Edgar Filing: WISCONSIN ENERGY CORP

2007 Q2 10-Q UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-Q

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

For the Quarterly Period Ended June 30, 2007

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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer [X] Accelerated filer [ ] Non-accelerated filer [ ].

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date (June 30, 2007):

Common Stock, $.01 Par Value,

116,948,339 shares outstanding.

		WISCONSIN ENERGY CORPORATION


		FORM 10-Q REPORT FOR THE QUARTER ENDED JUNE 30, 2007



		TABLE OF CONTENTS
Item			Page

	Introduction		8

	Part I -- Financial Information

1.	Financial Statements

	Consolidated Condensed Income Statements		9

	Consolidated Condensed Balance Sheets		10

	Consolidated Condensed Statements of Cash Flows		11

	Notes to Consolidated Condensed Financial Statements		12

2.	Management's Discussion and Analysis of
	Financial Condition and Results of Operations		23

3.	Quantitative and Qualitative Disclosures About Market Risk		42

4.	Controls and Procedures		42

	Part II -- Other Information

1.	Legal Proceedings		43

1A.	Risk Factors		44

2.	Unregistered Sales of Equity Securities and Use of Proceeds		44

4.	Submission of Matters to a Vote of Security Holders		44

6.	Exhibits		46

	Signatures		47

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
Point Beach		Point Beach Nuclear Plant
PWGS		Port Washington Generating Station
PWGS 1		Port Washington Generating Station Unit 1
PWGS 2		Port Washington Generating Station Unit 2


Other Affiliates and Subsidiaries
Minergy		Minergy Corp.
NMC		Nuclear Management Company, LLC
Wispark		Wispark LLC


Federal and State Regulatory Agencies
EPA		United States Environmental Protection Agency
FAA		Federal Aviation Administration
FERC		Federal Energy Regulatory Commission
MPSC		Michigan Public Service Commission
NRC		United States Nuclear Regulatory Commission
PSCW		Public Service Commission of Wisconsin
SEC		Securities and Exchange Commission
WDNR		Wisconsin Department of Natural Resources


Environmental Terms
BTA		Best Technology Available
CAIR		Clean Air Interstate Rule
CO₂		Carbon Dioxide
CWA		Clean Water Act
NAAQS		National Ambient Air Quality Standards
NO_X		Nitrogen Oxide
PM_2.5		Fine Particulate Matter
SIP		State Implementation Plans
SO₂		Sulfur Dioxide
WPDES		Wisconsin Pollution Discharge Elimination System

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.

Other Terms and Abbreviations
ALJ		Wisconsin Administrative Law Judge
Compensation Committee		Compensation Committee of the Board of Directors
CPCN		Certificate of Public Convenience and Necessity
FPL		FPL Group, Inc.
FTRs		Financial Transmission Rights
Junior Notes		Wisconsin Energy's 2007 Series A Junior Subordinated Notes due 2067 issued in May 2007
LMP		Locational Marginal Price
MISO		Midwest Independent Transmission System Operator, Inc.
MISO Midwest Market		MISO bid-based energy market
Moody's		Moody's Investor Services
PTF		Power the Future
PSEG		Public Service Enterprise Group
RCC		Replacement Capital Covenant dated May 11, 2007
RTO		Regional Transmission Organizations
S&P		Standard & Poors Corporation
UI		The United Illuminating Company


Measurements
MW		Megawatt(s) (One MW equals one million watts)
MWh		Megawatt-hour(s)


Accounting Terms
AFUDC		Allowance for Funds Used During Construction
CWIP		Construction Work in Progress
FASB		Financial Accounting Standards Board
FIN		FASB Interpretation
GAAP		Generally Accepted Accounting Principles
OPEB		Other Post-Retirement Employee Benefits
SFAS		Statement of Financial Accounting Standards


Accounting Pronouncements
FIN 46		Consolidation of Variable Interest Entities
FIN 48		Accounting for Uncertainty in Income Taxes
SFAS 109		Accounting for Income Taxes
SFAS 123R		Share-Based Payment (Revised 2004)
SFAS 133		Accounting for Derivative Instruments and Hedging Activities
SFAS 149		Amendment of SFAS 133 on Derivative Instruments and Hedging Activities
SFAS 157		Fair Value Measurements
SFAS 159		The Fair Value Option for Financial Assets and Financial Liabilities

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Certain statements contained in this report and other documents or oral presentations are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. 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 completion of construction projects, regulatory matters, fuel costs, sources of electric energy supply, the proposed sale of Point Beach, 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," "intends," "may," "objectives," "plans," "possible," "potential," "projects" 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, nuclear 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; nuclear or environmental incidents; resolution of used nuclear fuel storage and disposal issues; electric transmission or gas pipeline system constraints; unanticipated organizational structure or key personnel changes; collective bargaining agreements with union employees or work stoppages; inflation rates; or demographic and economic factors affecting utility service territories or operating environment.

Regulatory factors such as unanticipated changes in rate-setting policies or procedures; unanticipated changes in regulatory accounting policies and practices; industry restructuring initiatives; transmission or distribution system operation and/or administration initiatives; recovery of costs of previous investments made under traditional regulation; recovery of costs associated with adoption of changed accounting standards; required changes in facilities or operations to reduce the risks or impacts of potential terrorist activities; required approvals for new construction; changes in the NRC's regulations related to Point Beach or a permanent repository for used nuclear fuel; changes in the regulations of the EPA as well as the WDNR, the Michigan Department of Natural Resources or the Michigan Department of Environmental Quality, including but not limited to regulations relating to the release of emissions from fossil-fueled power plants such as CO₂, SO₂, NO_x, small particulates or mercury, water quality and lead paint; and regulations relating to the intake and discharge of water; the siting approval process for new generation and transmission facilities; recovery of costs associated with implementation of a bid-based energy market; or changes in the regulations from the WDNR related to the siting approval process for new pipeline construction.

The changing electric and gas utility environment as market-based forces replace strict industry regulation and other competitors enter the electric and gas markets resulting in increased wholesale and retail competition.

5

Unanticipated operational and/or financial consequences related to implementation of the MISO Midwest Market that started in April 2005.

Consolidation of the industry as a result of the combination and acquisition of utilities in the Midwest, nationally and globally as a result of the repeal of the Public Utility Holding Company Act of 1935 or otherwise.

Factors related to the proposed sale of Point Beach including receipt of the necessary approvals by various regulatory agencies, including the NRC, PSCW, MPSC and FERC for the transaction; and our ability to retain certain assets for the benefit of customers in the decommissioning trusts.

Factors which impede execution of our PTF strategy, including receipt of necessary state and federal regulatory approvals, timely and successful resolution of legal challenges, local opposition to siting of new generating facilities, construction risks, including the adverse interpretation or enforcement of permit conditions by the permitting agencies, and obtaining the investment capital from outside sources necessary to implement the strategy.

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.

Changes in social attitudes regarding the utility and power industries.

Customer business conditions including demand for their products or services and supply of labor and material used in creating their products and services.

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

Factors affecting the availability or cost of capital such as: changes in interest rates and other general capital market conditions; our capitalization structure; market perceptions of the utility industry, us or any of our subsidiaries; or security ratings.

Federal, state or local legislative factors such as changes in tax laws or rates; changes in trade, monetary and fiscal policies, laws and regulations; electric and gas industry restructuring initiatives; changes in the Price-Anderson Act; changes in environmental laws and regulations; or changes in allocation of energy assistance, including state public benefits funds.

Implementation of the Energy Policy Act of 2005 and the effect of state level proceedings and the development of regulations by federal and other agencies, including FERC.

Authoritative GAAP or policy changes from such standard setting bodies as the FASB, the SEC and the Public Company Accounting Oversight Board.

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

Possible risks associated with non-utility operations and investments, such as: general economic conditions; competition; operating risks; dependence upon certain suppliers and customers; the cyclical nature of property values that could affect real estate investments; unanticipated changes in environmental or energy regulations; and risks associated with minority investments, where there is a limited ability to control the development, management or operation of the project.

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

6

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, 2006.

Wisconsin Energy Corporation expressly disclaims 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 metro Milwaukee, Wisconsin; Wisconsin Gas, which serves gas customers in Wisconsin and water customers in suburban Milwaukee, Wisconsin; and Edison Sault, which serves electric customers in the Upper Peninsula of Michigan. Wisconsin Electric and Wisconsin Gas operate under the trade name of "We Energies".

Proposed Sale of Point Beach: In December 2006, we announced that Wisconsin Electric had signed a definitive agreement with an affiliate of FPL to sell Point Beach for approximately $998 million, subject to closing price adjustments. See Note 4 -- Proposed Sale of Point Beach in the Notes to Consolidated Condensed Financial Statements in this report.

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 to Wisconsin Electric 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 2006 Annual Report on Form 10-K for more information on PTF.

Other: Our other non-utility operating subsidiaries include Wispark, which has approximately $54.1 million of assets and develops and invests in real estate.

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 2006 Annual Report on Form 10-K, including the financial statements and notes therein.

WISCONSIN ENERGY CORPORATION

PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WISCONSIN ENERGY CORPORATION
CONSOLIDATED CONDENSED INCOME STATEMENTS
(Unaudited)

				Three Months Ended June 30		Six Months Ended June 30

				2007	2006	2007	2006

				(Millions of Dollars, Except Per Share Amounts)

	Operating Revenues			$906.5	$814.4	$2,207.6	$2,061.4

	Operating Expenses
		Fuel and purchased power		232.3	184.8	461.8	354.0
		Cost of gas sold		158.6	129.6	632.4	610.0
		Other operation and maintenance		304.2	290.1	607.2	588.0
		Depreciation, decommissioning
			and amortization	81.2	78.8	165.3	161.4
		Property and revenue taxes		25.1	24.0	51.3	49.3

	Total Operating Expenses			801.4	707.3	1,918.0	1,762.7


	Operating Income			105.1	107.1	289.6	298.7

	Equity in Earnings of Transmission Affiliate			10.5	9.4	21.2	19.0
	Other Income, Net			19.8	18.3	33.0	29.6
	Interest Expense			42.0	42.6	84.7	87.8


	Income From Continuing
		Operations Before Income Taxes		93.4	92.2	259.1	259.5

	Income Taxes			35.7	32.5	100.3	95.4

	Income from Continuing Operations			57.7	59.7	158.8	164.1

	Income (Loss) from Discontinued
		Operations, Net of Tax		(0.2)	3.2	(0.4)	4.5

	Net Income			$57.5	$62.9	$158.4	$168.6




	Earnings Per Share (Basic)
			Continuing operations	$0.49	$0.51	$1.35	$1.40
			Discontinued operations	-	0.03	-	0.04

	Total Earnings Per Share (Basic)			$0.49	$0.54	$1.35	$1.44




	Earnings Per Share (Diluted)
			Continuing operations	$0.49	$0.50	$1.34	$1.38
			Discontinued operations	-	0.03	-	0.04

	Total Earnings Per Share (Diluted)			$0.49	$0.53	$1.34	$1.42




	Weighted Average Common
		Shares Outstanding (Millions)
			Basic	116.9	117.0	117.0	117.0
			Diluted	118.5	118.4	118.6	118.4

