WEC Energy (WEC) 8-K Results of Operations and Financial Condition

								Exhibit 99.1
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
	WISCONSIN ENERGY CORPORATION
	CONSOLIDATED INCOME STATEMENTS
	Year Ended December 31
			2004		2003		2002
			(Millions of Dollars, Except Per Share Amounts)
	Total Operating Revenues		$	3,431.1	$	3,308.3	$	3,051.0
	Operating Expenses
		Fuel and purchased power		592.9		570.8		594.1
		Cost of gas sold		890.9		863.3		574.9
		Other operation and maintenance		1,002.7		934.2		933.8
		Depreciation, decommissioning and amortization		327.1		329.8		318.5
		Property and revenue taxes		87.3		82.4		87.8
		Asset valuation charges, net		150.4		45.6		141.5
	Total Operating Expenses			3,051.3		2,826.1		2,650.6
	Operating Income			379.8		482.2		400.4
	Other Income and Deductions, Net			16.1		42.2		43.7
	Interest Expense			193.4		213.8		227.1
	Income from Continuing
		Operations Before Income Taxes		202.5		310.6		217.0
	Income Taxes			80.3		110.2		85.3
	Income from Continuing Operations			122.2		200.4		131.7
	Income from Discontinued
		Operations, Net of Tax		184.2		43.9		35.3
	Net Income		$	306.4	$	244.3	$	167.0
	Earnings Per Share (Basic)
		Continuing Operations	$	1.04	$	1.71	$	1.14
		Discontinued Operations	$	1.56	$	0.38	$	0.31
	Total Earnings Per Share (Basic)		$	2.60	$	2.09	$	1.45
	Earnings Per Share (Diluted)
		Continuing Operations	$	1.03	$	1.69	$	1.13
		Discontinued Operations	$	1.54	$	0.37	$	0.31
	Total Earnings Per Share (Diluted)		$	2.57	$	2.06	$	1.44
	Weighted Average Common Shares Outstanding (Millions)
		Basic		117.7		117.1		115.4
		Diluted		119.1		118.4		116.3
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

1

WISCONSIN ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31
ASSETS
			2004	2003
			(Millions of Dollars)
Property, Plant and Equipment
	In service		$8,238.4	$8,342.4
	Accumulated depreciation		(3,121.6)	(3,021.3)
			5,116.8	5,321.1
	Construction work in progress		602.4	296.2
	Leased facilities, net		98.9	104.6
	Nuclear fuel, net		85.0	78.4
Net Property, Plant and Equipment			5,903.1	5,800.3
Investments
	Nuclear decommissioning trust fund		737.8	674.4
	Equity investment in transmission affiliate		187.8	154.4
	Other		99.5	122.5
Total Investments			1,025.1	951.3
Current Assets
	Cash and cash equivalents		35.6	28.1
	Accounts receivable, net of allowance for
		doubtful accounts of $40.1 and $51.1	349.3	333.7
	Accrued revenues		245.1	212.2
	Materials, supplies and inventories		409.5	385.6
	Deferred income taxes - current		4.9	56.5
	Prepayments and other		132.1	111.7
	Assets held for sale		-	938.0
Total Current Assets			1,176.5	2,065.8
Deferred Charges and Other Assets
	Regulatory assets		849.4	612.3
	Goodwill, net		441.9	441.9
	Other		169.4	142.9
Total Deferred Charges and Other Assets			1,460.7	1,197.1
Total Assets			$9,565.4	$10,014.5
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

2

WISCONSIN ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31
CAPITALIZATION AND LIABILITIES
		2004	2003
		(Millions of Dollars)
Capitalization
	Common equity	$2,492.4	$2,358.7
	Preferred stock of subsidiary	30.4	30.4
	Long-term debt	3,239.5	3,570.5
Total Capitalization		5,762.3	5,959.6
Current Liabilities
	Long-term debt due currently	101.0	166.2
	Short-term debt	338.0	590.8
	Accounts payable	309.7	248.7
	Payroll and vacation accrued	74.3	67.3
	Taxes accrued - income and other	12.1	23.0
	Interest accrued	28.1	35.8
	Other	129.2	80.2
	Liabilities held for sale	-	251.7
Total Current Liabilities		992.4	1,463.7
Deferred Credits and Other Liabilities
	Regulatory liabilities	922.4	887.7
	Asset retirement obligations	762.2	732.0
	Deferred income taxes - long-term	530.4	570.8
	Accumulated deferred investment tax credits	61.0	66.0
	Minimum pension liability	152.8	34.7
	Other long - term liabilities	381.9	300.0
Total Deferred Credits and Other Liabilities		2,810.7	2,591.2
Commitments and Contingencies (Note S)		-	-
Total Capitalization and Liabilities		$9,565.4	$10,014.5
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

3

WISCONSIN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31
				2004	2003	2002
				(Millions of Dollars)
Operating Activities
	Net income			$306.4	$244.3	$167.0
	Income from discontinued operations, net of tax			(184.2)	(43.9)	(35.3)
	Reconciliation to cash
		Depreciation, decommissioning and amortization		360.2	360.3	337.9
		Nuclear fuel expense amortization		24.0	25.3	27.3
		Equity in earnings of unconsolidated affiliates		(30.9)	(22.2)	(22.9)
		Distribution from unconsolidated affiliates		44.7	32.9	23.1
		Asset valuation charges, net		150.4	45.6	141.5
		Deferred income taxes and investment tax credits, net		6.5	64.5	(32.4)
		Accrued income taxes, net		(8.5)	(30.1)	27.4
		Change in -	Accounts receivable and accrued revenues	(48.5)	9.1	(66.3)
			Other accounts receivable	-	-	116.4
			Inventories	(23.9)	(72.3)	14.4
			Other current assets	(20.5)	(23.1)	5.6
			Accounts payable	39.3	(27.9)	10.0
			Other current liabilities	23.2	12.7	(2.8)
		Other		(39.5)	(45.3)	(50.0)
Cash Provided by Operating Activities				598.7	529.9	660.9
Investing Activities
	Capital expenditures			(636.8)	(649.0)	(541.8)
	Acquisitions and investments			(26.4)	(7.6)	(39.7)
	Proceeds from asset sales			899.6	55.3	310.0
	Nuclear fuel			(30.0)	(38.3)	(20.7)
	Nuclear decommissioning funding			(17.6)	(17.6)	(17.6)
	Cash from/(to) Discontinued Operations			32.4	61.2	(31.6)
	Other			21.9	(0.2)	(41.1)
Cash (Used in) Provided by Investing Activities				243.1	(596.2)	(382.5)
Financing Activities
	Issuance of common stock and exercise of stock options			70.9	62.9	52.6
	Repurchase of common stock			(152.7)	(6.8)	(52.3)
	Dividends paid on common stock			(97.8)	(93.7)	(92.4)
	Issuance of long-term debt			397.0	984.7	12.0
	Retirement and redemption of long-term debt			(798.4)	(526.2)	(450.1)
	Change in short-term debt			(252.8)	(337.8)	247.9
	Other			(0.5)	(23.7)	-
Cash (Used in) Provided by Financing Activities				(834.3)	59.4	(282.3)
Change in Cash and Cash Equivalents from Continuing Operations				7.5	(6.9)	(3.9)
Cash and Cash Equivalents at Beginning of Year				28.1	35.0	38.9
Cash and Cash Equivalents at End of Year				$35.6	$28.1	$35.0
Supplemental Information - Cash Paid For
	Interest (net of amount capitalized)			$232.2	$220.9	$233.6
	Income taxes (net of refunds)			$80.5	$92.2	$89.8
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

4

WISCONSIN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31
						2004	2003
						(Millions of Dollars)
Common Equity (See Consolidated Statements of Common Equity)
	Common stock - $.01 par value; authorized 325,000,000 shares;
		outstanding - 116,985,822 and 118,425,546 shares				$1.2	$1.2
	Other paid in capital					785.1	841.8
	Retained earnings					1,718.7	1,510.1
	Accumulated other comprehensive income (loss)					(7.4)	3.1
	Unearned compensation - restricted stock awards					(7.6)	(4.7)
	Stock options exercisable					2.4	7.2
Total Common Equity						2,492.4	2,358.7
Preferred Stock
	Wisconsin Energy
		$.01 par value; authorized 15,000,000 shares; none outstanding				-	-
	Wisconsin Electric
		Six Per Cent. Preferred Stock - $100 par value;
			authorized 45,000 shares; outstanding - 44,498 shares			4.4	4.4
		Serial preferred stock -
			$100 par value; authorized 2,286,500 shares; 3.60% Series
				redeemable at $101 per share; outstanding - 260,000 shares		26.0	26.0
			$25 par value; authorized 5,000,000 shares; none outstanding			-	-
	Wisconsin Gas
			$.01 par value; authorized - zero and 3,000,000 shares; none outstanding			-	-
Total Preferred Stock						30.4	30.4
Long-Term Debt
	First mortgage bonds
					7-1/4% due 2004	-	140.0
	Debentures (unsecured)
					6-5/8% due 2006	200.0	200.0
					9.47% due 2006	1.4	2.1
					3.50% due 2007	250.0	-
					4.50% due 2013	300.0	300.0
					6.60% due 2013	45.0	45.0
					5.20% due 2015	125.0	125.0
					6-1/2% due 2028	150.0	150.0
					5.625% due 2033	335.0	335.0
					6-7/8% due 2095	100.0	100.0
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

5

WISCONSIN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CAPITALIZATION - (Cont'd)
December 31
				2004	2003
				(Millions of Dollars)
Long-Term Debt - (Cont'd)
	Notes (secured, nonrecourse)
			3.79% variable rate due 2005 (a)	$6.5	$6.8
			6.36% effective rate due 2006	2.2	3.3
			6.90% due 2006	1.1	1.1
			2% stated rate due 2011	1.3	1.3
			4.81% effective rate due 2030	2.0	2.0
			2.67% variable rate due 2028 (a)	15.6	16.0
	Notes (unsecured)
			6-3/8% due 2005	65.0	65.0
			6.85% due 2005	10.0	10.0
			2.10% variable rate due 2006 (a)	1.0	1.0
			5.875% due 2006	250.0	550.0
			6.36% effective rate due 2006	2.4	3.6
			7.00% to 8.00% due 2001-2008	2.1	2.3
			5.50% due 2008	300.0	300.0
			6.21% due 2008	20.0	20.0
			6.48% due 2008	25.4	25.4
			5-1/2% due 2009	50.0	50.0
			6.50% due 2011	450.0	450.0
			6.51% due 2013	30.0	30.0
			2.10% variable rate due 2015 (a)	17.4	17.4
			1.25% variable rate due 2016 (b)	-	67.0
			1.65% variable rate due 2016 (a)	67.0	-
			6.94% due 2028	50.0	50.0
			1.52% variable rate due 2030 (b)	-	80.0
			1.70% variable rate due 2030 (a)	80.0	-
			6.20% due 2033	200.0	200.0
	Junior subordinated debentures (unsecured)
			6.85% due 2039 (see Note J)	-	206.2
	Obligations under capital leases			212.9	213.2
	Unamortized discount, net and other			(27.8)	(32.0)
	Long-term debt due currently			(101.0)	(166.2)
Total Long-Term Debt				3,239.5	3,570.5
Total Capitalization				$5,762.3	$5,959.6
(a)		Variable interest rate as of December 31, 2004.
(b)		Variable interest rate as of December 31, 2003.
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

