UNITED STATES
UNITED STATES |
SECURITIES AND EXCHANGE COMMISSION |
WASHINGTON, D.C. 20549 |
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K |
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) |
OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Fiscal Year EndedDecember 31, 2005 |
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year EndedDecember 31, 2004
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Commission |
| IRS Employer | |||||||
File Number | Address; and Telephone Number | Identification No. | |||||||
001-01245 | WISCONSIN ELECTRIC POWER COMPANY | 39-0476280 | |||||||
(A Wisconsin Corporation) | |||||||||
231 West Michigan Street | |||||||||
P.O. Box 2046 | |||||||||
Milwaukee, WI 53201 | |||||||||
(414) 221-2345 | |||||||||
Securities Registered Pursuant to Section 12(b) of the Act: None | |
Securities Registered Pursuant to Section 12(g) of the Act:
Serial Preferred Stock, 3.60% Series, $100 Par Value
Six Per Cent. Preferred Stock, $100 Par Value
Indicate by check mark if the registrant is a well known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [ ] No [X]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 12(b)13 or 15 (d) of the Act: None
Securities Registered Pursuant to Section 12(g) of the Act:
Serial Preferred Stock, 3.60% Series, $100 Par Value
Six Per Cent. Preferred Stock, $100 Par Value
Act. Yes [ ] No [X]
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 [ ]
Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this Chapter) is not contained herein, and will not be contained, to the best of the registrant’sregistrant's knowledge, in the definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.x
[X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one): Large accelerated filer [ ] Accelerated filer [ ] Non-accelerated filer [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[X]
The aggregate market value of the common equity of Wisconsin Electric Power Company held by non-affiliates as of June 30, 20042005 was zero. All of the common stock of Wisconsin Electric Power Company is held by Wisconsin Energy Corporation.
Indicate the number of shares outstanding of each of the registrant’sregistrant's classes of common stock, as of the latest practicable date (January 31, 2005)2006):
Common Stock, $10 Par Value, 33,289,327 shares outstanding. |
Common Stock, $10 Par Value, 33,289,327 shares outstanding.
Documents Incorporated by Reference
Portions of Wisconsin Electric Power Company’sCompany's definitive information statement for its Annual Meeting of Stockholders, to be held on April 29, 2005,28, 2006, are incorporated by reference into Part III hereof.
2004 Form 10-K
WISCONSIN ELECTRIC POWER COMPANY
FORM 10-K REPORT FOR THE YEAR ENDED DECEMBER 31, 2004
TABLE OF CONTENTS
WISCONSIN ELECTRIC POWER COMPANY | ||||
FORM 10-K REPORT FOR THE YEAR ENDED DECEMBER 31, 2005 | ||||
TABLE OF CONTENTS | |
Item | Page |
PART I | |
1. Business ............................................................................................................................................. | 18 |
1A. Risk Factors ...................................................................................................................................... | 18 |
1B. Unresolved Staff Comments ............................................................................................................. | 22 |
2. Properties .......................................................................................................................................... | 22 |
3. Legal Proceedings ............................................................................................................................. | 23 |
4. Submission of Matters to a Vote of Security Holders ...................................................................... | 24 |
Executive Officers of the Registrant .................................................................................................. | 24 |
PART II |
5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases | 26 |
6. Selected Financial Data .................................................................................................................... | 27 |
7. Management's Discussion and Analysis of Financial Condition and Results of Operations ........... | 29 |
7A. Quantitative and Qualitative Disclosures About Market Risk ......................................................... | 65 |
8. Financial Statements and Supplementary Data ................................................................................ | 66 |
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure .......... | 99 |
9A. Controls and Procedures ................................................................................................................... | 99 |
9B. Other Information ............................................................................................................................. | 99 |
PART III |
10. Directors and Executive Officers of the Registrant .......................................................................... | 99 |
11. Executive Compensation .................................................................................................................. | 100 |
12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder | 100 |
13. Certain Relationships and Related Transactions .............................................................................. | 100 |
14. Principal Accountant Fees and Services .......................................................................................... | 100 |
PART IV |
15. Exhibits and Financial Statement Schedules ................................................................................... | 101 |
Schedule II - Valuation and Qualifying Accounts ........................................................................... | 102 |
Signatures ......................................................................................................................................... | 103 |
Exhibit Index .................................................................................................................................... | E-1 |
PART I
ITEM 1. | BUSINESS |
INTRODUCTION
Wisconsin Electric Power Company (Wisconsin Electric), a wholly-owned subsidiary of Wisconsin Energy Corporation (Wisconsin Energy), was incorporated in the stateState 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 Wisconsin Electric, the Company, our, us or we refer to Wisconsin Electric Power Company and its subsidiary. We are an electric, gas and steam utility which serves approximately 1,081,400 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 437,800 gas customers in Wisconsin and approximately 460 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. We serve approximately 1,092,400 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 446,400 gas customers in Wisconsin and approximately 460 steam customers in metro Milwaukee, Wisconsin. For further financial information about our business segments, see “ResultsResults of Operations”Operations in Item 7 and “Note N–Note O -- Segment Reporting”Reporting in the Notes to Consolidated Financial Statements in Item 8.
Wisconsin Energy is also the parent company of Wisconsin Gas LLC (Wisconsin Gas), a natural gas distribution utility, which serves customers throughout Wisconsin, andWisconsin; Edison Sault Electric Company (Edison Sault), an electric utility which serves customers in the Upper Peninsula of Michigan.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 Electric and Wisconsin GasEnergy'sPower the Future strategy, which is described further in this report. We have combined common functions with Wisconsin Gas and operate under the trade name of “We Energies.”"We Energies".
Power the Future Strategy: In September 2000, Wisconsin Energy announced itsPower the Future Strategy:strategy In late February 2001, Wisconsin Energy filed a petition with the Public Service Commission of Wisconsin (PSCW) starting the regulatory review process for a 10-year strategy, originally proposed in September 2000, to improve the supply and reliability of electricity in Wisconsin. As part of Wisconsin Energy’sthePower the Future strategy, Wisconsin Energy isis: (1) investing in new natural gas-fired and coal-fired electric generating capacity;facilities, (2) upgrading our existing electric generating facilities and (3) investing in upgrades of our existing energy distribution system. The new generating capacity will be built by an affiliated company, W.E. Power LLC (We Power), and leased to us through long-term leases. Implementation of thePower the Future strategy is subject to a number of state and federal regulatory approvals and judicial review. Additional information concerningPower the Future may be found below in “Environmentalunder Utility Operations and Environmental Compliance” as well as in Item 7.
Other: Bostco LLC (Bostco) is our non-utility subsidiary that develops and invests in real estate. As of December 31, 2005, Bostco had $40.9 million of assets.
Cautionary Factors:Factors Regarding Forward - Looking Statements: Certain statements contained herein are “Forward-Looking Statements”"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’smanagement'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,” “objectives,” “plans,” “possible,” “potential,” “projects”"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-LookingForward-Look ing Statements as a result of certain risks and uncertainties, including but not limited to, those risks and uncertainties described in Item 1A Risk Factors and under the heading “Cautionary Factors”Cautionary Factors in Item 7 of this report, as well as other matters described under the heading “FactorsFactors Affecting Results, Liquidity and Capital Resources”Resources in Item 7 of this report, and other risks and uncertainties detailed from time to time in our filings with the Securities and Exchange Commission (SEC) or otherwise described throughout this document. We disclaim any obligation to update these forward-looking statements.
UTILITY OPERATIONS
ELECTRIC UTILITY OPERATIONS
We are the largest electric utility in the stateState of Wisconsin. We generate distribute and selldistribute electric energy in southeastern (including the metropolitan Milwaukee area), east central and northern Wisconsin and in the Upper Peninsula of Michigan.
2004 Form 10-K
ITEM 1. BUSINESS–(Cont’d)
Electric Sales
See “SelectedSelected Operating Data”Data in Item 6 for certain electric utility operating information by customer class during the period 20002001 through 2004.
2005.
We are authorized to provide retail electric service in designated territories in the stateState of Wisconsin, as established by indeterminate permits, certificates of public convenience and necessity or boundary agreements with other utilities, and in certain territories in the stateState of Michigan pursuant to franchises granted by municipalities. We also sell wholesale electric power.
power within the MISO Midwest Market.
Our electric energy sales to all classes of customers totaled approximately 31.232.0 million megawatt hours (mwh) during 2004,2005, a 1.5%2.6% increase from 2003.2004. Approximately 0.4 million of megawatt-hour sales during 20042005 were to Edison Sault. We had approximately 1,081,4001,092,400 electric customers at December 31, 2004,2005, an increase of 1.3%1.0% since December 31, 2003.2004.
Electric Sales Growth: Assuming moderate growth in the economy of our electric utility service territories and normal weather, we presently anticipate total retail and municipal electrickilowatt-hour sales to grow at an annual rate of 1.6%1.0% to 2.0%1.5% over the next five years. We also anticipate that our annual electric demand will grow at a rate of 2.0% to 3.0% over the next five years.
Sales to Large Electric Retail Customers:We provide electric utility service to a diversified base of customers in such industries as mining, paper, foundry, food products and machinery production, as well as to large retail chains.
Our largest retail electric customers are two iron ore mines located in the Upper Peninsula of Michigan. We currently have special negotiated power-sales contracts with these mines that expire in December 2007. The combined electric energy sales to the two mines accounted for 7.5%7.2% and 7.2%7.5% of our total electric utility energy sales during 2005 and 2004, respectively. The mines have notified us that they are disputing certain billings and 2003, respectively.they have placed the disputed amounts in escrow. In September 2005, the mines notified us that they have filed for formal arbitration related to this contract. We have notified the mines that we believe that they have failed to comply with certain notification provisions related to annual production as specified within the contract. For further information, see Legal Matters under Factors Affecting Results, Liquidity and Capital Resources in Item 7 of this report.
Sales to Wholesale Customers:During 2004,2005, we sold wholesale electric energy to three municipally owned systems, two rural cooperatives and one municipal joint action agency located in the states of Wisconsin, Michigan and Illinois. We also made wholesale electric energy sales to 34 other public utilities and power marketers throughout the region under rates approved by the Federal Energy Regulatory Commission (FERC). Wholesale sales accounted for approximately 9.3% of our total electric energy sales and 5.5% of total electric operating revenues during 2005, compared with 9.7% of our total electric energy sales and 4.1% of total electric operating revenues during 2004 compared with 9.5% of total electric energy sales and 4.0% of total electric operating revenues during 2003.2004.
Electric System Reliability Matters: Electric energy sales are impacted by seasonal factors and varying weather conditions from year-to-year. As a summer peaking utility, we reached our 20042005 electric peak demand obligation of 5,7226,278 megawatts on July 20, 2004August 9, 2005 and our all-time electric peak demand obligation of 6,376 megawatts on August 21, 2003. The summer period is the most relevant period for capacity planning purposes for us due toas a result of cooling load.
We are In 2005 and prior, we were a member of the MAINMid-America Interconnected Network, Inc. (MAIN) reliability council. MAINcouncil, whose guidelines direct members to haverequired a minimum 14.12%14% planning reserve margin for the short-term (up to one year ahead). Effective January 1, 2006, we became a member of ReliabilityFirst Corporation, a successor council encompassing most of the East Central Area Reliability Council and Mid Atlantic Area Council and a portion of MAIN. ReliabilityFirst Corporation has not yet established guidelin es in place priorthis area but members are expected to adhere to the upcoming peak season. PSCW guidelines for electric utilities inof their predecessor councils until new guidelines are established. Because we must also adhere to Public Service Commission of Wisconsin advise a minimum(PSCW) guidelines requiring an 18% planning reserve margin.margin
We had adequate capacity to meet all of our firm electric load obligations during 20042005 and expect to have adequate capacity to meet all of our firm obligations during 2005.2006. For additional information, see “FactorsFactors Affecting Results, Liquidity and Capital Resources”Resources in Item 7. For additional information regarding our generation facilities, see Item 2.
Competition
Prior to 2003, the nation’snation's electric utility industry had been following a trend towards restructuring and increased competition. However, given electric reliability problems experienced in the eastern United States duringeast coast in the summer of 2003 and in the stateState of California in 2001 and 2002, which had previously restructured its electric
2004 Form 10-K
ITEM 1. BUSINESS–(Cont’d)
industry framework, and given the current status of restructuring initiatives in regulatory jurisdictions where we primarily do business, we do not expect to be affected by a significant change in electric regulation in the next five years. The PSCW has been and remains focused on electric reliability infrastructure issues for the stateState of Wisconsin. The stateState of Michigan implemented electric retail access in 2002, and the FERC continues to strongly support the voluntary formation of large Regional Transmission Organizations (RTO) such as the Midwest Independent Transmission System Operator, Inc. (Midwest ISO).MISO. For additional information, see “FactorsFactors Affecting Results, Liquidity and Capital Resources”Resources in Item 7.
Electric Supply
The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, 20042005 as well as an estimate for 2005:2006:
Estimate | Actual | ||||||
2006 | 2005 | 2004 | 2003 | ||||
Coal | 54.7% | 58.5% | 62.5% | 59.4% | |||
Nuclear | 23.8% | 20.3% | 24.4% | 25.0% | |||
Hydroelectric | 1.2% | 1.0% | 1.1% | 1.1% | |||
Natural gas (a) | 4.3% | 3.0% | 0.2% | 0.6% | |||
Oil and Other | 0.1% | - % | - % | 0.1% | |||
Net Generation | 84.1% | 82.8% | 88.2% | 86.2% | |||
Purchased Power | 15.9% | 17.2% | 11.8% | 13.8% | |||
Total | 100.0% | 100.0% | 100.0% | 100.0% | |||
| Estimate 2005 | Actual | |||||||||||
| 2004 | 2003 | 2002 | ||||||||||
Coal | 54.1 | % | 62.5 | % | 59.4 | % | 59.2 | % | ||||
Nuclear | 22.0 | % | 24.4 | % | 25.0 | % | 25.0 | % | ||||
Hydroelectric | 1.2 | % | 1.1 | % | 1.1 | % | 1.4 | % | ||||
Natural gas (a) | 2.2 | % | 0.2 | % | 0.6 | % | 0.8 | % | ||||
Oil and Other | – | % | – | % | 0.1 | % | 0.1 | % | ||||
Net Generation | 79.5 | % | 88.2 | % | 86.2 | % | 86.5 | % | ||||
Purchased Power | 20.5 | % | 11.8 | % | 13.8 | % | 13.5 | % | ||||
Total | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | ||||
(a) | Includes the first natural gas-fired unit at Port Washington Generating Station |
We have not built a base load generating plant since the mid-1980’s. Over the past few years, we have seen an increase in natural gas as a fuel source to meet increased customer demand for electricity. Wisconsin Energy’sEnergy'sPower the Futureplan, which is discussed further in Item 7, Power the Future, includes the addition of 2,320 megawatts of generating capacity over the next sevenfive years. We These plants will be leased to Wisconsin Electric under long-term leases. ThePower is currently buildingthe Futureplanincludes two 545-megawatt natural gas units at anour existing site in Port Washington, Wisconsin. The first natural gas unit is expected to be operational earlywas placed into service in the third quarter ofJuly 2005. The second natural gas unit is expected to be operational by the end of the second quarter ofin 2008. We Power has also received approval from the PSCW to buildbegun construction of two 615-megawatt coal units (of which We Power will own approximately a 515-megawatt share of each unit) at anour existing site in Oak Creek, Wisconsin. The approval to build theseWe anticipate that the first coal units has been challenged, and this matter is scheduled tounit will be heardplaced in service in 2009, followed by the Supreme Court of Wisconsinsecond unit in March 2005. See Item 7, “Factors Affecting Results, Liquidity and Capital Resources–Power the Future” for further discussions on the legal and regulatory challenges associated with the proposed coal plants.2010.
We believe that Wisconsin Energy’sthePower the Futureplan will allow us to better manage the mix of fuels used to generate electricity for our customers. We believe that it is in the best interests of our customers to provide a diverse fuel mix that is expected to maintain a stable, reliable and affordable energy supply in our service territory.
Our net generation, including PWGS Unit 1, totaled 28.0 million megawatt hours during 2005 compared with 29.0 million megawatt hours during 2004 compared withand 27.8 million megawatt hours during 2003 and 27.6 million megawatt hours during 2002.2003. When compared with the
2004 Form 10-K
ITEM 1. BUSINESS–(Cont’d)
Our average fuel and purchased power costs per megawatt hour by fuel type for the years ended December 31 are shown below.below.
| 2004 | 2003 | 2002 | |||||||
Coal | $ | 14.18 | $ | 12.94 | $ | 12.09 | |||
Nuclear | $ | 4.68 | $ | 4.79 | $ | 5.04 | |||
Natural Gas-Peaking Units | $ | 95.16 | $ | 93.42 | $ | 60.56 | |||
Purchased Power | $ | 36.75 | $ | 38.66 | $ | 32.78 | |||
2005 | 2004 | 2003 | ||||
Coal | $14.74 | $14.18 | $12.94 | |||
Nuclear | $5.06 | $4.68 | $4.79 | |||
Natural Gas - Combined Cycle | $84.77 | - | - | |||
Natural Gas - Peaking Units | $125.67 | $95.16 | $93.42 | |||
Purchased Power | $55.47 | $37.49 | $39.11 |
We use natural gas to fuel our peaking units that are designed to run for short durations. The Port WashingtonPWGS natural gas-fired units being constructed by We Power asthat are part of thePower the Future plan are combined cycle facilities that are designed to run for longer durations and at a lower operating cost as compared to a peaking unit. The first unit at PWGS was placed into service in July 2005. We lease Unit 1 at PWGS from We Power.
Coal costs in 2004 were adversely affected byHistorically, the failure of one of our transportation suppliers to deliver coal under a long-term contract, forcing us to obtain replacement coal at substantially higher prices. We are currently evaluating various remedies available for this delivery failure under the transportation contract.
The fuel costs for coal and nuclear generation are relatively stable as the fuel costs are under long-term contracts. However, many existingIn 2005, we entered into new coal contracts to replace certain contracts that expired during 2005. Coal and rail contracts expire at the end of 2005.associated transportation services have seen greater volatility in pricing than typically experienced in these markets. Based on current market conditions, we expect coal and transportation costs to increase more significantly than our most recent historical trend beginning in 2006.
trend.
The costs for natural gas and purchased power, which is primarily natural gas-fired, are more volatile and have experienced significant increases since 2002. Natural gas costs have increased significantly because the supply of natural gas in recent years has not keep pace with the demand for natural gas and due to the impacts of hurricanes on offshore Gulf of Mexico natural gas production. Beginning in late 2003 and concurrent with the approval of the PSCW, we established hedging programs to mitigate significanthelp manage our natural gas price fluctuations due to gas prices.risk. This hedging program is generally implemented on an 18 month forward-looking basis. Proceeds related to the natural gas hedging program are reflected in the 2005 and 2004 average costs of Natural Gasnatural gas and Purchased Powerpurchased power shown above.
Our installed capacity by fuel type for the years ended December 31 is shown below.
Dependable Capability in Megawatts (a) | ||||||
2005 | 2004 | 2003 | ||||
Coal | 3,334 | 3,334 | 3,560 | |||
Nuclear | 1,036 | 1,036 | 1,036 | |||
Natural Gas/Oil (b) | 1,163 | 1,163 | 1,157 | |||
Hydro | 57 | 57 | 57 | |||
Total | 5,590 | 5,590 | 5,810 | |||
| Dependable Capability in Megawatts (a) | ||||||
| 2004 | 2003 | 2002 | ||||
Coal | 3,334 | 3,560 | 3,636 | |||
Nuclear | 1,036 | 1,036 | 1,022 | |||
Natural Gas/Oil (b) | 1,163 | 1,157 | 1,183 | |||
Hydro | 57 | 57 | 57 | |||
Total | 5,590 | 5,810 | 5,898 | |||
(a) | Dependable capability is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. The values were established by test and may change slightly from year to year. |
(b) | Approximately 67% of the Natural Gas/Oil units are dual fueled. The dual fuel facilities generally burn oil only if natural gas is not available due to constraints on the natural gas pipeline and/or at the local gas distribution company that delivers gas to the plants. Total does not include the 545-megawatts of natural gas-fired leased generation from We Power. |
Coal-Fired Generation
Coal-Fired Generation
Coal Supply: We diversify the coal supply for our power plants by purchasing coal from mines in northern and central Appalachia as well as from various western mines. During 2005, 97.6%2006, 99% of our projected coal requirements of 10.5
2004 Form 10-K
ITEM 1. BUSINESS–(Cont’d)
Following is a summary of the annual tonnage amounts for our principal long-term coal contracts by the month and year in which the contracts expire.
Contract | ||
|
| |
Dec. 2006 | 6,388,000 | |
Dec. 2008 | 3,178,000 | |
Dec. 2009 | 19,000 | |
Dec. 2010 | 25,000 |
As of the beginning of 2005, we had approximately a 77-day supply of coal in inventory at our coal-fired facilities.
(a) | Table includes coal for Edgewater 5. We have a 25% interest in Edgewater 5, which is operated by Alliant Energy Corp, an unaffiliated utility. |
Coal Deliveries:Approximately 75%82% of our 20052006 coal requirements are expected to be delivered by unit trains owned or leased by us. The unit trains will transport coal for the Oak Creek, and Pleasant Prairie and Edgewater Power Plants from Wyoming mines. Coal from PennsylvaniaCentral Appalachia and Colorado mines is also transported via rail to Lake Erie or Lake Michigan transfer docks and delivered to the Valley and Milwaukee County Power Plants. Montana and Wyoming coal for Presque Isle Power Plant is transported via rail to Superior, Wisconsin, placed in dock storage and reloaded into lake vessels for plant delivery. Central Appalachia and Colorado coal bound for Presque Isle Power Plant is shipped via rail to Lake Erie and Lake Michigan (Chicago) coal transfer docks, respectively, for lake vessel delivery to the plant.
Environmental Matters: For information regarding emission restrictions, especially as they relate to coal-fired generating facilities, see “EnvironmentalEnvironmental Compliance.”
Nuclear Generation
Point Beach Nuclear Plant: We own two 518-megawatt electric generating units at Point Beach Nuclear Plant (Point Beach) in Two Rivers, Wisconsin. The United States Nuclear Regulatory Commission (NRC) operating licenses for Point Beach expire in October 2010 for Unit 1 and in March 2013 for Unit 2. We and the Nuclear Management Company, LLC (NMC) filed an application with the NRCU.S. Nuclear Regulatory Commission (NRC) in February 2004 to renew the operating licenses for both of our nuclear reactors for an additional 20 years. Based uponIn December 2005, we received approval for license renewal from the NRC’s published schedule, we expect the NRC to make a decision on the license extension application by January 2006.NRC. The new operating licenses for Point Beach will expire in October 2030 for Unit 1 and in March 2033 for Unit 2. For additional information concerning Point Beach, see “FactorsFactors Affecting Results, Liquidity and Capital Resources”Resources in Item 7 and “Note F–Note F -- Nuclear Operations”Operations in the Notes to Consolidated Financial Statements in Item 8.
Nuclear Management Company: NMC, owned by our affiliate WEC Nuclear Corporation and the affiliates of fourtwo other unaffiliated investor-owned utilities in the region, operates Point Beach. NMC currently operates eightsix nuclear generating units at sixfour sites in the states of Wisconsin, Minnesota Michigan, and IowaMichigan with a total combined generating capacity of approximately 4,600 megawatts as of December 31, 2004.3,500 megawatts. We continue to own Point Beach and retain exclusive rights to the energy generated by the plant as well as financial responsibility for the safe operation, maintenance and decommissioning of Point Beach. For further information, see “FactorsFactors Affecting Results, Liquidity and Capital Resources”Resources in Item 7.
Nuclear Fuel Supply: We purchase uranium concentrates (Yellowcake) and contract for its conversion, enrichment and fabrication. There have been numerous events in the nuclear fuel supply market that have affected the price of uranium concentrates, conversion service and enrichment services. The price of the fuel commodities has risen steadily since the fourth quarter of 2003 and we anticipate that the price will continue to rise due to current demand exceeding current supply. NMC is continually monitoring the nuclear fuel commodities market to assess current and future commodity pricing and adjusting purchasing strategies to address changes in the market conditions. We maintain title to the nuclear fuel until fabricated fuel assemblies are delivered to Point Beach; it is
Uranium Requirements: We require approximately 400,000 to 450,000 pounds of Yellowcake to refuel a generating unit at Point Beach. Point Beach has staggered fuel cycles that are expected to average approximately 18 months in duration. The supply of Yellowcake for these refuelings is currently provided through one long-term contract,
2004 Form 10-K
ITEM 1. BUSINESS–(Cont’d)
which supplies 100% of the annual requirements through 2007, with an option to extend the current contract through 2009.
Conversion: We have a long-term contract Contract negotiations through NMC with a providerare currently underway that would supply approximately 25% of uranium conversion services to supply 100% of the conversion requirements for the Point Beach reactors through 2005.requirements from 2010 to 2016.
Conversion: We have the option to utilizeconversion services supply from a share of an NMC fleet contract for conversion services and four spot purchase contracts to meet approximately 56%100% of our conversion requirements for 2006. In 2005, the NMC conversion services contract was amended to supply approximately 20% of the Point Beach requirements through 2006.2010. We are currently pursuingnegotiating additional contracts for conversion services forto meet approximately 50% of the Point Beach to meet the remaining 2006 requirements and additional contracts for supply beyond 2006.through 2011.
Enrichment: We effectively have one long-term contract and another contract through NMC that provide for 100% of the required enrichment services for the Point Beach reactors through the year 2006 and approximately 38% of the enrichment services requirements through 2009. Contract negotiations for additional enrichment services supply are currently underway that would supply the remainder of the Point Beach requirements through 2009.
Fabrication: Fabrication of fuel assemblies from enriched uranium for Point Beach is covered under a contract with Westinghouse Electric Company, LLCLLC. The current contract for the balance of the plant’s current operating licenses.fabrication services is through 2010 for Unit 1 and 2013 for Unit 2.
Used Nuclear Fuel Storage & Disposal: For information concerning used fuel storage and disposal issues, see “FactorsFactors Affecting Results, Liquidity and Capital Resources”Resources in Item 7.
Nuclear Decommissioning: We provide for costs associated with the eventual decommissioning of Point Beach through the use of an external trust fund.funds. Payments to this fund,these funds, together with investment results, brought the balance in the fundfunds at December 31, 20042005 to approximately $737.8$782.1 million. For additional information regarding decommissioning, see “Note F–Note F -- Nuclear Operations”Operations in the Notes to Consolidated Financial Statements in Item 8.
Nuclear Plant Insurance: For information regarding nuclear plant insurance, see “FactorsFactors Affecting Results, Liquidity and Capital Resources”Resources in Item 7 and “Note F–Note F -- Nuclear Operations”Operations in the Notes to Consolidated Financial Statements in Item 8.
Hydroelectric Generation
Our hydroelectric generating system consists of thirteen operating plants with a total installed capacity of approximately 8988 megawatts and a dependable capability of approximately 57 megawatts. Of these thirteen plants, twelve are licensed by the FERC. The thirteenth plant, with an installed generating capacity of approximately 2 megawatts, does not require a license. Of the twelveTwelve licensed plants, eleven plants, representing a total of 8586 megawatts of installed capacity, have long-term licenses from the FERC. A fourteenth non-operating plant, the Sturgeon project, was not relicensed and is in the process of being removed. Staged removal of the Sturgeon project has commenced and is scheduled to be completed by 2006.
Natural Gas-Fired Generation
Our natural gas-fired generation consists of four owned operating plants with a dependable capability of approximately 888 megawatts, and four operating plants under contract with a dependable capability of approximately 1,098 megawatts. In addition, early in the third quarter ofJuly 2005, we expect to add 545 megawattsadded 545-megawatts of leased natural gas-fired generation under long-term lease withwhen the first of two unitsunit at the Port Washington plant under Wisconsin Energy’sPower the Futureplan.PWGS became operational. The second 545-megawatt unit at Port WashingtonPWGS is estimatedexpected to come on line in 2008.
With the exception of one plant under contract, which purchases its own natural gas and transportation services, weWe purchase natural gas for these plants on the spot market from gas marketers, utilities and producers and we arrange for transportation of the natural gas to our plants and plants under contract.plants. We have firm and interruptible transportation, balancing and storage agreements that are intended to facilitatesupport the plants' variable usage pattern of the plants.
usage.
The PSCW has approved a program that allows us to hedge up to 75% of our estimated gas purchasesusage for electric generation. This program is intendedgeneration in order to minimize the volatility ofhelp manage our natural gas prices to our customers.price risk. The costs of this program are included in our fuel and purchased power costs.
2004 Form 10-K
ITEM 1. BUSINESS–(Cont’d)
Oil-Fired Generation
Fuel oil is used for the combustion turbines at the Point Beach and Germantown Power Plants units 1-4. It is also used for boiler ignition and flame stabilization at the Presque Isle Power Plant, as backup for ignition at the Pleasant Prairie Power Plant and as a backup fuel for the natural gas-fired turbines discussed above.which have interruptible transportation. Our oil-fired generation has a dependable capability of approximately 275 megawatts. The natural gas facilities generally burn oil only if natural gas is not available due to constraints on the natural gas pipeline and/or at the local gas distribution company that delivers gas to the plants. Fuel oil requirements are purchased under partnering agreements with suppliers that assist us with inventory tracking and oil market price trends.suppliers.
Purchase Power Commitments
We enter into short and long-term purchase power commitments to meet a portion of our anticipated electric energy supply needs. The following table identifies our purchase power commitments with unaffiliated companies over the next five years:
Year | Megawatts Under Purchase Power Commitments | |
2005 | 1,263 | |
2006 | 1,161 | |
2007 | 1,111 | |
2008 | 651 | |
2009 | 535 |
| Megawatts Under | ||
2006 | 1,195 | ||
2007 | 1,153 | ||
2008 | 703 | ||
2009 | 585 | ||
2010 | 585 |
The majority of these purchase power commitments are tolling arrangements whereby we are responsible for the procurement, delivery and cost of natural gas fuel related to specific units identified in the contracts. The energy costs for the balance of the commitments are tied to the costs of natural gas.
Electric Transmission and Energy Markets
American Transmission Company: Effective January 1, 2001, we transferred all of our electric utility transmission assets to American Transmission Company LLC (ATC) in exchange for an ownership interest in this new company. Joining ATC wasis consistent with the FERC’sFERC's Order No. 2000, designed to foster competition, efficiency and reliability in the electric industry.
ATC is owned and governed by the utilities that contributed facilities or capital in accordance with 1999 Wisconsin Act 9. AtAs of December 31, 2004,2005, we owned approximately 33.2%29.4% of ATC. We anticipate that our ownership will be reduced to approximately 26% by December 31, 2006 as other owners contribute transmission assets to ATC.
ATC’sATC's sole business is to provide reliable, economic electric transmission service to all customers in a fair and equitable manner. Specifically, ATC plans, constructs, operates, maintains and expands transmission facilities it owns to provide for adequate and reliable transmission of electric power. ATC is expected to provide comparable service to all customers, including us, and to support effective competition in energy markets without favoring any market participant. ATC is regulated by the FERC for all rate terms and conditions of service and is a transmission-owning member of the Midwest ISO.MISO. As of February 1, 2002, operational control of ATC’sATC's transmission system was transferred to the Midwest ISO. WeMISO, and we are a non-transmission owning member and customer of the Midwest ISO.
MISO.
We have contracted to provide, at cost, services required by ATC and which ATC is not able to provide itself at this time.ATC. Services include transmission line and substation operation and maintenance, engineering, project, real estate, environmental, supply chain, control center accounting and miscellaneous services. The annual cost of the services that we provided by us was approximately$20.7 $20 million, $30.9$21 million
Midwest ISO:MISO: In connection with its status as a FERC approved RTO, the Midwest ISO is in the process of developing and implementingMISO developed a bid-based energy market. In March 2004,market, the MISO Midwest ISO filed a proposed Energy
2004 Form 10-K
ITEM 1. BUSINESS–(Cont’d)
Markets Tariff thatMarket, which was approved by the FERC, subject to modification, in August 2004 and which will govern the operation of the market. The scheduled implementation date for the bid-based energy market isimplemented on April 1, 2005.
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 Midwest ISO; but it also was the subject of a proceeding in which a new rate design governing service in the combined Midwest ISO and PJM Interconnection, L.L.C (PJM) service territories was to be developed. In November 2004, FERC issued an order allowing the existing Midwest ISO license plate rate design to continue until at least February 1, 2008.
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, 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.
For further information on MISO and the MISO Midwest Market, see “FactorsFactors Affecting Results, Liquidity and Capital Resources”Resources in Item 7.
Renewable Electric Energy
Wisconsin Energy’sEnergy'sPower the Future plan includes a commitment to significantly increase the amount of renewable energy generation we utilize beyond that required by Wisconsin law. Our target is to provide 5% of our retail electric sales in Wisconsin from renewable energy resources by the year 2011. In addition, we have an “"Energy For Tomorrow®Tomorrow®”" renewable energy program to provide our customers the opportunity to purchase energy from renewable resources.
Wisconsin’sWisconsin's public benefits legislation requires that for 2005,2006, retail energy providers supply 1.2% of a three year average of their Wisconsin retail electric sales from renewable energy. The required minimum percentage increases to 2.2% by the year 2011. For more information about public benefits see “Regulation”Regulation below.
In June 2005, we purchased the development rights to two wind farm projects from Navitas Energy Inc. We plan to develop the wind sites and construct wind turbines with a combined generating capability between 130 to 200 megawatts at a cost in the range of $250 to $320 million. We plan to file the necessary regulatory and environmental applications in 2006. We expect the turbines to be placed in service between 2007 and 2008 dependent upon the availability of wind turbines and the receipt of necessary regulatory approvals.
GAS UTILITY OPERATIONS
We are authorized to provide retail gas distribution service in designated territories in the stateState of Wisconsin, as established by indeterminate permits, certificates of public convenience and necessity, or boundary agreements with other utilities. We also transport customer-owned gas. Our gas utility operates in three distinct service areas: west and south of the City of Milwaukee, the Appleton area and areas within Iron and Vilas Counties, Wisconsin.
Gas Deliveries
Our gas utility business is highly seasonal due to the heating requirements of residential and commercial customers. Annual gas sales are also impacted by the variability of winter temperatures.
See “SelectedSelected Operating Data”Data in Item 6 for selected gas utility operating information by customer class during the period 20002001 through 2004.2005.
WeTotal gas therms delivered, approximately 835.1 million therms of gas during 2004, including customer-owned transported gas, a 6.0% decreasewere approximately 902.4 million therms during 2005, an 8.1% increase compared with 2003.2004. At December 31, 2004,2005, we were transporting gas for 368approximately 364 customers who purchased gas directly from other suppliers. Transported gas accounted for approximately 34%39% of the total volumes that we delivered during 2005, 34% during 2004, and 35% during 2003 and 38% during 2002.2003. We had approximately 437,800446,400 gas customers at December 31, 2004,2005, an increase of approximately 2.1%2.0% since December 31, 2003.
2004.
Our maximum daily send-out during 20042005 was 682,933656,249 dekatherms on January 29, 2004.17, 2005. A dekatherm is equivalent to ten therms or one million British thermal units.
2004 Form 10-K
ITEM 1. BUSINESS–(Cont’d)
Sales to Large Gas Customers: We provide gas utility service to a diversified base of industrial customers who are largely within our electric service territory. Major industries served include the paper, food products and fabricated metal products industries. Fuel used for our electric energy supply represents our largest transportation customer.
Gas Deliveries Growth: We currently forecast total therm deliveries of natural gas to grow at an annual rate of approximately 1.0%0.9% for our gas operations over the next five-years.five-year period ending December 31, 2010. This forecast reflects a current year normalized sales level and assumes moderate growth in the economy of our gas utility service territories and normal weather.
Competition
Competition in varying degrees exists between natural gas and other forms of energy available to consumers. Many of our large commercial and industrial customers are dual-fuel customers that are equipped to switch between natural gas and alternate fuels. We are allowed to offer lower-priced interruptible ratesgas sales and transportation services for these customers to enable them to reduce their energy costs and use gas rather than other fuels.dual fuel customers. Under gas transportation agreements, customers purchase gas directly from gas marketers and arrange with interstate pipelines and us to have the gas transported to thetheir facilities where it is used. We earn substantially the same margin (difference between revenue and cost of gas) whether we sell and transport gas to customers or only transport their gas.
Our future ability to maintain our present share of the industrial dual-fuel market (the market that is equipped to use gas or other fuels) depends on our success and the success of third-party gas marketers in obtaining long-term and short-term supplies of natural gas at competitive prices compared to other sources and in arranging or facilitating competitively-priced transportation service for those customers that desire to buy their own gas supplies.
Federal and state regulators continue to implement policies to bring more competition to the gas industry. For information concerning proceedings by the PSCW to consider how its regulation of gas distribution utilities should change to reflect the changing competitive environment in the gas industry, see “FactorsFactors Affecting Results, Liquidity and Capital Resources”Resources in Item 7. While the gas utility distribution function is expected to remain a highly regulated, monopoly function, the sales of the natural gas commodity and related services are expected to become increasinglyremain subject to competition from third parties. However, itIt remains uncertain if and when the current economic disincentives for small customers to choose an alternative gas commodity supplier may be removed such that we begin to face competition for the sale of gas to our smaller firm customers.
