Wisconsin Electric Power Company PFD 3.60% (WELPP) 10-Q 2005 Q2 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-Q

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

For the Quarterly Period EndedJune 30, 2005

Commission	Registrant; State of Incorporation		IRS Employer
File Number	Address; and Telephone Number		Identification No.
001-01245	WISCONSIN ELECTRIC POWER COMPANY		39-0476280
		(A Wisconsin Corporation)
		231 West Michigan Street
		P.O. Box 2046
		Milwaukee, WI 53201
		(414) 221-2345

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

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).    Yes [  ]    No [X]

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

Common Stock, $10 Par Value, 33,289,327 shares outstanding.

All of the common stock of Wisconsin Electric Power Company is owned by Wisconsin Energy Corporation.

		WISCONSIN ELECTRIC POWER COMPANY
		FORM 10-Q REPORT FOR THE QUARTER ENDED JUNE 30, 2005
		TABLE OF CONTENTS
Item			Page
	Introduction ...........................................................................................................................		3
	Part I -- Financial Information
1.	Financial Statements
	Consolidated Condensed Income Statements .....................................................................		4
	Consolidated Condensed Balance Sheets ..........................................................................		5
	Consolidated Condensed Statements of Cash Flows ..........................................................		6
	Notes to Consolidated Condensed Financial Statements ....................................................		7
2.	Management's Discussion and Analysis of
	Financial Condition and Results of Operations .................................................................		11
3.	Quantitative and Qualitative Disclosures About Market Risk ..................................................		33
4.	Controls and Procedures .......................................................................................................		33
	Part II -- Other Information
1.	Legal Proceedings .................................................................................................................		34
6.	Exhibits .................................................................................................................................		35
	Signatures .............................................................................................................................		36

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INTRODUCTION

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

We conduct our operations primarily in three operating segments: an electric utility segment, a natural gas utility segment and a steam utility segment. We serve approximately 1,086,000 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 441,000 gas customers in Wisconsin and about 460 steam customers in metro Milwaukee, Wisconsin. For further financial information about our business segments, see Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 7 -- Segment Information in the Notes to Consolidated Condensed Financial Statements.

Wisconsin Energy is also the parent company of Wisconsin Gas LLC (Wisconsin Gas), a natural gas distribution utility, which serves customers throughout Wisconsin; Edison Sault Electric Company (Edison Sault), an electric utility which serves customers in the Upper Peninsula of Michigan; and W.E. Power, LLC (We Power), an unregulated company that was formed in 2001 to design, construct, own, finance and lease to us the new generating capacity included in Wisconsin Energy'sPower the Future strategy, which is described further in this report. We have combined common functions with Wisconsin Gas and operate under the trade name of "We Energies".

Other:   Bostco LLC (Bostco) is our non-utility subsidiary that develops and invests in real estate. As of June 30, 2005, Bostco had $41.1 million of assets.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). We have condensed or omitted some information and note disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles pursuant to these rules and regulations. Our financial statements should be read in conjunction with the financial statements and notes thereto included in our 2004 Annual Report on Form 10-K.

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PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
	WISCONSIN ELECTRIC POWER COMPANY
	CONSOLIDATED CONDENSED INCOME STATEMENTS
	(Unaudited)
				Three Months Ended June 30		Six Months Ended June 30
				2005	2004	2005	2004
				(Millions of Dollars)
	Operating Revenues			$657.2	$583.8	$1,416.9	$1,325.5
	Operating Expenses
		Fuel and purchased power		185.8	150.6	343.1	293.1
		Cost of gas sold		60.5	55.2	234.9	217.6
		Other operation and maintenance		230.5	217.7	446.8	427.1
		Depreciation, decommissioning
			and amortization	68.3	69.8	138.1	133.4
		Property and revenue taxes		20.1	18.7	40.4	38.1
	Total Operating Expenses			565.2	512.0	1,203.3	1,109.3
	Operating Income			92.0	71.8	213.6	216.2
	Other Income, Net			14.1	9.3	27.7	17.9
	Interest Expense			22.6	22.8	45.2	46.1
	Income Before Income Taxes			83.5	58.3	196.1	188.0
	Income Taxes			31.8	21.6	73.7	71.3
	Net Income			51.7	36.7	122.4	116.7
	Preferred Stock Dividend
	Requirement			0.3	0.3	0.6	0.6
	Earnings Available
		for Common Stockholder		$51.4	$36.4	$121.8	$116.1
	The accompanying Notes to Consolidated Condensed Financial Statements are an integral part of
		these financial statements.

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WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED CONDENSED BALANCE SHEETS
			(Unaudited)
			June 30, 2005		December 31, 2004
			(Millions of Dollars)
Assets
Property, Plant and Equipment
	In service		$6,920.7		$6,873.0
	Accumulated depreciation		(2,709.1	)	(2,637.9	)
			4,211.6		4,235.1
	Construction work in progress		227.8		153.6
	Leased facilities, net		96.1		98.9
	Nuclear fuel, net		95.7		85.0
		Net Property, Plant and Equipment	4,631.2		4,572.6
Investments
	Nuclear decommissioning trust		741.6		737.8
	Equity investment in transmission affiliate		169.1		165.3
	Other		0.4		0.5
		Total Investments	911.1		903.6
Current Assets
	Cash and cash equivalents		15.8		26.1
	Accounts receivable		251.4		253.3
	Accrued revenues		142.2		164.5
	Materials, supplies and inventories		232.0		273.8
	Other		81.2		88.3
		Total Current Assets	722.6		806.0
Deferred Charges and Other Assets
	Regulatory assets		692.4		644.7
	Other		96.9		123.4
		Total Deferred Charges and Other Assets	789.3		768.1
Total Assets			$7,054.2		$7,050.3
Capitalization and Liabilities
Capitalization
	Common equity		$2,238.6		$2,204.2
	Preferred stock		30.4		30.4
	Long-term debt		1,694.1		1,683.1
		Total Capitalization	3,963.1		3,917.7
Current Liabilities
	Long-term debt due currently		19.4		23.7
	Short-term debt		171.6		189.5
	Accounts payable		244.1		249.8
	Accrued liabilities		119.6		112.2
	Other		89.4		93.0
		Total Current Liabilities	644.1		668.2
Deferred Credits and Other Liabilities
	Asset retirement obligations		316.0		762.2
	Regulatory liabilities		1,024.4		600.2
	Deferred income taxes - long-term		530.5		548.5
	Other		576.1		553.5
		Total Deferred Credits and Other Liabilities	2,447.0		2,464.4
Total Capitalization and Liabilities			$7,054.2		$7,050.3
The accompanying Notes to Consolidated Condensed Financial Statements are an integral part of
	these financial statements.