6

WISCONSIN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMMON EQUITY
							Accumulated
							Other		Stock
				Common	Other Paid	Retained	Comprehensive	Unearned	Options
				Stock	In Capital	Earnings	Income (Loss)	Compensation	Exercisable	Total
				(Millions of Dollars)
Balance - December 31, 2001				$1.2	$763.8	$1,284.9	($10.8)	($4.2)	$21.2	$2,056.1
	Net Income					167.0				167.0
	Other comprehensive income
		Foreign currency translation					3.0			3.0
		Minimum pension liability					(0.8)			(0.8)
		Hedging, net					1.1			1.1
			Comprehensive income	-	-	167.0	3.3	-	-	170.3
	Common stock cash
		dividends $0.80 per share				(92.4)				(92.4)
	Common stock issued				52.6					52.6
	Repurchase of common stock				(52.3)					(52.3)
	Amortization and forfeiture
		of restricted stock			(0.2)			0.9		0.7
	Stock options exercised				10.2				(10.2)	-
	Tax benefit of stock options exercised				4.5					4.5
	Other				(0.1)					(0.1)
Balance - December 31, 2002				$1.2	$778.5	$1,359.5	($7.5)	($3.3)	$11.0	$2,139.4
	Net Income					244.3				244.3
	Other comprehensive income
		Foreign currency translation					7.8			7.8
		Minimum pension liability					1.3			1.3
		Hedging, net					1.5			1.5
			Comprehensive income	-	-	244.3	10.6	-	-	254.9
	Common stock cash
		dividends $0.80 per share				(93.7)				(93.7)
	Common stock issued				62.9					62.9
	Repurchase of common stock				(6.8)					(6.8)
	Restricted stock awards							(2.8)		(2.8)
	Amortization and forfeiture
		of restricted stock			(0.3)			1.4		1.1
	Stock options exercised				3.8				(3.8)	-
	Tax benefit of stock options exercised				5.0					5.0
	Other				(1.3)					(1.3)
Balance - December 31, 2003				$1.2	$841.8	$1,510.1	$3.1	($4.7)	$7.2	$2,358.7
	Net Income					$306.4				306.4
	Other comprehensive income
		Foreign currency translation					(8.6)			(8.6)
		Minimum pension liability					(3.7)			(3.7)
		Hedging, net					1.8			1.8
			Comprehensive income	-	-	306.4	(10.5)	-	-	295.9
	Common stock cash
		dividends $0.83 per share				(97.8)				(97.8)
	Common stock issued				70.9					70.9
	Repurchase of common stock				(152.7)					(152.7)
	Restricted stock awards							(0.6)		(0.6)
	Performance option awards				5.9			(5.9)		-
	Amortization and forfeiture
		of restricted stock			(0.9)			3.6		2.7
	Stock options exercised				4.8				(4.8)	-
	Tax benefit of stock options exercised				15.3					15.3
Balance - December 31, 2004				$1.2	$785.1	$1,718.7	($7.4)	($7.6)	$2.4	$2,492.4
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.

7

WISCONSIN ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General:   Our consolidated financial statements include the accounts of Wisconsin Energy Corporation (Wisconsin Energy, the Company, our, we or us), a diversified holding company, as well as our principal subsidiaries in the following operating segments:

• Utility Energy Segment -- Consisting of Wisconsin Electric Power Company (Wisconsin Electric), Wisconsin Gas LLC (Wisconsin Gas) and Edison Sault Electric Company (Edison Sault); engaged primarily in the generation of electricity and the distribution of electricity and natural gas; and

• Non-Utility Energy Segment -- Consisting primarily of W.E. Power, LLC (We Power); engaged principally in the design, development, construction and ownership of electric power generating facilities for long term lease to Wisconsin Electric, and Wisvest Corporation (Wisvest).

Our other non-utility subsidiaries include primarily Minergy Corp., which develops and markets renewable energy and recycling technologies, and Wispark LLC (Wispark), which develops and invests in real estate. We have eliminated all significant intercompany transactions and balances from the consolidated financial statements.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Reclassifications:   We have reclassifiedcertain prior year financial statement amounts to conform to their current year presentation. These reclassifications had no effect on net income or earnings per share.

The most significant reclassifications relate to the reporting of discontinued operations pursuant to Statement of Financial Accounting Standards (SFAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Effective July 31, 2004, we sold our manufacturing business. This segment is now classified as a discontinued operation. The footnotes contained herein have been restated to reflect continuing operations for all periods presented. For further information see Note E - Asset Sales, Divestitures and Discontinued Operations.

Revenues:   We recognize energy revenues on the accrual basis and include estimated amounts for service rendered but not billed.

Wisconsin Electric's rates include base amounts for estimated fuel and purchased power costs. We can request recovery of fuel and purchased power costs prospectively from retail electric customers in the Wisconsin jurisdiction through our rate review process with the Public Service Commission of Wisconsin (PSCW) and in interim fuel cost hearings when such annualized costs are expected to be more than 3% higher than the forecasted costs used to establish rates.

Wisconsin Electric's and Wisconsin Gas' retail gas rates include monthly adjustments which permit the recovery or refund of actual purchased gas costs. We defer any difference between actual gas costs incurred (adjusted for a sharing mechanism) and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year and any residual balance at the annual October 31 reconciliation date is subsequently refunded to or recovered from customers.

Other Income and Deductions, Net:   We had the following other income and deductions for the years ended December 31:

8

Other Income and Deductions, Net	2004	2003	2002
	(Millions of Dollars)
Equity in Earnings of Unconsolidated Affiliates	$30.9	$22.2	$22.9
Carrying Costs on Deferred Assets	12.4	9.3	6.1
Debt Redemption Costs	(22.9)	-	-
Gain on Derivative Contracts (See Note M)	-	-	21.1
Other, net	(4.3)	10.7	(6.4)
Total Other Income and Deductions	$16.1	$42.2	$43.7

Property and Depreciation:   We record utilityproperty, plant and equipment at cost. Cost includes material, labor, overheads and allowance for funds used during construction. Additions to and significant replacements of property are charged to property, plant and equipment at cost; minor items are charged to maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.

We had the following property in service by segment at December 31:

Property In Service	2004	2003
	(Millions of Dollars)
Utility Energy	$7,986.3	$7,890.4
Non-Utility Energy	57.7	179.8
Other	194.4	272.2
Total	$8,238.4	$8,342.4

Our regulated utilities collect in their rates future removal costs for many assets that do not have an associated legal asset retirement obligation. We record a regulatory liability on our balance sheet for the estimated amounts we have collected in rates for future removal costs less amounts we have spent in removal activities. This regulatory liability was $599.3 million as of December 31, 2004 and $571.1 million as of December 31, 2003.

Estimated useful lives for non-regulated assets are 3 to 28 years for equipment, 2 to 5 years for software and 30 to 40 years for buildings.

For assets other than our regulated assets, we accrue depreciation expense at straight-line rates over the estimated useful lives of the assets.

We include capitalized software costs associated with our utility energy segment under the caption "Property, Plant and Equipment" on the Consolidated Balance Sheets. As of December 31, 2004 and 2003, the net book value of regulated capitalized software totaled $28.8 million and $36.0 million, respectively. The net book value of other capitalized software was approximately $2.6 million and $2.2 million as of December 31, 2004 and 2003, respectively.

Our utility depreciation rates are certified by the state regulatory commissions and include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 4.2% in 2004, 4.2% in 2003, and 4.5% in 2002. Nuclear plant decommissioning costs are accrued and included in depreciation expense (see Note H).

We record other property, plant and equipment at cost. Cost includes material, labor, overheads and capitalized interest. We charge additions to and significant replacements of property to property, plant and equipment at cost and we charge minor items to maintenance expense.

We had the following Construction Work in Progress (CWIP) by segment at December 31:

9

	2004	2003
	(Millions of Dollars)
Utility Energy	$160.8	$76.2
Non-Utility Energy	432.6	219.8
Other	9.0	0.2
Total	$602.4	$296.2

Allowance For Funds Used During Construction - Regulated:   Allowance for funds used during construction (AFUDC) is included in utility plant accounts and represents the cost of borrowed funds (AFUDC - debt) used during plant construction and a return on stockholders' capital (AFUDC - equity) used for construction purposes. AFUDC - debt is recorded as a reduction of interest expense and AFUDC - equity is recorded in Other Income and Deductions, Net.

As approved by the PSCW, Wisconsin Electric capitalized AFUDC - debt and equity at 10.18% during the periods reported.

In a rate order dated August 30, 2000, the PSCW authorized Wisconsin Electric to accrue AFUDC on all electric utility nitrogen oxide (NOx) remediation construction work in progress at a rate of 10.18%, and provided a full current return on electric safety and reliability construction work in progress so that no AFUDC accrual is required on these projects. In addition, the August 2000 PSCW order provided a current return on half of other utility construction work in progress and authorized AFUDC accruals on the remaining 50% of these projects.

As approved by the PSCW, Wisconsin Gas is allowed to accrue AFUDC on specific large construction projects at a rate of 10.32%.

Our regulated segment recorded the following AFUDC for the years ended December 31:

	2004	2003	2002
	(Millions of Dollars)
AFUDC - Debt	$1.5	$2.9	$2.3
AFUDC - Equity	$2.8	$5.1	$4.3

Capitalized Interest and Carrying Costs - Non-Regulated Energy:   As part of the construction of our power plants under thePower the Future program, we capitalize interest during construction in accordance with SFAS No. 34, Capitalization of Interest Cost. We will amortize capitalized interest over the life of the power plants. For the years ended December 31, 2004 and 2003, we capitalized $17.9 million and $6.5 million of interest costs, at an average rate of 6.1% and 5.7%.

Under the lease agreements associated with ourPower the Future power plants, we are able to collect from utility customers the carrying costs associated with the construction of our power plants. We defer these carrying costs on our balance sheet and they will be amortized to revenue over the individual lease term. For the years ended December 31, 2004 and 2003, we have deferred $38.2 million and $17.1 million of carrying costs related to thePower the Future power plants.

Earnings Per Common Share:   We compute basic earnings per common share by dividing net earnings by the weighted average number of common shares outstanding. Diluted earnings per share is less than basic earnings per share due to the dilutive effects of stock options.

10

Materials, Supplies and Inventories:   Our inventory at December 31 consists of:

Materials,
Supplies and Inventories	2004	2003
	(Millions of Dollars)
Fossil Fuel	$90.0	$108.0
Natural Gas in Storage	226.7	184.4
Materials and Supplies	92.8	93.2
Total	$409.5	$385.6

We price substantially all fossil fuel, materials and supplies and natural gas in storage inventories using the weighted-average method of accounting.