	Dividends Per Share of Common Stock			$0.25	$0.23	$0.50	$0.46

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

WISCONSIN ENERGY CORPORATION
CONSOLIDATED CONDENSED BALANCE SHEETS

			(Unaudited)
			June 30, 2007	December 31, 2006
			(Millions of Dollars)
Assets

Property, Plant and Equipment
	In service		$ 9,413.3	$ 9,265.4
	Accumulated depreciation		(3,490.9)	(3,423.7)

			5,922.4	5,841.7
	Construction work in progress		1,360.0	992.4
	Leased facilities, net		84.7	87.5
	Nuclear fuel, net		119.5	130.9

		Net Property, Plant and Equipment	7,486.6	7,052.5

Investments
	Nuclear decommissioning trust fund		929.1	881.6
	Equity investment in transmission affiliate		234.0	228.5
	Other		43.6	54.7

		Total Investments	1,206.7	1,164.8

Current Assets
	Cash and cash equivalents		36.7	37.0
	Accounts receivable		364.2	379.3
	Accrued revenues		161.0	257.8
	Materials, supplies and inventories		333.7	417.2
	Prepayments and Other		166.2	136.7

		Total Current Assets	1,061.8	1,228.0

Deferred Charges and Other Assets
	Regulatory assets		1,106.2	1,091.0
	Goodwill		441.9	441.9
	Other		159.2	152.0

		Total Deferred Charges and Other Assets	1,707.3	1,684.9

Total Assets			$ 11,462.4	$ 11,130.2




Capitalization and Liabilities

Capitalization
	Common equity		$ 2,978.6	$ 2,889.0
	Preferred stock of subsidiary		30.4	30.4
	Long-term debt		3,544.1	3,073.4

		Total Capitalization	6,553.1	5,992.8

Current Liabilities
	Long-term debt due currently		313.4	296.7
	Short-term debt		643.7	911.9
	Accounts payable		317.1	404.5
	Accrued liabilities		129.8	161.2
	Other		119.0	113.7

		Total Current Liabilities	1,523.0	1,888.0

Deferred Credits and Other Liabilities
	Regulatory liabilities		1,504.4	1,472.1
	Asset retirement obligations		380.8	371.7
	Deferred income taxes - long-term		555.8	572.9
	Deferred revenue, net		256.7	186.2
	Other		688.6	646.5

		Total Deferred Credits and Other Liabilities	3,386.3	3,249.4

Total Capitalization and Liabilities			$ 11,462.4	$ 11,130.2





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)

				Six Months Ended June 30

				2007	2006

				(Millions of Dollars)
Operating Activities
	Net income			$ 158.4	$ 168.6
	Reconciliation to cash
		Depreciation, decommissioning and amortization		170.2	166.0
		Nuclear fuel expense amortization		14.6	14.7
		Equity in earnings of transmission affiliate		(21.2)	(19.0)
		Distributions from transmission affiliate		15.8	14.9
		Deferred income taxes and investment tax credits, net		(23.6)	(25.5)
		Deferred revenue		71.9	30.9
		Change in -	Accounts receivable and accrued revenues	111.9	219.6
			Inventories	83.5	108.7
			Other current assets	2.4	(22.4)
			Accounts payable	(74.8)	(156.7)
			Accrued income taxes, net	(28.1)	82.6
			Deferred costs, net	(38.9)	(21.5)
			Other current liabilities and Other	13.5	19.7

Cash Provided by Operating Activities				455.6	580.6

Investing Activities
	Capital expenditures			(572.5)	(420.9)
	Proceeds from asset sales, net			16.0	41.5
	Nuclear fuel			(3.1)	(16.0)
	Nuclear decommissioning funding			(8.8)	(8.8)
	Proceeds from investments within nuclear decommissioning trust			213.4	301.7
	Purchases of investments within nuclear decommissioning trust			(213.4)	(301.7)
	Other			(28.4)	2.7

Cash (Used in) Investing Activities				(596.8)	(401.5)

Financing Activities
	Exercise of stock options			30.0	7.6
	Purchase of common stock			(54.7)	(13.1)
	Dividends paid on common stock			(58.5)	(53.8)
	Issuance of long-term debt			523.4	-
	Retirement of long-term debt			(30.6)	(277.3)
	Change in short-term debt			(268.2)	101.0
	Other, net			(0.5)	1.4

Cash Provided by (Used in) Financing Activities				140.9	(234.2)


Change in Cash and Cash Equivalents				(0.3)	(55.1)

Cash and Cash Equivalents at Beginning of Period				37.0	73.2


Cash and Cash Equivalents at End of Period				$ 36.7	$ 18.1




Supplemental Information - Cash Paid For
	Interest (net of amount capitalized)			$ 93.5	$ 94.9
	Income taxes (net of refunds)			$ 142.0	$ 46.3


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 2006 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 and six months ended June 30, 2007 are not necessarily indicative of the results which may be expected for the entire fiscal year 2007 because of seasonal and other factors.

Modifications to Prior Statements: We have modified certain income statement, balance sheet and cash flows presentations. Prior year financial statement amounts have been reclassified to conform to their current year presentation. These reporting changes had no impact on total earnings per share, total assets or cash provided, or used in operating, investing or financing activities.

2 -- NEW ACCOUNTING PRONOUNCEMENTS

Uncertainty in Income Taxes: In July 2006, the FASB issued FIN 48, an interpretation of SFAS 109. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in the enterprise's financial statements in accordance with SFAS 109. As of January 1, 2007, the adoption date for FIN 48, the amount of unrecognized tax benefits was approximately $41.7 million, which included estimated accrued interest and penalties of $5.4 million. The amount of unrecognized tax benefits excludes offsetting FIN 48 related deferred tax assets of $12.5 million. We recognize accrued interest and penalties in the provision for income taxes. The impact of adopting FIN 48 was not material. As of the date of adoption, the net amount of the unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was approximately $10.5 million. During the quarter we resolved approximately $2.9 million of liabilities with state tax jurisdictions of which $1.3 million related to discontinued operations. We do not anticipate any significant increases or decreases in the total amounts of unrecognized tax benefits within the next 12 months. Our primary tax jurisdictions include federal and the State of Wisconsin. Currently, the tax years of 2004 through 2006 are subject to federal examination and the tax years of 2002 through 2006 are subject to examination by the State of Wisconsin.

Fair Value Measurements: In September 2006, the FASB issued SFAS 157. SFAS 157 provides guidance for using fair value to measure assets and liabilities and also defines fair value, provides a framework for measuring fair value and expands disclosures related to fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We are currently evaluating the provisions of SFAS 157, and we expect to adopt it on January 1, 2008.

Fair Value Option: In February 2007, the FASB issued SFAS 159. SFAS 159 permits an entity to measure certain financial assets and financial liabilities at fair value and also establishes presentation and disclosure requirements. SFAS 159 is effective as of the beginning of an entity's first fiscal year beginning after November 15, 2007. We are currently evaluating the provisions of SFAS 159, and we expect to adopt it on January 1, 2008.

3 -- ACCOUNTING AND REPORTING FOR POWER THE FUTURE GENERATING UNITS

Background: As part of our PTF strategy, our non-utility subsidiary, We Power, is building four new generating units (PWGS 1 and 2 and OC 1 and 2) that will be leased to our utility subsidiary, Wisconsin Electric; under long-term leases that have been approved by the PSCW, our primary regulator. The leases are designed to recover the capital costs of the plant including a return. PWGS 1 was placed in service in July 2005 and is being leased to Wisconsin Electric. Wisconsin Electric will be responsible for all of the operating costs, including fuel, of the PTF units once they are placed in service and we anticipate that we will recover the operating costs of these plants in rates. 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.

During Construction: Under the terms of the lease, we collect in current rates amounts representing our pre-tax cost of capital (debt and equity) associated with capital expenditures for the 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 they will be amortized to revenue when the related assets are placed into service. During the construction of the PTF units, we capitalize interest costs at an overall weighted-average pre-tax cost of interest of approximately 6%. Capitalized interest is included in the total cost of the PTF units.

Cash Flows: The following table identifies key pre-tax cash outflows and inflows for the six months ended June 30, 2007 and 2006 related to the construction of our PTF units as compared to Wisconsin Energy overall.

	Capital Expenditures (Millions of Dollars)				Total

	PWGS 1	PWGS 2	OC 1	OC 2	PTF	WEC

2007	$ -	$48.2	$231.1	$71.1	$350.4	$572.5
2006	$ -	$69.5	$106.4	$31.2	$207.1	$420.9

	Capitalized Interest (Millions of Dollars)				Total

	PWGS 1	PWGS 2	OC 1	OC 2	PTF	WEC

2007	$ -	$6.9	$18.2	$5.7	$30.8	$31.6
2006	$ -	$3.1	$7.5	$2.7	$13.3	$16.1

	Deferred Revenue, net (Millions of Dollars)				Total

	PWGS 1	PWGS 2	OC 1	OC 2	PTF	WEC

2007	$ -	$15.7	$42.5	$13.7	$71.9	$71.9
2006	$ -	$7.1	$17.4	$6.4	$30.9	$30.9

Balance Sheet: As noted above, we collect in current rates carrying costs that are calculated based on the cash expenditures included in CWIP multiplied by our pre-tax cost of capital (approximately 14%). The carrying costs are recorded as deferred revenue. Our total CWIP balance includes cash expenditures, capitalized interest and accruals. The following table identifies key amounts related to our PTF units that are recorded on our balance sheet as of June 30, 2007 and December 31, 2006:

	CWIP - Cash Expenditures (Millions of Dollars)				Total

	PWGS 1	PWGS 2	OC 1	OC 2	PTF

June 30, 2007	$ -	$237.1	$710.0	$227.7	$1,174.8
December 31, 2006	$ -	$196.2	$487.7	$152.6	$836.5

	Total CWIP (Millions of Dollars)				Total

	PWGS 1	PWGS 2	OC 1	OC 2	PTF	WEC

June 30, 2007	$ -	$255.6	$757.8	$244.3	$1,257.7	$1,360.0
December 31, 2006	$ -	$207.7	$517.3	$163.5	$888.5	$992.4

	Net Plant in Service (Millions of Dollars)				Total

	PWGS 1	PWGS 2	OC 1	OC 2	PTF	WEC

June 30, 2007	$346.9	$ -	$ -	$ -	$346.9	$5,922.4
December 31, 2006	$350.1	$ -	$ -	$ -	$350.1	$5,841.7

	Deferred Revenue (Millions of Dollars)				Total

	PWGS 1	PWGS 2	OC 1	OC 2	PTF	WEC

June 30, 2007	$67.0	$43.2	$108.4	$38.1	$256.7	$256.7
December 31, 2006	$68.3	$27.5	$66.0	$24.4	$186.2	$186.2

Income Statement: 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. The authorized cash costs are established by the PSCW. The authorized cash costs exclude capitalized interest because 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 establish 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 related to the lease payments that are included in our rates. In addition, our revenues will include the amortization of the deferred revenues that reflect the carrying costs that are collected during construction. The deferred revenue will be amortized on a straight line basis over the lease term. We will depreciate the units on a straight line basis over their expected service life.

