WISCONSIN ELECTRIC POWER CO - Quarter Report: 2010 June (Form 10-Q)

Total Facility

Letters
of Credit

Credit Available

Facility
Expiration

(Millions of Dollars)

March 2011

WE 6-30-2010 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, 2010

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 [ ] 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, 2010):

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.

		WISCONSIN ELECTRIC POWER COMPANY


		FORM 10-Q REPORT FOR THE QUARTER ENDED JUNE 30, 2010



		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		21

3.	Quantitative and Qualitative Disclosures About Market Risk		34

4T.	Controls and Procedures		34

	Part II -- Other Information

1.	Legal Proceedings		34

1A.	Risk Factors		35

6.	Exhibits		35

	Signatures		36

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:

Wisconsin Electric Subsidiary and Affiliates

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 1		Oak Creek expansion Unit 1
OC 2		Oak Creek expansion Unit 2
PWGS		Port Washington Generating Station

Federal and State Regulatory Agencies
DOE		United States Department of Energy
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
MPSC		Michigan Public Service Commission
PSCW		Public Service Commission of Wisconsin
SEC		Securities and Exchange Commission

Environmental Terms
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
NO_x		Nitrogen Oxide
PM_2.5		Fine Particulate Matter
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
CPCN		Certificate of Public Convenience and Necessity
ERISA		Employee Retirement Income Security Act of 1974
Fitch		Fitch Ratings
FTRs		Financial Transmission Rights
LMP		Locational Marginal Price
MISO		Midwest Independent Transmission System Operator, Inc.
Moody's		Moody's Investor Service
OTC		Over-the-Counter
Plan		The Wisconsin Energy Corporation Retirement Account Plan
Point Beach		Point Beach Nuclear Power Plant
PTF		Power the Future
S&P		Standard & Poor's Ratings Services

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS - (Cont'd)

The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:

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

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

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. 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, 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," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects," "should" 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 unusual weather conditions; catastrophic weather-related or terrorism-related damage; 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; 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 economic climate in our service territories such as customer growth; customer business conditions, including demand for their products and services; and changes in market demand and demographic patterns.

Timing, resolution and impact of pending and future rate cases and negotiations, including recovery for new investments as part of Wisconsin Energy Corporation's (Wisconsin Energy) Power the Future (PTF) strategy, environmental compliance, transmission service, fuel costs and costs associated with the Midwest Independent Transmission System Operator, Inc. (MISO) Energy and Operating Reserves Markets.

Regulatory factors such as changes in rate-setting policies or procedures; changes in regulatory accounting policies and practices; industry restructuring initiatives; transmission or distribution system operation and/or administration initiatives; required changes in facilities or operations to reduce the risks or impacts of potential terrorist activities; required approvals for new construction; and the siting approval process for new generation and transmission facilities and new pipeline construction.

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

Factors which impede or delay execution of Wisconsin Energy's PTF strategy, including the adverse interpretation or enforcement of permit conditions by the permitting agencies; construction delays; and obtaining the investment capital from outside sources necessary to implement the strategy.

The impact of recent and future federal, state and local legislative and regulatory changes, including electric and gas industry restructuring initiatives; changes to the Federal Power Act and related regulations under the Energy Policy Act of 2005 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

5

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.

The cost and other effects of legal and administrative proceedings, settlements, investigations, claims and changes in those matters.

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

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

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

The impact of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010.

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

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, 2009.

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.

INTRODUCTION

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

We conduct our operations primarily in three operating segments: an electric utility segment, a natural gas utility segment and a steam utility segment. We serve approximately 1,118,100 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 462,500 gas customers in Wisconsin and approximately 465 steam customers in metropolitan Milwaukee, Wisconsin. For further financial information about our business segments, see Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 10 -- 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 2009 Annual Report on Form 10-K. We have combined common functions with Wisconsin Gas and operate under the trade name of "We Energies". In April 2010, we, along with Wisconsin Gas, filed a joint application with the Public Service Commission of Wisconsin (PSCW) to merge Wisconsin Gas into Wisconsin Electric.

Other: Bostco is our non-utility subsidiary that develops and invests in real estate. As of June 30, 2010, Bostco had $35.7 million of assets.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC. We have condensed or omitted some information and note disclosures normally included in financial statements prepared in accordance with GAAP pursuant to these rules and regulations. This Form 10-Q, including the financial statements contained herein, should be read in conjunction with our 2009 Annual Report on Form 10-K, including the financial statements and notes therein.

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

	2010	2009	2010	2009

	(Millions of Dollars)

Operating Revenues	$ 777.6	$ 723.7	$ 1,711.5	$ 1,712.1

Operating Expenses
Fuel and purchased power	259.6	253.7	538.2	519.8
Cost of gas sold	39.6	42.3	191.7	259.5
Other operation and maintenance	351.5	304.6	695.3	625.0
Depreciation and amortization	54.0	66.1	107.8	132.0
Property and revenue taxes	23.9	24.9	48.1	49.8

Total Operating Expenses	728.6	691.6	1,581.1	1,586.1

Amortization of Gain	47.2	55.1	96.6	119.3


Operating Income	96.2	87.2	227.0	245.3

Equity in Earnings of Transmission Affiliate	13.3	12.7	26.6	25.2
Other Income, net	9.6	6.4	15.7	12.3
Interest Expense, net	25.5	25.2	51.6	50.8


Income Before Income Taxes	93.6	81.1	217.7	232.0

Income Taxes	32.2	29.6	76.9	81.7


Net Income	61.4	51.5	140.8	150.3

Preferred Stock Dividend Requirement	0.3	0.3	0.6	0.6


Earnings Available for Common Stockholder	$ 61.1	$ 51.2	$ 140.2	$ 149.7





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

WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED CONDENSED BALANCE SHEETS

			(Unaudited)
			June 30, 2010	December 31, 2009
			(Millions of Dollars)
Assets

Property, Plant and Equipment
	In service		$ 7,782.4	$ 7,718.0
	Accumulated depreciation		(2,831.1)	(2,822.6)

			4,951.3	4,895.4
	Construction work in progress		576.8	382.6
	Leased facilities, net		1,888.5	959.6

		Net Property, Plant and Equipment	7,416.6	6,237.6

Investments
	Equity investment in transmission affiliate		284.9	276.7
	Other		0.4	0.5

		Total Investments	285.3	277.2

Current Assets
	Cash and cash equivalents		9.9	18.3
	Restricted cash		112.7	194.5
	Accounts receivable		236.6	223.0
	Accounts receivable from related parties		21.8	22.8
	Accrued revenues		164.6	212.8
	Materials, supplies and inventories		345.7	321.5
	Prepayments		107.1	122.2
	Regulatory assets		47.0	48.5
	Other		29.2	25.5

		Total Current Assets	1,074.6	1,189.1

Deferred Charges and Other Assets
	Regulatory assets		1,022.8	1,014.6
	Other		160.0	152.7

		Total Deferred Charges and Other Assets	1,182.8	1,167.3

Total Assets			$ 9,959.3	$ 8,871.2




Capitalization and Liabilities

Capitalization
	Common equity		$ 2,865.4	$ 2,804.2
	Preferred stock		30.4	30.4
	Long-term debt		1,970.2	1,969.5
	Capital lease obligations		2,068.5	1,111.3