Regulatory Accounting:   Our utility energy segment accounts for its regulated operations in accordance with SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. This statement sets forth the application of generally accepted accounting principles to those companies whose rates are determined by an independent third-party regulator. The economic effects of regulation can result in regulated companies recording costs that have been or are expected to be allowed in the rate making process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses in the periods when those same amounts are reflected in rates. We defer all of our regulatory assets pursuant to specific orders or by a generic order issued by our primary regulator. We expect to recover our outstanding regulatory as sets in rates over a period of no longer than 20 years. As of December 31, 2004, we had approximately $62.0 million of regulatory assets that were not earning a return. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities). For further information, see Note C.

Derivative Financial Instruments:   We have derivative physical and financial instruments as defined by SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. However, our use of financial instruments is limited. For further information, see Note M.

Cash and Cash Equivalents:   Cash and cash equivalents include marketable debt securities acquired three months or less from maturity.

Asset Retirement Obligations:   We adopted SFAS 143, Accounting for Asset Retirement Obligations, effective January 1, 2003. Consistent with SFAS 143, we record a liability at fair value for a legal asset retirement obligation in the period in which it is incurred. When a new legal obligation is recorded, we capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. We accrete the liability to its present value each period and depreciate the capitalized cost over the useful life of the related asset. At the end of the asset's useful life, we settle the obligation for its recorded amount or incur a gain or loss. As it relates to our regulated operations, we apply SFAS 71 and recognize regulatory assets or liabilities for the timing differences between when we recover legal asset retirement obligations in rates and when we would recognize these costs under SFAS 143. For further information see Note L.

Goodwill and Intangible Assets:   We account for goodwill and other intangible assets following SFAS 142, Goodwill and Other Intangible Assets, effective January 1, 2002. As of December 31, 2004 and 2003, we had recorded $441.9 million of goodwill related to our Utility Energy Segment. As of December 31, 2003, we had recorded $394.0 million of goodwill related to our Manufacturing Segment in Assets Held for Sale.

Under SFAS 142, goodwill and other intangibles with indefinite lives are not subject to amortization. However, goodwill and other intangibles are subject to fair value-based rules for measuring impairment, and resulting write-downs, if any, are to be reflected in operating expense. We assess the fair value of our SFAS 142 reporting unit by considering future discounted cash flows, a comparison of fair value based on public company trading multiples, and merger and acquisition transaction multiples for similar companies. This evaluation utilizes the information available under the circumstances, including reasonable and supportable assumptions and projections. We perform our annual impairment test for the reporting unit as of August 31. There was no impairment to the recorded goodwill balance as of our annual 2004 impairment test date for our reporting unit.

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Impairment or Disposal of Long Lived Assets:   We carry property, equipment and goodwill related to businesses held for sale at the lower of cost or estimated fair value less costs to sell. As of December 31, 2004, we had no assets classified as Held for Sale. The manufacturing segment had been reclassified as Held for Sale at December 31, 2003. Consistent with SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that their carrying value may not be recoverable from the use and eventual disposition of the asset based on the remaining useful life. For further information, see Note F.

Investments:   We account for investments in other affiliated companies in which we do not maintain control using the equity method. As of December 31, 2004 and 2003, we had a total ownership interest of approximately 37.8% and 39.4%, in American Transmission Company (ATC). We are represented by one out of ten ATC board members, each of whom has one vote. Due to the voting requirements, no individual member has more than 10% of the voting control. We account for our investment in ATC under the equity method.

Income Taxes:   We follow the liability method in accounting for income taxes as prescribed by SFAS No. 109, Accounting for Income Taxes (SFAS 109). SFAS 109 requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. Tax credits associated with regulated operations are deferred and amortized over the life of the assets. We file a consolidated Federal income tax return. Accordingly, we allocate Federal current tax expense benefits and credits to our subsidiaries based on their separate tax computations. For further information, see Note G.

Stock Options:   We account for stock options under Accounting Principles Board Opinion 25, Accounting for Stock Issued to Employees (APB 25) and adopted the disclosure provisions of SFAS No. 123, Accounting for Stock-Based Compensation, as amended by SFAS 148, Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of SFAS 123 (See Notes B and I).

Nuclear Fuel Amortization:   We amortize our nuclear fuel inventory to fuel expense as the power is generated, generally over a period of 60 months.

B -- RECENT ACCOUNTING PRONOUNCEMENTS

Share Based Compensation:   In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123 (revised 2004), Share-Based Payment (SFAS 123R), which amended SFAS 123, Accounting for Stock-Based Compensation. This statement supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. SFAS 123R addresses the accounting for share-based payment transactions with employees and other third parties, eliminates the ability to account for share-based compensation transactions using APB 25 and 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 expect to adopt it on July 1, 2005. We have not yet determined the method of transition. See Note I for information regarding the pro forma impact of this statement.

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C -- REGULATORY ASSETS AND LIABILITIES

Our regulatory assets and liabilities at December 31 consist of:

Regulatory Assets	2004	2003
	(Millions of Dollars)
Unrecognized pension costs (See Note O)	$342.8	$189.4
Deferred electric transmission costs	109.6	73.3
Deferred income tax related	99.9	133.0
Plant related -- capital lease (See Note J)	61.1	54.5
Environmental costs	58.0	55.6
Unrecovered plant costs	45.9	9.0
Bad debt costs	41.7	21.5
Other, net	90.4	76.0
Total Regulatory Assets	$849.4	$612.3

Regulatory Liabilities	2004	2003
	(Millions of Dollars)
Cost of removal obligations (See Notes H and L)	$599.3	$571.1
Deferred pension - income	116.9	128.3
Income tax related	109.4	126.8
Other, net	96.8	61.5
Total Deferred Regulatory Liabilities	$922.4	$887.7

We record a minimum pension liability to reflect the funded status of our pension plans (see Note O). We have concluded that substantially all of the unrecognized pension costs resulting from the recognition of our minimum pension liability that relate to our utility energy segment qualify as a regulatory asset.

Our regulated subsidiaries record deferred regulatory assets and liabilities representing the future expected impact of deferred taxes on utility revenues (see Note A).

In October 2002, the PSCW issued an order authorizing Wisconsin Electric to implement a surcharge for recovery of annual electric transmission costs projected through 2005. In addition, the PSCW order authorized escrow accounting treatment for transmission costs. The difference between actual incremental transmission costs incurred and the amount being recovered is charged to the escrow account. We have deferred a total of $109.6 million of electric transmission costs as a regulatory asset through December 31, 2004.

Consistent with a generic order from and past rate-making practices of the PSCW, we defer as a regulatory asset costs associated with the remediation of former manufactured gas plant sites. As of December 31, 2004, we have recorded $58.0 million of environmental costs associated with manufactured gas plant sites as a regulatory asset, including $31.4 million of deferrals for actual remediation costs incurred and a $26.6 million accrual for estimated future site remediation (See Note S). In addition, we have deferred $16.7 million of insurance recoveries associated with the environmental costs as regulatory liabilities. We expect to include total actual remediation costs incurred net of the related insurance recoveries in our next rate case at which time we would begin amortizing these costs over the following five years.

As part of ourPower the Future initiative, the PSCW approved the retirement and removal of the Port Washington Power Plant coal units to make way for construction of gas fired facilities. In a September 27, 2003 order, the Commission authorized transferring the undepreciated costs and related removal amounts to a regulatory asset account. This deferred unrecovered plant costs totaled $45.9 million at December 31, 2004.

As of December 31, 2004, we have deferred a regulatory asset of $41.7 million for bad debt costs. Prior to October 2002, Wisconsin Gas used the escrow method of accounting for bad debt costs whereby it deferred actual bad debt write-off that exceeded amounts that were allowed in its rates. In 2003 and 2004, the PSCW approved our request to defer bad debt write-offs at Wisconsin Gas and Wisconsin Electric to the extent that the write-offs exceeded

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amounts allowed in rates. We have requested that this deferral accounting continue in 2005. We will request approval to recover these costs in our next Wisconsin rate case.

In connection with the WICOR acquisition, we recorded the funded status of the Wisconsin Gas pension and post-retirement medical plans at fair value at the acquisition date. Due to the expected regulatory treatment of these items, we recorded a regulatory liability (Deferred pension - income) that is being amortized over an average remaining service life of 15 years ending 2015.

D -- 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 $736.3 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.

E -- ASSET SALES, DIVESTITURES AND DISCONTINUED OPERATIONS

We have been pursuing a corporate strategy since September 2000, which, among other things, identified the divestiture of non-core investments. These assets primarily related to our manufacturing business, non-utility energy investments and real estate.

Manufacturing:Effective July 31, 2004, we sold WICOR, Inc. to Pentair, Inc. and received cash proceeds of $857 million, and Pentair, Inc. assumed approximately $25 million of third party debt.

WICOR's only asset at the time of the sale consisted of its interest in WICOR Industries. As a condition of the sale, WICOR transferred its ownership of Wisconsin Gas to Wisconsin Energy through a stock redemption. Prior to the transaction, Wisconsin Gas converted from a corporation to a limited liability company (collectively the "Wisconsin Gas transfer"). We expect to pay cash taxes of approximately $114 million as a result of the stock redemption described above. However, we also expect to receive future tax deductions from a step-up in the tax basis of the Wisconsin Gas assets as a result of the Wisconsin Gas transfer. We therefore expect that substantially all of the cash taxes paid on the stock redemption will be recovered as deferred income tax assets through future deductions.

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. We have established reserves related to these customary indemnification matters. In addition, the amount of cash taxes and future deferred income tax benefits are subject to a number of factors including appraisals of the fair value of Wisconsin Gas assets and applicable tax laws. Any changes in the estimates of taxes and indemnification matters will be recorded as an adjustment to the gain on sale and reported in discontinued operations in the period the adjustment is determined.

In accordance with SFAS 144, the assets and liabilities associated with our manufacturing segment have been reclassified as held for sale in the accompanying December 31, 2003 balance sheet. SFAS 144 requires that a long-

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lived asset classified as held for sale be measured at the lower of its carrying amount or fair value, less costs to sell, and cease being depreciated. We also reclassified our manufacturing segment as discontinued operations in the accompanying income statements. Included in discontinued operations is interest expense associated with third-party debt that was assumed by the buyer upon completion of the sale. A summary of the components of Income from Discontinued Operations, Net of Tax in our Consolidated Condensed Income Statements follows:

	Year Ended December 31
	2004 (a)	2003	2002
	(Millions of Dollars)
Operating revenues	$481.0	$746.1	$685.2
Operating expenses	429.8	677.5	627.6
Interest expense and other	0.3	(0.2)	1.9
Income before income taxes	50.9	68.8	55.7
Income tax expense	19.0	24.9	20.4
Income from operations, net of tax	31.9	43.9	35.3
Gain on Sale, net of taxes of $2.1 million	152.3	-	-
Income from discontinued operations, net of tax	$184.2	$43.9	$35.3

(a) Includes the results of our manufacturing segment through July 31, 2004.