In July 2005, PWGS 1 was placed in service. This asset had a cost of approximately $364.3 million which included approximately $31.1 million of capitalized interest. The asset is being depreciated over its estimated useful life of approximately 37 years. The cost of the plant, plus a return, is expected to be recovered through Wisconsin Electric's rates over a 25 year period at an annual amount of approximately $48 million.

4 -- PROPOSED SALE OF POINT BEACH

In December 2006, we announced that we had signed a definitive agreement with an affiliate of FPL to sell Point Beach for approximately $998 million, subject to closing price adjustments. We also entered into a long-term power purchase agreement to purchase all of the existing capacity and energy of the plant. This long-term power purchase agreement will become effective upon the closing of the sale. The sale of the plant and the long-term power purchase agreement are subject to review and approval by various regulatory agencies, including the NRC, PSCW, MPSC and FERC. As of June 30, 2007, we have received approval from FERC. We anticipate closing the sale during the third quarter of 2007.

Under the terms of the asset sale agreement, the buyer is to assume the obligation to decommission the plant, and we will transfer certain decommissioning funds to the buyer. The total amount of funds that are to be transferred to the buyer are subject to approval by the PSCW.

We expect that the gain from the proposed sale and any decommissioning funds retained by the Company, less transaction related costs, will be credited to our customers as determined by the various regulatory authorities in rate proceedings.

5 -- 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 2006 Annual Report on Form 10-K. Effective January 1, 2006, we adopted SFAS 123R using the modified prospective method. We utilize the straight-line attribution method for recognizing share-based compensation expense under SFAS 123R. 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 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.

	Three Months Ended June 30		Six Months Ended June 30

	2007	2006	2007	2006

	(Millions of Dollars)

Stock options	$2.5	$1.9	$7.2	$3.8
Performance units	1.3	1.1	1.4	2.7
Restricted stock	0.2	0.3	0.5	0.6

Share-based compensation expense	$4.0	$3.3	$9.1	$7.1




Related Tax Benefit	$1.7	$1.3	$3.7	$2.8

Stock Option Activity: During the first six months of 2007, the Compensation Committee granted 1,371,590 options that had an estimated fair value of $8.72 per share. During the first six months of 2006, the Compensation Committee granted 1,292,275 options that had an estimated fair value of $7.55 per share. The following assumptions were used to value the options using a binomial option pricing model:

	2007	2006


Risk free interest rate	4.7% - 5.1%	4.3% - 4.4%
Dividend yield	2.2%	2.4%
Expected volatility	13.0% - 20.0%	17.0% - 20.0%
Expected forfeiture rate	2.0%	2.0%
Expected life (years)	6.0	6.3

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 through the three and six months ended June 30, 2007.

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

Outstanding as of April 1, 2007	8,287,815	$33.69
Granted	-
Exercised	(342,383)	$27.12
Forfeited	-

Outstanding as of June 30, 2007	7,945,432	$33.98





Outstanding as of January 1, 2007	7,721,826	$30.52
Granted	1,371,590	$47.76
Exercised	(1,137,020)	$27.10
Forfeited	(10,964)	$35.66

Outstanding as of June 30, 2007	7,945,432	$33.98	6.8	$81.5




Exercisable as of June 30, 2007	4,471,152	$28.82	5.5	$68.9

The intrinsic value of options exercised was $7.5 million and $24.2 million for the three and six months ended June 30, 2007, and $1.1 million and $5.6 million for the same periods in 2006, respectively. Cash received from options exercised was $30.0 million and $7.6 million for the six months ended June 30, 2007 and 2006, respectively. The related tax benefit for the same periods was approximately $8.9 million and $2.2 million, respectively.

The following table summarizes information about our non-vested options during the three and six months ended June 30, 2007:

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





Non-vested as of April 1, 2007	3,584,859	$8.21
Granted	-	-
Vested	(110,579)	$8.19
Forfeited	-	-

Non-vested as of June 30, 2007	3,474,280	$8.21




Non-vested as of January 1, 2007	2,587,849	$7.94
Granted	1,371,590	$8.72
Vested	(477,995)	$8.22
Forfeited	(7,164)	$8.18

Non-vested as of June 30, 2007	3,474,280	$8.21

As of June 30, 2007, total compensation costs related to non-vested stock options not yet recognized was approximately $13.1 million, which is expected to be recognized over the next 22 months on a weighted-average basis.

The following table summarizes information about stock options outstanding as of June 30, 2007:

	Options Outstanding			Options Exercisable

		Weighted - Average			Weighted - Average

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

$12.79 to $23.05	1,147,141	$21.49	3.9	1,147,141	$21.49	3.9
$25.31 to $31.07	1,567,082	$27.04	5.1	1,567,082	$27.04	5.1
$33.44 to $47.76	5,231,209	$38.80	8.0	1,756,929	$35.20	6.9

	7,945,432	$33.98	6.8	4,471,152	$28.82	5.5

Restricted Shares: The Compensation Committee has also approved restricted stock grants to certain key employees and directors. The following restricted stock activity occurred during the three and six months ended June 30 2007:

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





Outstanding as of April 1, 2007	158,954
Granted	-
Released / Forfeited	(3,951)	$25.31

Outstanding as of June 30, 2007	155,003




Outstanding as of January 1, 2007	184,665
Granted	14,139	$47.19
Released / Forfeited	(43,801)	$26.75

Outstanding as of June 30, 2007	155,003

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 $0.6 million and $2.5 million for the three and six months ended June 30, 2007, and $0.4 million for the same periods in 2006. The related tax benefit was $0.2 million and $0.9 million for the three and six months ended June 30, 2007 and $0.1 million for the same periods in 2006.

As of June 30, 2007, total compensation cost related to restricted stock not yet recognized was approximately $2.7 million, which is expected to be recognized over the next 50 months on a weighted-average basis.

Performance Units: In January 2007 and 2006, the Compensation Committee granted 136,905 and 150,821 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. We are accruing compensation costs over the three year period based on our estimate of the final expected value of the award. Performance units vesting were approximately $0.9 million, with a related tax benefit of $0.3 million, during the six months ended June 30, 2007. Performance shares earned as of December 31, 2006, vested and were distributed during the first quarter of 2007 and had a total intrinsic value of $7.2 million. The tax benefit realized due to the distribution of performance shares was approximately $2.1 million. As of June 30, 2007, total compensation cost related to performance units

not yet recognized was approximately $7.8 million, which is expected to be recognized over the next 24 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 our principal utility subsidiaries, Wisconsin Electric and Wisconsin Gas. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our principal utility 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 2006 Annual Report on Form 10-K for additional information on these restrictions.

We have the option to defer interest payments on the Junior Notes, from time to time, for one or more periods of up to 10 consecutive years per period. During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.

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. We recorded the following total comprehensive income during the six months ended June 30:

Comprehensive Income	2007	2006

	(Millions of Dollars)

Net Income	$158.4	$168.6
Other Comprehensive Income
Hedging	0.2	0.2

Total Other Comprehensive Income	0.2	0.2

Total Comprehensive Income	$158.6	$168.8

6 -- LONG-TERM DEBT

In May 2007, we issued $500 million of the Junior Notes due 2067. Due to certain features of the Junior Notes, rating agencies consider them to be hybrid instruments with a combination of debt and equity characteristics. The Junior Notes bear interest at 6.25% per year until May 15, 2017. Beginning May 15, 2017, the Junior Notes bear interest at the three-month London Interbank Offered Rate (LIBOR) plus 2.1125%, reset quarterly. The proceeds from this issuance were used to repay short-term debt incurred to fund PTF and for other working capital purposes.

In connection with the issuance of the Junior Notes, we executed the RCC for the benefit of persons that buy, hold or sell a specified series of long-term indebtedness (covered debt). Our 6.20% Senior Notes due April 1, 2033 have been initially designated as the covered debt under the RCC. The RCC provides that we may not redeem, defease or purchase and our subsidiaries may not purchase any Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, during the 180 days prior to the date of redemption, defeasance or purchase, we have received a specified amount of proceeds from the sale of qualifying securities.

7 -- DERIVATIVE INSTRUMENTS

We follow SFAS 133, as amended by SFAS 149, effective July 1, 2003, which requires that every derivative instrument be recorded on the balance sheet as an asset or liability measured at its fair value and that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives under SFAS 133, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. As of June 30, 2007 we recognized $16.5 million in regulatory assets and $2.1 million in regulatory liabilities related to derivatives.

8 -- BENEFITS

The components of our net periodic pension and OPEB costs for the three and six months ended June 30, 2007 and 2006 were as follows:

	Pension Benefits		OPEB

	2007	2006	2007	2006

	(Millions of Dollars)
Three Months Ended June 30
Net Periodic Benefit Cost
Service cost	$7.2	$7.9	$2.7	$2.8
Interest cost	18.0	17.5	4.9	4.4
Expected return on plan assets	(20.9)	(20.8)	(3.8)	(3.8)
Amortization of:
Transition obligation	-	-	0.1	0.2
Prior service cost (credit)	1.6	1.4	(3.3)	(3.4)
Actuarial loss	4.3	5.6	1.9	2.0

Net Periodic Benefit Cost	$10.2	$11.6	$2.5	$2.2

Six Months Ended June 30
Net Periodic Benefit Cost
Service cost	$15.1	$17.0	$5.8	$6.2
Interest cost	35.8	34.9	9.6	9.0
Expected return on plan assets	(42.2)	(41.0)	(7.6)	(7.5)
Amortization of:
Transition obligation	-	-	0.2	0.2
Prior service cost (credit)	2.9	2.7	(6.7)	(6.8)
Actuarial loss	9.0	11.7	3.7	4.4

Net Periodic Benefit Cost	$20.6	$25.3	$5.0	$5.5

9 -- GUARANTEES

We enter into various guarantees to provide financial and performance assurance to third parties on behalf of our affiliates. As of June 30, 2007, we had the following guarantees:

	Maximum Potential Future Payments	Outstanding as of June 30, 2007	Liability Recorded as of June 30, 2007

	(Millions of Dollars)
Wisconsin Energy
Non-Utility Energy	$ -	$ -	$ -
Other	2.5	2.5	-
Wisconsin Electric	234.1	0.2	-
Subsidiary	6.2	6.2	0.9

Total	$242.8	$8.9	$0.9

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 UI. 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.

Other guarantees 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 guarantees the potential retrospective premiums that could be assessed under Wisconsin Electric's nuclear insurance program (see Note I -- Nuclear Operations in our 2006 Annual Report on Form 10-K).

Subsidiary guarantees support loan obligations and surety bonds between our affiliates and third parties. In the event our affiliates fail to perform, our subsidiary would be responsible for the obligations.

Postemployment benefits: Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability, excluding severance benefits, for such benefits was $12.9 million as of June 30, 2007 and $13.0 million as of December 31, 2006.

10 -- SEGMENT INFORMATION

Summarized financial information concerning our reportable operating segments for the three and six month periods ended June 30, 2007 and 2006 is shown in the following table.

