WEC Energy 10Q 2005 Q2 Quarterly report

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 EndedJune 30, 2005

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 an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes [X] No [ ]

Indicate the number of shares outstanding of each of the Registrant's classes of common stock as of the latest practicable date (June 30, 2005):

Common Stock, $.01 Par Value,

116,981,633 shares outstanding.

		WISCONSIN ENERGY CORPORATION


		FORM 10-Q REPORT FOR THE QUARTER ENDED JUNE 30, 2005



		TABLE OF CONTENTS
Item			Page

	Introduction ...........................................................................................................................		3


	Part I -- Financial Information

1.	Financial Statements

	Consolidated Condensed Income Statements ...................................................................		4

	Consolidated Condensed Balance Sheets .........................................................................		5

	Consolidated Condensed Statements of Cash Flows ........................................................		6

	Notes to Consolidated Condensed Financial Statements ..................................................		7

2.	Management's Discussion and Analysis of
	Financial Condition and Results of Operations .................................................................		16

3.	Quantitative and Qualitative Disclosures About Market Risk ..............................................		43

4.	Controls and Procedures ........................................................................................................		44

	Part II -- Other Information

1.	Legal Proceedings ..................................................................................................................		44

2.	Unregistered Sales of Equity Securities and Use of Proceeds [and Issuer Purchases of Equity Securities] ................................................		46

4.	Submission of Matters to a Vote of Security Holders ............................................................		47

6.	Exhibits ...................................................................................................................................		48

	Signatures ................................................................................................................................		49

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. The accompanying condensed financial statements reflect discontinued operations for our manufacturing segment which was sold effective July 31, 2004, and our Calumet Energy (Calumet) facility which was sold effective May 31, 2005. 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 Power Company (Wisconsin Electric), Wisconsin Gas LLC (Wisconsin Gas) and W.E. Power, LLC (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 Electric Company (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".

Non-Utility Energy Segment: Our non-utility energy segment consists of We Power and Wisvest Corporation (Wisvest). We Power was formed in 2001 to design, construct, own, finance and lease to Wisconsin Electric the new generating capacity included in ourPower the Future strategy, which is described further in this report. As a result of a change in corporate strategy to focus onPower the Future, we have reduced the operations of Wisvest.

Other: Other non-utility operating subsidiaries of Wisconsin Energy include Minergy Corp. (Minergy), which has $25.1 million of assets and develops and markets renewable energy and recycling technologies, and Wispark LLC (Wispark), which has $115.8 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 Securities and Exchange Commission (SEC). We have condensed or omitted some information and note disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles pursuant to these rules and regulations. Our financial statements should be read in conjunction with the financial statements and notes thereto included in our 2004 Annual Report on Form 10-K.

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

				2005	2004	2005	2004

				(Millions of Dollars, Except Per Share Amounts)

	Operating Revenues			$792.9	$715.0	$1,892.0	$1,780.0

	Operating Expenses
		Fuel and purchased power		186.4	152.0	344.4	296.1
		Cost of gas sold		142.0	129.5	552.7	515.3
		Other operation and maintenance		272.7	255.2	531.6	509.6
		Depreciation, decommissioning
			and amortization	79.4	82.2	161.6	157.8
		Property and revenue taxes		22.7	21.7	45.7	43.7

	Total Operating Expenses			703.2	640.6	1,636.0	1,522.5



	Operating Income			89.7	74.4	256.0	257.5

	Other Income, Net			17.1	10.3	35.2	15.0

	Interest Expense			41.5	50.8	83.9	105.0


	Income From Continuing
		Operations Before Income Taxes		65.3	33.9	207.3	167.5

	Income Taxes			8.3	12.4	60.4	62.6

	Income from Continuing Operations			57.0	21.5	146.9	104.9

	Income from Discontinued
		Operations, Net of Tax (Note 2)		5.0	17.1	5.0	24.5


	Net Income			$62.0	$38.6	$151.9	$129.4





	Earnings Per Share (Basic)
			Continuing operations	$0.49	$0.18	$1.26	$0.89
			Discontinued operations	0.04	0.15	0.04	0.20

	Total Earnings Per Share (Basic)			$0.53	$0.33	$1.30	$1.09




	Earnings Per Share (Diluted)
			Continuing operations	$0.48	$0.18	$1.24	$0.88
			Discontinued operations	0.04	0.14	0.04	0.20

	Total Earnings Per Share (Diluted)			$0.52	$0.32	$1.28	$1.08




	Weighted Average Common
		Shares Outstanding (Millions)
			Basic	117.0	118.0	117.0	118.2
			Diluted	118.3	119.5	118.3	119.9

	Dividends Per Share of Common Stock			$0.22	$0.21	$0.44	$0.41

	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, 2005	December 31, 2004
			(Millions of Dollars)
Assets

Property, Plant and Equipment
	In service		$8,259.2		$8,203.8
	Accumulated depreciation		(3,193.8)		(3,107.3)

			5,065.4		5,096.5
	Construction work in progress		796.1		602.4
	Leased facilities, net		96.1		98.9
	Nuclear fuel, net		95.7		85.0

		Net Property, Plant and Equipment	6,053.3		5,882.8

Investments
	Nuclear decommissioning trust fund		741.6		737.8
	Equity investment in transmission affiliate		192.0		187.8
	Other		87.4		99.5

		Total Investments	1,021.0		1,025.1

Current Assets
	Cash and cash equivalents		20.6		35.6
	Accounts receivable		353.7		349.0
	Accrued revenues		157.8		245.1
	Materials, supplies and inventories		319.2		407.4
	Deferred income taxes - current		13.5		4.9
	Assets held for sale		-		29.8
	Other		183.6		132.2

		Total Current Assets	1,048.4		1,204.0

Deferred Charges and Other Assets
	Regulatory assets		899.5		849.4
	Goodwill, net		441.9		441.9
	Other		156.6		162.2

		Total Deferred Charges and Other Assets	1,498.0		1,453.5

Total Assets			$9,620.7		$9,565.4




Capitalization and Liabilities

Capitalization
	Common equity		$2,579.1		$2,492.4
	Preferred stock of subsidiary		30.4		30.4
	Long-term debt		2,992.4		3,239.5

		Total Capitalization	5,601.9		5,762.3

Current Liabilities
	Long-term debt due currently		347.3		101.0
	Short-term debt		249.9		338.0
	Accounts payable		294.4		309.7
	Accrued liabilities		103.6		114.5
	Other		172.8		129.2

		Total Current Liabilities	1,168.0		992.4

Deferred Credits and Other Liabilities
	Regulatory liabilities		1,344.7		922.4
	Asset retirement obligations		316.0		762.2
	Deferred income taxes - long-term		546.1		530.4
	Other		644.0		595.7

		Total Deferred Credits and Other Liabilities	2,850.8		2,810.7

Total Capitalization and Liabilities			$9,620.7		$9,565.4





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

				2005	2004

				(Millions of Dollars)
Operating Activities
	Net income			$151.9	$129.4
	Income from discontinued operations, net of tax			(5.0)	(24.5)
	Reconciliation to cash
		Depreciation, decommissioning and amortization		174.2	176.4
		Nuclear fuel expense amortization		10.1	10.7
		Equity in earnings of unconsolidated affiliates		(16.9)	(14.9)
		Distributions from unconsolidated affiliates		12.9	11.9
		Deferred income taxes and investment tax credits, net		4.7	33.6
		Accrued income taxes, net		(58.4)	(33.3)
		Deferred costs, net		(50.1)	(50.1)
		Change in - Accounts receivable and accrued revenues		82.6	105.7
			Inventories	88.2	72.9
			Other current assets	6.7	21.8
			Accounts payable	(9.5)	(20.8)
			Other current liabilities	32.9	43.6
		Other		11.1	31.6

Cash Provided by Operating Activities				435.4	494.0

Investing Activities
	Capital expenditures			(322.2)	(254.9)
	Proceeds from asset sales, net			54.7	15.9
	Nuclear fuel			(12.5)	(0.4)
	Nuclear decommissioning funding			(8.8)	(8.8)
	Other			3.2	33.1

Cash Used in Investing Activities				(285.6)	(215.1)

Financing Activities
	Issuance of common stock and exercise of stock options			37.7	47.8
	Purchase of common stock			(59.9)	(98.7)
	Dividends paid on common stock			(51.5)	(48.5)
	Issuance of long-term debt			-	17.4
	Retirement and redemption of long-term debt			(3.0)	(221.8)
	Change in short-term debt			(88.1)	18.2

Cash Used in Financing Activities				(164.8)	(285.6)


Change in Cash and Cash Equivalents from Continuing Operations				(15.0)	(6.7)


Cash and Cash Equivalents at Beginning of Period				35.6	28.1


Cash and Cash Equivalents at End of Period				$20.6	$21.4




Supplemental Information - Cash Paid For
	Interest (net of amount capitalized)			$101.3	$116.2
	Income taxes (net of refunds)			$100.3	$57.5


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 2004 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, 2005 are not necessarily indicative of the results which may be expected for the entire fiscal year 2005 because of seasonal and other factors.

We have modified certain income statement, balance sheet and cash flow presentations related to the reporting of discontinued operations pursuant to Statement of Financial Accounting Standards (SFAS) 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Previously, these were included as components of continuing operations. Prior year financial statement amounts have been reclassified to conform to their current year presentation. These reclassifications had no effect on total earnings per share.

2 -- DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE

Wisvest - Calumet: Effective May 31, 2005, we sold our Calumet facility for approximately $37.0 million in cash to Tenaska Power Fund, L.P. (Tenaska). The primary assets of Calumet were a 308-megawatt natural gas-fired peaking power facility in Chicago, Illinois and related operating contracts. The transaction generated an after tax gain of approximately $4.7 million upon closing and is expected to generate approximately $32.0 million in cash tax benefits.

Pursuant to the terms of the sales agreement, Wisvest has agreed to customary indemnification provisions related to environmental conditions and other matters. Except for retention of the full exposure to indemnify Tenaska for environmental claims related to certain property no longer leased or owned by Wisvest or any of its subsidiaries, Wisvest's maximum aggregate exposure under the indemnification provisions is $35 million. Pursuant to the terms of the agreement, we have guaranteed post-closing obligations under the agreement, including indemnity obligations.

In accordance with SFAS 144, we have reclassified the assets and liabilities of Calumet as Assets Held for Sale in the accompanying December 31, 2004 Consolidated Condensed Balance Sheet. In addition, we have recorded the operating results of Calumet as Discontinued Operations in the accompanying Consolidated Condensed Income Statements. Previously, Calumet's results were included in the non-utility energy segment.

WICOR Manufacturing: Effective July 31, 2004, we sold our manufacturing business to Pentair, Inc. (Pentair). The accompanying Consolidated Condensed Income Statements for the three and six months ended June 30, 2004, reflect the operating results of this business in Discontinued Operations.

Pursuant to the terms of the sales agreement, Wisconsin Energy agreed to customary indemnification provisions related to certain environmental, asbestos and product liability matters associated with the manufacturing business. In addition, the amount of cash taxes and future deferred income tax benefits are subject to a number of factors including appraisals and applicable tax laws. We have established reserves related to the indemnification and tax matters.

The following table identifies the Operating Revenues and Pre-tax Income for Calumet and WICOR manufacturing for the periods reported. These amounts are included in Discontinued Operations in the accompanying 2005 and 2004 Statements of Income.

	Three Months Ended June 30		Six Months Ended June 30
	2005	2004	2005	2004

	(Millions of Dollars)
Operating Revenues
WICOR	$ -	$225.5	$ -	$417.4
Calumet	1.2	1.4	2.3	2.3

Total	$1.2	$226.9	$2.3	$419.7




Income Before Income Taxes
WICOR	$ -	$29.0	$ -	$42.9
Calumet	7.6	(1.1)	7.6	(2.4)

Total	$7.6	$27.9	$7.6	$40.5

3 -- ASSET RETIREMENT OBLIGATIONS

SFAS 143, Accounting for Asset Retirement Obligations, primarily applies to the future decommissioning costs for our two units at our Point Beach Nuclear Plant (Point Beach). In June 2005, we filed an updated Nuclear Decommissioning Cost Study with the Public Service Commission of Wisconsin (PSCW). We engaged a consultant to perform the site specific study for regulatory funding purposes. This study assumes that the units would not run past their current operating licenses of 2010 and 2013, respectively, and the study made several assumptions as to the scope of the work. The study also estimated the liability for fuel management costs and non-nuclear demolition costs. These costs are excluded from the calculation of the SFAS 143 liability. The study estimated that the cost to decommission the plant in 2004 year dollars would be approximately $712.5 million. The prior study, which was completed in 2002, estimated the decommissioning costs to be $1.1 billion. Using the costs esti mated in this recent study, we estimated the nuclear asset retirement obligation to be $308.7 million at June 30, 2005 compared to $745.3 million at December 31, 2004.

