WISCONSIN ELECTRIC POWER CO - Quarter Report: 2012 June (Form 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 June 30, 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 (June 30, 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 JUNE 30, 2012



	TABLE OF CONTENTS
Item		Page

	Introduction	7

	Part I -- Financial Information

1.	Financial Statements

	Consolidated Condensed Income Statements	8

	Consolidated Condensed Balance Sheets	9

	Consolidated Condensed Statements of Cash Flows	10

	Notes to Consolidated Condensed Financial Statements	11

2.	Management's Discussion and Analysis of
	Financial Condition and Results of Operations	22

3.	Quantitative and Qualitative Disclosures About Market Risk	34

4.	Controls and Procedures	34

	Part II -- Other Information

1.	Legal Proceedings	34

1A.	Risk Factors	35

6.	Exhibits	36

	Signatures	37



June 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
DOJ		Wisconsin Department of Justice
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
IRS		Internal Revenue Service
MPSC		Michigan Public Service Commission
PSCW		Public Service Commission of Wisconsin
SEC		Securities and Exchange Commission
WDNR		Wisconsin Department of Natural Resources

Environmental Terms
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CSAPR		Cross-State Air Pollution Rule
MACT		Maximum Achievable Control Technology
NOV		Notice of Violation
SO₂		Sulfur Dioxide

Other Terms and Abbreviations
AQCS		Air Quality Control System
ARRs		Auction Revenue Rights
Compensation Committee		Compensation Committee of the Board of Directors of Wisconsin Energy
ERISA		Employee Retirement Income Security Act of 1974
Exchange Act		Securities Exchange Act of 1934, as amended
FTRs		Financial Transmission Rights
LMP		Locational Marginal Price
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



June 2012	3	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:

PTF		Power the Future
WPL		Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corp.

Measurements
Btu		British Thermal Unit(s)
Dth		Dekatherm(s) (One Dth equals one million Btu)
MW		Megawatt(s) (One MW equals one million Watts)
MWh		Megawatt-hour(s)
Watt		A measure of power production or usage

Accounting Terms
AFUDC		Allowance for Funds Used During Construction
FASB		Financial Accounting Standards Board
GAAP		Generally Accepted Accounting Principles
OPEB		Other Post-Retirement Employee Benefits



June 2012	4	Wisconsin Electric Power Company

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.



June 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, including rules recently adopted and/or proposed by the U.S. Commodity Futures Trading Commission that may impact our hedging activities and related costs.


•	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.



June 2012	6	Wisconsin Electric Power Company

Form 10-Q

INTRODUCTION

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

We conduct our operations primarily in three reportable segments: an electric utility segment, a natural gas utility segment and a steam utility segment. We serve approximately 1,122,900 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 466,400 gas customers in Wisconsin and approximately 460 steam customers in metropolitan Milwaukee, Wisconsin. For further financial information about our reportable segments, see Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 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 June 30, 2012, Bostco had $31.9 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.



June 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 June 30				Six Months Ended June 30
	2012		2011		2012		2011
	(Millions of Dollars)
Operating Revenues	$	840.6	$	853.3	$	1,787.2	$	1,859.5

Operating Expenses
Fuel and purchased power	260.0		287.2		515.1		556.0
Cost of gas sold	31.9		50.2		132.1		196.4
Other operation and maintenance	324.4		353.8		654.0		709.2
Depreciation and amortization	63.8		54.8		125.0		109.2
Property and revenue taxes	28.2		26.1		56.4		52.2
Total Operating Expenses	708.3		772.1		1,482.6		1,623.0

Operating Income	132.3		81.2		304.6		236.5

Equity in Earnings of Transmission Affiliate	14.3		13.4		28.0		27.0
Other Income, net	8.0		13.7		23.9		26.0
Interest Expense, net	28.0		23.3		53.2		47.5

Income Before Income Taxes	126.6		85.0		303.3		242.0

Income Tax Expense	43.3		26.9		104.1		76.4

Net Income	83.3		58.1		199.2		165.6

Preferred Stock Dividend Requirement	0.3		0.3		0.6		0.6

Earnings Available for Common Stockholder	$	83.0	$	57.8	$	198.6	$	165.0

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



June 2012	8	Wisconsin Electric Power Company

Form 10-Q



WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited)

	June 30, 2012			December 31, 2011
	(Millions of Dollars)
Assets
Property, Plant and Equipment
In service	$	8,987.6		$	8,416.2
Accumulated depreciation	(3,039.4		)	(2,964.7		)
	5,948.2			5,451.5
Construction work in progress	583.0			902.4
Leased facilities, net	2,389.1			2,428.2
Net Property, Plant and Equipment	8,920.3			8,782.1
Investments
Equity investment in transmission affiliate	318.4			307.5
Other	0.3			0.2
Total Investments	318.7			307.7
Current Assets
Cash and cash equivalents	12.0			12.7
Restricted cash	17.9			45.5
Accounts receivable, net	244.4			274.2
Accounts receivable from related parties	9.8			36.5
Income taxes receivable	129.1			99.4
Accrued revenues	190.6			200.5
Materials, supplies and inventories	300.3			319.2
Prepayments and other	170.1			182.0
Total Current Assets	1,074.2			1,170.0
Deferred Charges and Other Assets
Regulatory assets	1,353.7			1,236.2
Other	148.1			165.3
Total Deferred Charges and Other Assets	1,501.8			1,401.5
Total Assets	$	11,815.0		$	11,661.3