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

Wisconsin Energy Corporation	Utility	Non-Utility	Items	Consolidated

	(Millions of Dollars)
Three Months Ended

June 30, 2007
Operating Revenues (b)	$903.8	$21.1	($18.4)	$906.5
Operating Income (Loss)	$94.7	$11.1	($0.7)	$105.1
Interest Expense	$28.1	$1.9	$12.0	$42.0
Income Tax Expense (Benefit)	$37.5	$3.2	($5.0)	$35.7
Loss from Discontinued Operations, Net	$ -	$ -	($0.2)	($0.2)
Net Income (Loss)	$58.1	$6.0	($6.6)	$57.5
Capital Expenditures	$103.0	$179.3	$ -	$282.3

Three Months Ended

June 30, 2006
Operating Revenues (b)	$812.3	$20.2	($18.1)	$814.4
Operating Income (Loss)	$98.6	$11.5	($3.0)	$107.1
Interest Expense	$26.5	$3.6	$12.5	$42.6
Income Tax Expense (Benefit)	$35.6	$3.7	($6.8)	$32.5
Income from Discontinued Operations, Net	$ -	$ -	$3.2	$3.2
Net Income	$58.0	$4.6	$0.3	$62.9
Capital Expenditures	$97.7	$108.7	$ -	$206.4


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

Wisconsin Energy Corporation	Utility	Non-Utility	Items	Consolidated

	(Millions of Dollars)
Six Months Ended

June 30, 2007
Operating Revenues (b)	$2,204.4	$35.6	($32.4)	$2,207.6
Operating Income (Loss)	$272.2	$20.8	($3.4)	$289.6
Interest Expense	$57.2	$3.8	$23.7	$84.7
Income Tax Expense (Benefit)	$103.6	$6.5	($9.8)	$100.3
Loss from Discontinued Operations, Net	$ -	$ -	($0.4)	($0.4)
Net Income (Loss)	$161.3	$10.6	($13.5)	$158.4
Capital Expenditures	$217.3	$353.4	$1.8	$572.5
Total Assets	$10,119.1	$1,627.8	($284.5)	$11,462.4

Six Months Ended

June 30, 2006
Operating Revenues (b)	$2,059.5	$34.4	($32.5)	$2,061.4
Operating Income (Loss)	$284.1	$20.6	($6.0)	$298.7
Interest Expense	$54.6	$7.9	$25.3	$87.8
Income Tax Expense (Benefit)	$103.0	$5.8	($13.4)	$95.4
Income from Discontinued Operations, Net	$ -	$ -	$4.5	$4.5
Net Income (Loss)	$169.2	$7.2	($7.8)	$168.6
Capital Expenditures	$213.1	$207.8	$ -	$420.9
Total Assets	$9,415.2	$992.2	($7.0)	$10,400.4

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

(b)	An elimination for intersegment revenues is included in Operating Revenues of $19.5 million and $18.6 million for the three months ended June 30, 2007 and 2006, respectively, and in the amounts of $34.2 million and $33.1 million for the six months ended June 30, 2007 and 2006, respectively.

(c)	An elimination for the PWGS 1 lease between We Power and Wisconsin Electric is included in Total Assets of $310.9 million and $322.6 million at June 30, 2007 and 2006, respectively.

11 -- COMMITMENTS AND CONTINGENCIES

Environmental Matters: We periodically review our exposure for remediation costs as evidence becomes available indicating that our remediation liability has changed. Based on 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. 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. We have established reserves as deemed appropriate for these indemnification provisions.

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

RESULTS OF OPERATIONS -- THREE MONTHS ENDED JUNE 30, 2007
CONSOLIDATED EARNINGS

The following table compares our net income during the second quarter of 2007 with the second quarter of 2006 including favorable (better (B)) or unfavorable (worse (W)) variances.

	Three Months Ended June 30

	2007	B (W)	2006

	(Millions of Dollars)

Utility Energy Segment	$94.7	($3.9)	$98.6
Non-Utility Energy Segment	11.1	(0.4)	11.5
Corporate and Other	(0.7)	2.3	(3.0)

Total Operating Income	105.1	(2.0)	107.1
Equity in Earnings of Transmission Affiliate	10.5	1.1	9.4
Other Income, net	19.8	1.5	18.3
Interest Expense	42.0	0.6	42.6

Income From Continuing Operations Before Income Taxes	93.4	1.2	92.2
Income Taxes	35.7	(3.2)	32.5

Income From Continuing Operations	57.7	(2.0)	59.7
Income (Loss) From Discontinued Operations, Net of Tax	(0.2)	(3.4)	3.2

Net Income	$57.5	($5.4)	$62.9



Diluted Earnings Per Share
Continuing Operations	$0.49	($0.01)	$0.50
Discontinued Operations	$ -	($0.03)	$0.03

Total Diluted Earnings Per Share	$0.49	($0.04)	$0.53

UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Our utility energy segment contributed $94.7 million of operating income during the second quarter of 2007, a decrease of $3.9 million or 4.0% compared with the second quarter of 2006. The following table summarizes the operating income of this segment between the comparative quarters.

	Three Months Ended June 30

Utility Energy Segment	2007	B (W)	2006

	(Millions of Dollars)
Operating Revenues
Electric	$662.4	$60.5	$601.9
Gas	233.6	29.5	204.1
Other	7.8	1.5	6.3

Total Operating Revenues	903.8	91.5	812.3
Fuel and Purchased Power	233.3	(47.5)	185.8
Cost of Gas Sold	158.6	(29.0)	129.6

Gross Margin	511.9	15.0	496.9
Other Operating Expenses
Other Operation and Maintenance	313.9	(15.1)	298.8
Depreciation, Decommissioning
and Amortization	78.1	(2.4)	75.7
Property and Revenue Taxes	25.2	(1.4)	23.8

Operating Income	$94.7	($3.9)	$98.6

Electric Utility Revenues and Sales

The following table compares electric utility operating revenues and MWh sales by customer class during the second quarter of 2007 with the second quarter of 2006.

	Three Months Ended June 30

	Electric Revenues			MWh Sales

	2007	B (W)	2006	2007	B (W)	2006

	(Millions of Dollars)			(Thousands)
Customer Class
Residential	$214.4	$21.9	$192.4	1,960.8	114.9	1,845.9
Small Commercial/Industrial	213.2	19.5	193.7	2,292.1	76.7	2,215.4
Large Commercial/Industrial	182.2	20.3	161.9	2,853.8	25.4	2,828.4
Other Retail	4.6	0.3	4.3	39.9	1.2	38.7

Total Retail Sales	614.4	62.1	552.3	7,146.6	218.2	6,928.4
Other-Municipal	24.5	7.4	17.1	512.7	7.5	505.2
Resale-Utilities	11.8	(11.0)	22.8	191.9	(310.7)	502.6
Other Operating Revenues	11.7	2.0	9.7	-	-	-

Total	$662.4	$60.5	$601.9	7,851.2	(85.0)	7,936.2




Weather -- Degree Days (a)
Cooling (183 Normal)				181	38	143

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

Our electric utility operating revenues increased by $60.5 million, or approximately 10.1%, when compared to the second quarter of 2006. We estimate that $8.6 million of the increase was due to more favorable weather. Approximately $9.0 million of the increase relates to a settlement of a billing dispute with our largest customers, two iron ore mines. For further information on the mines arbitration, see Item 1-- Legal Proceedings -- Other Matters -- Arbitration Proceedings in Part II of this report. In addition, our revenues were approximately $30.1 million higher in the second quarter of 2007 as compared to the same period in 2006 due to revenues attributable to fuel and purchased power. Our policy for electric fuel revenues is to not recognize revenue for any currently billable amounts if it is probable that we will refund those amounts to customers. In 2006, we experienced lower than expected fuel and purchased power costs, and we established $30.1 million of reserves to reflect amounts that we expected to refund to customers. No such reserves have been established in 2007, as we are experiencing

higher fuel and purchased power costs. These increases were partially offset by a decrease of $11.0 million in opportunity sales as compared to the second quarter of 2006 due to lower plant availability.

Our total electric sales volumes decreased by approximately 1.1% in the second quarter of 2007; however, our retail sales volume increased by 3.1% as compared to the same period last year. The increase in retail sales was led by an increase in residential and commercial sales, which was driven by warmer weather in 2007 as compared to 2006. The increase in retail sales was offset by a 61.8% decline in wholesale sales (Resale - Utilities) due to lower plant availability as a result of planned outages.

Fuel and Purchased Power

Our fuel and purchased power costs increased by $47.5 million, or 25.6%, when compared to the second quarter of 2006. As noted above, our total electric sales volume decreased by approximately 1.1% in the quarter; however, our average fuel and purchased power cost per MWh increased by $6.31 or approximately 27.0%. In the second quarter of 2007, we had a 28.0% reduction in MWh output at our nuclear units due primarily to a scheduled refueling outage at Point Beach. In 2006, the scheduled refueling outage at Point Beach occurred in the fourth quarter. As a result of the reduced nuclear output, approximately 21.1% of our MWh sales in the second quarter of 2007 were supplied by higher cost natural gas-fired generation and purchased power as compared to 15.1% in the second quarter of 2006.

For further information, see Factors Affecting Results, Liquidity and Capital Resources - Utility Rates and Regulatory Matters below.

Gas Utility Revenues, Gross Margin and Therm Deliveries

A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the second quarter of 2007 with the second quarter of 2006. We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under gas cost recovery mechanisms. Between the comparative periods, total gas operating revenues increased by $29.5 million, or 14.5%, primarily because of higher natural gas prices.

	Three Months Ended June 30

	2007	B (W)	2006

	(Millions of Dollars)

Gas Operating Revenues	$233.6	$29.5	$204.1
Cost of Gas Sold	158.6	(29.0)	129.6

Gross Margin	$75.0	$0.5	$74.5

The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the second quarter of 2007 with the second quarter of 2006.

	Three Months Ended June 30

	Gross Margin			Therm Deliveries

	2007	B (W)	2006	2007	B (W)	2006

	(Millions of Dollars)			(Millions)
Customer Class
Residential	$46.5	$0.3	$46.2	105.3	0.9	104.4
Commercial/Industrial	14.3	-	14.3	63.4	1.5	61.9
Interruptible	0.5	0.1	0.4	5.1	1.1	4.0

Total Retail Gas Sales	61.3	0.4	60.9	173.8	3.5	170.3
Transported Gas	11.3	-	11.3	198.5	11.5	187.0
Other	2.4	0.1	2.3	-	-	-

Total	$75.0	$0.5	$74.5	372.3	15.0	357.3



Weather -- Degree Days (a)
Heating (945 Normal)				880	109	771

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

Our gas margins increased by $0.5 million, or approximately 0.7%, when compared to the second quarter of 2006. We estimate that a majority of this increase was related to increased sales primarily resulting from unseasonably cold weather in April 2007.

Other Operation and Maintenance Expenses

Our other operation and maintenance expenses increased by approximately $15.1 million, or 5.0%, when compared to the second quarter of 2006. This increase is primarily attributed to an increase in nuclear operation and maintenance expenses related to the timing of scheduled outages at Point Beach. In the second quarter of 2006, we did not have a scheduled nuclear refueling outage as was experienced in the second quarter of 2007.

