Edgar Filing: WISCONSIN ENERGY CORP

2010 Q1 10-Q UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended March 31, 2010

Commission	Registrant; State of Incorporation		IRS Employer
File Number	Address; and Telephone Number		Identification No.



001-09057	WISCONSIN ENERGY CORPORATION		39-1391525
		(A Wisconsin Corporation)
		231 West Michigan Street
		P.O. Box 1331
		Milwaukee, WI 53201
		(414) 221-2345

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes[X] No[ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

                                 Large accelerated filer [X]                                 Accelerated filer [  ]
                                 Non-accelerated filer [  ] (Do not                      Smaller reporting company [  ]
                                   check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date (March 31, 2010):

Common Stock, $.01 Par Value,

116,900,740 shares outstanding.

		WISCONSIN ENERGY CORPORATION


		FORM 10-Q REPORT FOR THE QUARTER ENDED MARCH 31, 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..............................................................................		22

3.	Quantitative and Qualitative Disclosures About Market Risk.............................................................		33

4.	Controls and Procedures ..................................................................................................................		33

	Part II -- Other Information

1.	Legal Proceedings ............................................................................................................................		34

1A.	Risk Factors ...................................................................................................................................		34

2.	Unregistered Sales of Equity Securities and Use of Proceeds ...........................................................		35

6.	Exhibits ............................................................................................................................................		36

	Signatures ..........................................................................................................................................		37

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

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 Energy Subsidiaries and Affiliates

Primary Subsidiaries
Edison Sault		Edison Sault Electric Company
We Power		W.E. Power, LLC
Wisconsin Electric		Wisconsin Electric Power Company
Wisconsin Gas		Wisconsin Gas LLC

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

Other Subsidiaries and Affiliates
ATC		American Transmission Company LLC
ERGSS		Elm Road Generating Station Supercritical, LLC
ERS		Elm Road Services, LLC
Wispark		Wispark LLC

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

Environmental Terms
CAA		Clean Air Act

Other Terms and Abbreviations
ALJ		Wisconsin Administrative Law Judge
ARRs		Auction Revenue Rights
Bechtel		Bechtel Power Corporation
Compensation Committee		Compensation Committee of the Board of Directors
CPCN		Certificate of Public Convenience and Necessity
Energy Policy Act		Energy Policy Act of 2005
Fitch		Fitch Ratings
FTRs		Financial Transmission Rights
Junior Notes		Wisconsin Energy's 2007 Series A Junior Subordinated Notes due 2067 issued in May 2007
MISO		Midwest Independent Transmission System Operator, Inc.
MISO Energy Markets		MISO Energy and Operating Reserves Markets
Moody's		Moody's Investor Service
OTC		Over-the-Counter
Point Beach		Point Beach Nuclear Power Plant
PSEG		Public Service Enterprise Group
PTF		Power the Future

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:

Settlement Agreement		Settlement Agreement and Release between ERS and Bechtel effective as of December 16, 2009
S&P		Standard & Poor's Ratings Services
WPL		Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corp.

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

Accounting Terms
AFUDC		Allowance for Funds Used During Construction
CWIP		Construction Work in Progress
FASB		Financial Accounting Standards Board
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 our PTF strategy, environmental compliance, transmission service, fuel costs and costs associated with the MISO Energy 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 our 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 and enforcement thereof by FERC and other regulatory agencies; changes in allocation of energy assistance, including state public benefits funds; changes in environmental, tax and

5

other laws and regulations to which we are subject; and changes in the application of existing laws and regulations.

Restrictions imposed by various financing arrangements and regulatory requirements on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans or advances.

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 any of our subsidiaries; and our credit ratings.

The investment performance of our 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.

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

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

The cyclical nature of property values that could affect our real estate investments.

Changes to the legislative or regulatory restrictions or caps on non-utility acquisitions, investments or projects, including the State of Wisconsin's public utility holding company law.

Other business or investment considerations that may be disclosed from time to time in our 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 Energy Corporation is a diversified holding company which conducts its operations primarily in two operating segments: a utility energy segment and a non-utility energy segment. Unless qualified by their context when used in this document, the terms Wisconsin Energy, the Company, our, us or we refer to the holding company and all of its subsidiaries. Our primary subsidiaries are Wisconsin Electric, Wisconsin Gas and We Power.

Utility Energy Segment: Our utility energy segment consists of: Wisconsin Electric, which serves electric customers in Wisconsin and the Upper Peninsula of Michigan, gas customers in Wisconsin and steam customers in metropolitan Milwaukee, Wisconsin; and Wisconsin Gas, which serves gas customers in Wisconsin. Wisconsin Electric and Wisconsin Gas operate under the trade name of "We Energies".

In April 2010, Wisconsin Electric and Wisconsin Gas filed a joint application with the PSCW to merge Wisconsin Gas into Wisconsin Electric.

Non-Utility Energy Segment: Our non-utility energy segment consists primarily of We Power. We Power was formed in 2001 to design, construct, own and lease the new generating capacity included in our PTF strategy. See Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2009 Annual Report on Form 10-K for more information on PTF.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC. We have condensed or omitted some information and note disclosures normally included in financial statements prepared in accordance with 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

PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WISCONSIN ENERGY CORPORATION
CONSOLIDATED CONDENSED INCOME STATEMENTS
(Unaudited)


					Three Months Ended March 31

					2010	2009

				(Millions of Dollars, Except Per Share Amounts)

	Operating Revenues				$1,255.9	$1,396.2

	Operating Expenses
		Fuel and purchased power			277.9	266.4
		Cost of gas sold			355.8	502.7
		Other operation and maintenance			339.7	334.4
		Depreciation, decommissioning
			and amortization		75.2	85.8
		Property and revenue taxes			27.0	28.1

	Total Operating Expenses				1,075.6	1,217.4

	Amortization of Gain				49.4	64.2


	Operating Income				229.7	243.0

	Equity in Earnings of Transmission Affiliate				15.2	14.3
	Other Income, net				6.2	6.3
	Interest Expense, net				49.4	40.8


	Income from Continuing
		Operations Before Income Taxes			201.7	222.8

	Income Taxes				71.9	81.3

	Income from Continuing Operations				129.8	141.5


	Loss from Discontinued
		Operations, Net of Tax			(0.1)	-

	Net Income				$129.7	$141.5




	Earnings Per Share (Basic)
			Continuing operations		$1.11	$1.21
			Discontinued operations		-	-

	Total Earnings Per Share (Basic)				$1.11	$1.21




	Earnings Per Share (Diluted)
			Continuing operations		$1.10	$1.20
			Discontinued operations		-	-

	Total Earnings Per Share (Diluted)				$1.10	$1.20




	Weighted Average Common
		Shares Outstanding (Millions)
			Basic		116.9	116.9
			Diluted		118.4	118.0

	Dividends Per Share of Common Stock				$0.40	$0.3375

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

WISCONSIN ENERGY CORPORATION
CONSOLIDATED CONDENSED BALANCE SHEETS

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

Property, Plant and Equipment
	In service		$ 11,495.0	$ 10,286.6
	Accumulated depreciation		(3,524.5)	(3,472.2)