Capitalization and Liabilities
Capitalization
Common equity	$	3,287.2		$	3,177.1
Preferred stock	30.4			30.4
Long-term debt	1,968.6			2,267.6
Capital lease obligations	2,715.1			2,716.5
Total Capitalization	8,001.3			8,191.6
Current Liabilities
Long-term debt and capital lease obligations due currently	347.2			37.9
Short-term debt	324.2			352.0
Subsidiary note payable to Wisconsin Energy	24.1			26.8
Accounts payable	229.5			265.2
Accounts payable to related parties	100.5			94.6
Accrued payroll and vacation	57.7			73.2
Other	129.6			173.4
Total Current Liabilities	1,212.8			1,023.1
Deferred Credits and Other Liabilities
Regulatory liabilities	649.9			658.1
Deferred income taxes - long-term	1,420.2			1,284.0
Pension and other benefit obligations	313.8			278.8
Other	217.0			225.7
Total Deferred Credits and Other Liabilities	2,600.9			2,446.6
Total Capitalization and Liabilities	$	11,815.0		$	11,661.3

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



June 2012	9	Wisconsin Electric Power Company

Form 10-Q



WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)

	Six Months Ended June 30
	2012			2011
	(Millions of Dollars)
Operating Activities
Net income	$	199.2		$	165.6
Reconciliation to cash
Depreciation and amortization	129.4			113.2
Deferred income taxes and investment tax credits, net	118.9			100.0
Contributions to qualified benefit plans	—			(107.1		)
Change in - Accounts receivable and accrued revenues	65.2			35.3
Inventories	18.9			25.4
Other current assets	12.8			5.0
Accounts payable	(31.9		)	(4.3		)
Accrued income taxes, net	(29.8		)	(22.3		)
Other current liabilities	(31.2		)	(2.7		)
Other, net	(68.6		)	62.0
Cash Provided by Operating Activities	382.9			370.1

Investing Activities
Capital expenditures	(258.2		)	(293.4		)
Investment in transmission affiliate	(5.8		)	(4.0		)
Proceeds from asset sales	2.7			38.5
Change in restricted cash	27.6			(37.2		)
Other, net	(29.0		)	(24.3		)
Cash Used in Investing Activities	(262.7		)	(320.4		)

Financing Activities
Dividends paid on common stock	(89.8		)	(89.8		)
Dividends paid on preferred stock	(0.6		)	(0.6		)
Change in total short-term debt	(30.5		)	22.4
Other, net	—			4.7
Cash Used in Financing Activities	(120.9		)	(63.3		)

Change in Cash and Cash Equivalents	(0.7		)	(13.6		)

Cash and Cash Equivalents at Beginning of Period	12.7			23.3

Cash and Cash Equivalents at End of Period	$	12.0		$	9.7

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



June 2012	10	Wisconsin Electric Power Company

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 and six months ended June 30, 2012 are not necessarily indicative of the results which may be expected for the entire fiscal year 2012 because of seasonal and other factors.

2 -- NEW ACCOUNTING PRONOUNCEMENTS

Presentation of Comprehensive Income: In June 2011, the Financial Accounting Standards Board (FASB) issued guidance on the presentation of comprehensive income. The guidance gives entities the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. This guidance is effective for fiscal years and interim periods beginning after December 15, 2011 and must be applied retrospectively. We adopted this guidance on January 1, 2012, and it did not have any material impact on us.

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

3 -- COMMON EQUITY

Stock Option Activity: During the first six 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 six 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.



June 2012	11	Wisconsin Electric Power Company

Form 10-Q

The following is a summary of Wisconsin Energy stock option activity by our employees during the three and six months ended June 30, 2012:



					Weighted-
					Average
			Weighted-		Remaining	Aggregate
	Number of		Average		Contractual Life	Intrinsic Value
Stock Options	Options		Exercise Price		(Years)	(Millions)
Outstanding as of April 1, 2012	10,210,668		$	23.15
Granted	—		$	—
Exercised	(1,232,784	)	$	20.12
Forfeited	—		$	—
Outstanding as of June 30, 2012	8,977,884		$	23.56

Outstanding as of January 1, 2012	9,907,526		$	21.76
Granted	903,865		$	34.88
Exercised	(1,833,507	)	$	19.42
Forfeited	—		$	—
Outstanding as of June 30, 2012	8,977,884		$	23.56	5.6	$	143.7

Exercisable as of June 30, 2012	7,322,624		$	21.89	4.9	$	129.5

The intrinsic value of Wisconsin Energy options exercised by our employees was $20.8 million and $30.9 million for the three and six months ended June 30, 2012, and $9.4 million and $17.6 million for the same periods in 2011, respectively. Cash received by Wisconsin Energy from exercises of its options by our employees was $35.6 million and $27.9 million for the six months ended June 30, 2012 and 2011, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was zero and approximately $7.1 million, respectively.

The following table summarizes information about Wisconsin Energy stock options held by our employees and outstanding as of June 30, 2012:



	Options Outstanding				Options Exercisable
		Weighted-Average				Weighted-Average
				Remaining				Remaining
	Number of	Exercise		Contractual	Number of	Exercise		Contractual
Range of Exercise Prices	Options	Price		Life (Years)	Options	Price		Life (Years)
$12.71 to $19.74	1,972,072	$	18.32	2.8	1,972,072	$	18.32	2.8
$21.11 to $24.92	5,673,007	$	23.15	5.7	5,238,007	$	23.00	5.6
$29.35 to $34.88	1,332,805	$	33.10	9.2	112,545	$	32.68	9.1
	8,977,884	$	23.56	5.6	7,322,624	$	21.89	4.9



June 2012	12	Wisconsin Electric Power Company

Form 10-Q

The following table summarizes information about our employees' non-vested Wisconsin Energy stock options during the three and six months ended June 30, 2012:



			Weighted-Average
Non-Vested Stock Options	Number of Options		Fair Value
Non-vested as of April 1, 2012	1,661,865		$	3.31
Granted	—		$	—
Vested	(6,605	)	$	3.30
Forfeited	—		$	—
Non-vested as of June 30, 2012	1,655,260		$	3.31

Non-vested as of January 1, 2012	2,953,580		$	3.78
Granted	903,865		$	3.34
Vested	(2,202,185	)	$	3.96
Forfeited	—		$	—
Non-vested as of June 30, 2012	1,655,260		$	3.31

As of June 30, 2012, our total compensation costs related to non-vested Wisconsin Energy stock options held by our employees and not yet recognized was approximately $2.3 million, which is expected to be recognized over the next 18 months on a weighted-average basis.