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WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
				Six Months Ended June 30
				2005		2004
				(Millions of Dollars)
Operating Activities
	Net income			$122.4		$116.7
	Reconciliation to cash
		Depreciation, decommissioning and amortization		148.7		143.9
		Nuclear fuel expense amortization		10.1		10.7
		Equity in earnings of unconsolidated affiliate		(15.1	)	(12.7	)
		Distributions from unconsolidated affiliate		11.3		9.8
		Deferred income taxes and investment tax credits, net		(14.1	)	21.2
		Deferred costs, net		(47.7	)	(46.2	)
		Accrued income taxes, net		5.0		(1.0	)
		Change in -	Accounts receivable and accrued revenues	24.2		54.4
			Inventories	41.8		40.9
			Other current assets	7.1		20.3
			Accounts payable	(4.8	)	1.1
			Other current liabilities	(7.2	)	26.3
		Other		23.5		24.8
Cash Provided by Operating Activities				305.2		410.2
Investing Activities
	Capital expenditures			(190.5	)	(148.8	)
	Nuclear fuel			(12.6	)	(0.4	)
	Nuclear decommissioning funding			(8.8	)	(8.8	)
	Other			(1.2	)	(13.2	)
Cash Used in Investing Activities				(213.1	)	(171.2	)
Financing Activities
	Dividends paid on common stock			(89.8	)	(89.8	)
	Dividends paid on preferred stock			(0.6	)	(0.6	)
	Issuance of long-term debt			21.4		17.4
	Retirement of long-term debt			(15.5	)	(13.8	)
	Change in short-term debt			(17.9	)	(164.4	)
Cash Used in Financing Activities				(102.4	)	(251.2	)
Change in Cash and Cash Equivalents				(10.3	)	(12.2	)
Cash and Cash Equivalents at Beginning of Period				26.1		20.0
Cash and Cash Equivalents at End of Period				$15.8		$7.8
Supplemental Information - Cash Paid For
	Interest (net of amount capitalized)			$52.1		$51.9
	Income taxes (net of refunds)			$84.6		$45.6
The accompanying Notes to Consolidated Condensed Financial Statements are an integral part of
	these financial statements.

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WISCONSIN ELECTRIC POWER COMPANY
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Unaudited)

 1. -- GENERAL INFORMATION

Our accompanying unaudited consolidated condensed financial statements should be read in conjunction with Item 8, Financial Statements and Supplementary Data, in our 2004 Annual Report on Form 10-K. In the opinion of management, we have included all adjustments, normal and recurring in nature, necessary to a fair presentation of the results of operations, cash flows and financial position in the accompanying income statements, statements of cash flows and balance sheets. The results of operations for the three and six months ended June 30, 2005 are not necessarily indicative of the results which may be expected for the entire fiscal year 2005 because of seasonal and other factors.

We have modified certain cash flow presentations. Prior year financial statement amounts have been reclassified to conform to their current year presentation.

 2. -- VARIABLE INTEREST ENTITIES

In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation 46, Consolidation of Variable Interest Entities (FIN 46). This standard requires an enterprise that is the primary beneficiary of a variable interest entity to consolidate that entity. We applied the Interpretation to any existing interests in variable interest entities beginning in the third quarter of 2003. In October 2003, the FASB deferred the adoption of FIN 46 for all entities commonly referred to as special-purpose entities to the first reporting period ending after December 15, 2003. In December 2003, the FASB issued FIN 46R, which revised FIN 46 and deferred the effective date for interests held in variable interest entities other than special purpose entities to financial statements for periods ending after March 15, 2004. We adopted FIN 46R in the first quarter of 2004.

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

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

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 3. -- ASSET RETIREMENT OBLIGATIONS

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

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

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

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

	Balance at 12/31/04	Liabilities Incurred	Liabilities Settled	Accretion	Cash Flow Revisions	Balance at 06/30/05
	(Millions of Dollars)
Asset Retirement Obligations	$762.2	$   -	($9.8)	$19.2	($455.6)	$316.0

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

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 4. -- COMMON EQUITY

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

	Six Months Ended June 30
Comprehensive Income	2005	2004
	(Millions of Dollars)
Net Income	$122.4	$116.7
Other Comprehensive Income (Loss)
Hedging	(0.1)	(0.1)
Total Other Comprehensive Income (Loss)	(0.1)	(0.1)
Total Comprehensive Income	$122.3	$116.6

 5. -- BENEFITS

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

	Pension Benefits		Other Post-retirement Benefits
	2005	2004	2005	2004
Three Months Ended June 30	(Millions of Dollars)
Net Periodic Benefit Cost
Service cost	$7.0	$6.6	$3.9	$2.6
Interest cost	14.7	15.4	4.7	3.9
Expected return on plan assets	(16.4)	(16.4)	(3.4)	(2.2)
Amortization of:
Transition (asset) obligation	-	(0.6)	0.8	0.4
Prior service cost	1.4	1.2	-	-
Actuarial loss	5.2	3.7	1.0	0.8
Net Periodic Benefit Cost	$11.9	$9.9	$7.0	$5.5
Six Months Ended June 30
Net Periodic Benefit Cost
Service cost	$15.0	$13.4	$6.6	$5.7
Interest cost	29.7	29.2	8.8	8.5
Expected return on plan assets	(32.2)	(31.3)	(4.5)	(4.0)
Amortization of:
Transition (asset) obligation	-	(1.1)	0.8	0.8
Prior service cost	2.6	2.4	-	-
Actuarial loss	8.9	6.6	2.7	2.6
Net Periodic Benefit Cost	$24.0	$19.2	$14.4	$13.6

We previously disclosed that we expect to contribute $4.5 million to fund pension benefits in 2005, none of which will be for our qualified plans since there is no minimum required by law. Contributions to other post-retirement benefit plans are discretionary.