A summary of the components of cash flows for discontinued operations follows:

	Year Ended December 31
	2004(a)	2003	2002
	(Millions of Dollars)
Net cash flows received from operating activities	$36.9	$93.9	$50.5
Net cash flows received from (used in) investing activities	(41.3)	(70.9)	16.6
Net cash flows used in financing activities	(2.0)	(6.1)	(66.6)
Net (decrease) increase in cash and temporary cash investments	($6.4)	$16.9	$0.5

Supplemental cash flow information:
Interest	$0.5	$1.0	$2.0
Income taxes, net of refunds	$8.5	$7.8	$1.1

(a) Includes the results of our manufacturing segment through July 31, 2004.

Cash and temporary cash investments of discontinued operations as of December 31, 2003 totaled $25.4 million and are included in Assets held for sale in the Consolidated Balance Sheet.

Non-Utility:   During 2003, we sold our investment in two energy marketing companies, a small investment in assets of a Minergy Corp. project, a 500 megawatt natural gas power island and miscellaneous small real estate and other sales. These sales resulted in net cash proceeds of approximately $56.0 million and $32.0 million in tax benefits. In addition, we received $15.0 million in dividends from certain of these companies at closing.

During 2002, we completed the sale of Wisvest - Connecticut LLC (Wisvest Connecticut), which resulted in net cash proceeds of approximately $220.0 million.

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F --ASSET VALUATION CHARGES

In the third quarter of 2004, we recorded non-cash asset valuation charges of $149.0 million ($96.9 million after-tax) related to Minergy Neenah and Calumet. These charges are discussed below. During 2003, we recorded asset valuation charges totaling $59.5 million, of which $19.4 million related to the write-off of our remaining investment in Androscoggin LLC, an independent power project and $40.1 million related to an investment in a power island. The power island is discussed in more detail below. During the first quarter of 2002, we recorded $141.5 million of impairment charges of which $125.1 million was related to our non-utility energy segment (primarily Wisvest - Connecticut) and a $16.4 million charge related to a decline in a venture capital investment. Wisvest - Connecticut was sold in the fourth quarter of 2002.

Minergy Neenah:   Minergy Neenah is a waste to energy facility that recycles paper sludge from area paper mills into steam, renewable electricity and glass aggregate. One of Minergy Neenah's key revenue sources is a long-term steam contract with a paper company whereby Minergy Neenah sells steam to the paper company's facility in Neenah. The paper company contacted Minergy Neenah to request a renegotiation of the steam contract to help sustain the long-term viability of the paper company's facility. Given the importance of the long-term steam contract to Minergy Neenah, we believed it was important to help maintain the viability of the paper company's facility. In October 2004, we signed an amendment to the steam contract which will reduce estimated steam revenues through 2017. We concluded the asset was impaired and recorded a non-cash asset valuation charge of $27.0 million ($17.6 million after-tax) in the third quarter of 2004.

Calumet:   Calumet is a 308 megawatt natural gas-based peaking power plant located in Chicago, Illinois. Since May 1, 2004, Calumet has operated under the control of PJM Interconnection, L.L.C. (PJM), a regional transmission organization that also operates bid based energy and capacity markets. In the third quarter of 2004, we determined that (i) Calumet has significant risk associated with liquidated damages for certain energy sales within the PJM market, (ii) the elimination of the risk is not guaranteed via assumption of the risk by a third party marketer or through the availability of appropriate insurance, and (iii) nonacceptance of, or failure to arrange for, coverage of the risk greatly diminishes the ability to viably sell merchant capacity, which has resulted in a change in the anticipated economics of the facility and the determination of an impairment of the facility. We concluded that this asset was impaired and recorded a non-cash asset valuatio n charge of $122.0 million ($79.3 million after-tax) in the third quarter of 2004.

Power Island:   Wisvest had purchased a 500 megawatt power island consisting of gas turbine generators and related equipment. This power island was not identified for a specific project. In 2002, we took possession of the power island and put it in storage. In the third quarter of 2003, we recorded a non-cash asset valuation charge of $40.1 million ($26.0 million after tax) to reflect the impairment of this asset. We determined in the third quarter of 2003 based on information obtained from our efforts to market the power island, that the carrying value of this asset exceeded market values. We estimated the fair market value of our 500 megawatt power island based upon a definitive agreement we entered into to sell the asset. This asset was sold in the fourth quarter of 2003 with no additional loss.

G -- INCOME TAXES

The following table is a summary of income tax expense for each of the years ended December 31:

Income Tax Expense	2004	2003	2002
	(Millions of Dollars)
Current tax expense	$73.8	$93.9	$138.9
Deferred income taxes, net	11.3	21.2	(48.7)
Investment tax credit, net	(4.8)	(4.9)	(4.9)
Total Income Tax Expense	$80.3	$110.2	$85.3

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The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable U.S. statutory federal income tax rate to income before income taxes as a result of the following:

	2004		2003		2002
		Effective		Effective		Effective
Income Tax Expense	Amount	Tax Rate	Amount	Tax Rate	Amount	Tax Rate
	(Millions of Dollars)
Expected tax at
statutory federal tax rates	$70.9	35.0%	$108.7	35.0%	$76.0	35.0%
State income taxes
net of federal tax benefit	20.2	10.0%	21.0	6.8%	21.5	9.9%
Investment tax credit restored	(4.8)	(2.4%)	(4.9)	(1.6%)	(4.9)	(2.3%)
Federal Historical rehabilitation credits (net)	(1.0)	(0.5%)	(1.7)	(0.5%)	(6.0)	(2.7%)
Other, net	(5.0)	(2.5%)	(12.9)	(4.2%)	(1.3)	(0.6%)
Total Income Tax Expense	$80.3	39.6%	$110.2	35.5%	$85.3	39.3%

The state income tax rate between 2004 and 2003 was adversely affected by the inability to receive state tax benefits from certain asset valuation charges.

The components of SFAS 109 deferred income taxes classified as net current assets and net long-term liabilities at December 31 are as follows:

	Current Assets (Liabilities)		Long-Term Liabilities (Assets)
Deferred Income Taxes	2004	2003	2004	2003
	(Millions of Dollars)
Property-related	$  -	$  -	$634.8	$693.8
Construction advances	-	-	(80.1)	(82.9)
Decommissioning trust	-	-	(74.5)	(65.5)
Recoverable gas costs	8.1	6.4	-	-
Prepaid taxes and insurance	(29.5)	-	-	-
Uncollectible account expense	(3.0)	16.6	-	-
Employee benefits
and compensation	13.7	10.7	(12.3)	1.4
Deferred transmission costs	-	-	40.5	21.8
State NOL's	-	-	(22.0)	(18.0)
Valuation allowance	-	-	40.5	22.5
Other	15.6	22.8	3.5	(2.3)
Total Deferred Income Taxes	$4.9	$56.5	$530.4	$570.8

We had not recorded $22.0 million and $18.0 million of tax benefits as of December 31, 2004 and 2003 primarily related to state loss carryforwards due to the uncertainty of the ability to benefit from these losses in the future. These loss carryforwards begin to expire in 2008 and have been reduced by a valuation allowance.

H -- NUCLEAR OPERATIONS

Point Beach Nuclear Plant:   Wisconsin Electric owns two 518-megawatt electric generating units at Point Beach Nuclear Plant in Two Rivers, Wisconsin. We currently expect the two units at Point Beach to operate to the end of their operating licenses, which expire in October 2010 for Unit 1 and in March 2013 for Unit 2. In February 2004, Nuclear Management Company (NMC) and Wisconsin Electric filed an application with the United States Nuclear Regulatory Commission (NRC) to renew the operating licenses for both of Wisconsin Electric's nuclear reactors for an additional 20 years. We expect the NRC to make a decision on the license extension application by January 2006, based upon the NRC's published schedule.

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Nuclear Insurance:   The Price-Anderson Act currently limits the total public liability for damages arising from a nuclear incident at a nuclear power plant to approximately $10.6 billion, of which $300 million is covered by liability insurance purchased from private sources. The remaining $10.3 billion is covered by an industry retrospective loss sharing plan whereby in the event of a nuclear incident resulting in damages exceeding the private insurance coverage, each owner of a nuclear plant would be assessed a deferred premium of up to $99.2 million per reactor (Wisconsin Electric owns two) with a limit of $10 million per reactor within one calendar year. As the owner of Point Beach, Wisconsin Electric would be obligated to pay its proportionate share of any such assessment.

Wisconsin Electric, through its membership in Nuclear Electric Insurance Limited (NEIL), carries decontamination, property damage and decommissioning shortfall insurance covering losses of up to $2.1 billion at Point Beach. Under policies issued by NEIL, the insured member may be liable for a retrospective premium in the event of catastrophic losses exceeding the full financial resources of NEIL. Wisconsin Electric's maximum retrospective liability under the above policies is $16.5 million.

Wisconsin Electric also maintains insurance with NEIL through which it can recover up to $3.5 million per week, subject to a total limit of $490 million, during any prolonged outage at Point Beach caused by accidental property damage. Wisconsin Electric's maximum retrospective liability under this policy is $9.6 million.

It should not be assumed that, in the event of a major nuclear incident, any insurance or statutory limitation of liability would protect Wisconsin Electric from material adverse impact.

Nuclear Decommissioning:   We record decommissioning expense in amounts equal to the amounts collected in rates and funded to the external trusts. Nuclear decommissioning costs are accrued over the expected service lives of the nuclear generating units and are included in electric rates. Decommissioning funding was $17.6 million for each of the years ended 2004, 2003 and 2002. As of December 31, 2004 and 2003, we had the following investments in Nuclear Decommissioning Trusts, stated at fair value.

	2004	2003
	(Millions of Dollars)
Funding and Realized Earnings	$529.1	$485.2
Unrealized Gains	208.7	189.2
Total Investments	$737.8	$674.4

As of December 31, 2004 approximately 66.7% of the trusts were invested in equity securities and 33.3% were invested in debt securities. In accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities, Wisconsin Electric's debt and equity security investments in the Nuclear Decommissioning Trust Fund are classified as available for sale. Gains and losses on the fund are determined on the basis of specific identification; net unrealized gains on the fund are recorded as part of the fund.

We record an Asset Retirement Obligation (ARO) under SFAS 143 for future decommissioning costs based upon the net present value of the expected cash flows associated with our legal obligation to decommission our nuclear plants. As of December 31, 2004 and 2003, our ARO associated with nuclear decommissioning totaled $745.3 million and $708.5 million, respectively. We recover decommissioning costs in our regulated rates. We record a regulatory asset to the extent that our decommissioning ARO exceeds amounts collected in rates and cumulative investment gains (our nuclear trust investments). In the future, to the extent that our nuclear trust investments exceed the decommissioning ARO, we would expect to record a regulatory liability. For further information on ARO's see Note L.

The decommissioning ARO is calculated using several significant assumptions including the timing of future cash flows, future inflation rates, the extent of work that is expected to be performed and the discount rate applied to future cash flows. These assumptions differ significantly from the assumptions used by the PSCW to calculate the nuclear decommissioning liability for funding purposes.

In 2002, we engaged a consultant to perform a site specific study for regulatory funding purposes. This study assumed that the plants would not run past their current operating licenses of 2010 and 2013, respectively, and the study made several assumptions as to the scope of 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 decommissioning

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ARO. The 2002 site specific study estimated that the cost to decommission the plant in 2003 year dollars was approximately $1.1 billion. At least every four years these studies are reviewed which could result in future changes to the decommissioning ARO. The differences between the regulatory funding liability and the decommissioning ARO are primarily related to fuel management costs, non-nuclear demolition costs and the timing of future cash flows.

