WISCONSIN ELECTRIC POWER CO - Quarter Report: 2005 September (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 by check mark whether the registrant is a shell company (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 (September 30, 2005):

All of the common stock of Wisconsin Electric Power Company is owned 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. 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 1,087,600 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 442,000 gas customers in Wisconsin and about 460 steam customers in metro Milwaukee, Wisconsin. For further financial information about our business segments, see Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 9 -- 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 September 30, 2005, Bostco had $41.2 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 and nine months ended September 30, 2005 are not necessarily indicative of the results which may be expected for the entire fiscal year 2005 because of seasonal and other factors.

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

In July 2005, the first 545- megawatt natural gas-fired generation unit was placed in service at the Port Washington Generating Station (PWGS). We are leasing this unit from PWGS under a Public Service Commission of Wisconsin (PSCW) approved lease. Pursuant to Statement of Financial Accounting Standards (SFAS) 13, Accounting for Leases, we are accounting for this lease as a capital lease and record the leased plant and corresponding obligation under the capital lease at the estimated fair value of $335.0 million. We are amortizing the leased plant on a straight-line basis over the original 25-year term of the lease.

For rate-making purposes this lease is treated as an operating lease pursuant to SFAS 71, Accounting for the Effects of Certain Types of Regulation. We record the lease payments as rent expense in Other operation and maintenance in the Consolidated Condensed Income Statement. The lease payments are expected to be recovered through our rates. The annual lease payments are approximately $48.0 million. We are recording a deferred regulatory asset for the difference between the lease payments and the sum of imputed interest cost and amortization costs calculated under capital lease accounting.

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

Due to the regulated nature of our utility business, we have established a regulatory liability to reflect the difference between nuclear decommissioning costs recovered in rates and the Asset Retirement

Obligation for nuclear decommissioning that is calculated under SFAS 143. For further information see Note 10 -- Regulatory Assets and Liabilities.

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 Financial Accounting Standards Board (FASB) issued Interpretation 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), an interpretation of FASB Statement No. 143. FIN 47 defines the term conditional asset retirement obligation as used in Statement No. 143. As defined in FIN 47, a conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The scope of FIN 47 includes asbestos costs, coal handling equipment, water intake facilities located on lakebeds and may also apply to other facilities. Any changes in expense due to differing assumptions between FIN 47 and those currently required by the PSCW are not expected to be material and we expect to defer the differences as regulatory assets or liabilities. FIN 47 will be effective as of 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 nine months ended September 30, 2005 and 2004:

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

We continue to evaluate our tolling and purchased power agreements with third parties on a quarterly basis. After making an exhaustive effort, we concluded that for three of these agreements, we are unable to obtain the information necessary to determine whether we are the primary beneficiary of these variable interest entities. Pursuant to the terms of two of the three agreements, we deliver fuel to the entity's facilities and receive electric power. We pay the entity a "toll" to convert our fuel into the electric energy. The output of the facility is available for us to dispatch during the term of the respective agreement. In the other agreement, we have rights to the firm capacity of the entity's facility. We have approximately $682.8 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 FIN 46R - 5, Implicit Variable Interests under FASB Interpretation 46 (revised December 2003). This statement requires that holdings of implicit variable interests are evaluated when applying Interpretation 46R. An implicit variable interest is defined as an implied pecuniary interest in an entity that changes with changes in the fair value of the entity's net assets exclusive of variable interests. An implicit variable interest acts the same as an explicit variable interest except it involves the absorbing and/or receiving of variability indirectly from the entity (rather than directly). FIN 46R-5 was effective for the first reporting period beginning after March 3, 2005 for entities that had already adopted FIN 46R; accordingly, we adopted FIN 46R - 5 in the second quarter of 2005. We have concluded that we currently do not have any implicit variable interests.

We follow SFAS 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, effective July 1, 2003, which requires that every derivative instrument be recorded on the balance sheet as an asset or liability measured at its fair value and that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives under SFAS 133, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities. As of September 30, 2005, we recognized $26.3 million in regulatory liabilities related to derivatives.

