customers and is approved by the PSCW; (3) holding an open house and tour of VAPP in 2012 to help inform the community on the plant, the unique role that it plays in the community, and to share environmental successes and future plans; and (4) converting VAPP to natural gas fuel by the 2017/2018 timeframe, provided we can demonstrate a direct economic benefit to customers and obtain authorization from the PSCW to do so.

Divested Assets:   Pursuant to the sale of the Point Beach Nuclear Power Plant (Point Beach), we have agreed to indemnification provisions customary to transactions involving the sale of nuclear assets. We also provided customary indemnifications to WPL in connection with the sale of our interest in Edgewater Generating Unit 5. We have established reserves as deemed appropriate for these indemnification provisions.

Cash Balance Pension Plan:   In June 2009, a lawsuit was filed by Alan M. Downes, a former employee, against

March 2012 20 Wisconsin Electric Power Company

Form 10-Q

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

In November 2011, the Plan entered into a settlement agreement with the plaintiffs for $45.0 million, and the court promptly issued an order preliminarily approving the settlement. As part of the settlement agreement, the Plan agreed to class certification for all similarly situated plaintiffs. The resolution of this matter resulted in a cost of less than $13 million for 2011 after considering insurance and reserves established in the prior year. The court approved the settlement on April 3, 2012 and issued its written order on April 20, 2012. The plaintiffs have 30 days from the date of the written order to appeal this decision.

We do not anticipate further charges as a result of the settlement, other than certain process-related costs we expect to incur to implement the settlement.

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

12 -- SUPPLEMENTAL CASH FLOW INFORMATION

During the 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. During the three months ended March 31, 2011, we paid $1.2 million in interest, capitalized $5.0 million of interest expense and paid $10.2 million in income taxes, net of refunds.

As of March 31, 2012 and 2011, the amount of accounts payable related to capital expenditures was $12.5 million and $19.4 million, respectively.

During the three months ended March 31, 2012 and 2011, our equity in earnings from ATC was $13.7 million and $13.6 million, respectively. During the three months ended March 31, 2012 and 2011, distributions received from ATC were $11.3 million and $10.9 million, respectively.

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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, 2012

Electric Utility Revenues and Sales

The following table compares electric utility operating revenues and MWh sales by customer class during the first quarter of 2012 with the first quarter of 2011, including favorable (better (B)) or unfavorable (worse (W)) variances:

	Electric Revenues							MWh Sales
Electric Utility Operations	2012		B (W)			2011		2012	B (W)		2011
	(Millions of Dollars)							(Thousands)
Customer Class
Residential	$	274.6	$	(8.4	)	$	283.0	1,942.9	(87.1	)	2,030.0
Small Commercial/Industrial	245.2		(1.2		)	246.4		2,151.6	(47.1	)	2,198.7
Large Commercial/Industrial	184.4		5.8			178.6		2,444.3	70.6		2,373.7
Other - Retail	6.0		(0.1		)	6.1		40.4	0.4		40.0
Total Retail	710.2		(3.9		)	714.1		6,579.2	(63.2	)	6,642.4
Wholesale - Other	36.7		0.7			36.0		332.7	(146.1	)	478.8
Resale - Utilities	17.0		(0.5		)	17.5		597.1	28.5		568.6
Other Operating Revenues	13.4		4.4			9.0		—	—		—
Total	$	777.3	$	0.7		$	776.6	7,509.0	(180.8	)	7,689.8
Weather -- Degree Days (a)
Heating (3,306 Normal)								2,610	(834	)	3,444
(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 $0.7 million, or 0.1%, when compared to the first quarter of 2011. The most significant factors that caused a change in revenues were:

• Unfavorable weather as compared to the prior year that decreased electric revenues by an estimated $19.3 million.

• Net pricing increases totaling $8.8 million, which primarily includes rates related to our request to review 2011 fuel costs that became effective April 29, 2011. For additional information, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters.

• A $4.4 million increase in other operating revenues, which includes the amortization of $6.7 million related to the DOE settlement used to offset an increase in fuel costs authorized by the PSCW. For additional information on the DOE settlement, see Factors Affecting Results, Liquidity and Capital Resources -- Nuclear Operations.

As measured by heating degree days, the first quarter of 2012 was 24.2% warmer than the same period in 2011 and 21.1% warmer than normal. The decrease in residential sales volumes in 2012 is primarily attributable to the warmer weather.

Fuel and Purchased Power

Our fuel and purchased power costs decreased by $13.7 million, or 5.1%, when compared to the first quarter of 2011. This decrease was primarily caused by a 2.4% decrease in total MWh sales as well as lower generating costs driven by a decrease in natural gas prices as compared to the first quarter of 2011.

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 2012 with the first quarter of 2011. We believe gross margin is a better performance indicator than revenues

March 2012 22 Wisconsin Electric Power Company

Form 10-Q

because changes in the cost of gas sold flow through to revenue under gas cost recovery mechanisms. Between the comparative periods, total gas operating revenues decreased by $57.7 million, or 26.9%, and cost of gas sold decreased by $46.0 million, or 31.5%, due to the significantly warmer winter weather, which resulted in lower therm deliveries, and a decline in the commodity cost of natural gas.

	Three Months Ended March 31
	2012		B (W)			2011
	(Millions of Dollars)
Gas Operating Revenues	$	156.7	$	(57.7	)	$	214.4
Cost of Gas Sold	100.2		46.0			146.2
Gross Margin	$	56.5	$	(11.7	)	$	68.2

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

	Gross Margin							Therm Deliveries
Gas Utility Operations	2012		B (W)			2011		2012	B (W)		2011
	(Millions of Dollars)							(Millions)
Customer Class
Residential	$	38.2	$	(7.8	)	$	46.0	129.8	(40.3	)	170.1
Commercial/Industrial	13.3		(3.4		)	16.7		73.0	(22.1	)	95.1
Interruptible	0.1		(0.1		)	0.2		1.7	(0.5	)	2.2
Total Retail	51.6		(11.3		)	62.9		204.5	(62.9	)	267.4
Transported Gas	4.4		(0.3		)	4.7		87.6	(4.9	)	92.5
Other	0.5		(0.1		)	0.6		—	—		—
Total	$	56.5	$	(11.7	)	$	68.2	292.1	(67.8	)	359.9
Weather -- Degree Days (a)
Heating (3,306 Normal)								2,610	(834	)	3,444
(a) As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year
moving average.