CONSOLIDATED OTHER INCOME, NET

Other income, net increased by approximately $1.5 million, or 8.2%, when compared to the second quarter of 2006. The largest increase relates to a gain on sale of property. In May 2007, we sold land in Northern Wisconsin and the Upper Peninsula of Michigan for a pre-tax gain of approximately $7.0 million compared with a pre-tax gain on the sale of our investment in Guardian Pipeline LLC of $2.8 million during the same period in 2006. This increase was offset, in part, by a decrease in AFUDC of $2.5 million related to the new scrubber we put in service at our Pleasant Prairie Power Plant during the fourth quarter of 2006. This scrubber was installed as part of our EPA consent decree spending. For further information on the consent decree with the EPA, see Note S -- Commitments and Contingencies in our 2006 Annual Report on Form 10-K. Furthermore, our interest in the earnings of unconsolidated affiliates decreased approximately $2.2 million when compared to the quarter ended June 30, 2006.

CONSOLIDATED INTEREST EXPENSE

	Three Months Ended June 30

Interest Expense	2007	2006

	(Millions of Dollars)

Gross Interest Costs	$59.2	$51.3
Less: Capitalized Interest	17.2	8.7

Interest Expense	$42.0	$42.6

Our gross interest costs increased by $7.9 million, or 15.4%, when compared to the second quarter of 2006 due to increased debt levels as a result of our PTF construction program. However, in connection with the PTF construction program we capitalize interest during construction. Our capitalized interest increased by $8.5 million due to higher levels of construction in progress at our PTF plants. As a result, our net interest expense declined by $0.6 million, or 1.4%, as compared to the second quarter of 2006.

CONSOLIDATED INCOME TAXES

For the second quarter of 2007, our effective tax rate applicable to continuing operations was 38.2% compared to 35.2% for the second quarter of 2006. For additional information, see Note H -- Income Taxes in our 2006 Annual Report on Form 10-K. We expect our 2007 annual effective tax rate to be between 38.0% and 39.0%.

DISCONTINUED OPERATIONS

Income from discontinued operations, net of tax, decreased by $3.4 million in the second quarter of 2007 as compared to the same period in 2006. In the second quarter of 2006, we had income of approximately $2.2 million related to the favorable resolution of tax liabilities.

RESULTS OF OPERATIONS -- SIX MONTHS ENDED JUNE 30, 2007
CONSOLIDATED EARNINGS

The following table compares our net income during the first six months of 2007 with the first six months of 2006 including favorable (better (B)) or unfavorable (worse (W)) variances.

	Six Months Ended June 30

	2007	B (W)	2006

	(Millions of Dollars)

Utility Energy Segment	$272.2	($11.9)	$284.1
Non-Utility Energy Segment	20.8	0.2	20.6
Corporate and Other	(3.4)	2.6	(6.0)

Total Operating Income	289.6	(9.1)	298.7
Equity in Earnings of Transmission Affiliate	21.2	2.2	19.0
Other Income, Net	33.0	3.4	29.6
Interest Expense	84.7	3.1	87.8

Income From Continuing Operations Before Income Taxes	259.1	(0.4)	259.5
Income Taxes	100.3	(4.9)	95.4

Income From Continuing Operations	158.8	(5.3)	164.1
Income (Loss) From Discontinued Operations, Net of Tax	(0.4)	(4.9)	4.5

Net Income	$158.4	($10.2)	$168.6



Diluted Earnings Per Share
Continuing Operations	$1.34	($0.04)	$1.38
Discontinued Operations	$ -	($0.04)	$0.04

Total Diluted Earnings Per Share	$1.34	($0.08)	$1.42

UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Our utility energy segment contributed $272.2 million of operating income during the first six months of 2007, a decrease of $11.9 million, or 4.2%, compared with the first six months of 2006. The following table summarizes the operating income of this segment between the comparative periods.

	Six Months Ended June 30

Utility Energy Segment	2007	B (W)	2006

	(Millions of Dollars)
Operating Revenues
Electric	$1,305.0	$93.2	$1,211.8
Gas	878.4	46.4	832.0
Other	21.0	5.3	15.7

Total Operating Revenues	2,204.4	144.9	2,059.5
Fuel and Purchased Power	463.9	(107.8)	356.1
Cost of Gas Sold	632.4	(22.4)	610.0

Gross Margin	1,108.1	14.7	1,093.4
Other Operating Expenses
Other Operation and Maintenance	625.7	(20.4)	605.3
Depreciation, Decommissioning
and Amortization	159.2	(4.1)	155.1
Property and Revenue Taxes	51.0	(2.1)	48.9

Operating Income	$272.2	($11.9)	$284.1

Electric Utility Revenues and Sales

The following table compares electric utility operating revenues and MWh sales by customer class during the first six months of 2007 with the first six months of 2006.

	Six Months Ended June 30

	Electric Revenues			MWh Sales

	2007	B (W)	2006	2007	B (W)	2006

	(Millions of Dollars)			(Thousands)
Customer Class
Residential	$447.0	$38.7	$408.3	4,110.3	203.1	3,907.2
Small Commercial/Industrial	421.5	33.8	387.7	4,594.1	160.8	4,433.3
Large Commercial/Industrial	341.6	25.9	315.7	5,524.1	(46.6)	5,570.7
Other Retail	9.8	0.4	9.4	83.5	(0.4)	83.9

Total Retail Sales	$1,219.9	$98.8	$1,121.1	14,312.0	316.9	13,995.1
Other-Municipal	47.5	10.8	36.7	1,040.2	(0.8)	1,041.0
Resale-Utilities	17.2	(18.6)	35.8	314.9	(481.8)	796.7
Other Operating Revenues	20.4	2.2	18.2	-	-	-

Total	$1,305.0	$93.2	$1,211.8	15,667.1	(165.7)	15,832.8




Weather -- Degree Days (a)
Heating (4,177 Normal)				4,151	445	3,706
Cooling (183 Normal)				188	45	143

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

Our electric utility operating revenues increased by $93.2 million, or approximately 7.7%, when compared to the first six months of 2006. We estimate that $14.9 million of the increase relates to pricing increases that were received in late January 2006 that were in effect for the entire six month period ended June 30, 2007. In addition, we estimate that $22.4 million of the increase was due to more favorable weather. Approximately $9.0 million of the increase relates to a settlement of a billing dispute with our largest customers, two iron ore mines. For further information on the mines arbitration, see Item 1 -- Legal Proceedings -- Other Matters -- Arbitration Proceedings in Part II of this report. In addition, our revenues were approximately $34.1 million higher in the first six months of 2007 as compared to the same period in 2006 due to revenues attributable to fuel and purchased power. Our policy for electric fuel revenues is to not recognize revenue for any currently billable amounts if it is probable that we will refund those amounts to customers. In 2006, we experienced lower than expected fuel and purchased power costs, and we established $34.1 million of reserves to reflect amounts that we expected to refund to customers. No such reserves have been established in 2007 as we are experiencing higher fuel and purchased power costs. These increases were partially offset by a decrease of $18.6 million in opportunity sales as compared to the first six months of 2006 due to lower plant availability.

Our total electric sales volume decreased by approximately 1.0%; however, our retail sales volume increased by 2.3% as compared to the same period last year. The increase in retail sales was led by an increase in residential and commercial sales which was driven by favorable winter weather in 2007 as compared to 2006. The increase in retail sales was offset by a 60.5% decline in wholesale sales (Resale-Utilities) due to lower plant availability.

Fuel and Purchased Power

Our fuel and purchased power costs increased by $107.8 million, or 30.3%, when compared to the first six months of 2006. As noted above, our total electric sales volume decreased by approximately 1.0% in

the first six months of 2007; however, our average fuel and purchased power cost per MWh increased by $7.12 or approximately 31.6%. In the first six months of 2007, we had a 14.0% reduction in MWh output at our nuclear units due primarily to a planned refueling outage at Point Beach. Additionally, generation from our coal units was 13.0% lower in the first six months of 2007 due primarily to coal unit outages in the first quarter of 2007 as compared to 2006. In 2006, the scheduled refueling outage at Point Beach occurred in the fourth quarter. As a result of the reduced coal and nuclear output, approximately 24.5% of our MWh sales in the first six months of 2007 were supplied by higher cost natural gas-fired generation and purchased power as compared to 14.1% in the first six months of 2006.

For further information, see Factors Affecting Results, Liquidity and Capital Resources - Utility Rates and Regulatory Matters below.

Gas Utility Revenues, Gross Margin and Therm Deliveries

A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the first six months of 2007 with the first six months of 2006. We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under gas cost recovery mechanisms. Between the comparative periods, total gas operating revenues increased by $46.4 million, or 5.6%, primarily because of higher natural gas prices and the new rates that went into effect at the end of January 2006.

	Six Months Ended June 30

	2007	B (W)	2006

	(Millions of Dollars)

Gas Operating Revenues	$878.4	$46.4	$832.0
Cost of Gas Sold	632.4	(22.4)	610.0

Gross Margin	$246.0	$24.0	$222.0

The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the first six months of 2007 with the first six months of 2006.

	Six Months Ended June 30

	Gross Margin			Therm Deliveries

	2007	B (W)	2006	2007	B (W)	2006

	(Millions of Dollars)			(Millions)
Customer Class
Residential	$157.6	$16.1	$141.5	486.3	58.0	428.3
Commercial/Industrial	55.6	7.6	48.0	283.6	28.0	255.6
Interruptible	1.1	0.1	1.0	12.4	1.5	10.9

Total Retail Gas Sales	214.3	23.8	190.5	782.3	87.5	694.8
Transported Gas	26.8	0.2	26.6	482.2	52.8	429.4
Other	4.9	-	4.9	-	-	-

Total	$246.0	$24.0	$222.0	1,264.5	140.3	1,124.2



Weather -- Degree Days (a)
Heating (4,177 Normal)				4,151	445	3,706

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

Our gas margins increased by $24.0 million, or 10.8%, when compared to the first six months of 2006. We estimate that approximately $17.5 million of this increase related to increased sales as a result of more normal winter weather. The first six months of 2007 were approximately 12.0% colder than the same period in 2006. As a result, our retail therm deliveries increased approximately 12.6% as compared

to the first six months of 2006. In addition, we estimate that our gas margins improved by approximately $6.6 million due to a rate order that went into effect in the latter part of January 2006 and was effective for the entire six month period ended June 30, 2007.

Other Operation and Maintenance Expenses

Our other operation and maintenance expenses increased by $20.4 million, or approximately 3.4%, when compared to the first six months of 2006. In January 2006, we received a rate order to cover increased expenses related to transmission costs, bad debt costs and PTF costs. We estimate that for the first six months of 2007, other operation and maintenance expenses (and revenues) were approximately $12.7 million higher than the same period last year as a result of the January 2006 rate order. In the first six months of 2007, we had a scheduled nuclear refueling outage. We did not have a similar outage in the first six months of 2006. This resulted in an increase of approximately $19.1 million in nuclear operation and maintenance expenses between the comparative periods. This increase is offset, in part, due to a $13.0 million reduction in benefit related costs and other factors.

CONSOLIDATED OTHER INCOME, NET

Other income, net increased by approximately $3.4 million, or 11.5%, when compared to the six months ended June 30, 2006. The largest increase relates to a gain on the sale of property. In May 2007, we sold land in Northern Wisconsin and the Upper Peninsula of Michigan for a pre-tax gain of approximately $7.0 million. This increase is offset by a decrease in AFUDC of $4.8 million related to the new scrubber we put in service at our Pleasant Prairie Power Plant during the fourth quarter of 2006. This scrubber was installed as part of our EPA consent decree spending. For further information on the consent decree with the EPA, see Note S -- Commitments and Contingencies in our 2006 Annual Report on Form 10-K.