Gas Supply, Pipeline Capacity and Storage
We have been able to meet our contractual obligations with both our suppliers and our customers despite periods of severe cold and unseasonably warm weather.
Pipeline Capacity and Storage: Wisconsin Energy has a one-third ownership interest in Guardian pipeline, which receives its gas supply at the Joliet, Illinois market hub. The other interstate pipelines serving Wisconsin originate in three major gas producing areas of North America: the Oklahoma and Texas basins, the Gulf of Mexico and western Canada. We have contracted for long-term firm capacity from each of these areas. This strategy reflects ourmanagement's belief that overall supply security is enhanced by geographic diversification of the supply portfolios and that Canada represents an important long-term source of reliable, competitively-priced gas.
Because of the daily and seasonal variations in gas usage in Wisconsin, we have also contracted for substantial underground storage capacity, primarily in Michigan. Storage capacity enables us to manage significant changes in daily demand and to optimize our overall gas supply and capacity costs. We generally inject gas into storage during the spring and summer months and withdraw it in the winter months. As a result, we can contract for less long-line pipeline capacity than would otherwise be necessary, and can purchase gas on a more uniform daily basis from suppliers year-round. Each of these capabilities enables us to reduce our overall costs.
We also maintain high deliverability storage in the Southeast production areas, as well as in our market area. This storage capacity is designed to deliver gas when other supplies cannot be delivered during extremely cold weather in the producing areas, which can reduce long-line supply.
We hold firm daily transportation and storage capacity entitlements from pipelines and other service providers under long-term contracts.
Term Gas Supply: We currently have contracts for firm supplies with terms in excess of 30 days with suppliers for gas acquired atin the Joliet, Illinois market hub and in the three producing areas discussed above. The pricing of the term
2004 Form 10-K
ITEM 1. BUSINESS–(Cont’d)
contracts is based upon first of the month indices. Combined with our storage capability, we believemanagement believes that the volume of gas under contract is sufficient to meet our forecasted firm peak day demand.
Secondary Market Transactions: Capacity release is a mechanism by which pipeline long-line and storage capacity and gas supplies under contract can be resold in the secondary market. Local distribution companies, like our gas operations, must contract for capacity and supply sufficient to meet the firm peak day demand of our customers. Peak or near peak demand days generally occur only a few times each year. Capacity release facilitates higher utilization of contracted capacity and supply during those times when the full contracted capacity and supply are not needed by us,the utility, helping to mitigate the fixed costs associated with maintaining peak levels of capacity and gas supply. Through pre-arranged agreements and day-to-day electronic bulletin board postings, interested parties can purchase this excess capacity and supply. The proceeds from these transactions are passed through to ratepayers, subject to our gas cost incentive mechanismmechanisms pursuant to which we have ana n opportunity to share in the cost savings. See “FactorsFactors Affecting Results, Liquidity and Capital Resources–Resources -- Rates and Regulatory Matters”Matters in Item 7 for information on the gas cost recovery mechanism. During 2004,2005, we continued our active participation in the capacity release market.
Spot Market Gas Supply: We expect to continue to make gas purchases in the 30-day spot market as price and other circumstances dictate. We have supply relationships with a number of sellers from whom we purchase spot gas.
Hedging Gas Supply Prices:We have PSCW approval to hedge (i) up to 50%45% of planned flowing gas supply using NYMEX-basedNYMEX based natural gas options, (ii) up to 10%15% of planned flowing gas supply using NYMEX based natural gas future contracts and (iii) up to 33%35% of planned storage withdrawals using NYMEX based natural gas options. Those approvals allow us to pass 100% of the hedging costs (premiums and brokerage fees) and proceeds (gains and losses) through our purchase gas adjustment mechanism. Hedge targets (volumes) are provided annually to the PSCW as part of our five-year gas supply plan filing.
To the extent that opportunities develop and our physical supply operating plans will support them, we also have PSCW approval to utilize NYMEX based natural gas derivatives to capture favorable forward market price differentials. That approval provides for 100% of the related proceeds to accrue to our gas cost recovery (incentive) mechanism.
Guardian Pipeline: Wisconsin Energy has a one-third interest in a joint venture, Guardian Pipeline L.L.C. (Guardian). We do not have an ownership interest in Guardian. Two unaffiliated companies also have one-third interests. Guardian owns an interstate natural gas pipeline from the Joliet, Illinois market hub to southeastern Wisconsin that is designed to serve the growing demand for natural gas in Wisconsin and Northern Illinois. Guardian pipeline began commercial operation in early December 2002. Currently, Guardian has firm precedenttransmission service agreements to transport 87%98% of its 750,000 dekatherms per day pipeline design capacity.
Neither Wisconsin Electric nor Together, we and Wisconsin Gas has an ownership interest in Guardian. However, Wisconsin Gas hashave committed to purchase 650,000 dekatherms (approximately 87% of the pipeline’spipeline's total capacity) per day of capacity on the pipeline over a long-term contract that expires in December 2012. In December of each year, Wisconsin Gas assigns its excess capacity for our use.
STEAM UTILITY OPERATIONS
Our steam utility generates, distributes and sells steam supplied by our Valley and Milwaukee County Power Plants. We operate a district steam system in downtown Milwaukee and the near south side of Milwaukee. Steam is supplied to this system from our Valley Power Plant, a coal-fired cogeneration facility. We also operate the steam production and distribution facilities of the Milwaukee County Power Plant located on the Milwaukee County Grounds in Wauwatosa, Wisconsin.
Annual sales of steam fluctuate from year to year based upon system growth and variations in weather conditions. During 2004,2005, the steam utility had $22.0$23.4 million of operating revenues from the sale of 2,908 million pounds of steam compared with$22.0 million of operating revenues from the sale of 2,869 million pounds of steam compared with $22.5 million of operating revenues from the sale of 3,073 million pounds of steam during 2003.2004. As of December 31, 20042005 and 2003,2004, steam was used by approximately 460 customers for processing, space heating, domestic hot water and humidification.
2004 Form 10-K
ITEM 1. BUSINESS–(Cont’d)
UTILITY RATE MATTERS
See “FactorsFactors Affecting Results, Liquidity and Capital Resources–Resources -- Rates and Regulatory Matters”Matters in Item 7.
REGULATION
We arewere an exempt holding company under Section 3(a)(1) of the Public Utility Holding Company Act of 1935, as amended (PUHCA 1935), and Rule 2 hereunderthereunder and, accordingly, arewere exempt from that law’slaw's provisions other than with respect to certain acquisitions of securities of a public utility. In August 2005, President Bush signed into law the Energy Policy Act of 2005 (Energy Policy Act). The Energy Policy Act repealed PUHCA 1935 and enacted the Public Utility Holding Company Act of 2005 (PUHCA 2005), transferring jurisdiction over holding companies from the SEC to the FERC. We will be required to notify the FERC of our status as a holding company by reason of our ownership interest in ATC and to seek from the FERC the exempt status similar to that held under PUHCA 1935. For information on how rates are set see “Factors Affecting Results, Liquidity and Capital Resources–Rates and Regulatory Matters”Matters in Item 7.
We are subject to the Energy Policy Act and the corresponding regulations developed by certain federal agencies. The Energy Policy Act, among other things, repeals PUHCA 1935 making electric utility industry consolidation more possible, authorizes the FERC to review proposed mergers and the acquisition of generation facilities, changes the FERC regulatory scheme applicable to qualifying co-generation facilities and modifies certain other aspects of energy regulations and Federal tax policies applicable to us. Additionally, the Energy Policy Act created an Electric Reliability Organization to be overseen by the FERC, which will establish mandatory electric reliability standards, replacing the current voluntary standards developed by the North American Electric Reliability Council, and will have the authority to levy monetary sanctions for failure to comply with the new standards.
We are subject to the regulation of the PSCW as to retail electric, gas, and steam rates in the stateState of Wisconsin, standards of service, issuance of securities, construction of certain new facilities, transactions with affiliates, billing practices and various other matters. We are subject to regulation of the PSCW as to certain levels of short-term debt obligations. We are subject to the regulation of the MPSC as to the various matters associated with retail electric service in the stateState of Michigan as noted above except as to issuance of securities, construction of certain new facilities, levels of short-term debt obligations and advance approval of transactions with affiliates. Our hydroelectric facilities are regulated by the FERC. We are subject to regulation of the FERC with respect to wholesale power service and accounting.
The following table compares the source of our operating revenues by regulatory jurisdiction for each of the three years in the period ended December 31, 2004.2005.
2005 | 2004 | 2003 | |||||||||||||||||||||||||||
| 2004 | 2003 | 2002 | Amount | Percent | Amount | Percent | Amount | Percent | |||||||||||||||||||||
| Amount | Percent | Amount | Percent | Amount | Percent | ||||||||||||||||||||||||
| (Millions of Dollars) | (Millions of Dollars) | ||||||||||||||||||||||||||||
Wisconsin | |||||||||||||||||||||||||||||
Electric Utility–Retail | $ | 1,830.6 | 70.0 | % | $ | 1,762.8 | 69.9 | % | $ | 1,687.5 | 73.5 | % | |||||||||||||||||
Gas Utility–Retail | 523.8 | 20.0 | % | 513.0 | 20.3 | % | 389.8 | 17.0 | % | ||||||||||||||||||||
Other Utility–Retail | 22.0 | 0.8 | % | 22.4 | 0.9 | % | 21.5 | 0.9 | % | ||||||||||||||||||||
Electric Utility - Retail | $2,049.7 | 69.8% | $1,830.6 | 70.0% | $1,762.8 | 69.9% | |||||||||||||||||||||||
Gas Utility - Retail | 593.6 | 20.2% | 523.8 | 20.0% | 513.0 | 20.3% | |||||||||||||||||||||||
Steam Utility - Retail | 23.5 | 0.8% | 22.0 | 0.8% | 22.4 | 0.9% | |||||||||||||||||||||||
Total | 2,376.4 | 90.8 | % | 2,298.2 | 91.1 | % | 2,098.8 | 91.4 | % | 2,666.8 | 90.8% | 2,376.4 | 90.8% | 2,298.2 | 91.1% | ||||||||||||||
Michigan | |||||||||||||||||||||||||||||
Electric Utility–Retail | 134.4 | 5.1 | % | 123.9 | 4.9 | % | 110.7 | 4.8 | % | ||||||||||||||||||||
Electric Utility - Retail | 143.2 | 4.9% | 134.4 | 5.1% | 123.9 | 4.9% | |||||||||||||||||||||||
FERC | |||||||||||||||||||||||||||||
Electric Utility–Wholesale | 105.8 | 4.1 | % | 99.8 | 4.0 | % | 86.4 | 3.8 | % | ||||||||||||||||||||
Electric Utility - Wholesale | 128.0 | 4.3% | 105.8 | 4.1% | 99.8 | 4.0% | |||||||||||||||||||||||
Total Utility Operating Revenues | $ | 2,616.6 | 100.0 | % | $ | 2,521.9 | 100.0 | % | $ | 2,295.9 | 100.0 | % | $2,938.0 | 100.0% | $2,616.6 | 100.0% | $2,521.9 | 100.0% | |||||||||||
For information concerning the implementation of full electric retail competition in the stateState of Michigan effective January 1, 2002, see “FactorsFactors Affecting Results, Liquidity and Capital Resources”Resources in Item 7.
Operation and construction relating to our Point Beach Nuclear Plant are subject to regulation by the NRC. Our operations are also subject to regulations, where applicable, of the United States Environmental Protection Agency (EPA), the Wisconsin Department of Natural Resources (WDNR), the Michigan Department of Natural Resources and the Michigan Department of Environmental Quality.
Electric Reliability Legislation: In 1998, the Wisconsin State Legislature passed and the Governor of Wisconsin signed into law 1997 Wisconsin Act 204, intended to address concerns with electric reliability in the state of Wisconsin. 1997 Wisconsin Act 204 included new requirements concerning market power which utilities and their affiliates must meet in order to construct generating facilities. The requirements apply to electric utility facilities in excess of 100 megawatts.
Public Benefits:Public benefits legislation was included in 1999 Wisconsin Act 9. The law created new funding which is adjusted annually to be collected by all electric utilities and remitted to the Wisconsin Department of
2004 Form 10-K
ITEM 1. BUSINESS–(Cont’d)
programs to the DOA. We implemented this change in October 2000. The utilities’utilities' traditional role of providing these programs has shifted to the DOA, which administers the funds for a statewide public benefits program. As part of its order authorizing the construction of We Power’sthe two coal units under Wisconsin Energy’sEnergy'sPower the Future strategy, the PSCW required us to implement an energy efficiency program for the years 2005-2008 in addition to the DOA-administeredDOA administered programs.
This law also requires that for 2005,2006, retail energy providers supply 1.2% of a three-yearthree year average of their Wisconsin retail electric sales from renewable energy. The required minimum percentage increases to 2.2% by the year 2011.
ENVIRONMENTAL COMPLIANCE
Environmental Expenditures
Expenditures for environmental compliance and remediation issues are included in anticipated capital expenditures described in “LiquidityLiquidity and Capital Resources”Resources in Item 7. For discussion of additional environmental issues, see Environmental Matters in Item 3. For further information concerning air quality standards and rulemaking initiated by the EPA, including estimated costs of compliance, see “FactorsFactors Affecting Results, Liquidity and Capital Resources”Resources in Item 7.
Our compliance with federal, state and local environmental protection requirements resulted in capital expenditures of approximately $153 million in 2005 compared with $78 million in 2004 compared with $15 million in 2003.2004. Expenditures incurred during 20042005 primarily included costs associated with the installation of pollution abatement facilities at our power plants. These expenditures are expected to approximate $147$83 million during 2005,2006, reflecting nitrogen oxide (NOx), sulfur dioxide (SO2) and other pollution control equipment needed to comply with various rules promulgated by the EPA.
We estimate that our operation, maintenance and depreciation expenses for fly ash removal equipment and other environmental protection systems were approximately $40 million during 2005 and $52 million during 2004 and $51 million during 2003.2004.
Solid Waste Landfills
We provide for the disposal of non-ash related solid wastes and hazardous wastes through licensed independent contractors, but federal statutory provisions impose joint and several liability on the generators of waste for certain cleanup costs. Currently there are no active cases.cases against us.
Coal-Ash Landfills
Some early designed and constructed coal-ash landfills may allow the release of low levels of constituents resulting in the need for various levels of remediation. Where we have become aware of these conditions, efforts have been expended to define the nature and extent of any release, and work has been performed to address these conditions. For additional information, see “Note P–Note Q -- Commitments and Contingencies”Contingencies in the Notes to Consolidated Financial Statements in Item 8. Sites currently undergoing remediation and/or monitoring include:
Lakeside Property: During 2001, we completed an investigation of property that was used primarily for coal storage, fuel oil transport and coal ash disposal in support of the former Lakeside Power Plant in St. Francis, Wisconsin. Excavation and utilization of residual coal at the site, slope stabilization and cover construction have been completed. Currently, discussion is taking place with neighbors and other interested parties to determine the ultimate use of the remediated property and some other adjacent land that we also own. Future costs for remediation of this site are estimated to be approximately $1.0 million.
Oak Creek North Landfill: Groundwater impairments at this landfill, located in the City of Oak Creek, Wisconsin, prompted us to investigate, during 1998, the condition of the existing cover and other conditions at the site. Surface water drainage improvements were implemented at this site during 1999 and 2000, which are expected to eliminate ash contact with water and remove unwanted ponding of water near monitoring systems.water. Future costs for remediation are estimated to be approximately $1.5 million and involve reconfiguration of the site and construction of a new cap, which will be accomplished as a part of site upgrades needed to facilitate construction of the new power plants.
2004 Form 10-K
ITEM 1. BUSINESS–(Cont’d)
Manufactured Gas Plant Sites
We are reviewing and addressing environmental conditions at a number of former manufactured gas plant sites. See “Environmental Matters” in Item 3 and “Note P–Note Q -- Commitments and Contingencies”Contingencies in the Notes to Consolidated Financial Statements in Item 8.
Air Quality
The 1990 amendments to the Federal Clean Air Act mandate significant nationwide reductions in air emissions. The most significant sections of this law applicable to the country’s electric utilities are the acid rain and non-attainment provisions. The acid rain provisions limit SO2 and NOx emissions in phases. The amendments’ Phase II requirements are having a minimal impact on our utilities because of existing cost effective compliance strategies and previous actions taken.
The 1-hour ozone non-attainment rules implemented by the state of Wisconsin and ozone transport rules implemented by the state of Michigan, both under authority of the Federal Clean Air Act, will limit NOx emissions in phases ending in 2007.
In 2004, the EPA began implementing the National Ambient Air Quality Standards for 8-hour ozone and fine particulate matter (PM2.5).
See “FactorsFactors Affecting Results, Liquidity and Capital Resources”Resources -- Environmental Matters in Item 7 for additional information concerning National Ambient Air Quality Standards established during 1997 by the EPA and ozone non-attainment rulemaking promulgated by the EPA during 1998.Quality.
Clean Water Act
Wisconsin Energy’sPower the Futurestrategy provides a plan to meet our growing demand for electricity while using environmentally friendly equipment. Wisconsin Energy plans to build two coal units (the Elm Road units) at the site of our existing Oak Creek Power Plant. The Elm Road units will use a supercritical pulverized coal design and state-of-the-art emission controls. Two natural gas-fired units are being constructed at our existing Port Washington Power Plant site, where older, less efficient coal-fired units installed before 1950 were retired in 2003 and 2004. Implementation of Wisconsin Energy’sPower the Futureplan also provides for upgrades to our existing power plants and modernization to increase efficiency and reduce emissions. As a result of the use of the latest emission reduction technologies on the new units, and the installation of equipment to reduce emissions on certain of our existing coal-fired units, the plan is expected to result in a significant reduction in SO2, NOx and mercury emissions. In addition to the positive environmental attributes of the generation technologies, the plan involves an increased commitment to conservation and renewable fuels, as well as a commitment to reduce greenhouse gases. For further information about Wisconsin Energy’sPower the Future strategy, see “FactorsSee Factors Affecting Results, Liquidity and Capital Resources–Power the Future–Elm Road”Resources -- Environmental Matters in Item 7.
Clean Water Act
Section 316(b) of7 for additional information concerning the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impact. This law dates back to 1972; however, prior to September 2004, there have not been federal rules that define precisely how states and EPA regions would determine that an existing intake meets BTA requirements. This rule establishes, for the first time, national performance standards and compliance alternatives for existing facilities that are designed to minimize the potential adverse environmental impacts to aquatic organisms associated with water withdrawals from cooling water intakes. Costs associated with implementation of the rule for our Oak Creek Power Plant, and We Power’s Elm Road Generating Station and Port Washington Generating Station have been included in project costs. Studies to determine costs, if any that may be associated with our other existing facilities are expected to take place over the next three years.Act.
OTHER
2004 Form 10-K
ITEM 1. BUSINESS–(Cont’d)
OTHER
Research and Development: We had immaterial research and development expenditures in the last three years, primarily for improvement of service and abatement of air and water pollution by our electric utility operations. Research and development activities include work done by employees, consultants and contractors, plus sponsorship of research by industry associations.
Employees:At December 31, 2004,2005, we had 4,7914,653 total employees, of which 3,3953,207 were represented under labor agreements. We had the following employees represented under labor agreements with the following bargaining units as of December 31, 2004.2005:
Number of | Expiration Date of | ||||||
Local 2150 of International Brotherhood of Electrical Workers |
|
| |||||
Local 317 of International Union of Operating Engineers |
|
| |||||
Local 12005 of United Steel Workers of America (a) |
|
| |||||
Local 510 of International Brotherhood of Electrical Workers |
|
| |||||
Local 7-0111 of Paper, |
|
| |||||
Total | 3,207 | ||||||
| |||||||
During 2004, labor and management successfully renegotiated four of these contracts covering 2,967 employees.
ITEM 1A. | ||||
RISK FACTORS |
Our business is significantly impacted by governmental regulation.
We are subject to significant state, local and federal governmental regulation. We are subject to the regulation of the PSCW as to retail electric, gas and steam rates in the State of Wisconsin, standards of service, issuance of securities, short-term debt obligations, construction of certain new facilities, transactions with affiliates, billing practices and various other matters. In addition, we are subject to the regulation of the MPSC as to the various matters associated with retail electric service in the State of Michigan, except as to issuance of securities, construction of certain new facilities, levels of short-term debt obligations and advance approval of transactions with affiliates. Further, our hydroelectric facilities are regulated by the FERC, and the FERC also regulates our wholesale power service and accounting practices. Our significant level of regulation imposes restrictions on our operations and causes us to incur substantial compliance costs.
We estimate that approximately 88% of our electric revenues are regulated by the PSCW, 6% are regulated by the MPSC and the balance of our electric revenues is regulated by the FERC. All of our natural gas revenues are regulated by the PSCW.
Our ability to obtain rate adjustments in the future is dependent upon regulatory action and there can be no assurance that we will be able to obtain rate adjustments in the future that will allow us to maintain our current authorized rates of return.
Factors beyond We Power's control could adversely affect project costs and completion of the natural gas-fired and coal-fired generating units We Power is constructing as part of Wisconsin Energy's Power the Future strategy.
Under Wisconsin Energy'sPower the Future strategy, we expect to meet a significant portion of our future generation needs through the leasing of two 545-megawatt natural gas-fired generating units at the Port Washington Generating Station and two 615-megawatt coal-fired generating units (of which We Power will own a 515-megawatt share) to be located adjacent to our Oak Creek Power Plant. These new generating facilities are being constructed by We Power and will be leased to us under long-term leases. The first of these four units was placed into service in July 2005.
Large construction projects of this type are subject to usual construction 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, 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 law or regulations, adverse interpretation or enforcement of permit conditions, laws and regulations by the permitting agencies, governmental actions and events in the global economy.
As required by the Energy Policy Act, FERC developed new rules to implement certain provisions of the Energy Policy Act. Pursuant to these new rules, we are required to seek FERC authorization to lease from We Power the threePower the Futureunits that are currently being constructed by We Power. We are unable to determine at this time the magnitude of this new regulatory requirement on thePower the Future plan, if any.
We face significant costs of compliance with existing and future environmental regulations.
We are subject to extensive environmental regulations relating to, among other things, air emissions such as carbon dioxide, sulfur dioxide, nitrogen oxide, small particulates and mercury, water discharges and management of hazardous and solid waste. We incur significant expenditures in complying with these environmental requirements, including expenditures for the installation of pollution control equipment, environmental monitoring, emissions fees and permits at all of our facilities.
Existing environmental regulations may be revised or new laws or regulations may be adopted which could result in significant additional expenditures and operating restrictions on our facilities. In the event we are not able to
In addition, we may also be responsible for liabilities associated with the environmental condition of the facilities that we have previously owned and operated, regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. The incurrence of a material environmental liability could have a significant adverse effect on our results of operations and financial condition.
Ownership and operation of nuclear generating units involve inherent risks that may result in substantial costs and liabilities.
We own two 518-megawatt nuclear electric generating units at the Point Beach site. The units are operated by NMC, a joint venture of Wisconsin Energy and affiliates of other unaffiliated utilities. During 2005, our nuclear generating units provided 20% of our net electric energy supply. Our nuclear facilities are subject to environmental, health and financial risks, including: handling of nuclear materials, on-site storage of spent nuclear fuel and the current lack of a long-term solution for disposal of materials; mechanical or structural problems; lapses in maintenance procedures; human errors in the operation of the reactors or safety systems; the threat of possible terrorist attacks; limitations on the amounts and types of insurance coverage commercially available; the continued ability of NMC to effectively manage and operate our nuclear facilities; and uncertainties regarding our ability to maintain adequate reserves for decommissioning the units. While we have no reason to anticipate a ser ious nuclear incident at our units, if an incident were to occur, it could result in substantial costs to us that may significantly exceed the amount of our insurance coverage and reserves.
The NRC has broad authority to impose licensing and safety related requirements for the operation of nuclear generating facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, until compliance is achieved. Further, in the event of a major incident at a nuclear facility anywhere in the world, the NRC could limit or prohibit the operation or licensing of any domestic nuclear unit.
As a result of the September 11, 2001 terrorist attacks, the NRC and the industry have been strengthening security at nuclear power plants. Increased security measures and other safety requirements could require us to make substantial capital expenditures at our nuclear generating units.
Energy sales are impacted by seasonal factors and varying weather conditions from year-to-year.
Our electric and gas utility businesses are generally seasonal businesses. Demand for electricity is greater in the summer and winter months associated with cooling and heating. In addition, demand for natural gas peaks in the winter heating season. As a result, our overall results in the future may fluctuate substantially on a seasonal basis. In addition, we have historically had lower revenues and net income when weather conditions are milder. Our rates in Wisconsin are set by the PSCW based on estimated temperatures which approximate 20-year averages. Below normal temperatures during the summer cooling season, and to a lesser extent, above normal temperatures during the winter heating season will negatively impact the results of operations and cash flows of our electric utility business. In addition, above normal temperatures during the winter heating season negatively impact the results of operations and cash flows of our gas utility business.
Higher natural gas costs may negatively impact our electric and gas utility operations.
Significant increases in the cost of natural gas affect our electric and gas utility operations. Natural gas costs have increased significantly, both because the supply of natural gas in recent years has not kept pace with the demand for natural gas, which has grown throughout the United States as a result of increased reliance on natural gas-fired electric generating facilities, and due to the impacts of hurricanes on offshore Gulf of Mexico natural gas production. We expect that demand for natural gas will remain high into the foreseeable future and that significant price relief will not occur until additional natural gas reserves are developed.
Our electric operations burn natural gas in several of our peaking power plants and in the leased Port Washington Generation Station Unit 1 and as a supplemental fuel at several coal-fired plants, and in many instances the cost of purchased power is tied to the cost of natural gas. In addition, higher natural gas costs also can have the effect of increasing demand for other sources of fuel thereby increasing the costs of these fuels as well.
In addition, higher natural gas costs increase our working capital requirements. As a result of gas cost recovery mechanisms, our gas distribution business receives dollar for dollar pass through of the cost of natural gas. However, increased natural gas costs increase the risk that customers will switch to alternative sources of fuel or reduce their usage, which could reduce future gas margins. We have experienced reduced usage of natural gas by our residential customers in 2005 and expect this to continue during the 2006 winter heating season. In addition, higher natural gas costs combined with slower economic conditions also exposes us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills.
We may not be able to obtain an adequate supply of coal, which could limit our ability to operate our facilities.
We are dependent on coal for much of our electric generating capacity. While we have coal supply and transportation contracts in place, there can be no assurance that the counterparties to these agreements will fulfill their obligations to supply coal to us. The suppliers under these agreements may experience financial or operational problems which inhibit their ability to fulfill their obligations to us. In addition, suppliers under these agreements may not be required to supply coal to us under certain circumstances, such as in the event of a natural disaster. If we are unable to obtain our coal requirements under our coal supply and transportation contracts, we may be required to purchase coal at higher prices, or we may be forced to obtain additional megawatt hour purchases through other potentially higher cost generating resources in the MISO Midwest Market. Higher costs to obtain coal increase our working capital requirements.
Our financial performance may be adversely affected if we are unable to successfully operate our facilities.
Our financial performance depends on the successful operation of our electric generating and gas distribution facilities. Operation of these facilities involves many risks, including: operator error and breakdown or failure of equipment processes; fuel supply interruptions; labor disputes; operating limitations that may be imposed by environmental or other regulatory requirements; or catastrophic events such as fires, earthquakes, explosions, floods or other similar occurrences. Unplanned generation outages can result in additional maintenance expenses as well as incremental replacement power costs.
We are exposed to risks related to general economic conditions in our service territories.
Our electric and gas utility businesses are impacted by the economic cycles of the customers we serve. In the event regional economic conditions decline, we may experience reduced demand for electricity or natural gas which could result in decreased earnings and cash flow. In addition, regional economic conditions also impact our collections of accounts receivable.
Our business is dependent on our ability to successfully access capital markets.
We rely on access to short-term and long-term capital markets to support our capital expenditures and other capital requirements, including expenditures for our utility infrastructure and to comply with future regulatory requirements. We have historically secured funds from a variety of sources, including the issuance of short-term and long-term debt securities and preferred stock. Successful implementation of our long-term business strategies is dependent upon the ability of us to access the capital markets under competitive terms and rates. If our access to the capital markets were limited due to a ratings downgrade, prevailing market conditions or other factors, our results of operations and financial condition could be significantly adversely affected.
Repeal of the Public Utility Holding Company Act of 1935 and enactment of the Public Utility Holding Company Act of 2005 may subject us to increased regulation.
We were an exempt holding company under PUHCA 1935, and, accordingly, were exempt from that law's provisions other than with respect to certain acquisitions of securities of a public utility. However, the Energy Policy Act repealed PUHCA 1935 and enacted PUHCA 2005, transferring jurisdiction over holding companies from the SEC to the FERC. We will be required to notify the FERC of our status as a holding company and to seek from the FERC the exempt status similar to that held under PUHCA 1935. If we are unable to obtain exempt status from the FERC, we may become subject to increased regulation as a holding company by the FERC.
Restructuring in the regulated energy industry could have a negative impact on our business.
The regulated energy industry continues to experience significant structural changes. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant adverse financial impact on us. The timeline for restructuring and retail access continues to be stretched out, and it is uncertain when retail access will happen in Wisconsin; however, Michigan has adopted retail choice which potentially affects our Michigan operations. Under retail access legislation, customers are permitted to choose their own electric generation supplier. All Michigan electric customers were able to choose their electric generation supplier beginning in January 2002. Although competition and customer switching to alternative suppliers in our service territory in Michigan has been limited, the additional competitive pressures resulting from retail access could lead to a loss of customers and our incurring stranded costs.
The FERC continues to support the existing RTOs which affect the structure of the wholesale market within those RTOs. In connection with its status as a FERC approved RTO, MISO implemented the MISO Midwest Market on April 1, 2005. The MISO Midwest Market rules require that all market participants submit day-ahead and/or real-time bids and offers for energy at locations across the MISO region. MISO then calculates the most efficient solution for all of the bids and offers made into the market that day and establishes a locational marginal price (LMP) which reflects the market price for energy. As a participant in the new MISO Midwest Market, we are required to follow MISO's instructions when dispatching generating units to support MISO's responsibility for maintaining stability of the transmission system.
Additionally, the MISO Midwest Market subjects us to additional costs primarily associated with constraints in the transmission system. MISO implemented the LMP system, a market-based platform for valuing transmission congestion. The LMP system includes the ability to mitigate or eliminate congestion charges through the use of financial transmission rights (FTRs). FTRs are allocated to market participants by MISO. We are presently operating under an FTR allocation that will be in effect through May 31, 2006. To date, our unhedged congestion charges have not been material. However, there can be no assurance that we will be granted an adequate level of FTRs in the future to avoid material unhedged congestion charges.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIESITEM 2. PROPERTIES
We own our principal properties outright, except that the major portion of electric utility distribution lines, steam utility distribution mains and gas utility distribution mains and services are located, for the most part, on or in streets and highways and on land owned by others.
Effective January 1, 2001, we exited the electric transmission business by contributing all of our transmission assets to ATC in exchange for an equity interest in this new company. For further information, see “Electric Utility Operations” in Item 1.
As of December 31, 2004,2005, we own the following generating stations with dependable capabilities during 20042005 as indicated.
No. of | Dependable Capability | ||||||||
Name | Fuel | Units | July | December | |||||
Steam Plants | |||||||||
Point Beach | Nuclear | 2 | 1,026 | 1,036 | |||||
Oak Creek | Coal | 4 | 1,135 | 1,139 | |||||
Presque Isle | Coal | 9 | 618 | 618 | |||||
Pleasant Prairie | Coal | 2 | 1,224 | 1,234 | |||||
Valley | Coal | 2 | 267 | 227 | |||||
Edgewater 5 (b) | Coal | 1 | 105 | 105 | |||||
Milwaukee County | Coal | 3 | 10 | 11 | |||||
Total Steam Plants | 23 | 4,385 | 4,370 | ||||||
Hydro Plants (13 in number) | 33 | 54 | 57 | ||||||
Germantown Combustion Turbines | Gas/Oil | 5 | 345 | 345 | |||||
Concord Combustion Turbines | Gas/Oil | 4 | 376 | 376 | |||||
Paris Combustion Turbines | Gas/Oil | 4 | 400 | 400 | |||||
Other Combustion Turbines & Diesel | Gas/Oil | 4 | 38 | 42 | |||||
Total System | 73 | 5,598 | 5,590 | ||||||
Name | Fuel | No. of Units | Dependable Capability In Megawatts (a) | |||||
| July | December | |||||||
Steam Plants | ||||||||
Point Beach | Nuclear | 2 | 1,026 | 1,036 | ||||
Oak Creek | Coal | 4 | 1,135 | 1,139 | ||||
Presque Isle | Coal | 9 | 618 | 618 | ||||
Pleasant Prairie | Coal | 2 | 1,224 | 1,234 | ||||
Valley | Coal | 2 | 267 | 227 | ||||
Edgewater 5 (b) | Coal | 1 | 105 | 105 | ||||
Milwaukee County | Coal | 3 | 10 | 11 | ||||
Total Steam Plants | 23 | 4,385 | 4,370 | |||||
Hydro Plants (13 in number) | 33 | 54 | 57 | |||||
Germantown Combustion Turbines | Gas/Oil | 5 | 345 | 345 | ||||
Concord Combustion Turbines | Gas/Oil | 4 | 376 | 376 | ||||
Paris Combustion Turbines | Gas/Oil | 4 | 400 | 400 | ||||
Other Combustion Turbines & Diesel | Gas/Oil | 4 | 38 | 42 | ||||
Total System | 73 | 5,598 | 5,590 | |||||
(a) | Dependable capability is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. Changing seasonal conditions are responsible for the different capabilities reported for the winter and summer periods in the above table. The values were established by test and may change slightly from year to year. |
(b) | We have a 25% interest in Edgewater 5 Generating Unit, which is operated by Alliant Energy Corp, an unaffiliated utility. |
Effective July 2005, we began leasing PWGS Unit 1, a 545-megawatt natural gas-fired generation unit, from We Power under a 25 year lease. In addition, we have a power purchase contract with an unaffiliated independent power producer. The contract is for 236 megawatts of firm capacity from a gas-fired cogeneration facility that expires in 2022.
As of December 31, 2004,2005, our electric utility operated approximately 21,900 pole-miles of overhead distribution lines and 20,40021,700 miles of underground distribution cable, as well as approximately 352390 distribution substations and 267,700272,200 line transformers.
As of December 31, 2004,2005, our gas distribution system included approximately 8,9839,100 miles of mains connected at 22 gate stations to the pipeline transmission systems of ANR Pipeline Company, Guardian, Natural Gas Pipeline Company of America, Northern Natural Pipeline Company and Great Lakes Transmission Company. We have a liquefied natural gas storage plant which converts and stores in liquefied form natural gas received during periods of low consumption. The liquefied natural gas storage plant has a send-out capability of 70,000 dekatherms per day. We also have a propane air system for peaking purposes. This propane air system will provide approximately 2,000 dekatherms per day of supply to the system.
Where electric distribution lines and services and gas distribution mains
2004 Form 10-K
ITEM 2. PROPERTIES–(Cont’d)
As of December 31, 2004,2005, the combined steam systems supplied by the Valley and Milwaukee County Power Plants consisted of approximately 43 miles of both high pressure and low pressure steam piping, nine9 miles of walkable tunnels and other pressure regulating equipment.
We own various office buildings and service centers throughout our service area.
ITEM 3. | LEGAL PROCEEDINGS |
In addition to those legal proceedings discussed below, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these legal proceedings cannot be predicted with certainty, we believe, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material adverse effect on our financial statements.
ENVIRONMENTAL MATTERS
We are subject to federal, state and certain local laws and regulations governing the environmental aspects of our operations. We believeManagement believes that, perhaps with immaterial exceptions, our existing facilities are in compliance with applicable environmental requirements.
EPA Information Requests:We responded to an EPA request for information pursuant to Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) Section 104(e) for the Solvay Coke and Gas Site located in Milwaukee, Wisconsin. All potentially responsive records and corporate legal files have been reviewed and responsive information was provided in October 2004. A predecessor company of ours owned a parcel of property that is within the property boundaries of the site. We have not been named as a potentially responsible party at this time. Although we have not accepted responsibility for costs of any sort related to the property, remediation cost estimates and reserves continue to be included in the estimated manufactured gas plant values reported in “Note P–Note Q -- Commitments and Contingencies”Contingencies in the Notes to Consolidated Financial Statements in Item 8.
See “Environmental Compliance”Environmental Compliance in Item 1 and “EnvironmentalEnvironmental Matters,” “Manufactured Manufactured Gas Plant Sites,” “Ash Ash Landfill Sites”Sites and “EPA Information Requests”EPA - Proposed Consent Decree in “Note P–Note Q -- Commitments and Contingencies”Contingencies in the Notes to Consolidated Financial Statements, which are incorporated by reference herein, for a discussion of matters related to certain solid waste and coal-ash landfills, manufactured gas plant sites and air quality.