		Total Capitalization	6,934.5	5,915.4

Current Liabilities
	Long-term debt and capital lease obligations due currently		16.3	12.0
	Short-term debt		167.5	92.0
	Subsidiary note payable to Wisconsin Energy		28.3	28.2
	Accounts payable		211.0	207.0
	Accounts payable to related parties		89.5	79.9
	Regulatory liabilities		120.5	220.8
	Other		214.1	229.5

		Total Current Liabilities	847.2	869.4

Deferred Credits and Other Liabilities
	Regulatory liabilities		672.0	591.3
	Deferred income taxes - long-term		849.3	833.8
	Pension and other benefit obligations		389.8	374.2
	Other		266.5	287.1

		Total Deferred Credits and Other Liabilities	2,177.6	2,086.4

Total Capitalization and Liabilities			$ 9,959.3	$ 8,871.2





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

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

				Six Months Ended June 30

				2010	2009

				(Millions of Dollars)
Operating Activities
	Net income			$ 140.8	$ 150.3
	Reconciliation to cash
		Depreciation and amortization		111.8	137.0
		Amortization of gain		(96.6)	(119.3)
		Equity in earnings of transmission affiliate		(26.6)	(25.2)
		Distributions from transmission affiliate		21.8	20.0
		Deferred income taxes and investment tax credits, net		8.9	6.4
		Contributions to benefit plans		-	(283.8)
		Change in -	Accounts receivable and accrued revenues	26.5	80.6
			Inventories	(24.2)	19.5
			Other current assets	22.9	18.1
			Accounts payable	7.4	(73.5)
			Accrued income taxes, net	(14.6)	73.2
			Deferred costs, net	13.0	23.1
			Other current liabilities	(9.6)	(6.5)
		Other, net		29.0	(8.4)

Cash Provided by Operating Activities				210.5	11.5

Investing Activities
	Capital expenditures			(265.8)	(242.2)
	Investment in transmission affiliate			(3.5)	(10.1)
	Change in restricted cash			81.8	103.1
	Other, net			(20.9)	(13.8)

Cash Used in Investing Activities				(208.4)	(163.0)

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			75.6	223.2
	Other, net			4.3	0.5

Cash (Used in) Provided by Financing Activities				(10.5)	133.3


Change in Cash and Cash Equivalents				(8.4)	(18.2)

Cash and Cash Equivalents at Beginning of Period				18.3	28.4


Cash and Cash Equivalents at End of Period				$ 9.9	$ 10.2





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

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 2009 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, 2010 are not necessarily indicative of the results which may be expected for the entire fiscal year 2010 because of seasonal and other factors.

2 -- NEW ACCOUNTING PRONOUNCEMENTS

Amendments to Variable Interest Entity Consolidation Guidance: In June 2009, the Financial Accounting Standards Board issued new accounting guidance related to variable interest entity consolidation. The purpose of this guidance is to improve financial reporting by enterprises with variable interest entities. The new guidance is effective for all new and existing variable interest entities for fiscal years beginning after November 15, 2009. We adopted these provisions on January 1, 2010. This adoption did not have any impact on our financial condition, results of operations or cash flows. See Note 11 -- Variable Interest Entities for required disclosures.

3 -- COMMON EQUITY

Share-Based Compensation Expense: For a description of share-based compensation, including Wisconsin Energy stock options, restricted stock and performance units, see Note I -- Common Equity in our 2009 Annual Report on Form 10-K. We utilize the straight-line attribution method for recognizing share-based compensation expense. Accordingly, for employee awards, equity classified share-based compensation cost is measured at the grant date based on the fair value of the award and is recognized as expense over the requisite service period. There were no modifications to the terms of outstanding Wisconsin Energy stock options held by our employees during the period.

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

	Three Months Ended June 30		Six Months Ended June 30

	2010	2009	2010	2009

	(Millions of Dollars)

Stock options	$1.7	$2.6	$3.4	$4.9
Performance units	7.5	0.1	10.0	3.5
Restricted stock	0.2	0.1	0.4	0.2

Share-based compensation expense	$9.4	$2.8	$13.8	$8.6




Related Tax Benefit	$3.8	$1.1	$5.6	$3.4

Stock Option Activity: During the first six months of 2010, the Compensation Committee granted 257,350 Wisconsin Energy stock options to our employees that had an estimated fair value of $6.72 per share. During the first six months of 2009, the Compensation Committee granted 1,129,315 Wisconsin Energy stock options to our employees that had an estimated fair value of $8.01 per share. The following assumptions were used to value the Wisconsin Energy options using a binomial option pricing model:

	2010	2009


Risk-free interest rate	0.2% - 3.9%	0.3% - 2.5%
Dividend yield	3.7%	3.0%
Expected volatility	20.3%	25.9%
Expected forfeiture rate	2.0%	2.0%
Expected life (years)	5.9	6.2

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

The following is a summary of our employees' Wisconsin Energy stock option activity for the three and six months ended June 30, 2010:

			Weighted-
		Weighted-	Average	Aggregate
		Average	Remaining	Intrinsic
	Number of	Exercise	Contractual Life	Value
Stock Options	Options	Price	(Years)	(Millions)


Outstanding as of April 1, 2010	7,980,162	$39.68
Granted	-	$ -
Exercised	(657,153)	$32.99
Forfeited	-	$ -

Outstanding as of June 30, 2010	7,323,009	$40.28




Outstanding as of January 1, 2010	8,237,428	$38.95
Granted	257,350	$49.84
Exercised	(1,166,769)	$32.97
Forfeited	(5,000)	$45.70

Outstanding as of June 30, 2010	7,323,009	$40.28	5.9	$76.6




Exercisable as of June 30, 2010	4,736,069	$37.32	4.7	$63.6

The intrinsic value of Wisconsin Energy options exercised by our employees was $12.4 million and $21.0 million for the three and six months ended June 30, 2010, and $0.3 million and $1.2 million for the same periods in 2009, respectively. Cash received by Wisconsin Energy from exercises of its options by our employees was $38.5 million and $2.0 million for the six months ended June 30, 2010 and 2009, respectively. The actual tax benefit realized for the tax deductions from option exercises during the same periods was approximately $8.3 million and $0.5 million, respectively.

The following table summarizes information about Wisconsin Energy stock options held by our employees that were outstanding as of June 30, 2010:

	Options Outstanding			Options Exercisable

		Weighted-Average			Weighted-Average

			Remaining			Remaining
			Contractual			Contractual
	Number of	Exercise	Life	Number of	Exercise	Life
Range of Exercise Prices	Options	Price	(Years)	Options	Price	(Years)


$20.39 to $29.13	738,676	$25.10	2.4	738,676	$25.10	2.4
$33.44 to $39.48	2,688,265	$35.64	4.5	2,688,265	$35.64	4.5
$42.22 to $49.84	3,896,068	$46.36	7.6	1,309,128	$47.65	6.6

	7,323,009	$40.28	5.9	4,736,069	$37.32	4.7

The following table summarizes information about our employees' non-vested Wisconsin Energy stock options during the six months ended June 30, 2010. There was no activity related to non-vested stock options during the second quarter of 2010.