Our gas margin decreased by $11.7 million, or approximately 17.2%, when compared to the first quarter of 2011 as a result of record warm winter weather. The first quarter of 2012 was the warmest winter in 122 years. As measured by heating degree days, the first quarter of 2012 was 24.2% warmer than the same period in 2011 and 21.1% warmer than normal.

Other Operation and Maintenance Expense

Our other operation and maintenance expense decreased by $25.8 million, or approximately 7.3%, when compared to the first quarter of 2011. This decrease, which we expect to continue through the remainder of the year, is primarily due to the one year suspension of $148 million of amortization expense on certain regulatory assets as authorized under our 2012 Wisconsin Rate Case. For additional information on the 2012 rate case, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters.

Depreciation and Amortization Expense

Our depreciation and amortization expense increased by $6.8 million, or approximately 12.5%, when compared to the first quarter of 2011, primarily because of an overall increase in utility plant in service. The Glacier Hills Wind Park went in service in December 2011. We expect depreciation expense to increase in 2012 related to the in-service events of the Oak Creek Air Quality Control System (AQCS) project. For additional information, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters -- Oak Creek Air Quality Control System.

March 2012 23 Wisconsin Electric Power Company

Form 10-Q

Other Income, net

	Three Months Ended March 31
Other Income, net	2012		B (W)		2011
	(Millions of Dollars)
AFUDC - Equity	$	14.7	$	2.6	$	12.1
Other	1.2		1.0		0.2
Other Income, net	$	15.9	$	3.6	$	12.3

Other income, net increased by $3.6 million, or approximately 29.3%, when compared to the first quarter of 2011. The increase in AFUDC - Equity is primarily related to the construction of the Oak Creek AQCS project and the Rothschild biomass facility. We expect AFUDC-Equity to decrease after the Oak Creek AQCS project goes in service. For additional information, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters -- Oak Creek Air Quality Control System.

Interest Expense, net

	Three Months Ended March 31
Interest Expense	2012		B (W)			2011
	(Millions of Dollars)
Gross Interest Costs	$	31.3	$	(2.1	)	$	29.2
Less: Capitalized Interest	6.1		1.1			5.0
Interest Expense, net	$	25.2	$	(1.0	)	$	24.2

Our gross interest costs increased by $2.1 million, or 7.2%, when compared to the first quarter of 2011 primarily because of higher average long-term debt balances compared to the same period in 2011. In September 2011, we issued $300 million of long-term debt. Our capitalized interest increased by $1.1 million primarily due to increased capital expenditures related to the biomass facility during the first quarter of 2012 as compared to the same period in 2011, partially offset by the reduction in capitalized interest as a result of the Glacier Hills Wind Park project going into service in December 2011. As a result, our net interest expense increased by $1.0 million, or 4.1%, as compared to the first quarter of 2011.

Income Tax Expense

For the first quarter of 2012, our effective tax rate was 34.4% compared to 31.5% for the first quarter of 2011. For additional information, see Note G -- Income Taxes in our 2011 Annual Report on Form 10-K. We expect our 2012 annual effective tax rate to be between 34% and 35%.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

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

	2012			2011
	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$	230.2		$	209.7
Investing Activities	$	(110.7	)	$	(125.7	)
Financing Activities	$	(115.7	)	$	(95.9	)

March 2012 24 Wisconsin Electric Power Company

Form 10-Q

Operating Activities

Cash provided by operating activities increased by $20.5 million during the first quarter of 2012 as compared to the same period in 2011, primarily because we contributed $107.1 million to our qualified benefit plans during the first quarter of 2011. We made no such contributions to our qualified plans in the first quarter of 2012. In the first quarter of 2011, we expensed approximately $37.0 million of non-cash charges associated with the amortization of certain regulatory assets and liabilities. The PSCW allowed us to suspend these amortizations in 2012. In addition, in 2011, we received approximately $45.5 million in refunds related to the DOE settlement, which were recorded as a regulatory liability.

Investing Activities

Cash used in investing activities declined by $15.0 million during the first quarter of 2012 as compared to the same period in 2011. Our capital expenditures increased by $4.6 million during the first quarter of 2012 as compared to the same period in 2011, primarily because of increased spending on the biomass facility. During the first quarter of 2011, we received proceeds from asset sales totaling $38.3 million in connection with the sale of our interest in Edgewater Generating Unit 5, as compared to proceeds of $2.7 million during the first quarter of 2012. Finally, changes in restricted cash improved our cash from investing activities by $58.0 million. In 2011, we received $45.5 million in proceeds from the settlement with the DOE. The proceeds were treated as restricted cash, which was recorded as cash used in investing activities. In 2012, we released $20.8 million of the proceeds through bill credits and the reimbursement of costs. The release of restricted cash was treated as cash provided by investing activities.

Financing Activities

Cash used in financing activities increased by $19.8 million during the first quarter of 2012 as compared to the same period in 2011. This change is primarily due to changes in our debt levels. During the first quarter of 2012, we decreased our short-term debt levels by $70.5 million compared to a decrease of $53.0 million during the same period in 2011.

CAPITAL RESOURCES AND REQUIREMENTS

Liquidity

We anticipate meeting our capital requirements during the remainder of 2012 and beyond primarily through internally generated funds and short-term borrowings, supplemented as necessary 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.

As of March 31, 2012, we had approximately $495.6 million of available, undrawn lines under our bank back-up credit facility, and approximately $281.5 million of commercial paper outstanding that was supported by the available lines of credit. During the first three months of 2012, our maximum commercial paper outstanding was $382.0 million with a weighted-average interest rate of 0.24%.