			7,970.5	6,814.4
	Construction work in progress		1,197.6	2,185.6
	Leased facilities, net		69.1	70.5

		Net Property, Plant and Equipment	9,237.2	9,070.5

Investments
	Equity investment in transmission affiliate		321.2	314.6
	Other		37.7	44.1

		Total Investments	358.9	358.7

Current Assets
	Cash and cash equivalents		12.8	20.9
	Restricted cash		151.0	194.5
	Accounts receivable		407.3	304.4
	Accrued revenues		192.3	290.4
	Materials, supplies and inventories		337.0	379.3
	Regulatory assets		54.4	58.9
	Prepayments and other		165.1	213.3

		Total Current Assets	1,319.9	1,461.7

Deferred Charges and Other Assets
	Regulatory assets		1,179.0	1,192.5
	Goodwill		441.9	441.9
	Other		184.6	172.6

		Total Deferred Charges and Other Assets	1,805.5	1,807.0

Total Assets			$ 12,721.5	$ 12,697.9




Capitalization and Liabilities

Capitalization
	Common equity		$ 3,641.8	$ 3,566.9
	Preferred stock of subsidiary		30.4	30.4
	Long-term debt		4,396.1	3,875.8

		Total Capitalization	8,068.3	7,473.1

Current Liabilities
	Long-term debt due currently		42.7	295.7
	Short-term debt		478.0	825.1
	Accounts payable		279.0	292.2
	Regulatory liabilities		168.4	222.8
	Other		287.2	246.1

		Total Current Liabilities	1,255.3	1,881.9

Deferred Credits and Other Liabilities
	Regulatory liabilities		896.0	886.7
	Deferred income taxes - long-term		1,038.9	1,017.9
	Deferred revenue, net		764.6	739.1
	Pension and other benefit obligations		324.4	319.5
	Other		374.0	379.7

		Total Deferred Credits and Other Liabilities	3,397.9	3,342.9

Total Capitalization and Liabilities			$ 12,721.5	$ 12,697.9





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

WISCONSIN ENERGY CORPORATION
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)

				Three Months Ended March 31

				2010	2009

				(Millions of Dollars)
Operating Activities
	Net income			$ 129.7	$ 141.5
	Reconciliation to cash
		Depreciation, decommissioning and amortization		71.9	87.6
		Amortization of gain		(49.4)	(64.2)
		Equity in earnings of transmission affiliate		(15.2)	(14.3)
		Distributions from transmission affiliate		12.5	11.4
		Deferred income taxes and investment tax credits, net		5.1	(2.8)
		Deferred revenue		32.2	48.6
		Contributions to benefit plans		-	(289.3)
		Change in -	Accounts receivable and accrued revenues	(33.7)	(73.1)
			Inventories	42.3	93.4
			Other current assets	12.2	8.9
			Accounts payable	(36.1)	(119.5)
			Accrued income taxes, net	48.0	82.0
			Deferred costs, net	6.5	11.5
			Other current liabilities	53.1	58.2
		Other, net		24.6	40.4

Cash Provided by Operating Activities				303.7	20.3

Investing Activities
	Capital expenditures			(194.6)	(171.4)
	Investment in transmission affiliate			(3.9)	(6.3)
	Proceeds from asset sales, net			0.2	0.1
	Change in restricted cash			43.5	57.9
	Other, net			(16.3)	(23.3)

Cash Used in Investing Activities				(171.1)	(143.0)

Financing Activities
	Exercise of stock options			19.9	3.0
	Purchase of common stock			(31.8)	(5.6)
	Dividends paid on common stock			(46.8)	(39.5)
	Issuance of long-term debt			530.0	11.5
	Retirement and repurchase of long-term debt			(261.7)	(51.7)
	Change in short-term debt			(347.1)	189.0
	Other, net			(3.2)	0.6

Cash (Used in) Provided by Financing Activities				(140.7)	107.3


Change in Cash and Cash Equivalents				(8.1)	(15.4)

Cash and Cash Equivalents at Beginning of Period				20.9	32.5


Cash and Cash Equivalents at End of Period				$ 12.8	$ 17.1





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

WISCONSIN ENERGY CORPORATION
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Unaudited)

1 -- GENERAL INFORMATION

Our accompanying unaudited consolidated condensed financial statements should be read in conjunction with Item 8, Financial Statements and Supplementary Data, in our 2009 Annual Report on Form 10-K. In the opinion of management, we have included all adjustments, normal and recurring in nature, necessary to a fair presentation of the results of operations, cash flows and financial position in the accompanying income statements, statements of cash flows and balance sheets. The results of operations for the three months ended March 31, 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 FASB 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 12 -- Variable Interest Entities for required disclosures.

3 -- Accounting and Reporting for Power the Future Generating Units

Background: As part of our PTF strategy, our non-utility subsidiary, We Power, has built three new generating units (PWGS 1, PWGS 2 and OC 1) and is in the process of building another new generating unit, OC 2, which are, and will be, leased to our utility subsidiary, Wisconsin Electric, under long-term leases that have been approved by the PSCW. The leases are designed to recover the capital costs of the plant, including a return. PWGS 1 was placed in service in July 2005, PWGS 2 was placed in service in May 2008 and OC 1 was placed in service in February 2010. The accompanying consolidated financial statements eliminate all intercompany transactions between We Power and Wisconsin Electric and reflect the cash inflows from Wisconsin Electric customers and the cash outflows to our vendors and suppliers.

The Oak Creek expansion includes common projects that will benefit the existing units at this site as well as the new units. These projects include a coal handling facility and a water intake system, which were placed into service in November 2007 and January 2009, respectively.

During Construction: Under the terms of each lease, we collect in current rates amounts representing our pre-tax cost of capital (debt and equity) associated with capital expenditures for our PTF units. Our pre-tax cost of capital is approximately 14%. The carrying costs that we collect in rates are recorded as deferred revenue and will be amortized to revenue over the term of each lease once the respective unit is placed into service. During the construction of our PTF units, we capitalize interest costs at an overall weighted-average pre-tax cost of interest which was approximately 5% for the three months ended March 31, 2010 and for the twelve months ended December 31, 2009. Capitalized interest is included in the total cost of the PTF units.

Plant in Service: Once the PTF units are placed in service, we expect to recover in rates the lease costs which reflect the authorized cash construction costs of the units plus a return on the investment. The authorized cash costs are established by the PSCW. The authorized cash costs exclude capitalized interest since carrying costs are recovered during the construction of the units. The lease payments are expected to be levelized, except that OC 1 and OC 2 will be recovered on a levelized basis that has a one time 10.6% escalation after the first

five years of the leases. The leases established a set return on equity component of 12.7% after tax. The interest component of the return is determined up to 180 days prior to the date that the units are placed in service.

We recognize revenues (consisting of the lease payments included in rates and the amortization of the deferred revenue) on a levelized basis over the term of the lease. We depreciate the units on a straight-line basis over their expected service life.