UTILITY RATE MATTERS
See “FactorsFactors Affecting Results, Liquidity and Capital Resources–Resources -- Rates and Regulatory Matters”Matters in Item 7 for information concerning rate matters in the jurisdictions where we do business.
OTHER MATTERS
Used Nuclear Fuel Storage and Removal:See “FactorsFactors Affecting Results, Liquidity and Capital Resources–Resources -- Nuclear Operations”Operations in Item 7 for information concerning the United States Department of Energy’sEnergy's breach of a contract with us that required the Department of Energy to begin permanently removing used nuclear fuel from Point Beach Nuclear Plant by January 31, 1998.
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 ourits electrical system.
On June 25, 2003, the Wisconsin Supreme Court upheld a Court of Appeals decision that affirmed a jury’s verdict against us, awarding $1.2 million to the plaintiffs in a stray voltage lawsuit. The Wisconsin Supreme Court rejected the argument that if a utility company’s measurement of stray voltage is below the PSCW “level of concern,” such
2004 Form 10-K
ITEM 3. LEGAL PROCEEDINGS–(Cont’d)
company cannot be found negligent in stray voltage cases. The Supreme Court decision held that PSCW regulations regarding stray voltage were only minimum standards to be considered by a jury in stray voltage litigation. However, the Supreme Court remanded back to the trial court its requirement imposed on us to replace a cable with an ungrounded distribution line. In February 2005, the parties reached an agreement in principle to settle all remaining issues in the case.
On February 26, 2004, a Wisconsin jury awarded $850,000 to a dairy farmer who alleged that our distribution system caused damages to his livestock. We have filed an appeal in this decision. In May 2005, a stray voltage
Even though any claims which may be made against us with respect to stray voltage case was pending; however, the parties reached an agreement in principleand ground currents are not expected to settle all issues in the case.have a material adverse effect on its financial condition, we continue to evaluate various options and strategies to mitigate this risk. For additional information, see “FactorsFactors Affecting Results, Liquidity and Capital Resources–Resources -- Legal Matters”Matters in Item 7.
Electromagnetic Fields:Claims have been made or threatened against electric utilities across the country for bodily injury, disease or other damages allegedly caused or aggravated by exposure to electromagnetic fields associated with electric transmission and distribution lines. Results of scientific studies conducted to date have not established the existence of a causal connection between electromagnetic fields and any adverse health affects. We believe that our facilities are constructed and operated in accordance with applicable legal requirements and standards. Currently, there are no cases pending or threatened against us with respect to damage caused by electromagnetic fields.
For information regarding additional legal matters, see “FactorsFactors Affecting Results, Liquidity and Capital Resources–Resources -- Legal Matters”Matters in Item 7.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS |
No matters were submitted to a vote of our security holders during the fourth quarter of 2004.
2004 Form 10-K2005.
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages at December 31, 20042005 and positions of our executive officers are listed below along with their business experience during the past five years. All officers are appointed until they resign, die or are removed pursuant to the Bylaws. There are no family relationships among these officers, nor is there any agreement or understanding between any officer and any other person pursuant to which the officer was selected. Reference to Wisconsin Gas LLC includes the time spent with the Company prior to its predecessor, Wisconsin Gas Company.conversion from a corporation to a limited liability company.
Gale E. Klappa.Age 54.55.
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Charles R. Cole.Age 58.Cole.Age 59.
• Company–Company - Senior Vice President since 2001. Vice President of Distribution Operations from 1999 to 2000.
• LLC–LLC - Senior Vice President since July 2004.
Stephen P. Dickson.Age 44.Dickson.Age 45.
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Frederick D. Kuester.Age 54.55.
• Corporation–Corporation - Executive Vice President since May 2004.
• Company–Company - Executive Vice President since May 2004. Chief Operating Officer since October 2003.
• LLC–LLC - Executive Vice President since May 2004.
• Corporation–Corporation- Senior Vice President–President - International from 2001 to October 2003 and Chief Executive Officer of Mirant Asia-Pacific Limited from 1999 to October 2003. Mirant is a multi-national energy company that produces and sells electricity. Mirant Corporation and certain of its subsidiaries voluntarily filed for bankruptcy in July 2003. Other than certain Canadian subsidiaries, none of Mirant’sMirant's international subsidiaries filed for bankruptcy.
Allen L. Leverett.Age 38.39.
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Georgia Power Company–Company - Executive Vice President, Treasurer and Chief Financial Officer and Treasurer from May 2002 to July 2003. Assistant Treasurer from 2000 to 2002. Georgia Power Company is a utility affiliate of The Southern Company, which is a public utility holding company serving the southeastern United States.
•
Southern Company Services, Inc.– - Vice President and Treasurer from 2000 to 2002. Vice President of Financial Planning and Analysis from 1997 to 2000. Southern Company Services is also an affiliate of The Southern Company.
2004 Form 10-K
EXECUTIVE OFFICERS OF THE REGISTRANT–(Cont’d)
Kristine A. Rappé. Age 48..Age 49.
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Larry Salustro.Age 57.Salustro.Age 58.
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Certain executive officers also hold offices in Wisconsin Energy’sEnergy's non-utility subsidiaries.subsidiaries and our non-utility subsidiary.
In addition, effective January 3, 2006, James C. Fleming was appointed Executive Vice President of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas LLC.
James C. Fleming.Age 60.
PART II
ITEM 5. | MARKET FOR |
DIVIDENDS AND COMMON STOCK PRICES
Dividends declared on our common stock during the two most recent fiscal years are set forth below. Dividends were paid entirely in cash. Dividends were paid to our sole common stockholder, Wisconsin Energy Corporation. There is no established public trading market for our common stock.
Quarter | 2005 | 2004 | ||
(Millions of Dollars) | ||||
First | $44.9 | $44.9 | ||
Second | 44.9 | 44.9 | ||
Third | 44.9 | 44.9 | ||
Fourth | 44.9 | 44.9 | ||
Total | $179.6 | $179.6 | ||
Quarter | 2004 | 2003 | ||||
| (Millions of Dollars) | ||||||
First | $ | 44.9 | $ | 44.9 | ||
Second | 44.9 | 44.9 | ||||
Third | 44.9 | 44.9 | ||||
Fourth | 44.9 | 44.9 | ||||
Total | $ | 179.6 | $ | 179.6 | ||
Subject to any regulatory restriction or other limitations on the payment of dividends, future dividends will be at the discretion of the board of directors and will depend upon, among other factors, earnings, financial condition and other requirements.
Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. Under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy. For information regarding restrictions on our ability to pay dividends, see Note N -- Common Equity in the Notes to Consolidated Financial Statements in Item 8.
2004 Form 10-K
ITEM 6. SELECTED FINANCIAL DATA | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
WISCONSIN ELECTRIC POWER COMPANY | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
CONSOLIDATED SELECTED FINANCIAL AND STATISTICAL DATA |
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Financial | 2005 | 2004 | 2003 | 2002 | 2001 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Year Ended December 31 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings available for | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
common stockholder (Millions) | $283.6 | $248.7 | $255.5 | $258.0 | $245.3 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Operating revenues (Millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Electric | $2,320.9 | $2,070.8 | $1,986.4 | $1,884.6 | $1,839.8 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gas | 593.6 | 523.8 | 513.0 | 389.8 | 457.1 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Steam | 23.5 | 22.0 | 22.5 | 21.5 | 21.8 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total operating revenues | $2,938.0 | $2,616.6 | $2,521.9 | $2,295.9 | $2,318.7 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
At December 31 (Millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total assets | $7,909.2 | $7,050.3 | $6,644.6 | $6,285.1 | $6,040.6 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-term debt and capital lease | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
obligations (including current maturities) | $2,058.5 | $1,706.8 | $1,599.5 | $1,459.4 | $1,703.2 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Utility Energy Statistics | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Electric | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Megawatt-hours sold (Thousands) | 31,973.2 | 31,162.4 | 30,713.8 | 30,378.2 | 30,539.7 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Customers (End of year) | 1,092,424 | 1,081,400 | 1,068,034 | 1,056,370 | 1,044,129 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gas | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Therms delivered (Millions) | 902.4 | 835.1 | 888.3 | 890.0 | 852.4 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Customers (End of year) | 446,396 | 437,800 | 428,719 | 420,494 | 412,674 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Steam | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Pounds sold (Millions) | 2,907.6 | 2,869.0 | 3,072.8 | 3,001.1 | 2,929.2 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Customers (End of year) | 463 | 460 | 459 | 467 | 449 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
CONSOLIDATED SELECTED QUARTERLY FINANCIAL DATA (Unaudited) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(Millions of Dollars) (a) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
March | June | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Three Months Ended | 2005 | 2004 | 2005 | 2004 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total operating revenues | $759.7 | $741.7 | $657.2 | $583.8 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Operating income | $121.6 | $144.4 | $92.0 | $71.8 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings available for | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
common stockholder | $70.4 | $79.7 | $51.4 | $36.4 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
September | December | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Three Months Ended | 2005 | 2004 | 2005 | 2004 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total operating revenues | $711.5 | $600.6 | $809.6 | $690.5 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Operating income | $130.2 | $106.4 | $133.5 | $136.6 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings available for | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
common stockholder | $78.9 | $58.8 | $82.9 | $73.8 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(a) | Quarterly results of operations are not directly comparable because of seasonal and other factors. See Management's | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Discussion and Analysis of Financial Condition and Results of Operations. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
WISCONSIN ELECTRIC POWER COMPANY | |||||||||||||||
SELECTED OPERATING DATA | |||||||||||||||
Year Ended December 31 | 2005 | 2004 | 2003 | 2002 | 2001 | ||||||||||
Electric Utility | |||||||||||||||
Operating Revenues (Millions) | |||||||||||||||
Residential | $815.6 | $720.7 | $705.0 | $693.4 | $644.8 | ||||||||||
Small Commercial/Industrial | 727.6 | 651.9 | 626.0 | 591.0 | 577.3 | ||||||||||
Large Commercial/Industrial | 592.7 | 541.4 | 511.4 | 475.6 | 472.0 | ||||||||||
Other - Retail/Municipal | 103.1 | 82.6 | 77.1 | 71.0 | 63.2 | ||||||||||
Resale - Utilities | 42.5 | 39.9 | 39.1 | 31.3 | 69.6 | ||||||||||
Other Operating Revenues | 39.4 | 34.3 | 27.8 | 22.3 | 12.9 | ||||||||||
Total Operating Revenues | $2,320.9 | $2,070.8 | $1,986.4 | $1,884.6 | $1,839.8 | ||||||||||
Megawatt-hour Sales (Thousands) | |||||||||||||||
Residential | 8,389.6 | 7,885.3 | 7,928.8 | 8,147.8 | 7,615.7 | ||||||||||
Small Commercial/Industrial | 8,943.9 | 8,597.0 | 8,493.1 | 8,473.2 | 8,354.2 | ||||||||||
Large Commercial/Industrial | 11,489.8 | 11,477.4 | 11,201.8 | 10,933.0 | 10,983.0 | ||||||||||
Other - Retail/Municipal | 2,467.1 | 2,157.6 | 1,980.4 | 1,810.4 | 1,599.4 | ||||||||||
Resale - Utilities | 682.8 | 1,045.1 | 1,109.7 | 1,013.8 | 1,987.4 | ||||||||||
Total Sales | 31,973.2 | 31,162.4 | 30,713.8 | 30,378.2 | 30,539.7 | ||||||||||
Number of Customers (Average) | |||||||||||||||
Residential | 977,820 | 966,840 | 954,757 | 945,298 | 931,714 | ||||||||||
Small Commercial/Industrial | 105,982 | 104,261 | 102,928 | 102,058 | 100,456 | ||||||||||
Large Commercial/Industrial | 701 | 705 | 703 | 705 | 706 | ||||||||||
Other | 2,399 | 2,371 | 2,348 | 2,345 | 2,319 | ||||||||||
Total Customers | 1,086,902 | 1,074,177 | 1,060,736 | 1,050,406 | 1,035,195 | ||||||||||
Gas Utility | |||||||||||||||
Operating Revenues (Millions) | |||||||||||||||
Residential | $378.4 | $330.5 | $317.5 | $250.9 | $275.8 | ||||||||||
Commercial/Industrial | 205.0 | 173.8 | 166.9 | 125.8 | 150.0 | ||||||||||
Interruptible | 4.9 | 4.1 | 3.8 | 3.2 | 5.1 | ||||||||||
Total Retail Gas Sales | 588.3 | 508.4 | 488.2 | 379.9 | 430.9 | ||||||||||
Transported Gas | 15.0 | 15.3 | 15.6 | 16.0 | 15.4 | ||||||||||
Other Operating Revenues | (9.7) | 0.1 | 9.2 | (6.1) | 10.8 | ||||||||||
Total Operating Revenues | $593.6 | $523.8 | $513.0 | $389.8 | $457.1 | ||||||||||
Therms Delivered (Millions) | |||||||||||||||
Residential | 340.5 | 342.3 | 361.0 | 345.4 | 318.4 | ||||||||||
Commercial/Industrial | 199.9 | 200.4 | 210.8 | 199.2 | 194.5 | ||||||||||
Interruptible | 6.2 | 6.4 | 6.8 | 7.4 | 8.9 | ||||||||||
Total Retail Gas Sales | 546.6 | 549.1 | 578.6 | 552.0 | 521.8 | ||||||||||
Transported Gas | 355.8 | 286.0 | 309.7 | 338.0 | 330.6 | ||||||||||
Total Therms Delivered | 902.4 | 835.1 | 888.3 | 890.0 | 852.4 | ||||||||||
Number of Customers (Average) | |||||||||||||||
Residential | 405,283 | 396,985 | 388,896 | 381,846 | 376,510 | ||||||||||
Commercial/Industrial | 35,945 | 35,174 | 34,646 | 34,180 | 33,839 | ||||||||||
Interruptible | 23 | 24 | 23 | 24 | 30 | ||||||||||
Transported Gas | 366 | 369 | 362 | 366 | 427 | ||||||||||
Total Customers | 441,617 | 432,552 | 423,927 | 416,416 | 410,806 | ||||||||||
Degree Days (a) | |||||||||||||||
Heating (6,697 Normal) | 6,628 | 6,663 | 7,063 | 6,551 | 6,338 | ||||||||||
Cooling (700 Normal) | 949 | 442 | 606 | 897 | 711 | ||||||||||
(a) | As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a twenty-year | ||||||||||||||
moving average. | |||||||||||||||
| (Millions of Dollars) (a) | ||||||||||||
| March | June | |||||||||||
Three Months Ended | 2004 | 2003 | 2004 | 2003 | ||||||||
Total operating revenues | $ | 741.7 | $ | 718.8 | $ | 583.8 | $ | 564.9 | ||||
Operating income | $ | 144.4 | $ | 132.5 | $ | 71.8 | $ | 93.2 | ||||
Earnings available for common stockholder | $ | 79.7 | $ | 75.1 | $ | 36.4 | $ | 49.5 | ||||
| September | December | |||||||||||
Three Months Ended | 2004 | 2003 | 2004 | 2003 | ||||||||
Total operating revenues | $ | 600.6 | $ | 599.6 | $ | 690.5 | $ | 638.6 | ||||
Operating income | $ | 106.4 | $ | 124.5 | $ | 136.6 | $ | 121.1 | ||||
Earnings available for common stockholder | $ | 58.8 | $ | 67.7 | $ | 73.8 | $ | 63.2 | ||||
2004 Form 10-K
WISCONSIN ELECTRIC POWER COMPANY
SELECTED OPERATING DATA
Year Ended December 31
| 2004 | 2003 | 2002 | 2001 | 2000 | ||||||||||||
Electric Utility | |||||||||||||||||
Operating Revenues (Millions) | |||||||||||||||||
Residential | $ | 720.7 | $ | 705.0 | $ | 693.4 | $ | 644.8 | $ | 597.2 | |||||||
Small Commercial/Industrial | 651.9 | 626.0 | 591.0 | 577.3 | 534.7 | ||||||||||||
Large Commercial/Industrial | 541.4 | 511.4 | 475.6 | 472.0 | 464.9 | ||||||||||||
Other–Retail/Municipal | 82.6 | 77.1 | 71.0 | 63.2 | 58.3 | ||||||||||||
Resale–Utilities | 39.9 | 39.1 | 31.3 | 69.6 | 84.0 | ||||||||||||
Other Operating Revenues | 34.3 | 27.8 | 22.3 | 12.9 | 24.3 | ||||||||||||
Total Operating Revenues | $ | 2,070.8 | $ | 1,986.4 | $ | 1,884.6 | $ | 1,839.8 | $ | 1,763.4 | |||||||
Megawatt-hour Sales (Thousands) | |||||||||||||||||
Residential | 7,885.3 | 7,928.8 | 8,147.8 | 7,615.7 | 7,477.6 | ||||||||||||
Small Commercial/Industrial | 8,597.0 | 8,493.1 | 8,473.2 | 8,354.2 | 8,287.5 | ||||||||||||
Large Commercial/Industrial | 11,477.4 | 11,201.8 | 10,933.0 | 10,983.0 | 11,626.2 | ||||||||||||
Other–Retail/Municipal | 2,157.6 | 1,980.4 | 1,810.4 | 1,599.4 | 1,527.3 | ||||||||||||
Resale–Utilities | 1,045.1 | 1,109.7 | 1,013.8 | 1,987.4 | 2,480.2 | ||||||||||||
Total Sales | 31,162.4 | 30,713.8 | 30,378.2 | 30,539.7 | 31,398.8 | ||||||||||||
Number of Customers (Average) | |||||||||||||||||
Residential | 966,840 | 954,757 | 945,298 | 931,714 | 916,028 | ||||||||||||
Small Commercial/Industrial | 104,261 | 102,928 | 102,058 | 100,456 | 98,277 | ||||||||||||
Large Commercial/Industrial | 705 | 703 | 705 | 706 | 712 | ||||||||||||
Other | 2,371 | 2,348 | 2,345 | 2,319 | 2,283 | ||||||||||||
Total Customers | 1,074,177 | 1,060,736 | 1,050,406 | 1,035,195 | 1,017,300 | ||||||||||||
Gas Utility | |||||||||||||||||
Operating Revenues (Millions) | |||||||||||||||||
Residential | $ | 330.5 | $ | 317.5 | $ | 250.9 | $ | 275.8 | $ | 244.3 | |||||||
Commercial/Industrial | 173.8 | 166.9 | 125.8 | 150.0 | 132.0 | ||||||||||||
Interruptible | 4.1 | 3.8 | 3.2 | 5.1 | 5.3 | ||||||||||||
Total Retail Gas Sales | 508.4 | 488.2 | 379.9 | 430.9 | 381.6 | ||||||||||||
Transported Gas | 15.3 | 15.6 | 16.0 | 15.4 | 18.9 | ||||||||||||
Other Operating Revenues | 0.1 | 9.2 | (6.1 | ) | 10.8 | (0.8 | ) | ||||||||||
Total Operating Revenues | $ | 523.8 | $ | 513.0 | $ | 389.8 | $ | 457.1 | $ | 399.7 | |||||||
Therms Delivered (Millions) | |||||||||||||||||
Residential | 342.3 | 361.0 | 345.4 | 318.4 | 335.7 | ||||||||||||
Commercial/Industrial | 200.4 | 210.8 | 199.2 | 194.5 | 206.2 | ||||||||||||
Interruptible | 6.4 | 6.8 | 7.4 | 8.9 | 12.0 | ||||||||||||
Total Retail Gas Sales | 549.1 | 578.6 | 552.0 | 521.8 | 553.9 | ||||||||||||
Transported Gas | 286.0 | 309.7 | 338.0 | 330.6 | 391.0 | ||||||||||||
Total Therms Delivered | 835.1 | 888.3 | 890.0 | 852.4 | 944.9 | ||||||||||||
Number of Customers (Average) | |||||||||||||||||
Residential | 396,985 | 388,896 | 381,846 | 376,510 | 369,210 | ||||||||||||
Commercial/Industrial | 35,174 | 34,646 | 34,180 | 33,839 | 33,275 | ||||||||||||
Interruptible | 24 | 23 | 24 | 30 | 33 | ||||||||||||
Transported Gas | 369 | 362 | 366 | 427 | 389 | ||||||||||||
Total Customers | 432,552 | 423,927 | 416,416 | 410,806 | 402,907 | ||||||||||||
Degree Days (a) | |||||||||||||||||
Heating (6,739 Normal) | 6,663 | 7,063 | 6,551 | 6,338 | 6,716 | ||||||||||||
Cooling (714 Normal) | 442 | 606 | 897 | 711 | 566 | ||||||||||||
2004 Form 10-K
ITEM 7. | MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
CORPORATE DEVELOPMENTS
INTRODUCTION
Wisconsin Electric Power Company, a wholly-owned subsidiary of Wisconsin Energy Corporation (Wisconsin Energy), is engaged primarily in the business of generating electricity and distributing electricity and natural gas in Wisconsin and the Upper Peninsula of Michigan. Unless qualified by their context, when used in this document the terms Wisconsin Electric, the Company, our, us or we refer to Wisconsin Electric Power Company and its subsidiary.
Wisconsin Energy is also the parent company of Wisconsin Gas LLC (Wisconsin Gas), a natural gas distribution utility which serves customers throughout Wisconsin, and Edison Sault Electric Company (Edison Sault), an electric utility which serves customers in the Upper Peninsula of Michigan. Wisconsin Electric and Wisconsin Gas have combined common functions and operate under the trade name of “We Energies”"We Energies".
Cautionary Factors:Factor Regarding Forward - Looking Statements: Certain statements contained herein are “Forward-Looking Statements”"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’smanagement'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,” “objectives,” “plans,” “possible,” “potential,” “projects”"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-LookingForward-Looki ng Statements as a result of certain risks and uncertainties, including but not limited to, those risks and uncertainties described in Item 1A Risk Factors and under the heading “Cautionary Factors”Cautionary Factors in this Item 7, as well as other matters described under the heading “FactorsFactors Affecting Results, Liquidity and Capital Resources”Resources in this Item 7, and other risks and uncertainties detailed from time to time in our filings with the Securities and Exchange Commission (SEC) or otherwise described throughout this document. We disclaim any obligation to update these forward-looking statements.
CORPORATE STRATEGY
Business Opportunities
Wisconsin Energy’sEnergy's key corporate strategy isPower the Future, which was announced in September 2000. This strategy is designed to address Wisconsin’sWisconsin's growing electric supply needs by increasing the electric generating capacity in the state while maintaining a fuel-diverse, reasonably priced electric supply. It also is designed to improve the delivery of energy within our distribution systems to meet increasing customer demands and to support our commitment to improved environmental performance. We expect that thePower the Future strategy will have a significant impact on us. In July 2005, the first of four new electric generating units under thePower the Future strategy was placed into service.
Power the Future Strategy: In February 2001, Wisconsin Energy filed a petition with the Public Service Commission of Wisconsin (PSCW) that would allow Wisconsin Energy to begin implementing its 10-yearPower the Future strategy to improve the supply and reliability of electricity in Wisconsin.Power the Future is intended to meet a growing demand for electricity and ensure a diverse fuel mix while keeping electricity prices reasonable. UnderPower the Future, Wisconsin Energy plans to add new coal-fired and natural gas-fired generating capacity to Wisconsin’sthe state's power portfolio which would allow us to maintain approximately the same fuel mix as exists today. As part of’of itsPower the Future strategy, Wisconsin Energy isplans to (1) investing a net ofinvest approximately $2.5$2.6 billion in 2,120 megawatts of new natural gas-fired and coal-fired generating capacity at existing sites; (2) upgradingupgrade our existing electric generating facilities and (3) investingin vest in upgrades of our existing energy distribution system. The new generating capacity will be built by an affiliated company, W.E. Power LLC (We Power).
Subsequent to Wisconsin Energy’sEnergy's February 2001 filing, the state legislature amended several laws, making changes which arewere critical to the implementation ofPower the Future. In October 2001, the PSCW issued a declaratory ruling finding, among other things, that it was prudent to proceed withPower the Future and for Wisconsin Energy
2004 Form 10-K
to incur the associated pre-certification expenses. However, individual expenses are subject to review by the PSCW in order to be recovered.
In November 2001, Wisconsin Energy created We Power to design, construct, own finance and lease the new generating capacity. We will lease each new generating facility from We Power as well as operate and maintain the new plants under 2525- to 30-year lease agreements approved by the PSCW. Based upon the structure of the leases, Wisconsin Energy expects to recover the initial investments in We Power’sPower's new facilities over the initial lease term. At the end of the leases, we will have the right to acquire the plants outright at market value or to renew the leases. We expect that all lease payments and operating costs ofunder the plantsplant leases will be recoverable in rates under the provisions of the Wisconsin Leased Generation Law.
Under thePower the Future strategy, Wisconsin Energy expects to meet a significant portion of our future generation needs through We Power’sPower's construction of the Port Washington Generating Station (PWGS) and Elm Road generating stations.
the Oak Creek expansion.
As of December 31, 2004,2005, Wisconsin Energy:
Received a Certificate of Public Convenience and Necessity (CPCN) from the PSCW to build two 545-megawatt natural gas-fired intermediate load units in Port Washington, |
| Began site preparation |
Received a CPCN from the PSCW to build two 615-megawatt coal-fired base load units |
Completed the planned sale in November 2005 of approximately a 17% ownership interest in the Oak Creek expansion to two co-owners. We will lease We Power's 515-megawatt interest in each unit. | |
Received approval from the PSCW for various leases between us and We Power. |
Primary risks underPower the Future are associated with successful, timely resolution of court challenges related to the Elm Road facility, timely receipt of remaining permits for Elm Road, and construction risks associated with the schedule and costs for both Wisconsin Energy’s Elm RoadEnergy's Oak Creek expansion and Port Washington generating stations.the PWGS, continuing legal challenges to permits obtained and changes in applicable laws or regulations, adverse interpretation or enforcement of permit conditions, laws and regulations by the permitting agencies, the inability to obtain necessary operating permits in a timely manner, obtaining the investment capital from outside sources necessary to implement the strategy, governmental actions and events in the global economy.
You can find additional information regarding risks associated with thePower the Future strategy, as well as the regulatory process, and specific regulatory approvals and associated legal challenges in “FactorsFactors Affecting Results, Liquidity and Capital Resources”Resources below.
Utility Operations: We are realizing operating efficiencies through the integration of our operations with those of Wisconsin Gas. These operating efficiencies are expected to increase customer satisfaction and reduce operating
2004 Form 10-K
Divestiture of Assets
During 2000, we agreed to join American Transmission Company LLC (ATC) by transferring our electric utility transmission system assets to ATC in exchange for an ownership interest in this new company. Transfer of these electric transmission assets became effective on January 1, 2001. As of December 31, 2004,2005, we had an ownership interest of approximately 33.2%29.4% in ATC. For additional information, see “Note A–Note A -- Summary of Significant Accounting Policies”Policies in the Notes to Consolidated Financial Statements.
RESULTS OF OPERATIONS
EARNINGS
EARNINGS2005 vs. 2004: Earnings increased to $283.6 million in 2005 compared with $248.7 million in 2004. Operating income increased $18.1 million between the comparative periods. During 2005, we experienced an increase in revenues due to favorable weather and pricing increases. Also, during 2004, we recorded severance costs under a voluntary severance program. The year to year increase in operating income was partially offset by higher fuel and purchased power costs and increased operation and maintenance expenses during 2005. We had two scheduled outages at our nuclear plant in 2005 in comparison to one scheduled outage in 2004.
2004 vs. 2003: Earnings decreased by $6.8 million to $248.7 million induring 2004 compared with $255.5 million in 2003. Operating income was down $12.1 million between the comparative periods. During 2004, we experienced an increase in revenues due to base electric sales growth, and we benefited from lower bad debt expenses. However, these items were offset by higher pension and medical costs, severance costs recorded during the second half of 2004 and unfavorable weather.
2003 vs. 2002: Earnings decreased by $2.5 million to $255.5 million during 2003 when compared to 2002. The decline is primarily due to cooler summer weather; higher fuel and purchased power costs; increases in pension, medical and other benefit costs; higher nuclear costs; and costs associated with Wisconsin Energy’sPower the Future growth strategy. The decline was somewhat mitigated by a March 2003 rate increase associated with fuel and purchased power expenses as well as by higher gas margins; growth in our base electric business; litigation settlements in 2002 compared with the receipt of insurance recoveries in 2003, primarily related to the Giddings & Lewis/City of West Allis litigation; and higher other income and deductions.
The following table summarizes our consolidated earnings during 2005, 2004 2003 and 2002.2003.
2005 | 2004 | 2003 | ||||
(Millions of Dollars) | ||||||
Utility Gross Margin | ||||||
Electric (See below) | $1,555.0 | $1,492.2 | $1,430.7 | |||
Gas (See below) | 147.3 | 146.9 | 157.6 | |||
Steam | 15.6 | 15.2 | 15.8 | |||
Total Gross Margin | 1,717.9 | 1,654.3 | 1,604.1 | |||
Other Operating Expenses | ||||||
Other Operation and Maintenance | 880.5 | 844.7 | 784.0 | |||
Depreciation, Decommissioning and Amortization | 281.8 | 274.1 | 276.2 | |||
Property and Revenue Taxes | 78.3 | 76.3 | 72.6 | |||
Operating Income | 477.3 | 459.2 | 471.3 | |||
Other Income and Deductions, Net | 58.8 | 33.5 | 31.5 | |||
Interest Expense | 85.8 | 89.6 | 91.2 | |||
Income Before Income Taxes | 450.3 | 403.1 | 411.6 | |||
Income Taxes | 165.5 | 153.2 | 154.9 | |||
Preferred Stock Dividend Requirement | 1.2 | 1.2 | 1.2 | |||
Earnings Available for Common Stockholder | $283.6 | $248.7 | $255.5 | |||
| 2004 | 2003 | 2002 | |||||||
| (Millions of Dollars) | |||||||||
Utility Gross Margin | |||||||||
Electric (See below) | $ | 1,492.2 | $ | 1,430.7 | $ | 1,397.5 | |||
Gas (See below) | 146.9 | 157.6 | 149.0 | ||||||
Steam | 15.2 | 15.8 | 14.7 | ||||||
Total Gross Margin | 1,654.3 | 1,604.1 | 1,561.2 | ||||||
Other Operating Expenses | |||||||||
Other Operation and Maintenance | 844.7 | 784.0 | 736.3 | ||||||
Depreciation, Decommissioning and Amortization | 274.1 | 276.2 | 267.9 | ||||||
Property and Revenue Taxes | 76.3 | 72.6 | 71.7 | ||||||
Operating Income | 459.2 | 471.3 | 485.3 | ||||||
Other Income and Deductions, Net | 33.5 | 31.5 | 24.3 | ||||||
Interest Expense | 89.6 | 91.2 | 92.7 | ||||||
Income Before Income Taxes | 403.1 | 411.6 | 416.9 | ||||||
Income Taxes | 153.2 | 154.9 | 157.7 | ||||||
Preferred Stock Dividend Requirement | 1.2 | 1.2 | 1.2 | ||||||
Earnings Available for Common Stockholder | $ | 248.7 | $ | 255.5 | $ | 258.0 | |||
Electric Utility Gross Margin
The following table compares our electric utility gross margin during 20042005 with similar information for 20032004 and 2002,2003, including a summary of electric operating revenues and electric sales by customer class.
Electric Revenues and Gross Margin | Electric Megawatt-Hour Sales | |||||||||||
Electric Utility Operations | 2005 | 2004 | 2003 | 2005 | 2004 | 2003 | ||||||
(Millions of Dollars) | (Thousands, Except Degree Days) | |||||||||||
Customer Class | ||||||||||||
Residential | $815.5 | $720.7 | $705.0 | 8,389.6 | 7,885.3 | 7,928.8 | ||||||
Small Commercial/Industrial | 727.6 | 651.9 | 626.0 | 8,943.9 | 8,597.0 | 8,493.1 | ||||||
Large Commercial/Industrial | 592.7 | 541.4 | 511.4 | 11,489.8 | 11,477.4 | 11,201.8 | ||||||
Other-Retail/Municipal | 103.1 | 82.6 | 77.1 | 2,467.1 | 2,157.6 | 1,980.4 | ||||||
Resale-Utilities | 42.5 | 39.9 | 39.1 | 682.8 | 1,045.1 | 1,109.7 | ||||||
Other Operating Revenues | 39.5 | 34.3 | 27.8 | - | - | - | ||||||
Total Electric Operating Revenues | 2,320.9 | 2,070.8 | 1,986.4 | 31,973.2 | 31,162.4 | 30,713.8 | ||||||
Fuel and Purchased Power | ||||||||||||
Fuel | 432.6 | 335.0 | 298.3 | |||||||||
Purchased Power | 333.3 | 243.6 | 257.4 | |||||||||
Total Fuel and Purchased Power | 765.9 | 578.6 | 555.7 | |||||||||
Total Electric Gross Margin | $1,555.0 | $1,492.2 | $1,430.7 | |||||||||
Weather -- Degree Days (a) | ||||||||||||
Heating (6,697 Normal) | 6,628 | 6,663 | 7,063 | |||||||||
Cooling (700 Normal) | 949 | 442 | 606 | |||||||||
(a) | ||||
2004 Form 10-K
| Electric Revenues and Gross Margin | Electric Megawatt-Hour Sales | ||||||||||||||
Electric Utility Operations | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | |||||||||
| (Millions of Dollars) | (Thousands, Except Degree Days) | ||||||||||||||
Customer Class | |||||||||||||||
Residential | $ | 720.7 | $ | 705.0 | $ | 693.4 | 7,885.3 | 7,928.8 | 8,147.8 | ||||||
Small Commercial/Industrial | 651.9 | 626.0 | 591.0 | 8,597.0 | 8,493.1 | 8,473.2 | |||||||||
Large Commercial/Industrial | 541.4 | 511.4 | 475.6 | 11,477.4 | 11,201.8 | 10,933.0 | |||||||||
Other-Retail/Municipal | 82.6 | 77.1 | 71.0 | 2,157.6 | 1,980.4 | 1,810.4 | |||||||||
Resale-Utilities | 39.9 | 39.1 | 31.3 | 1,045.1 | 1,109.7 | 1,013.8 | |||||||||
Other Operating Revenues | 34.3 | 27.8 | 22.3 | – | – | – | |||||||||
Total Electric Operating Revenues | 2,070.8 | 1,986.4 | 1,884.6 | 31,162.4 | 30,713.8 | 30,378.2 | |||||||||
Fuel and Purchased Power | |||||||||||||||
Fuel | 335.0 | 298.3 | 278.9 | ||||||||||||
Purchased Power | 243.6 | 257.4 | 208.2 | ||||||||||||
Total Fuel and Purchased Power | 578.6 | 555.7 | 487.1 | ||||||||||||
Total Electric Gross Margin | $ | 1,492.2 | $ | 1,430.7 | $ | 1,397.5 | |||||||||
Weather–Degree Days (a) | |||||||||||||||
Heating (6,739 Normal) | 6,663 | 7,063 | 6,551 | ||||||||||||
Cooling (714 Normal) | 442 | 606 | 897 | ||||||||||||
| As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a twenty-year moving average. |
Electric Utility Revenues and Sales
2005 vs. 2004: During 2005, our total electric utility operating revenues increased by $250.1 million or 12.1% when compared with 2004 primarily due to favorable weather during the summer of 2005 and pricing increases.
During 2005, we estimate that pricing increases contributed an additional $145.8 million of revenues than in 2004. The most significant impact to rates was a March 2005 interim order we received from the PSCW authorizing an annualized increase in electric rates of approximately $114.9 million due to the increased costs of fuel and purchased power. In November 2005, we received the final rate order, which authorized an additional $7.7 million of annual revenues. Additional orders impacting rates in 2005 were the May 2004 and May 2005 orders we received from the PSCW authorizing annualized increases in electric rates of approximately $59.0 million and $59.7 million, respectively, primarily to cover construction costs associated with Wisconsin Energy'sPower the Future program.
Total electric sales increased by 810.8 thousand megawatt-hours or 2.6% between 2005 and 2004. Residential sales volumes increased 6.4% due to the favorable summer weather in 2005. Total sales volumes to commercial/industrial customers increased 1.8% between comparative periods. Sales volumes to commercial/industrial customers, excluding our largest customers, two iron ore mines, increased 2.4% due to the favorable weather during the summer of 2005. We estimate that weather increased our electric revenues by approximately $68.8 million during 2005 as compared to the prior year. As measured by cooling degree days, 2005 was 114.7% warmer than in 2004.
Sales volumes in the Resale-Utilities class decreased 34.7% primarily due to the reduced availability of base-load capacity for sale at competitive prices as a result of limited fuel supplies and outages. Sales volumes to municipal utilities, the other retail/municipal customer class, increased 14.3% between the periods due to higher off-peak demand from lower margin municipal wholesale power customers.
2004 vs. 2003: During 2004, our total electric utility operating revenues increased by $84.4 million or 4.2% when compared with 2003 due to pricing increases and to growth in our base businesses, partially offset by the effects of unfavorable weather during the summer of 2004.