		Weighted-
	Number of	Average
Non-Vested Stock Options	Options	Fair Value


Non-vested as of January 1, 2010	3,409,280	$8.73
Granted	257,350	$6.72
Vested	(1,074,690)	$8.72
Forfeited	(5,000)	$8.53

Non-vested as of June 30, 2010	2,586,940	$8.53

As of June 30, 2010, our total compensation costs related to non-vested Wisconsin Energy stock options not yet recognized was approximately $5.0 million, which is expected to be recognized over the next 13 months on a weighted-average basis.

Restricted Shares: The Compensation Committee has also approved Wisconsin Energy restricted stock grants to certain of our key employees. These awards have a three-year vesting period, with, typically, 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, 2010:

		Weighted-
		Average
	Number of	Grant Date
Restricted Shares	Shares	Fair Value


Outstanding as of April 1, 2010	89,944
Granted	-	$ -
Released	(3,951)	$25.31
Forfeited	-	$ -

Outstanding as of June 30, 2010	85,993




Outstanding as of January 1, 2010	57,999
Granted	32,505	$49.55
Released	(4,451)	$27.00
Forfeited	(60)	$49.55

Outstanding as of June 30, 2010	85,993

Wisconsin Energy records the market value of the restricted stock awards on the date of grant. We then 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 $0.2 million for each of the three and six months ended June 30, 2010, and $0.1 million and $0.2 million for the same periods in 2009, respectively. The actual tax benefit realized for the tax deductions from released restricted shares was $0.1 million for the three and six months ended June 30, 2010 and 2009, respectively.

As of June 30, 2010, total compensation cost related to our share of Wisconsin Energy restricted stock not yet recognized was approximately $1.8 million, which is expected to be recognized over the next 31 months on a weighted-average basis.

Performance Units: In January 2010 and 2009, the Compensation Committee awarded 260,310 and 309,310 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, 2009 and 2008 vested and were settled during the first quarter of 2010 and 2009, and had a total intrinsic value of $9.3 million and $7.9 million, respectively. The actual tax benefit realized for the tax deductions from the settlement of performance units was approximately $3.2 million and $2.9 million, respectively. As of June 30, 2010, total compensation cost related to performance units not yet recognized was approximately $22.1 million, which is expected to be recognized over the next 23 months on a weighted-average basis.

Restrictions: Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. In addition, under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy. See Note I -- Common Equity in our 2009 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. During the six months ended June 30, 2010 and 2009, total comprehensive income was equal to net income.

4 -- LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS

On February 2, 2010, Oak Creek expansion Unit 1 (OC 1) was placed into service. Prior to December 31, 2009, certain common facilities associated with the Oak Creek facility were placed into service. We now have care, custody and control of OC 1 and will operate and maintain it over the 30 year life of the lease. As a result of the commercial operation of OC 1, in February 2010, we recorded an additional capital lease asset and capital lease obligation related to the Oak Creek expansion totaling approximately $1.0 billion. 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 lease for OC 1, including the common facilities, was $1.3 billion as of June 30, 2010 and will decrease to zero over the remaining life of the contract.

5 -- DIVESTITURES

Edgewater Generating Unit 5: During the fourth quarter of 2009, we reached a contingent agreement to sell our 25% interest in Edgewater Generating Unit 5 to Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corp., for our net book value, including working capital. In March 2010, the agreement became effective and we are in the process of receiving regulatory approvals. The completion of the sale is subject to approval by applicable regulatory bodies, including the PSCW and the Michigan Public Service Commission (MPSC). In June 2010, we received approval for the sale from FERC. If approved by the remaining regulatory bodies, we expect the sale to close by the end of 2010 and to realize proceeds of between $40 million and $45 million depending on the working capital balances and our level of capital investment in the unit prior to the sale.

6 -- FAIR VALUE MEASUREMENTS

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

Fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. Accordingly, we also utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Assets and liabilities measured and reported at fair value are classified and disclosed in one of the following categories:

Level 1 -- Quoted prices are 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, 2010

	Level 1	Level 2	Level 3	Total

	(Millions of Dollars)
Assets:
Restricted Cash	$112.7	$ -	$ -	$112.7
Derivatives	0.3	4.8	15.9	21.0

Total	$113.0	$4.8	$15.9	$133.7

Liabilities:
Derivatives	$4.2	$2.7	$ -	$6.9

Total	$4.2	$2.7	$ -	$6.9

Recurring Fair Value Measures	As of December 31, 2009

	Level 1	Level 2	Level 3	Total

	(Millions of Dollars)
Assets:
Restricted Cash	$194.5	$ -	$ -	$194.5
Derivatives	0.6	3.3	5.8	9.7

Total	$195.1	$3.3	$5.8	$204.2

Liabilities:
Derivatives	$4.2	$2.4	$ -	$6.6

Total	$4.2	$2.4	$ -	$6.6

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

The following tables summarize the fair value of derivatives classified as Level 3 in the fair value hierarchy:

Quarter to Date	2010	2009

	(Millions of Dollars)

Balance as of April 1	$1.9	$2.9
Realized and unrealized gains (losses)	-	-
Purchases, issuances and settlements	14.0	12.5
Transfers in and/or out of Level 3	-	-

Balance as of June 30	$15.9	$15.4




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

Year to Date	2010	2009

	(Millions of Dollars)

Balance as of January 1	$5.8	$8.8
Realized and unrealized gains (losses)	-	-
Purchases, issuances and settlements	10.1	6.6
Transfers in and/or out of Level 3	-	-

Balance as of June 30	$15.9	$15.4




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, 2010		December 31, 2009

Financial Instruments	Carrying Amount	Fair Value	Carrying Amount	Fair Value

	(Millions of Dollars)

Preferred stock, no redemption required	$30.4	$21.7	$30.4	$20.2
Long-term debt including current portion	$1,987.1	$2,210.0	$1,987.1	$2,088.2

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 unamortized discount on debt, is estimated based upon quoted market value for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows.

7 -- DERIVATIVE INSTRUMENTS

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

We record derivative instruments on the balance sheet as an asset or liability measured at its fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. 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, 2010, we recognized $11.5 million in regulatory assets and $20.7 million in regulatory liabilities related to derivatives in comparison to $11.6 million in regulatory assets and $9.3 million in regulatory liabilities as of December 31, 2009.

We record our current derivative assets on the balance sheet in Other current assets and the current portion of the liabilities in Other current liabilities. The long-term portion of our derivative assets of $0.9 million is recorded in Other deferred charges and other assets, and the long-term portion of our derivative liabilities of $0.4 million is recorded in Other deferred credits and other liabilities. Our Consolidated Condensed Balance Sheet as of June 30, 2010 and December 31, 2009 includes:

	June 30, 2010		December 31, 2009

	Derivative	Derivative	Derivative	Derivative
	Asset	Liability	Asset	Liability

	(Millions of Dollars)

Natural Gas	$2.0	$6.5	$1.2	$6.6
Energy	-	0.4	-	-
Fuel Oil	0.2	-	0.6	-
FTRs	15.9	-	5.8	-
Coal	2.9	-	2.1	-

Total	$21.0	$6.9	$9.7	$6.6

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) for the three and six months ended June 30, 2010 and 2009 were as follows:

	Three Months Ended June 30, 2010		Three Months Ended June 30, 2009

	Volume	Gains (Losses)	Volume	Gains (Losses)

