WISCONSIN ELECTRIC POWER CO - Quarter Report: 2005 March (Form 10-Q)

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 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 (March 31, 2005):

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

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 1,085,000 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 440,000 gas customers in Wisconsin and about 460 steam customers in metro Milwaukee, Wisconsin. 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 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's Power 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 March 31, 2005, Bostco had $41.4 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.

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 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 months ended March 31, 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.

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 $721.1 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 FASB Staff Position (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. We are currently evaluating FSP FIN 46R - 5.

SFAS 143, Accounting for Asset Retirement Obligations, primarily applies to the future decommissioning costs for our Point Beach Nuclear Plant (Point Beach). SFAS 143 also applies to a

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.

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.

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, 2005 and 2004:

The components of our net periodic pension and other post-retirement benefit costs for the three months ended March 31, 2005 and 2004 were as follows:

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 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 are still accurate.

Severance Plans:   We incurred $22.3 million ($13.4 million after-tax) of severance costs in 2004. 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 quarter of 2005, we made severance related payments that reduced the reserve for severance benefits from $6.6 million at December 31, 2004 to $2.6 million as of March 31, 2005.

We enter into various guarantees to provide financial and performance assurance to third parties. As of March 31, 2005, 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, excluding severance benefits, for such benefits was $12.7 million as of March 31, 2005 and $12.0 million as of December 31, 2004.

Summarized financial information concerning our reportable operating segments for the three month periods ended March 31, 2005 and 2004 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, 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.

Cautionary Factors Regarding Forward -- Looking Statements:   Certain statements contained herein are "Forward-Looking Statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-Looking Statements include, among other things, statements regarding management's expectations and projections regarding completion of construction projects, regulatory matters, fuel costs, sources of electric energy supply, gas deliveries, remediation costs, environmental and other capital expenditures, liquidity and capital resources and other matters. Also, Forward-Looking Statements may be identified by reference to a future period or periods or by the use of forward looking terminology such as "anticipates," "believes," "estimates," "expects," "forecasts," "intends," "may," "objectives," "plans," "possible," "potential," "projects" or similar terms or variations of these terms. Actual results may differ materially from those set forth in Forward-Looking 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

We had net income of $70.7 million for the first quarter of 2005, a decrease of $9.3 million or 11.6% from the first quarter of 2004. Net income declined primarily due to increased fuel and purchased power costs and a weather-related decline in electric sales during 2005. A more detailed analysis of our financial results follows.

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

During the first quarter of 2005, total electric utility operating revenues increased by $6.6 million or 1.3% when compared with the first quarter of 2004. This net increase reflected pricing increases of approximately $19.7 million, offset by lower volume sales to other utilities. The most significant impact to rates was the May 2004 order received from the Public Service Commission of Wisconsin (PSCW) authorizing an annualized increase in electric rates of approximately $59.0 million to cover construction costs associated with Wisconsin Energy's Power the Future program and to recover low income uncollectible expenses transferred to Wisconsin's public benefits fund. This rate increase was not in effect in the first quarter of 2004.

Total electric megawatt-hour sales volumes decreased by 277.5 thousand megawatt-hours or 3.5% during the first quarter of 2005 compared with the same period in 2004. As measured by heating degree days,

In April 2005, Point Beach Nuclear Unit 2 shut down for its normal refueling outage, which is scheduled approximately every 18 months. Point Beach Nuclear Unit 1 is scheduled to have a refueling outage over the third and fourth quarters of 2005. During these outages, we will replace the reactor vessel heads in each unit. This work, along with other planned maintenance, is expected to result in longer than normal outages. 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.

A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the first quarter of 2005 with similar information for the first 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. Between the comparative periods, total gas operating revenues increased by $11.0 million, or 4.9%.

For the three months ended March 31, 2005, gas utility gross margin decreased by $1.0 million or 1.7% when compared to the three months ended March 31, 2004. This net decrease reflects lower total therm deliveries primarily due to weather. As measured by heating degree days, the first quarter of 2005 was 2.3% warmer than the first quarter of 2004.

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

Other operation and maintenance expenses increased by $6.9 million or 3.3% during the first quarter of 2005 compared with the first quarter of 2004. The largest increase relates to $14.5 million of costs related to the Port Washington Generating Station lease and conservation programs. These costs were recognized in connection with the May 2004 limited rate increase which provided revenues on virtually a dollar for dollar basis. In addition, benefits costs have increased approximately $2.0 million due to increased medical and pension costs. Partially offsetting these increases were reductions in bad debt costs of $2.4 million due to the implementation of escrow accounting for residential bad debts in the first quarter of 2005. We did not receive similar authority from the PSCW to defer 2004 residential bad debt costs until the second quarter of 2004. In addition, we estimate that employee costs were down approximately $3.8 million due to the voluntary severance programs that were in effect in 2004.

