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

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 each 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 (March 31, 2004):

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

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. Unless qualified by their context when used in this document, the terms the Company, Our, Us or We refer to Wisconsin Electric Power Company and its subsidiaries. We are an electric, gas and steam utility, which serves approximately 1,072,000 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 430,500 gas customers in Wisconsin and about 465 steam customers in metro Milwaukee, Wisconsin. We maintain our principal executive offices in Milwaukee, Wisconsin.

We conduct our operations primarily in three operating segments: an electric utility segment, a natural gas utility segment and a steam utility segment. For further financial information about our business segments, see "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 Company (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). Wisconsin Electric and Wisconsin Gas have combined common functions 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 March 31, 2004, Bostco has $45.1 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. 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 2003 Annual Report on Form 10-K.

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

Our accompanying unaudited consolidated condensed financial statements should be read in conjunction with Item 8, Financial Statements and Supplementary Data, in our 2003 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 statement of the results of operations, cash flows and financial position in the accompanying income statements, statements of cash flows and balance sheets. The results of operations for the three months ended March 31, 2004 are not necessarily indicative of the results which may be expected for the entire fiscal year 2004 because of seasonal and other factors.

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.

Upon adoption of FIN 46R in the first quarter of 2004, we evaluated several tolling and purchased power agreements with third parties and concluded that for three of these agreements, after making an exhaustive effort, we are unable to obtain the information necessary to determine whether we or the entity that owns the facility is the variable interest entity's primary beneficiary. Pursuant to the terms of two of the 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. We have approximately $788.9 million of required payments over the remaining term of the agreements, which expire in 5 to 25 years. We believe the required payments will continue to be recoverable in rates. We account for one of these agreements as a capita l lease.

We account for asset retirement obligations under Statement of Financial Accounting Standards (SFAS) 143, Accounting for Asset Retirement Obligations. SFAS 143 primarily applies to the future decommissioning costs for our Point Beach Nuclear Plant (Point Beach).

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

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

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 three months ended March 31, 2004 and 2003:

The components of our net periodic pension and other post-retirement benefit costs for the three months ended March 31, 2004 and 2003 were as follows:

We previously disclosed that we expect to contribute $3.5 million to our qualified pension plans in 2004. This contribution is expected to occur in September 2004. Any contribution in 2004 to other post-retirement benefit plans is expected to occur in December. This contribution is discretionary as these plans are not subject to any minimum regulatory funding requirements.

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. Certain accounting issues raised by the Act, such as how to account for the federal subsidy, are not explicitly addressed by SFAS 106, Employers' Accounting for Post-retirement Benefits Other Than Pensions.

The FASB issued FASB Staff Position (FSP) SFAS 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (FSP 106-1) that allows sponsors to elect to defer recognition of the effects of the Act.

We are in the process of evaluating the impact of the Act on our U.S. post-retirement health plans. During this period, in accordance with FSP 106-1, we have elected to defer recognition of the effects of the Act. Accordingly, the financial statements do not reflect the effects of the Act. Upon the issuance of final guidance on this matter by the FASB, previously issued financial statements may require restatement and future results of operations may be impacted. That accounting guidance is expected to be issued by the FASB in the second quarter of 2004.

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

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 for such benefits has not changed significantly from the $10.2 million accrual we recorded as of December 31, 2003.

Summarized financial information concerning our reportable operating segments for the three month periods ended March 31, 2004 and 2003 is shown in the following table.

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, management believes 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.

Cautionary Factors:   Certain statements contained herein are "Forward-Looking Statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-Looking Statements may be identified by reference to a future period or periods or by the use of forward looking terminology such as "may," "intends," "anticipates," "believes," "estimates," "expects," "forecasts," "objectives," "plans," "possible," "potential," "project" 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, changes in political and economic conditions, equity and bond market fluctuations, varying weather conditions, governmental regulation and supervision, as well as other risks and uncertainties detailed from time to time in our filings with the Securities and Exchange Commission (SEC) including factors described throughout this document and below in "Factors Affecting Results, Liquidity and Capital Resources".

We had net income of $80.0 million for the first three months of 2004, an increase of $4.6 million or 6.1% from the first three months of 2003. The increase is primarily due to the impact of rate increases related to fuel and purchased power costs and lower depreciation, decommissioning and amortization costs. Increases in the first quarter of 2004 in pension, medical and other benefit costs and financing costs partially offset the increase in earnings compared with the same period in 2003. A more detailed analysis of financial results by segment follows.