		(Millions of Dollars)		(Millions of Dollars)

Natural Gas	8.8 million Dth	($2.9)	12.3 million Dth	($21.4)
Energy	102,400 MWh	(0.2)	3,200 MWh	(0.1)
Fuel Oil	2.0 million gallons	(0.2)	1.3 million gallons	(1.0)
FTRs	6,657 MW	3.2	5,605 MW	3.7

Total		($0.1)		($18.8)

	Six Months Ended June 30, 2010		Six Months Ended June 30, 2009

	Volume	Gains (Losses)	Volume	Gains (Losses)

		(Millions of Dollars)		(Millions of Dollars)

Natural Gas	21.5 million Dth	($10.3)	23.5 million Dth	($39.0)
Energy	159,600 MWh	-	15,120 MWh	(0.6)
Fuel Oil	3.8 million gallons	-	2.2 million gallons	(1.3)
FTRs	12,088 MW	12.2	11,785 MW	4.2

Total		$1.9		($36.7)

As of June 30, 2010 and December 31, 2009, we have posted collateral of $8.1 million and $6.6 million, respectively, in our margin accounts. These amounts are recorded on the balance sheet 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, 2010 and 2009 were as follows:

	Pension Costs

	Three Months Ended June 30		Six Months Ended June 30

Benefit Plan Cost Components	2010	2009	2010	2009

	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$4.6	$5.5	$11.0	$10.7
Interest cost	14.7	15.4	29.5	30.9
Expected return on plan assets	(14.8)	(18.3)	(29.8)	(36.5)
Amortization of:
Transition obligation	-	-	-	-
Prior service cost	0.6	0.5	1.1	1.1
Actuarial loss	4.8	3.0	9.4	6.4

Net Periodic Benefit Cost	$9.9	$6.1	$21.2	$12.6

	OPEB Costs

	Three Months Ended June 30		Six Months Ended June 30

Benefit Plan Cost Components	2010	2009	2010	2009

	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$2.6	$2.0	$5.3	$4.1
Interest cost	4.3	4.1	8.7	8.3
Expected return on plan assets	(2.3)	(2.2)	(4.6)	(4.5)
Amortization of:
Transition obligation	0.1	-	0.2	0.1
Prior service credit	(3.0)	(3.1)	(5.9)	(6.3)
Actuarial loss	2.1	1.4	4.1	2.8

Net Periodic Benefit Cost	$3.8	$2.2	$7.8	$4.5

9 -- GUARANTEES

We enter into various guarantees to provide financial and performance assurance to third parties. As of June 30, 2010, we had the following guarantees:

Maximum Potential
Future Payments	Outstanding	Liability Recorded

(Millions of Dollars)

$2.8	$0.1	$ -

We are subject to the potential retrospective premiums that could be assessed under our insurance program.

Postemployment Benefits: Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $11.5 million as of June 30, 2010 and $10.8 million as of December 31, 2009.

10 -- SEGMENT INFORMATION

Summarized financial information concerning our operating segments for the three and six months ended June 30, 2010 and 2009 is shown in the following table:

	Operating Segments

	Electric	Gas	Steam	Total

	(Millions of Dollars)
Three Months Ended


June 30, 2010
Operating Revenues (a)	$701.7	$69.2	$6.7	$777.6
Operating Income	$95.8	$0.4	$ -	$96.2

June 30, 2009
Operating Revenues (a)	$644.2	$72.3	$7.2	$723.7
Operating Income (Loss)	$86.0	$1.4	($0.2)	$87.2

Six Months Ended


June 30, 2010
Operating Revenues (a)	$1,405.5	$284.4	$21.6	$1,711.5
Operating Income	$193.2	$29.3	$4.5	$227.0

June 30, 2009
Operating Revenues (a)	$1,329.9	$359.8	$22.4	$1,712.1
Operating Income	$200.8	$39.2	$5.3	$245.3

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

As of June 30, 2010, our total assets in our electric utility segment increased by approximately $1.0 billion as compared to December 31, 2009 primarily because of the commencement of commercial operation of OC 1 in February 2010, at which time we recorded an additional capital lease asset of approximately $1.0 billion.

11 -- 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 which 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 three years. 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 13 years. We have examined the risks of the entity including operations and maintenance, dispatch, financing, fuel costs and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity and there is no residual guarantee associated with the purchased power agreement.

We have approximately $392.0 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, 2010 were $31.0 million. Our maximum exposure to loss is limited to the capacity payments under the contracts.

12 -- COMMITMENTS AND CONTINGENCIES

Environmental Matters: We periodically review our exposure for remediation costs as evidence becomes available indicating that our liability has changed. Given current information, 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.

Indemnifications: In connection with the sale of Point Beach, we agreed to provide the buyer with indemnification provisions customary to transactions involving the sale of nuclear assets.

Income Taxes: During the second quarter of 2010, our federal unrecognized tax benefits decreased by $12.3 million as the result of payment of a tax obligation for a prior year.

13 -- SUPPLEMENTAL CASH FLOW INFORMATION

During the six months ended June 30, 2010, we paid $51.2 million in interest, net of amounts capitalized, and $75.2 million in income taxes, net of refunds. During the six months ended June 30, 2009, we paid $50.0 million in interest, net of amounts capitalized, and $0.6 million in income taxes, net of refunds.

As of June 30, 2010 and 2009, the amount of accounts payable related to capital expenditures was $14.4 million and $9.9 million, respectively.

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

RESULTS OF OPERATIONS -- THREE MONTHS ENDED JUNE 30, 2010
EARNINGS

We recorded net income of $61.4 million for the second quarter of 2010, an increase of $9.9 million, or 19.2%, from the second quarter of 2009. Our operating income was $96.2 million for the second quarter of 2010, an increase of $9.0 million, or 10.3%, from the second quarter of 2009. A more detailed analysis of our financial results follows.

Electric Utility Revenues and Sales

The following table compares electric utility operating revenues and MWh sales by customer class during the second quarter of 2010 with the second quarter of 2009 including favorable (better (B)) or unfavorable (worse (W)) variances:

	Three Months Ended June 30

	Electric Revenues			MWh Sales

Electric Utility Operations	2010	B (W)	2009	2010		B (W)		2009

	(Millions of Dollars)			(Thousands)
Customer Class
Residential	$251.4	$23.4	$228.0		1,873.9		32.1		1,841.8
Small Commercial/Industrial	230.4	20.8	209.6		2,146.3		96.1		2,050.2
Large Commercial/Industrial	171.3	27.3	144.0		2,458.6		307.5		2,151.1
Other - Retail	5.0	0.1	4.9		35.8		(0.8)		36.6

Total Retail	658.1	71.6	586.5		6,514.6		434.9		6,079.7
Wholesale - Other	30.1	3.0	27.1		400.0		93.1		306.9
Resale - Utilities	8.1	2.3	5.8		310.7		96.2		214.5
Other Operating Revenues	5.4	(19.4)	24.8		-		-		-

Total	$701.7	$57.5	$644.2		7,225.3		624.2		6,601.1




Weather -- Degree Days (a)
Heating (949 Normal)					671		(275)		946
Cooling (170 Normal)					208		74		134

(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 $57.5 million, or 8.9%, when compared to the second quarter of 2009. The most significant factors that caused the change in revenues were:

Net pricing increases totaling $30.8 million related to Wisconsin and Michigan rate orders that became effective in 2010. For information on these rate orders, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters.
Favorable weather that increased electric revenues by an estimated $19.4 million as compared to the second quarter of 2009.
Net economic growth that increased electric revenues by an estimated $12.7 million as compared to the second quarter of 2009.
2010 pricing increases totaling approximately $7.9 million, reflecting the reduction of Point Beach bill credits to retail customers.