Due to the regulated nature of our utility business, we have established a regulatory liability to reflect the difference between nuclear decommissioning costs recovered in rates and the Asset Retirement Obligation (ARO) for nuclear decommissioning that is calculated under SFAS 143. As of June 30, 2005, we have increased our nuclear decommissioning regulatory liability by $432.8 million in comparison to the liability at December 31, 2004, to reflect the reduction of the ARO for nuclear decommissioning as described above.

SFAS 143 also applies to a smaller extent to several other utility assets including the dismantlement of certain hydro facilities and the removal of certain coal handling equipment and water intake facilities located on lakebeds. We have not recorded any asset retirement obligations for the removal of the coal handling equipment or for the water intake facilities located on lakebeds, because the associated liability cannot reasonably be estimated.

The following table presents the change in our asset retirement obligations, which are included on the consolidated balance sheet in Deferred Credits and Other Liabilities.

	Balance at 12/31/04	Liabilities Incurred	Liabilities Settled	Accretion	Cash Flow Revisions	Balance at 06/30/05

	(Millions of Dollars)
Asset Retirement Obligations	$762.2	$ -	($9.8)	$19.2	$(455.6)	$316.0

In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), an interpretation of FASB Statement No. 143. FIN 47 defines the term conditional asset retirement obligation as used in Statement No. 143. As defined in FIN 47, a conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. We are currently evaluating FIN 47 but we do not expect an impact on the results of our regulated operations due to the regulatory treatment of asset retirement costs. FIN 47 will be effective for the fiscal year ending December 31, 2005.

4 -- COMMON EQUITY

Comprehensive Income: Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to owners. We had the following total comprehensive income during the six months ended June 30, 2005 and 2004:

	Six Months Ended June 30

Comprehensive Income	2005	2004

	(Millions of Dollars)

Net Income	$151.9	$129.4
Other Comprehensive Income (Loss)
Currency Translation Adjustments	-	(1.8)
Hedging	(0.3)	(0.3)

Total Other Comprehensive Income (Loss)	(0.3)	(2.1)

Total Comprehensive Income	$151.6	$127.3

Stock-Based Compensation: We apply Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations in accounting for our stock option plans and have adopted the disclosure-only provisions of SFAS 123, Accounting for Stock-Based Compensation, as amended. The following table illustrates the effect on net income and earnings per share as if we had accounted for stock options under the fair value method of SFAS 123 in each period. The fair value of options at date of grant was estimated using the Black-Scholes option-pricing model. Had we expensed stock-based compensation under SFAS 123, our diluted earnings per share would have remained unchanged for the second quarter of 2005. Dilutive earnings per share would have been reduced by $0.01 per share for the year-to-date period ending June 30, 2005.

	Three months ended June 30		Six months ended June 30

	2005	2004	2005	2004

	(Millions of Dollars, Except Per Share Amounts)
Net Income
As reported	$62.0	$38.6	$151.9	$129.4
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects	0.5	0.5	0.9	1.2
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	1.0	2.9	2.0	6.0

Pro forma	$61.5	$36.2	$150.8	$124.6




Basic Earnings Per Common Share
As reported	$0.53	$0.33	$1.30	$1.09
Pro forma	$0.53	$0.31	$1.29	$1.05

Diluted Earnings Per Common Share
As reported	$0.52	$0.32	$1.28	$1.08
Pro forma	$0.52	$0.30	$1.27	$1.04

In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based Payment (SFAS 123R), which amended SFAS 123, Accounting for Stock-Based Compensation. In March 2005, the SEC issued Staff Accounting Bulletin No. 107 (SAB 107) regarding the SEC's interpretation of SFAS 123R and the valuation of share-based payment for public companies. In April 2005, the SEC deferred the effective date of SFAS 123R to January 1, 2006. This statement requires that the compensation costs relating to such transactions be recognized in the consolidated income statement. We are currently evaluating the provisions of SFAS 123R and SAB 107, including the method of transition, and expect to adopt SFAS 123R on January 1, 2006.

Common Stock Activity: In February 2004, we announced that we did not expect to issue new shares through our various employee benefit plans and the dividend reinvestment plan; rather, we instructed the plan agents to begin purchasing shares for the plans in the open market in lieu of issuing new shares.

During the first six months of 2005, we received proceeds of $37.7 million related to the exercise of stock options, compared with $43.0 million during the same period in 2004. We instructed our plan agent to purchase common stock in the open market at a cost of $59.9 million to fulfill the exercised stock options in the first six months of 2005, compared with $67.8 million during the same period in 2004. This cost is included in Purchase of common stock on our Consolidated Condensed Statements of Cash Flows.

5 -- VARIABLE INTEREST ENTITIES

In January 2003, the FASB issued Interpretation 46, Consolidation of Variable Interest Entities (FIN 46). This standard requires an enterprise that is the primary beneficiary of a variable interest entity to consolidate that entity. We applied the Interpretation to any existing interests in variable interest entities beginning in the third quarter of 2003. In October 2003, the FASB deferred the adoption of FIN 46 for all entities commonly referred to as special-purpose entities to the first reporting period ending after December 15, 2003. In December 2003, the FASB issued FIN 46R, which revised FIN 46 and deferred the effective date for interests held in variable interest entities other than special purpose entities to

financial statements for periods ending after March 15, 2004. We adopted FIN 46R in the first quarter of 2004.

We continue to evaluate our tolling and purchased power agreements with third parties on a quarterly basis. After making an exhaustive effort, we concluded that for three of these agreements, we are unable to obtain the information necessary to determine whether we are the primary beneficiary of these variable interest entities. Pursuant to the terms of two of the three agreements, we deliver fuel to the entity's facilities and receive electric power. We pay the entity a "toll" to convert our fuel into the electric energy. The output of the facility is available for us to dispatch during the term of the respective agreement. In the other agreement, we have rights to the firm capacity of the entity's facility. We have approximately $703.2 million of required payments over the remaining term of these three agreements, which expire over the next 18 years. We believe the required payments will continue to be recoverable in rates. We account for one of these agreements as a capital lease.

In March 2005, the FASB issued FSP FIN 46R - 5, Implicit Variable Interests under FASB Interpretation 46 (revised December 2003). This statement requires that holdings of implicit variable interests are evaluated when applying Interpretation 46R. An implicit variable interest is defined as an implied pecuniary interest in an entity that changes with changes in the fair value of the entity's net assets exclusive of variable interests. An implicit variable interest acts the same as an explicit variable interest except it involves the absorbing and/or receiving of variability indirectly from the entity (rather than directly). FIN 46R-5 was effective for the first reporting period beginning after March 3, 2005 for entities that had already adopted FIN 46R; accordingly, we have evaluated and adopted FIN 46R -5 this quarter. We have concluded that we currently do not have any implicit variable interests. We will continue to evaluate FIN 46R- 5 on a quarterly basis.

6 -- DERIVATIVE INSTRUMENTS

We follow SFAS 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, 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.

We had a limited number of financial contracts that were defined as derivatives under SFAS 133 and qualified for cash flow hedge accounting. These contracts were utilized to manage the cost of gas used in testing a new generating unit while it was under construction. Changes in the fair market values of these instruments were recorded in Accumulated Other Comprehensive Income. At the date the underlying transactions occurred, the amounts in Accumulated Other Comprehensive Income were capitalized.

7 -- BENEFITS

The components of our net periodic pension and other post-retirement benefit costs for the three and six months ended June 30, 2005 and 2004 were as follows:

	Pension Benefits		Other Post-retirement Benefits
	Pension Benefits		Other Post-retirement Benefits

	2005	2004	2005	2004

Three Months Ended June 30	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$7.7	$7.4	$4.1	$2.8
Interest cost	17.1	18.2	5.8	5.0
Expected return on plan assets	(22.4)	(22.5)	(5.8)	(3.9)
Amortization of:
Transition (asset) obligation	0.1	(0.6)	0.8	0.4
Prior service cost	1.3	1.3	0.2	0.2
Actuarial loss	6.1	4.1	1.6	1.0

Net Periodic Benefit Cost	$9.9	$7.9	$6.7	$5.5




Six Months Ended June 30
Net Periodic Benefit Cost
Service cost	$16.6	$15.1	$6.9	$6.0
Interest cost	34.8	34.5	11.0	10.8
Expected return on plan assets	(43.8)	(42.9)	(7.7)	(7.0)
Amortization of:
Transition (asset) obligation	-	(1.1)	0.8	0.8
Prior service cost	2.6	2.5	0.3	0.3
Actuarial loss	10.4	7.4	3.6	3.3

Net Periodic Benefit Cost	$20.6	$15.5	$14.9	$14.2

We previously disclosed that we expect to contribute $5.7 million to fund pension benefits in 2005, none of which will be for our qualified plans since there is no minimum required by law. Contributions to other post-retirement benefit plans are discretionary.

Employee Benefit Plans and Post-retirement Benefits: In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act) was signed into law. The Act introduced a prescription drug benefit program under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans. In the second quarter of 2004, the FASB issued FASB Staff Position (FSP) SFAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.

In accordance with FSP 106-2, we chose to recognize the effects of the Act retroactively effective January 1, 2004 with the impacts calculated actuarially. In January 2005, the Centers for Medicare & Medicaid Services released final regulations to implement the new prescription drug benefit under Part D of Medicare. It was determined that the employer sponsored plans meet these regulations and that the previously determined actuarial measurements do not need to be revised. The final regulations addressing account based plans similar to the Cash Balance Medical Plan covering former Wisconsin Gas employees were issued in the second quarter of 2005 and it was determined that the employer sponsored plan meets these regulations and that the previously determined actuarial measurements do not need to be revised.

Severance Plans: In the third and fourth quarters of 2004, we incurred $30.5 million ($18.3 million after-tax) of severance costs. The majority of the severance costs related to an enhanced severance package offered to selected management employees of Wisconsin Energy and its subsidiaries who voluntarily resigned in the fourth quarter of 2004. During the first six months of 2005, we made severance related payments that reduced the reserve for severance benefits from $6.6 million at December 31, 2004 to $2.2 million as of June 30, 2005.

8 -- GUARANTEES

We enter into various guarantees to provide financial and performance assurance to third parties on behalf of affiliates. As of June 30, 2005, we had the following guarantees:

	Maximum Potential Future Payments	Outstanding at June 30, 2005	Liability Recorded at June 30, 2005

	(Millions of Dollars)

Wisconsin Energy
Non-Utility Energy	$ -	$ -	$ -
Other	6.6	6.6	-

Wisconsin Electric	232.6	0.1	-
Subsidiary	21.4	9.8	0.1

Total	$260.6	$16.5	$0.1

A Non-Utility Energy 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 United Illuminating. 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.

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 $17.5 million as of June 30, 2005 and $15.6 million as of December 31, 2004.

9 -- INCOME TAXES

As disclosed in Note G -- Income Taxes to our Form 10-K for the year ended December 31, 2004, we had established valuation allowances related to tax benefits associated with state net operating losses. As of December 31, 2004, we had concluded that it was more likely than not that we would not ultimately realize these tax benefits. In connection with the favorable decision by the Supreme Court of Wisconsin in June 2005 to uphold the Certificate of Public Convenience and Necessity (CPCN) granted by the PSCW for the construction of the Elm Road Generating Station, we have concluded that it is more likely than not that we will be able to utilize certain tax benefits associated with state net operating losses that have been carried forward from prior years. As such, in the second quarter of 2005 we have reversed $16.6 million of valuation allowances associated with the state tax net operating losses that have been carried forward to future years.

10 -- SEGMENT INFORMATION

Summarized financial information concerning our reportable operating segments for the three and six month periods ended June 30, 2005 and 2004 is shown in the following table.