CONSOLIDATED INTEREST EXPENSE

	Six Months Ended June 30

Interest Expense	2007	2006

	(Millions of Dollars)

Gross Interest Costs	$116.3	$103.9
Less: Capitalized Interest	31.6	16.1

Interest Expense	$84.7	$87.8

Our gross interest costs increased by $12.4 million, or 11.9%, in the six months ended June 30, 2007 when compared with the same period in 2006. This increase reflects higher debt levels as a result of our PTF construction program. However, in connection with the PTF construction program we capitalize interest during construction. Our capitalized interest increased by $15.5 million due to higher levels of construction in progress at our PTF plants. As a result, our net interest expense declined by $3.1 million, or 3.5%, as compared to the first six months of 2006.

CONSOLIDATED INCOME TAXES

For the first six months of 2007, our effective tax rate applicable to continuing operations was 38.7% compared to 36.8% for the first six months of 2006. We expect our 2007 annual effective tax rate to be between 38.0% and 39.0%. For additional information, see Note H -- Income Taxes in our 2006 Annual Report on Form 10-K.

DISCONTINUED OPERATIONS

Income from discontinued operations, net of tax decreased by $4.9 million in the six months ended June 30, 2007 as compared to the same period in 2006. In the six months ended June 30, 2006, we had income of approximately $2.2 million related to the favorable resolution of tax liabilities.

LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS

The following summarizes our cash flows from continuing operations during the first six months of 2007 and 2006:

	Six Months Ended June 30

Wisconsin Energy Corporation	2007	2006

	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$455.6	$580.6
Investing Activities	($596.8)	($401.5)
Financing Activities	$140.9	($234.2)

Operating Activities

Cash provided by operating activities was $455.6 million during the six months ended June 30, 2007 or $125.0 million lower than the comparable period in 2006. This decline is due primarily to higher tax payments and changes in working capital requirements. Tax payments increased as a result of higher taxable income and due to the prepaid balance of income taxes as of December 31, 2005, which reduced tax payments in 2006. In the six months ended June 30, 2007, we had unfavorable recoveries of fuel and purchased power costs of $37.1 million. In the same period in 2006, we had favorable recoveries of fuel and purchased power costs of $54.0 million, including deferred fuel costs. In addition, we experienced lower cash proceeds from the use of gas in storage as we have reduced the working capital balances as of December 2006 as compared to December 2005.

Investing Activities

Cash used in investing activities was $596.8 million during the six months ended June 30, 2007, or $195.3 million higher than the comparable period in 2006. This increase was anticipated and was primarily due to the increased levels of construction at the PTF plants.

Financing Activities

Cash provided by financing activities was $140.9 million during the six months ended June 30, 2007, or $375.1 million greater than the comparable period in 2006. During 2007, we received $523.4 million of cash proceeds from the issuance of debt, including the $500 million principal amount of Junior Notes offered in May 2007. We used the net proceeds of the Junior Notes to pay down short-term debt incurred to fund PTF and for other working capital purposes.

In the first six months of 2007, we received proceeds of $30.0 million related to the exercise of stock options, compared with $7.6 million in the first six months of 2006. 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 $54.7 million, compared with $13.1 million in the first six months of 2006. 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 six months of 2007 primarily through internally generated funds and short-term borrowings, supplemented by the issuance of intermediate or long-term debt securities depending on market conditions and other factors. Beyond 2007, we anticipate meeting our capital requirements through internally generated funds supplemented, when required, by short-term borrowings and the issuance of debt securities.

We 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 believe that we have adequate capacity to fund our operations for the foreseeable future through our existing borrowing arrangements, our access to capital markets and internally generated cash.

In May 2007, Wisconsin Energy filed a shelf registration statement with the SEC for an unspecified amount of debt securities, which became effective upon filing. We issued the Junior Notes pursuant to this registration statement in May 2007.

Wisconsin Energy, Wisconsin Electric and Wisconsin Gas credit agreements provide liquidity support for each company's obligations with respect to commercial paper and for general corporate purposes.

As of June 30, 2007, we had approximately $1.7 billion of available unused lines of bank back-up credit facilities on a consolidated basis and approximately $643.7 million of total consolidated short-term debt outstanding.

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 June 30, 2007:

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

	(Millions of Dollars)

Wisconsin Energy	$900.0	$1.5	$898.5	April 2011	5 year
Wisconsin Electric	$500.0	$4.1	$495.9	March 2011	5 year
Wisconsin Gas	$300.0	$ -	$300.0	March 2011	5 year

The following table shows our actual capitalization structure as of June 30, 2007, as well as an adjusted capitalization structure that is consistent with the manner in which the rating agencies currently view the Junior Notes:

Capitalization Structure	Actual		Adjusted

	(Millions of Dollars)

Common Equity	$2,978.6	39.6%	$3,228.6	43.0%
Preferred Stock of Subsidiary	30.4	0.4%	30.4	0.4%
Long-Term Debt (including
current maturities)	3,857.5	51.4%	3,607.5	48.0%
Short-Term Debt	643.7	8.6%	643.7	8.6%

Total Capitalization	$7,510.2	100.0%	$7,510.2	100.0%




Total Debt	$4,501.2		$4,251.2

Ratio of Debt to Total Capitalization		59.9%		56.6%

Included in Long-Term Debt for the quarter ended June 30, 2007, is the $500 million aggregate principal amount of the Junior Notes as these debt securities are reflected as long-term debt on our Consolidated Condensed Balance Sheets. 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 rating agencies' treatment of the Junior Notes, where they attribute 50% equity credit 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 both the GAAP calculation and the rating agency non-GAAP adjusted calculation. Therefore, we believe the non-GAAP adjusted presentation is useful and relevant to investors in understanding how management and the rating agencies evaluate our capitalization structure.

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 June 30, 2007.

	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
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-

For additional information on these security ratings and the ratings outlooks assigned to Wisconsin Energy and its subsidiaries, see Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Requirements -- Capital Resources in our 2006 Annual Report on Form 10-K.

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 2007 are expected to be principally for capital expenditures and long-term debt maturities. Our 2007 annual consolidated capital expenditure budget, excluding the purchase of nuclear fuel, is approximately $1,371.0 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 9 -- Guarantees in the Notes to Consolidated Condensed Financial Statements in this report.

We have identified three tolling and purchased power agreements with third parties but have been unable to determine if we are the primary beneficiary of any of these three variable interest entities as defined by FIN 46. As a result, we do not consolidate these entities. Instead, we account for one of these contracts as a capital lease and for the other two contracts as operating leases. For additional information, see Note G -- Variable Interest Entities in our 2006 Annual Report on Form 10-K. We have included our contractual obligations under all three of these contracts in our evaluation of Contractual Obligations/Commercial Commitments discussed below.

Contractual Obligations/Commercial Commitments: Our total contractual obligations and other commercial commitments increased to approximately $10.6 billion as of June 30, 2007 compared with $10.2 billion as of December 31, 2006. This increase was due primarily to the issuance in May 2007 of the Junior Notes and agreements entered into in connection with our wind generation project. This increase was offset in part by periodic payments related to these types of obligations made in the ordinary course of business during the six months ended June 30, 2007. For purposes of determining our contractual obligations and commercial commitments only, we assumed the Junior Notes would be retired in 2017 with the proceeds from the issuance of qualifying securities pursuant to the terms of the RCC.

FACTORS AFFECTING RESULTS, LIQUDITY 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 2006 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, nuclear operations, 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 will lease 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 Note E -- Accounting and Reporting for Power the Future Generating Units in the Notes to Consolidated Financial Statements and Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Item 7 of our 2006 Annual Report on Form 10-K and Note 3 -- Accounting and Reporting for Power the Future Generating Units in the Notes to Consolidated Condensed Financial Statements in this report for additional information on PTF.

Port Washington: Construction of PWGS 2 is well underway. Site preparation, including removal of the old coal units at the site, was completed in early 2006, and all of the major components have been procured. The unit is expected to begin commercial operation during the second quarter of 2008.

Oak Creek Expansion: The CPCN granted for the construction of the Oak Creek expansion was the subject of a number of legal challenges by third parties; these legal challenges were resolved in June 2005. We have received all permits necessary to commence construction, which began in June 2005. Certain of these permits continue to be contested but remain in effect unless and until overturned by a reviewing court or administrative law judge.

A contested case hearing for the WPDES permit was held in March 2006. The ALJ upheld the issuance of the permit in a decision issued in July 2006. In August 2006, the opponents filed in Dane County Circuit Court for judicial review of the ALJ's decision upholding the issuance of the permit. In March 2007, the Dane County Circuit Court affirmed in part the decision by the ALJ to uphold the WDNR's issuance of the permit. The Court also remanded certain aspects of the ALJ's decision for further consideration based on the January 2007 decision by the Federal Court of Appeals for the Second Circuit concerning the federal rule on cooling water intake systems for existing facilities (the Phase II rule) (Riverkeeper, Inc. v. EPA, Nos. 04-6692-ag(L) (2d Cir. 2007)). The Second Circuit found certain portions of the Phase II rule impermissible and remanded several parts of the Phase II rule to the EPA for further consideration or potential additional rulemaking. Consistent with its announcement in March, in July 2007, the EPA formally suspended the Phase II rule in its entirety and directed states to use their "best professional judgment" in evaluating intake systems.

In light of these actions, we have requested that the WDNR modify the WPDES permit. We have submitted additional information to the WDNR as part of that process. We anticipate that completion of the review and a decision on the modification of the permit may take the remainder of 2007. When a permit is modified through the modification procedure under state law, as under federal regulations, the existing permit continues in full force and effect during the modification process. A modified permit will be subject to public notice and comment and a request for a contested case proceeding.

In June 2007, the ALJ granted our motion to stay the administrative proceeding on the remanded permit pending WDNR's action on our request to modify the permit. In June 2007, the opponents filed a motion with the Dane County Circuit Court requesting an order directing the ALJ to re-decide the issues on remand without review by WDNR and directing us to cease construction on the intake system. Briefs on the issues were submitted in July 2007, and a hearing is scheduled for August 2007.

UTILITY RATES AND REGULATORY MATTERS
2008 Rate Case

In May, 2007, Wisconsin Electric and Wisconsin Gas initiated rate proceedings with the PSCW. Wisconsin Electric has asked the PSCW to approve a comprehensive plan which would result in net price increases of 7.5% in 2008 and 7.5% in 2009 for its electric customers in Wisconsin, a 1.8% price increase in 2008 for its gas customers and approximately 16.0% price increases in 2008 for all steam customers in Milwaukee. Wisconsin Gas has filed for a 4.1% price increase in 2008 for its gas customers.

Electric pricing increases are largely needed to allow us to continue progress on previously approved initiatives, including: costs associated with generation capacities, primarily the new PTF plants approved by the PSCW in 2002 and 2003; recovery of costs associated with transmission; compliance with environmental regulations; continuation of investment in renewable and efficiency programs, including the new wind facilities approved by the PSCW in February 2007; and scheduled recovery of regulatory assets.