Depreciation, Decommissioning and Amortization expenses increased by $6.2 million or 9.7% during the first quarter of 2005. The variance is due primarily to a decommissioning expense reduction in the first quarter of 2004 of $7.7 million to reflect the regulatory treatment of income taxes associated with gains in decommissioning trusts. This same benefit was not recognized in the first quarter of 2005.

Other income, net increased by $5.0 million in the first quarter of 2005 compared to the first quarter of 2004. This increase is primarily due to an increase of $1.3 million in our interest in the earnings of our transmission affiliate during the first quarter of 2005, the recognition of additional carrying costs on deferred electric transmission costs and an increase of $1.5 million for equity-related Allowance for Funds Used During Construction (AFUDC) due to a higher average balance of utility construction projects between the comparative periods.

For the first quarter of 2005, our effective tax rate was 37.2% compared with a 38.3% rate during the first quarter of 2004.

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

Cash provided by operating activities decreased to $254.7 million during the first three months of 2005 compared with $293.4 million during the same period in 2004. This decrease was due in large part to higher deferred costs and decreased cash earnings between the comparative periods.

During the first three months of 2005, we invested a total of $99.9 million in our business compared to $85.8 million during the same period in 2004. This increase is related to environmental projects at certain of our power plants.

During the three months ended March 31, 2005, we used $168.4 million for financing activities compared with using $217.6 million for financing activities during the first three months of 2004. We reduced total debt by $123.2 million during the first three months of 2005 compared with a $172.4 million reduction in total debt during the first three months of 2004.

We anticipate meeting our capital requirements during the remaining nine 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. In January 2005, we notified the PSCW that we would not issue the environmental trust bonds until the satisfactory resolution of tax rulings associated with the proposed securitization and the resolution of the Elm Road proceedings before the Supreme Court of Wisconsin associated with Wisconsin Energy's Power the Future strategy. The issuance would also be dependent upon market conditions.

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

As of March 31, 2005, we have approximately $357.0 million of available unused lines of bank back-up credit facilities on a consolidated basis. On March 31, 2005, we had approximately $74.9 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, 2005:

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

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 March 31, 2005.

On March 29, 2005, S&P affirmed our security ratings and changed our security rating outlook from stable to negative.

The security rating outlooks assigned by Moody's and Fitch are all stable.

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

Capital requirements 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 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. 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 March 31, 2005 compared with $5.6 billion as of December 31, 2004. This increase primarily reflects purchase obligations under new coal supply contracts.

Construction Risk:   In December 2002, the PSCW issued a written order granting a Certificate of Public Convenience and Necessity (CPCN) to commence construction of We Power's 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 and force majeure and excused events 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 for We Power to commence construction of two 615-megawatt super critical pulverized coal generating units (Elm Road units) on 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. 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, 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 collateral is not provided or an accelerated payment. At March 31, 2005, we estimate that the potential payments under these agreements that could result from credit rating downgrades totaled approximately $96.4 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 effectively manage utilization of our available generating capacity and energy during periods when available power resources are expected to exceed the requirements of our 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 market participants in the Midwest Independent Transmission System Operator, Inc. (Midwest ISO) bid-based energy market. For additional information on the Midwest ISO's bid-based energy market see Utility Rates and Regulatory Matters -- Other Utility Rate Matters and Industry Restructuring and Competition below. We manage our fuel and gas supply costs through a portfolio of short and long-term procurement contracts with various suppliers for the purchase of coal, uranium, natural gas and fuel oil.

Under Wisconsin Energy's Power 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 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 1, and we expect the unit to be operational early in the third quarter of 2005. 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 site preparation of Unit 2 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 on the site of our existing Oak Creek Power Plant. The first unit was scheduled to be operational in 2009 and the second unit was scheduled to be operational in 2010. The CPCN was granted contingent upon us obtaining the necessary environmental permits. We Power expects to have co-owners that will have an interest in the project of approximately 17%.

The construction of the Elm Road units is subject to a number of regulatory approvals and legal challenges by third parties. The most notable remaining legal challenges relate to the Elm Road CPCN.