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

9
(FSP) SFAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.

In accordance with FSP 106-2, we chose to recognize the effects of the Act retroactively effective January 1, 2004 with the impacts calculated actuarially. In January 2005, the Centers for Medicare & Medicaid Services released final regulations to implement the new prescription drug benefit under Part D of Medicare. It was determined that the employer sponsored plans meet these regulations and that the previously determined actuarial measurements do not need to be revised.

Severance Plans:   In the third and fourth quarters of 2004, we incurred $22.3 million ($13.4 million after-tax) of severance costs. The majority of the severance costs related to an enhanced severance package offered to selected management employees who voluntarily resigned in the fourth quarter of 2004. During the first six months of 2005, we made severance related payments that reduced the reserve for severance benefits from $6.6 million at December 31, 2004 to $2.2 million as of June 30, 2005.

 6. -- GUARANTEES

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

Maximum Potential Future Payments	Outstanding at June 30, 2005	Liability Recorded at June 30, 2005
$232.6	$0.1	$    -

We guarantee the potential retrospective premiums that could be assessed under our nuclear insurance program.

Postemployment benefits:   Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability, excluding severance benefits, for such benefits was $13.3 million as of June 30, 2005 and $12.0 million as of December 31, 2004.

 7. -- SEGMENT INFORMATION

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

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Wisconsin Electric	Reportable Operating Segments
Power Company	Electric	Gas		Steam	Total
	(Millions of Dollars)
Three Months Ended
June 30, 2005
Operating Revenues (a)	$567.2	$85.4	$4.6		$657.2
Operating Income (Loss)	$96.7	($2.8)	($1.9)		$92.0
June 30, 2004
Operating Revenues (a)	$499.4	$80.4	$4.0		$583.8
Operating Income (Loss)	$76.0	($2.8)	($1.4)		$71.8
Six Months Ended
June 30, 2005
Operating Revenues (a)	$1,083.9	$319.2	$13.8		$1,416.9
Operating Income	$184.4	$28.6	$0.6		$213.6
June 30, 2004
Operating Revenues (a)	$1,009.5	$303.2	$12.8		$1,325.5
Operating Income	$188.8	$26.9	$0.5		$216.2

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

 8. -- COMMITMENTS AND CONTINGENCIES

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

9. -- CAPITAL LEASE OBLIGATION -- SUBSEQUENT EVENT

On July 16, 2005, Unit 1 at the Port Washington Generating Station commenced commercial operation. We will lease this facility from We Power pursuant to a lease approved by the PSCW. In July 2005, we recorded a capital lease obligation on our balance sheet for approximately $330 million. We also recorded additional property, plant and equipment for approximately the same amount.

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

Cautionary Factors Regarding Forward - Looking Statements:   Certain statements contained herein are "Forward-Looking Statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-Looking Statements include, among other things, statements regarding management's expectations and projections regarding completion of construction projects, regulatory matters, fuel costs, sources of electric energy supply, gas deliveries, remediation costs, environmental and other capital expenditures, liquidity and capital resources and other matters. Also, Forward-Looking Statements may be identified by reference to a future period or periods or by the use of forward looking

11
terminology such as "anticipates," "believes," "estimates," "expects," "forecasts," "intends," "may," "objectives," "plans," "possible," "potential," "projects" or similar terms or variations of these terms. Actual results may differ materially from those set forth in Forward-Looking Statements as a result of certain risks and uncertainties, including but not limited to, those risks and uncertainties described under the heading "Cautionary Factors" in this Item 2, as well as other matters described under the heading "Factors Affecting Results, Liquidity and Capital Resources" in this Item 2, and other risks and uncertainties detailed from time to time in our filings with the SEC or otherwise described throughout this document.

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

EARNINGS

We had net income of $51.7 million for the second quarter of 2005, an increase of $15.0 million or 40.9% from the second quarter of 2004. Increased net income primarily reflects a weather-related increase in electric sales during 2005. A more detailed analysis of our financial results follows.

Electric Utility Revenues and Sales

The following table compares our electric utility operating revenues and megawatt-hour sales by customer class during the second quarter of 2005 with similar information for the second quarter of 2004 including favorable (better (B)) or unfavorable (worse (W)) variances.

	Three Months Ended June 30
	Electric Revenues			Megawatt-Hour Sales
Electric Utility Operations	2005	B (W)	2004	2005	B (W)	2004
	(Millions of Dollars)			(Thousands)
Operating Revenues
Residential	$196.5	$31.9	$164.6	1,996.2	216.2	1,780.0
Small Commercial/Industrial	180.8	20.3	160.5	2,158.1	90.2	2,067.9
Large Commercial/Industrial	156.0	18.3	137.7	2,908.9	25.3	2,883.6
Other-Retail/Municipal	24.0	2.6	21.4	589.3	58.6	530.7
Resale-Utilities	7.0	0.6	6.4	138.2	(25.2)	163.4
Other Operating Revenues	2.9	(5.9)	8.8	-	-	-
Total Operating Revenues	$567.2	$67.8	$499.4	7,790.7	365.1	7,425.6
Weather -- Degree Days (a)
Cooling (178 Normal)				237	146	91

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

During the second quarter of 2005, total electric utility operating revenues increased by $67.8 million or 13.6% when compared with the second quarter of 2004. This net increase primarily reflected pricing increases of approximately $38.5 million. The most significant impact to rates was the March 2005 interim order received by us from the PSCW authorizing an annualized increase in electric rates of approximately $114.9 million due to the increased costs of fuel and purchased power as a result of customer growth and the increase in the reliance upon natural gas as a fuel source. A similar rate increase was not in effect in the second quarter of 2004. For further information regarding rates see

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Item 2. Management's Discussion and Analysis - Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters.