We have a limited number of financial contracts that are defined as derivatives under SFAS 133 and qualify for cash flow hedge accounting. These contracts are utilized to manage the cost of gas for utility operations. Changes in the fair market values of these instruments are recorded in Accumulated Other Comprehensive Income. At the date the underlying transaction occurs, the amounts in Accumulated Other Comprehensive Income for utility operations are reported in earnings. We estimate that $0.6 million will be reclassified from Accumulated Other Comprehensive Income as a reduction in earnings during the fourth quarter of 2005.

The components of our net periodic pension and other post-retirement benefit costs for the three and nine months ended September 30, 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.

In October 2005, we announced that we were offering to our retirees a Medicare Advantage program as an option within our existing post-retirement medical and drug plans. The Medicare Advantage program is part of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 that was passed by Congress, and the program offers post-65 medical and drug benefits through private insurance carriers. The Medicare Advantage program is expected to reduce the cost of post-65 medical and drug costs for our retirees and the Company. We expect that the offering of the Medicare Advantage program will require us to remeasure the fair value of our other post-retirement plans in the fourth quarter of 2005, in accordance with SFAS No. 106, Employers' Accounting for Post-Retirement Benefits Other than Pensions.

Severance Plans:   In the third and fourth quarters of 2004, we incurred $22.3 million ($13.4 million after tax) of severance costs. The majority of the severance costs related to an enhanced severance package offered to selected management employees who voluntarily resigned in the fourth quarter of 2004. During the first nine months of 2005, substantially all of the severance related benefits were paid.

We enter into various guarantees to provide financial and performance assurance to third parties. As of September 30, 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 $14.4 million as of September 30, 2005 and $12.0 million as of December 31, 2004.

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

Our regulatory assets and liabilities at September 30, 2005 and December 31, 2004 consist of:

In the third quarter of 2005, we received $31.1 million from the sale of emission credits. These proceeds are included in Other, net regulatory liabilities.

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, coal and 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,"

We had net income of $79.2 million for the third quarter of 2005, an increase of $20.1 million or 34.0% from the third quarter of 2004. Increased net income primarily reflects a favorable weather-related increase in electric sales. Additionally, in the third quarter of 2004, we incurred $8.8 million of severance related costs due the voluntary severance programs that were implemented in the third quarter of 2004. These increases were offset in part due to the timing of a scheduled refueling outage at Point Beach Nuclear Plant. Unit 1 has a scheduled refueling outage that began during the third quarter of 2005. In 2004, we had a comparable outage at Point Beach during the second quarter. 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 third quarter of 2005 with similar information for the third quarter of 2004 including favorable (better (B)) or unfavorable (worse (W)) variances.

During the third quarter of 2005, total electric utility operating revenues increased by $109.6 million or 20.1% when compared with the third quarter of 2004. This net increase primarily reflected pricing increases of approximately $44.6 million and warmer weather. The most significant impact to rates was

Total electric megawatt-hour sales volumes increased by 745.9 thousand megawatt-hours or 9.3% during the third quarter of 2005 compared with the same period in 2004. We estimate that warm weather positively impacted electric operating revenues by $38.3 million during the third quarter of 2005 as compared to the third quarter of 2004. As measured by cooling degree days the third quarter of 2005 was 92.8% warmer than the same period in 2004, increasing cooling load sales to residential customers who are more weather sensitive and contribute higher margins than other customer classes. Residential sales volumes increased 12.9% in the third quarter of 2005 as compared to the same period in 2004. Sales volumes to commercial/industrial customers, excluding our largest customers, two iron ore mines, increased 5.4% between the comparative periods due partially to the warmer weather. Total sales volumes to commercial/industrial customers increased 5.5% between the comparative periods.

Sales volumes to other utilities increased 46.3% between the comparative periods. This increase is attributed, in part, to Unit 1 at the Port Washington Generating Station achieving operational status in July 2005, which provided additional generation capacity. Sales volumes to municipal utilities, the other retail/municipal customer class, increased 21.5% between the periods due to higher off-peak demand from lower margin municipal wholesale power customers.