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, 2012:

March 2012 25 Wisconsin Electric Power Company

Form 10-Q

Total Facility		Letters of Credit		Credit Available		Facility Expiration
(Millions of Dollars)
$	500.0	$	4.4	$	495.6	December 2013

We are the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amount 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, 2012, 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.

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 2011 Annual Report on Form 10-K for additional information related to our credit rating risk.

Capital Requirements

Capital Expenditures: Capital requirements during the remainder of 2012 are expected to be principally for capital expenditures relating to our electric and gas distribution systems, our biomass facility and environmental controls at our Oak Creek generating units. Our 2012 capital expenditure estimate is approximately $600 million.

Off-Balance Sheet Arrangements:   We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support construction projects, commodity contracts and other payment obligations. We continue to believe that these agreements do not have, and are not reasonably likely to have, a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors. For further information, see Note 10 -- Variable Interest Entities in the Notes to Consolidated Condensed Financial Statements in this report.

Contractual Obligations/Commercial Commitments:   Our total contractual obligations and other commercial commitments were approximately $27.7 billion as of March 31, 2012 compared with $27.9 billion as of December 31, 2011. Our total contractual obligations and other commercial commitments as of March 31, 2012 decreased compared with December 31, 2011 primarily due to periodic payments related to these obligations which were greater than new commitments made in the ordinary course of business.

FACTORS AFFECTING RESULTS, LIQUIDITY AND CAPITAL RESOURCES

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

March 2012 26 Wisconsin Electric Power Company

Form 10-Q

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 1, Port Washington Generating Station 2 and Oak Creek expansion Unit 1 in our rates as authorized by the PSCW, the Michigan Public Service Commission (MPSC) and FERC. We are recovering the lease payment associated with OC 2 as authorized by the PSCW and FERC, and have requested authorization from the MPSC in the rate case filed in July 2011. See Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Item 7 of our 2011 Annual Report on Form 10-K for additional information on PTF.

RATES AND REGULATORY MATTERS

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

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

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

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

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

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

• Authorizes the refund of $26 million of net proceeds from our settlement of the spent nuclear fuel litigation with the DOE.

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

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

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

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

March 2012 27 Wisconsin Electric Power Company

Form 10-Q

$7.7 million. A final decision from the MPSC is expected in July 2012.

2012 Fuel Recovery Request:   On August 3, 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 are projected higher coal, coal transportation and purchased power costs. This filing was made under the new Wisconsin fuel rules which require annual fuel cost filings. On January 5, 2012, the PSCW issued an order which provided for an increase in fuel costs of approximately $26 million, offset by approximately $26 million from the settlement with the DOE regarding the storage of spent nuclear fuel, resulting in no change in customer bills.

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

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

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

Pursuant to the NDAA, which was passed in December 2011, utilities are now able to elect to receive a cash grant for renewable energy projects without the effect of normalization for income tax purposes. As a result of the NDAA, we currently anticipate pursuing a cash grant relating to the biomass facility.

Oak Creek Air Quality Control System:   In July 2008, we received approval from the PSCW granting us 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. On March 3, 2012, the wet flue gas desulfurization and selective catalytic reduction equipment for units 5 and 6 was placed into commercial operation. We expect the equipment for units 7 and 8 to be completed by the end of summer 2012. We currently expect the cost of completing this project to be approximately $750 million ($900 million including AFUDC).

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

ENVIRONMENTAL MATTERS

Air Quality

Mercury and Other Hazardous Air Pollutants:   On December 16, 2011, the EPA issued the final utility MACT rule (referred to as the Mercury and Air Toxics Standards (MATS) rule), which imposes stringent limitations on numerous hazardous air pollutants, including mercury, from coal and oil-fired electric generating units. While we are continuing to evaluate the impact of the rule on the operation of our existing coal-fired generation facilities, as well as alternatives for complying with the rule, we currently estimate our capital cost to comply with this rule will be approximately $16 million to $25 million. Based upon our review, the VAPP and Presque Isle Power Plant may require modifications. We believe that our clean air strategy, including the environmental upgrades that have already been constructed and that are currently under construction at our other plants, positions those plants well to

March 2012 28 Wisconsin Electric Power Company

Form 10-Q

meet the rule's requirements.

Cross-State Air Pollution Rule:   On August 8, 2011, the EPA issued a final rule, the Cross-State Air Pollution Rule (CSAPR), formerly known as the Clean Air Transport Rule. This rule was proposed in 2010 to replace the Clean Air Interstate Rule (CAIR), which had been remanded to the EPA in 2008. The stated purpose of the CSAPR is to limit the interstate transport of emissions of Nitrogen Oxide (NO_x) and SO₂ that contribute to fine particulate matter and ozone non-attainment in downwind states through a proposed allocation scheme. On February 7, 2012, the EPA issued final technical revisions to the rule and issued a draft final rule which together delay the implementation date for certain penalty provisions that could potentially impact the Presque Isle Power Plant and increase the number of allowances issued to the states of Michigan and Wisconsin. Even with these proposed revisions, however, the Presque Isle Power Plant may not have been allocated sufficient allowances to meet its obligations to operate and provide stability to the transmission system in the Upper Peninsula of Michigan. This situation could then put the plant at risk for certain penalties under the rule.

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

Climate Change:   Federal, state, regional and international authorities have undertaken efforts to limit greenhouse gas emissions. The regulation of greenhouse gas emissions through legislation and regulation has been, and continues to be, a focus of the President and his administration. Although legislation that would impose mandatory requirements related to greenhouse gas emissions, renewable energy standards and/or energy efficiency standards failed to pass in the U.S. Congress, we expect such legislation to be considered in the future. Any mandatory restrictions on our Carbon Dioxide (CO₂) emissions that may be adopted by Congress or Wisconsin's or Michigan's legislature could result in significant compliance costs that could affect future results of operations, cash flows and financial condition.

On March 27, 2012, the EPA, using its existing authority under the Clean Air Act (CAA), proposed new source performance standards pertaining to greenhouse gas emissions from certain new power plants, including coal-fueled plants, based on the performance of combined cycle natural gas-fueled generating plants. We believe this rule effectively prohibits new conventional coal-fueled power plants.