We estimate that warm summer weather positively impacted electric sales by $22.3 million during the second quarter of 2005 as compared to the second quarter of 2004. As measured by cooling degree days the second quarter of 2005 was 160.4% warmer than the same period in 2004, increasing cooling load sales to residential customers who are more weather sensitive and contribute higher margins than other customer classes. Residential sales volumes increased 12.1% in the second quarter of 2005 as compared to the same period in 2004. Total electric megawatt-hour sales volumes increased by 365.1 thousand megawatt-hours or 4.9% during the second quarter of 2005 compared with the same period in 2004.

Fuel and Purchased Power

Total fuel and purchased power expenses increased by $35.2 million or 23.4% when compared to the second quarter of 2004. This increase was due to (1) increased megawatt-hour sales, (2) the reduced availability of coal-fired generation due to a higher number of unit outages in the second quarter of 2005 as compared to 2004 and the retirement of the remaining coal-fired generating units at Port Washington Power Plant in September 2004 and (3) the higher cost of purchased energy prices. The cost of purchased energy, for the second quarter of 2005 was $58.48 per megawatt-hour, 59.2% higher than 2004. Higher gas prices and warmer June weather were the primary drivers of the increased cost of purchased energy.

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

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

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Gas Utility Revenues, Gross Margin and Therm Deliveries

A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the second quarter of 2005 with similar information for the second quarter of 2004. We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under gas cost recovery mechanisms.

		Three Months Ended June 30
		2005	B (W)	2004
	(Millions of Dollars)
Operating Revenues		$85.4	$5.0	$80.4
Cost of Gas Sold		60.5	(5.3)	55.2
Gross Margin		$24.9	($0.3)	$25.2

For the three months ended June 30, 2005, gas utility gross margin decreased by $0.3 million or 1.2% when compared to the three months ended June 30, 2004. The following table compares our gas utility gross margin and natural gas therm deliveries by customer class during the second quarter of 2005 with similar information for the second quarter of 2004.

	Three Months Ended June 30
	Gross Margin			Therm Deliveries
Gas Utility Operations	2005	B (W)	2004	2005	B (W)	2004
	(Millions of Dollars)			(Millions)
Customer Class
Residential	$15.8	($0.3)	$16.1	43.7	(2.8)	46.5
Commercial/Industrial	5.0	(0.1)	5.1	26.7	(0.3)	27.0
Interruptible	0.1	-	0.1	1.0	(0.2)	1.2
Total Retail Gas Sales	20.9	(0.4)	21.3	71.4	(3.3)	74.7
Transported Gas	3.5	-	3.5	90.9	26.0	64.9
Other	0.5	0.1	0.4	-	-	-
Total	$24.9	($0.3)	$25.2	162.3	22.7	139.6
Weather -- Degree Days (a)
Heating (946 Normal)				891	(72)	963

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

Total therm deliveries were 16.3% higher during the second quarter of 2005 primarily due to increased transport gas deliveries of 26.0 million therms. Our margins on transported gas are significantly lower than our margins for retail gas sales. The increase in volume of transport gas sales was due to a higher amount of electric generation from natural gas within our service territory. Increased transport sales were offset in part due to decreased heating load sales to residential customers who are more weather sensitive and contribute higher margins than other customer classes. As measured by heating degree days, the second quarter of 2005 was 7.5% warmer than the second quarter of 2004.

Other Operation and Maintenance Expenses

Other operation and maintenance expenses increased by $12.8 million or 5.9% during the second quarter of 2005 compared with the second quarter of 2004. The largest increase relates to $11.4 million of costs related to the Port Washington Generating Station lease and conservation programs, all of which were recognized in connection with the May 2004 and May 2005 limited rate increases which provided revenues on virtually a dollar for dollar basis. Bad debt expense increased $2.5 million. In addition, we

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estimate that employee costs were down approximately $4.9 million due to the voluntary severance programs that were implemented in the third and fourth quarters of 2004.

Nuclear costs decreased $7.4 million between the comparative periods due to reduced outage costs, primarily as a result of the elimination in 2005 of the reactor head inspection required on Point Beach Unit 1 during the scheduled outage in the second quarter of 2004. In the second quarter of 2005, we replaced the reactor vessel head during the scheduled outage on Point Beach Unit 2, and therefore we are no longer required to perform the extensive reactor head inspections. We plan to replace the reactor vessel head on Unit 1 over the third and fourth quarters of 2005 during its planned outage.

Depreciation, Decommissioning and Amortization

Depreciation, Decommissioning and Amortization expenses decreased by $1.5 million or 2.1% during the second quarter of 2005. The variance is due primarily to a decommissioning expense reduction of $3.7 million to reflect the regulatory treatment of income taxes associated with gains in decommissioning trusts. This reduction was offset in part by depreciation on increased plant balances between the comparative periods.

Other Income, Net

Other income, net increased by $4.8 million in the second quarter of 2005 compared to the second quarter of 2004. This increase is primarily due to an increase of $1.0 million in our interest in the earnings of our transmission affiliate during the second quarter of 2005, the recognition of additional carrying costs on deferred electric transmission costs of $1.5 million and an increase of $1.9 million for equity-related Allowance for Funds Used During Construction (AFUDC) due to a higher average balance of AFUDC-qualifying utility construction projects between the comparative periods.

Income Taxes

For the second quarter of 2005, our effective tax rate was 38.1% compared to 37.0% for the second quarter of 2004.

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

EARNINGS

We had net income of $122.4 million for the first six months of 2005, an increase of $5.7 million or 4.9% from the first six months of 2004. Net income increased primarily due to a weather-related increase in electric sales during 2005. A more detailed analysis of our financial results follows.

Electric Utility Revenues and Sales

The following table compares our electric utility operating revenues and megawatt-hour sales by customer class during the first six months of 2005 with similar information for the first six months of 2004 including favorable (better (B)) or unfavorable (worse (W)) variances.