Restricted Shares: During the first six 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 and six months ended June 30, 2012:



			Weighted-Average
Restricted Shares	Number of Shares		Grant Date Fair Value
Outstanding as of April 1, 2012	140,790
Granted	—		$	—
Released	(7,902	)	$	12.66
Forfeited	(453	)	$	31.02
Outstanding as of June 30, 2012	132,435

Outstanding as of January 1, 2012	115,946
Granted	71,496		$	34.46
Released	(50,332	)	$	25.02
Forfeited	(4,675	)	$	26.32
Outstanding as of June 30, 2012	132,435

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 $0.3 million and $1.9 million for the three and six months ended June 30, 2012, and $0.2 million and $1.5 million for the same periods in 2011, respectively. The actual tax benefit realized for the tax deductions from released restricted shares for the same periods was zero for the three and six months ended June 30, 2012, and $0.1 million and $0.6 million for the same periods in 2011, respectively.

As of June 30, 2012, total compensation cost related to our share of Wisconsin Energy restricted stock not yet recognized was approximately $2.9 million, which is expected to be recognized over the next 25 months on a



June 2012	13	Wisconsin Electric Power Company

Form 10-Q

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 June 30, 2012, total compensation cost related to our share of Wisconsin Energy performance units not yet recognized was approximately $25.2 million, which is expected to be recognized over the next 20 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 and six months ended June 30, 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 June 30, 2012 and will decrease to zero over the remaining life of the contract.

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

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



June 2012	14	Wisconsin Electric Power Company

Form 10-Q

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 June 30, 2012
	Level 1		Level 2		Level 3		Total
	(Millions of Dollars)
Assets:
Restricted Cash	$	17.9	$	—	$	—	$	17.9
Derivatives	1.3		10.7		9.9		21.9
Total	$	19.2	$	10.7	$	9.9	$	39.8

Liabilities:
Derivatives	$	0.5	$	7.4	$	—	$	7.9
Total	$	0.5	$	7.4	$	—	$	7.9



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-



June 2012	15	Wisconsin Electric Power Company

Form 10-Q

traded derivative contracts and OTC derivative contracts. Exchange-traded derivative contracts, which include futures and exchange-traded options, are generally based on unadjusted quoted prices in active markets and are classified within Level 1. Some OTC derivative contracts are valued using broker or dealer quotations, or market transactions in either the listed or OTC markets utilizing a mid-market pricing convention (the mid-point between bid and ask prices), as appropriate. In such cases, these derivatives are classified within Level 2. Certain OTC derivatives may utilize models to measure fair value. Generally, we use a similar model to value similar instruments. Valuation models utilize various inputs which include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs (i.e., inputs derived principally from or corroborated by observable market data by correlation or other means). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Certain OTC derivatives are in less active markets with a lower availability of pricing information which might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in Level 3.

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



	Three Months Ended June 30						Six Months Ended June 30
	2012			2011			2012			2011
	(Millions of Dollars)

Beginning Balance	$	2.2		$	2.1		$	5.7		$	5.9
Realized and unrealized gains (losses)	—			—			—			—
Purchases	10.9			16.1			10.9			16.1
Issuances	—			—			—			—
Settlements	(3.2		)	(3.6		)	(6.7		)	(7.4		)
Transfers in and/or out of Level 3	—			—			—			—
Balance as of June 30	$	9.9		$	14.6		$	9.9		$	14.6

Change in unrealized gains (losses) relating to instruments still held as of June 30	$	—		$	—		$	—		$	—

Derivative instruments reflected in Level 3 of the hierarchy include MISO Financial Transmission Rights (FTRs) that are measured at fair value each reporting period using monthly or annual auction shadow prices from relevant auctions. Changes in fair value for Level 3 recurring items are recorded on our balance sheet. See Note 7 -- Derivative Instruments for further information on the offset to regulatory assets and liabilities.

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



	June 30, 2012				December 31, 2011
Financial Instruments	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(Millions of Dollars)
Preferred stock, no redemption required	$	30.4	$	26.1	$	30.4	$	25.1
Long-term debt, including current portion	$	2,287.0	$	2,676.9	$	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.



June 2012	16	Wisconsin Electric Power Company

Form 10-Q

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 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

June 30, 2012, we recognized $11.8 million in regulatory assets and $20.6 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. The long-term portion of our derivative assets of $0.1 million is recorded in other deferred charges and other assets as of June 30, 2012, and the long-term portion of our derivative liabilities of $1.5 million is recorded in other deferred credits and other liabilities as of June 30, 2012. Our Consolidated Condensed Balance Sheets as of June 30, 2012 and December 31, 2011 include:



	June 30, 2012				December 31, 2011
	Derivative Asset		Derivative Liability		Derivative Asset		Derivative Liability
	(Millions of Dollars)
Natural Gas	$	2.2	$	—	$	0.7	$	4.6
Fuel Oil	—		0.5		0.3		0.1
FTRs	9.9		—		5.7		—
Coal	9.8		7.4		12.5		—
Total	$	21.9	$	7.9	$	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 June 30, 2012				Three Months Ended June 30, 2011
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)