The ultimate timing and amount of future cash flows associated with nuclear decommissioning is dependent upon many significant variables including the scope of work involved, the ability to relicense the plants, future inflation rates and discount rates. However, based on the current plant licenses, we do not expect to make any significant nuclear decommissioning expenditures before the year 2011.

Decontamination and Decommissioning Fund:   The Energy Policy Act of 1992 established a Uranium Enrichment Decontamination and Decommissioning Fund (D&D Fund) for the United States Department of Energy's nuclear fuel enrichment facilities. Deposits to the D&D Fund are derived in part from special assessments on utilities using enrichment services. As of December 31, 2004, Wisconsin Electric recorded its remaining estimated liability equal to projected special assessments of $7.2 million. The deferred regulatory asset will be amortized to nuclear fuel expense and included in utility rates over the next three years ending in 2007.

I -- COMMON EQUITY

Common Stock Activity:  In September 2000, the Board of Directors amended the common stock repurchase plan to authorize us to purchase up to $400 million of our shares of common stock in the open market. In 2004, we purchased and retired approximately 1.6 million shares of common stock for $50.4 million. The plan expired on December 31, 2004. Over the life of the plan we purchased and retired approximately 14.9 million shares of common stock for $344.0 million.

Prior to February 2004, we issued shares of our common stock to fulfill obligations under various employee benefit plans and the dividend reinvestment plan. We received proceeds of approximately $4.8 million, $62.9 million, and $52.6 million during 2004, 2003, and 2002, related to these share issuances. In February 2004, we announced that we did not expect to issue new shares under these programs; rather we instructed the plan agents to begin purchasing the shares in the open market in lieu of issuing new shares. During 2004, our plan agents purchased 3.2 million shares at a cost of $102.3 million to fulfill exercised stock options. In 2004, we received proceeds of $66.1 million related to the exercise of stock options.

Stock Based Compensation Plans:   Our 1993 Omnibus Stock Incentive Plan, as amended (OSIP), as approved by stockholders, enables us to provide a long-term incentive through equity interests in Wisconsin Energy, to outside directors, selected officers and key employees of the Company and its subsidiaries. The OSIP provides for the granting of stock options, stock appreciation rights, stock awards and performance units. Awards may be paid in common stock, cash or a combination thereof.

The exercise price of a stock option under the OSIP is to be no less than 100% of the common stock's fair market value on the grant date and options may not be exercised within six months of the grant date except in the event of a change in control. The stock options that were granted prior to 2005 generally vest on a straight line basis over a four year period and expire no later than ten years from the date of grant.

The following is a summary of our stock options issued through December 31, 2004. In addition to the OSIP, the table below reflects our assumption of former WICOR options in 2000, which were converted into options to purchase shares of Wisconsin Energy common stock on the same terms and conditions as were applicable under the WICOR options.

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	2004		2003		2002
		Weighted-		Weighted-		Weighted-
	Number	Average	Number	Average	Number	Average
	Of	Exercise	of	Exercise	of	Exercise
Stock Options	Options	Price	Options	Price	Options	Price
Outstanding at January 1	9,823,935	$22.87	8,307,190	$21.21	7,135,463	$19.16
Granted	1,844,765	$33.44	2,913,289	$26.05	2,465,815	$22.88
Exercised	(3,249,688)	$20.97	(1,357,197)	$19.55	(1,284,500)	$13.47
Forfeited	(128,701)	$28.21	(39,347)	$21.97	(9,588)	$24.38
Outstanding at December 31	8,290,311	$25.88	9,823,935	$22.87	8,307,190	$21.21
Exercisable at December 31	8,090,987	$25.99	4,303,482	$21.25	4,267,604	$20.56

In December, 2004, the Compensation Committee of the Board of Directors approved certain changes to unvested options and to future grants. The Compensation Committee approved the acceleration of vesting of all unvested options awarded to executive officers and other key employees in 2002, 2003 and 2004 in anticipation of the changes in accounting required under the new accounting standard for share based payments which is effective July 1, 2005. In addition, the Compensation Committee determined that future option grants would be non-qualified stock options and they would vest on a cliff-basis after a three year period. The Company recorded a $0.4 million charge, net of tax, in connection with the accelerated vesting of unvested stock options.

In January 2005, the Compensation Committee awarded 1,328,966 non-qualified stock options to our officers and key employees under its normal schedule of awarding long-term incentive compensation.

The following table summarizes information about stock options outstanding at December 31, 2004:

	Options Outstanding			Options Exercisable
		Average			Average
		Exercise	Life		Exercise
Range of Exercise Prices	Number	Price	(years)	Number	Price
$9.30  to  $19.97	797,094	$17.99	4.6	797,094	$17.99
$20.39  to  $23.05	2,428,418	$21.89	6.6	2,270,760	$21.97
$24.58  to  $27.65	2,542,747	$25.71	7.3	2,501,081	$25.71
$29.13  to  $33.44	2,522,052	$32.40	8.1	2,522,052	$32.40
	8,290,311	$25.88	7.1	8,090,987	$25.99

We follow APB 25 and related interpretations when accounting for our stock option plans and we have adopted the disclosure-only provisions of SFAS 123, as amended by SFAS 148. The fair value of options at date of grant was estimated using the Black-Scholes option-pricing model with the following weighted average assumptions:

	2004	2003	2002
Risk free interest rate	4.6%	4.5%	5.6%
Dividend yield	2.5%	3.1%	3.5%
Expected volatility	23.10%	25.73%	25.5%
Expected life (years)	10	10	10
Pro forma weighted average fair
value of our stock options granted	$9.45	$7.04	$6.25

As described more fully in the following table, our diluted earnings would have been reduced by $0.24, $0.06 and $0.05 per share, respectively, had we expensed the 2004, 2003 and 2002 grants for stock-based compensation plans under SFAS 123. The 2004 pro forma expense includes the effect of accelerating the vesting of stock options, as described above, which resulted in a pro forma expense of $0.16 per share.

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	2004	2003	2002
	(Millions of Dollars, Except Per Share Amounts)
Net Income
As reported	$306.4	$244.3	$167.0
Add: Stock-based employee      compensation expense included      in reported net income, net of related      tax effects	$2.5	$0.7	$0.3
Deduct: Total stock-based employee      compensation expense determined      under fair value based method for all      awards, net of related tax effects	$31.5	$8.5	$5.3
Pro forma	$ 277.4	$236.5	$162.0
Basic Earnings Per Common Share
As reported	$2.60	$2.09	$1.45
Pro forma	$2.36	$2.02	$1.40
Diluted Earnings Per Common Share
As reported	$2.57	$2.06	$1.44
Pro forma	$2.33	$2.00	$1.39

The Compensation Committee has also approved restricted stock grants to certain key employees and directors. The following restricted stock activity occurred during 2004, 2003 and 2002:

	2004		2003		2002
		Weighted-		Weighted-		Weighted-
	Number	Average	Number	Average	Number	Average
	of	Market	of	Market	of	Market
Restricted Shares	Shares	Price	Shares	Price	Shares	Price
Outstanding at January 1	294,920		219,052		243,941
Granted	16,570	$33.36	104,500	$27.72	-	-
Released / Forfeited	(90,127)	$22.87	(28,632)	$22.84	(24,889)	$20.64
Outstanding at December 31	221,363		294,920		219,052

Recipients of the restricted shares, who have the right to vote the shares and to receive dividends, are not required to provide consideration to us other than rendering service. Forfeiture provisions on the restricted stock generally expire 10 years after award grant subject to an accelerated expiration schedule based on the achievement of certain financial performance goals.

Under the provisions of APB 25, we record the market value of the restricted stock awards on the date of grant as a separate unearned compensation component of common stock equity and then we charge their value to expense over the vesting period of the awards. We also adjust expense for acceleration of vesting due to achievement of performance goals.

In January 2004, the Compensation Committee granted 159,159 performance shares to officers and other key employees. The ultimate number of shares of Common Stock which will be awarded under this program is dependent upon the achievement of certain financial performance of the Company's stock over a three year period ending December 31, 2006. Under the terms of the award, participants may earn between 0% and 175% of the base performance award. We are accruing compensation costs over the three year period based on our estimate of the final expected value of the award.

In January 2005, the Compensation Committee granted 101,834 performance units to executive officers and other key employees. These awards are similar to the January 2004 grant, except that these units will be settled in cash instead of shares of our common stock.

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Restrictions:   Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our principal utility subsidiaries to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. Under Wisconsin law, Wisconsin Electric and Wisconsin Gas are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy. We do not believe that these restrictions will materially affect our operations.

J -- LONG-TERM DEBT

First Mortgage Bonds, Debentures and Notes:   At December 31, 2004, the maturities and sinking fund requirements through 2009 and thereafter for the aggregate amount of our long-term debt outstanding (excluding obligations under capital leases) were:

	(Millions of Dollars)
2005	$    86.3
2006	455.8
2007	251.0
2008	346.5
2009	50.8
Thereafter	1,965.0
Total	$3,155.4

Long-term debt premium or discount and expense of issuance are amortized over the lives of the debt issues and included as interest expense.

In August 2004, Wisconsin Electric retired $140 million of 7-1/4% First Mortgage Bonds at their scheduled maturity. Wisconsin Electric financed this retirement through the issuance of short-term commercial paper.

In September 2004, we used cash proceeds from the sale of WICOR Industries for the redemption of $300 million of Wisconsin Energy 5.875% senior notes due April 1, 2006. In September 2004, we recorded approximately $17.0 million of costs associated with this early redemption, which are included in Other Income and Deductions, Net in our Consolidated Income Statement for the year ended December 31, 2004.

In November 2004, Wisconsin Electric sold $250 million of unsecured 3.50% debentures due December 1, 2007. The securities were issued under an existing $665 million shelf registration statement filed with the Securities and Exchange Commission (SEC). The proceeds from the sale were used to repay our outstanding commercial paper.

In December 2004, Wisconsin Electric refinanced $147 million of the $165 million aggregate principal amount of unsecured variable rate putable weekly reset tax-exempt debt with new "auction" non-putable unsecured variable rate weekly reset tax-exempt debt.

In March 2003, Wisconsin Energy sold $200 million of unsecured 6.20% Senior Notes due April 1, 2033. These securities were issued under a shelf registration statement filed with the SEC. The proceeds of the offering were used to repay a portion of our outstanding commercial paper as it matured.

In May 2003, Wisconsin Electric sold $635 million of unsecured Debentures ($300 million of ten-year 4.50% Debentures due 2013 and $335 million of thirty-year 5.625% Debentures due 2033) under an $800 million shelf registration statement filed with the SEC. Wisconsin Electric used a portion of the proceeds from the Debentures to repay short-term debt, which was originally incurred to retire debt that matured in December 2002. The balance of the proceeds were used to redeem $425 million of Wisconsin Electric's debt securities in June 2003 and to fund the early redemption in August 2003 of another $60 million debt issue.