During 2004, we received $54.5 million of higher operating revenues as a result of pricing increases which were not in effect during 2003. In May 2004, we received an order from the PSCW authorizing an annualized increase in electric rates of approximately $59.5$59.0 million to cover construction costs associated with Wisconsin Energy’sEnergy'sPower the Future program and to recover low income uncollectible expenses transferred to Wisconsin’sWisconsin's public benefits fund. In addition, two rate increases related to a rise in fuel and purchased power costs were implemented in March and October 2003, which increased revenues by approximately $16.3 million during 2004.
Total electric sales increased by 448.6 thousand megawatt-hours or 1.5% between 2004 and 2003. Residential sales were down 0.5%, and small commercial/industrial sales were up just 1.2% due to the unfavorable weather during 2004. We estimate that the unfavorable weather reduced our electric revenues by approximately $28.6 million as compared to the prior year and by $20.7 million as compared to normal weather. As measured by cooling degree days, 2004 was 27.1% cooler than in 2003 and 38.1% cooler than normal.
However, we estimate that customer growth and higher weather-normalized use per customer during 2004 mitigated much of the impact of unfavorable weather. Sales volumes to large commercial/industrial customers improved by 2.5%. Excluding our largest customers, two iron ore mines, sales volumes to our remaining large commercial/industrial customers improved by 1.4%. Sales to municipal utilities, the other retail/municipal customer class, increased 8.9% between the periods due to higher off-peak demand from low-margin municipal wholesale power customers.
Electric Fuel and Purchased Power Expenses
20032005 vs. 2002: During 2003, total electric utility operating revenues increased by $101.8 million or 5.4% when compared with 2002, primarily due to the impact of rate increases related to2004: Gross fuel and purchased power costs for our electric utility increased by a total of $260.1 million during 2005 when compared with 2004. During 2005, we deferred $72.8 million of fuel and purchased power costs which resulted in a net increase of fuel and purchased power expense of $187.3 million or 32.4% during 2005 when compared to a surcharge related to transmission costs.2004. The total rate impact was approximately $83.3 million 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 authorizedexpense was driven by a 2.6% increase in megawatt-hour sales and an additional $6.1 million of
2004 Form 10-K
annual revenues. In spite of the interim fuel order, we under recovered fuel costs by $7.6 million during 2003, which is $5.3 million worse thanincrease in our under recovery during 2002. Much of our under recoveryaverage cost of fuel costs during 2003 can be attributedand purchased power from $17.56 per megawatt-hour in 2004 to the need to purchase replacement power$22.60 per megawatt-hour in May and June of 2003 due to a flood at our Presque Isle Power Plant and to high natural gas prices. The impact of unfavorable summer weather in 2003 reduced electric operating revenues by approximately $19.0 million2005, or 28.7% between the comparative periods.
The increase in our average cost of fuel and purchased power is due primarily to (1) the reduced availability of nuclear generation due to scheduled refueling outages, (2) higher natural gas prices that increased the cost of power supplied by natural gas, (3) the impact of the implementation of the Midwest Independent Transmission System Operator, Inc.'s (MISO) bid based energy market (MISO Midwest Market) in April 2005 and (4) limitations on coal supplies due to transportation shortfalls.
Total electricDuring 2005, we had two scheduled refueling outages at our nuclear plant and in 2004 we had one scheduled refueling outage. As a result, we had approximately 1,145,000 fewer megawatt hours of nuclear generation in 2005. Our average fuel cost for nuclear generation is approximately $5 per megawatt hour, while the average energy cost for purchased power was approximately $55 per megawatt hour. We estimate that the reduction in nuclear generation resulted in approximately $57 million of increased fuel and purchased power costs in 2005 as compared to 2004. During the 2005 outages we replaced both reactor vessel heads resulting in longer outages. This work, along with other planned maintenance, lasted longer than originally expected due to delays. During 2006, we have one planned refueling outage at our nuclear plant. For more information regarding the scheduled refueling outages, see Factors Affecting Results, Liquidity and Capital Resources -- Nuclear Operations.
In 2005, we experienced significant increases in the cost of natural gas used in our own generating assets and in the price of purchased energy which is highly influenced by the price of natural gas. This increase was most significant in the last six months of 2005 due to market related factors including the hurricanes in the Gulf of Mexico. The average combined cost per megawatt hour of purchased energy and natural gas fired units in 2005 was 46.8% higher than in 2004, increasing total cost by approximately $72.5 million.
In April 2005, we began participating in the MISO Midwest Market which fundamentally changed the way we dispatch our generating units and obtain purchased energy. As part of this new market, we are subject to new types of charges which, among other things, recognize the cost of transmission congestion, megawatt-hour sales increasedlosses and other costs associated with operating the generating units in an uneconomic fashion to support the MISO Midwest Market service territory. Because the State of Wisconsin has a constrained transmission system, we believe these costs are higher for us than in other parts of the MISO Midwest Market service territory. The incremental costs associated with the MISO Midwest Market charges identified above were approximately $28 million in 2005. For more information regarding MISO and the MISO Midwest Market, see Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition -- Electric Transmission and Energy Markets.
Our 2005 operations were also adversely impacted by 1.1% during 2003. Residential sales fell 2.7%limitations on deliveries of coal supply due to the impactfailure of unfavorable weather conditions on cooling load during the second and third quartersour primary rail delivery supplier to deliver contracted quantities of 2003. Salescoal to our units. The largest customers, two iron ore mines, increased by 238.4 thousand megawatt-hours or 12.1% between the comparative periods despite temporary curtailments of electric saleslimitation was related to critical rail track maintenance in the secondPowder River basin. This, in turn, resulted in reduced coal deliveries of the coal which primarily serves our Oak Creek and fourth quartersPleasant Prairie generating units from June through December 2005. In response to the reduced deliveries, we limited the generating capability of 2003 resulting fromthese units in off-peak periods and purchased more expensive replacement power and, where possible, took measures to purchase and transport higher cost coal in place of contracted supplies. We estimate that this increased our costs by approximately $52 million in 2005. For additional information on the decreased coal deliveries, see Factors Affecting Results, Liquidity and Capital Resources -- Market Risks and Other Significant Risks -- Commodity Pr ice Risk below.
Under the State of Wisconsin fuel rules, we are allowed to request recovery in fuel revenues if our projected fuel and purchased power costs exceed bands established by the PSCW. In March 2005, we received a flood-relatedrate order that allowed us to increase our annual revenues by $114.9 million (final order received in November 2005 for an annual increase of $122.6 million) due to increased fuel and purchased power costs. As provided under the Wisconsin rules, we are also allowed to request deferral for the costs associated with adverse events which materially impact fuel and purchased power costs which were not anticipated, or for which costs could not be reasonably estimated at the time of the fuel recovery request for consideration in future rate proceedings. During 2005, we deferred approximately $72.8 million of fuel and purchased power costs due to the extended outage at Point Beach Unit 2, the coal delivery problems and increased costs associated with the MISO Midwest Market. Duri ng 2005, we estimate that we under-recovered fuel and purchased power costs by $108.4 million before these deferred items. Adjusted for the allowed deferrals, our Presque Isle Power Plantnet under-recovered fuel and a transmission outage. During the first and third quarters of 2002, the mines had extended outages. Excluding these two mines, our total electric energy sales increased by 0.3% between the comparative periods, and sales volumes to the remaining large commercial/industrial customers improved by 0.3%. Sales to municipal utilities, the other retail/municipal customer class, increased 9.4% between the periods due to higher off-peak demand from low-margin municipal wholesalepurchased power customers.costs were approximately $35.6 million.
Electric Fuel and Purchased Power Expenses
2004 vs. 2003: Total fuel and purchased power expenses for our electric utility increased by $22.9 million or 4.1% during 2004 when compared with 2003. This increase is primarily due to our 1.5% increase in total megawatt-hour sales and to higher coal and purchased capacity costs. Increased availability of several of our coal-fired generating units during 2004, which are less expensive to operate than our natural gas-fired generating units, mitigated the rise in fuel and purchased power costs. Very cool summer weather significantly reduced our need to use higher cost peak generating units and purchased power during 2004, also mitigating the rise in fuel and purchased power costs between the comparative periods.
2003 vs. 2002: During 2003, total fuel and purchased power expenses increased $68.6 million or 14.1% due in large part to increases in fuel prices, especially for natural gas, the primary fuel source for our purchased power, resulting in a 14% increase in the cost per megawatt hour of purchased power. Average commodity gas market prices were $5.39 for 2003 compared to $3.22 for 2002 on a per dekatherm basis. Fuel and purchased power costs also increased due to higher purchased capacity costs and a higher need for purchased energy in 2003 compared with the same period in 2002. Approximately $8 million of this increase was caused by the flood that temporarily shut down our Presque Isle Power Plant during the second quarter of 2003.
Gas Utility Revenues, Gross Margin and Therm Deliveries
The following table compares our total gas utility operating revenues and gross margin (total gas utility operating revenues less cost of gas sold) during 2005, 2004 2003 and 2002.2003.
Gas Utility Operations | 2005 | 2004 | 2003 | |||
(Millions of Dollars) | ||||||
Operating Revenues | $593.6 | $523.8 | $513.0 | |||
Cost of Gas Sold | 446.3 | 376.9 | 355.4 | |||
Gross Margin | $147.3 | $146.9 | $157.6 | |||
Gas Utility Operations | 2004 | 2003 | 2002 | ||||||
| (Millions of Dollars) | |||||||||
Operating Revenues | $ | 523.8 | $ | 513.0 | $ | 389.8 | |||
Cost of Gas Sold | 376.9 | 355.4 | 240.8 | ||||||
Gross Margin | $ | 146.9 | $ | 157.6 | $ | 149.0 | |||
We believe that 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. The following table compares our gas utility gross margin and therm deliveries by customer class during 2005, 2004 2003 and 2002.2003.
Gas Gross Margin | Gas Therm Deliveries | |||||||||||
Gas Utility Operations | 2005 | 2004 | 2003 | 2005 | 2004 | 2003 | ||||||
(Millions of Dollars) | (Millions, Except Degree Days) | |||||||||||
Customer Class | ||||||||||||
Residential | $96.4 | $95.7 | $98.8 | 340.5 | 342.3 | 361.0 | ||||||
Commercial/Industrial | 33.0 | 32.9 | 34.2 | 199.9 | 200.4 | 210.8 | ||||||
Interruptible | 0.5 | 0.5 | 0.5 | 6.2 | 6.4 | 6.8 | ||||||
Total Gas Sold | 129.9 | 129.1 | 133.5 | 546.6 | 549.1 | 578.6 | ||||||
Transported Gas | 15.6 | 15.9 | 16.2 | 355.8 | 286.0 | 309.7 | ||||||
Other Operating | 1.8 | 1.9 | 7.9 | - | - | - | ||||||
Total | $147.3 | $146.9 | $157.6 | 902.4 | 835.1 | 888.3 | ||||||
Weather -- Degree Days (a) | ||||||||||||
Heating (6,697 Normal) | 6,628 | 6,663 | 7,063 | |||||||||
(a) | ||||
2004 Form 10-K
| Gas Gross Margin | Gas Therm Deliveries | ||||||||||||||
Gas Utility Operations | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | |||||||||
| (Millions of Dollars) | (Millions, Except Degree Days) | ||||||||||||||
Customer Class | |||||||||||||||
Residential | $ | 95.7 | $ | 98.8 | $ | 95.3 | 342.3 | 361.0 | 345.4 | ||||||
Commercial/Industrial | 32.9 | 34.2 | 32.7 | 200.4 | 210.8 | 199.2 | |||||||||
Interruptible | 0.5 | 0.5 | 0.5 | 6.4 | 6.8 | 7.4 | |||||||||
Total Gas Sold | 129.1 | 133.5 | 128.5 | 549.1 | 578.6 | 552.0 | |||||||||
Transported Gas | 15.9 | 16.2 | 16.7 | 286.0 | 309.7 | 338.0 | |||||||||
Other Operating | 1.9 | 7.9 | 3.8 | – | – | – | |||||||||
Total | $ | 146.9 | $ | 157.6 | $ | 149.0 | 835.1 | 888.3 | 890.0 | ||||||
Weather–Degree Days (a) | |||||||||||||||
Heating (6,739 Normal) | 6,663 | 7,063 | 6,551 | ||||||||||||
| As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a twenty-year moving average. |
2005 vs. 2004: Gas utility gross margin was relatively flat in 2005, increasing by only $0.4 million or 0.3%. Total therm deliveries were 8.1% higher during 2005, primarily due to increased transport gas deliveries of 69.8 million therms. Transport volumes increased between the comparative periods due to a higher amount of electric generation from natural gas within our service territory. Our margins on these transport gas volumes are significantly lower than our margins for retail gas sales, which is the primary reason why gross margin remained flat even with an increase in therm deliveries. 2004 vs. 2003: Our total gas utility gross margin fell from $157.6 million in 2003 to $146.9 million in 2004 largely due to a decrease in therm deliveries resulting from less favorable weather. Total therm deliveries were 6.0% lower during 2004 primarily due to weather. As measured by heating degree days, 2004 was 5.7% warmer than 2003 and 1.1% warmer than normal, which reduced heating load. We estimate that weather reduced gross margin by approximately $5.4 million between the comparative periods. We also recognized $5.8 million less in gas cost incentive revenues under our gas cost recovery mechanisms when compared with 2003.
2003 vs. 2002: During 2003, our total gas utility gross margin improved by $8.6 million compared with 2002. This was directly related to a favorable weather-related increase in therm deliveries, especially to residential customers who are more weather sensitive and contribute higher margins per therm than other customer classes. As measured by heating degree days, 2003 was 7.8% colder than 2002 and 5.1% colder than normal, increasing heating load. A $4.4 million increase in gas cost incentive revenues during 2003 under our gas cost recovery mechanism also contributed to the increased gross margin and operating revenues between the comparative periods. Total therm deliveries of natural gas decreased by 0.2% during 2003 but varied within customer classes. Volume deliveries for the residential and commercial/industrial customer classes increased by 4.5% and 5.8%, respectively, reflecting the colder weather.
Other Operation and Maintenance Expenses
2005 vs. 2004: Other operation and maintenance expenses increased by $35.8 million or 4.2% during 2005 compared with 2004. The most significant changes in our operation and maintenance expense related to increased lease costs and increased nuclear outage costs. Partially offsetting these increases were a charge in 2004 for severance costs related to the voluntary severance program and lower employee costs in 2005 due to fewer employees.
The largest operations and maintenance increase was due to $50.0 million of additional costs related to lease agreements between us and We Power in connection with thePower the Future plan. Initially, we defer the lease payments and then amortize the payments to expense as we recover revenues from our customers under specific pricing agreements. As noted in the electric revenue discussion, in May 2004 and May 2005 the PSCW approved pricing increases to recover the Wisconsin retail portion of these lease costs.
In addition to the increased lease costs, our nuclear operating and maintenance expense increased approximately $11.0 million due to two scheduled refueling outages in 2005 where we also replaced the reactor vessel heads. In 2004, we had one scheduled refueling outage and in 2006 we only have one scheduled refueling outage. This increase was partially offset by a $10.0 million settlement we received to resolve a vendor dispute.
Additionally, in 2004 we recognized $22.3 million of severance related costs due to the voluntary severance program that was implemented in the second half of 2004. In 2005, we had approximately 138 fewer employees, which reduced operation and maintenance costs by $11.1 million.
Benefit costs increased $12.2 million between comparative periods due to increased pension and medical costs. 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. As a result of the Medicare Advantage program we anticipate that our 2006 post-retirement costs will be approximately $13.9 million less than our 2005 costs. However, we expect an increase in our 2006 pension costs to offset this reduction due to lower discount rates and lower than expected historical returns on plan assets.
2004 vs. 2003: Other operation and maintenance expenses increased by $60.7 million or 7.7% during 2004 compared with 2003. The largest increase related to $36.3 million of costs that we recognized under a lease agreement in connection with the construction of the power plant in Port Washington, Wisconsin under Wisconsin Energy’sEnergy'sPower the Future plan. Under the lease agreement, we are billed for costs, and these costs are deferred on our balance sheet. The costs are amortized to expense as we recover revenues from our customers under specific pricing agreements which allow us to recover the lease costs. As noted in the electric revenue discussion, increased revenues resulting from the order we received from the PSCW in May 2004 basically offset these lease costs on a dollar for dollar basis.basis for the Wisconsin retail portion. In addition to the lease costs, we also recognized $4.0 million of increased public benefits costs which were also included in the May 2004 price increase.
In addition, our employee benefit costs increased $13.7 million due to increased pension and medical costs. We also incurred $22.3 million of severance-related costs during 2004, primarily due to a Voluntary Separation Plan which wasvoluntary severance program offered to certain management and represented employees in the second half of 2004. Partially offsetting these increases was a $5.7 million reduction in bad debt costs due to improved collections and the timing of a deferral order.
Depreciation, Decommissioning and Amortization Expense
20032005 vs. 2002: During 2003, our other operation2004: Depreciation, decommissioning and maintenance expensesamortization expense increased by $47.7$7.7 million or 6.5% whenin 2005 as compared with 2002. Theto 2004. This increase was primarily attributabledue to approximately $39.4 million of higher
2004 Form 10-K
electric transmission expenses. A surcharge for transmission costs that was approved byincreased depreciable plant balances. In November 2005, the PSCW in October 2002 offsetapproved new depreciation rates which are effective January 1, 2006. We expect the impact of higher transmission expenses. Pension, medical and other benefit costs increasednew depreciation rates to reduce annual depreciation expense by approximately $25$15 million during 2003. Overall, nuclear costs were $8.7 million higher during 2003 compared with 2002 due to an extended outagethe lengthening of nuclear plant lives.
2004 vs. 2003: Depreciation, decommissioning and costsamortization expense decreased by $2.1 million in 2004 as compared to 2003. This slight decrease was due to a $7.7 million reduction in decommissioning expense in 2004 due to the tax impacts associated with supplemental inspections at Point Beachrebalancing the nuclear decommissioning trusts. This decrease was partially offset by the U.S. Nuclear Regulatory Commission (NRC). Insurance recoveries of approximately $11.1 million in 2003 compared to associated settlement costs of $17.3 million in 2002, both primarily related to the Giddings & Lewis/City of West Allis litigation, offset some of the increase in other operation and maintenance expenses. We spent approximately $7.2 million more in 2003 than in 2002increased depreciation expense on the implementation of Wisconsin Energy’sPower the Future strategy.increased depreciable plant balances.
Other Income and Deductions, Net
2004 vs. 2003: NetThe following table identifies the components of consolidated other income and deductions, net during 2005, 2004 and 2003.
Other Income and Deductions, Net | 2005 | 2004 | 2003 | |||
(Millions of Dollars) | ||||||
Equity in Earnings of ATC | $30.4 | $26.4 | $22.8 | |||
Carrying Costs on Deferred Transmission Charges | 20.5 | 13.9 | 9.3 | |||
Allowance for Funds Used During Construction | 9.2 | 1.7 | 2.4 | |||
Donations and Contributions | (6.7) | (5.6) | (3.1) | |||
Other, net | 5.4 | (2.9) | 0.1 | |||
Total Other Income and Deductions, Net | $58.8 | $33.5 | $31.5 | |||
2005 vs. 2004: Other income and deductions, net increased by $25.3 million in 2005 compared to 2004. Significant items included an increase of $4.0 million in our interest in ATC earnings, an increase of $6.6 million in the recognition of carrying costs on deferred electric transmission costs, and a $7.5 million increase in Allowance
2004 vs. 2003: Other income and deductions, net were up $2.0 million in 2004 as compared to 2003, primarily due to a civil penalty that we agreed to pay in the second quarter of 2003 pursuant to the terms of a consent decree entered into with the United States Environmental Protection Agency (EPA), an increase in our interest in the earnings of ATC, our unconsolidated affiliate, and to the recognition of higher carrying costs on deferred electric transmission costs, partially offset by an increase in contributions to the WEC Foundation. For additional information, see “Note A–Summary
Interest Expense
2005 vs. 2004: Total interest expense decreased by $3.8 million in 2005 compared with 2004. The major components of Significant Accounting Policies”this decrease included a reduction in the Notes to Consolidated Financial Statements.
2003 vs. 2002: During 2003, net consolidated other incomeamortization of debt premiums and deductions were up by $7.2 million compared to 2002. This increase was primarilyincreased capitalized interest in 2005 due to costs that we recordeda higher average balance of construction projects in 2002 associated with early bond redemptions as well as higher equity in the earnings of ATC and the recognition of higher carrying costs on deferred electric transmission costs between the comparative periods2005. These items were partially offset by the civil penaltyincreases in interest expense due mainly to higher interest rates on our short-term debt. Additionally, in November 2004 we agreed to pay in 2003 pursuant to the terms of a consent decree with the EPA. Also, we recorded $5.3sold $250 million of costs associated with bond redemptions in 2002.unsecured 3.50% Debentures due December 1, 2007, the proceeds of which were used to repay outstanding commercial paper, including commercial paper which funded the August 2004 retirement of our $140 million of 7-1/4% First Mortgage Bonds.
Interest Expense
2004 vs. 2003: Total interest expense decreased by $1.6 million in 2004 compared with 2003. This decrease primarily reflects the replacement of higher cost long-term debt outstanding during 2003 with lower cost borrowings outstanding during 2004. In August 2004, we retired $140 million of 7-1/4% First Mortgage Bonds at their scheduled maturity through the issuance of lower-cost short-term debt.
2003 vs. 2002: Total interest expense decreased by $1.5 million in 2003 compared to 2002. This decline was primarily due to lower interest rates.
Income Taxes
2005 vs. 2004: Our effective income tax rate was 36.9 % in 2005 compared with 38.0% in 2004. This decrease in the effective income tax rate reflected higher AFUDC - Equity.
2004 vs. 2003: Our effective income tax rate was 38.0% in 2004 compared with 37.6% in 2003. This increase in the effective income tax rate was due primarily to a reduction in tax credits associated with rehabilitation projects.
2003 vs. 2002: Our effective income tax rate was 37.6% in 2003 compared with 37.8% in 2002. The 2003 and 2002 effective income tax rates reflect tax credits associated with rehabilitation projects.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS
The following table summarizes our cash flows during 2005, 2004 2003 and 2002:2003:
Wisconsin Electric | 2005 | 2004 | 2003 | |||
(Millions of Dollars) | ||||||
Cash Provided by (Used in) | ||||||
Operating Activities | $481.3 | $630.8 | $514.2 | |||
Investing Activities | ($482.1) | ($423.9) | ($402.8) | |||
Financing Activities | ($2.1) | ($200.8) | ($104.7) | |||
2004 Form 10-K
Wisconsin Electric | 2004 | 2003 | 2002 | ||||||
| (Millions of Dollars) | |||||||||
Cash Provided by (Used in) | |||||||||
Operating Activities | $630.8 | $514.2 | $656.3 | ||||||
Investing Activities | ($423.9 | ) | ($402.8 | ) | ($416.1 | ) | |||
Financing Activities | ($200.8 | ) | ($104.7 | ) | ($248.2 | ) | |||
Operating Activities
Cash provided by operating activities decreased to $481.3 million during 2005 compared with $630.8 million during 2004. This decrease was driven primarily by increased working capital needs, an increase in deferred costs, and an increase in cash taxes paid. During 2005, we experienced significant increases in natural gas costs which increased our working capital requirements for natural gas in storage. The increased natural gas costs also led to an increase in accounts receivable as the cost of gas is recovered dollar for dollar in our natural gas revenues. During 2005, we also experienced increased deferred costs related to transmission costs and deferred fuel. We would not expect similar levels of deferred transmission costs in 2006 as we received a rate order in January 2006 which increased our
Cash provided by operating activities increased to $630.8 million during 2004 compared with $514.2 million during the same period in 2003.This increase was due in large part to higher deferred income taxes and to lower working capital requirements between the comparative periods.
Investing Activities
Cash providedDuring 2005, we made net investments totaling $482.1 million compared to $423.9 during 2004. Capital expenditures increased by operating activities decreased$50.3 million to $514.2$409.2 million and were primarily related to facilitating compliance with the consent decree entered into with the EPA (See Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters). In addition, expenditures associated with nuclear fuel purchases were higher by $19.7 million during 2003 compared with $656.32005. These increases were partially offset by a reduction in capital contributions to ATC of $14.0 million during the same period in 2002. This decrease was primarily due to a $116.4 million refund received in the first quarter of 2002 from a favorable court ruling in the Giddings & Lewis/City of West Allis litigation, increased use of working capital in 2003 due to higher natural gas prices and higher volumes of natural gas in storage and increased tax payments.
Investing Activities
2005.
During 2004, we invested a total of $423.9 million in our business compared to $402.8 million during 2003. Between the comparative periods, capital expenditures were up $15.2 million, but we spent $8.3 million less on nuclear fuel due to the timing of scheduled outages at Point Beach. In 2004, we made a $23.2 million capital contribution to ATC.
Financing Activities
During 2003, we made net investments totaling $402.8 million, a decrease of $13.3 million over the prior year. For 2003 and 2002, capital expenditures totaled $343.7 million and $365.7 million, respectively. In addition, due to the timing of refueling outage schedules at Point Beach Nuclear Plant, we spent $17.6 million more on the acquisition of nuclear fuel in 2003 than in 2002.
Financing Activities
During 2004,2005, we used $200.8$ 2.1 million for net financing activities compared with using $200.8 million during 2004 and using $104.7 million during 2003 and using $248.2 million during 2002.2003. The following table summarizes our cash flows from financing activities:
2005 | 2004 | 2003 | ||||
(Millions of Dollars) | ||||||
Dividends to Wisconsin Energy | ($179.6) | ($179.6) | ($179.6) | |||
Increase (Reduction) in Total Debt | 163.2 | (19.5) | 94.1 | |||
Other | 14.3 | (1.7) | (19.2) | |||
Cash Used in Financing | ($2.1) | ($200.8) | ($104.7) | |||
| 2004 | 2003 | 2002 | ||||||||||
| (Millions of Dollars) | ||||||||||||
Dividends to Wisconsin Energy | ($ | 179.6 | ) | ($ | 179.6 | ) | ($ | 179.6 | ) | |||
Increase (Reduction) in Total Debt | (19.5 | ) | 94.1 | (67.4 | ) | |||||||
Other | (1.7 | ) | (19.2 | ) | (1.2 | ) | ||||||
Cash Used in Financing | ($ | 200.8 | ) | ($ | 104.7 | ) | ($ | 248.2 | ) | |||
The 2005 decrease in cash used for financing activities is due, in part, to increased short-term debt levels during 2005.
In November 2004, we issued $250 million of unsecured 3.50% debentures due December 1, 2007, the proceeds of which were used to pay down outstanding commercial paper.
In August 2004, we retired $140 million of 7-1/4% First Mortgage Bonds at their scheduled maturity.
In June and August 2003, we refinanced a total of $485 million of our debt securities. These debt refinancings are beingwere accounted for using the PSCW-authorizedPSCW authorized revenue neutral method of accounting, under which net debt extinguishment costs in the amount of approximately $18.3 million were deferred and are being amortized over an approximately two year period ending in July 2005 based upon the level of interest savings achieved.
2004 Form 10-K
For additional information concerning changes in our long-term debt, see “Note G–Note G -- Long-Term Debt”Debt in the Notes to Consolidated Financial Statements.
CAPITAL RESOURCES AND REQUIREMENTS
Capital Resources
We anticipate meeting our capital requirements during 20052006 and the next several years 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.
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 notifiedWe will continue to evaluate the PSCW that we would not issue thepotential issuance of 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 Wisconsin State Supreme Court. The issuance would also be dependent upon market conditions.
bonds.
We have credit agreements that provide liquidity support for our obligations with respect to commercial paper.
As of December 31, 2004,2005, we had $372.0$368.0 million of available unused lines of bank back-up credit facilities on a consolidated basis and $189.5$352.7 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 December 31, 2004:2005:
| Total Facility | Letters of Credit | Credit Available | Facility Maturity | Facility Term | ||||
| (Millions of Dollars) | ||||||||
| $250.0 | $3.0 | $247.0 | Jun-2007 | 3 year | ||||
| $125.0 | $– | $125.0 | Nov-2007 | 3 year | ||||
| Letters |
| Facility | Facility | ||||
(Millions of Dollars) | ||||||||
$250.0 | $7.0 | $243.0 | Jun-2007 | 3 year | ||||
$125.0 | $ - | $125.0 | Nov-2007 | 3 year | ||||
On June 23, 2004, we entered into an unsecured three year $250 million bank back-up credit facility to replace a $250 million 364 day credit facility that was expiring. This facility will expire in June 2007 andEach of these facilities may be extended for an additional 364 days beyond the date of expiration, subject to lender agreement.
On November 1, 2004, we entered into an unsecured three year $125 million bank back-upWe are reviewing the possibility of amending and extending these existing credit facility to replace a $100 million 11-month letter agreement that was expiring. This facility will expire in November 2007 and may be extended for an additional 364 days, subject to lender agreement.
2004 Form 10-K
facilities.
The following table shows our consolidated capitalization structure at December 31:
Capitalization Structure | 2005 | 2004 | ||||||
(Millions of Dollars) | ||||||||
Common Equity | $2,310.9 | 48.6% | $2,204.2 | 53.4% | ||||
Preferred Stock | 30.4 | 0.6% | 30.4 | 0.7% | ||||
Long-Term Debt (a) | 1,493.0 | 31.5% | 1,493.9 | 36.2% | ||||
Capital Lease Obligations (a) | 565.5 | 11.9% | 212.9 | 5.1% | ||||
Short-Term Debt | 352.7 | 7.4% | 189.5 | 4.6% | ||||
Total | $4,752.5 | 100.0% | $4,130.9 | 100.0% | ||||
(a) Includes current maturities | ||||||||
Capitalization Structure | 2004 | 2003 | ||||||||||
| (Millions of Dollars) | ||||||||||||
Common Equity | $ | 2,204.2 | 53.4 | % | $ | 2,131.9 | 52.3 | % | ||||
Preferred Stock | 30.4 | 0.7 | % | 30.4 | 0.7 | % | ||||||
Long-Term Debt (including current maturities) | 1,706.8 | 41.3 | % | 1,599.5 | 39.2 | % | ||||||
Short-Term Debt | 189.5 | 4.6 | % | 315.9 | 7.8 | % | ||||||
Total | $ | 4,130.9 | 100.0 | % | $ | 4,077.7 | 100.0 | % | ||||
We recorded a $335.5 million capital lease in July 2005 in connection with the in-service date of the first unit at the PWGS. For additional information, see Note G -- Long-Term Debt in the Notes to Consolidated Financial Statements.
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’sMoody's Investors Service (Moody’s)(Moody's) and Fitch Ratings (Fitch) as of December 31, 2004.2005.
S&P |
| Fitch | ||||
Commercial Paper | A-2 | P-1 | F1 | |||
Senior Secured Debt | A- | Aa3 | AA- | |||
Unsecured Debt | A- | A1 | A+ | |||
Preferred Stock | BBB | A3 | A |
On March 29, 2005, S&P affirmed our security ratings and changed our security rating outlook from stable to negative. The security rating outlooks assigned to us by S&P, Moody’sMoody's and Fitch are allboth stable.
In March 2003, S&P lowered its corporate credit rating for us from A to A-. S&P lowered its rating for our senior secured debt from A to A-. S&P affirmed our A- senior unsecured debt rating. S&P lowered the rating for our preferred stock from BBB+ to BBB. S&P lowered our short-term rating from A-1 to A-2.
In October 2003, Moody’sMoody's downgraded certain of our security ratings. Moody’sMoody's lowered our senior secured debt rating from Aa2 to Aa3, our senior unsecured debt rating from Aa3 to A1 and our preferred stock debt rating from A2 to A3. Moody’sMoody's confirmed our P-1 commercial paper rating.
In October 2003, Fitch downgraded certain of our security ratings. Fitch lowered our senior secured debt rating from AA to AA-, our senior unsecured debt rating from AA- to A+ and our preferred stock rating from AA- to A. Fitch lowered our commercial paper rating from F1+ to F1.
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.
ratingCapital Requirements.
Capital Requirements
Total capital expenditures, excluding the purchase of nuclear fuel and expenditures for new generating capacity contained in Wisconsin Energy'sPower the Future strategy, are currently estimated to be $460.0$444.0 million during 2005.2006. Due to changing environmental and other regulations such as air quality standards and electric reliability initiatives that impact us, future long-term capital requirements may vary from recent capital requirements. We currently expect ourthese capital expenditures excluding the purchase of nuclear fuel and expenditures for new generating capacity contained in Wisconsin Energy’sPower the Future strategy, to be between $350$390 million and $475$460 million per year during the next fivefour years.
In June 2005, we purchased the development rights to two wind farm projects from Navitas Energy Inc. We plan to develop the wind sites and construct wind turbines with a combined generating capability between 130 to 200 megawatts at a cost in the range of $250 to $320 million. We anticipate the cost to build the wind farm projects would be recovered in our rates. We plan to file the necessary regulatory and environmental applications in 2006. We expect the turbines to be placed in service between 2007 and 2008 dependent upon the availability of wind turbines and the receipt of necessary regulatory approvals.
2004 Form 10-K
Investments in Outside Trusts: We have funded our pension obligations, certain other post-retirement obligations and future nuclear obligations in outside trusts. Collectively, these trusts had investments of approximately $1.6
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 believe that suchthese 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 M–Guarantees”Note M -- 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 Financial Accounting Standard Board (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.leases as reflected in the table below. We have included our contractual obligations under all three of these contracts in our “ContractualContractual Obligations/Commercial Commitments”Commitments disclosure that follows. For additional information, see “Note D–Note D -- Variable Interest Entities”Entities in the Notes to Consolidated Financial Statements.
Contractual Obligations/Commercial Commitments: We have the following contractual obligations and other commercial commitments as of December 31, 2004:2005:
Payments Due by Period | ||||||||||
|
| Less than 1 year |
|
| More than 5 years | |||||
(Millions of Dollars) | ||||||||||
Long-Term Debt Obligations (b) | $3,090.4 | $279.6 | $367.9 | $109.1 | $2,333.8 | |||||
Capital Lease Obligations (c) | 1,751.0 | 108.1 | 198.5 | 177.3 | 1,267.1 | |||||
Operating Lease Obligations (d) | 225.1 | 51.1 | 84.9 | 40.8 | 48.3 | |||||
Purchase Obligations (e) | 719.3 | 221.3 | 296.2 | 108.4 | 93.4 | |||||
Other Long-Term Liabilities | 3.8 | 1.5 | 0.9 | 1.4 | - | |||||
Total Contractual Obligations | $5,789.6 | $661.6 | $948.4 | $437.0 | $3,742.6 | |||||
| Payments Due by Period | |||||||||||||||
Contractual Obligations (a) | Total | Less than 1 year | 1-3 years | 3-5 years | More than 5 years | ||||||||||
| (Millions of Dollars) | |||||||||||||||
Long-Term Debt Obligations (b) | $ | 3,114.3 | $ | 40.0 | $ | 593.7 | $ | 107.7 | $ | 2,372.9 | |||||
Capital Lease Obligations (c) | 1,797.4 | 78.3 | 187.4 | 173.7 | 989.0 | ||||||||||
Operating Lease Obligations (d) | 270.4 | 50.4 | 99.3 | 54.6 | 66.1 | ||||||||||
Purchase Obligations (e) | 501.7 | 192.4 | 169.6 | 56.3 | 83.4 | ||||||||||
Other Long-Term Liabilities | 0.4 | 0.2 | 0.2 | – | – | ||||||||||
Total Contractual Obligations | $ | 5,684.2 | $ | 361.3 | $ | 1,050.2 | $ | 392.3 | $ | 3,880.4 | |||||
(a) | The amounts included in the table are calculated using current market prices, forward curves and other estimates. Contracts with multiple unknown variables have been omitted from the analysis. |
(b) | Principal and interest payments on our Long-Term Debt and the Long-Term Debt of our affiliates (excluding capital lease obligations). |
(c) | Capital Lease Obligations for nuclear fuel lease and purchase power commitments. Includes payments on a |
(d) | Operating Lease Obligations for purchased power and rail car leases. |
(e) | Purchase Obligations under various contracts for the procurement of fuel, power, gas supply and associated transportation and for information technology and other services for utility operations. |
Our obligations for utility operations have historically been included as part of the rate making process and therefore are generally recoverable from customers.
2004 Form 10-K
FACTORS AFFECTING RESULTS, LIQUIDITY AND CAPITAL RESOURCES
MARKET RISKS AND OTHER SIGNIFICANT RISKS
We are exposed to market and other significant risks as a result of the nature of our businesses and the environment in which those businesses operate. These risks, described in further detail below, include but are not limited to:
Construction Risk: In December 2002, the PSCW issued a written order granting a CPCN to commence construction of We Power’s Port Washington Generating Station (Port Washington units)Power's PWGS consisting of two 545 megawatt545-megawatt natural gas-fired combined cycle generating units on the site of our existing Port Washington Power Plant. The order approvesapproved key financial terms of the leased generation contracts including fixed construction costcosts of the two Port Washington unitsPWGS 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 and event of loss provisions. For additional information, see Power the Future -- Port Washington below.