4 -- COMMON EQUITY

Share-Based Compensation Expense: For a description of share-based compensation, including stock options, restricted stock and performance units, see Note J -- 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 outstanding stock options during the period. Shares purchased on the open market by our independent agents are currently used to satisfy share-based awards.

The following table summarizes recorded pre-tax share-based compensation expense and the related tax benefit for share-based awards made to our employees and directors for the three months ended March 31:

	2010	2009

	(Millions of Dollars)

Stock options	$1.9	$2.5
Performance units	2.7	3.8
Restricted stock	0.3	0.2

Share-based compensation expense	$4.9	$6.5




Related tax benefit	$2.0	$2.6

Stock Option Activity: During the first three months of 2010, the Compensation Committee granted 274,750 options that had an estimated fair value of $6.72 per share. During the first three months of 2009, the Compensation Committee granted 1,216,625 options that had an estimated fair value of $8.01 per share. The following assumptions were used to value the 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 our historical experience.

The following is a summary of our stock option activity during the three months ended March 31, 2010:

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

Outstanding as of January 1, 2010	9,087,315	$38.49
Granted	274,750	$49.84
Exercised	(630,079)	$31.64
Forfeited	(5,000)	$45.70

Outstanding as of March 31, 2010	8,726,986	$39.34	5.9	$88.0




Exercisable as of March 31, 2010	5,947,441	$36.37	4.8	$77.6

The intrinsic value of options exercised was $11.5 million and $2.5 million for the three months ended March 31, 2010 and 2009, respectively. Cash received from options exercised was $19.9 million and $3.0 million for the three months ended March 31, 2010 and 2009, respectively. The actual tax benefit realized for the tax deductions from option exercises for the same periods was approximately $4.3 million and $1.0 million, respectively.

Stock options to purchase 274,260 shares of common stock with an exercise price of $49.84 were outstanding during the first three months of 2010, but were not included in the computation of diluted earnings per share because they were anti-dilutive.

The following table summarizes information about our stock options outstanding as of March 31, 2010:

	Options Outstanding			Options Exercisable

		Weighted-Average			Weighted-Average

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

$20.39 to $31.07	1,239,121	$25.26	2.6	1,239,121	$25.26	2.6
$33.44 to $39.48	3,276,602	$35.63	4.7	3,276,602	$35.63	4.7
$42.22 to $49.84	4,211,263	$46.37	7.9	1,431,718	$47.66	6.8

	8,726,986	$39.34	5.9	5,947,441	$36.37	4.8

The following table summarizes information about our non-vested options during the three months ended March 31, 2010:

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


Non-vested as of January 1, 2010	3,665,100	$8.73
Granted	274,750	$6.72
Vested	(1,155,305)	$8.72
Forfeited	(5,000)	$8.53

Non-vested as of March 31, 2010	2,779,545	$8.53

As of March 31, 2010, total compensation costs related to non-vested stock options not yet recognized was approximately $7.4 million, which is expected to be recognized over the next 15 months on a weighted-average basis.

Restricted Shares: During the first three months of 2010, the Compensation Committee granted 46,740 restricted shares to certain key employees and directors. These awards have a three-year vesting period, with

one-third of the award vesting on each anniversary of the grant date. During the vesting period, restricted share recipients have voting rights and are entitled to dividends in the same manner as other shareholders.

The following restricted stock activity occurred during the three months ended March 31, 2010:

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


Outstanding as of January 1, 2010	99,649
Granted	46,740	$49.55
Released	(13,068)	$46.93
Forfeited	(60)	$49.55

Outstanding as of March 31, 2010	133,261

We record the market value of the restricted stock awards on the date of grant and then we charge their value to expense over the vesting period of the awards. The intrinsic value of restricted stock vesting was $0.7 million for the three months ended March 31, 2010. The intrinsic value for the same period in 2009 was $0.6 million. The actual tax benefit realized for the tax deductions from released restricted shares was $0.1 million for the three months ended March 31, 2010, and $0.2 million for the same period in 2009.

As of March 31, 2010, total compensation cost related to restricted stock not yet recognized was approximately $3.3 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 granted 277,915 and 333,220 performance units, respectively, to officers and other key employees under the Wisconsin Energy Performance Unit Plan. Under the grants, the ultimate number of units that will be awarded is dependent upon the achievement of certain financial performance of our 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 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 $9.8 million and $8.4 million, respectively. The actual tax benefit realized for the tax deductions from the settlement of performance units was approximately $3.4 million and $3.1 million, respectively. As of March 31, 2010, total compensation cost related to performance units not yet recognized was approximately $24.3 million, which is expected to be recognized over the next 26 months on a weighted-average basis.

Restrictions: Wisconsin Energy's ability as a holding company to pay common dividends primarily depends on the availability of funds received from its principal utility subsidiaries, Wisconsin Electric and Wisconsin Gas. In the future, as the last of the PTF plants is placed in service, We Power will also be able to provide funds for Wisconsin Energy to pay dividends. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans or advances. In addition, under Wisconsin law, Wisconsin Electric and Wisconsin Gas are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy. See Note J --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.

Our total comprehensive income for the three months ended March 31, 2010 and 2009 was $129.8 million and $141.6 million, respectively, which approximates net income for each of those periods.

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 WPL for our net book value, including working capital. In March 2010, the agreement became effective and we are in the process of requesting regulatory approvals. The completion of the sale is subject to approval by applicable regulatory bodies, including the PSCW and MPSC. If approved, 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.

Edison Sault: In October 2009, we announced that we had reached an agreement to sell Edison Sault to Cloverland Electric Cooperative for approximately $61.5 million, which represents a nominal gain. We will retain Edison Sault's membership interest in ATC. The sale was contingent upon certain conditions, including regulatory approvals, the last of which was received subsequent to March 31, 2010. For the quarter ended March 31, 2010, Edison Sault's operating revenues were $19.2 million. See Note 15 -- Subsequent Event -- Sale of Edison Sault for additional information on this sale.

6 -- LONG-TERM DEBT

In February 2010, we issued a total of $530 million in long-term debt ($255 million aggregate principal amount of 5.209% Series A Senior Notes due February 11, 2030 and $275 million aggregate principal amount of 6.09% Series A Senior Notes due February 11, 2040) and used the net proceeds to repay debt incurred to finance the construction of OC 1.

7 -- 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 OTC forwards and options.

Level 3 -- Pricing inputs include significant inputs that are generally less observable from objective sources. The inputs in the determination of fair value require significant management judgment or estimation. At each balance sheet date, we perform an analysis of all instruments subject to fair value reporting and include in Level 3 all instruments whose fair value is based on significant unobservable inputs.

In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, an instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the instrument.