Wisconsin Energy Corporation	Reportable Operating Segments Energy			Corporate (b) & Other (c) & Reconciling Eliminations	Total Consolidated


	Utility	Non-Utility (a)	Manufacturing (b)
	(Millions of Dollars)
Three Months Ended

June 30, 2005
Operating Revenues (d)	$785.1	$3.0	$ -	$4.8	$792.9
Operating Income (Loss)	$90.1	$0.3	$ -	($0.7)	$89.7
Interest Expense	$27.3	$3.0	$ -	$11.2	$41.5
Income Tax Expense	$29.9	($0.6)	$ -	($21.0)	$8.3
Income (Loss) from Discontinued Operations, Net	$ -	$5.0	$ -	$ -	$5.0
Net Income (Loss)	$48.9	$3.9	$ -	$9.2	$62.0
Capital Expenditures	$111.4	$38.0	$ -	$4.0	$153.4

June 30, 2004
Operating Revenues (d)	$703.8	$2.5	$ -	$8.7	$715.0
Operating Income (Loss)	$74.1	$ -	($0.7)	$1.0	$74.4
Interest Expense	$27.6	$3.3	$4.1	$15.8	$50.8
Income Tax Expense	$21.8	($1.1)	($1.9)	($6.4)	$12.4
Income (Loss) from Discontinued Operations, Net	$ -	($0.6)	$17.7	$ -	$17.1
Net Income (Loss)	$34.9	($2.8)	$14.8	($8.3)	$38.6
Capital Expenditures	$89.5	$28.2	$6.4	$2.8	$126.9

Six Months Ended

June 30, 2005
Operating Revenues (d)	$1,879.0	$3.2	$ -	$9.8	$1,892.0
Operating Income (Loss)	$260.7	($0.6)	$ -	($4.1)	$256.0
Interest Expense	$55.2	$6.0	$ -	$22.7	$83.9
Income Tax Expense	$89.5	($1.9)	$ -	($27.2)	$60.4
Income (Loss) from Discontinued Operations, Net	$ -	$5.0	$ -	$ -	$5.0
Net Income (Loss)	$146.3	$1.3	$ -	$4.3	$151.9
Capital Expenditures	$208.4	$108.1	$ -	$5.7	$322.2
Total Assets	$8,554.7	$572.5	$ -	$493.5	$9,620.7

Wisconsin Energy Corporation	Reportable Operating Segments Energy			Corporate (b) & Other (c) & Reconciling Eliminations	Total Consolidated


	Utility	Non-Utility (a)	Manufacturing (b)
	(Millions of Dollars)

June 30, 2004
Operating Revenues (d)	$1,760.5	$2.7	$ -	$16.8	$1,780.0
Operating Income (Loss)	$260.7	($1.8)	($1.5)	$0.1	$257.5
Interest Expense	$55.6	$7.1	$8.6	$33.7	$105.0
Income Tax Expense	$86.0	($4.0)	($3.9)	($15.5)	$62.6
Income (Loss) from Discontinued Operations, Net	$ -	($1.6)	$28.6	($2.5)	$24.5
Net Income (Loss)	$138.8	($6.3)	$22.5	($25.6)	$129.4
Capital Expenditures	$173.0	$76.9	$10.0	$5.0	$264.9
Total Assets	$8,188.8	$482.9	$956.9	$299.8	$9,928.4

(a)	The sale of our Calumet operations was completed effective May 31, 2005 and Calumet was reported at June 30, 2005 and June 30, 2004 as a discontinued operation. The after tax gain of $4.7 million recorded for the sale of Calumet is included in Income from Discontinued Operations, Net. Certain overheads reported for Calumet will continue to exist following the sale and are reported in continuing operations. Certain other costs are directly attributable to the discontinued operations.

(b)	The sale of our manufacturing segment was completed effective July 31, 2004, and was reported at June 30, 2004 as discontinued operations. Certain corporate overheads reported in the manufacturing segment continue to exist following the sale and are reported in continuing operations. Certain other corporate costs are directly attributable to the discontinued operations.

(c)	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.

(d)	An elimination for intersegment revenues is included in Operating Revenues of $3.4 million and $2.0 million for the three months ended June 30, 2005 and 2004, respectively, and in the amounts of $5.8 million and $3.1 million for the six months ended June 2005 and 2004, 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.

12 -- LONG-TERM DEBT -- SUBSEQUENT EVENT

In July 2005, we issued $155.0 million of 4.91% Senior Notes due July 15, 2030 in a private placement. The Senior Notes have a mortgage style repayment feature and have an average life approximating 15 years. Proceeds from the sale of the Senior Notes were used primarily to repay short-term debt incurred during construction of Unit 1 at the Port Washington Generating Station (PWGS). The notes are secured by a collateral assignment to the lenders of the leases between PWGS and Wisconsin Electric in connection with the first natural gas-fired unit.

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

Cautionary Factors Regarding Forward - Looking Statements: Certain statements contained herein are "Forward-Looking Statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-Looking Statements include, among other things, statements regarding management's expectations and projections regarding completion of construction projects, regulatory matters, fuel costs, sources of electric energy supply, gas deliveries, remediation costs, environmental and other capital expenditures, liquidity and capital resources and other matters. Also, 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 State ments as a result of certain risks and uncertainties, including but not limited to, those risks and uncertainties described under the heading "Cautionary Factors" in this Item 2, as well as other matters described under the heading "Factors Affecting Results, Liquidity and Capital Resources" in this Item 2, and other risks and uncertainties detailed from time to time in our filings with the SEC or otherwise described throughout this document.

RESULTS OF OPERATIONS -- THREE MONTHS ENDED JUNE 30, 2005

CONSOLIDATED EARNINGS

The following table compares our net income during the second quarter of 2005 with similar information during the second quarter of 2004 including favorable (better (B)) or unfavorable (worse (W)) variances. Our diluted earnings per share were $0.52 during the second quarter of 2005 compared with $0.32 per share during the same period in 2004. Increased earnings primarily reflect warm summer weather and lower interest expense. In addition, in the second quarter of 2005 we also had a lower effective tax rate due to the reversal of valuation allowances associated with state tax net operating losses that have been carried forward.


	Three Months Ended June 30

		2005	B (W)	2004

	(Millions of Dollars, Except Per Share Amounts)

Utility Energy Segment		$90.1	$16.0	$74.1
Non-Utility Energy Segment		0.3	0.3	-
Corporate and Other		(0.7)	(1.0)	0.3

Total Operating Income		89.7	15.3	74.4
Other Income, Net		17.1	6.8	10.3
Interest Expense		41.5	9.3	50.8

Income From Continuing Operations Before Income Taxes		65.3	31.4	33.9
Income Taxes		8.3	4.1	12.4

Income From Continuing Operations		57.0	35.5	21.5
Income From Discontinued Operations, Net of Tax (a)		5.0	(12.1)	17.1

Net Income		$62.0	$23.4	$38.6



Diluted Earnings Per Share		$0.52	$0.20	$0.32

(a)	Income from Discontinued Operations, Net of Tax includes in 2005 and 2004, the operations of Calumet which were classified as discontinued in the first quarter of 2005 and 2004. Additionally, in 2004 the manufacturing segment, which was sold effective July 31, 2004, was reflected as discontinued operations for the three months ended June 30, 2004.

A more detailed analysis of financial results by segment follows.

UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Our utility energy segment contributed $90.1 million of operating income during the second quarter of 2005, an increase of $16.0 million or 21.6% compared with the second quarter of 2004. The following table summarizes the operating income of this segment between the comparative quarters.

	Three Months Ended June 30

Utility Energy Segment	2005	B (W)	2004

	(Millions of Dollars)
Operating Revenues
Electric	$574.3	$68.1	$506.2
Gas	205.8	12.5	193.3
Other	5.0	0.7	4.3

Total Operating Revenues	785.1	81.3	703.8
Fuel and Purchased Power	187.4	(35.4)	152.0
Cost of Gas Sold	142.0	(12.5)	129.5

Gross Margin	455.7	33.4	422.3
Other Operating Expenses
Other Operation and Maintenance	264.2	(17.1)	247.1
Depreciation, Decommissioning
and Amortization	78.9	1.3	80.2
Property and Revenue Taxes	22.5	(1.6)	20.9

Operating Income	$90.1	$16.0	$74.1

Electric Utility Revenues and Sales

The following table compares electric utility operating revenues and megawatt-hour sales by customer class during the second quarter of 2005 with similar information for the second quarter of 2004.

	Three Months Ended June 30

	Electric Revenues			Megawatt-Hour Sales

Electric Utility Operations	2005	B (W)	2004	2005	B (W)	2004

	(Millions of Dollars)			(Thousands)
Operating Revenues
Residential	$199.2	$32.1	$167.1	2,036.6	217.1	1,819.5
Small Commercial/Industrial	184.9	20.6	164.3	2,216.2	91.1	2,125.1
Large Commercial/Industrial	158.3	18.4	139.9	2,960.9	23.6	2,937.3
Other-Retail/Municipal	25.9	2.7	23.2	644.9	56.6	588.3
Resale-Utilities	3.1	0.3	2.8	60.4	(19.9)	80.3
Other Operating Revenues	2.9	(6.0)	8.9	-	-	-

Total Operating Revenues	$574.3	$68.1	$506.2	7,919.0	368.5	7,550.5




Weather -- Degree Days (a)
Cooling (178 Normal)				237	146	91

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

During the second quarter of 2005, total electric utility operating revenues increased by $68.1 million or 13.5% when compared with the second quarter of 2004. This net increase primarily reflected pricing increases of approximately $38.5 million. The most significant impact to rates was the March 2005 interim order received by Wisconsin Electric from the PSCW authorizing an annualized increase in electric rates of approximately $114.9 million due to the increased costs of fuel and purchased power as a result of customer growth and the increase in the reliance upon natural gas as a fuel source. A similar rate increase was not in effect in the second quarter of 2004. For further information regarding rates see Item 2. Management's Discussion and Analysis - Factors Affecting Results, Liquidity and Capital Resources-- Utility Rates and Regulatory Matters.

We estimate that warm summer weather positively impacted electric sales by $22.3 million during the second quarter of 2005 as compared to the second quarter of 2004. As measured by cooling degree days the second quarter of 2005 was 160.4% warmer than the same period in 2004, increasing cooling load sales to residential customers who are more weather sensitive and contribute higher margins than other customer classes. Residential sales volumes increased 11.9% in the second quarter of 2005 as compared to the same period in 2004. Total electric megawatt-hour sales volumes increased by 368.5 thousand megawatt-hours or 4.9% during the second quarter of 2005 compared with the same period in 2004.

Fuel and Purchased Power

Total fuel and purchased power expenses increased by $35.4 million or 23.3% when compared to the second quarter of 2004. This increase was due to (1) increased megawatt-hour sales, (2) the reduced availability of coal-fired generation due to a higher number of unit outages in the second quarter of 2005 as compared to 2004 and the retirement of the remaining coal-fired generating units at Port Washington Power Plant in September 2004 and (3) the higher cost of purchased energy prices. The cost of purchased energy for the second quarter of 2005 was $56.60 per megawatt-hour, 59.4% higher than 2004. Higher gas prices and warmer June weather were the primary drivers of the increased cost of purchased energy.

Effective April 1, 2005, we began participating in the Midwest Independent Transmission System Operator, Inc. (Midwest ISO) bid-based energy market (Midwest ISO Day 2) which significantly changed how our generating units are dispatched and how we buy and sell power. The State of Wisconsin and the Upper Peninsula of Michigan have significant transmission constraints, and we believe we are more exposed to higher cost uncertainty as a result of the start of Midwest ISO Day 2. As a result of this increased exposure, we, along with other utilities in the State of Wisconsin, have received approval by the PSCW to defer certain costs associated with Midwest ISO Day 2. Based on this authorization, we have deferred $4.2 million for future rate recovery. For more information regarding the Midwest ISO and Midwest ISO Day 2, see Item 2. Management's Discussion and Analysis - Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition -- Electric Transmission and Energ y Markets.

In April 2005, Point Beach Unit 2 shut down for its normal refueling outage, which is scheduled approximately every 18 months. A similar outage occurred on Point Beach Unit 1 in the second quarter of 2004. During the 2005 outage, we replaced the reactor vessel head in Unit 2. This work, along with other planned maintenance, was originally expected to be completed by the end of May. However, the outage was delayed due to the need to obtain a Safety Evaluation Report and a license amendment from the Nuclear Regulatory Commission (NRC) prior to lifting and setting the new Unit 2 reactor vessel head. The license amendment was received in late June, the reactor vessel head was replaced and the outage was completed and Unit 2 returned to full load on July 16, 2005. We received approval from the PSCW in May 2005 to defer incremental replacement power costs for future recovery as a result of the extended outage. We deferred $15.8 million of incremental purchased power costs related to the extended out age as of June 30, 2005 and we expect to recover these costs in the future, subject to review and approval of the PSCW. Unit 1 is scheduled to have a similar refueling outage over the third and fourth quarters of 2005 in which its reactor vessel head is scheduled to be replaced and other planned maintenance will be performed. For more information regarding the scheduled refueling outages, see Item 2. Management's Discussion and Analysis - Factors Affecting Results, Liquidity and Capital Resources -- Nuclear Operations.

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 2005 with similar information for the second quarter of 2004. 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.

	Three Months Ended June 30

Gas Utility Operations	2005	B (W)	2004

	(Millions of Dollars)

Gas Operating Revenues	$205.8	$12.5	$193.3
Cost of Gas Sold	142.0	(12.5)	129.5

Gross Margin	$63.8	$ -	$63.8

The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the second quarter of 2005 with similar information for the second quarter of 2004. For the three months ended June 30, 2005 and June 30, 2004, gas utility gross margin was $63.8 million.