In addition, in November 2003, the PSCW issued a written order granting a CPCN for We Power to commence construction of two 615-megawatt super critical pulverized coal generating units (Elm Road units) on(Oak Creek expansion) adjacent to the site of our existing Oak Creek Power Plant. The order approves key financial terms of the leased generation contracts including fixeda target construction cost of the two Elm Road units.Oak Creek expansion of $2.191 billion plus, subject to PSCW approval, cost over-runs of up to 5%, costs attributable to force majeure events, excused events and event of loss provisions. For additional information, see “Power the Future–Elm Road” -- Oak Creek Expansion below.
Large construction projects of this type are subject to usual construction 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, 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 inabilitycontinuing legal challenges to obtain necessary permits in a timely manner andobtained, changes in applicable laws or regulations, adverse interpretation or enforcement of permit conditions, laws and regulations by the permitting agencies, the inability to obtain necessary operating permits in a timely manner, governmental actions and events in the global economy.
If final costs for the construction of the Port Washington units or the Elm Road unitsPWGS exceed the fixed costs allowed in the PSCW order, We Power cannot recoverabsent a finding by the PSCW of extraordinary circumstances such as force majeure conditions, this excess will not adjust the amount of the lease payments recovered from us. If final costs of the Oak Creek expansion 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 Oak Creek expansion 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 ourrecovered from customers unless specifically allowedabsent a finding by the PSCW. Project costs above the authorized amount, but below a 5% cap will be subject to a prudence determination by the PSCW.PSCW of extraordinary circumstances such as force majeure conditions.
Regulatory Recovery Risk: Our electric operations burn natural gas in our leased power plants, in several of our peaking power plants orand as a supplemental fuel at several coal-fired plants, andplants. In addition, the cost of purchased power is generally tied to the cost of natural gas in many instances.gas. We bear regulatory risk for the recovery of these fuel and purchased power costs when theythese costs are higher than the base rate established in our rate structure.
As noted below in Commodity Price Risk, our electric operations operate under a fuel cost adjustment clause in the Wisconsin retail jurisdiction for fuel and purchased power costs associated with the generation and delivery of electricity. This clause establishes a fuel base forPrior to January 1, 2006, we were allowed to request recovery of fuel and purchased power costs from retail electric customers in the Wisconsin jurisdiction through our rate review process with the PSCW and wein interim fuel cost hearings when such annualized costs were expected to be more than 3% higher than the forecasted costs used to establish rates. In January 2006, the PSCW approved a plan for us to refund any over-collection of fuel costs on an annual basis for 2006 to Wisconsin ratepayers and any under-collection will be subject to a 2% band. Beginning in 2007, our electric operations will operate under a fuel cost adjustment clause in the Wisconsin retail jurisdiction for under- and over- collection within a 2% band.
For 2005, 2004 and 2003, our actual net fuel and purchased power costs exceeded fuel costs included in rates by $35.6 million, $0.8 million and $7.6 million, respectively.
We account for our regulated operations in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation. Our rates are determined by regulatory authorities. Our primary regulator is the PSCW. SFAS 71 allows regulated entities to defer certain costs that would otherwise be charged to expense, if the regulated entity believes the recovery of these costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators, and recovery of these deferred costs in future rates is subject to the review and approval of those regulators. We assume the risks and benefits of fuel cost variancesultimate recovery of these items in future rates. If the recovery of these costs is not approved by our regulators, the costs are charged to income in the current period. We expect to recover our outstanding regulatory assets in rates over a period of no longer than 20 years. Regulators can impose liabilities on a prospective basis for amounts previously coll ected from customers and for amounts that are within 3% of the fuel base. We are subject to risks associated with the regulatory approval process including regulatory lag once the costs fall outside the 3% variance of the fuel base. During the second quarter of 2002, the PSCW issued an order authorizing new fuel cost adjustment rulesexpected to be implemented in the Wisconsin retail jurisdiction. The new rules will not be effective until January 2006, the end of a five year rate freeze associated with Wisconsin Energy’s merger with WICOR, Inc. in 2000. Until this time,refunded to customers. Under SFAS 71, we will operate under an approved transaction mechanism similar to the old fuel cost adjustment procedure. For 2004, 2003 and 2002, our actual fuel and purchased power costs exceeded our fuel base rates by $0.8 million, $7.6 million and $2.3 million, respectively. In 2004, 2003 and 2002, our electric rates included a fuel surcharge.record these items as regulatory liabilities.
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 manageoptimize utilization of our available generating capacity and energy during periods when available power resources are expectedprojected to exceed the requirements ofbe greater than or less than our load obligations. This practice may also include forward contracts for the purchase of power during periods when the anticipated market price of electric energy is below expected incremental power production costs. In addition, effective April 1, 2005, we became a market participant in the MISO Midwest Market. For additional information on the MISO Midwest Market see Rates and Regulatory Matters -- Other Utility Rate Matters and Industry Restructuring and Competition -- Electric Transmission and Energy Markets below. We manage our fuel and gas supply costs through a portfolio of shortshort- and long-term procurement contracts with various supplierssupp liers for the purchase of coal, uranium, natural gas and fuel oil.
2004 Form 10-KIn 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 was 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 response, we reduced generation at certain coal fueled units, primarily during lower cost off peak periods, to conserve coal inventories. This required us to obtain additional megawatt hour purchases through other potentially higher cost generating resources in the MISO Midwest Market. In August 2005, we requested and received approval from the PSCW to defer incremental fuel costs associated with reduced coal deliveries. Through December 31, 2005, we deferred approximately $26.0 million of incremental fuel costs and we expect to recover these costs in future rates, subject to review and approval of the PSCW. We do not expect to defer any additional costs related to this matter.
Wisconsin’sWisconsin's retail electric fuel cost adjustment procedure mitigates some of our risk of electric fuel cost fluctuation. If cumulative fuel and purchased power costs for electric utility operations deviate from a prescribed range when compared to the costs projected in the most recent retail rate proceeding, retail electric rates may be adjusted, subject to risks associated with the regulatory approval process including regulatory lag. Regulatory lag risk occurs between the time we incur costs in excess of what we collect in rates, and the time we receive approval for interim rates following a regulatory filing. Regulatory lag risk can increase or decrease due to many factors which may also change during this approval period including commodity price fluctuations, unscheduled operating outages or unscheduled maintenance. In 2002, the PSCW authorized the inclusion of price risk management financial instruments for the management of our electric utility gas costs. During 2003, we implemented a gas hedging program wa s approved by the PSCW.PSCW and implemented by us.
The PSCW has authorized dollar for dollar recovery for the majority of natural gas costs for our gas utility operations through a gas cost recovery mechanism,mechanisms, which mitigates most of the risk of gas cost variations. For additional information concerning the electric utilityour fuel cost adjustment procedure and our gas cost recovery mechanism,mechanisms, see “RatesRates and Regulatory Matters”Matters below.
Natural Gas Costs: Significant increases in the cost of natural gas affect our electric and gas utility operations. Natural gas costs have increased significantly, both because the supply of natural gas in recent years has not kept pace with the demand for natural gas which has grown throughoutand due to the United States as a resultimpacts of increased reliancehurricanes on offshore Gulf of Mexico natural gas-fired electric generating facilities.gas production. We expect that demand for natural gas will remain high into the foreseeable future and that significant price relief will not occur until additional natural gas is added to the nation’snation's energy supply mix.
Higher natural gas costs increase our working capital requirements resultingand result in higher gross receipts taxes in the stateState of Wisconsin. Higher natural gas costs combined with slower economic conditions also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills. Because federal and state energy assistance dollars have not kept pace with rising natural gas costs, our risks related to bad debt expenses associated with non-paying customers havehas increased.
In February 2005, the PSCW authorized the use of the escrow method of accounting for bad debt costs allowing for deferral of Wisconsin residential bad debt expense that exceed amounts allowed in rates. In 2004 and 2003, we had approval from the PSCW to defer residential bad debt net write-offs that exceed amounts allowed in rates.
As a result of a gas cost recovery mechanism,mechanisms, our gas distribution operations receive dollar for dollar pass throughrecovery on most of the cost of natural gas. However, increased natural gas costs increase the risk that customers will switch to alternative fuel sources, which could reduce future gas margins. In addition, we are experiencing reduced usage of natural gas by our residential customers, who contribute higher margins than other customer classes, due to the increased natural gas costs. We expect to continue to experience this reduced usage during the 2006 winter heating season.
Weather: Our rates are set by the PSCW based upon estimated temperatures which approximate 20-year averages. Our electric revenues are unfavorably sensitive to below normal temperatures during the summer cooling season, and to some extent, to above normal temperatures during the winter heating season. Our gas revenues are unfavorably sensitive to above normal temperatures during the winter heating season. A summary of actual weather information in our service territory during 2005, 2004 2003 and 2002,2003, as measured by degree-days, may be found above in “ResultsResults of Operations.”
Interest Rate Risk:We have various short-term borrowing arrangements to provide working capital and general corporate funds. We also have variable rate long-term debt outstanding at December 31, 2004.2005. Borrowing levels under these arrangements vary from period to period depending upon capital investments and other factors. Future short-term interest expense and payments will reflect both future short-term interest rates and borrowing levels.
We performed an interest rate sensitivity analysis at December 31, 20042005 of our outstanding portfolio of $189.5$352.7 million of short-term debt with a weighted average interest rate of 3.07%4.59% and $165.4 million of variable-rate long-term debt with a weighted average interest rate of 1.72%3.51%. A one-percentage point change in interest rates would cause our annual interest expense to increase or decrease by approximately $1.9$3.5 million before taxes from short-term borrowings and by $1.7 million before taxes from variable rate long-term debt outstanding.
Marketable Securities Return Risk:We fund our pension, other post-retirement benefit and nuclear decommissioning obligations through various trust funds, which in turn invest in debt and equity securities. Changes in the market price of the assets in these trust funds can affect future pension, other post-retirement benefit and nuclear decommissioning expenses. Future contributions to these trust funds can also be affected by changes in the market price of trust fund assets. We expect that the risk of expense and contribution variations as a result of changes in the market price of trust fund assets would be mitigated in part through future rate actions by our various
2004 Form 10-K
utility regulators. However,Through December 31, 2005, we are currentlywere operating under a PSCW-ordered, qualified five-year rate restriction period through 2005.period. For further information about the rate restriction, see “RatesRates and Regulatory Matters”Matters below.
At December 31, 2004,2005, we held, or Wisconsin Energy held on our behalf, the following total trust fund assets at fair value, primarily consisting of publicly traded debt and equity security investments.
Wisconsin Electric Power Company | Millions of Dollars | ||
Pension trust funds | $ | 748.0 | |
Nuclear decommissioning trust fund | $ | 737.8 | |
Other post-retirement benefits trust funds | $ | 107.4 | |
Wisconsin Electric Power Company | Millions of Dollars | |
Pension trust funds | $719.6 | |
Nuclear decommissioning trust fund | $782.1 | |
Other post-retirement benefits trust funds | $108.1 |
Fiduciary oversight of the pension and other post-retirement plan trust fund investments is the responsibility of a Chairman-appointedan Investment Trust Policy Committee. Qualified external investment managers are engaged to manage the investments. Asset/liability studies are periodically conducted with the assistance of an outside investment advisor. The current study for the pension fund projects long-term, annualized returns of approximately 9%8.5%.
Fiduciary oversight for the nuclear decommissioning trust fund investments is also the responsibility of the Chairman-appointed Investment Trust Policy Committee. Qualified external investment managers are also engaged to manage these investments. Asset/liability studies are periodically conducted with the assistance of an outside investment advisor, subject to additional constraints established by the PSCW. The current study projects long-term, annualized returns of approximately 9%. Current PSCW constraints allow a maximum allocation of 65% in equities. The allocation to equities is expected to be reduced as the date for decommissioning Point Beach Nuclear Plant approaches in order to increase the probability of sufficient liquidity at the time the funds will be needed.
We insure various property and outage risks through Nuclear Electric Insurance Limited (NEIL). Annually, NEIL reviews its underwriting and investment results and determines the feasibility of granting a distribution to policyholders. Adverse loss experience, rising reinsurance costs or impaired investment results at NEIL could result in increased costs or decreased distributions to us.
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 in the event of a credit ratings change to below investment grade, a termination paymentspayment if collateral is not provided or an accelerated payment. At December 31, 2004,2005, we estimate that the potential payments under these agreements that could result from credit rating downgrades totaled approximately $109.0$69.1 million.
Economic Risk.Risk: We are exposed to market risks in the regional Midwestmidwest economy.
Inflationary Risk: We continue to monitor the impact of inflation, especially with respect to the rising costs of medical plans, in order to minimize its effects in future years through pricing strategies, productivity improvements and cost reductions. Except for continuance of an increasing trend in the inflation of medical costs and the impacts on our medical and post-retirement benefit plans, we have expectations of low-to-moderate inflation. We do not believe the impact of general inflation will have a material effect on our future results of operations.
For additional information concerning risk factors, including market risks, see “Cautionary Factors” below.Cautionary Factors below and Risk Factors in Item 1A above.
POWER THE FUTURE
Under Wisconsin Energy’sEnergy'sPower the Future strategy, we expect to meet a significant portion of our future generation needs through the construction of the Port WashingtonPWGS and Elm Road generating stationsthe Oak Creek expansion by We Power. TheWe Power will lease the new plants will be leased to us by We Power under long-term leases, and we expect to recover the lease payments in our electric rates.
2004 Form 10-K
Power the Future–Future - Port Washington
Background:In December 2002, the PSCW issued a written order (the Port Order) granting us, as well as Wisconsin Energy and We Power, a CPCN to commence construction of the Port Washington Generating StationPWGS consisting of two 545-megawatt natural gas-fired combined cycle generating units (Port(PWGS Units 1 and 2) on the site of our existing Port Washington Power Plant. The Port Order also authorized Wisconsin Gas to proceed with the construction of a connecting natural gas lateral, which was completed in December 2004, and ATC to construct required transmission system upgrades to serve PortPWGS Units 1 and 2 as a result of their concurrent applications. In January 2003, we commenced demolition of two of our existing coal-fired units on the site to make room for the new units. In July 2003, We Power began construction ofPWGS Unit 1 was completed in July 2005 and expectsplaced into service at that time. Unit 1 was completed within the unit to be operational early in the third quarter of 2005.PSCW approved cost parameters. In October 2003, We Power received approval from the Federal Energy Regulatory Commission (FERC) to transfer by long-term lease certain associated FERC jurisdictional transmission related 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.
Lease Terms:The PSCW approved the lease agreements and related documents under which we will staff, operate and maintain PortPWGS Units 1 and 2. Key terms of the leased generation contracts include:
In January 2003, we filed a request with the PSCW to defer costs for recovery in future rates. The PSCW approved the request in an open meeting in April 2003. (See “Limited Rate Adjustment Requests” below for further information.) We Power began collecting certain costs from us in the third quarter of 2003 as provided for in lease generation contracts that were signed in May 2003. We defer the lease costs on our balance sheet, and we amortize the costs to expense as we recover the costs in rates.
Legal and Regulatory Matters:In March 2003, an individual who participated in the PSCW’s Port Washington CPCN proceedings 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). This case was remanded back There are currently no legal challenges to the PSCW which, after reviewing certain environmental matters, affirmed the original CPCN. The same individual then filed additional appeals challenging the CPCN; however, in October 2004, the Court, at the requestconstruction of the individual, dismissedPWGS and all outstanding appeals related to the CPCN.
The construction of Port Units 1 and 2 required the receipt of many permits including permits relating to air and water quality. All construction permits have been received. In addition, with the construction of Portreceived for Units 1 and 2, Wisconsin Gas needed2. As a result of the approval fromenactment of the WDNR forEnergy Policy Act of 2005 (the Energy Policy Act) the constructionFERC, through an amendment to Section 203 of a natural gas lateral which will deliver fuelthe Federal Power Act, has been given jurisdiction over the acquisition of generation (which includes leasing generation), an activity that previously was not subject to the Units. After several discussions withFERC's jurisdiction. Under the WDNR, Wisconsin Gas agreedFERC's recently issued rules implementing the Energy Policy Act, we will be required to modifyseek FERC authorization in order to lease the planned route and mitigate certain environmental impacts. In July 2003, Wisconsin Gas received approval for construction forremaining PWGS unit prior to the natural gas lateral andunit being placed into service. We are unable to determine at this time the lateral was completed in December 2004.
magnitude of the impact of this new regulatory requirement on thePower the Future–FutureElm Road plan, if any.
Power the Future - Oak Creek Expansion
Background:In November 2003, the PSCW issued an order (the Elm RoadOak Creek Order) granting us, as well asalong with Wisconsin Energy and We Power, a CPCN to commence construction of two 615-megawatt coal-fired units (the Elm Road units)Oak Creek expansion) to be located nearadjacent to the site of our existing Oak Creek Power Plant. TheWe anticipate the first unit was scheduled towill be operational in 2009 and the second unit was scheduled towill be operational in 2010. The Elm RoadOak Creek Order concluded, among other things, that there was a need for additional electric generation for Southeastern Wisconsin and that a diversity of fuel sources best serves the interests of the state.State. The total cost for the two units was set at
2004 Form 10-K
$2.19 $2.191 billion adjusted for inflation, and the order provided for recovery of excess costs of up to 5% of the total project, subject to a prudence review by the PSCW. The CPCN was granted contingent upon us obtaining the necessary environmental permits. All necessary permits have been received at this time. In April 2004,June 2005, construction commenced at the site.
In November 2005, We Power entered intocompleted the sale of approximately a contract with Bechtel to secure necessary engineering, design and construction services and major equipment components for these units. We Power expects that it will have co-owners that will have an17% interest in the project of approximately 17%.to two unaffiliated entities, who will share ratably in the construction costs.
Lease Terms:In October 2004, the PSCW approved the lease generation contracts between us and We Power for the Elm Road units.Oak Creek expansion. Key terms of the leased generation contracts include:
In April 2004, the PSCW approved the deferral of certain costs related to the Elm Road unitsOak Creek expansion for recovery in future rates. In May 2004, we filed a request with the PSCW(See Limited Rate Adjustment Request below for an increase in rates due to several factors including the Elm Road lease payment costs. We expect to receive an order from the PSCW on this request in April 2005.further information).
Legal and Regulatory Matters: The CPCN granted for the construction of the Elm Road units isOak Creek expansion was the subject toof a number of regulatory approvals and legal challenges by third parties. The most notable remainingparties; these legal challenges relatewere resolved in June 2005. We have received all permits necessary to the Elm Road CPCN.
commence construction. Certain of these permits continue to be contested, but remain in effect unless and until overturned by a reviewing court or administrative law judge. The major permits are discussed below.
In November 2004, a Dane County Circuit Court judge reviewing challenges to the PSCW’sPSCW's order authorizing We Power to buildconstruction of two coal-fired generating facilities 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 decisions on several other points.
We, along with Wisconsin Energy, We Power, the PSCW and the WDNR filed motions for direct, expedited appeal in mid-December 2004 with the Supreme Court of Wisconsin. We believe that the appeal represents a clear need for prompt, ultimate judicial resolution of matters involving substantial public importance to Wisconsin. While the The Dane County Circuit Court's decision specifically addresses the Oak Creek expansion, we believe this order would make it very difficult for any new generation facilities to be built anywherewas appealed and in the state. In addition to serious questions of reliability and availability of power, this decision also poses increased costs to customers. In JanuaryJune 2005, the Supreme Court of Wisconsin agreed to hearissued its decision which reversed the appeal. The Supreme Court scheduled oral arguments in this matter for March 30, 2005. We anticipate aDane County Circuit Court's decision to be issued no later than June 30, 2005.
We continue to work withthat vacated the PSCW order authorizing the WDNROak Creek expansion and other agenciesupheld the PSCW's order in all respects. The CPCN granted by the PSCW was reinstated and is in full force and effect.
As a result of the delay to obtain all required permitsthe start of construction caused by litigation, the project cost is expected to increase by $50 to $55 million. This represents an increase of approximately 2.4% to 2.6% in the total cost of the project. We Power believes these costs are ultimately recoverable under the terms of the lease agreements. However, recovery is subject to We Power's final calculation of costs and project approvals. The major permitsalso to review and approval by the status regarding these permits are discussed below.
PSCW.
In September 2003, several parties filed a request with the WDNRWisconsin Department of Natural Resources (WDNR) for a contested case hearing in connection with our application to the WDNR for a Chapter 30 permit for wetlands and waterways alterations and construction on the bed of Lake Michigan for the construction of the Elm Road units.Oak Creek expansion. That request was granted and assigned to an administrative law judge. The hearing took place in August 2004 and post hearing briefing concluded in September 2004. In November 2004, the administrative law judge approved the WDNR’sWDNR's issuance of the wetlands and waterwaysChapter 30 permit (Chapter 30 permit) for the Elm Road units.Oak Creek expansion. 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.opponents' petition based on procedural errors. The WDNR has joined in this motion. In March 2005, the court dismissed the appeal. The opponents appealed the court's dismissal to the Wisconsin Court of Appeals. In February 2006, the Wi sconsin Court of Appeals affirmed the lower court's dismissal of the case. The opponents can seek reconsideration of the court's decision or can petition the Wisconsin Supreme Court for review.
Wisconsin Energy hasWe 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 RoadOak Creek expansion and existing Oak Creek generating units. In JanuaryMarch 2005, the WDNR published its notice of intent to issue adetermined 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 filed a public comment period endingpetition for judicial review in February 2005. Additionally, Wisconsin EnergyDane County Circuit Court and a request for a contested case proceeding with the WDNR. In September 2005, the judicial review proceeding in Dane County Circuit Court was dismissed. All parties to this action agreed to the dismissal. The WDNR granted a contested case hearing and the administrative law judge has applied toscheduled a hearing for March 2006. We anticipate a decision by the administrative law judge in 2006.
In May 2005, we received the Army Corps of Engineers for the federal permitspermit necessary for the construction of the Elm
2004 Form 10-K
Road units. We anticipate decisions on these permitsOak Creek expansion. Opponents may appeal the permit in the first half of 2005. Decisions favorable to the project may be contested by project opponents.
federal court.
In January 2004, the WDNR issued the Air Pollution Control and Construction Permit (Air 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 forOak Creek expansion. The permit was opposed and 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 ControlPermit. The decision was opposed and Construction Permit. In February 2005, the project opponents filed a petition for judicial review of the decision with the Dane County Circuit Court.
The terms In September 2005, the Dane County Circuit Court dismissed with prejudice the appeal of We Power’s construction contract with Bechtel for the Elm Road units presently provide that full noticeadministrative law judge's decision. All parties to proceed must be giventhis action agreed to Bechtel by July 1, 2005. In order for Bechtelthe dismissal. This dismissal is the final resolution of all legal challenges 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.
issuance of the Air Permit.
In July 2004, we entered intoaddition, as a result of the enactment of the Energy Policy Act the FERC, through an environmental and economic agreement withamendment to Section 203 of the TownFederal Power Act, has been given jurisdiction over the acquisition of Caledonia (the community immediately adjacentgeneration (which includes leasing generation), an activity that previously was not subject to the Oak Creek plant site), covering Wisconsin Energy’s plans for expansionFERC's jurisdiction. Under the FERC's recently issued rules implementing the Energy Policy Act, we will be required to seek FERC authorization in order to lease
RATES AND REGULATORY MATTERS
The PSCW regulates our retail electric, natural gas and steam rates in the stateState of Wisconsin, while the FERC regulates our wholesale power, electric transmission and interstate gas transportation service rates. The Michigan Public Service Commission (MPSC) regulates retail electric rates in the stateState of Michigan. We estimate that approximately 88% of our electric utility revenues are regulated by the PSCW, 7%6% are regulated by the MPSC and the balance of our electric revenues are regulated by the FERC. All of our natural gas and steam utility revenues are regulated by the PSCW. Orders from the PSCW can be viewed at http://psc.wi.gov/ and orders from the MPSC can be viewed at www.michigan.gov/mpsc/.
Overview: InFor the state of Wisconsin,period from March 2000 until December 31, 2005, our rates arewere governed by an order from the PSCW issued in March 2000 in connection with the approval of Wisconsin Energy’s WICOR acquisition.Energy's acquisition of WICOR. Under this order, we arewere restricted from increasing Wisconsin rates for a five year period ending December 31, 2005, with certain limited exceptions. We may seek biennial
Price Increase Requests: In July 2005, we filed an electric and steam price increase request with the PSCW. Under a limited rate reviews duringproceeding, we requested an increase in electric rates of $143.6 million for 2006, and an $8.8 million total increase in rates for steam over the five-yeartwo year period of 2006 and 2007. The requested electric rate restrictionincrease included: (1) costs associated with the continued investment in Wisconsin Energy'sPower the Futurestrategy; (2) recovery of transmission costs incurred that exceed the amount we are currently collecting from customers; (3) additional sources of renewable energy; and (4) a rate freeze for day to day operations of the electric system until 2008. The requested steam rate increase was due to (1) the costs of maintaining the steam system, (2) the cost of fuel and (3) the costs associated with making changes to our steam utility operations as part of the reconstruction of the Marquette Interchange project in downt own Milwaukee, Wisconsin.
Subsequent to the initial filing of this pricing request, we experienced a result of:
significant increase in the cost of fuel and purchased power due to the increases in natural gas prices and the reductions in coal deliveries as discussed above. In October 2005, we filed a letter with the PSCW informing them of our need to include the increased cost of natural gas used for generation of electricity in our pending 2006 pricing request. The PSCW considered these additional costs and approved an increase in electric rates of $222.0 million in January 2006. In addition, the PSCW found thatapproved an increase in steam rates of $7.8 million or 31.5% to be phased in over the two year period of 2006 and 2007. These rate increases became effective on January 26, 2006 and we anticipate will remain in effect through December 2007.
The January 2006 order also addressed our under- and over-collection of fuel costs in our electric rates. For 2006, the PSCW approved a plan for us to refund any over-collection of fuel costs on an annual basis to ratepayers and the band for under-collection of fuel costs will be 2%. Beginning in 2007, our electric operations will operate under a fuel cost adjustment procedures as well asclause in the Wisconsin retail jurisdiction with a plus or minus 2% band.
In June 2005, we filed with the PSCW a natural gas cost recovery mechanisms would not be subjectprice increase request of $27.4 million. The increase was requested to address the five-year rate restriction period and that it was reasonable to allow us to retain efficiency gainshigher costs associated with the merger. As identified below,adding and maintaining gas mains and infrastructure to maintain safety and reliability and certain costs related to gas in storage. In January 2006, we have received rate increases during the five year restriction period for the exceptions listed above. Under the March 2000 order, a full rate review will be required byapproval from the PSCW for rates beginninga rate increase of $21.4 million or 2.9%. This rate increase became effective on January 26, 2006 and we anticipate will remain in effect through December 2007.
The January 1, 2006. We expect to make a filing in2006 order approved return on equity for our operations of 11.2%. In 2005, in connection with this PSCW review.our approved return on equity was 12.2%.
2004 Form 10-K
The table below summarizes the anticipated annualized revenue impact of recent rate changes. Our current Wisconsin rates are based on an authorized return on common equity of 12.2%.
Service | Incremental |
|
| |||
(Millions) | (%) | |||||
Retail electric, Wisconsin | $222.0 | 10.6% | January 26, 2006 | |||
Retail gas, Wisconsin | $21.4 | 2.9% | January 26, 2006 | |||
Retail steam, Wisconsin (a) | $7.8 | 31.5% | January 26, 2006 | |||
Fuel electric, Michigan | $2.7 | 5.9% | January 1, 2006 | |||
Fuel electric, Wisconsin (b) | $7.7 | 0.3% | November 24, 2005 | |||
Fuel electric, Michigan | $2.5 | 5.8% | November 1, 2005 | |||
Retail electric, Wisconsin | $59.7 | 3.1% | May 19, 2005 | |||
Retail steam, Wisconsin | $0.5 | 3.6% | May 19, 2005 | |||
Fuel electric, Wisconsin (b) | $114.9 | 5.9% | March 18, 2005 | |||
Fuel electric, Michigan | $3.4 | 8.0% | January 1, 2005 | |||
Fuel electric, Michigan | $1.3 | 3.1% | October 1, 2004 | |||
Retail steam, Wisconsin | $0.5 | 3.4% | May 5, 2004 | |||
Retail electric, Wisconsin (c) | $59.0 | 3.3% | May 5, 2004 | |||
Fuel electric, Michigan | $3.3 | 7.6% | January 1, 2004 | |||
Fuel electric, Wisconsin (d) | $6.1 | 0.3% | October 2, 2003 | |||
Fuel electric, Wisconsin (d) | $55.1 | 3.3% | March 14, 2003 | |||
Fuel electric, Michigan | $0.9 | 2.0% | January 1, 2003 |
Service | Incremental Annualized Revenue Increase | Percent Change in Rates | Effective Date | ||||
| (Millions) | (%) | ||||||
Fuel electric, Michigan | $3.4 | 8.0 | % | January 1, 2005 | |||
Fuel electric, Michigan | $1.3 | 3.1 | % | October 1, 2004 | |||
Retail steam, Wisconsin | $0.5 | 3.4 | % | May 5, 2004 | |||
Retail electric, Wisconsin (a) | $59.0 | 3.3 | % | May 5, 2004 | |||
Fuel electric, Michigan | $3.3 | 7.6 | % | January 1, 2004 | |||
Fuel electric, Wisconsin (b) | $6.1 | 0.3 | % | October 2, 2003 | |||
Fuel electric, Wisconsin (b) | $55.1 | 3.3 | % | March 14, 2003 | |||
Fuel electric, Michigan | $0.9 | 2.0 | % | January 1, 2003 | |||
Retail electric, Wisconsin (c) | $48.1 | 3.2 | % | October 22, 2002 | |||
Retail electric, Michigan (d) | $3.2 | 7.8 | % | September 16, 2002 | |||
Fuel electric, Michigan | $1.6 | 3.8 | % | January 1, 2002 |
(a) | In January 2006, the PSCW issued a final order authorizing an increase in steam ratesof $7.8 million over the two year period of 2006 and 2007. |
(b) | In November 2005, the PSCW issued a final order authorizing a fuel surcharge for $7.7 million of additional fuel costs. In March 2005, the PSCW issued an interim order authorizing a fuel surcharge for $114.9 million that was effective until the November 2005 final order was issued by the PSCW. The final November 2005 order for $122.6 million superseded the March 2005 interim order. |
(c) | In May 2004, the PSCW issued a final order authorizing an increase in electric rates for costs associated with the |
(d) | In October 2003, the PSCW issued a final order authorizing a fuel surcharge for $6.1 million of additional fuel costs. In March 2003, the PSCW issued an interim order authorizing a surcharge for $55.1 million of additional fuel costs on an annualized basis subject to true up. |
Limited Rate Adjustment Requests
2005 Revenue Deficiencies: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 StationPWGS and the Elm Road Generating StationOak Creek expansion being constructed as part of theWisconsin Energy'sPower the Future strategy, (2) costs associated with our energy efficiency procurement plan and (3) costs associated with making changes to our steam utility systems as part of the reconstruction of the Marquette Interchange highway project in downtown Milwaukee, Wisconsin. The filing identified anticipated revenue deficiencies in 2005 attributable to Wisconsin in the amount of $84.8 million (4.5%) for our electric operations and $0.5 million (3.6%) for our steam operations. In January 2005, as a result of the litigation involving the Elm Road units,Oak Creek expansion, we amended this filing to reduce the total revenue request to $52.4 million. We anticipate receivingIn May 2005, the PSC W issued its final written order implementing an order from the PSCW before April 2005.annualized increase in electric rates of $59.7 million (3.1%) and an increase of $0.5 million (3.6%) in steam rates.
2005 Fuel Recovery Filing: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 expect to receivereceived approval offor the increase in
2004 Form 10-K
Other Utility Rate Matters
Electric Transmission Cost Recovery: We transferred all ofdivested our transmission assets with the formation of the ATC in January 2001. We now procure transmission service from ATC at FERC approved tariff rates. In connection with the formation of the ATC, our transmission costs have escalated due to the socialization of costs within the ATC and increased transmission infrastructure requirements in the state. In 2002, in connection with the increased costs experienced by our customers, the PSCW issued an order which allowed the deferral of transmission costs in excess of amounts imbedded in rates. We are allowed to earn a return on the unrecovered transmission costs at our weighted average cost of capital. As of December 31, 2004,2005, we have deferred $109.6$169.4 million of unrecovered transmission costs. We expect to beginIn January 2006, our rates were increased by approximately $67.5 million annually to recover thesetransmission costs beginningthat were not currently in 2006.rates. We will contin ue to accrue carrying costs on the unrecovered balances.
Fuel Cost Adjustment Procedure: Within the stateState of Wisconsin, we operate under a fuel cost adjustment clause for fuel and purchased power costs associated with the generation and delivery of electricity and purchase power contracts. Imbedded within itsour base rates is an amount to recover fuel costs. Under the current fuel rules, no adjustments are made to rates as long as fuel and purchased power costs are expected to be within a 3% band of the costs imbedded in current rates for the twelve month period ending December 31. If, however, annual fuel costs are expected to fall outside of the 3% band, and actual interim costs fall outside of established ranges, then we may file for a change in fuel recoveries on a prospective basis.
For 2006, the upper band is 2% and we will refund any over- recovered annual fuel costs. For 2007, the band is plus or minus 2%.
In Michigan, our electric utility operates under a Power Supply Cost Recovery (PSCR) mechanism which generally allows for the recovery of fuel and purchase power costs on a dollar for dollar basis.
Gas Cost Recovery Mechanism: Our natural gas operations operate under a gas cost recovery mechanism (GCRM) as approved by the PSCW. Generally, the GCRM allows for a dollar for dollar recovery of gas costs. There is an incentive mechanism under the GCRM which allows for increased revenues if we acquire gas lower than benchmarks approved by the PSCW. We earned $0.2 million ofDuring 2005, no additional revenues during 2004were earned under the incentive portion of the GCRM compared withand $0.2 million and $6.0 million duringof additional revenues were earned in 2004 and 2003 and $1.6 million during 2002.under the GCRM.
Bad Debt Costs: In 2003 and 2004, due to a combination of unusually high natural gas prices, a soft economy within our utility service territories, and limited governmental assistance available to low-income customers, we saw a significant increase in residential uncollectible accounts receivable. Because of this, we requested and received letters from the PSCW which allowed us to defer the costs of residential bad debts to the extent that the costs exceeded the amounts allowed in rates. As a result of these letters from the PSCW, we deferred approximately $11.7 million in 2004 and $10.9 million in 2004 and 2003 related to bad debt costs.
In January 2006, the PSCW issued an order approving the amortization over the next five years of the bad debts deferred in 2004 and 2003 for our gas operations. The bad debts deferred in 2004 and 2003 related to electric operations will be considered for recovery in future rates, subject to audit and approval of the PSCW.
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 iswas 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 the use of escrow accounting. The final decision was received in March 2005. The escrow method of accounting for bad debt costs allows for deferral of Wisconsin
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 notifiedWe will continue to evaluate the PSCW that we would not issue thepotential issuance of 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 Wisconsin State Supreme Court. The issuance would also be dependent upon market conditions.bonds.
MISO Midwest Independent Transmission System Operator, Inc. (Midwest ISO) Day 2:Market: 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 MISO Midwest ISO Day 2 energy markets, exceptMarket. We received approval for locational marginal pricing (LMP) energy costs.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 the MISO Midwest Market costs until each utility's first rate case following April 1, 2008. The purpose of the March 2005 request for escrow accounting was to provide clarification on costs not included in the March 2005 approval for deferral accounting treatment. We anticipate receiving a decision related toon this request prior to the scheduled start of the Midwest ISO energy market on April 1, 2005.
2004 Form 10-K
Nuclear Refueling Outages–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 occurthat occurred in the fall of 2005. In March 2005, the PSCW denied this request. In May 2005, we requested and we received approval from the PSCW to defer replacement power costs incurred after May 30, 2005 due to the longer-than-expected outage at Point Beach Unit 2. We estimatedeferred $22.1 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. For additional information see Nuclear Operations below.
Reduced Coal Deliveries: In August 2005, we requested and received approval from the PSCW to defer incremental fuel costs associated with reduced coal deliveries. Through December 31, 2005, we deferred approximately $26.0 million of incremental fuel costs and we expect to recover these costs in future rates, subject to review and approval of the PSCW. We do not anticipate deferring additional costs under this order in 2006. For further information regarding rates see Management's Discussion and Analysis - Factors Affecting Results, Liquidity and Capital Resources -- Market Risks and Other Significant Risks -- Commodity Price Risk.
Depreciation Rates: In January 2005, along with Wisconsin Gas, we filed a joint application with the PSCW for certification of depreciation rates for specific classes of utility plant assets. In November 2005, we received notice from the PSCW that the additional non-fuel operationproposed estimated lives, net salvage values and maintenancedepreciation rates were approved and became effective January 1, 2006. We expect the new depreciation rates to reduce annual depreciation expense associated withby approximately $15 million due to the falllengthening of nuclear outage is approximately $15.0 million. The PSCW denied our request on March 10, 2005.plant lives which will reduce annual expense.