The proposed net price increase for electric customers in Wisconsin reflects credits expected from the pending sale of Point Beach. If the sale is approved and closed, there will be an estimated $653 million of proceeds available to offset the required price increases in Wisconsin. Our proposed plan, if approved, would apply $107 million to recover existing regulatory assets in 2008. Our plan would provide monthly bill credits of approximately $372 million in 2008 and $188 million, including interest, in 2009, and any remaining proceeds in our next scheduled rate filing. The proposed credits have a significant impact on net price increases for electric customers. For example, a $50 million increase or decrease in the pricing credits provided in 2008, while leaving the other components of our proposal unchanged, would result in a corresponding decrease or increase of approximately 2.5% in the net price change to electric customers in 2008.

If the Point Beach sale is not approved or otherwise is not completed, the credits would not be available. The new prices, which will be subject to a full review by the PSCW, are expected to be implemented in January 2008.

2006 Rate Order

Electric Rates: In January 2006, Wisconsin Electric received an order from the PSCW that allowed it to increase annual electric revenues by approximately $222.0 million, or 10.6%, to recover increased costs associated with investments in our PTF units, transmission services and fuel and purchased power, as well as costs associated with additional sources of renewable energy. The rate increase was based on an authorized return on equity of 11.2%. The order also required Wisconsin Electric to refund to customers, with interest, any fuel revenues that it received in excess of fuel and purchased power costs that it incurred, as defined by the Wisconsin fuel rules. The original order stipulated that any refund would also include interest at short-term rates. This refund provision expired December 31, 2006.

During 2006, we experienced lower than expected fuel and purchased power costs. In September 2006, we requested and received approval from the PSCW to refund favorable fuel recoveries including accrued interest at short-term rates. In addition, in September 2006 the PSCW determined that if the total recoveries for 2006 exceeded $36 million, interest on the amount in excess of $36 million would be paid at the rate of 11.2%, our authorized return on equity rather than at short-term rates as originally set forth in the order. During October 2006, we refunded $28.7 million, including interest, to Wisconsin retail customers as a credit on their bill, and an additional $10.3 million, including interest, in the first quarter of 2007.

For 2007, Wisconsin Electric returned to the traditional fuel cost adjustment clause in the Wisconsin retail jurisdiction whereby fuel revenues may be adjusted prospectively if fuel and purchased power costs fall outside a pre-established annual band of plus or minus 2%.

Gas Rates: Our gas operations went through a traditional rate proceeding whereby the revenues were set to recover projected costs and to provide a return on rate base. The January 2006 order provided for increases in gas revenues totaling $60.1 million annually ($21.4 million, or 2.9%, for Wisconsin Electric gas operations and $38.7 million, or 3.7%, for Wisconsin Gas gas operations). The rate increases were based on an authorized return on equity of 11.2% for the gas operations of both Wisconsin Electric and Wisconsin Gas.

Steam Rates: The steam rate proceeding was a traditional rate proceeding. The January 2006 order provided for an increase in steam rates of $7.8 million, or 31.5%, to be phased in over a two year period beginning in 2006. The rate increase was based on an authorized return on equity of 11.2%.

Limited Rate Adjustment Requests

2005 Fuel Recovery Filing: In February 2005, Wisconsin Electric filed an application with the PSCW for an increase in electric rates in the amount of $114.9 million due to the increased costs of fuel and purchased power as a result of customer growth and the increase in our reliance upon natural gas as a fuel source. We received approval for the increase in fuel recoveries on an interim basis in March 2005. In November 2005, we received the final rate order, which authorized an additional $7.7 million in rate increases, for a total increase of $122.6 million (6.2%). In December 2005, two parties filed suit against the PSCW in Dane County Circuit Court challenging the PSCW's decision to allow fuel cost recovery, while allowing us to keep the savings that resulted from the WICOR, Inc. acquisition. As a condition of the PSCW approval of the WICOR acquisition, Wisconsin Electric and Wisconsin Gas were restricted from increasing Wisconsin rates for a five year period ending December 31, 2005, with certain limited exceptions, but we were allowed to keep the savings generated from the merger. In July 2006, the Dane County Circuit Court affirmed the PSCW's decision. In August 2006, the opponents appealed this decision to the Wisconsin Court of Appeals. On July 18, 2007, the Court of Appeals affirmed the Dane County Circuit Court decision upholding the PSCW's order. The Petitioners have 30 days from the date of the Court of Appeals decision within which to file a Petition for Review with the Wisconsin Supreme Court.

Other Regulatory Matters

Coal Generation Forced Outage - 2007: In March 2007, we requested and received approval from the PSCW to defer as a regulatory asset approximately $13.2 million related to replacement power costs due to a forced outage of Unit 1 at the Pleasant Prairie Power Plant. The outage extended from February 2007 through March 2007.

Wholesale Electric Rates: In August 2006, Wisconsin Electric filed a wholesale rate case with FERC. The filing requested an annual increase in rates of approximately $16.7 million applicable to four existing wholesale electric customers. In November 2006, FERC accepted the rate filing subject to refund with interest. Three of the existing customers' rates were effective January 1, 2007. The remaining largest wholesale customer's rates were effective May 1, 2007. A settlement of the rate filing is pending before FERC.

Fuel Rules: In June 2006, the PSCW opened a docket (01-AC-224) in which it was looking into revising the current fuel rules (Chapter PSC 116). In February 2007, five Wisconsin utilities regulated by the fuel rules, including Wisconsin Electric, filed a joint proposal to modify the existing rules in this docket. The proposal recommends modifying the rules to allow for escrow accounting for fuel costs outside a plus or minus 1% annual band width of fuel costs allowed in rates. It further recommends that

the escrow balance be trued-up annually following the end of each calendar year. We are unable to predict if or when the PSCW will make any changes to the existing fuel rules.

See Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters in Item 7 of our 2006 Annual Report on Form 10-K for additional information regarding our utility rates and other regulatory matters.

WIND GENERATION

In June 2005, we purchased the development rights to two wind farm projects (Blue Sky Green Field) from Navitas Energy Inc. We plan to develop the wind sites and construct wind turbines with a combined generating capacity of approximately 145 MW. We filed for approval of a CPCN with the PSCW in March 2006. Hearings were held at the end of November 2006. In February 2007, the PSCW issued a written notice approving the CPCN.

In addition to the CPCN approval, we secured other required permits, including all requested FAA permits, and began construction in June 2007. We will continue working to secure any additional permits necessary. During March 2007, we entered into a final agreement with Vestas Wind Systems for the purchase of wind turbines. Equipment is expected to begin arriving at the site during the fourth quarter of 2007. We have also entered into service and warranty agreements with Vestas that will cover the first two years of operation. In May 2007, we entered into an agreement with Alliant Energy EPC, LLC to construct the wind farm. We estimate that the capital cost of the project, excluding AFUDC, will be approximately $300 million. We currently expect the turbines to be placed into service no later than the second quarter of 2008.

NUCLEAR OPERATIONS

Wisconsin Electric owns two 518 MW electric generating units at Point Beach in Two Rivers, Wisconsin. The plant is operated by NMC, a joint venture of the Company and affiliates of other unaffiliated utilities. Wisconsin Electric has entered into a definitive agreement with an affiliate of FPL to sell Point Beach for approximately $998 million, subject to closing price adjustments. See Note 4 -- Proposed Sale of Point Beach in the Notes to Consolidated Condensed Financial Statements in this report and Factors Affecting Results, Liquidity and Capital Resources -- Nuclear Operations in Item 7 of our 2006 Annual Report on Form 10-K for additional information regarding the sale of Point Beach.

Each Unit at Point Beach has a scheduled refueling outage approximately every 18 months. During 2007, we had one scheduled outage which began at the end of the first quarter and was successfully completed in May 2007. In 2006, we had one scheduled refueling outage that took place during the fourth quarter. See Factors Affecting Results, Liquidity and Capital Resources -- Nuclear Operations in Item 7 of our 2006 Annual Report on Form 10-K for additional information regarding our nuclear operations.

ELECTRIC TRANSMISSION

MISO: In connection with its status as a FERC approved RTO, MISO implemented a bid-based energy market, the MISO Midwest Market, which commenced operations on April 1, 2005. In April 2006, FERC issued an order determining that MISO had not applied its energy markets tariff correctly in the assessment of Revenue Sufficiency Guarantee charges. FERC ordered MISO to resettle all affected transactions retroactive to April 1, 2005. In October 2006 and March 2007, we received additional rulings from FERC on these issues. FERC's rulings have been challenged by MISO, Wisconsin Electric

and numerous other market participants. MISO commenced with the retroactive resettlement of the market associated with the currently effective orders in July 2007, with completion anticipated in January 2008. Due to the complexity of the order and pending challenges, we are evaluating the overall financial implication to us.

As part of this energy market, MISO developed a market-based platform for valuing transmission congestion and losses premised upon the LMP system that has been implemented in certain northeastern and mid-Atlantic states. The LMP system includes the ability to mitigate or eliminate congestion costs through the use of FTRs. FTRs are allocated to market participants by MISO. A new allocation of FTRs was completed in April 2007 for the period June 1, 2007 through May 31, 2008. We were granted substantially all of the FTRs that we were permitted to request during the allocation process.

MISO is in the process of developing a market for two ancillary services, regulation reserves and contingency reserves. In February 2007, MISO filed tariff revisions to include ancillary services. The MISO ancillary services market is proposed to begin in 2008. We currently self-provide both regulation reserves and contingency reserves. In the MISO ancillary services market, we expect that we will buy/sell regulation and contingency reserves from/to the market. The MISO ancillary services market is expected to reduce overall ancillary services costs in the MISO footprint. We anticipate achieving a net reduction in fuel costs but are unable to determine the amount of savings we will realize at this time. The MISO ancillary services market is also expected to enable MISO to assume significant balancing area responsibilities such as frequency control and disturbance control.

See Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition -- Electric Transmission and Energy Markets in Item 7 of our 2006 Annual Report on Form 10-K for additional information regarding MISO.

ENVIRONMENTAL MATTERS

Clean Water Act: Section 316(b) of the CWA requires that the location, design, construction and capacity of cooling water intake structures reflect the BTA for minimizing adverse environmental impact. This law dates back to 1972; however, prior to September 2004, there were no federal rules that defined precisely how states and EPA regions determined that an existing intake met BTA requirements. The Phase II rule established, for the first time, national performance standards and compliance alternatives for existing facilities that are designed to minimize the potential adverse environmental impacts to aquatic organisms associated with water withdrawals from cooling water intakes. Costs associated with implementation of the Phase II rule for Wisconsin Electric's Oak Creek Power Plant, We Power's Oak Creek expansion and PWGS were included in project costs.

In January 2007, the Federal Court of Appeals for the Second Circuit issued a decision concerning the Phase II rule for existing facilities (Riverkeeper, Inc. v. EPA, Nos. 04-6692-ag(L) (2d Cir. 2007)). The Second Circuit found certain portions of the rule impermissible and remanded several parts of the Phase II rule to the EPA for further consideration or potential additional rulemaking. Consistent with its announcement in March, in July 2007, the EPA formally suspended the Phase II rule in its entirety and directed states to use their "best professional judgment" in evaluating intake systems. We will work with the relevant state agencies as permits for our facilities come due for renewal to determine what, if any, actions need to be taken. Until the EPA completes its reconsideration and rulemaking, we cannot predict what impact these changes to the federal rules may have on our facilities. For additional information on this matter related to the Oak Creek expansion, see Factors Affecting Results, Liquidity and Capital Resources -- Power the Future -- Oak Creek Expansion in this report.