	Three Months Ended June 30

	Gross Margin			Therm Deliveries

Gas Utility Operations	2005	B (W)	2004	2005	B (W)	2004

	(Millions of Dollars)			(Millions)
Customer Class
Residential	$39.3	($1.3)	$40.6	103.4	(7.7)	111.1
Commercial/Industrial	11.5	($0.1)	11.6	62.2	(0.9)	63.1
Interruptible	0.4	-	0.4	4.3	(1.8)	6.1

Total Retail Gas Sales	$51.2	($1.4)	52.6	169.9	(10.4)	180.3
Transported Gas	10.5	1.2	9.3	203.6	37.8	165.8
Other	2.1	0.2	1.9	-	-	-

Total	$63.8	$ -	$63.8	373.5	27.4	346.1



Weather -- Degree Days (a)
Heating (946 Normal)				891	(72)	963

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

Total therm deliveries were 7.9% higher during the second quarter of 2005 primarily due to increased transport gas deliveries of 37.8 million therms.Our margins on transported gas are significantly lower than our margins for retail gas sales. The increase in volume of transport gas sales was due to a higher amount of electric generation from natural gas within our service territory. Increased transport sales were offset, in part, due to decreased heating load sales to residential customers who are more weather sensitive and contribute higher margins than other customer classes. As measured by heating degree days, the second quarter of 2005 was 7.5% warmer than the second quarter of 2004.

Other Operation and Maintenance Expenses

Other operation and maintenance expenses increased by $17.1 million or 6.9% during the second quarter of 2005 compared with the second quarter of 2004. The largest increase relates to $11.4 million of costs related to the Port Washington Generating Station lease and conservation programs, all of which were recognized in connection with the May 2004 and May 2005 limited rate increases which provided revenues on virtually a dollar for dollar basis. Benefits costs have increased approximately $4.4 million between the comparative periods due to increased medical and pension costs and bad debt expense increased $1.0 million. In addition, we estimate that employee costs were down approximately $4.5 million due to the voluntary severance programs that were implemented in the third and fourth quarters of 2004. Nuclear costs decreased $7.4 million between the comparative periods due to reduced outage costs, primarily as a result of the elimination in 2005 of the reactor head inspection required on Point Beach Unit 1 during the scheduled outage in the second quarter of 2004. In the second quarter of 2005, we replaced the reactor vessel head during the scheduled outage on Point Beach Unit 2, and therefore we are no longer required to perform the extensive reactor head inspections. We plan to replace the reactor vessel head on Unit 1 over the third and fourth quarters of 2005 during its planned outage.

Depreciation, Decommissioning and Amortization

Depreciation, Decommissioning and Amortization expenses decreased by $1.3 million or 1.6% during the second quarter of 2005. Decommissioning expense was reduced by $3.7 million to reflect the regulatory treatment of income taxes associated with gains in decommissioning trusts. This reduction was offset in part by depreciation on increased plant balances between the comparative periods.

NON-UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Our non-utility energy segment had operating income of $0.3 million during the second quarter of 2005 compared with no operating income or loss during the second quarter of 2004. The following table compares the operating performance of our non-utility energy segment between the comparative periods. We sold our Calumet facility effective May 31, 2005, which was previously included in the operations of the non-utility energy segment. As a result of this sale, we have determined that the Calumet operations meet the definition of discontinued operations under SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets. See Results of Operations -- Discontinued Operations below for further information.

	Three Months Ended June 30

Non-Utility Energy Segment	2005	B (W)	2004

	(Millions of Dollars)

Operating Revenues	$3.0	$0.5	$2.5
Fuel and Purchased Power	-	-	-

Gross Margin	3.0	0.5	2.5
Other Operating Expenses
Other Operation and Maintenance	2.2	(0.6)	1.6
Depreciation, Decommissioning
and Amortization	0.4	(0.1)	0.3
Property and Revenue Taxes	0.1	0.5	0.6

Operating Income	$0.3	$0.3	$ -

CORPORATE AND OTHER CONTRIBUTION TO OPERATING INCOME

Corporate and other affiliates had an operating loss of $0.7 million in the second quarter of 2005 compared with operating income of $0.3 million in the same period in 2004. The decrease in operating earnings is attributable to lower operating earnings at Minergy and Wispark.

CONSOLIDATED OTHER INCOME, NET

Other income, net increased by $6.8 million in the second quarter of 2005 compared with the second quarter of 2004. The variance is due in part to an increase in the allowance for funds used during construction of $1.7 million due to a higher average balance of Allowance for Funds Used during Construction (AFUDC) - qualifying utility construction projects between the comparative periods. In addition, we recognized higher carrying costs on deferred electric transmission costs of $1.5 million and interest in the earnings of our transmission affiliate increased $1.2 million between the comparative periods.

CONSOLIDATED INTEREST EXPENSE

Interest expense decreased by $9.3 million in the three months ended June 30, 2005 compared with the same period in 2004. This decrease reflects the lower debt level achieved primarily with the proceeds from the sale of our manufacturing segment. Total debt outstanding at June 30, 2005 was $555.2 million less than the debt outstanding as of June 30, 2004.

CONSOLIDATED INCOME TAXES

For the second quarter of 2005, our effective tax rate applicable to continuing operations was 12.7% compared to 36.6% for the second quarter of 2004. The decrease in the effective tax rate was due to the reversal of $16.6 million of valuation allowances associated with state tax net operating losses that have been carried forward. For further information see Note 9 -- Income Taxes in the Notes to Consolidated Condensed Financial Statements in Item 1 of Part I of this report.

DISCONTINUED OPERATIONS

We began classifying the operations of Calumet as discontinued when we entered into the agreement to sell this operation in March 2005. Previously, Calumet's results were included in continuing operations within the non-utility energy segment. We realized $5.0 million and ($0.6) million of net income (loss) from discontinued operations during the second quarters of 2005 and 2004, respectively, for the Calumet operations. Net income from discontinued operations for the second quarter of 2005 includes an after tax gain on the sale of Calumet of $4.7 million.

We began classifying our manufacturing segment as a discontinued operation in February 2004 when we entered into the agreement to sell this segment. We sold this segment to Pentair effective July 31, 2004. We realized no net income from the manufacturing segment during the second quarter of 2005 as this segment is no longer part of our operations, compared to $17.7 million in the second quarter of 2004.

See Note 2 -- Discontinued Operations and Assets Held for Sale in the Notes to Consolidated Condensed Financial Statements in Item 1 of Part I of this report for further information regarding the transactions described above.

RESULTS OF OPERATIONS -- SIX MONTHS ENDED JUNE 30, 2005

CONSOLIDATED EARNINGS

The following table compares our net income during the first six months of 2005 with similar information during the first six months of 2004 including favorable (better (B)) or unfavorable (worse (W)) variances. Our diluted earnings per share were $1.28 during the first six months of 2005 compared with $1.08 per share during the same period in 2004. Increased earnings primarily reflect $0.03 per share of debt redemption costs incurred during the first quarter of 2004, an increase in our interest in the earnings of our transmission affiliate, higher carrying costs on deferred electric transmission costs, and increased allowance for funds used during construction of $0.02 per share each. In addition, in the first six months of 2005 we also had lower interest expense of $0.13 per share and a lower effective tax rate due to the reversal of valuation allowances associated with state tax net operating losses that have been carried forward of $0.14 per share.


	Six Months Ended June 30

		2005	B (W)	2004

	(Millions of Dollars, Except Per Share Amounts)


Utility Energy Segment		$260.7	$ -	$260.7
Non-Utility Energy Segment		(0.6)	1.2	(1.8)
Corporate and Other		(4.1)	(2.7)	(1.4)

Total Operating Income (Loss)		256.0	(1.5)	257.5
Other Income, Net		35.2	20.2	15.0
Interest Expense		83.9	21.1	105.0

Income From Continuing Operations Before Income Taxes		207.3	39.8	167.5
Income Taxes		60.4	2.2	62.6

Income From Continuing Operations		146.9	42.0	104.9
Income From Discontinued Operations, Net of Tax (a)		5.0	(19.5)	24.5

Net Income		$151.9	$22.5	$129.4



Diluted Earnings Per Share		$1.28	$0.20	$1.08

(a)	Income from Discontinued Operations, Net of Tax includes in 2005 and 2004, the operations of Calumet which were classified as discontinued for six months ended June 30, 2005 and June 30, 2004. The sale of Calumet was completed effective May 31, 2005. Additionally, in 2004 the manufacturing segment, which was sold effective July 31, 2004, was reflected as discontinued operations for the six months ended June 30, 2004.

A more detailed analysis of financial results by segment follows.

UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Our utility energy segment contributed $260.7 million of operating income during the first six months of 2005 and 2004. The following table summarizes the operating income of this segment between the comparative periods.

	Six Months Ended June 30

Utility Energy Segment	2005	B (W)	2004

	(Millions of Dollars)
Operating Revenues
Electric	$1,098.4	$75.0	$1,023.4
Gas	765.8	42.2	723.6
Other	14.8	1.3	13.5

Total Operating Revenues	1,879.0	118.5	1,760.5
Fuel and Purchased Power	346.5	(50.4)	296.1
Cost of Gas Sold	552.7	(37.4)	515.3

Gross Margin	979.8	30.7	949.1
Other Operating Expenses
Other Operation and Maintenance	514.7	(23.0)	491.7
Depreciation, Decommissioning
And Amortization	159.1	(5.1)	154.0
Property and Revenue Taxes	45.3	(2.6)	42.7

Operating Income	$260.7	$ -	$260.7

Electric Utility Revenues and Sales

The following table compares electric utility operating revenues and megawatt-hour sales by customer class during the first six months of 2005 with similar information for the first six months of 2004.

	Six Months Ended June 30

	Electric Revenues			Megawatt-Hour Sales

Electric Utility Operations	2005	B (W)	2004	2005	B (W)	2004

	(Millions of Dollars)			(Thousands)
Operating Revenues
Residential	$388.9	$35.1	$353.8	4,099.5	163.5	3,936.0
Small Commercial/Industrial	351.2	28.7	322.5	4,428.6	115.7	4,312.9
Large Commercial/Industrial	290.4	22.9	267.5	5,713.0	(24.3)	5,737.3
Other-Retail/Municipal	52.2	7.5	44.7	1,347.7	142.7	1,205.0
Resale-Utilities	4.6	(13.2)	17.8	105.3	(296.2)	401.5
Other Operating Revenues	11.1	(6.0)	17.1	-	-	-

Total Operating Revenues	$1,098.4	$75.0	$1,023.4	15,694.1	101.4	15,592.7




Weather -- Degree Days (a)
Heating (4,212 Normal)				4,179	(149)	4,328
Cooling (179 Normal)				237	146	91

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

During the first six months of 2005, total electric utility operating revenues increased by $75.0 million or 7.3% when compared with the first six months of 2004. This net increase primarily reflected pricing increases of approximately $58.2 million and warm summer weather that was offset, in part, by decreased opportunity sales. The most significant impacts to rates were (1) the March 2005 interim order received by Wisconsin Electric from the PSCW authorizing an annualized increase in electric rates of approximately $114.9 million due to the increased costs of fuel and purchased power as a result of customer growth and the increase in the reliance upon natural gas as a fuel source and (2) the May 2004 order received by Wisconsin Electric from the PSCW authorizing an annualized increase in electric rates of approximately $59.0 million to cover construction costs associated with ourPower the Future program and to recover low income uncollectible expenses transferred to Wi sconsin's public benefits fund. For further information regarding rates see Item 2. Management's Discussion and Analysis - Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters.

Total electric megawatt-hour sales volumes increased by 101.4 thousand megawatt-hours or 0.7% during the first six months of 2005 compared with the same period in 2004. Sales volumes to other utilities were down 73.8% due to a decrease in availability of opportunity sales. As measured by cooling degree days, the first six months of 2005 were 160.4% warmer than the first six months of 2004, increasing cooling load sales to residential customers who are more weather sensitive and contribute higher margins than other customer classes. We estimate that weather had a favorable impact on operating revenues of approximately $20.9 million for the six months ended June 30, 2005 as compared to the first six months ended June 30, 2004.

Fuel and Purchased Power

Total fuel and purchased power expenses increased by $50.4 million or 17.0% when compared to the first six months of 2004. This increase was due to (1) increased megawatt-hour sales, (2) the reduced availability of coal-fired generation due to a higher number of unit outages in the second quarter of 2005 as compared to 2004 and the retirement of the remaining coal-fired generating units at Port Washington Power Plant in September 2004 and (3) the higher cost of purchased energy prices. The cost of

purchased energy, for the first six months of 2005 was $51.34 per megawatt-hour, 44.4% higher than the same period in 2004. Higher gas prices and warmer June weather were the primary drivers of the increased cost of purchased energy.

Effective April 1, 2005, we began participating in Midwest ISO Day 2 which significantly changed how our generating units are dispatched and how we buy and sell power. The State of Wisconsin and the Upper Peninsula of Michigan have significant transmission constraints, and we believe we are more exposed to higher cost uncertainty as a result of the start of Midwest ISO Day 2. As a result of this increased exposure, we, along with other utilities in the State of Wisconsin, have received approval by the PSCW to defer certain costs associated with Midwest ISO Day 2. Based on this authorization, we have deferred $4.2 million for future rate recovery. For more information regarding Midwest ISO and Midwest ISO Day 2 see Item 2. Management's Discussion and Analysis - Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition-- Electric Transmission and Energy Markets.