As measured by cooling degree days, the second quarter of 2010 was 55.2% warmer than the same period in 2009 and 22.4% warmer than normal. Collectively, retail sales to our residential and small commercial and industrial customers, who are more weather sensitive, increased by 3.3%. Sales to our large commercial and industrial customers increased by 14.3% during the second quarter of 2010 as compared to the same period in 2009 primarily because of an improving economy. Electric sales to our largest customers, two iron ore mines, which represent approximately 6.5% of our annual sales, increased significantly for the quarter. If these sales are excluded, sales to our large commercial and industrial customers increased by 7.1% for the second quarter of 2010 as compared to the second quarter of 2009. The $19.4 million decline in Other Operating Revenues primarily relates to regulatory amortizations during the second quarter of 2010 as compared to the same period in 2009, and a one-time entry in the second quarter of 2009 related to the expected recovery of MISO costs.

Fuel and Purchased Power

Our fuel and purchased power costs increased by $5.9 million, or 2.3%, when compared to the second quarter of 2009. This increase was primarily caused by the 9.5% increase in total MWh sales, partially offset by a 6.5% decrease in the average cost/MWh between periods. The lower average cost/MWh was primarily caused by a 35.6% increase in generation from our lower cost coal units.

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 2010 with the second quarter of 2009. 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 $3.1 million, or 4.3%, primarily because of lower natural gas prices and milder weather.

	Three Months Ended June 30

	2010	B (W)	2009

	(Millions of Dollars)

Gas Operating Revenues	$69.2	($3.1)	$72.3
Cost of Gas Sold	39.6	2.7	42.3

Gross Margin	$29.6	($0.4)	$30.0

The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the second quarter of 2010 with the second quarter of 2009:

	Three Months Ended June 30

	Gross Margin			Therm Deliveries

Gas Utility Operations	2010	B (W)	2009	2010	B (W)	2009

	(Millions of Dollars)			(Millions)
Customer Class
Residential	$19.4	($1.7)	$21.1	39.5	(9.0)	48.5
Commercial/Industrial	5.3	(0.3)	5.6	22.2	(5.8)	28.0
Interruptible	0.1	-	0.1	0.9	(0.2)	1.1

Total Retail	24.8	(2.0)	26.8	62.6	(15.0)	77.6
Transported Gas	3.4	0.9	2.5	65.8	(2.0)	67.8
Other	1.4	0.7	0.7	-	-	-

Total	$29.6	($0.4)	$30.0	128.4	(17.0)	145.4



Weather -- Degree Days (a)
Heating (949 Normal)				671	(275)	946

(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 $0.4 million, or approximately 1.3%, when compared to the second quarter of 2009 primarily because of a decline in sales volumes as a result of milder weather during the second quarter of 2010 that reduced heating loads. As measured by heating degree days, the second quarter of 2010 was 29.1% warmer than the same period in 2009 and 29.3% warmer than normal.

Other Operation and Maintenance Expense

Our other operation and maintenance expense increased by $46.9 million, or approximately 15.4%, when compared to the second quarter of 2009. The 2010 PSCW rate case order allowed for pricing increases related to regulatory items including PTF lease costs, bad debt expense and amortization of other deferred costs. We estimate that these items were approximately $18.6 million higher in the second quarter of 2010 as compared to the same period in 2009. In addition, operation and maintenance

expenses at our power plants increased by approximately $17.2 million primarily because of the operation of OC 1, which was placed into service in February 2010, and higher maintenance costs at our other power plants.

Depreciation and Amortization Expense

Our depreciation and amortization expense decreased by $12.1 million, or approximately 18.3%, when compared to the second quarter of 2009 primarily because of new depreciation rates that were implemented in connection with the 2010 PSCW rate case order. The new depreciation rates generally reflect longer lives for our utility assets.

Amortization of Gain

In connection with the September 2007 sale of Point Beach, we reached agreements with our regulators to allow for the net gain on the sale to be used for the benefit of our customers. The majority of the benefits are being returned to customers in the form of bill credits. The net gain was originally recorded as a regulatory liability, and it is being amortized to the income statement as we issue bill credits to our customers. When the bill credits are issued to customers, we transfer cash from the restricted accounts to the unrestricted accounts, adjusted for taxes. During the second quarter of 2010 and 2009, the Amortization of Gain was $47.2 million and $55.1 million, respectively.

Other Income, net

Other income, net increased by $3.2 million, or approximately 50.0%, when compared to the second quarter of 2009 primarily because of an increase in Allowance for Funds Used During Construction (AFUDC) - Equity related to the construction of our Oak Creek Air Quality Control System (AQCS) project.

Interest Expense, net

	Three Months Ended June 30

Interest Expense, net	2010	2009

	(Millions of Dollars)

Gross Interest Costs	$28.6	$26.7
Less: Capitalized Interest	3.1	1.5

Interest Expense, net	$25.5	$25.2

Our gross interest costs increased by $1.9 million, or 7.1%, when compared to the second quarter of 2009 primarily because of higher long-term debt balances to fund our planned construction activity. Our capitalized interest increased by $1.6 million primarily because of increased capital expenditures related to our Oak Creek AQCS project during the second quarter of 2010 as compared to the same period in 2009. As a result, our net interest expense increased by $0.3 million, or 1.2%, as compared to the second quarter of 2009.

Income Taxes

For the second quarter of 2010, our effective tax rate was 34.4% compared to 36.5% for the second quarter of 2009. For additional information, see Note G -- Income Taxes in our 2009 Annual Report on Form 10-K.

RESULTS OF OPERATIONS -- SIX MONTHS ENDED JUNE 30, 2010
EARNINGS

We recorded net income of $140.8 million for the first six months of 2010, a decrease of $9.5 million, or 6.3%, from the first six months of 2009. Our operating income was $227.0 million for the first six months of 2010, a decrease of $18.3 million, or 7.5%, from the first six months of 2009. The decrease in operating income was primarily caused by unfavorable recoveries of revenues associated with fuel and purchased power and milder winter weather in 2010. During the first six months of 2010, we experienced unfavorable fuel recoveries of approximately $30 million. During the same period in 2009, we experienced favorable fuel recoveries of approximately $24 million. Although we received a fuel order from the PSCW in March 2010 allowing us to increase our rates on an interim basis, we expect to be in an unfavorable fuel recovery position for 2010. For additional information on the fuel order, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters -- 2010 Fuel Recovery Request.