Greenhouse Gases: There have been international efforts seeking legally binding reductions in emissions of greenhouse gases, principally CO₂, including the United Nations Framework Convention on

Climate Change held in Kyoto, Japan. While the current administration has not supported U.S. ratification of the Kyoto Protocol or other legislation requiring reductions in CO₂, in 2002, it announced a goal of reducing the greenhouse gas intensity of the U.S. economy by 18% by 2012. In addition, in December 2004, the United States Department of Energy announced the Climate VISION program in furtherance of reduced greenhouse gas emissions. We continue to take voluntary measures to reduce our emissions of greenhouse gases. We also continue to analyze the state and federal legislative proposals for greenhouse gas regulation, including mandatory restrictions on CO₂; however, we are unable at this time to definitively determine the impact of such future regulations on our operations or rates.

We continue to support flexible, market-based strategies to curb greenhouse gas emissions. These strategies include emissions trading, joint implementation projects and credit for early actions. We also support a voluntary approach that encourages technology development and transfer and includes all sectors of the economy and all significant global emitters.

Our emissions in future years will continue to be influenced by several actions completed, planned or underway as part of the PTF strategy, including:

Repowering the Port Washington Power Plant from coal to natural gas combined cycle units.
Adding coal-fired units as part of the Oak Creek expansion that will be the most efficient coal units in our system.
Increasing investment in energy efficiency and conservation.
Maintaining and increasing non-emitting generation by adding 145 MW of wind capacity and increasing customer participation in the Energy for Tomorrow^® renewable energy program.
Successful renewal of the Point Beach units' operating licenses.

National Ambient Air Quality Standards: In 2000 and 2001, Michigan and Wisconsin finalized state rules implementing phased emission reductions required to meet the NAAQS for 1-hour ozone. In 2004, the EPA began implementing NAAQS for 8-hour ozone and PM_2.5. In December 2006, the EPA further revised the PM_2.5 standard, and in June 2007, the EPA announced its proposal to further lower the 8-hour ozone standard.

8-hour Ozone Standard: In April 2004, the EPA designated 10 counties in Southeastern Wisconsin as non-attainment areas for the 8-hour ozone NAAQS. States were required to develop and submit SIPs to the EPA by June 2007 to demonstrate how they intend to comply with the 8-hour ozone NAAQS. The rule that applies to emissions from our power plants in the affected areas of Wisconsin has been adopted by the state. The required reductions will be accomplished through implementation of the CAIR. (See below for further information regarding CAIR.) We believe compliance with the NO_x emission reduction requirements under the agreements with the WDNR and EPA will substantially mitigate costs to comply with the EPA's 8-hour ozone NAAQS. In June 2007, the EPA announced its proposal to further lower the 8-hour standard. The proposal is undergoing public comment. Until this proposal becomes a final rule, we are unable to predict the impact on the operation of our existing coal-fired generation facilities.

PM_2.5 Standard: In December 2004, the EPA designated PM _2.5 non-attainment areas in the country. All counties in Wisconsin and all counties in the Upper Peninsula of Michigan were designated as in attainment with the standard. It is unknown at this time whether Wisconsin or Michigan will require additional emission reductions as part of state or regional implementation of the PM_2.5standard and what impact those requirements would have on operation of our existing coal-fired generation facilities. In December 2006, a more restrictive federal standard became effective, which may place some counties into non-attainment status. This standard is currently being litigated. Until such time as the states develop rules and submit SIPs to EPA to demonstrate how they intend to comply with the standard, we are unable to predict the impact of

this more restrictive standard on the operation of our existing coal-fired generation facilities or our new PTF generating units being leased by Wisconsin Electric including OC 1, OC 2 and PWGS.

Clean Air Interstate Rule: The EPA issued the final CAIR regulation in March 2005 to facilitate the states in meeting the 8-hour ozone and PM_2.5 standards by addressing the regional transport of SO₂ and NO_x. CAIR requires NO_x and SO₂ emission reductions in two phases from electric generating units located in a 28-state region within the eastern United States. Wisconsin and Michigan are affected states under CAIR. The phase 1 compliance deadline is January 1, 2009 for NO_x and January 1, 2010 for SO₂, and the phase 2 compliance deadline is January 1, 2015 for both NO_x and SO₂. Overall, the CAIR is expected to result in a 70% reduction in SO₂ emissions and a 65% reduction in NO_x emissions from 2002 emission levels. The states were required to develop and submit implementation plans by no later than March 2007. A final CAIR rule has been adopted in Wisconsin and Michigan. We believe that compliance with the NO_x and SO₂ emission reductions requirements under the agreements with the WDNR and EPA will substantially mitigate costs to comply with the CAIR rule.

See Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters in Item 7 of our 2006 Annual Report on Form 10-K for additional information regarding environmental matters affecting our operations.

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 2006 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 has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The following should be read in conjunction with Item 3. Legal Proceedings in Part I of our 2006 Annual Report on Form 10-K and Item 1. Legal Proceedings in Part II of our Quarterly Report on Form 10-Q for the period ended March 31, 2007.

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

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.

Power the Future: See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Part I of this report for information concerning our PTF strategy.

OTHER MATTERS

Stray Voltage: In recent years, several actions by dairy farmers have been commenced or claims made against Wisconsin Electric for loss of milk production and other damages to livestock allegedly caused by stray voltage resulting from the operation of its electrical system.

In May 2005, a stray voltage lawsuit was filed against Wisconsin Electric. This lawsuit was settled in June 2007. This claim against Wisconsin Electric did not have a material adverse effect on our financial condition or results of operations.

Even though any claims which may be made against Wisconsin Electric with respect to stray voltage and ground currents are not expected to have a material adverse effect on its financial condition, we continue to evaluate various options and strategies to mitigate this risk.

Arbitration Proceedings: In May 2007, Wisconsin Electric entered into a settlement agreement with its largest industrial customers, two iron ore mines in the Upper Peninsula of Michigan. The settlement is a full and complete resolution of all claims and disputes between the parties for electric service rendered by Wisconsin Electric under the current power purchase agreements through March 31, 2007. The MPSC approved the settlement in May 2007. The settlement provided for the mines to pay Wisconsin Electric approximately $9.0 million and Wisconsin Electric released to the mines all funds held in escrow. The estimated earnings impact of the payment from the mines is $0.04 per share. The settlement also provides a mutually satisfactory pricing structure through December 31, 2007, when the power purchase agreements with the mines expire. Beginning January 1, 2008, the mines will be eligible to receive electric service from Wisconsin Electric in accordance with tariffs approved by the MPSC.

ITEM 1A. RISK FACTORS

See Item 1A. Risk Factors in our 2006 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-month period ended June 30, 2007.

2007	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)

April 1- April 30	1,934	$49.82	-	$ -

May 1- May 31	-	$ -	-	$ -

June 1- June 30	-	$ -	-	$ -

Total	1,934	$49.82	-	$ -

(a)

This table does not include shares purchased by independent agents to satisfy obligations under our employee benefit plans and stock purchase and dividend reinvestment plan. All shares reported during the quarter were surrendered by employees to satisfy tax withholding obligations upon vesting of restricted stock.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

At Wisconsin Energy's 2007 Annual Meeting of Stockholders held on May 3, 2007, stockholders voted on the following items with the following results:

Item 1 -- Election of Ten Directors for Terms Expiring in 2008: The Board of Directors' nominees named below were elected as directors by the indicated votes and percentages cast for each nominee. Directors are elected by a plurality of the votes cast by the shares entitled to vote. Any shares not voted, whether by withheld authority, broker non-votes or otherwise, have no effect in the election of directors. There was no solicitation in opposition to the nominees proposed in our Proxy Statement.

Nominee	Shares For		Shares Withheld


John F. Ahearne	102,783,817	98.41%	1,655,814	1.59%
John F. Bergstrom	102,242,922	97.90%	2,196,709	2.10%
Barbara L. Bowles	103,295,446	98.90%	1,144,185	1.10%
Patricia Chadwick	103,556,037	99.15%	883,594	0.85%
Robert A. Cornog	102,844,505	98.47%	1,595,126	1.53%
Curt S. Culver	103,612,816	99.21%	826,815	0.79%
Thomas J. Fischer	101,169,802	96.87%	3,269,829	3.13%
Gale E. Klappa	102,775,439	98.41%	1,664,192	1.59%
Ulice Payne, Jr.	103,352,726	98.96%	1,086,905	1.04%
Frederick P. Stratton, Jr.	102,986,855	98.61%	1,452,776	1.39%

Item 2 -- Ratification of Deloitte & Touche LLP as independent auditors for 2007: The Audit and Oversight Committee of the Board of Directors has sole authority to select, evaluate and, where appropriate, terminate and replace the independent auditors. The Audit and Oversight Committee appointed Deloitte & Touche LLP as our independent auditors for the fiscal year ending December 31, 2007, subject to stockholder ratification. The Committee believes that stockholder ratification of this matter is important considering the critical role the independent auditors play in maintaining the integrity of our financial statements. Stockholders ratified Deloitte & Touche LLP as independent auditors for fiscal year 2007 by the following vote:

Shares Voted For	Percentage of Shares For	Shares Voted Against	Percentage of Shares Against	Shares Abstain	Percentage of Shares Abstain

103,204,078	98.82%	652,573	0.62%	582,980	0.56%

Of 116,950,919 voting shares outstanding as of the February 23, 2007 record date for the annual meeting, 104,439,631 shares (approximately 89.30% of the shares outstanding) were represented at the meeting.

Further information concerning these matters is contained in our Proxy Statement dated March 23, 2007 with respect to the 2007 Annual Meeting of Stockholders.

ITEM 6. EXHIBITS

Exhibit No.


2	Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession

2.1	Letter Agreement between Wisconsin Electric Power Company and FPL Energy Point Beach, LLC, dated May 24, 2007, which effectively amends the Asset Sale Agreement between the parties and FPL Capital Group, Inc.

4	Instruments Defining the Rights of Security Holders, Including Indentures

4.1	Securities Resolution No. 5 of Wisconsin Energy Corporation, dated as of May 8, 2007, under the Indenture for Debt Securities, dated as of March 15, 1999, between Wisconsin Energy and The Bank of New York Trust Company, N.A. (as successor to The First National Bank of Chicago), as Trustee. (Exhibit 4.1 to Wisconsin Energy Corporation's 5/8/07 Form 8-K.)

4.2	Replacement Capital Covenant, dated May 11, 2007, by Wisconsin Energy Corporation for the benefit of certain debtholders named therein. (Exhibit 4.2 to Wisconsin Energy Corporation's 5/8/07 Form 8-K.)

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

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

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

32	Section 1350 Certifications

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

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

SIGNATURES

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

	WISCONSIN ENERGY CORPORATION
	(Registrant)

	/s/STEPHEN P. DICKSON
Date: August 1, 2007	Stephen P. Dickson, Vice President and Controller, Principal Accounting Officer and duly authorized officer