In April 2005, Point Beach Unit 2 shut down for its normal refueling outage, which is scheduled approximately every 18 months. A similar outage occurred on Point Beach Unit 1 in the second quarter of 2004. During the 2005 outage, we replaced the reactor vessel head in Unit 2. This work, along with other planned maintenance, was originally expected to be completed by the end of May. However, the outage was delayed due to the need to obtain a Safety Evaluation Report and a license amendment from the NRC prior to lifting and setting the new Unit 2 reactor vessel head. The license amendment was received in late June, the reactor vessel head was replaced and the outage was completed and Unit 2 returned to full load on July 16, 2005. We received approval from the PSCW in May 2005 to defer incremental replacement power costs for future recovery as a result of the extended outage. We deferred $15.8 million of incremental purchased power costs related to the extended outage as of June 30, 200 5 and we expect to recover these costs in the future, subject to review and approval of the PSCW. Unit 1 is scheduled to have a similar refueling outage over the third and fourth quarters of 2005 in which its reactor vessel head is scheduled to be replaced and other planned maintenance will be performed. For more information regarding the scheduled refueling outages, see Item 2. Management's Discussion and Analysis - Factors Affecting Results, Liquidity and Capital Resources -- Nuclear Operations.

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 2005 with similar information for the first six months of 2004. 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.

	Six Months Ended June 30

Gas Utility Operations	2005	B (W)	2004

	(Millions of Dollars)

Gas Operating Revenues	$765.8	$42.2	$723.6
Cost of Gas Sold	552.7	(37.4)	515.3

Gross Margin	$213.1	$4.8	$208.3

The following table compares gas utility gross margin and natural gas therm deliveries by customer class during the first six months of 2005 with similar information for the first six months of 2004.

	Six Months Ended June 30

	Gross Margin			Therm Deliveries

Gas Utility Operations	2005	B (W)	2004	2005	B (W)	2004

	(Millions of Dollars)			(Millions)
Customer Class
Residential	$139.7	$1.6	$138.1	486.3	(19.0)	505.3
Commercial/Industrial	42.4	0.5	41.9	277.9	(6.2)	284.1
Interruptible	0.9	(0.2)	1.1	11.3	(3.8)	15.1

Total Retail Gas Sales	183.0	1.9	181.1	775.5	(29.0)	804.5
Transported Gas	25.8	2.8	23.0	454.5	39.5	415.0
Other	4.3	0.1	4.2	-	-	-

Total	$213.1	$4.8	$208.3	1,230.0	10.5	1,219.5



Weather -- Degree Days (a)
Heating (4,212 Normal)				4,179	(149)	4,328

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

For the six months ended June 30, 2005, gas utility gross margin increased by $4.8 million or 2.3% when compared to the six months ended June 30, 2004. This reflects primarily $6.5 million of price increases. The price increases are related to the PSCW approval of an annual rate increase of $25.9 million, which became effective in March 2004. Our margins on transported gas are significantly lower than our margins for retail gas sales. Transport therm deliveries increased 9.5% due to a higher amount of electric generation from natural gas within our service territory. The price increase and increased transport sales were offset, in part, by a decrease in residential therm deliveries of 3.8% due to warmer weather. As measured by heating degree days, the first six months of 2005 were 3.4% warmer than the first six months of 2004.

Other Operation and Maintenance Expenses

Other operation and maintenance expenses increased by $23.0 million or 4.7% during the first six months of 2005 compared with the first six months of 2004. The largest increase relates to $25.4 million of costs related to the Port Washington Generating Station lease and conservation programs, all of which were recognized in connection with the May 2004 and May 2005 limited rate increases which provided revenues on virtually a dollar for dollar basis. In addition, benefits costs have increased approximately $4.9 million between the comparative periods due to increased medical and pension costs. We estimate that employee costs were down approximately $11.1 million due to the voluntary severance programs that were implemented in the third and fourth quarters of 2004. Nuclear costs decreased $5.7 million between the comparative periods due to reduced outage costs, primarily as a result of the elimination in 2005 of the reactor head inspection required on Point Be ach Unit 1 during the scheduled outage in the second quarter of 2004. In the second quarter of 2005, we replaced the reactor vessel head during the scheduled outage on Point Beach Unit 2, and therefore we are no longer required to perform the extensive reactor head inspections. We plan to replace the reactor vessel head on Unit 1 over the third and fourth quarters of 2005 during its planned outage.

Depreciation, Decommissioning and Amortization

Depreciation, Decommissioning and Amortization expenses increased by $5.1 million or 3.3% during the first six months of 2005. The variance is due primarily to a difference in the amount recognized for a decommissioning expense reduction to reflect the regulatory treatment of income taxes associated with gains in decommissioning trusts. The reduction recognized in the first six months of 2004 was $7.7 million compared with the $3.7 million reduction recognized in the same period in 2005.

NON-UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME

Our non-utility energy segment had an operating loss of $0.6 million during the first six months of 2005 compared with an operating loss of $1.8 million during the first six months of 2004. The following table compares the operating performance of our non-utility energy segment between the comparative periods. We sold our Calumet facility effective May 31, 2005, which was previously included in the operations of the non-utility energy segment. As a result of this sale, we have determined that the Calumet operations meet the definition of discontinued operations under SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets. See Results of Operations -- Discontinued Operations below for further information.

	Six Months Ended June 30

Non-Utility Energy Segment	2005	B (W)	2004

	(Millions of Dollars)

Operating Revenues	$3.2	0.5	$2.7
Fuel and Purchased Power	-	-	-

Gross Margin	3.2	0.5	2.7
Other Operating Expenses
Other Operation and Maintenance	2.9	0.3	3.2
Depreciation, Decommissioning
and Amortization	0.7	-	0.7
Property and Revenue Taxes	0.2	0.4	0.6

Operating Loss	($0.6)	$1.2	($1.8)

CORPORATE AND OTHER CONTRIBUTION TO OPERATING INCOME

Corporate and other affiliates had an operating loss of $4.1 million in the first six months of 2005 compared with an operating loss of $1.4 million in the same period in 2004. The increase in operating loss is attributable to lower operating earnings at Minergy and Wispark.

CONSOLIDATED OTHER INCOME, NET

Other income, net increased by $20.2 million in the first six months of 2005 compared to the first six months of 2004. The variance is primarily due to $5.9 million of debt redemption costs incurred during the first quarter of 2004. In addition, our interest in the earnings of our transmission affiliate increased $2.5 million, we recognized higher carrying costs on deferred electric transmission costs of $2.9 million, and allowance for funds used during construction increased $3.1 million in the first six months of 2005 due to a higher average balance of AFUDC - qualifying utility construction projects between the comparative periods.

CONSOLIDATED INTEREST EXPENSE

Interest expense decreased by $21.1 million in the six months ended June 30, 2005 compared with the same period in 2004. This decrease reflects the lower debt level achieved primarily with the proceeds from the sale of our manufacturing segment. Total debt outstanding at June 30, 2005 was $555.2 million less than the debt outstanding as of June 30, 2004.

CONSOLIDATED INCOME TAXES

For the first six months of 2005, our effective tax rate applicable to continuing operations was 29.1% compared to 37.4% for the first six months of 2004. The decrease in the effective tax rate was due to the reversal of $16.6 million of valuation allowances associated with state tax net operating losses that have been carried forward. For further information see Note 9 -- Income Taxes in the Notes to Consolidated Condensed Financial Statements in Item 1 of Part I of this report.

DISCONTINUED OPERATIONS

We began classifying the operations of Calumet as discontinued when we entered into the agreement to sell this operation in March 2005. Previously, Calumet's results were included in continuing operations within the non-utility energy segment. We realized $5.0 million and ($1.6) million of net income (loss) from discontinued operations during the first six months of 2005 and 2004, respectively, for the Calumet operations. Net income from discontinued operations for the first six months of 2005 includes an after tax gain on the sale of Calumet of $4.7 million.

We began classifying our manufacturing segment as a discontinued operation in February 2004 when we entered into the agreement to sell this segment. We sold this segment to Pentair effective July 31, 2004. We realized no net income from the manufacturing segment during the first six months of 2005 as this segment is no longer part of our operations, compared to $26.1 million in the first six months of 2004.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

The following summarizes our cash flows from continuing operations during the first six months of 2005 and 2004:

	Six Months Ended June 30

Wisconsin Energy Corporation	2005	2004

	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$435.4	$494.0
Investing Activities	($285.6)	($215.1)
Financing Activities	($164.8)	($285.6)

Operating Activities

Cash provided by operating activities decreased to $435.4 million during the first six months of 2005 compared with $494.0 million during the same period in 2004. This decrease was due to an increase in income taxes paid offset, in part, by a decrease in working capital requirements.

Investing Activities

During the first six months of 2005, cash used in investing activities was $285.6 million, an increase of $70.5 million over the same period in 2004. This increase is primarily due to increased capital

expenditures at We Power related to ourPower the Future plan and for compliance with the EPA consent decree (See Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters).

Financing Activities

During the six months ended June 30, 2005, we used $164.8 million for financing activities compared with using $285.6 million for financing activities during the first six months of 2004. In the first six months of 2005 the primary uses of cash were to reduce short-term debt, purchase common stock to satisfy benefit plan obligations and to pay dividends on common stock.

The primary use of cash in the first six months of 2004 included approximately $200 million associated with the March 2004 redemption of WEC Capital Trust I's Trust Preferred Securities and $98.7 million for the repurchase of common stock pursuant to our Board approved repurchase plan and to fulfill the exercise of stock options.

In March 2004, we announced that we would resume purchasing up to $50 million of our common shares in the open market under our previously authorized share repurchase program that was initiated in 2000. During the first six months of 2004, we purchased 1.0 million shares of common stock for $30.9 million under this plan. This program expired effective December 31, 2004.

In February 2004, we instructed the agents for our various stock plans to begin purchasing shares of our common stock for our stock plans in the open market in lieu of issuing new shares, and based upon market conditions and other factors, we intend to continue to instruct the plan agents to do so.

In the first six months of 2005, we received proceeds of $37.7 million related to the exercise of stock options, compared with $43.0 million in the first six months of 2004. 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 $59.9 million, compared with $67.8 million in the first six months of 2004. 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 2005 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 2005, we anticipate meeting our capital requirements through internally generated funds supplemented, when required, by the issuance of debt securities and construction financing.

In July 2005, we issued $155.0 million of 4.91% Senior Notes due July 15, 2030 in a private placement. The Senior Notes have a mortgage style repayment feature and have an average life approximating 15 years. Proceeds from the sale of the Senior Notes were used primarily to repay short-term debt incurred during construction of Unit 1 at PWGS. For further information, see Note 12 -- Long-Term Debt--Subsequent Event in the Notes to Consolidated Condensed Financial Statements in Item 1 of Part I of this report.

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 borrowing arrangements and internally generated cash.

In March 2004, the Governor of Wisconsin signed into law a measure that gives utilities the ability to securitize the portion of customer bills that recovers the cost of certain investments intended to improve the environment. The measure would result in a lower cost to customers when compared to traditional financing and ratemaking. In June 2004, Wisconsin Electric filed an application with the PSCW that sought authority to issue up to $500 million of environmental trust bonds pursuant to this legislation. In October 2004, the PSCW approved an order authorizing Wisconsin Electric to issue environmental trust bonds to finance the recovery of $425 million of environmental control costs plus up-front financing costs. The proposed terms of the bonds are subject to further PSCW approval prior to issuance. The issuance of environmental trust bonds is dependent upon the satisfactory resolution of tax rulings associated with the proposed securitization and market conditions.

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

As of June 30, 2005, we have approximately $1.1 billion of available unused lines of bank back-up credit facilities on a consolidated basis. On June 30, 2005, we had approximately $249.9 million of 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, 2005:

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

		(Millions of Dollars)

Wisconsin Energy		$300.0	$ -		$300.0	June-2007	3 year
Wisconsin Energy		$300.0	$2.1		$297.9	Apr-2006	3 year
Wisconsin Electric		$250.0	$23.0		$227.0	June-2007	3 year
Wisconsin Electric		$125.0	$ -		$125.0	Nov-2007	3 year
Wisconsin Gas		$200.0	$ -		$200.0	June-2007	3 year

The following table shows our consolidated capitalization structure at June 30, 2005 and at December 31, 2004:

Capitalization Structure	June 30, 2005		December 31, 2004

	(Millions of Dollars)

Common Equity	$2,579.1	41.6%	$2,492.4	40.2%
Preferred Stock of Subsidiaries	30.4	0.5%	30.4	0.5%
Long-Term Debt (including
current maturities)	3,339.7	53.9%	3,340.5	53.9%
Short-Term Debt	249.9	4.0%	338.0	5.4%

Total	$6,199.1	100.0%	$6,201.3	100.0%



Ratio of Debt to Total Capital		57.9%		59.3%

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 Standard & Poors Corporation (S&P), Moody's Investors Service (Moody's) and Fitch Ratings (Fitch) as of June 30, 2005.