ELECTRIC SYSTEM RELIABILITY
In response to customer demand for higher quality power required by modern digital equipment, we are evaluating and updating our electric distribution system as part of Wisconsin Energy’sPower the Future strategy.system. We are taking some immediate steps to reduce the likelihood of outages by upgrading substations and rebuilding lines to upgrade voltages and reliability. These improvements, along with better technology for analysis of our existing system, better resource management to speed restoration and improved customer communication, are near-term efforts to enhance our current electric distribution infrastructure. InFor the long-term, we are initiatinghave developed a newdistribution system asset management strategy that is expectedrequires increased levels of automation of both substations and line equipment to consistently provide the level of reliability needed for a digital economy, using new technology and advanced communications. In addition, we are participating in a world-wide consortium for electric infrastructure to support a digital society sponsored by the Electric Power Research Institute. Implementation of Wisconsin Energy’sPower the Future strategy is subject to a number of state and federal regulatory approvals. For additional information, see “Power the Future” above.economy.
We had adequate capacity to meet all of our firm electric load obligations during 2004.2005. All of our generating plants performed well during the hottestwarmest periods of the summer and all power purchase commitments under firm contract were received. During this period, public appeals for conservation were not required, nor was there the need to interrupt or curtail service to non-firm customers who participate in load management programs in exchange for discounted rates.
In May 2003, a flood at a hydroelectric dam owned by another utility forced a complete shutdown of our 618-megawatt Presque Isle Power Plant in Marquette, Michigan, which resulted in the curtailment of non-firm service to some customers, as well as brief interruptions to firm service. Deliveries were also curtailed on several occasions to certain special contract customers in the Upper Peninsula of Michigan were also curtailed on several occasions because of transmission constraints in the area including an incident in December 2003. During the December 2003 incident, flow was interrupted on the three main electric transmission lines owned by ATC and connecting Wisconsin to the Upper Peninsula of Michigan. This incident also resulted in short outages to some firm customers.
We expect to have adequate capacity to meet all of our firm load obligations during 2005.2006. However, extremely hot weather, unexpected equipment failure or unavailability could require us to call upon load management procedures during 20052006 as we haveit has in past years.
ENVIRONMENTAL MATTERS
Consistent with other companies in the energy industry, we face potentially significant ongoing environmental compliance and remediation challenges related to current and past operations. Specific environmental issues affecting our utility operationsand non-utility energy segments include but are not limited to (1) air emissions such as carbon dioxide (CO2), sulfur dioxide (SO2), nitrogen oxide (NOx), small particulates and mercury, (2) disposal of combustion by-products such as fly ash, (3) remediation of former manufactured gas plant sites, (4) disposal of used nuclear fuel, and (5) the eventual decommissioning of nuclear power plants.
We are currently pursuing a proactive strategy to manage our environmental issues including (1) substituting new and cleaner generating facilities for older facilities as part of Wisconsin Energy’sEnergy'sPower the Future strategy, (2) developing additional sources of renewable electric energy supply, (3) participating in regional initiativesadding emission control equipment to reduce the emissions of NOx from our fossil fuel-based generatingexisting facilities to comply with new ambient air quality standards and federal clean air rules, (4) entering into agreements with the WDNR and EPA to reduce emissions of SO2 and NOx by more than 65% and mercury by 50% by 2013 from our coal-fired power plants in Wisconsin and Michigan, by more than 65% and mercury by 50% within 10 years, (5) recycling of ash from coal-fired generating units, and (6) the clean-up of former manufactured gas plant sites. The capital cost of implementing the EPA agreementconsent decree is estimated to be approximately $600 million over the ten10 years ending 2013. Through December 31, 2005, we have spent approximately $216.5&nbs p;million associated with implementing the EPA agreement. There could be additional costs of compliance with the EPA consent decree should we elect to control rather than retire Units 5 and 6 at the Oak Creek Power Plant. We believe this additional cost may add approximately $150 million to $350 million to the estimate. For further information concerning an associatedthe consent decree, see “Note P–Note Q -- Commitments and Contingencies”Contingencies in the Notes to Consolidated Financial
2004 Form 10-K
Statements in this report. For further information concerning disposal of used nuclear fuel and nuclear power plant decommissioning, see “Nuclear Operations”Nuclear Operations below and “Note F–Note F -- Nuclear Operations”Operations in the Notes to Consolidated Financial Statements in this report, respectively.
National Ambient Air Quality Standards:In 2004, EPA began2000 and 2001, Michigan and Wisconsin finalized state rules implementing phased emission reductions required to meet the National Ambient Air Quality StandardsStandard (NAAQS) for 1-hour ozone.In 2004, the EPA began implementing NAAQS for 8-hour ozone and fine particulate matter (PM2.5) by designating non-attainment areas in the country.. The states are currently developing rules to implement the new standards. Although specific emission control requirements are not yet defined, we believe that the revised standards will likely require significant reductions in SO2 and NOx emissions from coal-fired generating facilities. We expect that reductions needed to achieve compliance with the 8-hour ozone attainment standard will be implemented in stages from 2007 through 2010, beginning with 1-hour ozone reductions.2010. Reductions associated with the new fine particulate matter standards are expected to be implemented in stages after the year 2010 and extending to the year 2017. We arear e currently unable to predict the impact that the revised air quality standards might have on the operations of our existing coal-fired generating facilities.facilities until the states develop
1-hour Ozone Non-Attainment Standards:Standard: The 1-hour ozone non-attainmentnonattainment rules currently being implemented by the stateState of Wisconsin and the ozone transport rules implemented by the stateState of Michigan limit NOx emissions in phases over the next five years.2003 - 2008 time period.
We currently expect to incur total annual operation and maintenance costs of $1-2$2-3 million during the period 2004 through 2007 to comply with the Michigan and Wisconsin rules. In January 2000, the PSCW approved our comprehensive plan to meet the Wisconsin regulations,rules, permitting recovery in rates of NOx emission reduction costs over an accelerated 10-year recovery period.
8-hour Ozone Standard: In April 2004, the EPA designated 10 counties in Southeastern Wisconsin as non-attainmentnonattainment areas for the 8-hour ozone NAAQS. States will beare required to develop and submit State Implementation Plans to the EPA by June 2007 to demonstrate how they intend to comply with the 8-hour ozone NAAQS by June 2007. ReductionsNAAQS. We expect that reductions needed to achieve compliance with the 8-hour ozone attainment standard will be implemented in stages from 2007 through 2010.2010, and that some or all of these reductions will be accomplished through implementation of the Clean Air Interstate Rule (CAIR). See below for further information regarding CAIR. We believe that compliance with the NOx emission reductions requirements under the agreements with the WDNR and EPA will substantially mitigate costs to comply with the EPA’sEPA's 8-hour ozone NAAQS. However, the timing of the requirements may be impacted by requiring earlier installation of NOx controls at some units, depending on how the states implement the rules.
PM2.5Standard:In December 2004, the EPA designated PM2.5 non-attainment nonattainment areas in the country. All counties in the stateState of Wisconsin and all counties in the Upper Peninsula of Michigan were designated as in attainment with the standard. EPA published proposed regulations calledIt is unknown at this time whether Wisconsin or Michigan will require additional emission reductions as part of state or regional implementation of the PM2.5standard and what impact those requirements would have on operation of our existing coal-fired generation facilities.
Clean Air Interstate Rule (CAIR)Rule: The EPA issued the final CAIR regulation in January 2004March 2005 to facilitate the states in meeting the 8-hour ozone and PM2.5 standards by addressing the regional transport of SO2 and NOx. The proposed rules would requireCAIR requires NOx and SO2 emission reductions in two phases from electric generating units located in a 28-state region within the eastern U.S.United States. Wisconsin and Michigan are affected states under CAIR. The EPAphase 1 compliance deadline is planningJanuary 1, 2009 for NOx and January 1, 2010 for SO2, and the phase 2 compliance deadline is January 1, 2015 for both NOx and SO2. Overall, the CAIR is expected to issueresult in a 70% reduction in SO2emissions and a 65% reduction in NOx emissions from 2002 emission levels.The states are required to develop and submit implementation plans by October ;2006, and until those plans are in place, it is not possible to estimate the final CAIR regulations by March 15, 2005.impact of the CAIR. We believe that compliance with the NOx and SO2 emission reductions requirements under the agreements with the WDNR and EPA will substantially mitigate costs to comply with the CAIR rule.
Mercury Emission Control Rulemaking: As required by the 1990 amendments to the Federal Clean Air Act, theMercury Rule: The EPA issued athe final Clean Air Mercury Rule (CAMR) in March 2005 following the agency's 2000 regulatory determination in December 2000 that utility mercury emissions should be regulated. CAMR limits mercury emissions from new and existing coal-fired power plants, and caps utility mercury emission in two phases, applicable in 2010 and 2018. The EPAcaps limit emissions at approximately 20% and ultimately 70% below today's utility mercury levels. The states are required to develop and submit implementation plans by November 2006. Until those plans are in place, it is not possible to estimate the final impact of the CAMR, but additional expenditures are anticipated in order to meet both phases of the federal rule. Because the technology is under development, it is difficult to estimate the cost. We believe the range of possible expenditures could be approximately $50 million to $200 million. The construction air permit issued draft rules in December 2003 and is expected to issue final rules by March 15, 2005. The compliance date for the finalOak Creek expansion is not impacted by the new rule.
The federal rules cannotrule is being challenged by a number of states including Wisconsin and Michigan. Depending on the litigation, the timing for compliance may be predicted at this time, but could be as early as 2008.
affected.
The WDNR independently developed mercury emission control rules that affect electric utilities in Wisconsin. TheWisconsin and issued state-only mercury control rules became effective in October 2004. The rules require emission reductions of 40% by 2010 and 75% by 2015. The rules explicitly recognize an underlying state statutory
Clean Air Visibility Rule: The EPA issued the Clean Air Visibility Rule (CAVR) in June 2005 to meetaddress regional haze, or regionally-impaired visibility caused by multiple sources over a wide area. The rule defines Best Available Retrofit Technology (BART) requirements for electric generating units and how BART will be addressed in the 28 states subject to EPA's CAIR. Under CAVR, states are required to identify certain industrial facilities and power plants that affect visibility in the nation's 156 Class I protected areas. States then determine the types of emission controls that those facilities must use to control their emissions. The pollutants from power plants that reduce visibility include particulate matter or compounds that contribute to fine particulate formation, NOx, SO2 and ammonia. States must submit plans to implement CAVR to the EPA by December 2007. The reductions associated with the state mercury rules. This is because the federal rulesplans are very likelyscheduled to bebegin to take effect in place prior to the compliance dates contained in the state rule.2014 with full implementation before 2018. We are currently unable to predict the ultimate rules that will be developed and adopted by the EPA, and we are not able to predict the impact that the EPA’s mercury emission control rulemakingsCAVR might have on the operations of our existing or anticipated coal-fired generating facilities.facilities until the states develop rules and submit implementation plans to the EPA.
Clean Water Act: Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impact. This law dates back to 1972; however, prior to September 2004, Form 10-Kthere have not been federal rules that define precisely how states and EPA regions would determine that an existing intake meets BTA requirements. This rule establishes, for the first time, national performance standards and compliance alternatives for existing facilities that are designed to minimize the potential adverse environmental impacts to aquatic organisms associated with water withdrawals from cooling water intakes. Costs associated with implementation of the rule for our Oak Creek Power Plant, We Power's Oak Creek expansion and PWGS have been included in project costs. Studies to determine costs, if any, that may be associated with our other existing facili ties are expected to take place over the next three years.
Manufactured Gas Plant Sites:We are voluntarily reviewing and addressing environmental conditions at a number of former manufactured gas plant sites. For further information, see “Note P–Note Q -- Commitments and Contingencies”Contingencies in the Notes to Consolidated Financial Statements.
Ash Landfill Sites:We aggressively seek environmentally acceptable, beneficial uses for our combustion byproducts. For further information, see “Note P–Note Q -- Commitments and Contingencies”Contingencies in the Notes to Consolidated Financial Statements.
EPA Information Requests:- Proposed Consent Decree: We receivedentered into a proposed consent decree with the EPA to address all matters relating to information requests for informationreceived from the EPA regional offices pursuant to Section 114(a) of the Clean Air Act. For further information, see “Note P–Note Q -- Commitments and Contingencies”Contingencies in the Notes to Consolidated Financial Statements.
Greenhouse Gases: There have been international efforts seeking legally binding reductions in emissions of greenhouse gases, principally carbon dioxide (CO2), including the United Nations Framework Convention on Climate Change held in Kyoto, Japan. While the Bush Administration has not supported U.S. ratification of the Kyoto Protocol or other legislation requiring reductions in CO2, in 2002, the Bush Administration announced a goal of reducing the greenhouse gas intensity of the U.S. economy by 18% by 2012. In addition, in December 2004, the U.S. Department of Energy announced the Climate VISION program in furtherance of reduced greenhouse gas emissions. We continue to take voluntary measures to reduce our emissions of greenhouse gases; however, the impact of any future legislation that would require reductions in greenhouse gases cannot be assessed at this time.
We continue to support flexible, market-based strategies to curb greenhouse gas emissions. These strategies include emissions trading, joint implementation projects and credit for early actions. We also support a voluntary approach that encourages technology development and transfer and includes all sectors of the economy and all significant global emitters.
Our emissions in future years will continue to be influenced by several actions planned or underway as part of thePower the Future plan, including:
LEGAL MATTERS
Presque Isle Flood: During the second quarter of 2003, our Presque Isle Power Plant was temporarily shut down due to the failure of a hydroelectric reservoir dike which flooded Marquette, Michigan. We estimate that our fuel and purchased power costs increased by approximately $8 million due to the need for replacement power during the plant outage. These increased costs were included as part of the fuel surcharge request discussed above. In addition, we incurred approximately $13.5 million in damage to equipment and property. We are pursuing recovery from insurance carriers and other parties for the above costs. During 2004, wehave reached settlements with an insurance carrier for approximately $9.1 million. Weand other third parties. Through litigation, we are continuing to pursue recovery against the remaining insurance carriers and other third parties.
Arbitration Proceedings: Our largest electric customer owns two mines that operate in the Upper Peninsula of Michigan. The mines represent approximately 7% of our annual electric sales and less than 1% of our annual net income. The mines have special negotiated contracts that expire in December 2007. The contracts have price caps for approximately 80% of the energy sales. The mines are billed at rates reflecting incremental costs and amounts billed that exceed the price caps are refunded without interest in the year following the contract year. We do not recognize revenue on amounts billed that exceed the price caps.
The incremental power costs in the Upper Peninsula of Michigan are continuingnow determined by MISO. In April 2005, we began to analyzebill the mines the incremental power costs as quantified by the MISO Midwest Market. The mines have notified us that they are disputing these billings and refinethey have placed the costs associateddisputed amounts in escrow. In September 2005, the mines notified us that they filed for formal arbitration related to the contracts. We have notified the mines that we believe that they have failed to comply with certain notification provisions related to annual production as specified within the contracts. As of December 31, 2005, the mines have placed $70.6 million in escrow. As noted above, the amounts that have been placed in escrow primarily relate to amounts that would have been refunded without interest in the year following the contract year. At this matter.time, we are unable to predict the outcome of the formal arbitration process, but we believe that it will not have a material im pact on our financial condition or results of operations.
Stray Voltage:On July 11, 1996, the PSCW issued a final order regarding the stray voltage policies of Wisconsin’sWisconsin's investor-owned utilities. The order clarified the definition of stray voltage, affirmed the level at which utility action is required, and placed some of the responsibility for this issue in the hands of the customer. Additionally, the order established a uniform stray voltage tariff which delineates utility responsibility and provides for the recovery of costs associated with unnecessary customer demanded services.
In recent years, dairy farmers have commenced actions or made claims against us for loss of milk production and other damages to livestock allegedly caused by stray voltage, and more recently, ground currents resulting from the operation of ourits electrical system, even though that electrical system has been operated within the parameters of the PSCW’sPSCW's order. In 2003, the Wisconsin Supreme Court upheld a Court of Appeals’Appeals' affirmance of a jury verdict against us, awarding $1.2 million to the plaintiffs in a stray voltage lawsuit and heldlawsuit. The Supreme Court rejected the argument that even thoughif a utility company’scompany's measurement of stray voltage is below the PSCW “level"level of concern,”" that utility could stillnot be found negligent in stray voltage cases. Additionally, the Court held that the PSCW regulations regarding stray voltage were only minimum standards to be considered by a jury in stray voltage litigation.
As a result of this case, claims by dairy farmers for livestock damage have been based upon ground currents with levels measuring less than the PSCW level of concern. Even though the claims which have been made against us
NUCLEAR OPERATIONS
Point Beach Nuclear Plant: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 between usof the Company and affiliates of other unaffiliated utilities. During 2005, 2004 and 2003, Point Beach provided approximately 25%20% of our net electric energy supply during each of the three years ended December 31, 2004.
supply.
Each Unit at the Plant has a scheduled refueling outage approximately every 18 months. In 2005, Unit 2 had a scheduled refueling outage over the second and third quarters and Unit 1 had a scheduled refueling outage over the third and fourth quarters. During the 2005 scheduled refueling outages we replaced the reactor vessel heads at each Unit. As expected, this work, along with other planned maintenance, resulted 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. See Results of Operations for further discussion regarding the costs associated with nuclear outages. In the fourth quarter of 2006, Unit 2 is scheduled to have a refueling outage. In 2004, Unit 1 had a scheduled refueling outage in the second quarter and in 2003, Unit 2 had a scheduled refueling outage over the third and fourth quarters.
In 2005, Unit 2 is scheduled to have a refueling outage in the second quarter and Unit 1 is scheduled to have a refueling outage over the third and fourth quarters. During the 2005 scheduled refueling
February 2004, Form 10-K
outages, we will replace the reactor vessel heads at each Unit. This work, along with other planned maintenance, is expected to result in longer than normal outages. During scheduled refueling outages,NMC, we incur significant operations and maintenance costs for work performed duringfiled an application with the outage and we incur costs associated with replacement power.
The United States Nuclear Regulatory Commission (NRC) operating licenses for Point Beach expire in October 2010 for Unit 1 and in March 2013 for Unit 2. In February 2004, we and NMC filed an application with the NRC to renew the operating license for both unitsUnits for an additional 20 years. The NRC has indicated that they expect to act onapproved the license renewal request before Januaryin December 2005. The new operating licenses expire in October 2030 for Unit 1 and March 2033 for Unit 2.
In February 2006, we announced that we are undertaking a formal review this year regarding our options for the ownership and operation of Point Beach. At December 31, 2005, NMC operated seven nuclear generating units, down from eight units at December 31, 2004. As of February 2006, that number has decreased to six units and another owner has announced the planned sale of their unit, which would further reduce the size of the fleet operated by NMC. Given these changes, we believe it is prudent to evaluate a range of options for Point Beach. The options that we are planning to evaluate include: (1) continued operation by NMC, (2) continued operation by a third party operator other than NMC, (3) a return to in-house operation of the plant by us and (4) a sale of the Point Beach facility. We plan to complete this formal review in the fourth quarter of 2006.
In July 2000, our senior management authorized the commencement of initial design work for the power uprate of both unitsUnits at Point Beach. Subject to approval by the PSCW, the project could add approximately 90 megawatts of electrical output to Point Beach. In February 2003, Point Beach completed an equipment upgrade which resulted in a capacity increase of seven7 megawatts per generating Unit. We are currently evaluating the timing for implementation of the power uprate project.
During 2002 and 2003, the NRC issued Final Significance Determination letters for two red (high safety significance) inspection findings regarding problems identified by Point Beach with the performance of the auxiliary feedwater system recirculation lines. During 2003, the NRC conducted a three-phase supplemental inspection of Point Beach in accordance with NRC Inspection Procedure 95003 to review corrective actions for the findings as well as the effectiveness of the corrective action, emergency preparedness and engineering programs.
The inspection results were presented at a public meeting in December 2003, and documented in a February 2004 NRC letter to NMC. The NRC determined that the plant is being operated in a manner that ensures public safety but also identified several performance issues in the areas of problem identification and resolution, emergency preparedness, electrical design basis calculation control and engineering-operations communication.
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.
As a result of the September 11, 2001 terrorist attacks, NRC and the industry have been strengthening security at nuclear power plants. Security at Point Beach remains at a high level, with limited access to the site continuing. Point Beach has responded to NRC’sNRC's February 2002 Order for interim safeguards and security compensatory measures. Point Beach has also responded to NRC orders regarding security of independent spent fuel storage installations, design basis threat and security officer training and work hours.
Used Nuclear Fuel Storage and Disposal: We are authorized by the PSCW to load and store sufficient dry fuel storage containers to allow Point Beach Units 1 and 2 to operate to the end of their currentoriginal operating licenses, but not to exceed the original 48-canister capacity of the dry fuel storage facility.
The original operating licenses were set to expire in October 2010 for Unit 1 and in March 2013 for Unit 2 before they were renewed by the NRC in December 2005.
Temporary storage alternatives at Point Beach are necessary until the United States Department of Energy takes ownership of and permanently removes the used fuel as mandated by the Nuclear Waste Policy Act of 1982, as amended in 1987. The Nuclear Waste Policy Act established the Nuclear Waste Fund which is composed of payments made by the generators and owners of such waste and fuel.Effective January 31, 1998, the Department of Energy failed to meet its contractual obligation to begin removing used fuel from Point Beach, a responsibility for which we have paid a total of $200.3$207.4 million into the Nuclear Waste Fund over the life of the plant.
Plant.
On August 13, 2000, the United States Court of Appeals for the Federal Circuit ruled in a lawsuit brought by Maine Yankee and Northern States Power Company that the Department of Energy’sEnergy's failure to begin performance by January 31, 1998 constituted a breach of the Standard Contract, providing clear grounds for filing complaints in the Court of Federal Claims. Consequently, we filed a complaint on November 16, 2000 against the Department of Energy in the Court of Federal Claims. In October 2004, the Court of Federal Claims granted our motion for summary judgment on liability. The matter is pending.Court has subsequently scheduled the trial for March 2007. We have incurred substantial damages to date and damages continue to accrue. We are seeking recovery of our damages in this lawsuit.
2004 Form 10-K
lawsuit and we expect that any recoveries would be considered in setting future rates.
In July 2002, the President Bush signed a resolution which allowed the United States Department of Energy to begin preparation of the application to the NRC for a license to design and build a spent fuel repository in Yucca Mountain, in Nevada. The Department of Energy has indicated that it does not expect a permanent used fuel repository to be available any earlier than 2010. It is not possible, at this time, to predict with certainty when the Department of Energy will actually begin accepting used nuclear fuel.
INDUSTRY RESTRUCTURING AND COMPETITION
Electric Utility Industry
Across the United States, electric industry restructuring progress remains slow as it has been subsequent to the California price and supply problems in early 2001. The FERC continues to strongly support large Regional Transmission Organizationsregional transmission organizations (RTOs), which will affect the structure of the wholesale marketmarket. To this end, the Midwest ISO is expected to implementMISO implemented a bid-based market, the MISO Midwest Market, including the use of LMPslocational marginal pricing (LMP) to value electric transmission congestion. The MISO Midwest ISO energy markets are currently slated to commenceMarket commenced operation on April 1, 2005. The timeline for restructuring and retail access continues to be stretched out, and it is uncertain when retail access will happen in Wisconsin. However,Wisconsin; however, Michigan has adopted retail choice which potentially affects our Michigan operations. Deliberations are expectedIn August 2005, President Bush signed in to continue in Congress on a federal energy bill containing changes that would impactlaw the Energy Policy Act, which impacts the electric utility industry. (See Other Matters below for additional information on the Energy Policy Act). In the past few years, bills have passed the U. S. House of Representatives, but were not passed by the Senate. Major issuesaddition, major iss ues in industry restructuring, implementation of RTO markets and market power mitigation received substantial attention in 2004.2005. We continue to focus on infrastructure issues through Wisconsin Energy’sEnergy'sPower the Future growth strategy.
Restructuring in Wisconsin:Electric utility revenues in Wisconsin are regulated by the PSCW. Due to many factors, including relatively competitive electric rates charged by the state’sstate's electric utilities, Wisconsin is proceeding with restructuring of the electric utility industry at a much slower pace than many other states in the United States. Instead, the PSCW has been focused in recent years on electric reliability infrastructure issues for the stateState of Wisconsin such as:
The PSCW continues to maintain the position that the question of whether to implement electric retail competition in Wisconsin should ultimately be decided by the Wisconsin Legislature.legislature. No such legislation has been introduced in Wisconsin to date.
Restructuring in Michigan: Electric utility revenues in Michigan are regulated by the MPSC. In June 2000, the Governor of Michigan signed the “Customer"Customer Choice and Electric Reliability Act”Act" into law empowering the MPSC to implement electric retail access in Michigan. The new law provides that as of January 1, 2002, all Michigan retail customers of investor-owned utilities have the ability to choose their electric power producer. The Michigan Retail Access law was characterized by the Michigan Governor as “Choice"Choice for those who want it and protection for those who need it.”
"
As of January 1, 2002, our Michigan retail customers were allowed to remain with their regulated utility at regulated rates or choose an alternative electric supplier to provide power supply service. We have maintained our generation capacity and distribution assets and provide regulated service as we have in the past. We continue providing distribution and customer service functions regardless of the customer’scustomer's power supplier.
Competition and customer switching to alternative suppliers in our service territory in Michigan has been limited. With the exception of two general inquiries, no alternate supplier activity has occurred in our service territoryterritories in
2004 Form 10-K
Michigan, reflecting the small market area, our competitive regulated power supply prices and a lack of interest in general in the Upper Peninsula of Michigan as a market for alternative electric suppliers.
Restructuring in Illinois: In 1999, the stateState of Illinois passed legislation that introduced retail electric choice for large customers and introduced choice for all retail customers in May 2002. This legislation has not had, and is not expected to have a material impact on our business. We havehad one wholesale customer in Illinois, the City of Geneva, whose contract is scheduled to expireexpired on December 31, 2005.
Electric Transmission and Energy Markets
American Transmission Company: Effective January 1, 2001, we transferred all of our electric utility transmission assets to ATC in exchange for an ownership interest in this new company. Joining ATC is consistent with the FERC’s Order No. 2000, intended to foster competition, efficiency and reliability in the electric industry.
ATC is regulated by the FERC for all rate terms and conditions of service and is a transmission-owning member of the Midwest ISO.MISO. As of February 1, 2002, operational control of ATC’sATC's transmission system was transferred to the Midwest ISOMISO, and we became a non-transmission owning member and customer of the Midwest ISO.MISO.
Midwest ISO:MISO: In connection with its status as a FERC approved RTO, the Midwest ISO is in the process of implementingMISO implemented a bid-based energy market, the MISO Midwest Market, which is currently scheduled to be implementedcommenced operations on April 1, 2005. As part of this energy market, the Midwest ISO is developingMISO developed a market-based platform for valuing transmission congestion premised upon the LMP system that has been implemented in certain northeastern and mid-Atlantic states. As proposed to the FERC and preliminarily approved, theThe LMP system will includeincludes the ability to mitigate or eliminate congestion costs through the use of Financial Transmission Rights (FTRs), which will be initially. FTRs are allocated to market participants 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, both positive and negative, of the impacts of the LMP pricing system on Wisconsin and the Upper Peninsula of Michigan’s utilities (also known as WUMS utilities).
In August 2004, the FERC accepted the Midwest ISO Energy Markets Tariff (August 2004 Plan), subject to further development on certain issues and subsequent compliance filings by the Midwest ISO. Included in the plan were mitigation features, which were proposed by us and other WUMS utilities, to minimize the potential cost impacts of the start of the market on the WUMS utilities. Also included was an FTR mitigation plan for entities in highly congested areas such as WUMS.MISO. The August 2004 Plan is subject to numerous requests for rehearing which may result in further modifications to the Tariff.
It is unknown at this time what, if any, financial impact the LMP congestion pricing system might have on us. The Midwest ISO recently completed its first allocation of FTRs was completed for the period startingof April 1, 2005 and endingthrough August 31, 2005. We received 94% of the FTRs that we requested in the allocation process. The FTR allocation process will bewas then performed again for the period from September 1, 2005 to May 31, 2006, and it is unknown how many FTRs we will be granted during that allocation process.2006. To date, our unhedged congestion charges have not been material.
The Midwest ISO is currently deferringMISO deferred the costs to develop and start-up its energy market (new software systems and personnel). OnceNow that the market is operational, the development and start-up costs will beare charged to the Midwest ISO’sMISO market participants, including us.
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 MISO Midwest ISO “Day 2” energy markets.Market. Our request excluded LMP energy costs which will be recoverablebecause these costs are subject to recovery under Wisconsin’sthe Wisconsin Fuel Cost Adjustment Procedure. In March 2005, the PSCW accepted our request. We anticipate receiving a decision related to this request prior to the scheduled startsubmitted another joint proposal with other utilities in March 2005, requesting escrow accounting treatment for MISO Midwest Market costs until each utility's first rate case following April 1, 2008. The purpose of the Midwest ISO marketMarch 2005 request for escrow accounting was to provide clarification on April 1, 2005.
costs not included in the March 2005 approval for deferral accounting treatment. For further information on the accounting for MISO transactions see Critical Accounting Estimates below.
In the Midwest ISO,MISO, base transmission costs are currently being paid by load serving entities (LSEs) located in the service territories of each Midwest ISOMISO transmission owner in proportion to the load served by the LSE versus the total load of the service territory. This “license plate”"license plate" rate design is scheduled to be replaced after a six-year phase-in of rates in the Midwest ISO; but it also was the subject of a proceeding in which a new rate design governing service in the combined Midwest ISO and PJM Interconnection, L.L.C (PJM) service territories was to be
2004 Form 10-K
developed. However, the FERC has ordered the elimination of through and out transmission charges for transactions between the Midwest ISO and the PJM.
In November 2004, FERC issued an order allowing the existing Midwest ISO license plate rate design to continue until at leastMISO on or around February 1, 2008. In addition, FERC ordered a seams elimination charge to be paid by Midwest ISO LSE’sMISO LSE's 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’sFERC's elimination of through and out transmission charges between the Midwest ISOMISO and PJM.PJM Interconnection, L.L.C. 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 chargec harge are the subject of a hearing process initiated by FERC in a February 2005 order. We are currently unable to determineA decision from the impact 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 resulthearing process is expected in the second half 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, entities that currently pay a transmission charge to move energy through or out of a neighboring transmission system will no longer pay this charge2006. In January 2006, along with certain other parties to the neighboring transmission system owner or operator uponproceeding, we submitted an offer of settlement to the neighboring transmission system owner or operator joining an RTO.
Discussions as to appropriate lost revenue chargespresiding administrative law judge that, if approved, will resolve all issues set for hearing that impact us with regard to several entities’ decisions, including thatthe continued payment of Commonwealth Edison Company, a non-affiliated Illinois utility that provides us withthrough and out transmission service, to place their transmission facilities undercharges as well as the control of PJM were terminated in September 2004. In lieu of chargingseams elimination charge. To date, neither the previously ordered seam elimination cost adjustment,administrative law judge nor the FERC permittedhas addressed the Midwest ISO, PJM andmerits of the affected entities, including Commonwealth Edison Company, to continue to charge their existing rates for transmission to adjoining areas until December 1, 2004, after whichsettlement. If the affected entities as directedsettlement offer is approved by the FERC were required to developas submitted, we would receive a new rate design that will eliminate the multiplesmall refund of transmission charges between the service territoriesin excess of the Midwest ISO and PJM. Proposals addressing the rate design issue were filed at the FERC on October 1, 2004. These proposals were rejected by the FERC and the transmission owners. The Midwest ISO and PJM were directed to file Seams Elimination Charge Adjustment (SECA) proposals to be effective December 1, 2004. As previously noted, the reasonableness and magnitude of the proposed SECA charges has been set for a hearing. For further information see the above discussion related to Midwest ISO.seams elimination charge.
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. We were allocated FTRs for virtually all of our PJM transmission through May 31, 2005, and a new allocation will take place for the period June 1, 2005 through May 31, 2006. To date, we have experienced minimal net congestion costs associated with our FTRs in PJM. Congestion costs are included under the definition of fuel for the Wisconsin Fuel Cost Adjustment Procedure.
Natural Gas Utility Industry
Restructuring in Wisconsin: The PSCW haspreviously instituted generic proceedings to consider how its regulation of gas distribution utilities should change to reflect the changing competitive environment in the natural gas industry. To date, the PSCW has made a policy decision to deregulate the sale of natural gas in customer segments with workably competitive market choices and has adopted standards for transactions between a utility and its gas marketing affiliates. However, work on deregulation of the gas distribution industry by the PSCW is presently on hold. Currently, we are unable to predict the impact of potential future deregulation on our results of operations or financial position.
OTHER MATTERS
In August 2005, President Bush signed into law the Energy Policy Act. Among other things, the Energy Policy Act includes tax subsidies for electric utilities and the repeal of the Public Utility Holding Company Act of 1935 (PUHCA 1935). The Energy Policy Act also amends federal energy laws and provides the FERC with new oversight responsibilities for the electric utility industry. Implementation of the Energy Policy Act requires the development of regulations by federal agencies, including the FERC. As noted above, the Energy Policy Act and corresponding rules require us to seek FERC authorization to allow us to lease from We Power the threePower the Futureunits that are currently being constructed by We Power. Additionally, the Energy Policy Act enacted the Public Utility Holding Company Act of 2005 (PUHCA 2005), transferring jurisdiction over holding companies from the SEC to the FERC. We will be required to notify the FERC of our status as a holding company and to seek from the FERC the exempt status similar to that held under PUHCA 1935. As federal agencies continue to develop new rules to implement the Energy Policy Act, we expect additional impacts on us in the future.
ACCOUNTING DEVELOPMENTS
New Pronouncements: In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No.SFAS 123 (revised 2004), Share-Based Payment (SFAS 123R), which amended SFAS 123, Accounting for Stock-Based Compensation. In March 2005, the SEC issued Staff Accounting Bulletin 107 (SAB 107) regarding the SEC's interpretation of SFAS 123R and the valuation of share-based payment for public companies. In April 2005, the SEC deferred the effective date of SFAS 123R to January 1, 2006. This statement requires that the compensation costs relating to such transactions be recognized in the consolidated income statement. We are currently evaluating
2004 Form 10-K
the provisions ofadopted SFAS 123R and expect to adopt it on JulySAB 107 effective January 1, 2005. We have not yet determined2006 using the methodmodified prospective method. See Note A -- Summary of transition. See“Significant Accounting Policies and Note B–B -- Recent Accounting Pronouncements”Pronouncements in the Notes to Consolidated Financial Statements in this report for additional informa tion.
In March 2005, the FASB issued Interpretation 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), an interpretation of FASB Statement 143. We adopted FIN 47 effective December 31, 2005. For further information see Note I -- Asset Retirement Obligations.
We adopted FASB Staff Position FIN 46R - 5, Implicit Variable Interests under FASB Interpretation 46 (revised December 2003), in the second quarter of 2005. This statement requires that holdings of implicit variable interests are evaluated when applying Interpretation 46R. See Note D -- Variable Interest Entities for further information.
In May 2005, the FASB issued SFAS 154, Accounting Changes and Error Corrections, a replacement of Accounting Principles Board (APB) Opinion 20 and SFAS 3. This statement requires a retrospective application of direct changes in accounting principles to prior periods' financial statements, unless it is impracticable to determine the period-specific or cumulative effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. In addition, SFAS 154 instructs that a change in depreciation, amortization or depletion method for long-lived, non-financial assets must be recorded as a change in accounting estimate affected by a change in accounting principle. We adopted SFAS 154, effective January 1, 2006. The adoption of SFAS 154 has not had an impact on our consolidated financial position or results of operations, as we have not had a change in accounting principle that w e were required to implement to date in 2006.
CRITICAL ACCOUNTING ESTIMATES
Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles (GAAP) requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions. In addition, the financial and operating environment also may have a significant effect, not only on the operation of our business, but on our results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied have not changed.
The following is a list of accounting policies that are most significant to the portrayal of our financial condition and results of operations and that require management’smanagement's most difficult, subjective or complex judgments.
Regulatory Accounting:Our electric, gas and steam operations We operate under rates established by state and federal regulatory commissions which are designed to recover the cost of service and provide a reasonable return to investors. Developing competitive pressures in the utility industry may result in future utility prices which are based upon factors other than the traditional original cost of investment. In this situation, continued deferral of certain regulatory asset and liability amounts on our books, as allowed under Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71), may no longer be appropriate and the unamortized regulatory assets net of the regulatory liabilities would be recorded as an extraordinary after-tax non-cash charge to earnings.As of December 31, 2004,2005, we had $656.6$822.5 million in regulatory assets and $600.2$1,051.9 million in regulatory liabilities in comparison to $443.4 million of regulatory assets and $561.7 million of regulatory liabilities as of December 31, 2003.liabilities. We continuallycontinuall y review the applicability of SFAS 71 and have determined that it is currently appropriate to continue
Pension and Other Post-retirement Benefits: Our reported costs of providing non-contributory defined pension benefits (described in “Note L–Benefits”Note L -- Benefits in the Notes to Consolidated Financial Statements) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. Pension costs are impacted by actual employee demographics (including age, compensation levels and employment periods), the level of contributions made to plans and earnings on plan assets. Changes made to the provisions of the plans may also impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs.