Natural Gas	8.9 million Dth	$	(6.8	)	8.0 million Dth	$	(2.9	)
Fuel Oil	2.1 million gallons	0.8			3.4 million gallons	2.1
FTRs	5,296 MW	1.6			6,191 MW	1.5
Total		$	(4.4	)		$	0.7



	Six Months Ended June 30, 2012				Six Months Ended June 30, 2011
	Volume	Gains (Losses)			Volume	Gains (Losses)
		(Millions of Dollars)				(Millions of Dollars)

Natural Gas	18.1 million Dth	$	(14.4	)	16.8 million Dth	$	(7.8	)
Fuel Oil	3.8 million gallons	1.4			6.6 million gallons	2.5
FTRs	10,654 MW	2.2			12,543 MW	5.3
Total		$	(10.8	)		$	—



June 2012	17	Wisconsin Electric Power Company

Form 10-Q

As of June 30, 2012 and December 31, 2011, we posted collateral of $5.3 million and $6.4 million, respectively, in our margin accounts. These amounts are recorded on the balance sheets in other current assets.

8 -- BENEFITS

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



	Pension Costs
	Three Months Ended June 30						Six Months Ended June 30
Benefit Plan Cost Components	2012			2011			2012			2011
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	4.9		$	3.2		$	9.9		$	7.3
Interest cost	14.2			14.7			28.4			29.2
Expected return on plan assets	(17.8		)	(15.8		)	(35.9		)	(31.9		)
Amortization of:
Prior service cost	0.6			0.6			1.1			1.1
Actuarial loss	7.7			6.3			15.0			12.1
Net Periodic Benefit Cost	$	9.6		$	9.0		$	18.5		$	17.8



	OPEB Costs
	Three Months Ended June 30						Six Months Ended June 30
Benefit Plan Cost Components	2012			2011			2012			2011
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$	2.2		$	2.3		$	4.9		$	5.0
Interest cost	4.2			4.2			8.4			8.5
Expected return on plan assets	(3.2		)	(2.8		)	(6.5		)	(5.6		)
Amortization of:
Transition obligation	0.1			0.1			0.2			0.2
Prior service (credit)	(0.4		)	(0.5		)	(0.9		)	(1.0		)
Actuarial loss	1.2			1.1			2.4			2.1
Net Periodic Benefit Cost	$	4.1		$	4.4		$	8.5		$	9.2

During the first six months of 2011, we contributed $107.1 million to our qualified benefit plans. No such contributions were made during the first six months of 2012. 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 June 30, 2012 and

$12.2 million as of December 31, 2011.



June 2012	18	Wisconsin Electric Power Company

Form 10-Q

9 -- SEGMENT INFORMATION

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



	Reportable Segments
	Electric		Gas		Steam			Total
	(Millions of Dollars)
Three Months Ended

June 30, 2012
Operating Revenues (a)	$	772.6	$	61.2	$	6.8		$	840.6
Operating Income (Loss)	$	132.6	$	1.6	$	(1.9	)	$	132.3

June 30, 2011
Operating Revenues (a)	$	762.6	$	83.2	$	7.5		$	853.3
Operating Income (Loss)	$	79.9	$	3.6	$	(2.3	)	$	81.2

Six Months Ended

June 30, 2012
Operating Revenues (a)	$	1,549.9	$	217.9	$	19.4		$	1,787.2
Operating Income	$	276.2	$	28.3	$	0.1		$	304.6

June 30, 2011
Operating Revenues (a)	$	1,539.2	$	297.6	$	22.7		$	1,859.5
Operating Income	$	193.8	$	40.1	$	2.6		$	236.5


(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



June 2012	19	Wisconsin Electric Power Company

Form 10-Q

associated with the purchased power agreement.

We have approximately $283.4 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 six months ended June 30, 2012 and 2011 were $29.6 million and $32.1 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contracts.

11 -- COMMITMENTS AND CONTINGENCIES

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

We have a program of comprehensive environmental remediation planning for former manufactured gas plant sites and coal-combustion product disposal sites. We perform ongoing assessments of 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 June 30, 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 in March 2012. If the case proceeds to hearing, it would be held in early 2013. In March 2011, the Sierra Club also petitioned the United States Environmental Protection Agency (EPA) for additional reductions and monitoring for particulate matter, and revisions to certain applicable requirements. No timeline has been set by the EPA to respond to that petition. In May 2012, the Sierra Club filed a notice of intent to bring suit to force the EPA to issue a response to that petition.

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

We 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.



June 2012	20	Wisconsin Electric Power Company

Form 10-Q

Divested Assets: Pursuant to the sale of the Point Beach Nuclear Power Plant (Point Beach), we have agreed to indemnification provisions customary to transactions involving the sale of nuclear assets. We also provided customary indemnifications to WPL in connection with the sale of our interest in Edgewater Generating Unit 5. 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. Substantially all payments to class members have been made pursuant to the settlement. We do not anticipate further charges as a result of the settlement.

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

12 -- SUPPLEMENTAL CASH FLOW INFORMATION

During the six months ended June 30, 2012, we paid $52.5 million in interest, net of amounts capitalized, and paid $14.6 million in income taxes, net of refunds. During the six months ended June 30, 2011, we paid $46.6 million in interest, net of amounts capitalized, and received $6.3 million in net refunds from income taxes.

As of June 30, 2012 and 2011, the amount of accounts payable related to capital expenditures was $18.8 million and $50.5 million, respectively.

During the six months ended June 30, 2012 and 2011, our equity in earnings from ATC was $28.0 million and $27.0 million, respectively. During the six months ended June 30, 2012 and 2011, distributions received from ATC were $22.7 million and $21.6 million, respectively.