The following tables summarize our financial assets and liabilities by level within the fair value hierarchy:

Recurring Fair Value Measures	As of March 31, 2010

	Level 1	Level 2	Level 3	Total

	(Millions of Dollars)
Assets:
Restricted Cash	$151.0	$ -	$ -	$151.0
Derivatives	1.8	9.5	1.9	13.2

Total	$152.8	$9.5	$1.9	$164.2

Liabilities:
Derivatives	$18.4	$4.3	$ -	$22.7

Total	$18.4	$4.3	$ -	$22.7

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	0.7	4.2	5.9	10.8

Total	$195.2	$4.2	$5.9	$205.3

Liabilities:
Derivatives	$4.5	$4.8	$ -	$9.3

Total	$4.5	$4.8	$ -	$9.3

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 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:

Fair Value of Derivatives	2010	2009

	(Millions of Dollars)

Balance as of January 1	$5.9	$8.8
Realized and unrealized gains (losses)	-	-
Settlements	(4.0)	(5.9)
Transfers in and/or out of Level 3	-	-

Balance as of March 31	$1.9	$2.9




Change in unrealized gains (losses) relating to instruments still held as of March 31	$ -	$ -

Derivative instruments reflected in Level 3 of the hierarchy include MISO 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 8 -- Derivative Instruments, for further information on the offset to regulatory assets and liabilities.

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

	March 31, 2010		December 31, 2009

	Carrying	Fair	Carrying	Fair
Financial Instruments	Amount	Value	Amount	Value

	(Millions of Dollars)

Preferred stock, no redemption required	$30.4	$21.2	$30.4	$20.2
Long-term debt including current portion	$4,318.0	$4,469.3	$4,049.8	$4,162.5

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

8 -- DERIVATIVE INSTRUMENTS

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

We record derivative instruments on the balance sheet as an asset or liability measured at its fair value, and changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. We do not offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivatives executed with the same counterparty under the same master netting arrangement. As of March 31, 2010, we recognized $33.3 million in regulatory assets and $12.6 million in regulatory liabilities related to derivatives in comparison to $19.1 million in regulatory assets and $10.3 million in regulatory liabilities as of December 31, 2009.

We record our current derivative assets on the balance sheet in Prepayments and other current assets and the current portion of the liabilities in Other current liabilities. The long-term portion of our derivative assets of $1.1 million is recorded in Other deferred charges and other assets and the long-term portion of our derivative liabilities of $1.7 million is recorded in Other deferred credits and other liabilities. Our Consolidated Condensed Balance Sheet as of March 31, 2010 and December 31, 2009 includes:

	March 31, 2010		December 31, 2009

	Derivative Asset	Derivative Liability	Derivative Asset	Derivative Liability

	(Millions of Dollars)

Natural Gas	$5.0	$22.7	$2.2	$9.3
Energy	1.0	-	-	-
Fuel Oil	0.8	-	0.6	-
FTRs	1.9	-	5.9	-
Coal	4.5	-	2.1	-

Total	$13.2	$22.7	$10.8	$9.3

Our Consolidated Condensed Income Statements include gains (losses) on derivative instruments used in our risk management strategies under Fuel and purchased power for those commodities supporting our electric operations and under Cost of gas sold for the natural gas sold to our customers. Our estimated notional volumes and gain (losses) for the quarters ended March 31, 2010 and 2009 follow:

	March 31, 2010		March 31, 2009

	Volume	Gains (Losses)	Volume	Gains (Losses)

		(Millions of Dollars)		(Millions of Dollars)

Natural Gas	28.3 million Dth	($11.7)	22.4 million Dth	($25.3)
Energy	57,200 MWh	0.2	11,920 MWh	(0.5)
Fuel Oil	1.8 million gallons	0.2	0.9 million gallons	(0.3)
FTRs	5,522 MW	9.2	6,283 MW	0.7

Total		($2.1)		($25.4)

As of March 31, 2010 and December 31, 2010, we have posted collateral of $25.7 million and $9.3 million, respectively, in our margin accounts. These amounts are recorded on the balance sheet in Prepayments and other current assets.

9 -- BENEFITS

The components of our net periodic pension and OPEB costs for the three months ended March 31 were as follows:

	Pension Benefits		OPEB

Benefit Plan Cost Components	2010	2009	2010	2009

	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$6.9	$5.3	$2.8	$2.3
Interest cost	17.4	18.2	5.4	5.3
Expected return on plan assets	(19.7)	(23.7)	(3.6)	(3.5)
Amortization of:
Transition obligation	-	-	0.1	0.1
Prior service cost (credit)	0.6	0.6	(3.0)	(3.2)
Actuarial loss	6.6	5.2	2.7	2.3

Net Periodic Benefit Cost	$11.8	$5.6	$4.4	$3.3

In January 2009, the committee that overseas the investment of the pension assets authorized the Trustee of pension plan to invest in the commercial paper of Wisconsin Energy. As of March 31, 2010, the Pension Trust and OPBE plan assets held approximately $23.0 million of commercial paper issued by Wisconsin Energy, which represents less than 10% of the total assets of the plan.

10 -- GUARANTEES

We enter into various guarantees to provide financial and performance assurance to third parties on behalf of our affiliates. As of March 31, 2010, we had the following guarantees:

Maximum Potential Future Payments	Outstanding	Liability Recorded

(Millions of Dollars)
$3.1	$0.3	$ -

A non-utility energy segment guarantee in support of Wisvest-Connecticut, which we sold in December 2002 to PSEG, provides financial assurance for potential obligations relating to environmental remediation under the original purchase agreement for Wisvest-Connecticut with The United Illuminating Company. The potential obligations for environmental remediation, which are unlimited, are reimbursable by PSEG under the terms of the sale agreement in the event that we are required to perform under the guarantee.

We also provide guarantees to support obligations of our affiliates to third parties under loan agreements and surety bonds. In the event our affiliates fail to perform, we would be responsible for the obligations.

Wisconsin Electric is subject to the potential retrospective premiums that could be assessed under its 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 $16.3 million as of March 31, 2010 and $15.8 million as of December 31, 2009.

11 -- SEGMENT INFORMATION

Summarized financial information concerning our reportable operating segments for the three month periods ended March 31, 2010 and 2009 is shown in the following table:

			Corporate &
Reportable Operating Segments			Other (a) &
	Energy		Reconciling	Total

Wisconsin Energy Corporation	Utility	Non-Utility	Items	Consolidated

	(Millions of Dollars)


March 31, 2010
Operating Revenues (b)	$1,250.2	$65.5	($59.8)	$1,255.9
Depreciation, Decommissioning and Amortization	$63.3	$11.7	$0.2	$75.2
Operating Income (Loss)	$179.4	$52.1	($1.8)	$229.7
Equity in Earnings (Loss) of Unconsolidated Affiliates	$15.2	$ -	($0.1)	$15.1
Interest Expense, net	$30.2	$7.4	$11.8	$49.4
Income Tax Expense (Benefit)	$62.8	$18.4	($9.3)	$71.9
Loss from Discontinued Operations, Net of Tax	$ -	$ -	($0.1)	($0.1)
Net Income (Loss)	$107.4	$26.3	($4.0)	$129.7
Capital Expenditures	$131.6	$62.6	$0.4	$194.6
Total Assets (c)	$11,759.3	$2,909.5	($1,947.3)	$12,721.5

March 31, 2009
Operating Revenues (b)	$1,395.6	$36.7	($36.1)	$1,396.2
Depreciation, Decommissioning and Amortization	$78.5	$7.2	$0.1	$85.8
Operating Income (Loss)	$216.3	$27.9	($1.2)	$243.0
Equity in Earnings (Loss) of Unconsolidated Affiliates	$14.3	$ -	($0.1)	$14.2
Interest Expense, net	$30.1	$4.1	$6.6	$40.8
Income Tax Expense (Benefit)	$73.4	$10.8	($2.9)	$81.3
Income (Loss) from Discontinued Operations, Net of Tax	$0.2	$ -	($0.2)	$ -
Net Income (Loss)	$133.4	$13.9	($5.8)	$141.5
Capital Expenditures	$130.2	$41.2	$ -	$171.4
Total Assets (c)	$10,757.2	$2,536.7	($882.8)	$12,411.1

(a)	Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark, as well as interest on corporate debt.