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	Six Months Ended June 30
	Electric Revenues			Megawatt-Hour Sales
Electric Utility Operations	2005	B (W)	2004	2005	B (W)	2004
	(Millions of Dollars)			(Thousands)
Operating Revenues
Residential	$382.8	$35.0	$347.8	4,003.6	162.4	3,841.2
Small Commercial/Industrial	343.1	28.4	314.7	4,310.1	114.5	4,195.6
Large Commercial/Industrial	286.3	23.0	263.3	5,617.0	(18.5)	5,635.5
Other-Retail/Municipal	48.2	7.6	40.6	1,225.2	145.8	1,079.4
Resale-Utilities	12.5	(13.6)	26.1	295.0	(316.6)	611.6
Other Operating Revenues	11.0	(6.0)	17.0	-	-	-
Total Operating Revenues	$1,083.9	$74.4	$1,009.5	15,450.9	87.6	15,363.3
Weather -- Degree Days (a)
Heating (4,212 Normal)				4,179	(149)	4,328
Cooling (179 Normal)				237	146	91

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

During the first six months of 2005, total electric utility operating revenues increased by $74.4 million or 7.4% when compared with the first six months of 2004. This net increase primarily reflected pricing increases of approximately $58.2 million and warm summer weather that was offset, in part, by decreased opportunity sales. The most significant impacts to rates were (1) the March 2005 interim order we received from the PSCW authorizing an annualized increase in electric rates of approximately $114.9 million due to the increased costs of fuel and purchased power as a result of customer growth and the increase in the reliance upon natural gas as a fuel source and (2) the May 2004 order we received from the PSCW authorizing an annualized increase in electric rates of approximately $59.0 million to cover construction costs associated with Wisconsin Energy'sPower the Future program and to recover low income uncollectible expenses transferred to Wisconsin's public benefi ts fund. For further information regarding rates see Item 2. Management's Discussion and Analysis - Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters.

Total electric megawatt-hour sales volumes increased by 87.6 thousand megawatt-hours or 0.6% during the first six months of 2005 compared with the same period in 2004. Sales volumes to other utilities were down 51.8% due to a decrease in availability of opportunity sales. As measured by cooling degree days, the first six months of 2005 were 160.4% warmer than the first six months of 2004, increasing cooling load sales to residential customers who are more weather sensitive and contribute higher margins than other customer classes. We estimate that weather had a favorable impact on operating revenues of approximately $20.9 million for the six months ended June 30, 2005 as compared to the first six months ended June 30, 2004.

Fuel and Purchased Power

Total fuel and purchased power expenses increased by $50.0 million or 17.1% when compared to the first six months of 2004. This increase was due to (1) increased megawatt-hour sales, (2) the reduced availability of coal-fired generation due to a higher number of unit outages in the second quarter of 2005 as compared to 2004 and the retirement of the remaining coal-fired generating units at Port Washington Power Plant in September, 2004 and (3) the higher cost of purchased energy prices. The cost of purchased energy, for the first six months of 2005 was $53.09 per megawatt-hour, 44.5% higher than the same period in 2004. Higher gas prices and warmer June weather were the primary drivers of the increased cost of purchased energy.

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

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

Gas Utility Revenues, Gross Margin and Therm Deliveries

A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the first six months of 2005 with similar information for the first six months of 2004. We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under gas cost recovery mechanisms.

		Six Months Ended June 30
		2005	B (W)	2004
	(Millions of Dollars)
Operating Revenues		$319.2	$16.0	$303.2
Cost of Gas Sold		234.9	(17.3)	217.6
Gross Margin		$84.3	($1.3)	$85.6

For the six months ended June 30, 2005, gas utility gross margin decreased by $1.3 million or 1.5% when compared to the six months ended June 30, 2004. The following table compares our gas utility gross margin and natural gas therm deliveries by customer class during the first half of 2005 with similar information for the first half of 2004.

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	Six Months Ended June 30
	Gross Margin			Therm Deliveries
Gas Utility Operations	2005	B (W)	2004	2005	B (W)	2004
	(Millions of Dollars)			(Millions)
Customer Class
Residential	$55.3	($0.8)	$56.1	207.3	(6.7)	214.0
Commercial/Industrial	19.1	(0.4)	19.5	119.1	(3.3)	122.4
Interruptible	0.3	-	0.3	3.1	(0.7)	3.8
Total Retail Gas Sales	74.7	(1.2)	75.9	329.5	(10.7)	340.2
Transported Gas	8.4	(0.2)	8.6	182.9	22.9	160.0
Other	1.2	0.1	1.1	0.3	0.3	-
Total	$84.3	($1.3)	$85.6	512.7	12.5	500.2
Weather -- Degree Days (a)
Heating (4,212 Normal)				4,179	(149)	4,328

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

Our margins on transported gas are significantly lower than our margins for retail gas sales. Transport therm deliveries increased 14.3% due to a higher amount of electric generation from natural gas within our service territory. The increased transport sales were offset, in part, by a decrease in residential therm deliveries of 3.1% due to warmer weather. Our residential customers are more weather sensitive and contribute higher margins than other customer classes. As measured by heating degree days, the first six months of 2005 were 3.4% warmer than the first six months of 2004.

Other Operation and Maintenance Expenses

Other operation and maintenance expenses increased by $19.7 million or 4.6% during the first half of 2005 compared with the first half of 2004. The largest increase relates to $24.9 million of costs related to the Port Washington Generating Station lease and conservation programs, all of which were recognized in connection with the May 2004 and May 2005 limited rate increases which provided revenues on virtually a dollar for dollar basis. Benefits costs have decreased approximately $3.3 million between the comparative periods. We estimate that employee costs were down approximately $10.0 million due to the voluntary severance programs that were implemented in the third and fourth quarters of 2004. Nuclear costs decreased $5.7 million between the comparative periods due to reduced outage costs, primarily as a result of the elimination in 2005 of the reactor head inspection required on Point Beach Unit 1 during the scheduled outage in the second quarter of 2004. In the second quarter of 2005, we replaced the reactor vessel head during the scheduled outage on Point Beach Unit 2, and therefore we are no longer required to perform the extensive reactor head inspections. We plan to replace the reactor vessel head on Unit 1 over the third and fourth quarters of 2005 during its planned outage.