We expect the EPA to attempt to address performance standards for reconstructed and modified generating units in a future rule. Any such rule may impact our ability to do maintenance or modify our existing facilities. Depending on the extent of rate recovery and other factors, these anticipated future rules could have a material adverse impact on our financial condition. For additional information, see the caption "We may face significant costs to comply with the regulation of greenhouse gas emissions." under Item 1A Risk Factors in our 2011 Annual Report on Form 10-K.

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

LEGAL MATTERS

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

In November 2011, the Plan entered into a settlement agreement with the plaintiffs for $45.0 million, and the court promptly issued an order preliminarily approving the settlement. As part of the settlement agreement, the Plan agreed to class certification for all similarly situated plaintiffs. The resolution of this matter resulted in a cost of less than $13 million for 2011 after considering insurance and reserves established in the prior year. The court approved the settlement on April 3, 2012 and issued its written order on April 20, 2012. The plaintiffs have 30 days from the date of the written order to appeal this decision.

March 2012 29 Wisconsin Electric Power Company

Form 10-Q

We do not anticipate further charges as a result of the settlement, other than certain process-related costs we expect to incur to implement the settlement.

NUCLEAR OPERATIONS

Used Nuclear Fuel Storage and Disposal:   The Nuclear Waste Policy Act established the Nuclear Waste Fund, which is composed of payments made by the generators and owners of nuclear plants. We owned Point Beach through September 2007 and placed approximately $215.2 million into this fund. Effective January 31, 1998, the DOE failed to meet its contractual obligation to begin removing used fuel from Point Beach. We filed a complaint in November 2000 against the DOE in the Court of Federal Claims for failure to begin performance. In December 2009, the Court ruled in our favor, granting us more than $50 million in damages. In February 2010, the DOE filed an appeal. We negotiated a settlement with the DOE for $45.5 million, which we received in the first quarter of 2011. This amount, net of costs incurred, is being returned to customers as part of the PSCW's approval of our 2012 fuel recovery request and the MPSC's approval of our interim order for the 2012 Michigan rate case.

OTHER MATTERS

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures:   Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based upon such evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective (i) in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act and (ii) to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

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

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Form 10-Q

PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

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

ENVIRONMENTAL MATTERS

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

A mixture of soil, coal ash and water, along with several trailers, vehicles and other construction materials from the AQCS construction site, slid down the bluff to the shoreline area. Some of these materials fell into Lake Michigan.

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

We consulted with nearby water utilities and they indicated that there were no impacts to public drinking water supplies. In November 2011, the WDNR conducted a survey of Lake Michigan's lakebed. The survey did not locate any fly ash or construction materials on the lakebed immediately east and south of the Oak Creek site. Both water quality and sediment sampling have not indicated a serious risk of harm to human health or the environment.

The WDNR issued a Notice of Violation (NOV) along with its investigative findings on March 1, 2012, and an enforcement conference was held with Company representatives on March 7, 2012. The NOV involves the north surface water detention basin and a related permit condition. Ash deposits were removed from beneath the north detention basin during construction, which we believe was consistent with the permit condition requiring installation of a liner only if the basin was placed over a "waste area." Therefore, we do not believe a liner was required. We have also provided answers to follow-up questions provided by the WDNR at the enforcement conference. The WDNR or other regulatory agency may seek fines or penalties from us as a result of this incident.

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

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.

OTHER MATTERS

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

March 2012 31 Wisconsin Electric Power Company

Form 10-Q

ITEM 1A. RISK FACTORS

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

ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable.

ITEM 5. OTHER INFORMATION

Director Frederick P. Stratton, Jr. did not stand for re-election at either the 2012 Annual Meeting of Stockholders of Wisconsin Electric held on April 26, 2012 or the 2012 Annual Meeting of Stockholders of Wisconsin Energy held on May 3, 2012, at which time his term expired. Director Stratton has served on the Wisconsin Electric Board of Directors since 1986, the Wisconsin Energy Board of Directors since 1987 and the Wisconsin Gas Board of Directors since 2000. In consideration of his exemplary service and contributions to these Boards of Directors, on May 1, 2012, the Compensation Committee accelerated the vesting of all unvested shares of restricted stock of Wisconsin Energy awarded to Director Stratton, consisting of approximately 8,212 shares, effective May 3, 2012.

March 2012 32 Wisconsin Electric Power Company

Form 10-Q

ITEM 6. EXHIBITS

Exhibit No.
10	Material Contracts
10.1	Terms of Employment for Susan H. Martin. (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/2012 Form 10-Q (File No. 001-09057).)
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 2012 33 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 3, 2012	Stephen P. Dickson, Vice President and Controller, Principal Accounting Officer and duly authorized officer

March 2012 34 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
	3/31/2012			3/31/2012			12/31/2011			12/31/2010			12/31/2009			12/31/2008			12/31/2007
	(Millions of Dollars)
Pre-tax Income	$	174.3		$	505.2		$	485.2		$	470.8		$	435.3		$	439.4		$	468.7
Subtract:
Capitalized Interest	(6.1		)	(25.8		)	(24.7		)	(13.5		)	(6.6		)	(3.0		)	(1.8		)
Earnings Before Adding Fixed Charges (a)	168.2			479.4			460.5			457.3			428.7			436.4			466.9
Fixed Charges
Interest on Long-Term Debt	30.8			119.0			116.7			113.7			104.2			77.7			82.6
Other Interest Expense	0.5			2.0			2.2			1.3			2.7			11.9			12.2
Estimated Interest Component of Rentals	35.2			142.4			141.3			107.1			65.6			57.6			48.5
Total Fixed Charges as Defined (b)	66.5			263.4			260.2			222.1			172.5			147.2			143.3
Total Earnings as Defined	$	234.7		$	742.8		$	720.7		$	679.4		$	601.2		$	583.6		$	610.2
Ratio of Earnings to Fixed Charges	3.5x			2.8x			2.8x			3.1x			3.5x			4.0x			4.3x
(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 3, 2012