	S&P	Moody's	Fitch

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

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

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

Wisconsin Energy Capital Corporation
Unsecured Debt	BBB+	A3	A-

On March 29, 2005, S&P affirmed the security ratings of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas and changed the security ratings outlook from stable to negative for all three companies.

The security rating outlooks assigned by Moody's and Fitch for Wisconsin Energy, Wisconsin Electric, Wisconsin Gas and Wisconsin Energy Capital Corporation are all stable.

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 2005 are expected to be principally for capital expenditures and nuclear fuel. Our 2005 annual consolidated capital expenditure budget, excluding the purchase of nuclear fuel, is approximately $823.7 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 8 -- Guarantees in the Notes to Consolidated Condensed Financial Statements in this report for more information.

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 FASB Interpretation 46, Consolidation of Variable Interest Entities (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. We have included our contractual obligations under all three of

these contracts in our evaluation of Contractual Obligations/Commercial Commitments discussed below. For additional information, see Note 5 -- Variable Interest Entities in the Notes to Consolidated Condensed Financial Statements.

Contractual Obligations/Commercial Commitments: Our total contractual obligations and other commercial commitments are approximately $7.6 billion as of June 30, 2005 compared with $7.5 billion as of December 31, 2004. This increase primarily reflects purchase obligations under new coal supply contracts offset, in part, by periodic payments made in the ordinary course of business during the six months ended June 30, 2005. On July 29, 2005, upon issuing a full notice to proceed to Bechtel for the construction of the Elm Road units, our contractual obligations increased significantly.

FACTORS AFFECTING RESULTS, LIQUDITY AND CAPITAL RESOURCES

MARKET RISKS AND OTHER SIGNIFICANT RISKS

Construction Risk: In December 2002, the PSCW issued a written order granting a Certificate of Public Convenience and Necessity (CPCN) to commence construction of the Port Washington Generating Station (Port Washington units) consisting of two 545-megawatt natural gas-fired combined cycle generating units on the site of Wisconsin Electric's existing Port Washington Power Plant. The order approves key financial terms of the leased generation contracts including fixed construction costs of the two Port Washington units at $309.6 million and $280.3 million (2001 dollars), respectively, subject to escalation at the GDP inflation rate, force majeure, excused events and event of loss provisions. For additional information, see Power the Future -- Port Washington below.

In addition, in November 2003, the PSCW issued a written order granting a CPCN to commence construction of two 615-megawatt super critical pulverized coal generating units (Elm Road units) adjacent to the site of Wisconsin Electric's existing Oak Creek Power Plant. The order approves key financial terms of the leased generation contracts including a target construction cost of the two Elm Road units of $2.191 billion plus, subject to PSCW approval, cost over-runs of up to 5%, costs attributable to force majeure events, excused events and event of loss provisions. For additional information, see Power the Future -- Elm Road below.

Large construction projects of this type are subject to usual construction risks over which we will have limited or no control and which might adversely affect project costs and completion time. These risks include, but are not limited to, shortages of, the inability to obtain or the cost of labor or materials, the inability of the general contractor or subcontractors to perform under their contracts, strikes, adverse weather conditions, the inability to obtain necessary permits in a timely manner and changes in applicable laws or regulations, governmental actions and events in the global economy.

If final costs for the construction of the Port Washington units exceed the fixed costs allowed in the PSCW order, absent a finding by the PSCW of extraordinary circumstances such as force majeure conditions, this excess will not adjust the amount of the lease payments recovered from Wisconsin Electric. If final costs of the Elm Road project are within 5% of the target cost, and the additional costs are deemed to be prudent by the PSCW, the final lease payments for the Elm Road units recovered from Wisconsin Electric would be adjusted to reflect the actual construction costs. Costs above the 5% cap would not be included in lease payments or recovered from customers absent a finding by the PSCW of extraordinary circumstances such as force majeure conditions.

Credit Rating Risk: We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. We do have certain agreements in the form of commodity and energy services contracts and employee benefit plans that

could require, in the event of a credit ratings change to below investment grade, a termination payment if collateral is not provided or an accelerated payment. At June 30, 2005, we estimate that the potential payments under these agreements that could result from credit rating downgrades totaled approximately $82.1 million.

Commodity Price Risk: In the normal course of business, our utility and non-utility power generation subsidiaries utilize contracts of various duration for the forward sale and purchase of electricity. This is done to optimize utilization of their available generating capacity and energy during periods when available power resources are projected to be greater than or less than our load obligations. This practice may also include forward contracts for the purchase of power during periods when the anticipated market price of electric energy is below expected incremental power production costs. In addition, effective April 1, 2005, our electric utilities became market participants in Midwest ISO Day 2. For additional information on Midwest ISO Day 2 see Utility Rates and Regulatory Matters -- Other Utility Rate Matters and Industry Restructuring and Competition -- Electric Transmission and Energy Markets below. We manage our fuel and gas supply costs through a portfolio of short- and long-term procurement contracts with various suppliers for the purchase of coal, uranium, natural gas and fuel oil.

In addition, we manage our natural gas price risk by utilizing a gas hedging program (for gas used in producing electricity) approved by the PSCW.

In July 2005, we received a letter from Union Pacific Corporation notifying us that a force majeure event requiring maintenance on a Union Pacific railroad line is expected to result in a 15-20% reduction in the amount of contracted deliveries of Powder River Basin coal to certain of our coal generating facilities from June 2005 through November 2005. Although we believe that we will be able to minimize the adverse impact to our fuel and purchased power costs, the actions taken will likely reduce the amount of generating capability supplied by these coal units requiring us to obtain additional megawatt hour purchases through other potentially higher cost generating resources in Midwest ISO Day 2.

Power the Future

Under ourPower the Future strategy, we expect to meet a significant portion of our future generation needs through the construction of the Port Washington units and Elm Road units by We Power. The new plants will be leased by We Power to Wisconsin Electric under long-term leases, and we expect Wisconsin Electric to recover the lease payments in its electric rates.

Port Washington: In July 2003, We Power began construction of Unit 1. Unit 1 was put into service in July 2005 and is fully operational. In October 2003, we received approval from the Federal Energy Regulatory Commission (FERC) to transfer by long-term lease certain associated FERC jurisdictional assets from We Power to Wisconsin Electric. In May 2004 we filed an updated demand and energy forecast with the PSCW to document market demand for additional generating capacity. We Power began construction of Unit 2 with site preparation in May 2004. We expect Unit 2 to be operational in 2008.

Elm Road: In November 2003, the PSCW issued an order (the Elm Road Order) granting Wisconsin Energy, Wisconsin Electric and We Power a CPCN to commence construction of the Elm Road units to be located adjacent to Wisconsin Electric's existing Oak Creek Power Plant. The first unit is scheduled to be operational in 2009 and the second unit is scheduled to be operational in 2010. The CPCN was granted contingent upon us obtaining the necessary environmental permits. We have received all permits necessary to commence construction. We expect that two other co-owners will have purchased an ownership interest in the project of approximately 17% by the fourth quarter of 2005.

In November 2004, a Dane County Circuit Court judge reviewing challenges to the PSCW's order authorizing us to build the Elm Road units vacated the CPCN and remanded it back to the PSCW for additional proceedings. The Court determined that the PSCW committed errors in determining the completeness of our application and in its decision on several other points.

We, the PSCW and the Wisconsin Department of Natural Resources (WDNR) filed motions for direct, expedited appeal in mid-December 2004 with the Supreme Court of Wisconsin. In January 2005, the Supreme Court of Wisconsin agreed to hear the appeal and on March 30, 2005 they heard oral arguments in this matter. On June 28, 2005, the Supreme Court of Wisconsin issued its decision which reversed the Dane County Circuit Court's decision that vacated the PSCW order authorizing us to build the Elm Road units and upheld the PSCW's order in all respects. The CPCN granted by the PSCW was reinstated and is in full force and effect.

As a result of the delay to the start of construction caused by litigation, the project cost is expected to increase by $50 to $55 million dollars. This represents an increase of approximately 2.4% to 2.6% in the total cost of the project. We believe these costs are ultimately recoverable under the terms of the lease agreements between We Power and Wisconsin Electric. However, recovery is subject to our final calculation of costs and also to review and approval by the PSCW.

On June 29, 2005, a mobilization notice was given to Bechtel and construction commenced at the site. A full notice to proceed was issued to Bechtel on July 29, 2005.

We have received all permits necessary to commence construction. Certain of these permits continue to be contested, but remain in effect unless and until overturned by a reviewing court or administrative law judge.The major permits are discussed below.

In September 2003, several parties filed a request with the WDNR for a contested case hearing in connection with our application to the WDNR for a Chapter 30 permit for wetlands and waterways alterations and construction on the bed of Lake Michigan for the construction of the Elm Road units. That request was granted and assigned to an administrative law judge. The hearing took place in August 2004 and post hearing briefing concluded in September 2004. In November 2004, the administrative law judge approved the WDNR's issuance of the Chapter 30 permit for the Elm Road units. In December 2004, opponents filed a petition for review of the decision in Dane County Circuit Court. In January 2005, we filed a motion to dismiss the opponents' petition based on procedural errors. The WDNR joined in this motion. In March 2005, the court dismissed the appeal. The opponents have appealed the court's dismissal to the Wisconsin Court of Appeals. Briefing is scheduled to be completed in early September .

We applied to the WDNR to modify the existing Wisconsin Pollution Discharge Elimination System (WPDES) permit at this location that is required for operation of the water intake and discharge system for the planned Elm Road and existing Oak Creek generating units. In March 2005, the WDNR determined that the proposed cooling water intake structure and water discharge system meets regulatory requirements and reissued the WPDES permit with specific limitations and conditions. The opponents have filed a petition for judicial review in Dane County Circuit Court and a request for a contested case proceeding with the WDNR. The WDNR granted a contested case hearing and the case has been assigned to an administrative law judge for hearings. We anticipate a decision by the administrative law judge in the first half of 2006. In July 2005, the judge decided to hold the judicial review proceeding in the Dane County Circuit Court open until the scope of the contested case pr oceeding has been determined.

In May 2005, we received the Army Corps of Engineers federal permit necessary for the construction of the Elm Road units. Opponents may appeal the permit in federal court.

In January 2004, the WDNR issued the Air Pollution Control and Construction Permit to Wisconsin Electric for the Elm Road units. In February 2004, project opponents submitted a request for a contested case hearing with the WDNR which was granted. The contested case hearing was held in October 2004. In February 2005,an administrative law judge issued a decision affirming the WDNR January 2004 issuance of the Air Pollution Control and Construction Permit. In February 2005, the project opponents filed a petition for judicial review of the decision with the Dane County Circuit Court. In July 2005, the judge allowed Madison Gas and Electric Company, Wisconsin Public Power Inc. and Sierra Club to intervene in this appeal, and set a briefing schedule with final briefs due in December 2005.

UTILITY RATES AND REGULATORY MATTERS

In the state of Wisconsin, Wisconsin Electric and Wisconsin Gas rates are governed by an order from the PSCW issued in March 2000 in connection with the approval of the WICOR acquisition. Under this order, Wisconsin Electric and Wisconsin Gas are restricted from increasing Wisconsin rates for a five year period ending December 31, 2005, with certain exceptions. Under the March 2000 order, a full rate review is required by the PSCW for rates beginning on January 1, 2006. In June 2005, we filed with the PSCW a natural gas price increase request, as well as all materials for the PSCW and other parties to commence the rate review required by the March 2000 order. We requested a rate increase of $80.6 million to address the higher costs associated with adding and maintaining gas mains and infrastructure to maintain safety and reliability and certain costs related to gas in storage.

In July 2005, we filed an electric and steam price increase request with the PSCW. We requested an increase in electric rates of $143.6 million for 2006, and an $8.8 million total increase in rates for steam over the two year period of 2006 and 2007. The requested electric rate increase includes: (1) costs associated with the continued investment in ourPower the Futurestrategy, (2) recovery of American Transmission Company, LLC charges that exceed the amount we are currently collecting from customers, (3) additional sources of renewable energy, and (4) a rate freeze for day to day operations of the electric system until 2008. The requested steam rate increase is due to (1) the costs of maintaining the steam system, (2) the cost of fuel, and (3) the costs associated with making changes to our steam utility operations as part of the reconstruction of the Marquette Interchange project in downtown Milwaukee, Wisconsin.

In a scheduling conference held in July 2005, the PSCW administrative law judge set a schedule which would allow for a PSCW decision and order on both requests by year end 2005. Such an order would allow the rates to be effective January 2006.