Depreciation, Decommissioning and Amortization

Depreciation, Decommissioning and Amortization expenses increased by $4.7 million or 3.5% during the first six months of 2005. The variance is due primarily to a difference in the amount recognized for a decommissioning expense reduction to reflect the regulatory treatment of income taxes associated with gains in decommissioning trusts. The reduction recognized in the first six months of 2004 was $7.7 million compared with the $3.7 million reduction recognized in the same period in 2005.

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Other Income, Net

Other income, net increased by $9.8 million in the first six months of 2005 compared to the first six months of 2004. This increase is primarily due to an increase of $2.4 million in our interest in the earnings of our transmission affiliate during the second quarter of 2005, the recognition of additional carrying costs on deferred electric transmission costs of $2.9 million and an increase of $3.3 million for allowance for funds used during construction due to a higher average balance of AFUDC -qualifying utility construction projects between the comparative periods.

Income Taxes

For the first six months of 2005, our effective tax rate was 37.6% compared to 37.9% for the first six months of 2004.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOWS

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

	Six Months Ended June 30
Wisconsin Electric Power Company	2005	2004
	(Millions of Dollars)
Cash Provided by (Used in)
Operating Activities	$305.2	$410.2
Investing Activities	($213.1)	($171.2)
Financing Activities	($102.4)	($251.2)

Operating Activities

Cash provided by operating activities decreased to $305.2 million during the first six months of 2005 compared with $410.2 million during the same period in 2004. This variance was due to an increase in income taxes paid offset, in part, by a decrease in working capital requirements.

Investing Activities

During the first six months of 2005, we invested a total of $213.1 million in our business compared to $171.2 million during the same period in 2004. This increase is primarily related to capital expenditures to facilitate compliance with the U.S. Environmental Protection Agency (EPA) consent decree (See Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters). In addition, expenditures associated with nuclear fuel purchases were higher during the first six months of 2005.

Financing Activities

During the six months ended June 30, 2005, we used $102.4 million for financing activities compared with using $251.2 million for financing activities during the first six months of 2004. This variance is

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primarily due to the $160.8 million reduction in total debt during the first six months of 2004 compared to a $12.0 million reduction in total debt during the first six months of 2005.

CAPITAL RESOURCES AND REQUIREMENTS

Capital Resources

We anticipate meeting our capital requirements during the remaining six months of 2005 primarily through internally generated funds and short-term borrowings, supplemented by the issuance of intermediate or long-term debt securities depending on market conditions and other factors. Beyond 2005, we anticipate meeting our capital requirements through internally generated funds supplemented, when required, by the issuance of debt securities.

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

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

Our credit agreements provide liquidity support for our obligations with respect to commercial paper.

As of June 30, 2005, we have approximately $352.0 million of available unused lines of bank back-up credit facilities on a consolidated basis. On June 30, 2005, we had approximately $171.6 million of total consolidated short-term debt outstanding.

We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. The following table summarizes such facilities at June 30, 2005:

Total Facility	Letters of Credit	Credit Available	Facility Maturity	Facility Term
	(Millions of Dollars)
$250.0	$23.0	$227.0	June-2007	3 year
$125.0	$ -	$125.0	Nov-2007	3 year

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

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Capitalization Structure	June 30, 2005		December 31, 2004
	(Millions of Dollars)
Common Equity	$2,238.6	53.9%	$2,204.2	53.4%
Preferred Stock	30.4	0.7%	30.4	0.7%
Long-Term Debt (including
current maturities)	1,713.5	41.3%	1,706.8	41.3%
Short-Term Debt	171.6	4.1%	189.5	4.6%
Total	$4,154.1	100.0%	$4,130.9	100.0%

Access to capital markets at a reasonable cost is determined in large part by credit quality. The following table summarizes the ratings of our debt securities and preferred stock by Standard & Poors Corporation (S&P), Moody's Investors Service (Moody's) and Fitch Ratings (Fitch) as of June 30, 2005.

	S&P	Moody's	Fitch
Commercial Paper	A-2	P-1	F1
Secured Senior Debt	A-	Aa3	AA-
Unsecured Debt	A-	A1	A+
Preferred Stock	BBB	A3	A

On March 29, 2005, S&P affirmed our security ratings and changed our security rating outlook from stable to negative. The security rating outlook assigned by Moody's and Fitch is stable.

We believe these security ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agencies only. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell or hold securities, but rather an indication of creditworthiness. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating should be evaluated independently of any other rating.

Capital Requirements

Capital requirements during the remainder of 2005 are expected to be principally for capital expenditures and nuclear fuel. Our 2005 annual consolidated capital expenditure budget, excluding the purchase of nuclear fuel, is approximately $460.0 million.

Off-Balance Sheet Arrangements:   We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including financial guarantees and letters of credit which support commodity contracts and other payment obligations. We continue to believe that these agreements do not have, and are not reasonably likely to have, a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors. For further information, see Note 6 -- Guarantees in the Notes to Consolidated Condensed Financial Statements.

We have identified three tolling and purchased power agreements with third parties but have been unable to determine if we are the primary beneficiary of any of these three variable interest entities as defined by FASB Interpretation 46, Consolidation of Variable Interest Entities (FIN 46). As a result, we do not consolidate these entities. Instead, we account for one of these contracts as a capital lease and for the other two contracts as operating leases. We have included our contractual obligations under all three of these contracts in our evaluation of Contractual Obligations/Commercial Commitments discussed below.

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For additional information, see Note 2 -- Variable Interest Entities in the Notes to Consolidated Condensed Financial Statements.

Contractual Obligations/Commercial Commitments:    Our total contractual obligations and other commercial commitments are approximately $5.9 billion as of June 30, 2005 compared with $5.6 billion as of December 31, 2004. This increase primarily reflects purchase obligations under new coal supply contracts. On July 16, 2005, Port Washington Unit 1 became operational, thus significantly increasing our contractual obligations.