/s/GALE E. KLAPPA

Gale E. Klappa

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

EX-31.2

Exhibit 31.2

Certification Pursuant to

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

as Adopted Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002

I, Frederick D. Kuester, certify that:

1. I have reviewed this 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 3, 2012

/s/FREDERICK D. KUESTER

Frederick D. Kuester

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-32.1

Exhibit 32.1

Certification Pursuant to

18 U.S.C. Section 1350,

As Adopted Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Wisconsin Electric Power Company (the "Company") on Form 10-Q for the period ended March 31, 2012, as filed with the Securities and Exchange Commission on May 3, 2012 (the "Report"), I, Gale E. Klappa, Chairman, President and Chief Executive Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

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

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

/s/GALE E. KLAPPA

Gale E. Klappa

Chairman, President and Chief Executive Officer

May 3, 2012

EX-32.2

Exhibit 32.2

Certification Pursuant to

18 U.S.C. Section 1350,

As Adopted Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Wisconsin Electric Power Company (the "Company") on Form 10-Q for the period ended March 31, 2012, as filed with the Securities and Exchange Commission on May 3, 2012 (the "Report"), I, Frederick D. Kuester, Executive Vice President and Chief Financial Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

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

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

/s/FREDERICK D. KUESTER

Frederick D. Kuester

Executive Vice President and Chief Financial Officer

May 3, 2012

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Divestitures

3 Months Ended

Mar. 31, 2012

Discontinued Operations and Disposal Groups [Abstract]

Divestitures [Text Block]

DIVESTITURES

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

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Long Term Debt and Capital Lease Obligations

3 Months Ended

Mar. 31, 2012

Long-term Debt and Capital Lease Obligations [Abstract]

Debt and Capital Leases Disclosures [Text Block]

LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

On January 12, 2011, Oak Creek expansion Unit 2 (OC 2) was placed into service. We have care, custody and control of OC 2 and will operate and maintain it over the 30 year life of the lease. As a result of the commercial operation of OC 2, in January 2011, we recorded an additional capital lease asset and capital lease obligation related to the Oak Creek expansion totaling approximately $650 million. The lease payments are expected to be recovered through our rates, as supported by the Wisconsin 2001 Leased Generation Law. The total obligation under the capital leases for the Oak Creek expansion was approximately $2.0 billion as of March 31, 2012 and will decrease to zero over the remaining life of the contract.

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Consolidated Condensed Income Statements (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Operating Revenues	$ 946.6	$ 1,006.2
Operating Expenses
Fuel and purchased power	255.1	268.8
Cost of gas sold	100.2	146.2
Other operation and maintenance	329.6	355.4
Depreciation and amortization	61.2	54.4
Property and revenue taxes	28.2	26.1
Total Operating Expenses	774.3	850.9
Operating Income	172.3	155.3
Equity in earnings of transmission affiliate	13.7	13.6
Other Income, net	15.9	12.3
Interest Expense, net	25.2	24.2
Income Before Income Taxes	176.7	157.0
Income Tax Expense	60.8	49.5
Net Income	115.9	107.5
Preferred Stock Dividend Requirement	0.3	0.3
Earnings Available for Common Stockholder	$ 115.6	$ 107.2

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New Accounting Pronouncements

3 Months Ended

Mar. 31, 2012

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncements [Text Block]

NEW ACCOUNTING PRONOUNCEMENTS

Presentation of Comprehensive Income:   In June 2011, the Financial Accounting Standards Board (FASB) issued guidance on the presentation of comprehensive income. This guidance eliminates the option of presenting components of other comprehensive income as part of the statement of changes in stockholders' equity. The guidance gives entities the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. In December 2011, the FASB issued an amendment to indefinitely defer one of the requirements contained in its June 2011 final standard. That requirement called for reclassification adjustments from accumulated other comprehensive income to be measured and presented by income statement line item in net income and also in other comprehensive income. This guidance, including the related deferral, is effective for fiscal years and interim periods beginning after December 15, 2011 and must be applied retrospectively. We adopted this guidance on January 1, 2012, and it did not have any material impact on us.

Fair Value Measurement:   In May 2011, the FASB issued guidance amending existing guidance for measuring fair value and for disclosing information about fair value measurements. Under the new guidance, required disclosures are expanded, particularly for fair value measurements that are categorized within Level 3 of the fair value hierarchy, for which quantitative information about the unobservable inputs, the valuation processes used by the entity, and the sensitivity of the measurement to the unobservable inputs will be required. Entities are also required to disclose the categorization, by level of the fair value hierarchy, of items that are not measured at fair value in the balance sheets but for which the fair value is required to be disclosed. This guidance is effective for fiscal years and interim periods beginning after December 15, 2011 and must be applied prospectively. We adopted this guidance on January 1, 2012, and it did not have any material impact on us.

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Common Equity

3 Months Ended

Mar. 31, 2012

Stockholders' Equity Note [Abstract]

Common Equity [Text Block]

COMMON EQUITY

Share-Based Compensation Expense:   For additional information on share-based compensation, including Wisconsin Energy stock options, restricted stock and performance units, see Note H -- Common Equity in our 2011 Annual Report on Form 10-K. We utilize the straight-line attribution method for recognizing share-based compensation expense. Accordingly, for employee awards, equity classified share-based compensation cost is measured at the grant date based on the fair value of the award and is recognized as expense over the requisite service period. There were no modifications to the terms of outstanding Wisconsin Energy stock options held by our employees during the period.