Other Limited Rate Adjustment Requests

2005 Revenue Deficiencies: In May 2004, Wisconsin Electric filed an application with the PSCW for an annualized increase in electric and steam rates for anticipated 2005 revenue deficiencies associated with (1) costs for the new Port Washington Generating Station and the Elm Road Generating Station being constructed as part of ourPower the Future strategy, (2) costs associated with our energy efficiency procurement plan and (3) costs associated with making changes to our steam utility systems as part of the reconstruction of the Marquette Interchange highway project in downtown Milwaukee, Wisconsin. The filing identified anticipated revenue deficiencies in 2005 attributable to Wisconsin in the amount of $84.8 million (4.5%) for the electric operations of Wisconsin Electric, and $0.5 million (3.6%) for Wisconsin Electric's steam operations. In January 2005, as a result of the litigation involving our Elm Road units, we amended this filing to redu ce the total revenue request to $52.4 million. In May 2005, the PSCW issued its final written order implementing an annualized increase in electric rates of $59.7 million (3.1%) and an increase of $0.5 million (3.6%) in steam rates.

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 the reliance upon natural gas as a fuel source. We received approval for the increase in fuel recoveries on an interim basis in March 2005. The revenues associated with this interim order will be subject to refund and the costs associated with the filing will be audited by the PSCW. Under the fuel rules, Wisconsin Electric would have to refund to customers any over recoveries of fuel costs plus interest at a rate of 12.2%.

Other Utility Rate Matters

Bad Debt Costs: In December 2004, we filed with the PSCW a request to implement a pilot program, which, among other things, is designed to better match our collection efforts with the ability of low income customers to pay their bills. Included in this filing was a request to implement escrow accounting for all residential bad debt costs. In February 2005, the PSCW approved our pilot program and our request for escrow accounting. The final decision was received in March 2005. The escrow method of accounting for bad debt costs allows for deferral of residential bad debt expense that exceed amounts allowed in rates.

Environmental Trust Financing: In March 2004, the Governor of Wisconsin signed into law a measure that gives utilities the ability to securitize the portion of customer bills that recovers the cost of certain investments intended to improve the environment. The measure would result in a lower cost to customers when compared to traditional financing and ratemaking. In June 2004, Wisconsin Electric filed an application with the PSCW that sought authority to issue up to $500 million of environmental trust bonds pursuant to this legislation. In October 2004, the PSCW approved an order authorizing Wisconsin Electric to issue environmental trust bonds to finance the recovery of $425 million of environmental control costs plus up-front financing costs. The proposed terms of the bonds are subject to further PSCW approval prior to issuance. The issuance of environmental trust bonds is dependent upon the satisfactory resolution of tax rulings associated w ith the proposed securitization and market conditions.

Midwest ISO Day 2: In January 2005, we requested deferral accounting treatment from the PSCW for certain incremental costs or benefits that may occur due to the implementation on April 1, 2005 of Midwest ISO Day 2. We received approval for this accounting treatment in March 2005. Additionally, in March 2005, we submitted a joint proposal to the PSCW with other utilities requesting escrow accounting treatment for Midwest ISO Day 2 costs until each utility's first rate case following April 1, 2008. The purpose of the March 2005 request for escrow accounting was to (1) provide a long-term solution for the costs associated with Midwest ISO Day 2 until there is more experience in the market and (2) provide clarification on costs not included in the March 2005 approval for deferral accounting treatment. We anticipate receiving a decision on this request in the third quarter of 2005. For additional information see Industry Restructuring and Competition -- Electric Transmission and Energy Markets -- Midwest ISO below.

Point Beach Design Basis Calculation Re-analysis: We are in the initial process of performing a review of system design calculations to validate the plant design and licensing basis for the Point Beach Nuclear Plant. The cost of this project is expected to be approximately $15 million. The work is being performed to demonstrate that the design basis for the plants existing operating license is being met. This project will verify that the activities authorized by the existing operating license and the renewed operating license, if approved by the NRC, are and will continue to be conducted in accordance with the current licensing basis. This must be demonstrated in order to support the long-term operation of the plant. In July 2005, we requested approval from the PSCW that the costs associated with this project be capitalized. We believe this accounting treatment is appropriate as these activities are required to support the long-term operation of the plant. A dditionally, we requested that if the PSCW did not agree with the proposed accounting treatment, that these costs be considered for deferral.

Nuclear Refueling Outages - 2005: In May 2005, we requested and we received approval from the PSCW to defer replacement power costs incurred after May 30, 2005 due to the longer-than-expected outage at Point Beach Unit 2. We deferred $15.8 million of incremental purchased power costs related to the extended outage as of June 30, 2005. The deferral of these costs is subject to recovery in future rates. Additionally, any deferred amounts will be subject to PSCW audit. For additional information see Nuclear Operations below.

NUCLEAR OPERATIONS

Wisconsin Electric owns two 518-megawatt electric generating units (Unit 1 and Unit 2) at Point Beach Nuclear Plant in Two Rivers, Wisconsin. The Plant is operated by Nuclear Management Company, LLC (NMC), a joint venture of ours and affiliates of other unaffiliated utilities.

Each Unit at the Plant has a scheduled refueling outage approximately every 18 months. In 2004, Unit 1 had a scheduled refueling outage in the second quarter. In 2005 we have two scheduled outages. During these scheduled refueling outages we are replacing the reactor vessel heads in each Unit. This work, along with other planned maintenance, is expected to result in longer than normal outages. During scheduled refueling outages, we incur significant operations and maintenance costs for work performed during the outages and we incur costs associated with replacement power.

The Unit 2 outage began in April 2005 and was originally expected to be completed by the end of May 2005. However, the outage was delayed due to the need to obtain a Safety Evaluation Report and a license amendment from the U.S. Nuclear Regulatory Commission (NRC) prior to lifting and setting the new Unit 2 reactor vessel head. In late June, the license amendment was received, the reactor vessel head was replaced and the outage was completed and Unit 2 was returned to full load on July 16, 2005. In May 2005, we received approval from the PSCW to defer incremental replacement power costs as a result of the extended outage. The deferral of these costs is subject to recovery in future rates. Additionally, any deferred amounts will be subject to PSCW audit. Point Beach Nuclear Unit 1 is scheduled to have a refueling outage over the third and fourth quarters of 2005 during which time the Unit 1 reactor vessel head will be replaced. NMC filed a request with the NRC to obtain a similar lice nse amendment for the Unit 1 outage.

In June 2005, we made a filing with the PSCW which incorporated a recent site specific study which estimated the costs to decommission our Point Beach Nuclear Plant. This new study estimated the decommissioning costs at $712.5 million in 2004 dollars. The prior study, which was completed in 2002, estimated the decommissioning costs to be $1.1 billion. The reduction in the estimated costs is due to the site specific assumptions that were used in the most recent study. It is noted that these costs include work that is not included in the ARO liability under SFAS 143. For further information see Note 3 -- Asset Retirement Obligations in the Notes to Consolidated Condensed Financial Statements in Item 1 of Part I of this report.

INDUSTRY RESTRUCTURING AND COMPETITION

Electric Transmission and Energy Markets

Midwest ISO: On April 1, 2005, the Midwest ISO implemented a bid-based energy market (Midwest ISO Day 2). The Midwest ISO Day 2 rules require that all market participants submit day-ahead and/or real-time bids and offers for energy at locations across the Midwest ISO region. The Midwest ISO then calculates the most efficient solution for all the bids and offers made into the market that day. The

Midwest ISO is responsible for ensuring that load requirements in the region are met reliably and efficiently, and to manage congestion on the transmission system.

As part of the energy market, the Midwest ISO implemented a Locational Marginal Pricing (LMP) system, a market - based platform for valuing transmission congestion. The LMP system includes the ability to mitigate or eliminate congestion costs through the use of Financial Transmission Rights (FTRs). FTRs are allocated to market participants by the Midwest ISO. The first allocation of FTRs was completed for the period of April 1, 2005 through August 31, 2005. To date, our unhedged congestion charges have not been material. The FTR allocation process has been performed again for the period from September 1, 2005 to May 31, 2006. Wisconsin Electric and Edison Sault were granted substantially all of the FTRs that they were permitted to request during that allocation process.

To mitigate the risks of this new bid-based energy market, we requested deferral accounting treatment from the PSCW in January 2005 for certain incremental costs or benefits that may occur due to the implementation of Midwest ISO Day 2. Our request excluded LMP energy costs because these costs are subject to recovery under the Wisconsin Fuel Cost Adjustment Procedure. In March 2005, the PSCW accepted our request. We submitted another joint proposal with other utilities in March 2005, requesting escrow accounting treatment for Midwest ISO Day 2 costs until each utility's first rate case following April 1, 2008. The purpose of the March 2005 request for escrow accounting was to (1) provide a long-term solution for the costs associated with Midwest ISO Day 2 until there is more experience in the market and (2) provide clarification on costs not included in the March 2005 approval for deferral accounting treatment. For further information on the accounting for Midwest ISO transactions see Critical Accounting Estimates below.

Customer Issue: Our largest retail electric customer owns two iron ore mines located in the Upper Peninsula of Michigan. These mines represent approximately 7% of our annual electric utility energy sales and less than 1% of our consolidated net income. The mines have a special negotiated power-sales contract which expires in December 2007. The contract has price caps for roughly 80% of energy sales. The mines are billed at rates reflecting incremental costs and any amounts billed that are in excess of the price caps are refunded in the following year. We do not recognize as revenues the amounts that we expect to refund under the contract.

The incremental power costs in the Upper Peninsula of Michigan are now determined by the Midwest ISO. We began billing the mines the incremental power costs as quantified by Midwest ISO Day 2 in April 2005. The mines have notified us that they are disputing these billings and they have placed the disputed amounts in escrow pursuant to the contract terms. We are currently involved in discussions with the customer to resolve this dispute and other matters related to the contract.

Midwest ISO -- PJM Interconnection, L.L.C (PJM) Regional Transmission Charges: The FERC permits transmission owning utilities that have not joined a regional transmission organization (RTO) to propose a charge to recover revenues that would be lost as a result of RTO membership. These lost revenues result from FERC's requirement that, within an RTO and for transmission between the electric transmission systems operated by the Midwest ISO and PJM, entities that currently pay a transmission charge to move energy through or out of a neighboring transmission system will no longer pay this charge to the neighboring transmission system owner or operator upon the neighboring transmission system owner or operator joining an RTO.

The FERC has ordered the elimination of through and out transmission charges for transactions between the Midwest ISO and the PJM, an RTO adjacent to the Midwest ISO that manages the transmission system extending from Northern Illinois to the Mid-Atlantic States. In addition, FERC ordered a seams elimination charge to be paid by Midwest ISO load serving entities for the period beginning December 1, 2004 until March 31, 2006, to compensate transmission owners for the loss of revenues resulting from the joining of an RTO and/or FERC's elimination of through and out transmission charges

between the Midwest ISO and PJM. The FERC ordered that certain existing transmission transactions continue to pay for through and out service from December 1, 2004 until March 31, 2006. The details of the seams elimination charge and the quantification of the existing transaction charge are the subject of a hearing process initiated by FERC in a February 2005 order. A decision from the hearing process is expected in the second half of 2006. We are currently unable to determine the impacts on Wisconsin Electric and Edison Sault, however we do not anticipate material financial impacts.

ENVIRONMENTAL MATTERS

National Ambient Air Quality Standards: In 2004, the United States Environmental Protection Agency (EPA) began implementing theNational Ambient Air Quality Standards (NAAQS) for 8-hour ozone and fine particulate matter (PM_2.5) by designating nonattainment areas in the country. The states are currently developing rules to implement the new standards. Although specific emission control requirements are not yet defined, Wisconsin Electric believes that the revised standards will likely require significant reductions in SO₂ and NO_x emissions from coal-fired generating facilities. Reductions associated with the new fine particulate matter standards are expected to be implemented in stages after the year 2010 and extending to the year 2017.

Ozone Non-Attainment Standards: The 1-hour ozone nonattainment rules currently being implemented by the state of Wisconsin and ozone transport rules implemented by the state of Michigan limit NO_x emissions in phases over the next five years. Wisconsin Electric currently expects to incur total annual operation and maintenance costs of $1 to $2 million during the period 2004 through 2007 to comply with the Michigan and Wisconsin rules. In January 2000, the PSCW approved Wisconsin Electric's comprehensive plan to meet the Wisconsin regulations, permitting recovery in rates of NO_x emission reduction costs over an accelerated 10-year recovery period.

In April 2004, the EPA designated 10 counties in Southeastern Wisconsin as nonattainment areas for the 8-hour ozone NAAQS. States will be required to develop and submit State Implementation Plans to the EPA by June 2007 to demonstrate how they intend to comply with the 8-hour ozone NAAQS. We expect reductions needed to achieve compliance with the 8-hour ozone attainment standard will be implemented in stages from 2007 through 2010. Wisconsin Electric believes that compliance with the NO_x emission reductions requirements under the agreements with the WDNR and EPA will substantially mitigate costs to comply with the EPA's 8-hour ozone NAAQS. However, the timing of the requirements may be impacted by requiring earlier installation of NO_x controls at some units, depending on how the states implement the rules.