In October 2003, Wisconsin Electric redeemed $9 million of 6.85% First Mortgage Bonds.

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In December 2003, Wisconsin Gas sold $125 million of unsecured 5.20% debentures due 2015. These securities were issued under an existing $200 million shelf registration statement filed with the SEC. The proceeds of the offering were used to repay short-term debt.

Obligations Under Capital Leases:   In 1997, Wisconsin Electric entered into a 25 year power purchase contract with an unaffiliated independent power producer. The contract, for 236 megawatts of firm capacity from a gas-fired cogeneration facility, includes no minimum energy requirements. When the contract expires in 2022, Wisconsin Electric may, at its option and with proper notice, renew for another ten years or purchase the generating facility at fair value or allow the contract to expire. We account for this contract as a capital lease and recorded the leased facility and corresponding obligation under the capital lease at the estimated fair value of the plant's electric generating facilities. We are amortizing the leased facility on a straight-line basis over the original 25-year term of the contract.

We treat the long-term power purchase contract as an operating lease for rate-making purposes and we record our minimum lease payments as purchased power expense on the Consolidated Income Statements. We paid a total of $24.3 million, $23.4 million and $22.3 million in minimum lease payments during 2004, 2003, and 2002, respectively. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on our Consolidated Balance Sheets (see deferred regulatory asset - plant related - capital lease in Note C). Due to the timing of the minimum lease payments, we expect the regulatory asset to increase to approximately $78.5 million by the year 2009 and the total obligation under the capital lease to increase to $160.2 million by the end of 2005 before each is reduced to zero over the remaining life of the contract.

Wisconsin Electric also has a nuclear fuel leasing arrangement with Wisconsin Electric Fuel Trust (Trust) which is treated as a capital lease. We lease and amortize the nuclear fuel to fuel expense as power is generated, generally over a period of 60 months. Lease payments include charges for the cost of fuel burned, financing costs and management fees. In the event that Wisconsin Electric or the Trust terminates the lease, the Trust would recover its unamortized cost of nuclear fuel from Wisconsin Electric. Under the lease terms, Wisconsin Electric is in effect the ultimate guarantor of the Trust's commercial paper and line of credit borrowings that finance the investment in nuclear fuel. We recorded $1.4 million of interest expense on the nuclear fuel lease in fuel expense during 2004 and 2003 and $1.9 million during 2002.

Following is a summary of Wisconsin Electric's capitalized leased facilities and nuclear fuel at December 31.

Capital Lease Assets	2004	2003
	(Millions of Dollars)
Leased Facilities
Long-term purchase power commitment	$140.3	$140.3
Accumulated amortization	(41.4)	(35.7)
Total Leased Facilities	$98.9	$104.6
Nuclear Fuel
Under capital lease	$120.2	$115.9
Accumulated amortization	(74.0)	(67.0)
In process/stock	38.8	29.5
Total Nuclear Fuel	$85.0	$ 78.4

Future minimum lease payments under our capital leases and the present value of our net minimum lease payments as of December 31, 2004 are as follows:

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	Purchase
	Power	Nuclear
Capital Lease Obligations	Commitment	Fuel Lease	Total
	(Millions of Dollars)
2005	$30.1	$24.0	$54.1
2006	31.2	16.5	47.7
2007	32.4	8.6	41.0
2008	33.6	5.4	39.0
2009	34.9	1.1	36.0
Thereafter	369.0	-	369.0
Total Minimum Lease Payments	531.2	55.6	586.8
Less:  Estimated Executory Costs	(113.8)	-	(113.8)
Net Minimum Lease Payments	417.4	55.6	473.0
Less:  Interest	(257.4)	(2.7)	(260.1)
Present Value of Net
Minimum Lease Payments	160.0	52.9	212.9
Less:  Due Currently	-	(21.8)	(21.8)
	$160.0	$31.1	$191.1

Trust Preferred Securities:   In March 1999, WEC Capital Trust I, a Delaware business trust of which we own all of the outstanding common securities, issued $200 million of 6.85% trust preferred securities to the public. The sole asset of WEC Capital Trust I was $206.2 million of 6.85% junior subordinated debentures issued by us and due March 31, 2039. The terms and interest payments on these debentures corresponded to the terms and distributions on the trust preferred securities. WEC Capital Trust I had been consolidated into our financial statements prior to adoption of Interpretation 46. In March 2004, WEC Capital Trust I, the issuer of our trust preferred securities, redeemed all of the $200 million of the outstanding trust preferred securities, which required us to redeem our long-term notes due to WEC Capital Trust I. We financed this redemption through the issuance of short-term commercial paper. In March 2004, we recorded approx imately $5.9 million of costs associated with this early redemption, which are included in Other Income and Deductions, Net in our Consolidated Income Statement for the year ended December 31, 2004.

K -- SHORT-TERM DEBT

Short-term notes payable balances and their corresponding weighted-average interest rates as of December 31 consist of:

	2004		2003
		Interest		Interest
Short-Term Debt	Balance	Rate	Balance	Rate
	(Millions of Dollars, except for percentages)
Commercial paper	$338.0	2.35%	$590.8	1.18%

On December 31, 2004, we had approximately $1.2 billion of available unused lines of bank back-up credit facilities on a consolidated basis. We had approximately $338.0 million of total consolidated short-term debt outstanding on such date. Our bank back-up credit facilities mature beginning April 2006 through November 2007.

The following information relates to Short-Term Debt for the years ending December 31, 2004 and 2003:

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	2004	2003
	(Millions of Dollars, except for percentages)
Maximum Short-Term Debt Outstanding	$627.8	$930.7
Average Short-Term Debt Outstanding	434.9	642.9
Weighted Average Interest Rate	1.41%	1.28%

Wisconsin Energy, Wisconsin Electric and Wisconsin Gas have entered into various bank back-up credit agreements to maintain short-term credit liquidity which, among other terms, require the companies to maintain a minimum total funded debt to capitalization ratio of less than 70%, 65% and 65%, respectively.

Wisconsin Energy's bank back-up credit facilities require us to maintain a minimum ratio of consolidated EBITDA (Earnings before interest, taxes, depreciation and amortization) to consolidated interest expense. For the twelve months ended December 31, 2004 we were in compliance.

L -- ASSET RETIREMENT OBLIGATIONS

SFAS 143, Accounting for Asset Retirement Obligations, primarily applies to the future decommissioning costs for our Point Beach Nuclear Plant (Point Beach). Prior to January 2003, we recorded a long-term liability for accrued nuclear decommissioning costs. See Note H for further information about the nuclear decommissioning of Point Beach including our investments in Nuclear Decommissioning Trusts that are restricted to nuclear decommissioning.

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 be reasonably estimated.

The following table presents the change in our asset retirement obligations during 2004.

	Balance at	Liabilities	Liabilities		Cash Flow	Balance at
	12/31/03	Incurred	Settled	Accretion	Revisions	12/31/04
		(Millions of Dollars)
Asset Retirement Obligations	$732.0	$ -	$7.1	$37.3	$ -	$762.2

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

Wisvest - Connecticut LLC, which was sold December 6, 2002, had fuel oil contracts utilized to mitigate the commodity risk associated with generation costs. These contracts were defined as derivatives under SFAS 133 and did not qualify or were not designated for hedge accounting treatment. For the year ended December 31, 2002, we recorded non-cash, after - tax income of $12.7 million to reflect the changes in fuel oil prices during the year and the settlement of transactions.

We have a limited number of financial contracts that are defined as derivatives under SFAS 133 and qualify for cash flow hedge accounting. These contracts are utilized to manage the cost of gas for utility operations and gas used in testing a new generating unit under construction. Changes in the fair market values of these instruments are

25
recorded in Accumulated Other Comprehensive Income. At the date the underlying transaction occurs, the amounts in Accumulated Other Comprehensive Income for utility operations are reported in earnings and amounts related to the new generating unit are capitalized.

For the years ended December 31, 2004 and 2003 the amount of hedge ineffectiveness was immaterial. We did not exclude any components of derivative gains or losses from the assessment of hedge effectiveness. The maximum length of time over which we are hedging our exposure to the variability in future cash flows of forecasted transactions as of December 31, 2004 was six months. We estimate that $0.6 million will be reclassified from Accumulated Other Comprehensive Income to earnings or capitalized to Plant during the first six months of 2005.

During March 2003, we settled several treasury lock agreements entered into earlier in the first quarter of 2003 and during the third quarter of 2002 to mitigate interest rate risk associated with the issuance of $200 million of long-term unsecured senior notes in March 2003. As these agreements qualified for cash flow hedging accounting treatment under SFAS 133, the payment made upon settlement of these agreements is deferred in Accumulated Other Comprehensive Income and is being amortized as an increase to Interest Expense over the same period in which the interest cost is recognized in income.

We reclassified $0.8 million in treasury lock agreement settlement payments deferred in Accumulated Other Comprehensive Income, as an increase to Interest Expense for the year ended December 31, 2004. We estimate that during the next twelve months, $0.6 million will be reclassified from Accumulated Other Comprehensive Income as a reduction in earnings. We reclassified $0.8 million to Interest Expense for the year ended December 31, 2003.

In addition, during 2004, in conjunction with the redemption of $300 million of Wisconsin Energy 5.875% senior notes due April 1, 2006, $0.6 million of a treasury lock agreement settlement payment previously deferred in Accumulated Other Comprehensive Incomewas reclassified to Other Income and Deductions, Net.

N -- FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amount and estimated fair value of certain of our recorded financial instruments at December 31 are as follows:

	2004		2003
	Carrying	Fair	Carrying	Fair
Financial Instruments	Amount	Value	Amount	Value
	(Millions of Dollars)
Nuclear decommissioning trust fund	$737.8	$737.8	$674.4	$674.4
Preferred stock, no redemption required	$30.4	$22.7	$30.4	$20.9
Long-term debt including
current portion	$3,155.4	$3,301.0	$3,555.5	$3,699.0

The carrying value of cash and cash equivalents, net accounts receivable, accounts payable and short-term borrowings approximates fair value due to the short term nature of these instruments. The nuclear decommissioning trust fund is carried at fair value as reported by the trustee (see Note H). The fair value of our preferred stock is estimated based upon the quoted market value for the same or similar issues. The fair value of our long-term debt, including the current portion of long-term debt but excluding capitalized leases, is estimated based upon quoted market value for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows. The fair values of gas commodity instruments are equal to their carrying values as of December 31, 2004.

O -- BENEFITS

Pensions and Other Post-retirement Benefits:   We have funded and unfunded noncontributory defined benefit pension plans that together cover substantially all of our employees. The plans provide defined benefits based upon years of service and final average salary.

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We also have other post-retirement benefit plans covering substantially all of our employees. The health care plans are contributory with participants' contributions adjusted annually; the life insurance plans are noncontributory. The accounting for the health care plans anticipates future cost-sharing changes to the written plans that are consistent with our expressed intent to maintain the current cost sharing levels. The post-retirement health care plans include a limit on our share of costs for recent and future retirees. We use a year end measurement date for all of our pension and other post-retirement benefit plans.