June 2012	21	Wisconsin Electric Power Company

Form 10-Q

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

AND RESULTS OF OPERATIONS

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

Electric Utility Revenues and Sales

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



	Three Months Ended June 30
	Electric Revenues							MWh Sales
Electric Utility Operations	2012		B (W)			2011		2012	B (W)		2011
	(Millions of Dollars)							(Thousands)
Customer Class
Residential	$	276.9	$	17.1		$	259.8	1,988.6	153.0		1,835.6
Small Commercial/Industrial	249.7		9.0			240.7		2,169.4	104.2		2,065.2
Large Commercial/Industrial	183.9		(9.5		)	193.4		2,409.3	(92.8	)	2,502.1
Other - Retail	5.2		—			5.2		36.2	1.3		34.9
Total Retail	715.7		16.6			699.1		6,603.5	165.7		6,437.8
Wholesale - Other	35.6		(4.3		)	39.9		368.7	(157.4	)	526.1
Resale - Utilities	8.4		(6.8		)	15.2		198.7	(238.9	)	437.6
Other Operating Revenues	12.9		4.5			8.4		—	—		—
Total	$	772.6	$	10.0		$	762.6	7,170.9	(230.6	)	7,401.5

Weather -- Degree Days (a)
Heating (953 Normal)								765	(272	)	1,037
Cooling (159 Normal)								295	182		113

(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 $10.0 million, or 1.3%, when compared to the second quarter of 2011. The most significant factors that caused a change in revenues were:


•	Favorable weather as compared to the prior year that increased electric revenues by an estimated $40.1 million.


•	Net pricing decreases totaling $12.3 million, which primarily includes a reserve of $10.8 million related to Wisconsin fuel recoveries as a result of lower actual fuel costs than were included in the most recent Wisconsin fuel filing approved by the PSCW.


•	An increase in other operating revenues of $7.1 million related to the amortization of 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.


•	A $6.8 million reduction in sales for resale due to reduced sales into the MISO Energy Markets.

As measured by cooling degree days, the second quarter of 2012 was 161.1% warmer than the same period in 2011 and 85.5% warmer than normal. The growth in residential and small commercial/industrial sales was primarily driven by the warmer weather. The decrease in large commercial/industrial sales was driven by lower sales to the two iron ore mines in Michigan. If these customers are excluded, sales to our large commercial/industrial customers increased by 0.6%. Wholesale sales decreased primarily due to the low market price of power in 2012 as compared to 2011, which caused some of these customers to obtain energy from the MISO market rather than through our contracts. This reduction did not impact the majority of revenue received from these customers, which is tied to demand.



June 2012	22	Wisconsin Electric Power Company

Form 10-Q

Fuel and Purchased Power

Our fuel and purchased power costs decreased by $27.2 million, or 9.5%, when compared to the second quarter of 2011. This decrease was primarily caused by a 3.1% decrease in total MWh sales and a reduction in our average cost of fuel and purchased power because of lower natural gas prices.

Gas Utility Revenues, Gross Margin and Therm Deliveries

A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the second quarter of 2012 with the second quarter of 2011. We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under gas cost recovery mechanisms. Between the comparative periods, total gas operating revenues decreased by $22.0 million, or 26.4%, and cost of gas sold decreased by $18.3 million, or 36.5%, due to the significantly warmer weather, which resulted in lower therm deliveries, and a decline in the commodity cost of natural gas.



	Three Months Ended June 30
	2012		B (W)			2011
	(Millions of Dollars)

Gas Operating Revenues	$	61.2	$	(22.0	)	$	83.2
Cost of Gas Sold	31.9		18.3			50.2
Gross Margin	$	29.3	$	(3.7	)	$	33.0

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



	Three Months Ended June 30
	Gross Margin							Therm Deliveries
Gas Utility Operations	2012		B (W)			2011		2012	B (W)		2011
	(Millions of Dollars)							(Millions)
Customer Class
Residential	$	19.8	$	(2.2	)	$	22.0	41.2	(11.4	)	52.6
Commercial/Industrial	5.1		(1.6		)	6.7		21.5	(10.2	)	31.7
Interruptible	0.2		0.1			0.1		0.9	(0.2	)	1.1
Total Retail	25.1		(3.7		)	28.8		63.6	(21.8	)	85.4
Transported Gas	3.9		0.1			3.8		86.8	18.5		68.3
Other	0.3		(0.1		)	0.4		—	—		—
Total	$	29.3	$	(3.7	)	$	33.0	150.4	(3.3	)	153.7

Weather -- Degree Days (a)
Heating (953 Normal)								765	(272	)	1,037

(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 $3.7 million, or approximately 11.2%, when compared to the second quarter of 2011. This decrease primarily relates to a decrease in sales volumes as a result of warmer weather during the second quarter of 2012 that decreased heating loads. As measured by heating degree days, the second quarter of 2012 was 26.2% warmer than the same period in 2011 and 19.7% warmer than normal. Transported gas volumes for the second quarter of 2012 increased by 27.1% as compared to the same period in 2011. Virtually all of the volume increase related to gas used in electric generation, which has a small impact on margin. This margin increase was more than offset by a reduction in transportation volumes delivered to higher margin classes that are more weather sensitive than our large transport customers.

Other Operation and Maintenance Expense

Our other operation and maintenance expense decreased by $29.4 million, or approximately 8.3%, when compared



June 2012	23	Wisconsin Electric Power Company

Form 10-Q

to the second 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 $9.0 million, or approximately 16.4%, when compared to the second quarter of 2011, primarily because of an overall increase in utility plant in service. The Glacier Hills Wind Park went into service in December 2011, and the emission control equipment for units 5 and 6 of the Oak Creek Air Quality Control System (AQCS) project went into service in March 2012. We expect depreciation expense to continue to increase in 2012 once the emission control equipment for units 7 and 8 of the Oak Creek AQCS project is completed, which we are targeting by the end of summer 2012. For additional information, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters -- Oak Creek Air Quality Control System.