In accordance with SFAS 87, Employers’Employers' Accounting for Pensions (SFAS 87), changes in pension obligations associated with these factors may not be immediately recognized as pension costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants.
The following chart reflects pension plan sensitivities associated with changes in certain actuarial assumptions by the indicated percentage. Each sensitivity reflects a change to the given assumption, holding all other assumptions constant.
Pension Plans | Impact on | |||
2004 Form 10-K
| ||
| (Millions of Dollars) | ||
0.5% decrease in discount rate | $ | |
| 6.3 | ||
0.5% decrease in expected rate of return on plan assets | $3.5 | |
(a) | The inverse of the change in the actuarial assumption may be expected to have an approximately similar impact in the opposite direction. |
In addition to pension plans, we maintain other post-retirement benefit plans which provide health and life insurance benefits for retired employees (described in “Note L–Benefits”Note L -- Benefits in the Notes to Consolidated Financial Statements). We account for these plans in accordance with Statement of Financial Accounting Standards No.SFAS 106, Employers’Employers' Accounting for Post-retirement Benefits Other thanThan Pensions (SFAS 106). Our reported costs of providing these post-retirement benefits are dependent upon numerous factors resulting from actual plan experience including employee demographics (age and compensation levels), our contributions to the plans, earnings on plan assets and health care cost trends. Changes made to the provisions of the plans may also impact current and future post-retirement benefit costs. Other post-retirement benefit costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the post-retirementp ost-retirement benefit obligation and post-retirement costs. Our other post-retirement benefit plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased other post-retirement costs in future periods.
Similar to accounting for pension plans, theour regulators of our utility operations have adopted SFAS 106 for rate making purposes.
The following chart reflects other post-retirement benefit plan sensitivities associated with changes in certain actuarial assumptions by the indicated percentage. Each sensitivity reflects a change to the given assumption, holding all other assumptions constant.
Other Post-retirement Benefit Plans
| Impact on | ||
(Millions of Dollars) | |||
0.5% decrease in discount rate | $ | ||
| 2.0 | |||
0.5% decrease in health care cost trend rate | |||
($1.4) | |||
0.5% decrease in expected rate of return on plan assets | $ | 0.5 | |
(a) | The inverse of the change in the actuarial assumption may be expected to have an approximately similar impact in the opposite direction. |
Unbilled Revenues: We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated. This unbilled revenue is estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses and applicable customer rates. Significant fluctuations in energy demand for the unbilled period or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. Total utility operating revenues during 20042005 of $2.6 billion$2,938.0 million included accrued utility revenues of $164.5$175.6 million at December 31, 2004.2005.
2004 Form 10-K
Asset Retirement Obligations: We account for legal liabilities for asset retirements at fair value in the period in which they are incurred according to the provisions of Statement of Financial Accounting Standards No.SFAS 143, Accounting for Asset Retirement Obligations (SFAS 143). and Accounting for Conditional Asset Retirement Obligations (FIN 47), an Interpretation of SFAS 143. SFAS 143 applies primarily to decommissioning costs for our Point Beach Nuclear Plant. Using a discounted future cash flow methodology, our estimated nuclear asset retirement obligation was approximately $745$309.8 million at December 31, 2004.
2005. As it relates to our operations, FIN 47 applies primarily to asbestos removal costs. At December 31, 2005, we recorded an obligation of $37.4 million related to asbestos.
Calculation of thisthe nuclear decommissioning asset retirement obligation is based upon projected decommissioning costs calculated by an independent decommissioning consulting firm, as well as several significant assumptions including the timing of future cash flows, future inflation rates and the discount rate applied to future cash flows and an 85% probability of plant relicensing.flows. Assuming the following changes in key assumptions and holding all other assumptions constant, we estimate that our nuclear asset retirement obligation at December 31, 20042005 would have changed by the following amounts:
Change in Assumption | Change in Liability | ||
(Millions of Dollars) | |||
1% increase in inflation rate | $ | 101.1 | |
1% decrease in inflation rate | |||
| |||
| |||
We were unable to identify a viable market for or third party who would be willing to assume this liability. Accordingly, we have used a market-risk premium of zero when measuring our nuclear asset retirement obligation. We estimate that for each 1% increment that would be included as a market-risk premium, our nuclear asset retirement obligation would increase by approximately$7.5 $3.1 million.
For additional information concerning SFAS 143 and our estimated nuclear asset retirement obligation, see “Note I–Note I -- Asset Retirement Obligations”Obligations and “Note F–Note F --Nuclear Operations”Operations in the Notes to Consolidated Financial Statements.
MISO Bid-Based Energy Market: Effective April 1, 2005, MISO implemented the MISO Midwest Market, 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 MISO region. MISO then calculates the most efficient solution for all the bids and offers made into the market that day and establishes a LMP which reflects the market price for energy. As a participant in the new MISO Midwest Market, we are required to follow MISO's instructions when dispatching generating units to support MISO's responsibility for maintaining stability of the transmission system. To the extent the established LMP price for energy is not sufficient to recover the cost of running a generating unit dispatched at MISO's request, the tariff provides a mechanism for us to recover the deficiency (the "make-whole payment"). Since the start of the MISO Midwest Market, MISO has significantly increa sed the amount of generation provided by our higher cost combustion turbines. We have recorded a receivable from MISO for the make-whole payments associated with this operation. A reserve has been established for a portion of these receivables that are currently in dispute. Additionally, the MISO Midwest Market subjects us to additional costs primarily associated with constraints in the transmission system. We expect to recover these deferred costs in future rates, subject to PSCW audit and approval.
MISO settles each Operating Day a minimum of four times. A settlement statement is issued at 7, 14, 55 and 105 days after each Operating Day. In addition, since the market start, MISO has employed a non-standard settlement statement at 155 days after the Operating Day. MISO has also announced plans to issue a non-standard statement at 365 days after the Operating Day for days April 1, 2005 through August 31, 2005. Each subsequent statement may contain billing adjustments which alter our obligation to MISO.
CAUTIONARY FACTORS
This report and other documents or oral presentations contain or may contain forward-looking statements made by or on behalf of Wisconsin Electric. These statements are based upon management’smanagement's current expectations and are subject to risks and uncertainties that could cause our actual results to differ materially from those contemplated in the statements. Readers are cautioned not to place undue reliance on the forward-looking statements. When used in written documents or oral presentations, the terms “anticipates,” “believes,” “estimates,” “expects,” “forecasts,” “intends,” “may,” “objectives,” “plans,” “possible,” “potential,” “projects”"anticipates," "believes," "estimates," "expects," "forecasts," "intends," "may," "objectives," "plans," "possible," "potential," "projects" and similar expressions are intended to identify forward-looking statements. In addition to the assumptions and other factors referred to specifically in connection with these statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statements or otherwise affect our future results of operations and financialf inancial condition include, among others, the following:
2004 Form 10-K
|
.
*****
We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
See “FactorsFactors Affecting Results, Liquidity and Capital Resources–Resources -- Market Risks and Other Significant Risks”Risks in Item 7. Management’sManagement's Discussion and Analysis of Financial Condition and Results of Operations in this report for information concerning potential market risks to which we are exposed.
2004 Form 10-K
WISCONSIN ELECTRIC POWER COMPANY | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
CONSOLIDATED INCOME STATEMENTS | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Year Ended December 31 |
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2005 | 2004 | 2003 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(Millions of Dollars) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Operating Revenues | $2,938.0 | $2,616.6 | $2,521.9 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Operating Expenses | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fuel and purchased power | 773.8 | 585.4 | 562.4 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cost of gas sold | 446.3 | 376.9 | 355.4 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other operation and maintenance | 880.5 | 844.7 | 784.0 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Depreciation, decommissioning and amortization | 281.8 | 274.1 | 276.2 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property and revenue taxes | 78.3 | 76.3 | 72.6 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total Operating Expenses | 2,460.7 | 2,157.4 | 2,050.6 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Operating Income | 477.3 | 459.2 | 471.3 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Income and Deductions, Net | 58.8 | 33.5 | 31.5 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest Expense | 85.8 | 89.6 | 91.2 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Before Income Taxes | 450.3 | 403.1 | 411.6 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Taxes | 165.5 | 153.2 | 154.9 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net Income | 284.8 | 249.9 | 256.7 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Preferred Stock Dividend Requirement | 1.2 | 1.2 | 1.2 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings Available for Common | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Stockholder | $283.6 | $248.7 | $255.5 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2004 Form 10-K
WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31
| 2004 | 2003 | 2002 | ||||||||||
| (Millions of Dollars) | ||||||||||||
Operating Activities | ||||||||||||
Net income | $ | 249.9 | $ | 256.7 | $ | 259.2 | ||||||
Reconciliation to cash | ||||||||||||
Depreciation, decommissioning and amortization | 294.9 | 301.9 | 282.3 | |||||||||
Nuclear fuel expense amortization | 24.0 | 25.3 | 27.3 | |||||||||
Equity in earnings of unconsolidated affiliate | (26.4 | ) | (22.8 | ) | (20.4 | ) | ||||||
Distribution from unconsolidated affiliate | 20.4 | 17.6 | 18.1 | |||||||||
Deferred income taxes and investment tax credits, net | 136.8 | (1.7 | ) | (31.9 | ) | |||||||
Accrued income taxes, net | (64.4 | ) | (6.0 | ) | 37.2 | |||||||
Deferred transmission costs | (36.3 | ) | (9.5 | ) | (40.2 | ) | ||||||
Deferred lease costs | (28.2 | ) | (17.4 | ) | – | |||||||
Change in–Accounts receivable and accrued revenues | (28.7 | ) | 5.3 | (26.1 | ) | |||||||
Other accounts receivable | – | – | 116.4 | |||||||||
Inventories | 2.4 | (31.7 | ) | (17.4 | ) | |||||||
Other current assets | (6.5 | ) | (5.9 | ) | 2.0 | |||||||
Accounts payable | 57.1 | (8.7 | ) | (20.0 | ) | |||||||
Other current liabilities | 5.0 | 7.5 | 22.3 | |||||||||
Other | 30.8 | 3.6 | 47.5 | |||||||||
Cash Provided by Operating Activities | 630.8 | 514.2 | 656.3 | |||||||||
Investing Activities | ||||||||||||
Capital expenditures | (358.9 | ) | (343.7 | ) | (365.7 | ) | ||||||
Investments | (23.2 | ) | – | – | ||||||||
Nuclear fuel | (30.0 | ) | (38.3 | ) | (20.7 | ) | ||||||
Nuclear decommissioning funding | (17.6 | ) | (17.6 | ) | (17.6 | ) | ||||||
Other | 5.8 | (3.2 | ) | (12.1 | ) | |||||||
Cash Used in Investing Activities | (423.9 | ) | (402.8 | ) | (416.1 | ) | ||||||
Financing Activities | ||||||||||||
Dividends paid on common stock | (179.6 | ) | (179.6 | ) | (179.6 | ) | ||||||
Dividends paid on preferred stock | (1.2 | ) | (1.2 | ) | (1.2 | ) | ||||||
Issuance of long-term debt | 397.0 | 635.5 | 1.3 | |||||||||
Retirement and redemption of long-term debt | (290.1 | ) | (502.5 | ) | (251.1 | ) | ||||||
Change in short-term debt | (126.4 | ) | (38.9 | ) | 182.4 | |||||||
Other | (0.5 | ) | (18.0 | ) | – | |||||||
Cash Used in Financing Activities | (200.8 | ) | (104.7 | ) | (248.2 | ) | ||||||
Change in Cash and Cash Equivalents | 6.1 | 6.7 | (8.0 | ) | ||||||||
Cash and Cash Equivalents at Beginning of Year | 20.0 | 13.3 | 21.3 | |||||||||
Cash and Cash Equivalents at End of Year | $ | 26.1 | $ | 20.0 | $ | 13.3 | ||||||
Supplemental Information–Cash Paid For | ||||||||||||
Interest (net of amount capitalized) | $ | 103.9 | $ | 112.1 | $ | 114.8 | ||||||
Income taxes (net of refunds) | $ | 53.6 | $ | 148.7 | $ | 124.1 | ||||||
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
2004 Form 10-K
WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
December 31
ASSETS
| 2004 | 2003 | |||||||
| (Millions of Dollars) | ||||||||
Property, Plant and Equipment | ||||||||
Electric | $ | 5,752.0 | $ | 5,726.6 | ||||
Gas | 687.5 | 671.0 | ||||||
Steam | 76.3 | 69.7 | ||||||
Common | 302.1 | 299.0 | ||||||
Other | 55.1 | 52.8 | ||||||
| 6,873.0 | 6,819.1 | |||||||
Accumulated depreciation | (2,637.9 | ) | (2,571.4 | ) | ||||
| 4,235.1 | 4,247.7 | |||||||
Construction work in progress | 153.6 | 68.3 | ||||||
Leased facilities, net | 98.9 | 104.6 | ||||||
Nuclear fuel, net | 85.0 | 78.4 | ||||||
Net Property, Plant and Equipment | 4,572.6 | 4,499.0 | ||||||
Investments | ||||||||
Nuclear decommissioning trust fund | 737.8 | 674.4 | ||||||
Equity investment in transmission affiliate | 165.3 | 136.2 | ||||||
Other | 0.5 | 0.7 | ||||||
Total Investments | 903.6 | 811.3 | ||||||
Current Assets | ||||||||
Cash and cash equivalents | 26.1 | 20.0 | ||||||
Accounts receivable, net of allowance for doubtful accounts of $20.2 and $26.6 | 253.3 | 239.3 | ||||||
Accrued revenues | 164.5 | 149.8 | ||||||
Materials, supplies and inventories | 273.8 | 276.2 | ||||||
Prepayments | 86.9 | 95.6 | ||||||
Deferred income taxes–current | – | 42.4 | ||||||
Other | 1.4 | 3.6 | ||||||
Total Current Assets | 806.0 | 826.9 | ||||||
Deferred Charges and Other Assets | ||||||||
Regulatory assets | 644.7 | 443.4 | ||||||
Other | 123.4 | 64.0 | ||||||
Total Deferred Charges and Other Assets | 768.1 | 507.4 | ||||||
Total Assets | $ | 7,050.3 | $ | 6,644.6 | ||||
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
2004 Form 10-K
WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
December 31
CAPITALIZATION AND LIABILITIES
| 2004 | 2003 | |||||
| (Millions of Dollars) | ||||||
Capitalization | ||||||
Common equity | $ | 2,204.2 | $ | 2,131.9 | ||
Preferred stock | 30.4 | 30.4 | ||||
Long-term debt | 1,683.1 | 1,435.3 | ||||
Total Capitalization | 3,917.7 | 3,597.6 | ||||
Current Liabilities | ||||||
Long-term debt due currently | 23.7 | 164.2 | ||||
Short-term debt | 189.5 | 315.9 | ||||
Accounts payable | 249.8 | 184.9 | ||||
Payroll and vacation accrued | 65.2 | 58.1 | ||||
Taxes accrued–income and other | 38.3 | 103.7 | ||||
Interest accrued | 8.7 | 12.2 | ||||
Deferred income taxes–current | 6.7 | – | ||||
Other | 86.3 | 91.1 | ||||
Total Current Liabilities | 668.2 | 930.1 | ||||
Deferred Credits and Other Liabilities | ||||||
Asset retirement obligations | 762.2 | 732.0 | ||||
Regulatory liabilities | 600.2 | 561.7 | ||||
Deferred income taxes–long-term | 548.5 | 456.4 | ||||
Minimum pension liability | 248.0 | 113.8 | ||||
Accumulated deferred investment tax credits | 56.9 | 61.4 | ||||
Other long-term liabilities | 248.6 | 191.6 | ||||
Total Deferred Credits and Other Liabilities | 2,464.4 | 2,116.9 | ||||
Commitments and Contingencies (Note P) | – | – | ||||
Total Capitalization and Liabilities | $ | 7,050.3 | $ | 6,644.6 | ||
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
2004 Form 10-K
WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31
| 2004 | 2003 | |||||||||
| (Millions of Dollars) | ||||||||||
Common Equity (See Consolidated Statements of Common Equity) | ||||||||||
Common stock–$10 par value; authorized 65,000,000 shares; outstanding–33,289,327 shares | $ | 332.9 | $ | 332.9 | ||||||
Other paid in capital | 538.3 | 532.4 | ||||||||
Retained earnings | 1,339.9 | 1,270.8 | ||||||||
Accumulated other comprehensive income (loss) | (6.9 | ) | (4.2 | ) | ||||||
Total Common Equity | 2,204.2 | 2,131.9 | ||||||||
Preferred Stock | ||||||||||
Six Per Cent. Preferred Stock–$100 par value; authorized 45,000 shares; outstanding–44,498 shares | 4.4 | 4.4 | ||||||||
Serial preferred stock– | ||||||||||
$100 par value; authorized 2,286,500 shares; 3.60% Series redeemable at $101 per share; outstanding–260,000 shares | 26.0 | 26.0 | ||||||||
$25 par value; authorized 5,000,000 shares; none outstanding | – | – | ||||||||
Total Preferred Stock | 30.4 | 30.4 | ||||||||
Long-Term Debt | ||||||||||
First mortgage bonds | 7 1/4% due 2004 | – | 140.0 | |||||||
Debentures (unsecured) | 6 5/8% due 2006 | 200.0 | 200.0 | |||||||
9.47% due 2006 | 1.4 | 2.1 | ||||||||
3.50% due 2007 | 250.0 | – | ||||||||
4.50% due 2013 | 300.0 | 300.0 | ||||||||
6 1/2% due 2028 | 150.0 | 150.0 | ||||||||
5.625% due 2033 | 335.0 | 335.0 | ||||||||
6 7/8% due 2095 | 100.0 | 100.0 | ||||||||
Notes (secured, nonrecourse) | 2% stated rate due 2011 | 1.3 | 1.3 | |||||||
4.81% effective rate due 2030 | 2.0 | 2.0 | ||||||||
Notes (unsecured) | 6.36% effective rate due 2006 | 2.4 | 3.6 | |||||||
2.10% variable rate due 2006 (a) | 1.0 | 1.0 | ||||||||
2.10% variable rate due 2015 (a) | 17.4 | 17.4 | ||||||||
1.25% variable rate due 2016 (b) | – | 67.0 | ||||||||
1.65% variable rate due 2016 (a) | 67.0 | – | ||||||||
1.52% variable rate due 2030 (b) | – | 80.0 | ||||||||
1.70% variable rate due 2030 (a) | 80.0 | – | ||||||||
Obligations under capital leases | 212.9 | 213.2 | ||||||||
Unamortized discount | (13.6 | ) | (13.1 | ) | ||||||
Long-term debt currently due | (23.7 | ) | (164.2 | ) | ||||||
Total Long-Term Debt | 1,683.1 | 1,435.3 | ||||||||
Total Capitalization | $ | 3,917.7 | $ | 3,597.6 | ||||||
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
WISCONSIN ELECTRIC POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31 2005 2004 2003 (Millions of Dollars) Operating Activities Net income $284.8 $249.9 $256.7 Reconciliation to cash Depreciation, decommissioning and amortization 297.0 294.9 301.9 Nuclear fuel expense amortization 23.0 24.0 25.3 Equity in earnings of unconsolidated affiliate (30.4) (26.4) (22.8) Distributions from unconsolidated affiliate 23.7 20.4 17.6 Deferred income taxes and investment tax credits, net 19.9 136.8 (1.7) Change in - Accounts receivable and accrued revenues (66.7) (28.7) 5.3 Inventories (23.7) 2.4 (31.7) Other current assets (2.9) (6.5) (5.9) Accounts payable 44.1 57.1 (8.7) Accrued income taxes, net 31.5 (64.4) (6.0) Deferred costs, net (140.3) (34.3) (50.9) Other current liabilities 1.1 5.0 7.5 Other 20.2 0.6 27.6 Cash Provided by Operating Activities 481.3 630.8 514.2 Investing Activities Capital expenditures (409.2) (358.9) (343.7) Investments (9.2) (23.2) - Nuclear fuel (49.7) (30.0) (38.3) Nuclear decommissioning funding (17.6) (17.6) (17.6) Proceeds from investments within nuclear decommissioning trust 435.7 327.2 474.6 Purchases of investments within nuclear decommissioning trust (435.7) (327.2) (474.6) Other 3.6 5.8 (3.2) Cash Used in Investing Activities (482.1) (423.9) (402.8) Financing Activities Dividends paid on common stock (179.6) (179.6) (179.6) Dividends paid on preferred stock (1.2) (1.2) (1.2) Issuance of long-term debt 40.8 397.0 635.5 Retirement and redemption of long-term debt (25.3) (290.1) (502.5) Change in short-term debt 163.2 (126.4) (38.9) Other - (0.5) (18.0) Cash Used in Financing Activities (2.1) (200.8) (104.7) Change in Cash and Cash Equivalents (2.9) 6.1 6.7 Cash and Cash Equivalents at Beginning of Year 26.1 20.0 13.3 Cash and Cash Equivalents at End of Year $23.2 $26.1 $20.0 Supplemental Information - Cash Paid For Interest (net of amount capitalized) $103.9 $103.9 $112.1 Income taxes (net of refunds) $114.1 $53.6 $148.7 The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.2004 Form 10-K
WISCONSIN ELECTRIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMMON EQUITY
| Common Stock | Other Paid In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total | |||||||||
| (Millions of Dollars) | |||||||||||||
Balance–December 31, 2001 | $332.9 | $530.7 | $1,116.5 | $– | $1,980.1 | ||||||||
Net income | 259.2 | 259.2 | |||||||||||
Other comprehensive income (loss) | |||||||||||||
Minimum pension liability | (8.1 | ) | (8.1 | ) | |||||||||
Hedging, net | (0.5 | ) | (0.5 | ) | |||||||||
Comprehensive Income (loss) | – | – | 259.2 | (8.6 | ) | 250.6 | |||||||
Cash dividends | |||||||||||||
Common stock | (179.6 | ) | (179.6 | ) | |||||||||
Preferred stock | (1.2 | ) | (1.2 | ) | |||||||||
Balance–December 31, 2002 | $332.9 | $530.7 | $1,194.9 | ($8.6 | ) | $2,049.9 | |||||||
Net income | 256.7 | 256.7 | |||||||||||
Other comprehensive income | |||||||||||||
Minimum pension liability | 3.9 | 3.9 | |||||||||||
Hedging, net | 0.5 | 0.5 | |||||||||||
Comprehensive Income | – | – | 256.7 | 4.4 | 261.1 | ||||||||
Cash dividends | |||||||||||||
Common stock | (179.6 | ) | (179.6 | ) | |||||||||
Preferred stock | (1.2 | ) | (1.2 | ) | |||||||||
Tax benefit of exercised stock options allocated from Parent | 1.7 | 1.7 | |||||||||||
Balance–December 31, 2003 | $332.9 | $532.4 | $1,270.8 | ($4.2 | ) | $2,131.9 | |||||||
Net income | 249.9 | 249.9 | |||||||||||
Other comprehensive income | |||||||||||||
Minimum pension liability | (2.9 | ) | (2.9 | ) | |||||||||
Hedging, net | 0.2 | 0.2 | |||||||||||
Comprehensive Income | – | – | 249.9 | (2.7 | ) | 247.2 | |||||||
Cash dividends | |||||||||||||
Common stock | (179.6 | ) | (179.6 | ) | |||||||||
Preferred stock | (1.2 | ) | (1.2 | ) | |||||||||
Tax benefit of exercised stock options allocated from Parent | 5.9 | 5.9 | |||||||||||
Balance–December 31, 2004 | $332.9 | $538.3 | $1,339.9 | ($6.9 | ) | $2,204.2 | |||||||
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
2004 Form 10-K
WISCONSIN ELECTRIC POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A–SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
WISCONSIN ELECTRIC POWER COMPANY | |||||||
CONSOLIDATED BALANCE SHEETS | |||||||
December 31 | |||||||
ASSETS | |||||||
2005 | 2004 | ||||||
(Millions of Dollars) | |||||||
Property, Plant and Equipment | |||||||
Electric | $6,024.1 | $5,752.0 | |||||
Gas | 712.8 | 687.5 | |||||
Steam | 78.5 | 76.3 | |||||
Common | 278.1 | 302.1 | |||||
Other | 58.9 | 55.1 | |||||
7,152.4 | 6,873.0 | ||||||
Accumulated depreciation | (2,805.0) | (2,637.9) | |||||
4,347.4 | 4,235.1 | ||||||
Construction work in progress | 232.0 | 153.6 | |||||
Leased facilities, net | 422.6 | 98.9 | |||||
Nuclear fuel, net | 112.0 | 85.0 | |||||
Net Property, Plant and Equipment | 5,114.0 | 4,572.6 | |||||
Investments | |||||||
Nuclear decommissioning trust fund | 782.1 | 737.8 | |||||
Equity investment in transmission affiliate | 181.2 | 165.3 | |||||
Other | 0.4 | 0.5 | |||||
Total Investments | 963.7 | 903.6 | |||||
Current Assets | |||||||
Cash and cash equivalents | 23.2 | 26.1 | |||||
Accounts receivable, net of allowance for | |||||||
doubtful accounts of $20.2 and $20.2 | 308.9 | 253.3 | |||||
Accrued revenues | 175.6 | 164.5 | |||||
Materials, supplies and inventories | 297.5 | 273.8 | |||||
Prepayments | 90.0 | 86.9 | |||||
Other | 1.3 | 1.4 | |||||
Total Current Assets | 896.5 | 806.0 | |||||
Deferred Charges and Other Assets | |||||||
Regulatory assets | 822.5 | 644.7 | |||||
Other | 112.5 | 123.4 | |||||
Total Deferred Charges and Other Assets | 935.0 | 768.1 | |||||
Total Assets | $7,909.2 | $7,050.3 | |||||
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements. | |||||||
WISCONSIN ELECTRIC POWER COMPANY | |||||||
CONSOLIDATED BALANCE SHEETS | |||||||
December 31 | |||||||
CAPITALIZATION AND LIABILITIES | |||||||
2005 | 2004 | ||||||
(Millions of Dollars) | |||||||
Capitalization | |||||||
Common equity | $2,310.9 | $2,204.2 | |||||
Preferred stock | 30.4 | 30.4 | |||||
Long-term debt | 1,290.1 | 1,492.0 | |||||
Capital lease obligations | 536.0 | 191.1 | |||||
Total Capitalization | 4,167.4 | 3,917.7 | |||||
Current Liabilities | |||||||
Long-term debt and capital lease obligations due currently | 232.4 | 23.7 | |||||
Short-term debt | 352.7 | 189.5 | |||||
Accounts payable | 293.9 | 249.8 | |||||
Payroll and vacation accrued | 67.4 | 65.2 | |||||
Accrued taxes | 71.0 | 38.3 | |||||
Accrued interest | 8.6 | 8.7 | |||||
Deferred income taxes - current | 22.4 | 6.7 | |||||
Other | 84.1 | 86.3 | |||||
Total Current Liabilities | 1,132.5 | 668.2 | |||||
Deferred Credits and Other Liabilities | |||||||
Asset retirement obligations | 354.9 | 762.2 | |||||
Regulatory liabilities | 1,051.9 | 600.2 | |||||
Deferred income taxes - long-term | 553.2 | 548.5 | |||||
Minimum pension liability | 347.2 | 248.0 | |||||
Accumulated deferred investment tax credits | 52.6 | 56.9 | |||||
Other long-term liabilities | 249.5 | 248.6 | |||||
Total Deferred Credits and Other Liabilities | 2,609.3 | 2,464.4 | |||||
Commitments and Contingencies (Note Q) | - | - | |||||
Total Capitalization and Liabilities | $7,909.2 | $7,050.3 | |||||
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements. | |||||||
WISCONSIN ELECTRIC POWER COMPANY | |||||||||
CONSOLIDATED STATEMENTS OF CAPITALIZATION | |||||||||
December 31 | |||||||||
2005 | 2004 | ||||||||
(Millions of Dollars) | |||||||||
Common Equity (See Consolidated Statements of Common Equity) | |||||||||
Common stock - $10 par value; authorized | |||||||||
65,000,000 shares; outstanding - 33,289,327 shares | $332.9 | $332.9 | |||||||
Other paid in capital | 542.6 | 538.3 | |||||||
Retained earnings | 1,443.9 | 1,339.9 | |||||||
Accumulated other comprehensive income (loss) | (8.5) | (6.9) | |||||||
Total Common Equity | 2,310.9 | 2,204.2 | |||||||
Preferred Stock | |||||||||
Six Per Cent. Preferred Stock - $100 par value; | |||||||||
authorized 45,000 shares; outstanding - 44,498 shares | 4.4 | 4.4 | |||||||
Serial preferred stock - | |||||||||
$100 par value; authorized 2,286,500 shares; 3.60% Series | |||||||||
redeemable at $101 per share; outstanding - 260,000 shares | 26.0 | 26.0 | |||||||
$25 par value; authorized 5,000,000 shares; none outstanding | - | - | |||||||
Total Preferred Stock | 30.4 | 30.4 | |||||||
Long-Term Debt | |||||||||
Debentures (unsecured) | 6-5/8% due 2006 | 200.0 | 200.0 | ||||||
9.47% due 2006 | 0.7 | 1.4 | |||||||
3.50% due 2007 | 250.0 | 250.0 | |||||||
4.50% due 2013 | 300.0 | 300.0 | |||||||
6-1/2% due 2028 | 150.0 | 150.0 | |||||||
5.625% due 2033 | 335.0 | 335.0 | |||||||
6-7/8% due 2095 | 100.0 | 100.0 | |||||||
Notes (secured, nonrecourse) | 2% stated rate due 2011 | 1.2 | 1.3 | ||||||
4.81% effective rate due 2030 | 2.0 | 2.0 | |||||||
Notes (unsecured) | 6.36% effective rate due 2006 | 1.2 | 2.4 | ||||||
3.55% variable rate due 2006 (a) | 1.0 | 1.0 | |||||||
3.55% variable rate due 2015 (a) | 17.4 | 17.4 | |||||||
3.50% variable rate due 2016 (a) | 67.0 | 67.0 | |||||||
3.50% variable rate due 2030 (a) | 80.0 | 80.0 | |||||||
Obligations under capital leases | 565.5 | 212.9 | |||||||
Unamortized discount, net | (12.5) | (13.6) | |||||||
Long-term debt and capital lease obligations due currently | (232.4) | (23.7) | |||||||
Total Long-Term Debt | 1,826.1 | 1,683.1 | |||||||
Total Capitalization | $4,167.4 | $3,917.7 | |||||||
(a) Variable interest rate as of December 31, 2005. | |||||||||
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements. | |||||||||
WISCONSIN ELECTRIC POWER COMPANY | |||||||||||||||
CONSOLIDATED STATEMENTS OF COMMON EQUITY | |||||||||||||||
Accumulated | |||||||||||||||
Other | |||||||||||||||
Common | Other Paid | Retained | Comprehensive | ||||||||||||
Stock | In Capital | Earnings | Income (Loss) | Total | |||||||||||
(Millions of Dollars) | |||||||||||||||
Balance - December 31, 2002 | $332.9 | $530.7 | $1,194.9 | ($8.6) | $2,049.9 | ||||||||||
Net income | 256.7 | 256.7 | |||||||||||||
Other comprehensive income | |||||||||||||||
Minimum pension liability | 3.9 | 3.9 | |||||||||||||
Hedging, net | 0.5 | 0.5 | |||||||||||||
Comprehensive income | - | - | 256.7 | 4.4 | 261.1 | ||||||||||
Cash dividends | |||||||||||||||
Common stock | (179.6) | (179.6) | |||||||||||||
Preferred stock | (1.2) | (1.2) | |||||||||||||
Tax benefit of exercised stock | |||||||||||||||
options allocated from Parent | 1.7 | 1.7 | |||||||||||||
Balance - December 31, 2003 | 332.9 | 532.4 | 1,270.8 | (4.2) | 2,131.9 | ||||||||||
Net income | 249.9 | 249.9 | |||||||||||||
Other comprehensive income | |||||||||||||||
Minimum pension liability | (2.9) | (2.9) | |||||||||||||
Hedging, net | 0.2 | 0.2 | |||||||||||||
Comprehensive income | - | - | 249.9 | (2.7) | 247.2 | ||||||||||
Cash dividends | |||||||||||||||
Common stock | (179.6) | (179.6) | |||||||||||||
Preferred stock | (1.2) | (1.2) | |||||||||||||
Tax benefit of exercised stock | |||||||||||||||
options allocated from Parent | 5.9 | 5.9 | |||||||||||||
Balance - December 31, 2004 | 332.9 | 538.3 | 1,339.9 | (6.9) | 2,204.2 | ||||||||||
Net income | 284.8 | 284.8 | |||||||||||||
Other comprehensive income | |||||||||||||||
Minimum pension liability | (1.4) | (1.4) | |||||||||||||
Hedging, net | (0.2) | (0.2) | |||||||||||||
Comprehensive Income | - | - | 284.8 | (1.6) | 283.2 | ||||||||||
Cash dividends | |||||||||||||||
Common stock | (179.6) | (179.6) | |||||||||||||
Preferred stock | (1.2) | (1.2) | |||||||||||||
Tax benefit of exercised stock | |||||||||||||||
options allocated from Parent | 4.3 | 4.3 | |||||||||||||
Balance - December 31, 2005 | $332.9 | $542.6 | $1,443.9 | ($8.5) | $2,310.9 | ||||||||||
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements. | |||||||||||||||
WISCONSIN ELECTRIC POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General: Wisconsin Electric Power Company (Wisconsin Electric, the Company, our, us or we), a wholly-owned subsidiary of Wisconsin Energy Corporation (Wisconsin Energy), is an electric, gas and steam utility which services electric customers in Wisconsin and the Upper Peninsula of Michigan, gas customers in Wisconsin and steam customers in metro Milwaukee, Wisconsin. We consolidate our wholly owned subsidiary Bostco LLC (Bostco). Bostco owns real estate properties that are eligible for historical rehabilitation tax credits. Bostco had total assets of $40.9 million as of December 31, 2005.
All significant intercompany transactions and balances have been eliminated from the consolidated financial statements.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Reclassifications: We have changed the presentation of the investments within our nuclear decommissioning trusts on the Consolidated Statements of Cash Flows for the three years ended December 31, 2005, to present proceeds from investments within the nuclear decommissioning trusts and purchases of investments within the nuclear decommissioning trusts. Previously these items were excluded from the Consolidated Statements of Cash Flows as the nuclear decommissioning trusts are restricted investments. This change had no impact to net cash provided by (used in) operating, investing or financing activities.
Revenues: We recognize energy revenues on the accrual basis and include estimated amounts for service rendered but not billed.
Our Wisconsin retail rates are established by the Public Service Commission of Wisconsin (PSCW) and include base amounts for fuel and purchase power costs. The Wisconsin electric fuel rules allow us to request rate increases if fuel and purchased power costs exceed bands established by the PSCW. In a rate order issued in January 2006, the PSCW approved a plan to refund any over-collected fuel on an annual basis for 2006. In 2006, any under-collection will be subject to a 2% band. For 2007, the band will be plus or minus 2%.
Our retail gas rates include monthly adjustments which permit the recovery or refund of actual purchased gas costs. We defer any difference between actual gas costs incurred (adjusted for a sharing mechanism) and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year.
Property and Depreciation: We record property, plant and equipment at cost. Cost includes material, labor, overheads and capitalized interest. Utility property also includes allowance for equity funds used during construction. Additions to and significant replacements of property are charged to property, plant and equipment at cost; minor items are charged to maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired. Upon retirement or sale of other property and equipment, we remove the cost and related accumulated depreciation from the accounts and include any gain or loss in Other Income and Deductions, Net in the Consolidated Income Statements.
We include capitalized software costs associated with our regulated operations under the caption "Property, Plant and Equipment" on the Consolidated Balance Sheets. As of December 31, 2005 and 2004, the net book value of our capitalized software totaled $21.8 million and $27.7 million, respectively. The estimated useful life of our capitalized software is five years.
Our utility depreciation rates are certified by the state regulatory commissions and include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 3.9% in 2005, 4.0% in
For other assets and leased equipment, we accrue depreciation expense at straight-line rates over the estimated useful lives of the assets, or over the non-cancellable lease term for leased equipment.
We collect in our rates future removal costs for many assets that do not have an associated asset retirement obligation. We record a regulatory liability on our balance sheet for the estimated amounts we have collected in rates for future removal costs less amounts we have spent in removal activities. This regulatory liability was $414.1 million as of December 31, 2005 and $419.1 million as of December 31, 2004.
Allowance For Funds Used During Construction: Allowance for funds used during construction (AFUDC) is included in utility plant accounts and represents the cost of borrowed funds (AFUDC - debt) used during plant construction and a return on stockholders' capital (AFUDC - equity) used for construction purposes. AFUDC - debt is recorded as a reduction of interest expense and AFUDC - equity is recorded in Other Income and Deductions, Net.
As approved by the PSCW, we capitalized AFUDC - debt and equity at 10.18% during the periods reported.
In a rate order dated August 30, 2000, the PSCW authorized us to accrue AFUDC on all electric utility nitrogen oxide (NOx) remediation construction work in progress at a rate of 10.18%, and provided a full current return on electric safety and reliability construction work in progress so that no AFUDC accrual is required on these projects. In addition, the August 2000 PSCW order provided a current return on half of other utility construction work in progress and authorized AFUDC accruals on the remaining 50% of these projects.