				Other Post-retirement
	Pension Benefits			Benefits
Status of Benefit Plans	2004	2003	2002	2004	2003	2002
	(Millions of Dollars)
Change in Benefit Obligation
Benefit Obligation at January 1	$1,100.6	$1,010.0	$974.8	$366.0	$327.6	$262.5
Service cost	30.2	30.6	22.1	12.0	10.8	8.0
Interest cost	69.1	67.4	68.5	21.8	22.3	19.8
Plan participants' contributions	-	-	-	-	0.9	6.9
Plan amendments	2.0	19.4	(1.2)	0.7	5.1	2.3
Actuarial loss	103.8	33.7	32.8	9.9	14.8	51.6
Acquisitions / divestitures	-	-	(20.3)	-	-	(1.9)
Benefits paid	(100.7)	(60.5)	(66.7)	(14.9)	(15.5)	(21.6)
Benefit Obligation at December 31	$1,205.0	$1,100.6	$1,010.0	$395.5	$366.0	$327.6
Change in Plan Assets
Fair Value at January 1	$926.3	$801.6	$993.9	$166.8	$137.8	$148.8
Actual earnings (loss) on plan assets	95.4	183.0	(119.0)	12.3	24.7	(11.1)
Employer contributions	77.5	2.2	5.4	19.4	18.9	16.0
Plan participants' contributions	-	-	-	-	0.9	6.9
Acquisitions / divestitures	-	-	(12.0)	-	-	(1.2)
Benefits paid	(100.7)	(60.5)	(66.7)	(14.9)	(15.5)	(21.6)
Fair Value at December 31	$998.5	$926.3	$801.6	$183.6	$166.8	$137.8
Funded Status of Plans
Funded status at December 31	($206.5)	($174.3)	($208.4)	($211.8)	($199.2)	($189.8)
Unrecognized
Net actuarial loss	360.7	281.6	352.1	129.2	124.2	131.1
Prior service cost	34.0	36.8	22.2	6.9	6.9	2.4
Net transition (asset) obligation	(0.1)	(2.3)	(4.6)	12.6	14.2	15.8
Net Asset (Accrued Benefit Cost)	$188.1	$141.8	$161.3	($63.1)	($53.9)	($40.5)
Amounts recognized in the Balance Sheet consist of:
Regulatory assets (See Note C)	$342.8	$189.4		$  -	$  -
Other deferred charges	34.3	45.1		51.5	50.0
Minimum pension liability	(152.8)	(34.7)		-	-
Other long-term liabilities	(45.4)	(61.0)		(114.6)	(103.9)
Other comprehensive income	9.2	3.0		-	-
Net amount recognized at end of year	$188.1	$141.8		($63.1)	($53.9)

The accumulated benefit obligation for all defined benefit plans was $1,195.5 million and $1,013.5 million at December 31, 2004 and 2003, respectively.

Information for pension plans with an accumulated benefit obligation in excess of the fair value of assets are as follows:

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	2004	2003
	(Millions of Dollars)
Projected benefit obligation	$1,189.1	$1,081.2
Accumulated benefit obligation	$1,181.1	$994.8
Fair value of plan assets	$998.5	$926.3

The components of net periodic pension and other post-retirement benefit costs are:

				Other Post-retirement
Benefit Plan Cost Components	Pension Benefits			Benefits
	2004	2003	2002	2004	2003	2002
	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$30.2	$30.6	$22.1	$12.0	$10.8	$8.0
Interest cost	69.1	67.4	68.5	21.8	22.3	19.8
Expected return on plan assets	(85.6)	(87.3)	(93.6)	(14.1)	(11.6)	(12.6)
Amortization of:
Transition (asset) obligation	(2.3)	(2.3)	(2.3)	1.6	1.6	1.6
Prior service cost	4.8	4.8	3.4	0.7	0.6	0.2
Actuarial loss	15.0	3.4	3.1	6.6	8.6	4.6
Net Periodic Benefit Cost	$31.2	$16.6	$1.2	$28.6	$32.3	$21.6
Weighted-Average assumptions used to
determine benefit obligations at Dec. 31
Discount rate	5.75%	6.25%	6.75%	5.75%	6.25%	6.75%
Rate of compensation increase	4.0 to	4.0 to	4.0 to	4.0 to	4.0 to	4.0 to
	5.0	5.0	5.0	5.0	5.0	5.0
Weighted-Average assumptions used to
determine net cost for year ended Dec. 31
Discount rate	6.25%	6.75%	7.25%	6.25%	6.75%	7.25%
Expected return on plan assets	9.0	9.0	9.0	9.0	9.0	9.0
Rate of compensation increase	4.0 to	4.0 to	4.0 to	4.0 to	4.0 to	4.0 to
	5.0	5.0	5.0	5.0	5.0	5.0
Assumed health care cost trend rates at Dec. 31
Health care cost trend rate assumed for
next year				10	10	10
Rate that the cost trend rate gradually
Declines to				5	5	5
Year that the rate reaches the rate it is
Assumed to remain at				2010	2009	2008

The expected long-term rate of return on plan assets was 9% in 2004 and 2003. This return expectation on plan assets was determined by reviewing actual pension historical returns as well as calculating expected total trust returns using the weighted average of long-term market returns for each of the asset categories utilized in the pension fund.

Other Post-retirement Benefits Plans:   We use various Employees' Benefit Trusts to fund a major portion of other post-retirement benefits. The majority of the trusts' assets are mutual funds or commingled indexed funds.

A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	1% Increase	1% Decrease
	(Millions of Dollars)
Effect on
Post-retirement benefit obligation	$28.7	($25.9)
Total of service and interest cost components	$3.5	($3.0)

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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. The act resulted in a reduction of $24.1 million in our benefit obligation and reduced our 2004 SFAS 106 expense by $4.7 million. Assumptions used to develop this reduction include those used in the determination of the annual SFAS 106 expense and also include expectations of how the federal program will ultimately operate. 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 are still accurate. The final regulations have not yet addressed account based plans similar to the Cash Balance Medical Plan covering former Wisconsin Ga s employees. These plans are expected to be addressed by the regulations in February 2005. At this point, we do not expect the final regulations will change our estimates.

Plan Assets:   In our opinion, current pension trust assets and amounts which are expected to be contributed to the trusts in the future will be adequate to meet pension payment obligations to current and future retirees. Our pension plans asset allocation at December 31, 2004 and 2003, and our target allocation for 2005, by asset category, are as follows:

Asset Category	Target Allocation	Percentage of Pension Plans Assets at December 31
	2005	2004	2003
Equity Securities	72%	73%	76%
Debt Securities	28%	27%	24%
Total	100%	100%	100%

Our common stock is not included in equity securities. Investment managers are specifically prohibited from investing in our securities or any affiliate of ours except if part of a commingled fund.

The target asset allocation was established by our Board of Directors appointed Investment Trust Policy Committee, which oversees investment matters related to all of our funded benefit plans. Asset allocation is monitored by the Investment Trust Policy Committee.

Our other post-retirement benefit plans asset allocation at December 31, 2004 and 2003, and our target allocation for 2005, by asset category, are as follows:

Asset Category	Target Allocation	Percentage of Other Benefit Plans Assets at December 31
	2005	2004	2003
Equity Securities	46%	45%	48%
Debt Securities	53%	54%	50%
Other	1%	1%	2%
Total	100%	100%	100%

Our common stock is not included in equity securities. Investment managers are specifically prohibited from investing in our securities or any affiliate of ours except if part of a commingled fund.

The target asset allocation was established by our Board of Directors appointed Investment Trust Policy Committee, which oversees investment matters related to all of our funded benefit plans. Asset allocation is monitored by the Investment Trust Policy Committee.

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Cashflows:   

		Other Post-
	Pension	Retirement
Employer Contributions	Benefits	Benefits
	(Millions of Dollars)
2003	$2.2	$18.9
2004	$77.5	$19.4
2005 (Expected)	$5.7	$20.8

Of the $5.7 million expected to be contributed to fund pension benefits in 2005, none will be for our qualified plans since there is no minimum required by law. We contributed $55.7 million to our qualified pension plans during 2004. There was no contribution made during 2003 to the qualified pension plans.

The entire contribution to the other post-retirement benefit plans during 2004 was discretionary as the plans are not subject to any minimum regulatory funding requirements.

The following table identifies our expected benefit payments over the next 10 years:

		Gross Other	Expected
		Post	Medicare
		Employment	Part D
Year	Pension	Benefits	Subsidy
	(Millions of Dollars)
2005	$81.3	$21.9	$   -
2006	$85.2	$22.9	($1.2)
2007	$91.8	$23.9	($1.3)
2008	$92.4	$24.7	($1.4)
2009	$99.8	$25.6	($1.5)
2010-2014	$534.5	$151.4	($8.7)

Savings Plans:   We sponsor savings plans which allow employees to contribute a portion of their pre-tax and or after-tax income in accordance with plan-specified guidelines. Under these plans we expensed matching contributions of $10.5 million, $10.1 million and $10.0 million during 2004, 2003 and 2002, respectively.

Severance Plans:   For the year ended December 31, 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. The program was enacted to help reduce the upward pressure on operating expenses.

Approximately 200 employees received severance benefits during 2004. As of December 31, 2004 we have accrued $6.6 million of severance benefits which are expected to be paid during 2005.

P -- GUARANTEES

We enter into various guarantees to provide financial and performance assurance to third parties on behalf of our affiliates. As of December 31, 2004 we had the following guarantees:

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	Maximum
	Potential		Liability
	Future	Outstanding	Recorded at
	Payments	Dec 31, 2004	Dec 31, 2004
	(Millions of Dollars)
Wisconsin Energy
Non-Utility Energy	$     -	$     -	$     -
Other	45.5	45.5	-
Wisconsin Electric	231.0	0.1	-
Subsidiary	20.5	9.7	0.1
Total	$297.0	$55.3	$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, surety bonds and obligations under legal proceedings of the manufacturing business which was sold in July 2004. In the event our affiliates or the manufacturing business fail to perform, we would be responsible for the obligations.

Wisconsin Electric guarantees the potential retrospective premiums that could be assessed under Wisconsin Electric's nuclear insurance program (See Note H).

Subsidiary guarantees support loan obligations between our affiliates and third parties. In the event the loan obligations are not performed, 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 for such benefits was $15.6 million as of December 31, 2004.

Q -- SEGMENT REPORTING

Our reportable operating segments at December 31, 2004 include a utility energy segment and a non-utility energy segment. Additionally, our manufacturing segment was an operating segment prior to the sale of the segment in July 2004 to Pentair, Inc. We have organized our reportable operating segments based in part upon the regulatory environment in which our utility subsidiaries operate. In addition, the segments are managed separately because each business requires different technology and marketing strategies. The accounting policies of the reportable operating segments are the same as those described in Note A.

Our utility energy segment primarily includes our electric and natural gas utility operations. Our electric utility operation engages in the generation, distribution and sale of electric energy in southeastern (including metropolitan Milwaukee), east central and northern Wisconsin and in the Upper Peninsula of Michigan. Our natural gas utility operation is engaged in the purchase, distribution and sale of natural gas to retail customers and the transportation of customer-owned natural gas throughout Wisconsin. Our non-utility energy segment derives its revenues primarily from the ownership of electric power generating facilities for long-term lease to Wisconsin Electric and economic interests in other energy-related entities.