(b)	An elimination for intersegment revenues of $60.0 million and $36.2 million is included in Operating Revenues for the three months ended March 31, 2010 and 2009, respectively. This elimination is primarily between We Power and Wisconsin Electric.

(c)	An elimination of $1,837.7 million and $900.7 million is included in Total Assets at March 31, 2010 and March 31, 2009, respectively, for all PTF-related activity between We Power and Wisconsin Electric.

12 -- 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 $405.9 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 period ended March 31, 2010 was $14.7 million. Our maximum exposure to loss is limited to the capacity payments under the contracts.

13 -- 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.

Divestitures: Over the past several years, we have sold various businesses and assets. In connection with these sales, we have agreed to provide the respective buyers with customary indemnification provisions including, but not limited to, certain environmental, asbestos and product liability matters. In addition, pursuant to the sale of Point Beach, we have agreed to indemnification provisions customary to transactions involving the sale of nuclear assets. We have established reserves as deemed appropriate for these indemnification provisions.

Income Taxes: Within the next 12 months, we believe that our federal and state unrecognized tax benefits may decrease by approximately $12 million to $15 million as the result of payments on tax obligations.

14 -- SUPPLEMENTAL CASH FLOW INFORMATION

During the three months ended March 31, 2010, we paid $12.2 million in interest, capitalized $13.7 million of interest expense and paid $14.3 million in income taxes, net of refunds. During the three months ended March 31, 2009, we paid $14.4 million in interest, capitalized $19.2 million of interest expense and paid $0.8 million in income taxes, net of refunds.

As of March 31, 2010 and March 31, 2009, the amount of accounts payable related to capital expenditures was $37.7 million and $27.5 million, respectively.

15 -- SUBSEQUENT EVENT -- SALE OF EDISON SAULT

We previously announced that we had reached an agreement to sell Edison Sault to Cloverland Electric Cooperative for approximately $61.5 million, which represents a nominal gain. We also announced that we would retain the membership interest in ATC held by Edison Sault. The completion of the sale was contingent upon certain conditions and regulatory approvals. In April 2010, we received approval by the MPSC, the last remaining regulatory approval, and the sale was completed on May 4, 2010. As of March 31, 2010, Edison Sault had approximately $54.5 million of property, plant and equipment and $5.9 million of net current assets. The investment in ATC retained by us was approximately $38.7 million.

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

RESULTS OF OPERATIONS -- THREE MONTHS ENDED MARCH 31, 2010

CONSOLIDATED EARNINGS

The following table compares our operating income by business segment and our net income for the first quarter of 2010 with the first quarter of 2009 including favorable (better (B)) or unfavorable (worse (W)) variances:

	Three Months Ended March 31

	2010	B (W)	2009

	(Millions of Dollars)

Utility Energy Segment	$179.4	($36.9)	$216.3
Non-Utility Energy Segment	52.1	24.2	27.9
Corporate and Other	(1.8)	(0.6)	(1.2)

Total Operating Income	229.7	(13.3)	243.0
Equity in Earnings of Transmission Affiliate	15.2	0.9	14.3
Other Income, net	6.2	(0.1)	6.3
Interest Expense, net	49.4	(8.6)	40.8

Income From Continuing Operations Before Income Taxes	201.7	(21.1)	222.8
Income Taxes	71.9	9.4	81.3

Income From Continuing Operations	129.8	(11.7)	141.5
Loss From Discontinued Operations	(0.1)	(0.1)	-

Net Income	$129.7	($11.8)	$141.5



Diluted Earnings Per Share	$1.10	($0.10)	$1.20

UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Our utility energy segment contributed $179.4 million of Operating Income during the first quarter of 2010, a decrease of $36.9 million, or 17.1%, compared with the first quarter of 2009. The following table summarizes the operating income of this segment between the comparative quarters:

	Three Months Ended March 31

Utility Energy Segment	2010	B (W)	2009

	(Millions of Dollars)
Operating Revenues
Electric	$711.1	$17.6	$693.5
Gas	524.2	(162.7)	686.9
Other	14.9	(0.3)	15.2

Total Operating Revenues	1,250.2	(145.4)	1,395.6
Fuel and Purchased Power	279.1	(11.5)	267.6
Cost of Gas Sold	355.8	146.9	502.7

Gross Margin	615.3	10.0	625.3
Other Operating Expenses
Other Operation and Maintenance	395.2	(28.5)	366.7
Depreciation, Decommissioning
and Amortization	63.3	15.2	78.5
Property and Revenue Taxes	26.8	1.2	28.0

Total Operating Expenses	1,120.2	123.3	1,243.5
Amortization of Gain	49.4	(14.8)	64.2

Operating Income	$179.4	($36.9)	$216.3

The decrease in Operating Income for the three months ended March 31, 2010 as compared to the same period in 2009 was primarily caused by unfavorable recoveries of revenues associated with fuel and purchased power and milder weather in 2010. During the first quarter of 2010, we experienced unfavorable fuel recoveries of approximately $24 million. During the same period in 2009, we experienced favorable fuel recoveries of approximately $28 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 - Utility 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 three months ended March 31:

	Electric Revenues			MWh Sales

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

	(Millions of Dollars)			(Thousands)
Operating Revenues
Residential	$266.8	$3.9	$262.9	2,055.3	(76.7)	2,132.0
Small Commercial/Industrial	223.0	(4.7)	227.7	2,203.8	(75.8)	2,279.6
Large Commercial/Industrial	159.0	13.9	145.1	2,414.1	174.3	2,239.8
Other - Retail	5.8	0.1	5.7	42.0	(0.4)	42.4

Total Retail	654.6	13.2	641.4	6,715.2	21.4	6,693.8
Wholesale - Other	35.3	5.7	29.6	543.1	73.8	469.3
Resale - Utilities	15.3	(2.6)	17.9	366.0	(111.1)	477.1
Other Operating Revenues	5.9	1.3	4.6	-	-	-

Total	$711.1	$17.6	$693.5	7,624.3	(15.9)	7,640.2




Weather -- Degree Days (a)
Heating (3,244 Normal)				3,144	(314)	3,458

(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 a $17.6 million, or 2.5%, when compared to the first quarter of 2009. The most significant factors that caused a change in revenues were:

2010 pricing increases totaling approximately $14.8 million, reflecting the reduction of Point Beach bill credits to retail customers.
Net pricing increases totaling $7.8 million related to Wisconsin and Michigan rate orders. Effective January 1, 2010, Wisconsin Electric's Wisconsin retail rates increased 3.4%. However, the rate component attributable to fuel and purchased power costs decreased by 13.8%.
Unfavorable weather that reduced electric revenues by an estimated $13.3 million as compared to the first quarter of 2009.