The following table compares our electric utility operating revenues and electric utility megawatt-hour sales by customer class during the first quarter of 2004 with similar information for the first quarter of 2003 including favorable (better (B)) or unfavorable (worse (W)) variances.

During the first quarter of 2004, total electric utility operating revenues increased by $29.3 million or 6.4% when compared with 2003 primarily due to the impact of rate increases related to fuel and purchased power costs and to increases in volumes. The total rate impact associated with fuel and purchased power in 2004 was approximately $13.1 million compared with the same period in 2003. In March 2003, we received an interim increase in rates of $55.1 million annually to recover increases in fuel and purchased power costs. In October 2003, we received the final rate order, which authorized an additional $6.1 million of annual revenues.

Total electric megawatt-hour sales increased by 258,600 megawatt-hours or 3.4% during 2004. Residential sales were higher by 2.0% due to an increase in the number of customers during the first quarter of 2004. Residential customers contribute higher margins than other customer classes. Sales volumes to large commercial/industrial customers improved by 1.0% between the comparative periods. Sale volumes for resale to other utilities, the Resale-Utilities customer class, increased 63.8% between the periods due to an increased demand for wholesale power. however, these sales result in very small margins.

As measured by heating degree days, the first quarter of 2004 was 5.1% warmer than the same period in 2003 and 1.9% colder than normal. The impact of weather in the first quarter of 2004 was an increase in electric operating revenues of approximately $1.7 million compared to normal. In the first quarter of 2003, colder weather resulted in an increase in revenues of approximately $8.3 million compared to normal.

Fuel and Purchased Power expenses increased by $5.1 million, or 3.7% when compared to the first quarter of 2003. This increase is directly related to the 3.4% increase in megawatt-hour sales. The first quarter of 2004 was favorably impacted by the operations of our generation fleet as we produced 4.0% more megawatt-hours when compared to the first quarter of 2003. Because of the favorable performance of our generation fleet, there was no increase in the cost per megawatt-hour between quarters.

In April 2004, our Point Beach Unit 1 518-MW nuclear unit shut down for its normal refueling outage, which is scheduled approximately every 18 months. In 2003, we had one normal refueling outage of Unit 2 in the fourth quarter.

A comparison follows of our gas utility operating revenues, gross margin and gas deliveries during the first quarter of 2004 with similar information for the first quarter of 2003. 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. Gas operating revenues decreased by $6.2 million or 2.7% due primarily to a weather-related decrease in the therm deliveries between the comparative periods offset by a $2.5 million or 1.5% decrease in purchased gas costs.

For the three months ended March 31, 2004, gas margins decreased $3.7 million or 5.8% when compared to the three months ended March 31, 2003, due primarily to warmer winter weather as compared to 2003. As measured by heating degree days, the first quarter of 2004 was 5.1% warmer than the first quarter of 2003 but 1.9% colder than normal.

The decrease in therm deliveries due to weather was offset in part by an increase in customers of approximately 2.0%, during the first quarter of 2004 compared with the same period in 2003. Most of our customer growth was in the residential customer class.

The following table compares our gas utility gross margin and natural gas therm deliveries by customer class during the first quarter of 2004 with similar information for the first quarter of 2003.

Other Operation and Maintenance Expenses:   Other operation and maintenance expenses increased by $11.2 million or 5.7% during the first quarter of 2004 when compared with the first quarter of 2003. The increase was primarily attributable to pension, medical and other benefit costs, which increased by approximately $7.4 million.

Depreciation, Decommissioning and Amortization:   Depreciation, Decommissioning and Amortization expenses decreased by $3.7 million or 5.5% during the first quarter of 2004. In the first quarter of 2004, decommissioning expense was reduced by $7.7 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.

Financing Costs:   Total financing costs increased by $2.5 million in the three months ended March 31, 2004 compared to the same period in 2003. This increase reflects the issuance of new intermediate-term /long-term debt securities in 2003, the proceeds of which were used primarily to reduce short-term borrowings.

Income Taxes:   For the first quarter of 2004, our effective tax rate was 38.3%, which was more than the first quarter rate of 37.4% in 2003. This increase in the effective income tax rate was due primarily to a reduction in available Federal and State rehabilitation credits from 2003 to 2004.

The following summarizes our cash flows during the first three months of 2004 and 2003:

Cash provided by operating activities increased to $293.4 million during the first three months of 2004 compared with $249.0 million during the same period in 2003. This increase was due in large part to lower working capital requirements resulting from warmer winter weather and greater draw down of gas inventories in 2004 and increased earnings.