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 on the site of our existing Oak Creek Power Plant vacated the CPCN and remanded it back to the PSCW for additional proceedings. The Court determined that the PSCW committed errors in determining the completeness of 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. The Supreme Court heard oral arguments in this matter on March 30, 2005. We anticipate a decision to be issued no later than June 30, 2005.

We continue to work with the PSCW, the WDNR and other agencies to obtain all required permits and project approvals. The major permits and the status regarding these 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 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 briefings concluded in September 2004. In November 2004, the administrative law judge approved the WDNR's issuance of the wetlands and waterways permit (Chapter 30 permit) for the Elm Road units. In December 2004, two 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. The WDNR joined in this motion. In March 2005, the court dismissed the appeal based on improper filing procedures by the opponents. The opponents have appealed the court's dismissal to the Wisconsin Court of Appeals.

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

In January 2004, the WDNR issued the Air Pollution Control and Construction Permit to us for the Elm Road units. In February 2004, certain project opponents filed a petition for judicial review in the Dane County Circuit Court. At the same time, the project opponents submitted a request for a contested case hearing with the WDNR which was granted. Petitioners subsequently agreed to dismiss their petition for judicial review. 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. A Dane County Circuit Court judge has been assigned to the matter, but no timetable for the judicial review has been set.

The terms of We Power's construction contract with Bechtel for the Elm Road units presently provide that full notice to proceed must be given to Bechtel by July 1, 2005. In order for Bechtel to be able to proceed on July 1, it must begin site mobilization activities in May. Wisconsin Energy is unable to state whether the project could proceed if delayed beyond July 1, 2005.

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 will be required by the PSCW for rates beginning in January 1, 2006. We expect to make filings in the second and third quarters of 2005 in connection with this PSCW review.

2005 Revenue Deficiencies:   In May 2004, we filed an application with the PSCW for an 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's Power 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 April 2005, the PSCW made an oral decision to approve the request as modified. A final calculation of the increase cannot be made until the PSCW issues its written order.

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 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%.

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 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. In January 2005, we notified the PSCW that we would not issue environmental trust bonds until the satisfactory resolution of tax rulings associated with the proposed securitization and the resolution of the Elm Road proceedings before the Supreme Court of Wisconsin associated with Wisconsin Energy's Power the Future strategy. The issuance would also be dependent upon market conditions.

Midwest ISO Day 2:   In January 2005, we requested deferral accounting treatment from the PSCW for certain incremental costs or benefits that may occur due to the implementation on April 1, 2005 of the Midwest ISO Day 2 energy market. 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. For additional information see Industry Restructuring and Competition -- Electric Transmission and Energy Markets -- Midwest ISO below.

Nuclear Refueling Outages - 2005:   In January 2005, we requested deferral accounting treatment for non-fuel operations and maintenance expenses related to the second nuclear refueling outage expected to occur in the fall of 2005. In March 2005, the PSCW denied this request.

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 the Company 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. The Unit 2 outage began in April 2005 and the Unit 1 outage is scheduled over the third and fourth quarters. During these scheduled refueling outages we will replace 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.

Midwest ISO:   On April 1, 2005, the Midwest ISO implemented 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. The Midwest ISO is responsible to ensure that load requirements in the region are met reliably and efficiently, and to manage congestion on the transmission system.

As part of the energy market, the Midwest ISO implemented a Locational Marginal Pricing (LMP) system, a market-based platform for valuing transmission congestion. The LMP system includes the ability to mitigate or eliminate congestion costs through the use of Financial Transmission Rights (FTRs). FTRs are allocated to market participants by the Midwest ISO. The first allocation of FTRs was completed for the period of April 1, 2005 through August 31, 2005. As the Midwest ISO market only recently commenced operations, we are unable to predict at this time what, if any, financial impact the LMP congestion pricing system might have. The FTR allocation process will be performed again for the period from September 1, 2005 to May 31, 2006. It is unknown how many FTRs we will be granted during that allocation process and thus to what degree we will incur congestion charges.

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 the Midwest ISO Day 2 energy markets. 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 approved 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.

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 from December 1, 2004 until March 31, 2006, to compensate transmission owners for the loss of revenues resulting from the joining of an RTO and/or FERC's elimination of through and out transmission charges between the Midwest ISO and PJM. The FERC ordered that certain existing transmission transactions continue to pay for through and out service from December 1, 2004 until March 31, 2006. The details of the seams elimination charge and the quantification of the existing transaction charge are the subject of a hearing process initiated by FERC in a February 2005 order. A decision from the hearing process is expected in the second half of 2006. We are currently unable to determine the impacts on us; however we do not anticipate material financial impacts.