FACTORS AFFECTING RESULTS, LIQUDITY AND CAPITAL RESOURCES

MARKET RISKS AND OTHER SIGNIFICANT RISKS

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

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

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

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

Credit Rating Risk:   We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. We do have certain agreements in the form of commodity and energy services contracts and employee benefit plans that could require, in the event of a credit ratings change to below investment grade, a termination payment if

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collateral is not provided or an accelerated payment. At June 30, 2005, we estimate that the potential payments under these agreements that could result from credit rating downgrades totaled approximately $72.9 million.

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

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

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

Power the Future

Under Wisconsin Energy'sPower the Future strategy, we expect to meet a significant portion of our future generation needs through new plants that are being constructed by We Power. The new plants will be leased to us by We Power under long-term leases, and we expect to recover the lease payments in our electric rates.

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

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

In November 2004, a Dane County Circuit Court judge reviewing challenges to the PSCW's order authorizing We Power to build the Elm Road units vacated the CPCN and remanded it back to the PSCW

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for additional proceedings. The Court determined that the PSCW committed errors in determining the completeness of the application and in its decision on several other points.

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

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

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

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

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

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

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

In January 2004, the WDNR issued the Air Pollution Control and Construction Permit to us for the Elm Road units. In February 2004, project opponents submitted a request for a contested case hearing with

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

UTILITY RATES AND REGULATORY MATTERS

In the state of Wisconsin, our rates are governed by an order from the PSCW issued in March 2000 in connection with the approval of the WICOR acquisition. Under this order, we are restricted from increasing Wisconsin rates for a five year period ending December 31, 2005, with certain exceptions. Under the March 2000 order, a full rate review is required by the PSCW for rates beginning on January 1, 2006. In June 2005, we filed with the PSCW a natural gas price increase request, as well as all materials for the PSCW and other parties to commence the rate review required by the March 2000 order. We requested a rate increase of $27.4 million to address the higher costs associated with adding and maintaining gas mains and infrastructure to maintain safety and reliability and certain costs related to gas in storage.

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

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

Other Limited Rate Adjustment Requests

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

2005 Fuel Recovery Filing:   In February 2005, we filed an application with the PSCW for an increase in electric rates in the amount of $114.9 million due to the increased costs of fuel and purchased power as a result of customer growth and the increase in the reliance upon natural gas as a fuel source. We

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

Other Utility Rate Matters

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

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

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

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

Nuclear Refueling Outages - 2005:   In May 2005, we requested and we received approval from the PSCW to defer replacement power costs incurred after May 30, 2005 due to the longer-than-expected outage at Point Beach Unit 2. We deferred $15.8 million of incremental purchased power costs related to

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the extended outage as of June 30, 2005. The deferral of these costs is subject to recovery in future rates. Additionally, any deferred amounts will be subject to PSCW audit. For additional information see Nuclear Operations below.

NUCLEAR OPERATIONS

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

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

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

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

INDUSTRY RESTRUCTURING AND COMPETITION

Electric Transmission and Energy Markets

Midwest ISO:   On April 1, 2005, the Midwest ISO implemented a bid-based energy market (Midwest ISO Day 2). The Midwest ISO Day 2 rules require that all market participants submit day-ahead and/or real-time bids and offers for energy at locations across the Midwest ISO region. The Midwest ISO then calculates the most efficient solution for all the bids and offers made into the market that day. The Midwest ISO is responsible for ensuring that load requirements in the region are met reliably and efficiently, and to manage congestion on the transmission system.

As part of the energy market, the Midwest ISO implemented a Locational Marginal Pricing (LMP) system, a market - based platform for valuing transmission congestion. The LMP system includes the

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ability to mitigate or eliminate congestion costs through the use of Financial Transmission Rights (FTRs). FTRs are allocated to market participants by the Midwest ISO. The first allocation of FTRs was completed for the period of April 1, 2005 through August 31, 2005. To date, our unhedged congestion charges have not been material. The FTR allocation process has been performed again for the period from September 1, 2005 to May 31, 2006. We were granted substantially all of the FTRs that we were permitted to request during the allocation process.

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

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

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

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

The FERC has ordered the elimination of through and out transmission charges for transactions between the Midwest ISO and the PJM, an RTO adjacent to the Midwest ISO that manages the transmission system extending from Northern Illinois to the Mid-Atlantic States. In addition, FERC ordered a seams elimination charge to be paid by Midwest ISO load serving entities for the period beginning December 1, 2004 until March 31, 2006, to compensate transmission owners for the loss of revenues resulting from the joining of an RTO and/or FERC's elimination of through and out transmission charges between the Midwest ISO and PJM. The FERC ordered that certain existing transmission transactions continue to pay for through and out service from December 1, 2004 until March 31, 2006. The details of the seams elimination charge and the quantification of the existing transaction charge are the subject of a hearing process initiated by FERC in a February 2005 order. A decision from the hearing process is

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expected in the second half of 2006. We are currently unable to determine the impacts on us; however we do not anticipate material financial impacts.

ENVIRONMENTAL MATTERS

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

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

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

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

The EPA issued the final Clean Air Interstate Rule (CAIR) regulations in March 2005 to facilitate the states in meeting the 8-hour ozone and PM_2.5 standards by addressing the regional transport of SO₂ and NO_x. The proposed rules would require NO_x and SO₂ emission reductions in two phases from electric generating units located in a 28-state region within the eastern United States. Wisconsin and Michigan are affected states under CAIR. The states will develop implementation plans, and until those plans are in place, it is not possible to estimate the impact. However, we believe that compliance with the NO_x and SO₂ emission reductions requirements under the agreements with the WDNR and EPA will substantially mitigate costs to comply with the CAIR rule.

In our Form 10-K for the year ended December 31, 2004, we previously disclosed that we expected to incur approximately $600 million of capital costs over the 10 years ending 2013 to comply with the EPA consent decree. There could be additional costs of compliance with the EPA consent decree should we elect to control rather than retire Units 5 and 6 at our Oak Creek Power Plant. We believe this additional cost may add approximately $150 million to $350 million to the estimate.