During the first three months of 2004, we invested a total of $85.8 million compared to $85.7 million during the same period in 2003.

During the three months ended March 31, 2004, we used $217.6 million for financing activities compared with using $165.4 million for financing activities during the first three months of 2003. The primary uses of cash in the first quarter of 2004 included approximately $165.3 million for the repayment of short-term debt, $7.1 million for the repayment of long-term debt, and $44.9 million for the payment of dividends to Wisconsin Energy.

Cash requirements during the remaining nine months of 2004 are expected to be met primarily through internally generated funds, short-term borrowings and existing lines of credit supplemented through the sale of intermediate or long-term debt securities depending on market conditions and other factors.

We have access to outside 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.

We have $165 million of unsecured notes outstanding at March 31, 2004 that were issued as support for a similar amount of variable rate tax-exempt bonds issued on our behalf. The terms of the variable rate tax-exempt bonds require resetting of the interest rate on a weekly basis and allow holders to put the

We have approximately $350 million of available unused lines of bank back-up credit facilities on a consolidated basis. On March 31, 2004, we had approximately $151 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 March 31, 2004:

The following table shows our consolidated capitalization structure at March 31, 2004 and at December 31, 2003:

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 by Standard & Poors Corporation (S&P), Moody's Investors Service (Moody's) and Fitch Ratings (Fitch) as of March 31, 2004.

The security rating outlooks assigned by S&P, Moody's and Fitch for us are all stable.

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

Capital requirements during the remainder of 2004 are expected to be principally for capital expenditures, maturing debt of $140 million and nuclear fuel. Our 2004 annual consolidated capital expenditure budget, excluding the purchase of nuclear fuel, is approximately $406 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. As of March 31, 2004, our estimated maximum exposure under these agreements has not changed significantly compared to December 31, 2003. 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. See "Note 6 -- Guarantees" in the Notes to Consolidated Condensed Financial Statements in this report for more information.

Contractual Obligations/Commercial Commitments:   Our total contractual obligations and other commercial commitments as of March 31, 2004 decreased compared with December 31, 2003 as periodic payments related to these types of obligations were greater than new commitments made in the ordinary course of business during the quarter.

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 collateral or termination payments in the event of a credit ratings change to below investment grade. At March 31, 2004, we estimate that the potential payments under these agreements that could result from credit rating downgrades totaled approximately $98.9 million.

Construction Risk:   In December 2002, the PSCW issued a written order granting a Certificate of Public Convenience and Necessity (CPCN) for We Power to commence construction of the Port Washington Generating Station consisting of two 545 megawatt natural gas-based combined cycle generating units on the site of our existing Port Washington Power Plant. In addition, in November 2003, the PSCW issued a written order granting a CPCN for We Power to commence construction of two 615 megawatt super critical pulverized coal generating units on the site of our existing Oak Creek Power Plant (Elm Road units). We will lease and operate these facilities under long-term contracts with We Power. Project management is subject to a number of risks over which We Power 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, or the inability to obtain, labor or materials, th e inability of the general contractor or subcontractors to perform under their contracts, strikes, adverse weather conditions and changes in applicable laws or regulations. If final costs for the construction of the Port Washington Generating Station or the Elm Road units exceed the fixed costs allowed in the PSCW order, We Power can not recover this excess from us or our customers unless specifically allowed by the PSCW.

Limited Rate Adjustment Request:   On July 2, 2003, we filed an application with the PSCW for an increase in electric and steam rates for anticipated 2004 revenue deficiencies associated with (1) costs for the new Port Washington Generating Station being constructed as part of Wisconsin Energy's Power the Future strategy, (2) increased costs linked to changes in Wisconsin's public benefits legislation and (3) costs related to steam utility operations. The filing identified anticipated revenue deficiencies in 2004 attributable to Wisconsin in the amount of $63.5 million (3.5%) for our electric operations and $0.6 million (3.9%) for our steam operations. The filing also included an additional anticipated 2005 Wisconsin revenue deficiency in the amount of $0.4 million (2.6%) for our steam operations. Hearings on our July 2003 request were completed in December 2003. In April 2004, the PSCW approved an increase in electr ic and steam rates of approximately $59.5 million associated with our anticipated 2004 revenue deficiencies. We received an order implementing this increase in May 2004.