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 2010 with the first six months of 2009 including favorable (better (B)) or unfavorable (worse (W)) variances:

	Six Months Ended June 30

	Electric Revenues			MWh Sales

Electric Utility Operations	2010	B (W)	2009	2010	B (W)	2009

	(Millions of Dollars)			(Thousands)
Customer Class
Residential	$512.8	$27.4	$485.4	3,875.2	(39.7)		3,914.9
Small Commercial/Industrial	447.5	15.8	431.7	4,294.0	21.9		4,272.1
Large Commercial/Industrial	326.4	40.8	285.6	4,822.9	479.6		4,343.3
Other - Retail	10.8	0.3	10.5	76.2	(1.2)		77.4

Total Retail	1,297.5	84.3	1,213.2	13,068.3	460.6		12,607.7
Wholesale - Other	71.5	9.5	62.0	1,036.3	154.5		881.8
Resale - Utilities	23.4	(0.4)	23.8	676.6	(15.0)		691.6
Other Operating Revenues	13.1	(17.8)	30.9	-	-		-

Total	$1,405.5	$75.6	$1,329.9	14,781.2	600.1		14,181.1




Weather -- Degree Days (a)
Heating (4,193 Normal)				3,815	(589)		4,404
Cooling (171 Normal)				208	74		134

(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 $75.6 million, or 5.7%, when compared to the first six months of 2009. The most significant factors that caused the change in revenues were:

Net pricing increases totaling $37.2 million related to Wisconsin and Michigan rate orders that became effective in 2010. For information on these rate orders, see Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters.
2010 pricing increases totaling approximately $22.7 million, reflecting the reduction of Point Beach bill credits to retail customers.
Net economic growth that increased electric revenues by an estimated $17.8 million as compared to the first six months of 2009.
Favorable weather that increased electric revenues by an estimated $6.1 million as compared to the first six months of 2009.

Sales to our large commercial and industrial customers increased by 11.0% during the first six months of 2010 as compared to the same period in 2009 primarily because of an improving economy. However, electric sales to our largest customers, two iron ore mines, which represent approximately 6.5% of our annual sales, increased significantly for the first six months of the year. If these sales are excluded, sales to our large commercial and industrial customers increased by 3.8% for the first six months of 2010 as compared to the first six months of 2009. The $17.8 million decline in Other Operating Revenues primarily relates to regulatory amortizations during the first six months of 2010 as compared to the same period in 2009.

Fuel and Purchased Power

Our fuel and purchased power costs increased by $18.4 million, or 3.5%, when compared to the first six months of 2009. This increase was primarily caused by the 4.2% increase in MWh sales, partially offset by a 0.6% decrease in the average cost/MWh between periods. The lower average cost/MWh was primarily caused by an 11.5% increase in generation from our lower cost coal units, partially offset by a 5% increase in coal and transportation costs between periods.

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 2010 with the first six months of 2009. 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 $75.4 million, or 21.0%, primarily because of lower natural gas prices and milder weather.

	Six Months Ended June 30

	2010	B (W)	2009

	(Millions of Dollars)

Gas Operating Revenues	$284.4	($75.4)	$359.8
Cost of Gas Sold	191.7	67.8	259.5

Gross Margin	$92.7	($7.6)	$100.3

The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the first six months of 2010 with the first six months of 2009:

	Six Months Ended June 30

	Gross Margin			Therm Deliveries

Gas Utility Operations	2010	B (W)	2009	2010	B (W)	2009

	(Millions of Dollars)			(Millions)
Customer Class
Residential	$62.1	($5.7)	$67.8	192.6	(25.8)	218.4
Commercial/Industrial	20.4	(3.3)	23.7	108.1	(20.0)	128.1
Interruptible	0.3	-	0.3	3.2	(0.4)	3.6

Total Retail	82.8	(9.0)	91.8	303.9	(46.2)	350.1
Transported Gas	7.9	0.9	7.0	151.4	(8.0)	159.4
Other	2.0	0.5	1.5	-	-	-

Total	$92.7	($7.6)	$100.3	455.3	(54.2)	509.5



Weather -- Degree Days (a)
Heating (4,193 Normal)				3,815	(589)	4,404

(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 $7.6 million, or approximately 7.6%, when compared to the first six months of 2009 primarily because of a decline in sales volumes as a result of milder winter weather during the first six months of 2010 as compared to the first six months of 2009. As measured by heating degree days, the first six months of 2010 were 13.4% warmer than the same period in 2009 and 9.0% warmer than normal.

Other Operation and Maintenance Expense

Our other operation and maintenance expense increased by $70.3 million, or approximately 11.2%, when compared to the first six months of 2009. The 2010 PSCW rate case order allowed for pricing increases related to regulatory items including PTF lease costs, bad debt expense and amortization of other deferred costs. We estimate that these items were approximately $34.9 million higher in the first six months of 2010 as compared to the same period in 2009. In addition, operation and maintenance expenses at our power plants increased by approximately $24.5 million primarily because of the operation of OC 1, which was placed into service in February 2010, and higher maintenance costs at our other power plants.

Depreciation and Amortization Expense

Our depreciation and amortization expense decreased by $24.2 million, or approximately 18.3%, when compared to the first six months of 2009 primarily because of new depreciation rates that were implemented in connection with the 2010 PSCW rate case order. The new depreciation rates generally reflect longer lives for our utility assets.

Amortization of Gain

During the first six months of 2010 and 2009, the Amortization of Gain was $96.6 million and $119.3 million, respectively. For 2010, we expect to see a reduction in the Amortization of Gain of approximately $34.6 million as compared to 2009 because of the scheduled decrease in Point Beach bill credits. We expect that all remaining Point Beach bill credits will be issued by the end of 2010.

Other Income, net

Other income, net increased by $3.4 million, or approximately 27.6%, when compared to the first six months of 2009 primarily because of an increase in AFUDC - Equity related to the construction of our Oak Creek AQCS project.

Interest Expense, net

	Six Months Ended June 30

Interest Expense, net	2010	2009

	(Millions of Dollars)

Gross Interest Costs	$57.1	$53.5
Less: Capitalized Interest	5.5	2.7

Interest Expense, net	$51.6	$50.8

Our gross interest costs increased by $3.6 million, or 6.7%, when compared to the first six months of 2009 primarily because of higher long-term debt balances to fund our planned construction activity. Our capitalized interest increased by $2.8 million primarily because of increased capital expenditures related to our Oak Creek AQCS project during the first six months of 2010 as compared to the same period in 2009. As a result, our net interest expense increased by $0.8 million, or 1.6%, as compared to the first six months of 2009.

Income Taxes

For the first six months of 2010, our effective tax rate was 35.3% compared to 35.2% for the first six months of 2009. For additional information, see Note G -- Income Taxes in our 2009 Annual Report on Form 10-K. We expect our 2010 annual effective tax rate to be between 35.0% and 36.0%.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

The following summarizes our cash flows during the first six months of 2010 and 2009:

	Six Months Ended June 30

	2010	2009

	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$210.5	$11.5
Investing Activities	($208.4)	($163.0)
Financing Activities	($10.5)	$133.3

Operating Activities

Cash provided by operating activities was $210.5 million during the six months ended June 30, 2010, which was $199.0 million higher than the same period in 2009. The largest item which led to the increase in cash from operations related to $283.8 million of contributions to Wisconsin Energy's benefit plans in the first six months of 2009. No such contributions were required in the first six months of 2010.

Investing Activities

Cash used in investing activities was $208.4 million during the six months ended June 30, 2010, which was $45.4 million higher than the same period in 2009. The increase in cash used in investing activities primarily reflects an increase in capital expenditures and a reduction in the release of restricted cash related to the Point Beach bill credits. During the first six months of 2010, our capital expenditures increased by $23.6 million primarily because of the commencement of construction of our Glacier Hills Wind Park in May 2010. During the first six months of 2010, we released $21.3 million less from restricted cash as compared to the same period in 2009.