Total fuel and purchased power expenses increased by $80.6 million or 50.7% when compared to the third quarter of 2004. This increase was due to (1) increased megawatt-hour sales, (2) the reduced availability of coal-fired generation and (3) the higher cost of purchased energy. As noted above, our total sales volume increased 9.3% over the same period last year. Our cost of fuel and purchased power increased from $19.72 per megawatt-hour for the three months ended September 30, 2004 to $27.20 per megawatt-hour for the three months ended September 30, 2005 or 37.9% between the comparative periods.

We estimate that our under recovery of fuel and purchased power costs was approximately $17.0 million more during the three months ended September 30, 2005 as compared with the same period in 2004. In February 2005, Wisconsin Electric filed a request with the PSCW to raise electric rates by $114.9 million to recover higher forecasted fuel and purchased power costs. In March 2005, the PSCW authorized an interim fuel rate increase for $114.9 million subject to refund when the PSCW completes its review of our request. For further information, see Factors Affecting Results, Liquidity and Capital Resources -- Utility Rates and Regulatory Matters.

Effective April 1, 2005, we began to participate in the Midwest Independent Transmission System Operator, Inc. (MISO) bid-based energy market (MISO Midwest Market) which significantly changed how our generating units are dispatched and how we buy and sell power. The State of Wisconsin and the Upper Peninsula of Michigan have significant transmission constraints, and we believe our energy costs have higher uncertainty as a result of the start of the MISO Midwest Market. As a result of this increased exposure, we, along with other utilities in the State of Wisconsin, have received approval from the PSCW to defer certain costs associated with the MISO Midwest Market. Based on this authorization, we have deferred $11.2 million for future rate recovery for the three months ended September 30, 2005. For more information regarding MISO and the MISO Midwest Market, see Item 2. Management's Discussion and

In April 2005, Point Beach Unit 2 shut down for its normal refueling outage, which is scheduled approximately every 18 months. A similar outage occurred on Point Beach Unit 1 in the second quarter of 2004. During the 2005 outage, we replaced the reactor vessel head in Unit 2. This work, along with other planned maintenance, lasted longer than originally expected due to delays. The outage was delayed due to the need to obtain a Safety Evaluation Report and a license amendment from the United States Nuclear Regulatory Commission (NRC) prior to lifting and setting the new Unit 2 reactor vessel head. The license amendment was received in late June, the reactor vessel head was replaced and the outage was completed and Unit 2 returned to full load on July 16, 2005. We received approval from the PSCW in May 2005 to defer incremental replacement power costs for future recovery as a result of the extended outage. In the third quarter of 2005, we deferred $6.3 million of incremental purchased power costs related to the extended outage. We expect to recover these deferred costs in future rates, subject to PSCW audit and approval.

The Unit 1 outage, during which the reactor vessel head is scheduled to be replaced and other planned maintenance will be performed, began in September 2005. Prior to the start of the outage, the NRC granted the license amendment requested for the Unit 1 outage. The Unit 1 outage is expected to be completed in the fourth quarter of 2005. 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.

In July 2005, we received a letter from Union Pacific Corporation notifying us that a force majeure event requiring maintenance on a Union Pacific railroad line is expected to result in a 15-20% reduction in the amount of contracted deliveries of Powder River Basin coal to certain of our coal generating facilities from June 2005 through November 2005. In August 2005, we requested and the PSCW approved deferral treatment of incremental fuel costs associated with these reduced coal deliveries. In the third quarter of 2005, we deferred approximately $7.9 million of incremental fuel costs and we expect to recover these costs in future rates, subject to review and approval of the PSCW. For more information regarding the reduction in the amount of contracted coal deliveries, see Item 2. Management's Discussion and Analysis - Factors Affecting Results, Liquidity and Capital Resources -- Market Risks and Other Significant Risks -- Commodity Price Risk and Utility Rates and Regulatory Matters -- Other Utility Rate Matters.

A comparison follows of gas utility operating revenues, gross margin and gas deliveries during the third quarter of 2005 with similar information for the third 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.

For the three months ended September 30, 2005, gas utility gross margin increased by $0.6 million or 3.3% when compared to the three months ended September 30, 2004. The following table compares gas