In December 2004, the EPA designated PM_2.5 nonattainment areas in the country. All counties in the state of Wisconsin were designated as attainment with the standard.

The EPA issued the final Clean Air Interstate Rule (CAIR) regulations 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. The proposed rules would require 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 states will develop implementation plans, and until those plans are in place, it is not possible to estimate the impact. However, Wisconsin Electric believes 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.

In our Form 10-K for the year ended December 31, 2004, we previously disclosed that we expected to incur approximately $600 million of capital costs over the 10 years ending 2013 to comply with the EPA consent decree. There could be additional costs of compliance with the EPA consent decree should

Wisconsin Electric elect to control rather than retire Units 5 and 6 at the Oak Creek Power Plant. We believe this additional cost may add approximately $150 million to $350 million to the estimate.

Mercury Emission Control Rulemaking: As required by the 1990 amendments to the Federal Clean Air Act, the EPA issued a regulatory determination in December 2000 that utility mercury emissions should be regulated. The EPA issued the final Clean Air Mercury Rule (CAMR) in March 2005. The compliance dates for the federal rule is 2010 for Phase I and 2018 for Phase II. Additional expenditures will be required to meet the first and second phases of the federal rules. Because the technology is under development, it is difficult to estimate the cost. The expenditures for Phase I are not likely to be significant. We believe the range of possible expenditures for Phase II could be approximately $50 million to $200 million.

The federal rule is being challenged by a number of states including Wisconsin. Depending on the litigation, the timing for compliance may be affected. The construction air permit issued for Elm Road Generating Station is not impacted by the new rules.

The WDNR independently developed mercury emission control rules that affect electric utilities in Wisconsin. The mercury control rules became effective in October 2004. The rules require emission reductions of 40% by 2010 and 75% by 2015. The rules explicitly recognize an underlying state statutory restriction that state regulations cannot be more stringent than those included in any federal program. The rules state that the WDNR must adopt state rule changes within 18 months of publication of any federal rules. State rules are to be changed to be consistent with, and no more restrictive than, any federal rules. Our compliance planning estimates show that no additional emission control investments are likely to be needed to meet the state mercury rules. This is because the challenged federal rules are very likely to be in place prior to the compliance dates contained in the state rule.

ACCOUNTING DEVELOPMENTS

New Pronouncements: In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based Payment (SFAS 123R), which amended SFAS 123, Accounting for Stock-Based Compensation. In March 2005, the SEC issued Staff Accounting Bulletin No. 107 (SAB 107) regarding the SEC's interpretation of SFAS 123R and the valuation of share-based payment for public companies. In April 2005, the SEC deferred the effective date of SFAS 123R to January 1, 2006. This statement requires that the compensation costs relating to such transactions be recognized in the consolidated income statement. We are currently evaluating the provisions of SFAS 123R and SAB 107, including the method of transition and expect to adopt SFAS123R on January 1, 2006. For further information, see Note 4 -- Common Equity in the Notes to Consolidated Condensed Financial Statements in Item 1 of Part I of this report.

In March 2005, the FASB issued FASB Interpretation 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), an interpretation of FASB Statement No. 143. FIN 47 defines the term conditional asset retirement obligation as used in Statement No. 143. As defined in FIN 47, a conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. We are currently evaluating FIN 47, but we do not expect an impact on the results of our regulated operations due to the regulatory treatment of asset retirement costs. FIN 47 will be effective for the fiscal year ending December 31, 2005.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections, a replacement of APB (Accounting Principles Board) Opinion No. 20 and SFAS No. 3. This statement requires a retrospective application of direct changes in accounting principle to prior periods' financial statements, unless it is impracticable to determine the period-specific or cumulative effects of the change.

Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. In addition, SFAS No. 154 instructs that a change in depreciation, amortization or depletion method for long-lived, non-financial assets must be recorded as a change in accounting estimate affected by a change in accounting principle. The effective date for this statement is January 1, 2006. We do not expect the adoption of SFAS No. 154 to have an impact on our consolidated financial position or results of operations.

CRITICAL ACCOUNTING ESTIMATES

Midwest ISO Bid-Based Energy Market: Effective April 1, 2005, the Midwest ISO implemented Midwest ISO Day 2, a bid-based energy market. The market requires that all market participants submit day-ahead and/or real-time bids and offers for energy at locations across the Midwest ISO region. Midwest ISO then calculates the most efficient solution for all the bids and offers made into the market that day and establishes a locational marginal price (LMP) which reflects the market price for energy. As a participant in the new Midwest ISO Day 2 market, we are required to follow Midwest ISO's instructions when dispatching generating units to support Midwest ISO's responsibility for maintaining stability of the transmission system. To the extent the established LMP price for energy is not sufficient to recover the cost of running a generating unit dispatched at Midwest ISO's request, the tariff provides a mechanism for us to recover the deficiency (the "make-whole payment"). Since the start of Midwest ISO Day 2, the Midwest ISO has significantly increased the amount of generation provided by our higher cost Combustion Turbines. We have recorded a receivable from the Midwest ISO for the make-whole payments associated with this operation. A reserve has been established for a portion of these receivables that are currently in dispute. Additionally, Midwest ISO Day 2 subjects us to additional costs primarily associated with constraints in the transmission system. As allowed by the PSCW, we have deferred these costs for consideration in future rate proceedings.

For a full discussion of Critical Accounting Estimates see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Factors Affecting Results, Liquidity and Capital Resources -- Critical Accounting Estimates in Wisconsin Energy's 2004 Annual Report on Form 10-K filed with the SEC.

CAUTIONARY FACTORS

This report and other documents or oral presentations contain or may contain forward-looking statements made by or on behalf of Wisconsin Energy. 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 the forward-looking statements. When used in written documents or oral presentations, the terms "anticipates," "believes," "estimates," "expects," "forecasts," "intends," "may," "objectives," "plans," "possible," "potential," "projects" and similar expressions are intended to identify 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 fin ancial 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,

41

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 United States Nuclear Regulatory Commission's regulations related to Point Beach Nuclear Plant or a permanent repository for used nuclear fuel; changes in the regulations of the United States Environmental Protection Agency as well as the Wisconsin or Michigan Departments of Natural Resources, including but not limited to regulations relating to the release of emissions from fossil-fueled power plants such as carbon di oxide, sulfur dioxide, nitrogen oxide, small particulates or mercury; 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 Wisconsin Department of Natural Resources related to the siting approval process for new pipeline construction.

Unexpected difficulties or unanticipated effects of the qualified five-year electric and gas rate freeze ordered by the Public Service Commission of Wisconsin as a condition of approval of the WICOR merger in 2000.

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.

Unanticipated operational and/or financial consequences related to implementation of the Midwest Independent Transmission System Operator, Inc. bid-based energy market that started in April 2005, the associated outcome of our request of the Public Service Commission of Wisconsin to escrow potential future rate recovery for the incremental costs or benefits resulting from this new energy market, and the ultimate determination by the Federal Energy Regulatory Commission on the details of the seams elimination charges.

Consolidation of the industry as a result of the combination and acquisition of utilities in the Midwest, nationally and globally.

Factors which impede execution of ourPower the Future 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 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.

Authoritative generally accepted accounting principle or policy changes from such standard setting bodies as the Financial Accounting Standards Board, the Securities and Exchange Commission 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; risks associated with minority investments, where there is a limited ability to control the development, management or operation of the project; and the risk of higher interest costs associated with potentially reduced securities ratings by independent rating agencies as a result of these and other factors.

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

Other business or investment considerations that may be disclosed from time to time in our Securities and Exchange Commission filings or in other publicly disseminated written documents.

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

*****

For certain other information which may impact our future financial condition or results of operations, see Item 1, Financial Statements -- Notes to Consolidated Condensed Financial Statements, in Part I of this report as well as Item 1, Legal Proceedings, in Part II of this report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For information concerning market risk exposures at Wisconsin Energy Corporation, see Item 2, 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 I of this report and in Part I of Wisconsin Energy's Quarterly Report on Form 10-Q for the period ended March 31, 2005. For information concerning other market risk exposures, 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 Wisconsin Energy's 2004 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 (Exchange Act)) as of the end of the period covered by this report. Based on 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 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.

Internal Control Over Financial Reporting: On April 1, 2005, the Midwest ISO Day 2 bid-based energy market became effective which impacted our regulated electric generation operations and purchased power. In connection with the implementation of Midwest ISO Day 2, we have implemented a new software system and modified existing processes to facilitate participation in, and validate resultant settlements from the Midwest ISO market. Apart from this change, there have not been any other changes 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 have materially affected, or are 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 2004 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, 2005.

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.

ENVIRONMENTAL MATTERS

EPA Information Requests: Wisconsin Electric and Wisconsin Gas responded to an EPA request for information pursuant to Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) Section 104(e) for the Solvay Coke and Gas Site located in Milwaukee, Wisconsin. All potentially responsive records and corporate legal files have been reviewed and responsive information was provided in October 2004. A predecessor company of Wisconsin Electric owned a parcel of property that is within the property boundaries of the site. A predecessor company of Wisconsin Gas had a customer and corporate relationship with the entity that owned and operated the site, Milwaukee Solvay Coke Company. In July 2005, Wisconsin Gas received a general notice letter from the EPA identifying Wisconsin Gas as a potentially responsible party under CERCLA. Wisconsin Electric has not been

named as a potentially responsible party at this time. We responded to the EPA in July 2005, stating that Wisconsin Gas will participate in negotiations regarding the site, but that Wisconsin Gas does not admit to any liability for the site. Although neither company has accepted responsibility for costs of any sort related to the property, remediation cost estimates and reserves continue to be included in the estimated manufactured gas plant obligations as were reported in the December 31, 2004 Form 10-K Note S -- Commitments and Contingencies.

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 and -- Nuclear 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 and for information concerning nuclear operations at Wisconsin Electric's Point Beach Nuclear Plant.

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 recent PSCW and other actions related to ourPower the Futurestrategy.

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.

On February 26, 2004, a Wisconsin jury awarded $850,000 to a dairy farmer who alleged that Wisconsin Electric's distribution system caused damages to his livestock. Wisconsin Electric has filed an appeal in this decision. In May 2005, a stray voltage lawsuit was filed against Wisconsin Electric. We do not believe the lawsuit has merit and we will vigorously defend the case. The claims made against Wisconsin Electric in these cases are not expected to have a material adverse effect on our financial statements.

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.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS [AND ISSUER PURCHASES OF EQUITY SECURITIES]

ISSUER PURCHASES OF EQUITY SECURITIES

2005	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	1,789	(b)	$ -	-	$ -

May 1- May 31	-		$ -	-	$ -

June 1- June 30	-		$ -	-	$ -

Total	1,789		$ -

(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.
(b)	These shares were surrendered in April 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 2005 Annual Meeting of Stockholders held on May 5, 2005, stockholders voted on the following items with the following results:

Item 1 -- Election of Nine Directors for Terms Expiring in 2006: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	99,147,383	98.23%	1,787,457	1.77%
John F. Bergstrom	98,581,316	97.67%	2,353,524	2.33%
Barbara L. Bowles	99,875,861	98.95%	1,058,979	1.05%
Robert A. Cornog	99,199,156	98.28%	1,735,684	1.72%
Curt S. Culver	99,925,169	99.00%	1,009,671	1.00%
Gale E. Klappa	99,213,181	98.29%	1,721,659	1.71%
Ulice Payne, Jr.	99,735,704	98.81%	1,199,136	1.19%
Frederick P. Stratton, Jr.	98,999,415	98.08%	1,935,425	1.92%
George E. Wardeberg	99,137,565	98.22%	1,797,275	1.78%

Item 2 --Ratification of Deloitte & Touche LLP as independent auditors for 2005: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, 2005, 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 and Touche LLP as independent auditors for fiscal year 2005 by the following vote:

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

99,693,097	98.77%	670,126	0.66%	571,617	0.57%

Of 116,985,602 voting shares outstanding as of the February 25, 2005 record date for the annual meeting, 100,934,840 shares (approximately 86.28% of the shares outstanding) were represented at the meeting.

Further information concerning these matters is contained in our Proxy Statement dated March 18, 2005 with respect to the 2005 Annual Meeting of Stockholders.

ITEM 6. EXHIBITS

Exhibit No.


3	Articles of Incorporation and By-laws

3.1	Bylaws of Wisconsin Energy Corporation, as amended to May 5, 2005 (effective as of May 5, 2005). (Exhibit 3.2(b) to Wisconsin Energy Corporation's 12/31/2004 Form 10-K.)

10	Material Contracts

10.1	First Amendment to Membership Interests Purchase Agreement between CET Two, LLC and TPF Calumet, LLC, dated as of May 31, 2005.

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 2, 2005	Stephen P. Dickson, Controller, Principal Accounting Officer and duly authorized officer

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Avg

WEC Energy (WEC) 10-Q2005 Q2 Quarterly report

Content analysis