The following table summarizes recorded pre-tax share-based compensation expense and the related tax benefit for Wisconsin Energy share-based awards made to our employees:

	Three Months Ended March 31
	2012		2011
	(Millions of Dollars)
Performance units	$	10.3	$	1.0
Stock options	0.7		0.6
Restricted stock	0.6		0.3
Share-based compensation expense	$	11.6	$	1.9
Related tax benefit	$	4.6	$	0.7

Stock Option Activity:   During the first three months of 2012, the Compensation Committee of the Board of Directors of Wisconsin Energy (Compensation Committee) granted 903,865 Wisconsin Energy non-qualified stock options to our employees that had an estimated fair value of $3.34 per share. During the first three months of 2011, the Compensation Committee granted 435,370 Wisconsin Energy stock options to our employees that had an estimated fair value of $3.17 per share. The following assumptions were used to value the Wisconsin Energy options using a binomial option pricing model:

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

The risk-free interest rate is based on the U.S. Treasury interest rate whose term is consistent with the expected life of the stock options. Dividend yield, expected volatility, expected forfeiture rate and expected life assumptions are based on 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, 2012:

					Weighted-
					Average
			Weighted-		Remaining	Aggregate
	Number of		Average		Contractual Life	Intrinsic Value
Stock Options	Options		Exercise Price		(Years)	(Millions)
Outstanding as of January 1, 2012	9,907,526		$	21.76
Granted	903,865		$	34.88
Exercised	(600,723	)	$	17.98
Forfeited	—		$	—
Outstanding as of March 31, 2012	10,210,668		$	23.15	5.7	$	122.9
Exercisable as of March 31, 2012	8,548,803		$	21.63	5.1	$	115.9

The intrinsic value of Wisconsin Energy options exercised by our employees was $10.1 million and $8.2 million for the three months ended March 31, 2012 and 2011, respectively. Cash received by Wisconsin Energy from exercises of its options by our employees was $10.8 million and $12.2 million for the three months ended March 31, 2012 and 2011, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was zero and approximately $3.3 million, respectively.

The following table summarizes information about Wisconsin Energy stock options held by our employees and outstanding as of March 31, 2012:

	Options Outstanding				Options Exercisable
		Weighted-Average				Weighted-Average
				Remaining				Remaining
	Number of	Exercise		Contractual	Number of	Exercise		Contractual
Range of Exercise Prices	Options	Price		Life (Years)	Options	Price		Life (Years)
$12.71  to  $19.74	2,511,871	$	18.01	3.0	2,511,871	$	18.01	3.0
$21.11  to  $24.92	6,365,992	$	23.09	6.0	5,928,982	$	22.96	5.9
$29.35  to  $34.88	1,332,805	$	33.10	9.4	107,950	$	32.67	9.4
	10,210,668	$	23.15	5.7	8,548,803	$	21.63	5.1

The following table summarizes information about our employees' non-vested Wisconsin Energy stock options during the three months ended March 31, 2012:

			Weighted-Average
Non-Vested Stock Options	Number of Options		Fair Value
Non-vested as of January 1, 2012	2,953,580		$	3.78
Granted	903,865		$	3.34
Vested	(2,195,580	)	$	3.96
Forfeited	—		$	—
Non-vested as of March 31, 2012	1,661,865		$	3.31

As of March 31, 2012, our total compensation costs related to non-vested Wisconsin Energy stock options held by our employees and not yet recognized was approximately $3.0 million, which is expected to be recognized over the next 19 months on a weighted-average basis.

Restricted Shares:   During the first three months of 2012, the Compensation Committee granted 71,496 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, 2012:

			Weighted-Average
Restricted Shares	Number of Shares		Grant Date Fair Value
Outstanding as of January 1, 2012	115,946
Granted	71,496		$	34.46
Released	(42,430	)	$	27.33
Forfeited	(4,222	)	$	25.82
Outstanding as of March 31, 2012	140,790

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 $1.6 million and $1.3 million for the three months ended March 31, 2012 and 2011, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same periods was zero and $0.5 million for the three months ended March 31, 2012 and 2011, respectively.

As of March 31, 2012, total compensation cost related to our share of Wisconsin Energy restricted stock not yet recognized was approximately $3.5 million, which is expected to be recognized over the next 27 months on a weighted-average basis.

Performance Units:   In January 2012 and 2011, the Compensation Committee awarded 333,685 and 413,990 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, 2011 and 2010 vested and were settled during the first quarter of 2012 and 2011, and had a total intrinsic value of $26.1 million and $12.1 million, respectively. The actual tax benefit realized for the tax deductions from the settlement of performance units was approximately $9.6 million and $4.2 million, respectively. As of March 31, 2012, total compensation cost related to our share of Wisconsin Energy performance units not yet recognized was approximately $24.8 million, which is expected to be recognized over the next 22 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 2011 Annual Report on Form 10-K for additional information on these and other restrictions.

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

Comprehensive Income:   Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to owners. There was no other comprehensive income for the three months ended March 31, 2012 and 2011.

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Consolidated Condensed Balance Sheets (Unaudited) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment
In service	$ 8,908.0	$ 8,416.2
Accumulated depreciation	(3,001.8)	(2,964.7)
Property, Plant and Equipment in Service, Net	5,906.2	5,451.5
Construction work in progress	523.5	902.4
Leased facilities, net	2,413.6	2,428.2
Net Property, Plant and Equipment	8,843.3	8,782.1
Investments
Equity investment in transmission affiliate	312.2	307.5
Other	0.2	0.2
Total Investments	312.4	307.7
Current Assets
Cash and cash equivalents	16.5	12.7
Restricted cash	24.7	45.5
Accounts receivable, net	287.2	274.2
Accounts receivable from related parties	19.2	36.5
Accrued revenues	162.5	200.5
Materials, supplies and inventories	289.3	319.2
Prepayments and other	251.2	281.4
Total Current Assets	1,050.6	1,170.0
Deferred Charges and Other Assets
Regulatory assets	1,314.3	1,236.2
Other	150.8	165.3
Total Deferred Charges and Other Assets	1,465.1	1,401.5
Total Assets	11,671.4	11,661.3
Capitalization
Common equity	3,248.4	3,177.1
Preferred stock	30.4	30.4
Long-term debt	2,268.1	2,267.6
Capital lease obligations	2,720.8	2,716.5
Total Capitalization	8,267.7	8,191.6
Current Liabilities
Long-term debt and capital lease obligations due currently	42.6	37.9
Short-term debt	281.5	352.0
Subsidiary note payable to Wisconsin Energy	26.8	26.8
Accounts payable	200.1	265.2
Accounts payable to related parties	94.5	94.6
Accrued payroll and vacation	51.8	73.2
Other	187.3	173.4
Total Current Liabilities	884.6	1,023.1
Deferred Credits and Other Liabilities
Regulatory liabilities	655.5	658.1
Deferred income taxes - long term	1,362.6	1,284.0
Pension and other benefit obligations	280.9	278.8
Other	220.1	225.7
Total Deferred Credits and Other Liabilities	2,519.1	2,446.6
Total Capitalization and Liabilities	$ 11,671.4	$ 11,661.3