As measured by heating degree days, the first quarter of 2010 was 9.1% warmer than the same period in 2009 and 3.1% warmer than normal. Retail sales to our residential and small commercial and industrial customers decreased by 3.3% primarily due to weather. Sales to our large commercial and industrial customers increased by 7.8% during the first quarter of 2010 as compared to the same period in 2009. However, electric sales to our largest customers, two iron ore mines, which represent approximately 6.0% of our annual sales, increased significantly for the quarter. If these sales are excluded, sales to our large commercial and industrial customers increased 0.6% for the first quarter of 2010 as compared to the first quarter of 2009.

Fuel and Purchased Power

Our fuel and purchased power costs increased by $11.5 million, or 4.3%, when compared to the first quarter of 2009. This increase was primarily caused by higher coal and transportation costs. We expect fuel and purchased power costs for the remainder of 2010 to be impacted primarily by higher coal and transportation costs and higher MWh sales as compared with 2009.

Gas Utility Revenues, Gross Margin and Therm Deliveries

A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the first quarter of 2010 with similar information for the first 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 revenues decreased by $162.7 million, or 23.7%, primarily due to milder weather and lower natural gas costs.

	Three Months Ended March 31

Gas Utility Operations	2010	B (W)	2009

	(Millions of Dollars)

Gas Operating Revenues	$524.2	($162.7)	$686.9
Cost of Gas Sold	355.8	146.9	502.7

Gross Margin	$168.4	($15.8)	$184.2

The following table compares our gas utility gross margin and therm deliveries by customer class during the three months ended March 31:

	Gross Margin			Therm Deliveries

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

	(Millions of Dollars)			(Millions)
Customer Class
Residential	$109.0	($9.0)	$118.0	348.8	(41.2)	390.0
Commercial/Industrial	40.8	(6.6)	47.4	199.0	(32.3)	231.3
Interruptible	0.7	-	0.7	7.5	0.4	7.1

Total Retail	150.5	(15.6)	166.1	555.3	(73.1)	628.4
Transported Gas	15.4	0.2	15.2	284.4	11.5	272.9
Other	2.5	(0.4)	2.9	-	-	-

Total	$168.4	($15.8)	$184.2	839.7	(61.6)	901.3




Weather -- Degree Days (a)
Heating (3,244 Normal)				3,144	(314)	3,458

(a)	As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a 20-year moving average.

Our gas margins decreased by $15.8 million, or approximately 8.6%, when compared to the first quarter of 2009. We estimate that approximately $13.5 million of this decrease relates to a decline in sales volumes as a result of milder winter weather during the first quarter of 2010 as compared to the first quarter of 2009. As measured by heating degree days, the first three months of 2010 were 9.1% warmer than the same period in 2009 and 3.1% warmer than normal.

Other Operation and Maintenance Expense

Our other operation and maintenance expense increased by $28.5 million, or approximately 7.8%, when compared to the first 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 $22.3 million higher in the first quarter of 2010 as compared to the same period in 2009. In addition, operation and maintenance expenses at our power plants increased approximately $7.5 million primarily due to the operation of OC 1, which was placed in service in February 2010.

Depreciation, Decommissioning and Amortization Expense

Our depreciation, decommissioning and amortization expense decreased by $15.2 million, or approximately 19.4%, when compared to the first quarter of 2009, primarily due to 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 an agreement 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 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 first three months of 2010 and 2009, the Amortization of Gain was $49.4 million and $64.2 million, respectively.

For 2010, we expect to see a reduction in the Amortization of Gain of approximately $37.0 million as compared to 2009 because of the scheduled decrease in bill credits. We expect that all remaining bill credits will be issued by the end of 2010.

NON-UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Our non-utility energy segment consists primarily of our PTF units (PWGS 1, PWGS 2, OC 1 and OC 2). PWGS 1 and 2 were placed in service in July 2005 and May 2008, respectively. The common facilities associated with the Oak Creek expansion consist of the water intake system, which was placed in service in January 2009, and the coal handling system and other smaller assets, which were placed in service prior to January 1, 2009. OC 1 was placed in service in February 2010. The guaranteed in-service date for OC 2 is November 28, 2010.

The table below reflects a full quarter's earnings for 2010 and 2009 for PWGS 1 and 2 and the common facilities for the Oak Creek expansion. It also reflects two months of earnings in 2010 for OC 1. This segment reflects the lease revenues on the new units, as well as the depreciation expense. The operating and maintenance costs associated with the plants are the responsibility of Wisconsin Electric and are recorded in the utility segment.

	Quarter Ended March 31, 2010

	(Millions of Dollars)

	Port Washington	Oak Creek Expansion	All Other	Total

Operating Revenues	$26.0	$39.4	$0.1	$65.5
Operation and Maintenance Expense	0.1	0.7	0.9	1.7
Depreciation Expense	4.9	6.4	0.4	11.7

Operating Income	$21.0	$32.3	($1.2)	$52.1

	Quarter Ended March 31, 2009

	(Millions of Dollars)

	Port Washington	Oak Creek Expansion	All Other	Total

Operating Revenues	$26.2	$10.4	$0.1	$36.7
Operation and Maintenance Expense	0.1	0.7	0.8	1.6
Depreciation Expense	4.9	1.8	0.5	7.2

Operating Income	$21.2	$7.9	($1.2)	$27.9

CONSOLIDATED OTHER INCOME, NET

Other income, net, was $6.2 million during the first quarter of 2010 as compared to $6.3 million during the first quarter of 2009.

CONSOLIDATED INTEREST EXPENSE, NET

	Three Months Ended March 31

Interest Expense	2010	2009

	(Millions of Dollars)

Gross Interest Costs	$63.1	$60.0
Less: Capitalized Interest	13.7	19.2

Interest Expense, Net	$49.4	$40.8

Our gross interest costs increased by $3.1 million during the first quarter of 2010, primarily due to higher debt balances compared to the same period in 2009. In February 2010, we issued $530 million of long-term debt in connection with the commercial operation of OC 1 and used the net proceeds to repay debt incurred for construction. Our capitalized interest decreased by $5.5 million primarily because OC 1 was placed in service in February 2010. As a result, our net interest expense increased by $8.6 million, or 21.1%, as compared to the first quarter of 2009.