Mercury Emission Control Rulemaking:   As required by the 1990 amendments to the Federal Clean Air Act, the EPA issued a regulatory determination in December 2000 that utility mercury emissions

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should be regulated. The EPA issued the final Clean Air Mercury Rule (CAMR) in March 2005. The compliance dates for the federal rule is 2010 for Phase I and 2018 for Phase II. Additional expenditures will be required to meet the first and second phases of the federal rules. Because the technology is under development, it is difficult to estimate the cost. The expenditures for Phase I are not likely to be significant. We believe the range of possible expenditures for Phase II could be approximately $50 million to $200 million.

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

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

ACCOUNTING DEVELOPMENTS

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

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

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections, a replacement of APB (Accounting Principles Board) Opinion No. 20 and SFAS No. 3. This statement requires a retrospective application of direct changes in accounting principle to prior periods' financial statements, unless it is impracticable to determine the period-specific or cumulative effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. In addition, SFAS No. 154 instructs that a change in depreciation, amortization or depletion method for long-lived, non-financial assets must be recorded as a change in accounting estimate affected by a change in accounting principle. The effective date for this statement is January 1, 2006. We do not expect the adoption of SFAS No. 154 to have an impact on our consolidated financial position or results of operations.

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CRITICAL ACCOUNTING ESTIMATES

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

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

CAUTIONARY FACTORS

This report and other documents or oral presentations contain or may contain forward-looking statements made by us or on our behalf. These statements are based upon management's current expectations and are subject to risks and uncertainties that could cause our actual results to differ materially from those contemplated in the statements. Readers are cautioned not to place undue reliance on the forward-looking statements. When used in written documents or oral presentations, the terms "anticipates," "believes," "estimates," "expects," "forecasts," "intends," "may," "objectives," "plans," "possible," "potential," "projects" and similar expressions are intended to identify forward-looking statements. In addition to the assumptions and other factors referred to specifically in connection with these statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statements or otherwise affect our future results of operations and financial condit ion include, among others, the following:

• Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related or terrorism-related damage; availability of electric generating facilities; unscheduled generation outages, or unplanned maintenance or repairs; unanticipated events causing scheduled generation outages to last longer than expected; unanticipated changes in fossil fuel, nuclear fuel, purchased power, coal supply, gas supply or water supply costs or availability due to higher demand, shortages, transportation problems or other developments; nonperformance by electric energy or natural gas suppliers under existing power purchase or gas supply contracts; nuclear or environmental incidents; resolution of used nuclear fuel storage and disposal issues; electric transmission or gas pipeline system constraints; unanticipated organizational structure or key personnel changes; collective bargaining agreements with union employees or work stoppages; inflation rates; or demographic and economic factors affecting ut ility service territories or operating environment.

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• Regulatory factors such as unanticipated changes in rate-setting policies or procedures; unanticipated changes in regulatory accounting policies and practices; industry restructuring initiatives; transmission or distribution system operation and/or administration initiatives; recovery of costs of previous investments made under traditional regulation; recovery of costs associated with adoption of changed accounting standards; required changes in facilities or operations to reduce the risks or impacts of potential terrorist activities; required approvals for new construction; changes in the United States Nuclear Regulatory Commission's regulations related to Point Beach Nuclear Plant or a permanent repository for used nuclear fuel; changes in the regulations of the United States Environmental Protection Agency as well as the Wisconsin or Michigan Departments of Natural Resources, including but not limited to regulations relating to the release of emissions from fossil-fueled power plants such as carbon di oxide, sulfur dioxide, nitrogen oxide, small particulates or mercury; the siting approval process for new generation and transmission facilities; recovery of costs associated with implementation of a bid based energy market; or changes in the regulations from the Wisconsin Department of Natural Resources related to the siting approval process for new pipeline construction.

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

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

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

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

• Factors which impede execution of Wisconsin Energy'sPower the Future strategy, including receipt of necessary state and federal regulatory approvals, timely and successful resolution of legal challenges; local opposition to siting of new generating facilities, construction risks and obtaining the investment capital from outside sources necessary to implement the strategy.

• Changes in social attitudes regarding the utility and power industries.

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

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

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

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

• Authoritative generally accepted accounting principle or policy changes from such standard setting bodies as the Financial Accounting Standards Board, the Securities and Exchange Commission and the Public Company Accounting Oversight Board.

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

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

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

*****

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For information concerning market risk exposures at Wisconsin Electric Power Company, see Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations -- Factors Affecting Results, Liquidity and Capital Resources -- Market Risks and Other Significant Risks in Part I of this report and in Part I of Wisconsin Electric's Quarterly Report on Form 10-Q for the period ended March 31, 2005. For information concerning other market risk exposures, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations -- Factors Affecting Results, Liquidity and Capital Resources -- Market Risks and Other Significant Risks, in Part II of Wisconsin Electric's 2004 Annual Report on Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures:   Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of the end of the period covered by this report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act.

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

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changes in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the fiscal quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The following should be read in conjunction with Item 3, Legal Proceedings, in Part I of our 2004 Annual Report on Form 10-K and Item 1, Legal Proceedings, in Part II of our Quarterly Report on Form 10-Q for the period ended March 31, 2005.

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

UTILITY RATES AND REGULATORY MATTERS

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

Power the Future:   See Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations -- Factors Affecting Results, Liquidity and Capital Resources -- Power the Future in Part I of this report for information concerning recent PSCW and other actions related to Wisconsin Energy'sPower the Futurestrategy.

OTHER MATTERS

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

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

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

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ITEM 6. EXHIBITS

Exhibit No.

31	Rule 13a-14(a) / 15d-14(a) Certifications
31.1	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Section 1350 Certifications
32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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SIGNATURES

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

	WISCONSIN ELECTRIC POWER COMPANY
	(Registrant)
	/s/STEPHEN P. DICKSON
Date: August 4, 2005	Stephen P. Dickson, Controller, Principal Accounting Officer and duly authorized officer

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