In 2004 we expect to file with the PSCW for recovery of additional anticipated 2005 electric revenue deficiencies associated with costs for both the Port Washington Generating Station and Elm Road units, for recovery of additional steam utility costs.

Power the Future - Port Washington:   In March 2003, an individual who participated in the Port Washington CPCN proceedings before the PSCW filed a petition for review with the Dane County Circuit Court requesting the Court to reverse and remand in its entirety the PSCW's December 2002 Order granting the CPCN (Port Order). In January 2004, the Dane County Circuit Court issued a decision (January 2004 Order) vacating the Port Order and remanding the matter to the PSCW to develop additional environmental analysis to justify its decision to perform only an Environmental Assessment, rather than a more comprehensive Environmental Impact Statement. The PSCW addressed the court's decision by analyzing the environmental impact of the Port Washington project on its own merits, rather than comparing it to coal-based generation. In March 2004, the PSCW approved a Revised Environmental Assessment and affirmed the CPCN (March 2004 Order) it originally issue d in December 2002 authorizing construction of the Port Washington Generating Station. In April, the same individual filed various motions, including a motion for contempt sanctions, in the same Dane County Circuit Court against the PSCW and Wisconsin Energy and its subsidiaries on the grounds that the PSCW and Wisconsin Energy were in violation of the January 2004 Order. In response, the judge dismissed the case in April 2004, ruling that her court has no continuing jurisdiction in the case and there was no basis for granting the motion for sanctions.

Also in April 2004, this individual filed a petition for review in another Dane County Circuit Court to review the PSCW's March 2004 Order. This second appeal is pending.

Power the Future - 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 on the site of our existing Oak Creek Power Plant. In the first quarter of 2004, we requested PSCW approval to defer certain costs related to the Elm Road units for recovery in future rates. The PSCW approved the request in April at an open meeting. In April 2004, Elm Road Services, LLC, a wholly owned subsidiary of We Power, entered into a contract with Bechtel Power Corporation to secure necessary engineering, design and construction services and major equipment components for these units.

Four appeals challenging the PSCW's Elm Road Order have been filed. Wisconsin Energy has filed a Notice of Appearance and Statement of Position in each of these proceedings requesting that the PSCW's decision be upheld and the petitions be dismissed. Also, two cases were filed in January 2004 in Dane County Circuit Court against the Wisconsin Department of Natural Resources (WDNR) contending that

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 permit for wetlands and waterways alterations for the Elm Road units. That request was granted and has been assigned to an administrative law judge for scheduling. In January 2004, the WDNR issued the air pollution control construction permit to us for the Elm Road units. In February 2004, parties submitted to the WDNR and to the Dane County Circuit Court requests for a contested case hearing and for judicial review, respectively, on the Elm Road units air pollution control construction permit. The contested case hearing has been assigned and scheduled for October 2004. In addition, the City of Oak Creek has been allowed to intervene in the hearing. Petitioners agreed to dismissal of their petition for judicial review. We continue to work with the PSCW, the WDNR and other agencies to obtain all required permits and project approvals.

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 recover the cost of certain investments intended to improve the environment. The measure would result in a lower cost to customers when compared to traditional ratemaking. We are reviewing this legislation and the effect it may have on us if we choose to securitize environmental projects. All expenditures that utilities would seek to finance through the environmental trust would first need to be approved by the PSCW.

Point Beach Nuclear Plant:   We own two 518-megawatt electric generating units at Point Beach Nuclear Plant in Two Rivers, Wisconsin, which are operated by Nuclear Management Company, LLC (NMC), a joint venture of Wisconsin Energy and affiliates of other unaffiliated utilities. In April 2004, Unit 1 began its normal refueling outage, which is scheduled approximately every 18 months and is expected to last until the end of May.

In 2003, NMC formed an operating license renewal team, which completed a technical and economic evaluation of license renewal. Based upon the results of this evaluation and following approval by executive management and our Board of Directors in December 2003, NMC and Wisconsin Electric filed an application with the NRC in February 2004 to renew the operating licenses for both of Point Beach's nuclear reactors for an additional 20 years.

In February 2004, the United States Nuclear Regulatory Commission (NRC) issued its first revised order establishing interim inspection requirements for reactor vessel heads at pressurized water reactors. The revised order continues to impose requirements for pressurized water reactor licensees to inspect reactor vessel heads and related penetration nozzles until superceded by the pending revision of 10 CFR 50.55a, "Codes and Standards." We plan to replace both reactor vessel heads during the 2005 refueling outages as an alternative to incurring the additional time and costs of these examinations and filed an application to do this with the PSCW in June 2003. In October 2003, the PSCW approved reactor vessel head replacement for Units 1 and 2 at Point Beach. Total capital expenditure to replace the two reactor vessel heads is estimated at approximately $54 million.