Other Income, net



	Three Months Ended June 30
Other Income, net	2012		B (W)			2011
	(Millions of Dollars)

AFUDC - Equity	$	7.9	$	(5.5	)	$	13.4
Other	0.1		(0.2		)	0.3
Other Income, net	$	8.0	$	(5.7	)	$	13.7

Other income, net decreased by $5.7 million, or approximately 41.6%, when compared to the second quarter of 2011. The decrease in AFUDC - Equity is primarily related to the Glacier Hills Wind Park, which went into service in December 2011, and the emission control equipment for units 5 and 6 of the Oak Creek AQCS project, which went into service in March 2012. We expect AFUDC - Equity to continue to decrease in 2012 once the emission control equipment for units 7 and 8 of the Oak Creek AQCS project is completed, which we are targeting by the end of summer 2012. 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 June 30
Interest Expense	2012		B (W)			2011
	(Millions of Dollars)

Gross Interest Costs	$	31.3	$	(2.4	)	$	28.9
Less: Capitalized Interest	3.3		(2.3		)	5.6
Interest Expense, net	$	28.0	$	(4.7	)	$	23.3

Our gross interest costs increased by $2.4 million, or approximately 8.3%, when compared to the second quarter of 2011 primarily because we issued $300 million of long-term debt in September 2011. Our capitalized interest decreased by $2.3 million primarily because of lower construction work in progress. As a result, our net interest expense increased by $4.7 million, or 20.2%, as compared to the second quarter of 2011.

Income Tax Expense

For the second quarter of 2012, our effective tax rate was 34.2% compared to 31.6% for the second quarter of 2011, primarily due to a decrease in the projected 2012 annual tax benefits associated with AFUDC - Equity. For additional information, see Note G -- Income Taxes in our 2011 Annual Report on Form 10-K.



June 2012	24	Wisconsin Electric Power Company

Form 10-Q

RESULTS OF OPERATIONS -- SIX MONTHS ENDED JUNE 30, 2012

Electric Utility Revenues and Sales

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



	Six Months Ended June 30
	Electric Revenues							MWh Sales
Electric Utility Operations	2012		B (W)			2011		2012	B (W)		2011
	(Millions of Dollars)							(Thousands)
Customer Class
Residential	$	551.5	$	8.7		$	542.8	3,931.5	65.9		3,865.6
Small Commercial/Industrial	494.9		7.8			487.1		4,321.0	57.1		4,263.9
Large Commercial/Industrial	368.3		(3.7		)	372.0		4,853.6	(22.2	)	4,875.8
Other - Retail	11.2		(0.1		)	11.3		76.6	1.7		74.9
Total Retail	1,425.9		12.7			1,413.2		13,182.7	102.5		13,080.2
Wholesale - Other	72.3		(3.6		)	75.9		701.4	(303.5	)	1,004.9
Resale - Utilities	25.4		(7.3		)	32.7		795.8	(210.4	)	1,006.2
Other Operating Revenues	26.3		8.9			17.4		—	—		—
Total	$	1,549.9	$	10.7		$	1,539.2	14,679.9	(411.4	)	15,091.3
Weather -- Degree Days (a)
Heating (4,259 Normal)								3,375	(1,106	)	4,481
Cooling (160 Normal)								306	193		113

(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 $10.7 million, or 0.7%, when compared to the first six months of 2011. The most significant factors that caused a change in revenues were:


•	Favorable weather as compared to the prior year that increased electric revenues by an estimated $20.7 million.


•	An increase in other operating revenues of $13.8 million related to the amortization of the DOE settlement used to offset an increase in fuel costs authorized by the PSCW.


•	A decrease in revenues resulting from a reserve of $10.8 million related to Wisconsin fuel recoveries as a result of lower actual fuel costs than were included in the most recent Wisconsin fuel filing approved by the PSCW.


•	A $7.3 million reduction in sales for resale due to reduced sales into the MISO Energy Markets.

As measured by cooling degree days, the first six months of 2012 were 170.8% warmer than the same period in 2011 and 91.3% warmer than normal. The growth in residential and small commercial/industrial sales was primarily driven by the warmer weather. The decrease in large commercial/industrial sales was driven by lower sales to the two iron ore mines in Michigan. If these customers are excluded, sales to our large commercial/industrial customers increased by 0.8%. Wholesale sales decreased primarily due to the low market price of power in 2012 as compared to 2011, which caused some of these customers to obtain energy from the MISO market rather than through our contracts. This reduction did not impact the majority of revenue received from these customers, which is tied to demand.

Fuel and Purchased Power

Our fuel and purchased power costs decreased by $40.9 million, or 7.4%, when compared to the first six months of 2011. This decrease was primarily caused by a 2.7% decrease in total MWh sales and a reduction in our average cost of fuel and purchased power because of lower natural gas prices.



June 2012	25	Wisconsin Electric Power Company

Form 10-Q

Gas Utility Revenues, Gross Margin and Therm Deliveries

A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the first six months of 2012 with the first six months of 2011. We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under gas cost recovery mechanisms. Between the comparative periods, total gas operating revenues decreased by $79.7 million, or 26.8%, and cost of gas sold decreased by $64.3 million, or 32.7%, due to the significantly warmer weather, which resulted in lower therm deliveries, and a decline in the commodity cost of natural gas.