CONSOLIDATED INCOME TAXES

For the first quarter of 2010, our effective tax rate applicable to continuing operations was 35.6% compared to 36.5% for the first quarter of 2009. 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 from continuing operations during the three months ended March 31:

Wisconsin Energy Corporation	2010	2009

	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$303.7	$20.3
Investing Activities	($171.1)	($143.0)
Financing Activities	($140.7)	$107.3

Operating Activities

Cash provided by operating activities was $303.7 million during 2010, which was $283.4 million higher than 2009. The largest item which led to the increase in cash from operations related to $289.3 million of contributions to our benefit plans in the first quarter of 2009. No such contributions were required in the first quarter of 2010.

Investing Activities

Cash used in investing activities was $171.1 million during the three months ended March 31, 2010, which was $28.1 million higher than the same period in 2009. Our capital expenditures increased by $23.2 million during the three months ended March 31, 2010 as compared to the same period in 2009 primarily because of increased expenditures for OC 1 resulting from milestones achieved in 2010 related to the Settlement Agreement with Bechtel.

Financing Activities

Cash used in financing activities during the three months ended March 31, 2010 was $140.7 million, compared to cash provided by financing activities during the same period in 2009 of $107.3 million. Our operating cash flows during the first quarter of 2010 allowed us to increase our dividends and reduce our net debt levels during the quarter. During the first quarter of 2010, we paid approximately $46.8 million in cash dividends and reduced our net debt levels by approximately $78.8 million. For additional information on debt issuances, see Note 6 -- Long-Term Debt in the Notes to Consolidated Condensed Financial Statements.

During the first three months of 2010, we received proceeds of $19.9 million related to the exercise of stock options, compared with $3.0 million during the same period in 2009. Instead of issuing new shares for these stock options, we instructed our plan agent to purchase common stock in the open market at a cost of $31.8 million, compared with $5.6 million in the first quarter of 2009. This cost is included in Purchase of common stock on our Consolidated Condensed Statements of Cash Flows.

CAPITAL RESOURCES AND REQUIREMENTS
Capital Resources

We anticipate meeting our capital requirements during the remaining nine 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. Beyond 2010, we anticipate meeting our capital requirements through internally generated funds supplemented when required, by short-term borrowings and the issuance of debt securities.

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

Wisconsin Energy, Wisconsin Electric and Wisconsin Gas maintain bank back-up credit facilities, which provide liquidity support for each company's obligations with respect to commercial paper and for general corporate purposes.

An affiliate of Lehman Brothers Holdings, which filed for bankruptcy in September 2008, provided approximately $80 million of commitments under our bank back-up credit facilities on a consolidated basis. We have no current plans to replace Lehman's commitments. Excluding Lehman's commitments, as of March 31, 2010, we had approximately $1.6 billion of available, undrawn lines under our bank back-up credit facilities. As of March 31, 2010, we had approximately $478.0 million of short-term debt outstanding on a consolidated basis 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 facilities at March 31, 2010:

Company	Total Facility*	Letters of Credit	Credit Available *	Facility Expiration

	(Millions of Dollars)

Wisconsin Energy	$857.5	$1.1	$856.4	April 2011
Wisconsin Electric	$476.4	$2.3	$474.1	March 2011
Wisconsin Gas	$285.8	$ -	$285.8	March 2011

*	Excludes Lehman's commitments

The following table shows our capitalization structure as of March 31, 2010, as well as an adjusted capitalization structure that we believe is consistent with the manner in which the majority of rating agencies currently view the Junior Notes:

Capitalization Structure	Actual	Adjusted

	(Millions of Dollars)

Common Equity	$3,641.8	$3,891.8
Preferred Stock of Subsidiary	30.4	30.4
Long-Term Debt (including current maturities)	4,438.8	4,188.8
Short-Term Debt	478.0	478.0

Total Capitalization	$8,589.0	$8,589.0




Total Debt	$4,916.8	$4,666.8

Ratio of Debt to Total Capitalization	57.2%	54.3%

Included in Long-Term Debt on our Consolidated Condensed Balance Sheet as of March 31, 2010 is $500 million aggregate principal amount of the Junior Notes. The adjusted presentation attributes $250 million of the Junior Notes to Common Equity and $250 million to Long-Term Debt. We believe this presentation is consistent with the 50% equity credit the majority of rating agencies currently attribute to the Junior Notes.

The adjusted presentation of our consolidated capitalization structure is presented as a complement to our capitalization structure presented in accordance with GAAP. Management evaluates and manages Wisconsin Energy's capitalization structure, including its total debt to total capitalization ratio, using the GAAP calculation as adjusted by the rating agency treatment of the Junior Notes. Therefore, we believe the non-GAAP adjusted presentation reflecting this treatment is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.

Wisconsin Electric is the obligor under two series of tax-exempt pollution control refunding bonds in outstanding principal amounts of $147 million. In August 2009, Wisconsin Electric terminated letters of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. Wisconsin Electric issued commercial paper to fund the purchase of the bonds. As of March 31, 2010, the repurchased bonds were still outstanding, but were reported as a reduction in our consolidated long-term debt because they are held by Wisconsin Electric. Depending on market conditions and other factors, Wisconsin Electric may change the method used to determine the interest rate on the bonds and have them remarketed to third parties.

Access to capital markets at a reasonable cost is determined in large part by credit quality. The following table summarizes the ratings of our debt securities and the debt securities and preferred stock of our subsidiaries by S&P, Moody's and Fitch as of March 31, 2010:

	S&P	Moody's	Fitch

Wisconsin Energy
Commercial Paper	A-2	P-2	F2
Unsecured Senior Debt	BBB+	A3	A-
Unsecured Junior Notes	BBB-	Baa1	BBB

Wisconsin Electric
Commercial Paper	A-2	P-1	F1
Secured Senior Debt	A-	Aa3	AA-
Unsecured Debt	A-	A1	A+
Preferred Stock	BBB	A3	A-

Wisconsin Gas
Commercial Paper	A-2	P-1	F1
Unsecured Senior Debt	A-	A1	A+

Wisconsin Energy Capital Corporation
Unsecured Debt	BBB+	A3	A-

Fitch recently revised its ratings guidelines on corporate and utility hybrid and preferred securities. These ratings guideline revisions reduced the ratings of Wisconsin Energy's Unsecured Junior Notes and Wisconsin Electric's Preferred Stock one notch from BBB+ to BBB and from A to A -, respectively.

In February 2010, S&P, Moody's and Fitch rated ERGSS's Senior Notes A-, A1 and A+, respectively. The ratings outlook assigned by S&P, Moody's and Fitch to ERGSS is stable, stable and negative, respectively.

Subject to other factors affecting the credit markets as a whole, we believe these 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, but rather an indication of creditworthiness. 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. Each rating should be evaluated independently of any other rating.

Capital Requirements

Capital requirements during the remainder of 2010 are expected to be principally for capital expenditures in our utility operations relating to our electric distribution system and environmental controls at our existing Oak Creek generating units. Our 2010 consolidated capital expenditure budget is approximately $950.5 million.