We have completed the Unit 1 reactor vessel head inspection and have identified one penetration nozzle that needs repair. The repair consists of cutting and removing the associated thermal sleeve, machining and welding the penetration nozzle, and installing a new thermal sleeve. The repair is expected to extend the outage five to seven days at an additional Operation & Maintenance cost of $2 to $2.5 million. The nozzle was still intact and had not experienced any leakage of reactor coolant system water.

During 2003, the NRC conducted a three-phase supplemental inspection of Point Beach to review corrective actions taken by NMC pursuant to problems identified by Point Beach with the performance of the auxiliary feedwater system recirculation lines as well as the effectiveness of the corrective action, emergency preparedness and engineering programs.

NMC responded to the supplemental inspection in February 2004 with specific commitments to address the NRC concerns, including revision of the Point Beach Excellence Plan. We were assessed a fine of $60,000 related to issues identified with our emergency preparedness. NRC reviewed the adequacy of the revised Excellence Plan and its implementation, and NMC received a confirmatory action letter in April 2004. NRC will continue to provide increased oversight at Point Beach.

Midwest ISO:   In connection with its status as a Federal Energy Regulatory Commission (FERC) approved Regional Transmission Operator (RTO), the Midwest Independent Transmission System Operator, Inc. (Midwest ISO) is in the process of developing a bid-based energy market, which is currently proposed to be implemented on or about December 1, 2004. As part of this energy market, the Midwest ISO is developing a market-based platform for valuing transmission congestion premised upon the locational marginal pricing (LMP) system that has been implemented in certain northeastern and mid-Atlantic states. It is expected that the LMP system will include the ability to mitigate or eliminate congestion costs through the use of Financial Transmission Rights (FTR), which will be initially allocated by the Midwest ISO, and, it is anticipated, will be available through an auction-based system run by the Midwest ISO. Currently there are several different estimates of the impacts of the LMP pricing system on Wisconsin and the Upper Peninsula of Michigan's utilities (also known as WUMS utilities) ranging from annual cost savings of $50 million (based on a Midwest ISO study) to additional estimated annual expenses of up to $200 million (based on a U.S. Department of Energy study). The issues surrounding implementation of the energy market by Midwest ISO, including the implementation date, are being analyzed in a contested proceeding before the FERC in which we are participating. Parties to this FERC proceeding, including us and other WUMS utilities, have raised concerns about the impact of the Midwest ISO plan and have questioned the financial impact estimated by Midwest ISO. FERC can accept, reject or modify the Midwest ISO proposal. It is unknown at this time how and in what quantity FTRs will be initially allocated by the Midwest ISO and what, if any, the financial impact of the LMP congestion pricing system might have on us. The Midwest ISO is currently deferring the costs to develop and start-up its energy market (new software systems and personnel). Once the market is operational, the development and start-up costs will be charged to the Midwest ISO's transmission customers, which includes us.

In the Midwest ISO, base transmission costs are currently being paid by load serving entities (LSEs) located in the service territories of each Midwest ISO transmission owner in proportion to the load served by the LSE versus the total load of the service territory. This "license plate" rate design is scheduled to be replaced after a six-year phase-in of rates in the Midwest ISO. It is unknown at this point what rate design, and in what time frame a new rate design, will replace the Midwest ISO's current license plate rate design. We are currently unable to determine the impact that any new rate design will have on us.

Lost Revenue Charges:   The FERC permits transmission owning utilities that have not joined an 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 systems operated by the Midwest ISO and PJM Interconnection, LLC (PJM), entities that currently pay a transmission charge to move energy through or out of a neighboring transmission system will no longer

In December 2003, we, along with other entities, reached an agreement with the Midwest ISO and a consortium of companies referred to as the Grid America Companies on a lost revenue payment to be paid for a two-year period that results from the Grid America Companies' decision to place their transmission facilities under the operational control of the Midwest ISO. Discussions as to appropriate lost revenue charges with regard to several entities' decisions, including that of Commonwealth Edison Company, a transmission provider of ours, to place their transmission facilities under the control of PJM were recently terminated. In lieu of charging the previously ordered seam elimination cost adjustment, FERC permitted the Midwest ISO, PJM, and the affected entities, including Commonwealth Edison Company, to continue to charge their existing rates for transmission to adjoining areas until December 1, 2004. During this period, the affected entities, as directed by FERC, are required to develop a new rate design that will eliminate the multiple charges between the service territories of the Midwest ISO and PJM. It is unknown at this time what the outcome of these proceedings will be or what effect the new rate design will have on us.