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Document and Entity Information (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Jun. 30, 2011
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, 2012
Document Fiscal Year Focus	2012
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		$ 21.9

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Consolidated Condensed Statements of Cash Flows (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Operating Activities
Net Income	$ 115.9	$ 107.5
Reconciliation to cash
Depreciation and amortization	63.4	56.4
Deferred income taxes and investment tax credits, net	58.1	56.8
Contributions to qualified benefit plans	0	(107.1)
Change In
Accounts receivable and accrued revenues	36.2	(8.5)
Inventories	29.9	47.6
Other current assets	29.9	24.8
Accounts payable	(61.0)	(29.8)
Accrued income taxes, net	(6.8)	(18.8)
Other current liabilities	5.9	24.6
Other, net	(41.3)	56.2
Cash Provided by Operating Activities	230.2	209.7
Investing Activities
Capital expenditures	(117.1)	(112.5)
Investment in transmission affiliate	(2.3)	(2.3)
Proceeds from asset sales	2.7	38.3
Change in restricted cash	20.8	(37.2)
Other, net	(14.8)	(12.0)
Cash Used in Investing Activities	(110.7)	(125.7)
Financing Activities
Dividends paid on common stock	(44.9)	(44.9)
Dividends paid on preferred stock	(0.3)	(0.3)
Change in total short-term debt	(70.5)	(53.0)
Other, net	0	2.3
Cash Used in Financing Activities	(115.7)	(95.9)
Change in Cash and Cash Equivalents	3.8	(11.9)
Cash and Cash Equivalents at Beginning of Period	12.7	23.3
Cash and Cash Equivalents at End of Period	$ 16.5	$ 11.4

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Benefits

3 Months Ended

Mar. 31, 2012

General Discussion of Pension and Other Postretirement Benefits [Abstract]

Benefits [Text Block]

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
Benefit Plan Cost Components	2012			2011
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	5.0		$	4.1
Interest cost	14.2			14.5
Expected return on plan assets	(18.1		)	(16.1		)
Amortization of:
Prior service cost	0.5			0.5
Actuarial loss	7.3			5.8
Net Periodic Benefit Cost	$	8.9		$	8.8

	OPEB Costs
Benefit Plan Cost Components	2012			2011
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	2.7		$	2.7
Interest cost	4.2			4.3
Expected return on plan assets	(3.3		)	(2.8		)
Amortization of:
Transition obligation	0.1			0.1
Prior service (credit)	(0.5		)	(0.5		)
Actuarial loss	1.2			1.0
Net Periodic Benefit Cost	$	4.4		$	4.8

During the first quarter of 2011, we contributed $107.1 million 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 $3.3 million as of March 31, 2012 and

$12.2 million as of December 31, 2011.

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Derivative Instruments

3 Months Ended

Mar. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments [Text Block]

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. We do not offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivatives executed with the same counterparty under the same master netting arrangement. As of

March 31, 2012, we recognized $13.7 million in regulatory assets and $14.8 million in regulatory liabilities related to derivatives in comparison to $14.1 million in regulatory assets and $20.3 million in regulatory liabilities as of December 31, 2011.

We record our current derivative assets on the balance sheet in prepayments and other current assets and the current portion of the liabilities in other current liabilities. We had no long-term portion of derivative assets as of March 31, 2012, and the long-term portion of our derivative liabilities of $0.2 million is recorded in other deferred credits and other liabilities as of March 31, 2012. Our Consolidated Condensed Balance Sheets as of March 31, 2012 and December 31, 2011 include:

	March 31, 2012				December 31, 2011
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	1.0	$	6.6	$	0.7	$	4.6
Fuel Oil	0.9		—		0.3		0.1
FTRs	2.2		—		5.7		—
Coal	9.8		—		12.5		—
Total	$	13.9	$	6.6	$	19.2	$	4.7

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, 2012				Three Months Ended March 31, 2011
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)
Natural Gas	9.2 million Dth	$	(7.6	)	8.8 million Dth	$	(4.9	)
Fuel Oil	1.7 million gallons	0.6			3.2 million gallons	0.4
FTRs	5,358 MW	0.6			6,352 MW	3.8
Total		$	(6.4	)		$	(0.7	)

As of March 31, 2012 and December 31, 2011, we posted collateral of $8.3 million and $6.4 million, respectively, in our margin accounts. These amounts are recorded on the balance sheets in prepayments and other current assets.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2012

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. We have substantially completed planned remediation activities at some of these sites and certain other sites 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 $19 million over 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, 2012, we have established reserves of $6.4 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.

Valley Power Plant Title V Air Permit:   The WDNR renewed Valley Power Plant's (VAPP) Title V operating permit in February 2011. The term of the permit is five years. Sierra Club and Clean Wisconsin requested and were granted an administrative hearing before the WDNR on certain conditions of the permit. We filed a motion for partial summary judgment in that proceeding on March 22, 2012. If the case proceeds to hearing, it would be held in early 2013. The Sierra Club petitioned the United States Environmental Protection Agency (EPA) for additional reductions and monitoring for particulate matter, and revisions to certain applicable requirements. No timeline has been set by the EPA to respond to that petition.

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

We filed an application with the PSCW in December 2011 for authority to replace and upgrade the Lincoln Arthur natural gas main, which would also have the capability to accommodate the increased natural gas required if VAPP were to convert from coal to natural gas. Clean Wisconsin has requested intervenor status in the PSCW process.