	Six Months Ended June 30
	2012		B (W)			2011
	(Millions of Dollars)

Gas Operating Revenues	$	217.9	$	(79.7	)	$	297.6
Cost of Gas Sold	132.1		64.3			196.4
Gross Margin	$	85.8	$	(15.4	)	$	101.2

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



	Six Months Ended June 30
	Gross Margin							Therm Deliveries
Gas Utility Operations	2012		B (W)			2011		2012	B (W)		2011
	(Millions of Dollars)							(Millions)
Customer Class
Residential	$	58.0	$	(10.0	)	$	68.0	171.0	(51.7	)	222.7
Commercial/Industrial	18.4		(5.0		)	23.4		94.5	(32.3	)	126.8
Interruptible	0.3		—			0.3		2.6	(0.7	)	3.3
Total Retail	76.7		(15.0		)	91.7		268.1	(84.7	)	352.8
Transported Gas	8.3		(0.2		)	8.5		174.4	13.6		160.8
Other	0.8		(0.2		)	1.0		—	—		—
Total	$	85.8	$	(15.4	)	$	101.2	442.5	(71.1	)	513.6

Weather -- Degree Days (a)
Heating (4,259 Normal)								3,375	(1,106	)	4,481

(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 $15.4 million, or approximately 15.2%, when compared to the first six months of 2011. This decrease primarily relates to a decrease in sales volumes as a result of warmer weather during the first six months of 2012 that decreased heating loads. As measured by heating degree days, the first six months of 2012 were 24.7% warmer than the same period in 2011 and 20.8% warmer than normal. Transported gas volumes for the first six months of 2012 increased by 8.5% as compared to the same period in 2011. Virtually all of the volume increase related to gas used in electric generation, which has a small impact on margin. This margin increase was more than offset by a reduction in transportation volumes delivered to higher margin classes that are more weather sensitive than our large transport customers.

Other Operation and Maintenance Expense

Our other operation and maintenance expense decreased by $55.2 million, or approximately 7.8%, when compared to the first six months of 2011, primarily due to the one year suspension of $148 million of amortization expense on certain regulatory assets as authorized under our 2012 Wisconsin Rate Case. For additional information on the 2012 rate case, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters.



June 2012	26	Wisconsin Electric Power Company

Form 10-Q

Depreciation and Amortization Expense

Our depreciation and amortization expense increased by $15.8 million, or approximately 14.5%, when compared to the first six months of 2011, primarily because of an overall increase in utility plant in service. The Glacier Hills Wind Park went into service in December 2011, and the emission control equipment for units 5 and 6 of the Oak Creek AQCS project went into service in March 2012.

Other Income, net



	Six Months Ended June 30
Other Income, net	2012		B (W)			2011
	(Millions of Dollars)

AFUDC - Equity	$	22.6	$	(2.9	)	$	25.5
Other	1.3		0.8			0.5
Other Income, net	$	23.9	$	(2.1	)	$	26.0

Other income, net decreased by $2.1 million, or approximately 8.1%, when compared to the first six months of 2011. The decrease in AFUDC - Equity is primarily related to the Glacier Hills Wind Park, which went into service in December 2011, and the emission control equipment for units 5 and 6 of the Oak Creek AQCS project, which went into service in March 2012. We expect AFUDC - Equity to continue to decrease in 2012 once the emission control equipment for units 7 and 8 of the Oak Creek AQCS project is completed, which we are targeting by the end of summer 2012. For additional information, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters -- Oak Creek Air Quality Control System.

Interest Expense, net



	Six Months Ended June 30
Interest Expense	2012		B (W)			2011
	(Millions of Dollars)

Gross Interest Costs	$	62.6	$	(4.5	)	$	58.1
Less: Capitalized Interest	9.4		(1.2		)	10.6
Interest Expense, net	$	53.2	$	(5.7	)	$	47.5

Our gross interest costs increased by $4.5 million, or 7.7%, when compared to the first six months of 2011 primarily because we issued $300 million of long-term debt in September 2011. Our capitalized interest decreased by $1.2 million primarily because of lower construction work in progress. As a result, our net interest expense increased by $5.7 million, or 12.0%, as compared to the first six months of 2011.

Income Taxes

For the first six months of 2012, our effective tax rate was 34.3% compared to 31.6% for the first six months of 2011, primarily due to a decrease in the projected 2012 annual tax benefits associated with AFUDC - Equity. 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%.



June 2012	27	Wisconsin Electric Power Company

Form 10-Q

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

The following summarizes our cash flows during the six months ended June 30:



	2012			2011
	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$	382.9		$	370.1
Investing Activities	$	(262.7	)	$	(320.4	)
Financing Activities	$	(120.9	)	$	(63.3	)

Operating Activities

Cash provided by operating activities increased by $12.8 million during the first six months 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 six months of 2011. We made no such contributions to our qualified plans in the first six months of 2012. In the first six months of 2011, we expensed approximately $74.0 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 $57.7 million during the first six months of 2012 as compared to the same period in 2011. Our capital expenditures decreased by $35.2 million during the first six months of 2012 as compared to the same period in 2011, primarily because of decreased spending on the Oak Creek AQCS project. During the first six months of 2011, we received proceeds from asset sales totaling $38.5 million, which primarily relates to the sale of our interest in Edgewater Generating Unit 5, as compared to proceeds of $2.7 million during the first six months of 2012. Finally, changes in restricted cash improved our cash from investing activities by $64.8 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 $27.6 million of the proceeds through bill credits and the reimbursement of costs.

Financing Activities

Cash used in financing activities increased by $57.6 million during the first six months of 2012 as compared to the same period in 2011. This change is primarily due to changes in our debt levels. During the first six months of 2012, we decreased our short-term debt levels by $30.5 million compared to an increase of $22.4 million during the same period in 2011.