Congestion Charges on Other Systems.   Effective May 1, 2004, Commonwealth Edison transferred control of its transmission facilities to PJM, at which time PJM's LMP based congestion pricing system began to apply to transmission service on Commonwealth Edison's facilities. PJM has allocated FTRs to hedge against transmission congestion for the month of May. We did not receive FTRs for all of our firm transmission for the month of May; however, on April 29, 2004, the FERC issued an order requiring PJM to adopt measures that will mitigate against any unhedged congestion charges incurred during May. The FERC indicated it will address later FTR shortfalls in a future order.

Additionally, PJM has recently completed the allocation of FTRs for the year commencing June 1, 2004. We received 97% of the FTRs that we requested for this period. Because LMP based congestion pricing is new to the Commonwealth Edison system, it remains unclear what, if any, exposure to congestion payments we may face.

New Pronouncements:   The FASB issued FASB Staff Position (FSP) No. 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, (FSP 106-1) that allows sponsors to elect to defer recognition of the effects of the Act. In accordance with FSP 106-1, we elected to defer recognition of the effects of the Act. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require us to change previously reported information. For further information, see "Note 5 -- Benefits" in the Notes to Consolidated Condensed Financial Statements in Item 1 of Part I of this report.

This report and other documents or oral presentations contain or may contain forward-looking statements made by or on behalf of us. Such 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 "anticipate," "believe," "estimate," "expect," "forecast," "objective," "plan," "possible," "potential," "project" and similar expressions are intended to identify forward-looking statements. In addition to the assumptions

• 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 changes in fossil fuel, nuclear fuel, purchased power, gas supply or water supply costs or availability due to higher demand, shortages, transportation problems or other developments; nonperformance by electric energy or natural gas suppliers under existing power purchase or gas supply contracts; nuclear or environmental incidents; resolution of used nuclear fuel storage and disposal issues; electric transmission or gas pipeline system constraints; unanticipated organizational structure or key personnel changes; collective bargaining agreements with union employees or work stoppages; inflation rates; or demographic and economic factors affecting utility service territories or operating environment.

• Regulatory factors such as: unanticipated changes in rate-setting policies or procedures; unanticipated changes in regulatory accounting policies and practices; industry restructuring initiatives; transmission 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 United States Environmental Protection Agency's regulations as well as regulations from 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 diox ide, 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 in 2000 of the merger of Wisconsin Energy Corporation and WICOR, Inc.

• 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.

• 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's Power the Future strategy announced in September 2000 and revised in February 2001, including receipt of necessary state and federal regulatory approvals, local opposition to siting of new generating facilities, obtaining the investment capital from outside sources necessary to implement the strategy, and risk associated with construction of the Power the Future facilities on time and within budget.

• 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.

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

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

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

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

• 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.

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. 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 2003 Annual Report on Form 10-K.

Disclosure Controls and Procedures:   Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of our disclosure controls and

Internal Control Over Financial Reporting:   There have not been any changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) 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.

The following should be read in conjunction with Item 3, Legal Proceedings, in Part I of our 2003 Annual Report on Form 10-K.

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

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. One such action is currently pending. The claim made against us in this case is not expected to have a material adverse effect on our financial statements.

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 intend to appeal this decision.

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" in Part I of this report for information concerning recent PSCW and other actions related to Wisconsin Energy's Power the Future strategy.

See Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations - "Factors Affecting Results, Liquidity and Capital Resources" 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.

At our 2004 Annual Meeting of Stockholders held on April 30, 2004 for which we did not solicit proxies, nine incumbent directors, as listed in our Information Statement dated March 16, 2004 (the Information Statement), were elected for one year terms. Each director received 33,289,327 votes (100% of votes cast). Directors are elected by a plurality of the votes cast by the shares entitled to vote. Any shares not voted, whether by withheld authority, broker non-votes or otherwise, have no effect in the election of directors. There was no solicitation in opposition to the nominees proposed in the Information Statement.

Further information concerning these matters is contained in the Information Statement.

The following Exhibits are filed with or incorporated by reference in this Form 10-Q report:

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.