Financing Activities

Cash used in financing activities was $10.5 million during the six months ended June 30, 2010 compared to $133.3 million provided by financing activities during the same period in 2009. The decrease in financing cash flows is primarily related to changes in our short-term debt levels. During the first six months of 2010, we increased our short-term debt levels by $75.6 million compared to an increase of $223.2 million in our short-term debt levels during the same period in 2009.

CAPITAL RESOURCES AND REQUIREMENTS
Capital Resources

We anticipate meeting our capital requirements during the remaining six months of 2010 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 an equity contribution from our parent. Beyond 2010, we anticipate meeting our capital requirements through internally generated funds supplemented, when required, by short-term borrowings, the issuance of debt securities and equity contributions from our parent.

We currently have access to the capital markets and have been able to generate funds internally and externally to meet our capital requirements. Our ability to attract the necessary financial capital at reasonable terms is critical to our overall strategic plan. We currently believe that we have adequate capacity to fund our operations for the foreseeable future through our existing borrowing arrangement, access to capital markets and internally generated cash.

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

As of June 30, 2010, we had approximately $474.0 million of available, undrawn lines under our bank back-up credit facility, and approximately $167.5 million of commercial paper outstanding that was supported by the available lines of credit.

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, 2010:

We recorded an increase of approximately $1.0 billion to our capital lease obligation in connection with OC 1 being placed into service in February 2010. For additional information, see Note 4 -- Long-Term Debt and Capital Lease Obligations in the Notes to Consolidated Condensed Financial Statements in this report.

We are the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amount of $147 million. In August 2009, we terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We issued commercial paper to fund the purchase of the bonds. As of June 30, 2010, 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.

Access to capital markets at a reasonable cost is determined in large part by credit quality. Any change in ratings or ratings outlooks could impact our cost of capital and access to the capital markets.

In July 2010, S&P affirmed our ratings and our stable ratings outlook.

In June 2010, Fitch affirmed our ratings and revised our ratings outlook from negative to stable. Prior to these actions, Fitch revised its ratings guidelines on corporate and utility preferred securities, which reduced the ratings of our Preferred Stock one notch from A to A-.

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

Capital Requirements

Our estimated 2010, 2011 and 2012 capital expenditures reflecting actual costs through June 30, 2010 are as follows:

Capital Expenditures	2010	2011	2012

	(Millions of Dollars)

Renewable	$96.8	$384.7	$179.3
Environmental	229.4	193.9	80.7
Base Spending	300.8	329.1	370.7

Total	$627.0	$907.7	$630.7

Our actual future long-term capital requirements may vary from these estimates because of changing environmental and other regulations such as air quality standards, renewable energy standards and electric reliability initiatives that impact us.

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 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 9 -- Guarantees and Note 11 -- 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 $25.2 billion as of June 30, 2010 compared with $21.4 billion as of December 31, 2009. Our total contractual obligations and other commercial commitments as of June 30, 2010 increased compared with December 31, 2009 primarily because of increased capital lease obligations related to OC 1, which was placed into service in February 2010.

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 2009 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

Under Wisconsin Energy's PTF strategy, we expect to meet a significant portion of our future generation needs through the leasing of the Port Washington Generating Station (PWGS) and the Oak Creek expansion. We are leasing the PWGS units and OC 1 from We Power under long-term leases, and we are currently recovering the lease payments in our electric rates. When OC 2 goes into service, we expect to also recover those lease payments in our electric rates. See Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Item 7 of our 2009 Annual Report on Form 10-K for additional information on PTF.

Oak Creek Expansion: OC 1 was placed into service in February 2010. We expect OC 2 to be placed into service during the fourth quarter of 2010; the guaranteed in-service date for OC 2 is November 28, 2010.

RATES AND REGULATORY MATTERS

2010 Wisconsin Rate Case: In March 2009, we initiated rate proceedings with the PSCW. We initially asked the PSCW to approve a rate increase for our Wisconsin retail electric customers of approximately $76.5 million, or 2.8%, and a rate increase for our natural gas customers of approximately $22.1 million, or 3.6%. In addition, we requested increases of approximately $1.4 million, or 5.8%, and approximately $1.3 million, or 6.8%, for our Milwaukee Downtown (Valley) steam utility customers and Milwaukee County steam utility customers, respectively.

In July 2009, we filed supplemental testimony with the PSCW updating our rate increase request for retail electric customers to reflect the impact of lower sales as a result of the decline in the economy. The effect of the change resulted in us increasing our request from $76.5 million to $126.0 million.

In December 2009, the PSCW authorized rate adjustments related to our request to increase electric, natural gas and steam rates. The PSCW approved the following rate adjustments:

An increase of approximately $85.8 million (3.35%) in our retail electric rates, which included a decrease in base fuel revenues of approximately $111.0 million, or a fuel rate component decrease of 13.8%;
A decrease of approximately $2.0 million (0.35%) for natural gas service; and
A decrease of approximately $0.4 million (1.65%) for our Valley steam utility customers and a decrease of approximately $0.1 million (0.47%) for our Milwaukee County steam utility customers.

These rate adjustments became effective January 1, 2010. In addition, the PSCW lowered our authorized return on equity from 10.75% to 10.4%.

The PSCW also made, among others, the following determinations:

New depreciation rates were incorporated into the new base rates approved in the rate case;
Certain regulatory assets that were scheduled to be fully amortized over the next four years are to instead be amortized over the next eight years; and
We will continue to receive AFUDC on 100% of Construction Work in Progress for the environmental control projects at our Oak Creek Power Plant and at Edgewater Generating Unit 5, and on the Glacier Hills Wind Park.

2010 Michigan Rate Increase Request: In July 2009, we filed a $42 million rate increase request with the MPSC, primarily to recover the costs of PTF projects. Michigan law allows utilities, upon the satisfaction of certain conditions, to self-implement a rate increase request, subject to refund with interest. In December 2009, the MPSC approved our modified self-implementation plan to increase electric rates in Michigan by approximately $12 million effective upon commercial operation of OC 1, which occurred on February 2, 2010. On July 1, 2010, the MPSC issued the final order, approving an additional increase of $11.5 million effective July 2, 2010. The combined total increase, which is subject to appeal, is $23.5 million, or 14.2%. The time period for appeal on this decision is 30 days from the effective date of the order.

2010 Fuel Recovery Request: On February 19, 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 is being 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. On March 25, 2010, the PSCW approved an annual increase of $60.5 million in Wisconsin retail electric rates on an interim basis. The increased rates were effective March 25, 2010. The revenues that we collect are subject to refund with interest at a rate of 10.4%. We expect PSCW review and final approval by the end of 2010.

Wisconsin Electric - Wisconsin Gas Merger: On April 1, 2010, we, along with Wisconsin Gas, filed a joint application with the PSCW to merge Wisconsin Gas into Wisconsin Electric. If approved by the PSCW, we anticipate the merger will be effective January 1, 2011. We do not expect the merger to have any material adverse effect on our financial condition. In addition, we do not expect the merger request to have any negative rate impact on customers.