Off-Balance Sheet Arrangements: We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support construction projects, commodity contracts and other payment obligations. We continue to believe that these agreements do not have, and are not reasonably likely to have, a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors. For further information, see Note 10 -- Guarantees and Note 12 -- 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 $22.1 billion as of March 31, 2010 compared with $21.5 billion as of December 31, 2009. Our total contractual obligations and other commercial commitments as of March 31, 2010 increased compared with December 31, 2009 primarily due to long-term debt issued in February 2010 in connection with the commercial operation of OC 1. This increase was partially offset by periodic payments made in the ordinary course of business during the quarter.

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, our PTF strategy, utility rates and regulatory matters, electric system reliability, environmental matters, legal matters, industry restructuring and competition and other matters.

POWER THE FUTURE

Under our PTF strategy, we expect to meet a significant portion of our future generation needs through the construction of the PWGS and the Oak Creek expansion by We Power. We Power leases the new units to Wisconsin Electric under long-term leases, and we expect Wisconsin Electric to recover the lease payments in its 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. The guaranteed in-service date for OC 2 is November 28, 2010.

UTILITY RATES AND REGULATORY MATTERS

2010 Rate Case: In March 2009, Wisconsin Electric and Wisconsin Gas initiated rate proceedings with the PSCW. Wisconsin Electric initially asked the PSCW to approve a rate increase for its Wisconsin retail electric customers of approximately $76.5 million, or 2.8%, and a rate increase for its natural gas customers of approximately $22.1 million, or 3.6%. In addition, Wisconsin Electric requested increases of approximately $1.4 million, or 5.8%, and approximately $1.3 million, or 6.8%, for its Milwaukee Downtown (Valley) steam utility customers and Milwaukee County steam utility customers, respectively. Wisconsin Gas asked the PSCW to approve a rate increase for its natural gas customers of approximately $38.9 million, or 4.6%. In July 2009, Wisconsin Electric filed supplemental testimony with the PSCW updating its 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 Wisconsin Electric increasing its request from $76.5 million to $126.0 million.

In December 2009, the PSCW authorized rate adjustments related to Wisconsin Electric's and Wisconsin Gas' requests 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 retail electric rates for Wisconsin Electric;
A decrease of approximately $2.0 million (0.35%) for natural gas service for Wisconsin Electric;
An increase of approximately $5.7 million (0.70%) for natural gas service for Wisconsin Gas; and
A decrease of approximately $0.4 million (1.65%) for Wisconsin Electric's Valley steam utility customers and a decrease of approximately $0.1 million (0.47%) for its Milwaukee County steam utility customers.

These rate adjustments became effective January 1, 2010. In addition, the PSCW lowered the authorized return on equity for Wisconsin Electric from 10.75% to 10.4% and for Wisconsin Gas from 10.75% to 10.5%.

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

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

2010 Michigan Rate Increase Request: In July 2009, Wisconsin Electric 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 Wisconsin Electric's modified self-implementation plan to increase electric rates in Michigan by approximately $12 million, or 9.5%, effective upon commercial operation of OC 1, which occurred on February 2, 2010. This rate increase is subject to refund with interest, depending upon the MPSC's final decision on Wisconsin Electric's $42 million rate request which is expected in July 2010.

2010 Fuel Recovery Request: On February 19, 2010, Wisconsin Electric 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% pending PSCW review and final approval, which we expect by the end of 2010.

Wisconsin Electric - Wisconsin Gas Merger: On April 1, 2010, Wisconsin Electric and 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 would be completed by the end of 2010. We do not expect the merger to have any material effect on our results of operations. In addition, we do not expect the merger request to have any negative rate impact on customers.

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 CPCN with the PSCW in October 2008. The PSCW approved the CPCN in January 2010. We currently expect to install up to 90 wind turbines with a total generating capacity of up to approximately 162 MW, subject to the final site configuration. This project is expected to cost between $360 and $370 million, excluding AFUDC. We anticipate 2012 to 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 sawdust will be used to produce approximately 50 MW of 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 -- Utility Rates and Regulatory Matters in Item 7 of our 2009 Annual Report on Form 10-K for additional information regarding our utility rates and other regulatory matters.

ENVIRONMENTAL MATTERS

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. This determination provides that the atmospheric mix of six greenhouse gases endanger public health and welfare. The determination specifically addresses only the contribution to air pollution of greenhouse gas emissions from motor vehicles. On March 29, 2010, the EPA finalized its determination of when the CAA's permitting requirements for emissions from facilities, including electric generating units, would apply to greenhouse gas emissions. The agency determined that greenhouse gas emissions from such facilities will be subject to regulation under the CAA beginning on January 2, 2011, the date that the motor vehicle standards take effect. On April 1, 2010, the EPA issued its final motor vehicle rule establishing limits on greenhouse gas emissions from new motor vehicles. These actions set in motion a regulatory process that will lead to regulation of greenhouse gas emissions from stationary sources, including electric generating units, absent legislative action or intervention by the Administration. Regulation of greenhouse gas emissions from power plants will impact our ability to do maintenance or modify our existing facilities, and permit new facilities.

In September 2009, the EPA issued two proposals intended to provide guidance on, and effectively change how the CAA's existing permitting requirements could be applied to sources of greenhouse gas emissions in all sectors of the economy, including major stationary sources of air pollutants like electric generating plants. The endangerment finding, the regulation of greenhouse gas emissions from motor vehicles and these two additional proposals, when finalized, will provide a framework for the EPA to regulate greenhouse gas emissions from major sources under the CAA.

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 and Storage 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. Wisconsin Electric owned Point Beach through September 2007 and placed approximately $215.2 million into this fund. Effective January 31, 1998, the DOE failed to meet its contractual obligation to begin removing used fuel from Point Beach. Wisconsin Electric 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 favor of Wisconsin Electric, 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 Energy Corporation, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Factors Affecting Results, Liquidity and Capital Resources -- Market Risks and Other Significant Risks, in Part II of our 2009 Annual Report on Form 10-K.

ITEM 4. 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 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, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material adverse effect on our financial statements.

UTILITY RATES AND REGULATORY MATTERS

See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters in Part I of this report for information concerning rate matters in the jurisdictions where Wisconsin Electric, Wisconsin Gas and Edison Sault 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 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table sets forth information regarding the purchases of our equity securities made by or on behalf of us or any affiliated purchaser (as defined in Exchange Act Rule 10b-18) during the three months ended March 31, 2010:

ISSUER PURCHASES OF EQUITY SECURITIES

2010	Total Number of Shares Purchased (a)	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs

				(Millions of Dollars)

January 1- January 31	224	$49.16	-	$ -

February 1- February 28	-	-	-	$ -

March 1- March 31	-	-	-	$ -

Total	224	$49.16	-	$ -

(a)	All shares reported during the quarter were surrendered by employees to satisfy tax withholding obligations upon vesting of restricted stock.

ITEM 6. EXHIBITS

Exhibit No.

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

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

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

32	Section 1350 Certifications

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

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

101	Interactive Data File

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	WISCONSIN ENERGY CORPORATION
	(Registrant)

	/s/STEPHEN P. DICKSON
Date: May 6, 2010	Stephen P. Dickson, Vice President and Controller, Principal Accounting Officer and duly authorized officer