We also submitted a letter to the EPA in December 2011 with four voluntary goals which include: (1) reducing annual Sulfur Dioxide (SO₂) emissions from the plant to no more than 4,500 tons (a 65% decrease from 2001 emission levels); (2) installing a dry sorbent injection system that is needed to meet the utility Maximum Achievable Control Technology (MACT) rules earlier than the rules require if the installation would provide a direct economic benefit to customers and is approved by the PSCW; (3) holding an open house and tour of VAPP in 2012 to help inform the community on the plant, the unique role that it plays in the community, and to share environmental successes and future plans; and (4) converting VAPP to natural gas fuel by the 2017/2018 timeframe, provided we can demonstrate a direct economic benefit to customers and obtain authorization from the PSCW to do so.

Divested Assets:   Pursuant to the sale of the Point Beach Nuclear Power Plant (Point Beach), we have agreed to indemnification provisions customary to transactions involving the sale of nuclear assets. We also provided customary indemnifications to WPL in connection with the sale of our interest in Edgewater Generating Unit 5. We have established reserves as deemed appropriate for these indemnification provisions.

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

In November 2011, the Plan entered into a settlement agreement with the plaintiffs for $45.0 million, and the court promptly issued an order preliminarily approving the settlement. As part of the settlement agreement, the Plan agreed to class certification for all similarly situated plaintiffs. The resolution of this matter resulted in a cost of less than $13 million for 2011 after considering insurance and reserves established in the prior year. The court approved the settlement on April 3, 2012 and issued its written order on April 20, 2012. The plaintiffs have 30 days from the date of the written order to appeal this decision.

We do not anticipate further charges as a result of the settlement, other than certain process-related costs we expect to incur to implement the settlement.

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

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Segment Information

3 Months Ended

Mar. 31, 2012

Segment Information [Abstract]

Segment Information [Text Block]

SEGMENT INFORMATION

Summarized financial information concerning our operating segments for the three months ended March 31, 2012 and 2011 is shown in the following table:

	Operating Segments
	Electric		Gas		Steam		Total
	(Millions of Dollars)
Three Months Ended
March 31, 2012
Operating Revenues (a)	$	777.3	$	156.7	$	12.6	$	946.6
Operating Income (Loss)	$	143.6	$	26.7	$	2.0	$	172.3
March 31, 2011
Operating Revenues (a)	$	776.6	$	214.4	$	15.2	$	1,006.2
Operating Income (Loss)	$	113.9	$	36.5	$	4.9	$	155.3

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

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Variable Interest Entities

3 Months Ended

Mar. 31, 2012

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

We also have a purchased power agreement for 236 MW of firm capacity from a gas-fired cogeneration facility, which we account for as a capital lease. The agreement includes no minimum energy requirements over the remaining term of approximately 10 years. We have examined the risks of the entity including operations and maintenance, dispatch, financing, fuel costs and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity and there is no residual guarantee associated with the purchased power agreement.

We have approximately $296.7 million of required payments over the remaining term of these agreements. We believe that the required lease payments under these contracts will continue to be recoverable in rates. Total capacity and lease payments under these contracts for the three months ended March 31, 2012 and 2011 were $14.7 million and $15.0 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contracts.

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Supplemental Cash Flow Information

3 Months Ended

Mar. 31, 2012

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information [Text Block]

SUPPLEMENTAL CASH FLOW INFORMATION

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. During the three months ended March 31, 2011, we paid $1.2 million in interest, capitalized $5.0 million of interest expense and paid $10.2 million in income taxes, net of refunds.

As of March 31, 2012 and 2011, the amount of accounts payable related to capital expenditures was $12.5 million and $19.4 million, respectively.

During the three months ended March 31, 2012 and 2011, our equity in earnings from ATC was $13.7 million and $13.6 million, respectively. During the three months ended March 31, 2012 and 2011, distributions received from ATC were $11.3 million and $10.9 million, respectively.

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General Information

3 Months Ended

Mar. 31, 2012

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 2011 Annual Report on Form 10-K. In the opinion of management, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of the results of operations, cash flows and financial position in the accompanying income statements, statements of cash flows and balance sheets. The results of operations for the three months ended March 31, 2012 are not necessarily indicative of the results which may be expected for the entire fiscal year 2012 because of seasonal and other factors.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2012

Fair Value Disclosures [Abstract]

Fair Value Measurements [Text Block]

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, 2012
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	24.7	$	—	$	—	$	24.7
Derivatives	0.9		10.8		2.2		13.9
Total	$	25.6	$	10.8	$	2.2	$	38.6
Liabilities:
Derivatives	$	6.5	$	0.1	$	—	$	6.6
Total	$	6.5	$	0.1	$	—	$	6.6

Recurring Fair Value Measures	As of December 31, 2011
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	45.5	$	—	$	—	$	45.5
Derivatives	0.3		13.2		5.7		19.2
Total	$	45.8	$	13.2	$	5.7	$	64.7
Liabilities:
Derivatives	$	4.3	$	0.4	$	—	$	4.7
Total	$	4.3	$	0.4	$	—	$	4.7

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

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

	2012			2011
	(Millions of Dollars)
Balance as of January 1	$	5.7		$	5.9
Realized and unrealized gains (losses)	—			—
Purchases	—			—
Issuances	—			—
Settlements	(3.5		)	(3.8		)
Transfers in and/or out of Level 3	—			—
Balance as of March 31	$	2.2		$	2.1
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 7 -- Derivative Instruments for further information on the offset to regulatory assets and liabilities.

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

	March 31, 2012				December 31, 2011
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	25.0	$	30.4	$	25.1
Long-term debt, including current portion	$	2,287.0	$	2,599.7	$	2,287.0	$	2,669.0

The carrying value of net accounts receivable, accounts payable and short-term borrowings approximates fair value due to the short-term nature of these instruments. The fair value of our preferred stock is estimated based upon the quoted market value for the same or similar issues. The fair value of our long-term debt, including the current portion of long-term debt, but excluding capitalized leases and unamortized discount on debt, is estimated based upon quoted market value for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows. Based on these assessments, the above items have been classified within Level 2.