Wisconsin Fuel Rules: Within the state of Wisconsin, we operate under a fuel cost adjustment clause for fuel and purchased power costs associated with the generation and delivery of electricity and purchased power contracts. Embedded within our base rates is an amount to recover fuel costs. Under the current fuel rules, no adjustments are made to rates as long as fuel and purchased power costs are expected to be within a band of the costs embedded in current rates for the 12-month period ending December 31. If, however, annual fuel costs are expected to fall outside of the band, and actual costs fall outside of established fuel bands, then we may file for a change in fuel recoveries on a prospective basis.

In June 2006, the PSCW opened a docket (01-AC-224) to consider revisions to the existing fuel rules (Chapter PSC 116). In April 2010, the Wisconsin legislature passed the Fuel Rule Bill. The Governor of Wisconsin signed the bill in May 2010. Under this bill, the PSCW will be required to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel costs that are outside of the utility's symmetrical fuel cost tolerance. As part of the new rules, the PSCW would need to establish the size of the symmetrical band and the definition of recoverable fuel and purchased power costs. We expect the new fuel rules to be effective January 1, 2011.

Renewable Energy Portfolio: In July 2008, we completed the purchase of rights to a new wind farm site in Central Wisconsin, Glacier Hills Wind Park, and filed a request for a Certificate of Public Convenience and Necessity (CPCN) with the PSCW in October 2008. The PSCW approved the CPCN in January 2010. We currently expect to install 90 wind turbines with a total generating capacity of approximately 162 MW. This project is expected to cost between $360 million and $370 million, excluding AFUDC. Construction commenced in May 2010, and we anticipate 2012 will be the first full year of operation.

In September 2009, we announced plans to construct 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. We believe the biomass plant will be eligible for either the federal production tax credit or the federal 30% investment tax credit. We currently expect to invest approximately $255 million in the plant and for it to be completed during the fall of 2013, subject to regulatory and other approvals. In March 2010, we filed a request for a Certificate of Authority for the project with the PSCW. We expect the PSCW to approve the Certificate of Authority by the end of 2010.

See Factors Affecting Results, Liquidity and Capital Resources -- Rates and Regulatory Matters in Item 7 of our 2009 Annual Report on Form 10-K for additional information regarding our rates and other regulatory matters.

ELECTRIC TRANSMISSION AND ENERGY MARKETS

MISO: 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, 2010 through May 31, 2011. The resulting ARR valuation and the secured FTRs should mitigate our transmission congestion risk for that period.

ENVIRONMENTAL MATTERS

Proposed New Coal Ash Regulation: We currently have a successful program of beneficial utilization for substantially all of our coal combustion products, including fly ash, bottom ash and gypsum, which avoids the need for disposal in specially-designed landfills. Both Wisconsin and Michigan have regulations governing the use and disposal of these materials. Recently, however, the United States Environmental Protection Agency (EPA) issued a draft rule for public comment proposing various scenarios for regulating coal combustion products including classifying coal ash as hazardous waste. If coal ash is classified as hazardous waste, it could have a material adverse effect on our ability to continue our current program. Curtailing our program could result in the loss of a revenue stream that helps to offset the cost of pollution control equipment and the activities necessary to collect the coal ash.

In addition, if coal ash is classified as hazardous waste and we terminate our coal ash utilization program, we could be required to dispose of the coal ash at a significant cost to the Company.

EPA Regulation of Greenhouse Gas Emissions under the Clean Air Act: In December 2009, the EPA issued its endangerment finding related to greenhouse gas emissions, which set in motion a regulatory process that is leading to regulation of greenhouse gas emissions from stationary sources, including electric generating units, absent legislative or other intervention by the Administration or Congress. On March 29, 2010, the EPA finalized its determination of when the Clean Air Act's (CAA) permitting requirements for emissions from facilities, including electric generating units, would apply to greenhouse gas emissions. The regulation of stationary sources will occur in multiple steps in the coming years, with the first step scheduled to occur on January 2, 2011. The initial step covers sources that are already subject to EPA regulations for pollutants other than greenhouse gas and includes our generating facilities. Several parties have filed for judicial review of some of the EPA's new greenhouse gas rules. Regulation of greenhouse gas emissions from power plants will impact our ability to do maintenance or modify our existing facilities, and permit new facilities.

Clean Air Interstate Rule: The EPA issued the final Clean Air Interstate Rule (CAIR) in March 2005 to facilitate the states in meeting the 8-hour ozone and Fine Particulate Matter (PM_2.5) standards by addressing the regional transport of Sulfur Dioxide (SO₂) and Nitrogen Oxide (NO_x). In 2008, the U.S. Court of Appeals for the D.C. Circuit invalidated several aspects of CAIR and remanded the rule to the EPA to promulgate a replacement rule.

In July 2010, the EPA proposed a Transport Rule to replace CAIR. The proposed Transport Rule, like CAIR, would establish individual state caps for the emissions of SO₂ and NO_x from electric generating units in the Eastern half of the United States, including Michigan and Wisconsin. The CAIR is in effect as of 2009 for NO_x and 2010 for SO₂, but will be replaced with the new requirements of the Transport Rule, if adopted. The Transport Rule will require new reductions in 2012 for NO_x and SO₂ and additional reductions in 2014 for SO₂ for some states, including Wisconsin and Michigan. According to the EPA, the Transport Rule and other actions by States are expected to result in a 71% reduction of SO₂ and a 52% reduction of NO_x emissions from power plants in the eastern United States by 2014 from 2005 emission levels.

Comments on the proposed rule are due in late September and the EPA intends to finalize the rule in mid-2011.

We previously determined that compliance with the NO_x and SO₂ emission reductions requirements under the Consent Decree that we entered into with the EPA in April 2003 would substantially mitigate costs to comply with CAIR and would achieve the levels necessary under at least the first phase of CAIR. Although the proposed limits under the Transport Rule appear to be more stringent, our previous determination remains valid.

See Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7 of our 2009 Annual Report on Form 10-K for additional information regarding environmental matters affecting our operations.

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 United States Department of Energy (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 anticipate that any recoveries will be included in future rate cases.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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 2009 Annual Report on Form 10-K.

ITEM 4T. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures: Our management, with the participation of our Chief Executive Officer and Chief 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 Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period covered by this report. Based upon such evaluation, our Chief Executive Officer and Chief 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 Chief Executive Officer and Chief 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 2009 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, we believe, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material adverse effect on our financial statements.

Cash Balance Pension Plan: On June 30, 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. Counsel representing the plaintiff is attempting to seek class certification for other similarly situated plaintiffs. The complaint alleges 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 are 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. The plaintiff has not specified the amount of relief he is seeking. An adverse outcome of this lawsuit could affect Plan funding and expense. Although we are currently unable to predict the final outcome or impact of this litigation, we are aware that courts in similar lawsuits filed in Wisconsin have found that the interest crediting rates applied by the pension plans involved in those cases were not in compliance with ERISA.

RATES AND REGULATORY MATTERS

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

ITEM 1A. RISK FACTORS

See Item 1A. Risk Factors in our 2009 Annual Report on Form 10-K for a discussion of certain risk factors applicable to us.

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.

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: July 30, 2010	Stephen P. Dickson, Vice President and Controller, Principal Accounting Officer and duly authorized officer