Summarized financial information concerning our reportable operating segments for each of the years ended December 31, 2004, 2003 and 2002, is shown in the following table. The segment information below includes non-cash impairment charges of $149.0 million ($96.9 million after tax or $0.81 per share) in 2004, $45.6 million ($29.7 million after tax or $0.25 per share), net of gains in 2003 and $141.5 million ($92.0 million after tax or $0.79 per share) in 2002, primarily related to the Non-Utility Energy segment (See Notes E and F). Substantially all of our long-lived assets and operations are domestic.

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				Other (a),
	Reportable Operating Segments			Corp. (c) &
	Energy			Reconciling	Total
Year Ended	Utility	Non-Utility	Manufacturing (c)	Elims. (b)	Consolidated
	(Millions of Dollars)
December 31, 2004
Operating Revenues (b)	$3,375.4	$21.6	$   -	$34.1	$3,431.1
Depreciation, Decommissioning
and Amortization	$315.5	$6.1	$   -	$5.5	$327.1
Operating Income (Loss)	$528.6	($120.4)	($3.0)	($25.4)	$379.8
Equity in Earnings (Losses)
of Unconsolidated Affiliates	$30.1	$     -	$   -	$0.8	$30.9
Interest Expense	$108.6	$14.6	$9.9	$60.3	$193.4
Income Tax Expense	$174.5	($48.1)	($5.0)	($41.1)	$80.3
Income from Discontinued Operations, Net	$   -	$     -	$31.9	$152.3	$184.2
Net Income (Loss)	$283.9	($86.6)	$26.6	$82.5	$306.4
Capital Expenditures	$426.5	$191.0	$10.7	$19.3	$647.5
Total Assets	$8,775.3	$506.8	$    -	$283.3	$9,565.4
December 31, 2003
Operating Revenues (b)	$3,263.9	$14.4	$   -	$30.0	$3,308.3
Depreciation, Decommissioning
and Amortization	$316.2	$7.4	$   -	$6.2	$329.8
Operating Income (Loss)	$544.1	($61.5)	($1.7)	$1.3	$482.2
Equity in Earnings (Losses)
of Unconsolidated Affiliates	$25.9	($8.9)	$  -	$5.2	$22.2
Interest Expense	$104.1	$17.7	$18.6	$73.4	$213.8
Income Tax Expense	$182.6	($35.2)	($7.0)	($30.2)	$110.2
Income from Discontinued Operations, Net	$     -	$    -	$43.9	$  -	$43.9
Net Income (Loss)	$294.1	($52.7)	$30.8	($27.9)	$244.3
Capital Expenditures	$455.6	$163.6	$10.4	$29.8	$659.4
Total Assets	$8,303.9	$397.6	$938.0	$375.0	$10,014.5
December 31, 2002
Operating Revenues (b)	$2,852.1	$167.2	$    -	$31.7	$3,051.0
Depreciation, Decommissioning
and Amortization	$308.3	$5.1	$    -	$5.1	$318.5
Operating Income (Loss)	$562.1	($132.0)	($1.4)	($28.3)	$400.4
Equity in Earnings (Losses)
of Unconsolidated Affiliates	$23.4	($8.5)	$    -	$8.0	$22.9
Interest Expense	$107.3	$25.9	$16.2	$77.7	$227.1
Income Tax Expense	$184.1	($49.3)	($6.1)	($43.4)	$85.3
Income from Discontinued Operations, Net	$  -	$    -	$35.3	$   -	$35.3
Net Income (Loss)	$295.2	($94.4)	$24.0	($57.8)	$167.0
Capital Expenditures	$405.4	$92.7	$15.0	$43.7	$556.8
Total Assets	$7,820.5	$348.7	$925.5	$371.2	$9,465.9

(a)	Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark, non-utility investment in renewable energy and recycling technologies by Minergy as well as interest on corporate debt and in 2004, the gain on the sale of the manufacturing segment.
(b)	An elimination for intersegment revenues is included in Operating Revenues of $6.8 million, $5.9 million and $3.1 million for 2004, 2003 and 2002, respectively.
(c)	The sale of our manufacturing segment was completed effective July 31, 2004. The financial information presented for the manufacturing segment in 2004 is for the seven months ended July 31, 2004. The gain on the sale of the manufacturing segment is reflected in Corporate and Other. 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.

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R -- RELATED PARTIES

American Transmission Company:   We have a 37.8% interest in ATC, a regional transmission company established in 2000 under Wisconsin legislation. During 2004, 2003 and 2002, we paid ATC $105.8 million, $94.4 million and $87.3 million, respectively, for transmission services. We also provide a variety of operational, maintenance and project management work for ATC, which are reimbursed to us by ATC.

Guardian Pipeline:   We have a one third ownership interest in Guardian Pipeline, L.L.C., which owns and operates an interstate natural gas pipeline. Wisconsin Gas has committed to purchase 650,000 dekatherms per day of capacity (approximately 87% of the pipeline's total capacity) under the terms of a 10 year transportation agreement expiring December 2012.

S -- COMMITMENTS AND CONTINGENCIES

Capital Expenditures:   We have made certain commitments in connection with 2005 capital expenditures.

Operating Leases:   We enter into long-term purchase power contracts to meet a portion of our anticipated increase in future electric energy supply needs. These contracts expire at various times through 2013. Certain of these contracts were deemed to qualify as operating leases.

Future minimum payments for the next five years and thereafter for these contracts are as follows:

	(Millions of
	Dollars)
2005	$50.4
2006	50.0
2007	49.3
2008	33.8
2009	20.8
Thereafter	66.1
	$270.4

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

We have a program of comprehensive environmental remediation planning for former manufactured gas plant sites and coal-ash disposal sites. We perform ongoing assessments of manufactured gas plant sites and related disposal sites previously used by Wisconsin Electric or Wisconsin Gas, and coal ash disposal/landfill sites used by Wisconsin Electric, as discussed below. We are working with the Wisconsin Department of Natural Resources in our investigation and remediation planning. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.

Manufactured Gas Plant Sites:   We have identified fourteen sites at which Wisconsin Electric, Wisconsin Gas, or a predecessor company historically owned or operated a manufactured gas plant. We have completed planned remediation activities at five of those sites. Remediation at additional sites is currently being performed, and other sites are being investigated or monitored. We have identified additional sites that may have been impacted by historical manufactured gas plant activities. Based upon ongoing analysis, we estimate that the future costs for detailed site investigation and future remediation costs may range from $25-$50 million over the next ten years. This estimate is dependent upon several variables including, among other things, the extent of remediation, changes in technology and changes in regulation. As of December 31, 2004, we have established reserves of $26.6 million related to future remediation costs.

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The PSCW has allowed Wisconsin utilities, including Wisconsin Electric and Wisconsin Gas, to defer the costs spent on the remediation of manufactured gas plant sites, and has allowed for these costs to be recovered in rates over five years. Accordingly, we have recorded a regulatory asset for remediation costs.

Ash Landfill Sites:   Wisconsin Electric aggressively seeks environmentally acceptable, beneficial uses for its coal combustion by-products. However, these coal-ash by-products have been, and to a small degree, continue to be disposed in company-owned, licensed landfills. Some early designed and constructed landfills may allow the release of low levels of constituents resulting in the need for various levels of monitoring or adjusting. Where Wisconsin Electric has become aware of these conditions, efforts have been expended to define the nature and extent of any release, and work has been performed to address these conditions. The costs of these efforts are included in the fuel costs of Wisconsin Electric. During 2004, 2003 and 2002, Wisconsin Electric incurred $1.8 million, $2.1 million and $2.1 million, respectively, in coal-ash remediation expenses. As of December 31, 2004 we have no reserves established related to ash landfill sites.

EPA Information Requests:   Wisconsin Electric received a request for information in December 2000 from the United States Environmental Protection Agency (EPA) regional offices pursuant to Section 114(a) of the Clean Air Act and a supplemental request in December 2002. In April 2003, Wisconsin Electric and EPA announced that a consent decree had been reached which resolved all issues related to this matter. In July 2003, the court granted the state of Michigan and EPA's joint motion to amend the consent decree to allow Michigan to become a party. Under the consent decree, Wisconsin Electric will significantly reduce its air emissions from its coal-fired generating facilities. The reductions will be achieved by 2013 through a combination of installing new pollution control equipment, upgrading existing equipment, and retiring certain older units. The capital cost of implementing this agreement is estimated to be approximately $600 million over the 10 ye ars ending 2013. Under the agreement with EPA, Wisconsin Electric will conduct a full scale demonstration at its Presque Isle facility, in cooperation with the United States Department of Energy (DOE), to test new mercury reduction technologies. The DOE will contribute $24.8 million in addition to the $20 to $25 million Wisconsin Electric will spend to implement this project. These steps and the associated costs are consistent with our cost projections for implementing our Wisconsin Multi-Emission Cooperative Agreement and ourPower the Future plan. Wisconsin Electric also agreed to pay a civil penalty of $3.2 million which was charged to earnings in the second quarter of 2003.

The agreement has gone through the public comment period. In October 2003, three citizen groups filed a motion with the court to intervene in the proceeding to contest the consent decree; the court granted their motion. Also, in October 2003, the government filed its response to public comments and a motion asking the court to approve the amended consent decree. The intervenor groups subsequently filed a motion requesting that the court stay the government's motion for approval of the decree to allow the intervenors to conduct discovery. Briefing was completed and the judge heard oral arguments from the parties in August 2004. In September 2004, the court granted the intervenors' request for limited discovery with respect to two facilities within our generation fleet, and ordered that discovery be completed by December 2004. Final briefing is scheduled to be concluded on February 28, 2005. Following the submission of briefs, the court may con vene additional hearings.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Wisconsin Energy Corporation:

     We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Wisconsin Energy Corporation and subsidiaries (the "Company") as of December 31, 2004 and 2003, and the related consolidated statements of income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2004.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.

     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

     In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

     As described in Note L, on January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations."

     We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2004, based on the criteria established inInternal Control -Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 9, 2005 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

/s/DELOITTE & TOUCHE LLP
Deloitte & Touche LLP

Milwaukee, Wisconsin
February 9, 2005

35

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 To the Board of Directors and Stockholders of Wisconsin Energy Corporation:

     We have audited management's assessment, included in the accompanying Management's Report on Internal Control Over Financial Reporting, that Wisconsin Energy Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2004, based on the criteria established inInternal Control-Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.  The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting.  Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

     We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinions.

     A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of th e company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

     Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.  Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

     In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established inInternal Control-Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.  Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established inInternal Control-Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.

     We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and consolidated statement of capitalization as of December 31, 2004, and the related consolidated statements of income, stockholders' equity, and cash flows for the year ended December 31, 2004 of the Company and our report dated February 9, 2005 expressed an unqualified opinion on those financial statements.

/s/DELOITTE & TOUCHE LLP
Deloitte & Touche LLP

Milwaukee, Wisconsin
February 9, 2005

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