CAPITAL RESOURCES AND REQUIREMENTS

Working Capital

As of June 30, 2012, our current liabilities exceeded our current assets by approximately $138.6 million. We do not expect this to have any impact on our liquidity because we believe we have adequate back-up lines of credit in place, as well as access to the capital markets to finance our construction program and to refinance current maturities of long-term debt if necessary.

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



June 2012	28	Wisconsin Electric Power Company

Form 10-Q

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 June 30, 2012, we had approximately $494.1 million of available, undrawn lines under our bank back-up credit facility, and approximately $324.2 million of commercial paper outstanding that was supported by the available lines of credit. During the first six months of 2012, our maximum commercial paper outstanding was $382.0 million with a weighted-average interest rate of 0.25%.

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 June 30, 2012:



Total Facility		Letters of Credit		Credit Available		Facility Expiration
(Millions of Dollars)

$	500.0	$	5.9	$	494.1	December 2013

We are the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amounts of $147 million. In August 2009, we terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We issued commercial paper to fund the purchase of the bonds. As of June 30, 2012, the repurchased bonds were still outstanding, but were reported as a reduction in our consolidated long-term debt because they are held by 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.

In June 2012, S&P affirmed our ratings and revised our ratings outlook from stable to positive.

In June 2012, Fitch affirmed our ratings and the stable ratings outlook.

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. We estimate that we will spend approximately $600 million on capital expenditures during 2012.



June 2012	29	Wisconsin Electric Power Company

Form 10-Q

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 $27.3 billion as of June 30, 2012 compared with $27.9 billion as of December 31, 2011. Our total contractual obligations and other commercial commitments as of June 30, 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.

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, Oak Creek expansion Unit 1, and OC 2 in our rates as authorized by the PSCW, the Michigan Public Service Commission (MPSC) and FERC. See Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Item 7 of our 2011 Annual Report on Form 10-K for additional information on PTF.

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.



June 2012	30	Wisconsin Electric Power Company

Form 10-Q

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. Pursuant to Michigan law, we self-implemented a $5.7 million interim electric base rate increase in January 2012. This increase was offset by a refund of $2.7 million of net proceeds from 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. The MPSC approved a total increase in electric base rates of $9.2 million annually, effective June 27, 2012, and authorized a 10.1% return on equity.

2012 Fuel Recovery Request: On August 3, 2011, we filed a $50 million rate increase request with the PSCW to recover forecasted increases in fuel and purchased power costs. The primary reasons for the increase were projected higher coal, coal transportation and purchased power costs. This filing was made under the new 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. In September 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 are targeting completion of the facility by the end 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,



June 2012	31	Wisconsin Electric Power Company

Form 10-Q

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. In March 2012, the wet flue gas desulfurization and selective catalytic reduction equipment for units 5 and 6 was placed into commercial operation. We are targeting completion of the equipment for units 7 and 8 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.

ELECTRIC TRANSMISSION AND ENERGY MARKETS

As part of MISO, a market-based platform was developed for valuing transmission congestion premised upon the Locational Marginal Price (LMP) system that has been implemented in certain northeastern and mid-Atlantic states. The LMP system includes the ability to mitigate or eliminate congestion costs through Auction Revenue Rights (ARRs) and FTRs. ARRs are allocated to market participants by MISO and FTRs are purchased through auctions. A new allocation and auction was completed for the period of June 1, 2012 through May 31, 2013. The resulting ARR valuation and the secured FTRs should mitigate our transmission congestion risk for that period.

ENVIRONMENTAL MATTERS

Air Quality

Mercury and Other Hazardous Air Pollutants: In December 2011, the EPA issued the final utility MACT rule (referred to as the Mercury and Air Toxics Standards 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 our other plants well to meet the rule's requirements.

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

The rule was scheduled to become effective January 1, 2012. However, we and a number of other parties sought judicial review of the rule, and on December 30, 2011, the U.S. Court of Appeals for the District of Columbia granted a motion to stay the 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



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restrictions on our Carbon Dioxide emissions that may be adopted by Congress or Wisconsin's or Michigan's legislature could result in significant compliance costs that could affect future results of operations, cash flows and financial condition.

In March 2012, the EPA, using its existing authority under the Clean Air Act (CAA), proposed new source performance standards pertaining to greenhouse gas emissions from certain new power plants, including coal-fueled plants, based on the performance of combined cycle natural gas-fueled generating plants. We believe this rule effectively prohibits new conventional coal-fueled power plants. On June 26, 2012, the United States Court of Appeals for the Federal Circuit upheld the EPA's authority to regulate greenhouse gas emissions.

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

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.

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 rate order in our 2012 Michigan rate case.

OTHER MATTERS

Oak Creek Expansion Fuel Flexibility Project: The Oak Creek expansion units were designed and permitted to use bituminous coal from the Eastern United States rather than sub-bituminous coal. Market forces have resulted in a significant price differential between bituminous and sub-bituminous coals. We have applied for a new air permit from the WDNR to modify the Oak Creek expansion units for potential future use of sub-bituminous coal. Upon receiving an air permit, we intend to begin testing sub-bituminous coal in various combinations with bituminous coal



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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.

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 were removed from the area, and construction equipment and related materials were removed from Lake Michigan. The clean-up work was completed, and the bluff was



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stabilized for the winter. We expect permanent bluff reconstruction and stabilization work to be completed during this year's construction season.

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

In addition, 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.

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.



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ITEM 6. EXHIBITS



Exhibit No.

12		Statements re Computation of Ratios

12.1		Statement of Computation of Ratio of Earnings to Fixed Charges.

31		Rule 13a-14(a) / 15d-14(a) Certifications

31.1		Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32		Section 1350 Certifications

32.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101		Interactive Data File



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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:	August 2, 2012	Stephen P. Dickson, Vice President and Controller, Principal Accounting Officer and duly authorized officer



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