We recorded the following AFUDC for the years ended December 31:
2005 | 2004 | 2003 | ||||
(Millions of Dollars) | ||||||
AFUDC - Debt | $4.6 | $0.9 | $1.2 | |||
AFUDC - Equity | $9.2 | $1.7 | $2.4 | |||
Materials, Supplies and Inventories: Our inventory at December 31 consisted of:
Materials, Supplies and Inventories | 2005 | 2004 | ||
(Millions of Dollars) | ||||
Natural Gas in Storage | $117.8 | $102.9 | ||
Fossil Fuel | 90.4 | 86.3 | ||
Materials and Supplies | 89.3 | 84.6 | ||
Total | $297.5 | $273.8 | ||
We price substantially all fossil fuel, materials and supplies and natural gas in storage inventories using the weighted-average method of accounting.
Regulatory Accounting: We account for our regulated operations in accordance with Statement of Financial Accounting Standards (SFAS) 71, Accounting for the Effects of Certain Types of Regulation. This statement sets forth the application of generally accepted accounting principles to those companies whose rates are determined by an independent third-party regulator. The economic effects of regulation can result in regulated companies recording costs that have been or are expected to be allowed in the rate making process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses in the periods when those same amounts are reflected in rates. We defer all of our regulatory assets pursuant to specific orders or by a generic order
Derivative Financial Instruments: We have derivative physical and financial instruments as defined by SFAS 133, Accounting for Derivative Instruments and Hedging Activities. However, our use of financial instruments is limited. For further information, see Note J.
Cash and Cash Equivalents: Cash and cash equivalents include marketable debt securities acquired three months or less from maturity.
We have nuclear decommissioning trusts that hold investments in debt and equity securities. All assets within the nuclear decommissioning trusts are restricted to nuclear decommissioning activities as set forth by regulations promulgated by the Internal Revenue Service (IRS) and by the PSCW. The accompanying Consolidated Statements of Cash Flows include proceeds from investments within the nuclear decommissioning trusts and purchases of investments within the nuclear decommissioning trusts.
Restrictions: Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. In addition, under Wisconsin law, we are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy. We do not believe that these restrictions will materially affect our operations. For further information, see Note N.
Asset Retirement Obligations We adopted SFAS 143, Accounting for Asset Retirement Obligations, effective January 1, 2003. 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 143. FIN 47 defines the term conditional asset retirement obligation as used in Statement 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 adopted FIN 47 effective December 31, 2005. Consistent with SFAS 143, we record a liability at fair value for a legal asset retirement obligation in the period in which it is incurred. When a new legal obligation is recorded, we capitalize the cos ts of the liability by increasing the carrying amount of the related long-lived asset. We accrete the liability to its present value each period and depreciate the capitalized cost over the useful life of the related asset. At the end of the asset's useful life, we settle the obligation for its recorded amount or incur a gain or loss. As it relates to our regulated operations, we apply SFAS 71 and recognize regulatory assets or liabilities for the timing differences between when we recover legal asset retirement obligations in rates and when we would recognize these costs under SFAS 143. For further information see Note I.
Investments: We consolidate investments in affiliated companies in which we have a controlling financial interest. We account for investments in other affiliated companies in which we do not maintain control using the equity method. As of December 31, 2005 and 2004, we had a total ownership interest of approximately 29.4% and 33.2%, respectively, in American Transmission Company LLC (ATC). We are represented by one out of ten ATC board members, each of whom has one vote. Due to the voting requirements, no individual member has more than 10% of the voting control. We account for our investment in ATC under the equity method. For more information on ATC, see Note P.
Nuclear Fuel Amortization: We lease our nuclear fuel and amortize the fuel inventory to fuel expense as the power is generated, generally over a period of 60 months.
Income Taxes: We follow the liability method in accounting for income taxes as prescribed by SFAS 109, Accounting for Income Taxes (SFAS 109). SFAS 109 requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We assess the likelihood that our deferred tax assets would expire before being realized.
We are included in Wisconsin Energy's consolidated Federal income tax return. Wisconsin Energy allocates Federal tax expense or credits to us based on our separate tax computation.
Investment tax credits related to regulated utility assets are recorded as a deferred credit on the balance sheet and amortized to income over the applicable service lives of related properties in accordance with regulatory treatment. Historical rehabilitation credits are reported in income in the year claimed.
Wisconsin Energy allocates the tax benefit of stock options exercised to us to the extent the option holder's payroll cost was incurred by us. We record the allocated tax benefit as an addition to paid in capital.
Stock Options: Employees of Wisconsin Electric participate in the Wisconsin Energy 1993 Omnibus Stock Incentive Plan, as amended (OSIP), as approved by Wisconsin Energy stockholders. The amounts reported represent the allocated costs related to options held by our employees. For more information on the OSIP, see Note N.
Prior to 2006, Wisconsin Energy accounted for stock-based compensation using the intrinsic value method provided by Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees, and related interpretations under which no compensation cost has been recognized for stock option grants. Effective January 1, 2006, we adopted SFAS 123R, Share-Based Payment (Revised). See Note B for further discussion of this new standard and the impacts to our consolidated financial statements.
Wisconsin Energy previously adopted the disclosure provisions of SFAS 123, Accounting for Stock-Based Compensation, as amended by SFAS 148, Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of SFAS 123. The fair value of each Wisconsin Energy option at date of grant was estimated using the Black-Scholes option-pricing model with the following weighted average assumptions:
2005 | 2004 | 2003 | ||||
Risk free interest rate | 4.4% | 4.6% | 4.5% | |||
Dividend yield | 2.5% | 2.5% | 3.1% | |||
Expected volatility | 19.00% | 23.10% | 25.73% | |||
Expected life (years) | 10 | 10 | 10 | |||
Pro forma weighted average fair | ||||||
value of our stock options granted | $8.32 | $9.45 �� | $7.04 |
As described more fully in the following table, had compensation cost for the Wisconsin Energy stock options granted to our employees after January 1, 1999 been determined consistent with SFAS 123, our net income would have been reduced to the pro forma amounts set forth in the table below. In 2004, the pro forma expense increased, in part, due to the effect of accelerating the vesting of Wisconsin Energy stock options held by our employees. For further information regarding equity based compensation see Note B and Note N.
2005 | 2004 | 2003 | ||||
(Millions of Dollars) | ||||||
Net Income - as reported | $283.6 | $248.7 | $255.5 | |||
Add: Stock-based employee |
|
|
| |||
Deduct: Total stock-based employee |
|
|
| |||
Net Income - Pro forma | $282.3 | $230.5 | $251.3 | |||
B -- RECENT ACCOUNTING PRONOUNCEMENTS
Conditional Asset Retirement Obligations: In March 2005, the FASB issued Interpretation 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), an interpretation of FASB Statement 143. We adopted FIN 47 effective December 31, 2005. For further information see Note I.
Implicit Variable Interests: We adopted FASB Staff Position FIN 46R - 5, Implicit Variable Interests under FASB Interpretation 46 (revised December 2003), in the second quarter of 2005. This statement requires that holdings of implicit variable interests are evaluated when applying Interpretation 46R. See Note D for further information.
Share Based Compensation: In December 2004, the FASB issued SFAS 123 (revised 2004), Share-Based Payment (SFAS 123R), which is a revision of SFAS 123. SFAS 123R supersedes APB Opinion 25, and amends SFAS 95, Statement of Cash Flows. Generally, the approach in SFAS 123R is similar to the approach described in SFAS 123. However, SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative under the new standard.
We adopted SFAS 123R effective January 1, 2006 using the modified prospective method. We will use the binomial pricing model to estimate the fair value of stock options granted subsequent to December 31, 2005. We estimate that our 2006 earnings will reflect stock option expense of $2.7 million after-tax. Prior to 2006 and the adoption of SFAS 123R, we presented all tax benefits resulting from the exercise of stock options as operating cash flows in the Consolidated Statement of Cash Flows. SFAS 123R requires that cash flows resulting from tax deductions in excess of the cumulative compensation cost recognized for options exercised be classified as financing cash flows.
C -- REGULATORY ASSETS AND LIABILITIES
We account for our regulated operations in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation.
Our primary regulator considers our regulatory assets and liabilities in two categories, escrowed and deferred. In escrow accounting we expense amounts that are included in rates. If actual costs exceed, or are less than the amounts that are allowed in rates, the difference in cost is escrowed on the balance sheet as a regulatory asset or regulatory liability and the escrowed balance is considered in setting future rates. Under deferred cost accounting, we defer amounts to our balance sheet based upon specific orders or correspondence with our primary regulator. These deferred costs will be considered in future rate setting proceedings. As of December 31, 2005, we had approximately $32.7 million of net regulatory assets that were not earning a return.
Our regulatory assets and liabilities at December 31 consist of:
2005 | 2004 | |||
(Millions of Dollars) | ||||
Regulatory Assets | ||||
Deferred unrecognized pension costs (See Note L) | $240.7 | $202.5 | ||
Escrowed electric transmission costs | 169.4 | 109.6 | ||
Deferred income tax related | 93.5 | 96.4 | ||
Deferred fuel related costs | 72.8 | - | ||
Deferred plant related -- capital leases (See Note G) | 67.0 | 61.1 | ||
Escrowed unrecovered plant costs | 56.5 | 45.9 | ||
Deferred environmental costs | 43.9 | 45.5 | ||
Escrowed bad debt costs | 32.5 | 22.7 | ||
Other, net | 46.2 | 61.0 | ||
Total long-term regulatory assets | $822.5 | $644.7 | ||
Regulatory Liabilities | ||||
Deferred asset retirement obligations (See Notes F and I) | $475.3 | $20.1 | ||
Deferred cost of removal obligations (See Notes F and I) | 414.1 | 419.1 | ||
Deferred income tax related | 91.6 | 96.8 | ||
Other, net | 70.9 | 64.2 | ||
Total long-term regulatory liabilities | $1,051.9 | $600.2 | ||
Net long-term regulatory liabilities (assets) | $229.4 | ($44.5) | ||
We record a minimum pension liability to reflect the funded status of our pension plans (see Note L). We have concluded that substantially all of the unrecognized pension costs resulting from the recognition of our minimum pension liability that relate to our utility operations qualify as a regulatory asset.
We record deferred regulatory assets and liabilities representing the future expected impact of deferred taxes on utility revenues (see Note A).
Consistent with a generic order from and past rate-making practices of the PSCW, we defer as a regulatory asset costs associated with the remediation of former manufactured gas plant sites. As of December 31, 2005, we have recorded $43.9 million of environmental costs associated with manufactured gas plant sites as a regulatory asset, including $30.0 million of deferrals for actual remediation costs incurred and a $13.9 million accrual for estimated future site remediation (See Note Q). In addition, we have deferred $6.0 million of insurance recoveries associated with the environmental costs as regulatory liabilities. We included total actual remediation costs incurred net of the related insurance recoveries in our 2006 rate case. We began amortizing these costs upon receiving PSCW approval. These costs will be amortized over the next five years.
As part of Wisconsin Energy'sPower the Future initiative, the PSCW approved the retirement and removal of the Port Washington Power Plant coal units to make way for construction of gas-fired facilities. In a September 27, 2003 order, the PSCW authorized transferring the undepreciated costs and related removal amounts to a regulatory asset account. The escrowed unrecovered plant costs totaled $56.5 million at December 31, 2005.
As of December 31, 2005, we have deferred $72.8 million of fuel related costs. The costs resulted from an extended outage at our nuclear plant, increased costs associated with reduced coal deliveries due to a railroad transportation problem and increased costs associated with the Midwest Independent Transmission System Operator, Inc. (MISO) bid-based energy market (MISO Midwest Market).
D -- VARIABLE INTEREST ENTITIES
In January 2003, the FASB issued Interpretation 46, Consolidation of Variable Interest Entities (FIN 46). This standard requires an enterprise that is the primary beneficiary of a variable interest entity to consolidate that entity. We applied the Interpretation to any existing interests in variable interest entities beginning in the third quarter of
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 $667.5 million of required payments over the remaining term of these three agreements, which expire over the next 17 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.
E -- INCOME TAXES
The following table is a summary of income tax expense for each of the years ended December 31:
Income Tax Expense | 2005 | 2004 | 2003 | |||
(Millions of Dollars) | ||||||
Current tax expense | $145.6 | $16.4 | $156.6 | |||
Deferred income taxes, net | 24.1 | 141.2 | 2.8 | |||
Investment tax credit, net | (4.2) | (4.4) | (4.5) | |||
Total Income Tax Expense | $165.5 | $153.2 | $154.9 | |||
The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable U.S. statutory federal income tax rate to income before income taxes and preferred dividend as a result of the following:
2005 | 2004 | 2003 | ||||||||||
|
| Effective |
| Effective |
| Effective | ||||||
(Millions of Dollars) | ||||||||||||
Expected tax at | ||||||||||||
statutory federal tax rates | $157.2 | 35.0% | $141.1 | 35.0% | $144.1 | 35.0% | ||||||
State income taxes | ||||||||||||
net of federal tax benefit | 20.9 | 4.7% | 19.0 | 4.7% | 19.3 | 4.7% | ||||||
Investment tax credit restored | (4.2) | (0.9%) | (4.4) | (1.1%) | (4.5) | (1.1%) | ||||||
Other, net | (8.4) | (1.9%) | (2.5) | (0.6%) | (4.0) | (1.0%) | ||||||
Total Income Tax Expense | $165.5 | 36.9% | $153.2 | 38.0% | $154.9 | 37.6% | ||||||
The components of SFAS 109 deferred income taxes classified as net current assets and net long-term liabilities at December 31 are as follows:
2005 | 2004 | ||||
(Millions of Dollars) | |||||
Deferred Tax Assets | |||||
Current | |||||
Employee benefits and compensation | $10.2 | $10.5 | |||
Recoverable gas costs | 1.3 | 0.8 | |||
Other | 5.7 | 12.4 | |||
Total Current Deferred Tax Assets | $17.2 | $23.7 | |||
Non-current | |||||
Employee benefits and compensation | 99.7 | 62.4 | |||
Decommissioning trust | 85.8 | 74.5 | |||
Construction advances | 71.6 | 80.1 | |||
Deferred revenues | 28.3 | - | |||
Emission allowances | 18.4 | - | |||
Property-related | 7.2 | 7.2 | |||
Other | 15.2 | 19.8 | |||
Total Non-current Deferred Tax Assets | 326.2 | 244.0 | |||
Total Deferred Tax Assets | $343.4 | $267.7 | |||
Deferred Tax Liabilities | |||||
Current | |||||
Prepaid items | $32.3 | $26.5 | |||
Uncollectible account expense | 7.3 | 3.9 | |||
Total Current Deferred Tax Liabilities | $39.6 | $30.4 | |||
Non-current | |||||
Property-related | 746.3 | 693.2 | |||
Deferred transmission costs | 64.6 | 40.5 | |||
Investment in transmission affiliate | 35.4 | 35.9 | |||
Other | 33.1 | 22.9 | |||
Total Non-current Deferred Tax Liabilities | 879.4 | 792.5 | |||
Total Deferred Tax Liabilities | $919.0 | $822.9 | |||
Consolidated Balance Sheet Presentation | 2005 | 2004 | |||
Current Deferred Tax Asset (Liability) | ($22.4) | ($6.7) | |||
Non-current Deferred Tax Asset (Liability) | ($553.2) | ($548.5) | |||
F -- NUCLEAR OPERATIONS
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 (NMC). In February 2004, we and NMC filed an application with the United States Nuclear Regulatory Commission (NRC) to renew the operating license for both Units for an additional 20 years. The NRC approved the license renewal request in December 2005. The new operating licenses expire in October 2030 for Unit 1 and March 2033 for Unit 2. The previous operating licenses expired in October 2010 for Unit 1 and in March 2013 for Unit 2.
Nuclear Insurance: The Price-Anderson Act currently limits the total public liability for damages arising from a nuclear incident at a nuclear power plant to approximately $10.8 billion, of which $300 million is covered by liability insurance purchased from private sources. The remaining $10.5 billion is covered by an industry
Through our membership in Nuclear Electric Insurance Limited (NEIL), we carry decontamination, property damage and decommissioning shortfall insurance covering losses of up to $2.1 billion at Point Beach. Under policies issued by NEIL, the insured member may be liable for a retrospective premium in the event of catastrophic losses exceeding the full financial resources of NEIL. Our maximum retrospective liability under the above policies is $17.9 million.
We also maintain insurance with NEIL through which we can recover up to $3.5 million per week, subject to a total limit of $490 million, during any prolonged outage at Point Beach caused by accidental property damage. Our maximum retrospective liability under this policy is $9.9 million.
It should not be assumed that, in the event of a major nuclear incident, any insurance or statutory limitation of liability would protect us from material adverse impact.
Nuclear Decommissioning: We record decommissioning expense in amounts equal to the amounts collected in rates and funded to the external trusts. Nuclear decommissioning costs are accrued over the expected service lives of the nuclear generating units and are included in electric rates. Decommissioning funding was $17.6 million for each of the years ended 2005, 2004 and 2003. As of December 31, 2005 and 2004, we had the following investments in Nuclear Decommissioning Trusts, stated at fair value.
2005 | 2004 | |||
(Millions of Dollars) | ||||
Funding and Realized Earnings | $566.6 | $529.1 | ||
Unrealized Gains | 215.5 | 208.7 | ||
Total Investments | $782.1 | $737.8 | ||
As of December 31, 2005 approximately 66% of the trusts were invested in equity securities and 34% were invested in debt securities. In accordance with SFAS 115, Accounting for Certain Investments in Debt and Equity Securities, our debt and equity security investments in the Nuclear Decommissioning Trust Fund are classified as available for sale. Gains and losses on the fund are determined on the basis of specific identification; net unrealized gains on the fund are recorded as part of the fund. We fair value our investment in the Nuclear Decommissioning Trust Fund and we are allowed regulatory treatment for the fair value adjustment. Realized gains and losses for the years ended December 31, 2005 and 2004 were as follows:
2005 | 2004 | |||
(Millions of Dollars) | ||||
Realized Gains | $19.1 | $25.5 | ||
Realized Losses | 9.1 | 6.1 | ||
Net Realized Gain | $10.0 | $19.4 | ||
The PSCW requires us to perform periodic Decommissioning Cost Studies to evaluate the funded status of our Nuclear Decommissioning Trusts as compared with the estimated costs to perform the decommissioning work. In June 2005, we filed a new Decommissioning Cost Study with the PSCW. The study was performed by an outside consultant and it included several assumptions as to the timing and scope of the decommissioning work. This study estimated that the cost to decommission the plant would be $712.5 million in 2004 dollars. A prior study had estimated the costs to be $1.1 billion in 2003 dollars. The reduction in the estimated costs to decommission the plant was driven by several factors including the timing and the scope of the work to be performed.
The June 2005 Decommissioning Cost Study was also used to estimate our Asset Retirement Obligation (ARO) for nuclear decommissioning. We record an ARO for future decommissioning costs based upon the net present value of the expected cash flows associated with our legal obligation to decommission our plants. Under SFAS 143, certain
We recover decommissioning costs in our regulated rates. We have established a regulatory liability to reflect the difference between nuclear decommissioning costs recovered in rates and cumulative investment gains (our nuclear trust investments) in comparison to the ARO for nuclear decommissioning that is calculated under SFAS 143. As of December 31, 2005, we have increased our nuclear decommissioning regulatory liability by $439.7 million in comparison to the liability at December 31, 2004, to reflect the reduction of the ARO for nuclear decommissioning as described above. For further information on ARO's see Note I.
The ultimate timing and amount of future cash flows associated with nuclear decommissioning is dependent upon many significant variables including the scope of work involved, the ability to relicense the plants in the future, future inflation rates and discount rates. However, based on the license renewal received by the NRC in December 2005, we do not expect to make any significant nuclear decommissioning expenditures before the year 2030.
Decontamination and Decommissioning Fund: The Energy Policy Act of 1992 established a Uranium Enrichment Decontamination and Decommissioning Fund (D&D Fund) for the United States Department of Energy's nuclear fuel enrichment facilities. Deposits to the D&D Fund are derived in part from special assessments on utilities using enrichment services. As of December 31, 2005, we recorded our remaining estimated liability equal to projected special assessments of $3.7 million. The deferred regulatory asset will be amortized to nuclear fuel expense and included in utility rates over the next two years ending in 2007.
G -- LONG-TERM DEBT
Debentures and Notes: As of December 31, 2005, the maturities and sinking fund requirements of our long-term debt outstanding (excluding obligations under capital leases) were as follows:
(Millions of Dollars) | ||
2006 | $202.9 | |
2007 | 250.0 | |
2008 | - | |
2009 | - | |
2010 | - | |
Thereafter | 1,052.6 | |
Total | $1,505.5 | |
We amortize debt premiums, discounts and debt issuance costs over the lives of the debt and we include the costs in interest expense.
In August 2004, we retired $140 million of 7-1/4% First Mortgage Bonds at their scheduled maturity. We financed this retirement through the issuance of short-term commercial paper.
In November 2004, we sold $250 million of unsecured 3.50% Debentures due December 1, 2007. The securities were issued under an existing $665 million shelf registration statement filed with the Securities and Exchange Commission (SEC). The proceeds from the sale were used to repay our outstanding commercial paper.
In December 2004, we refinanced $147 million of the $165 million aggregate principal amount of unsecured variable rate putable weekly reset tax-exempt debt with new "auction" non-putable unsecured variable rate weekly reset tax-exempt debt.
Obligations under Capital Leases: In 1997, we entered into a 25 year power purchase contract with an unaffiliated independent power producer. The contract, for 236 megawatts of firm capacity from a gas-fired cogeneration facility, includes no minimum energy requirements. When the contract expires in 2022, we may, at our option and with proper notice, renew for another ten years or purchase the generating facility at fair value or allow the contract to expire. We account for this contract as a capital lease and recorded the leased facility and corresponding obligation under the capital lease at the estimated fair value of the plant's electric generating facilities. We are amortizing the leased facility on a straight-line basis over the original 25-year term of the contract.
We treat the long-term power purchase contract as an operating lease for rate-making purposes and we record our minimum lease payments as purchased power expense on the Consolidated Income Statements.We paid a total of $25.2 million, $24.3 million and $23.4 million in minimum lease payments during 2005, 2004, and 2003, respectively. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on our Consolidated Balance Sheets (see regulatory assets - deferred plant related - capital lease in Note C). Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $78.5 million by the year 2009 at which time the regulatory asset will be reduced to zero over the remaining life of the contract. The total obligation under the capital lease increa sed to $160.2 million at December 31, 2005 and will now be reduced to zero over the remaining life of the contract.
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 We Power under a PSCW approved lease. Pursuant to SFAS 13, Accounting for Leases, we are accounting for this lease as a capital lease and have recorded the leased plant and corresponding obligation under the capital lease at the estimated fair value of $335.5 million. We are amortizing the leased plant on a straight-line basis over the original 25-year term of the lease.
This lease is treated as an operating lease for rate-making purposes. We record the lease payments as rent expense in other operation and maintenance in the Consolidated Income Statement. The lease payments are expected to be recovered through our rates. The recoverability of the lease payments is supported by the 2001 lease generation law. The annual lease payments are approximately $47.8 million. We paid a total of $21.9 million in minimum lease payments during 2005. 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. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $125.1 million in the year 2021 at which time the regulatory asset will be reduced to zero over the remaining life of the contract. The total obligation under the capital lease was $334.7 million at De cember 31, 2005 and will decrease to zero over the remaining life of the contract.
We also have a nuclear fuel leasing arrangement with Wisconsin Electric Fuel Trust (Trust) which is treated as a capital lease. We lease and amortize the nuclear fuel to fuel expense as power is generated, generally over a period of 60 months. Lease payments include charges for the cost of fuel burned, financing costs and management fees. In the event that we or the Trust terminates the lease, the Trust would recover its unamortized cost of nuclear fuel from us. Under the lease terms, we are in effect the ultimate guarantor of the Trust's commercial paper and line of credit borrowings that finance the investment in nuclear fuel. We recorded $1.7 million of interest expense on the nuclear fuel lease in fuel expense during 2005, and $1.4 million during 2004 and 2003.
Following is a summary of our capitalized leased facilities and nuclear fuel at December 31.
Capital Lease Assets | 2005 | 2004 | ||
(Millions of Dollars) | ||||
Leased Facilities | ||||
Long-term purchase power commitment | $140.3 | $140.3 | ||
Accumulated amortization | (47.1) | (41.4) | ||
Total Leased Facilities | $93.2 | $98.9 | ||
PWGS Unit 1 | ||||
Under Capital Lease | $335.5 | - | ||
Accumulated amortization | (6.1) | - | ||
Total PWGS Unit 1 | $329.4 | - | ||
Nuclear Fuel | ||||
Under capital lease | $125.6 | $120.2 | ||
Accumulated amortization | (60.2) | (74.0) | ||
In process/stock | 46.6 | 38.8 | ||
Total Nuclear Fuel | $112.0 | $85.0 | ||
Future minimum lease payments under our capital leases and the present value of our net minimum lease payments as of December 31, 2005 are as follows:
| Purchase |
| Nuclear |
| ||||
(Millions of Dollars) | ||||||||
2006 | $31.2 | $47.8 | $29.1 | 108.1 | ||||
2007 | 32.4 | 47.8 | 20.8 | 101.0 | ||||
2008 | 33.6 | 47.8 | 16.0 | 97.4 | ||||
2009 | 34.9 | 47.8 | 7.6 | 90.3 | ||||
2010 | 36.2 | 47.8 | 3.0 | 87.0 | ||||
Thereafter | 332.8 | 934.3 | - | 1,267.1 | ||||
Total Minimum Lease Payments | 501.1 | 1,173.3 | 76.5 | 1,750.9 | ||||
Less: Estimated Executory Costs | (108.9) | - | - | (108.9) | ||||
Net Minimum Lease Payments | 392.2 | 1,173.3 | 76.5 | 1,642.0 | ||||
Less: Interest | (232.0) | (838.6) | (5.9) | (1,076.5) | ||||
Present Value of Net | ||||||||
Minimum Lease Payments | 160.2 | 334.7 | 70.6 | 565.5 | ||||
Less: Due Currently | (0.8) | (1.7) | (27.0) | (29.5) | ||||
$159.4 | $333.0 | $43.6 | $536.0 | |||||
H -- SHORT-TERM DEBT
Short-term notes payable balances and their corresponding weighted-average interest rates as of December 31 consist of:
2005 | 2004 | |||||||
|
| Interest |
| Interest | ||||
(Millions of Dollars) | ||||||||
Commercial paper | $322.2 | 4.39% | $156.7 | 2.35% | ||||
Other | 30.5 | 6.66% | 32.8 | 6.52% | ||||
Total Short-Term Debt | $352.7 | 4.59% | $189.5 | 3.07% | ||||
On December 31, 2005, we had $368.0 million of available unused lines of bank back-up credit facilities on a consolidated basis. We had $352.7 million of total consolidated short-term debt outstanding on such date. Our bank back-up credit facilities mature beginning June 2007 through November 2007.
The following information relates to Commercial paper outstanding for the years ended December 31, 2005 and 2004:
2005 | 2004 | |||
(Millions of Dollars, except for percentages) | ||||
Maximum Short-Term Debt Outstanding | $324.9 | $280.9 | ||
Average Short-Term Debt Outstanding | $117.8 | $155.5 | ||
Weighted Average Interest Rate | 3.26% | 1.43% | ||
We have entered into various bank back-up credit agreements to maintain short-term credit liquidity which, among other terms, require us to maintain a minimum total funded debt to capitalization ratio of less than 65%.
Our bank back-up credit agreements contain customary covenants, including certain limitations on our ability to sell assets. The credit agreements also contain customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, ERISA defaults and change of control.
At December 31, 2005, we were in compliance with all covenants.
I -- ASSET RETIREMENT OBLIGATIONS
We follow SFAS 143, Accounting for Asset Retirement Obligations (SFAS 143) and Accounting for Conditional Asset Retirement Obligations (FIN 47).
The following table presents the change in our asset retirement obligations during 2005.
Balance at | Initial | Liabilities | Liabilities |
| Cash Flow | Balance at | |
(Millions of Dollars) | |||||||
Asset Retirement Obligations |
|
|
|
|
|
|
|
(a) | Increase in asset retirement obligation for the initial adoption of FIN 47 |
SFAS 143 primarily applies to the future decommissioning costs for our Point Beach Nuclear Plant (Point Beach). Prior to January 2003, we recorded a long-term liability for accrued nuclear decommissioning costs. In 2005, due to an updated Nuclear Decommissioning Cost Study and approval of our application for license renewal, we adjusted the long-term liability accrued for nuclear decommissioning costs. See Note F for further information about the nuclear decommissioning of Point Beach including our investments in Nuclear Decommissioning Trusts that are restricted to nuclear decommissioning.
In March 2005, the FASB issued FIN 47, an interpretation of FASB Statement 143. FIN 47 defines a conditional asset retirement obligation as 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 adopted FIN 47 effective December 31, 2005. At adoption, we recorded additional asset retirement obligations of $38.4 million, of which $37.4 million related to asbestos removal costs.
The adoption of FIN 47 had no impact on our net income in 2005. As it relates to our regulated operations, we apply SFAS 71 and recognize regulatory assets or liabilities for the timing differences between when we recover legal asset retirement obligations in rates and when we would recognize these costs under FIN 47. This treatment is consistent with the adoption of SFAS 143 for our regulated operations.
If we had adopted interpretation FIN 47 at the beginning of fiscal 2004, we would have reported the following asset retirement obligations on our Consolidated Balance Sheets in "Asset Retirement Obligations" as of December 31:
Asset Retirement Obligations | 2005 | 2004 | ||
(Millions of Dollars) | ||||
Reported (b) | $354.9 | $762.2 | ||
Pro forma | $354.9 | $798.4 | ||
(b) | The 2004 reported balance represents the liability recorded under SFAS 143, which is primarily related to nuclear decommissioning costs |
J -- DERIVATIVE INSTRUMENTS
We follow SFAS 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, effective July 1, 2003, which requires that every derivative instrument be recorded on the balance sheet as an asset or liability measured at its fair value and that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. For most of our energy-related physical and financial contracts 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.
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. 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 are reported in earnings.
For the years ended December 31, 2005 and 2004, the amount of hedge ineffectiveness was immaterial. We did not exclude any components of derivative gains or losses from the assessment of hedge effectiveness.
K -- FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amount and estimated fair value of certain of our recorded financial instruments at December 31 are as follows:
2005 | 2004 | |||||||
| Carrying | Fair | Carrying | Fair | ||||
(Millions of Dollars) | ||||||||
Nuclear decommissioning trust fund | $782.1 | $782.1 | $737.8 | $737.8 | ||||
Preferred stock, no redemption required | $30.4 | $22.6 | $30.4 | $22.7 | ||||
Long-term debt including | ||||||||
current portion | $1,505.5 | $1,526.1 | $1,507.5 | $1,546.4 | ||||
The carrying value of cash and cash equivalents, net accounts receivable, accounts payable and short-term borrowings approximates fair value due to the short-term nature of these instruments. The nuclear decommissioning trust fund is carried at fair value as reported by the trustee (see Note F). The fair value of our preferred stock is estimated based upon the quoted market value for the same or similar issues. The fair value of our long-term debt, including the current portion of long-term debt but excluding capitalized leases, is estimated based upon quoted market value for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows. The fair values of gas commodity instruments are equal to their carrying values as of December 31, 2005.
L -- BENEFITS
Pensions and Other Post-retirement Benefits: We participate in Wisconsin Energy funded and unfunded noncontributory defined benefit pension plans that together cover substantially all of our employees. The plans provide defined benefits based upon years of service and final average salary.
We also have other post-retirement benefit plans covering substantially all of our employees. The health care plans are contributory with participants' contributions adjusted annually; the life insurance plans are noncontributory. The accounting for the health care plans anticipates future cost-sharing changes to the written plans that are consistent with our expressed intent to maintain the current cost sharing levels. The post-retirement health care plans include a limit on our share of costs for recent and future retirees. We use a year end measurement date for all of our pension and other post-retirement benefit plans.
Wisconsin Energy allocates the service cost component of pension costs to participating companies based on labor dollars. The assets, obligations and the components of SFAS 87 pension costs other than service cost (including the minimum pension liability) are allocated by Wisconsin Energy's actuary to each of the participating companies as if each participating company had its own plan. The disclosures below are based on an allocation to us of the amounts for Wisconsin Energy's benefit plans.
| Other | |||||||
Status of Benefit Plans | 2005 | 2004 | 2005 | 2004 | ||||
(Millions of Dollars) | ||||||||
Change in Benefit Obligation | ||||||||
Benefit Obligation at January 1 | $1,019.5 | $932.5 | $313.1 | $289.3 | ||||
Service cost | 30.0 | 26.9 | 13.0 | 11.4 | ||||
Interest cost | 59.4 | 58.4 | 16.8 | 17.1 | ||||
Plan amendments | 2.8 | 2.0 | (76.0) | - | ||||
Actuarial loss | 77.3 | 90.4 | 6.6 | 5.6 | ||||
Benefits paid | (79.9) | (90.7) | (11.9) | (10.3) | ||||
Benefit Obligation at December 31 | $1,109.1 | $1,019.5 | $261.6 | $313.1 | ||||
Change in Plan Assets | ||||||||
Fair Value at January 1 | $748.0 | $695.2 | $107.4 | $95.7 | ||||
Actual earnings on plan assets | 48.6 | 71.1 | 3.5 | 6.3 | ||||
Employer contributions | 2.9 | 72.4 | 9.1 | 15.7 | ||||
Benefits paid | (79.9) | (90.7) | (11.9) | (10.3) | ||||
Fair Value at December 31 | $719.6 | $748.0 | $108.1 | $107.4 | ||||
Funded Status of Plans | ||||||||
Funded status at December 31 | ($389.5) | ($271.5) | ($153.5) | ($205.7) | ||||
Unrecognized | ||||||||
Net actuarial loss | 297.5 | 222.3 | 102.3 | 96.3 | ||||
Prior service cost | 31.4 | 33.8 | (63.9) | 0.2 | ||||
Net transition (asset) obligation | - | (0.1) | 2.4 | 12.2 | ||||
Net Asset (Accrued Benefit Cost) | ($60.6) | ($15.5) | ($112.7) | ($97.0) | ||||
Amounts recognized in the Balance Sheet consist of: | ||||||||
Regulatory assets (See Note C) | $240.7 | $202.5 | $ - | $ - | ||||
Other deferred charges | 31.6 | 33.6 | 0.1 | 0.1 | ||||
Minimum pension liability | (347.2) | (248.0) | - | - | ||||
Other long-term liabilities | - | (15.5) | (112.8) | (97.1) | ||||
Other comprehensive income | 14.3 | 11.9 | - | - | ||||
Net amount recognized at end of year | ($60.6) | ($15.5) | ($112.7) | ($97.0) | ||||
The accumulated benefit obligation for all of our defined benefit plans was $1,067.2 million and $1,010.3 million at December 31, 2005 and 2004, respectively.
Information for pension plans with an accumulated benefit obligation in excess of the fair value of assets is as follows:
2005 | 2004 | ||||
(Millions of Dollars) | |||||
Projected benefit obligation | $1,109.1 | $1,003.6 | |||
Accumulated benefit obligation | $1,067.2 | $995.9 | |||
Fair value of plan assets | $719.6 | $748.0 | |||
The components of net periodic pension and other post-retirement benefit costs are:
| Other Post-retirement | |||||||||||
Benefit Plan Cost Components | 2005 | 2004 | 2003 | 2005 | 2004 | 2003 | ||||||
(Millions of Dollars) | ||||||||||||
Net Periodic Benefit Cost | ||||||||||||
Service cost | $30.0 | $26.9 | $27.2 | $13.0 | $11.4 | $10.3 | ||||||
Interest cost | 59.4 | 58.4 | 56.9 | 16.8 | 17.1 | 17.6 | ||||||
Expected return on plan assets | (64.4) | (62.6) | (64.0) | (8.9) | (7.9) | (6.5) | ||||||
Amortization of: | ||||||||||||
Transition (asset) obligation | (0.1) | (2.2) | (2.2) | 1.2 | 1.5 | 1.5 | ||||||
Prior service cost | 5.2 | 4.8 | 4.8 | (3.3) | - | - | ||||||
Actuarial loss | 17.9 | 13.2 | 3.0 | 6.0 | 5.1 | 6.6 | ||||||
Net Periodic Benefit Cost | $48.0 | $38.5 | $25.7 | $24.8 | $27.2 | $29.5 | ||||||
Weighted-Average assumptions used to | ||||||||||||
determine benefit obligations at Dec 31 | ||||||||||||
Discount rate | 5.50% | 5.75% | 6.25% | 5.50% | 5.75% | 6.25% | ||||||
Rate of compensation increase | 4.5 to | 4.5 to | 4.5 to | 4.5 to | 4.5 to | 4.5 to | ||||||
5.0 | 5.0 | 5.0 | 5.0 | 5.0 | 5.0 | |||||||
Weighted-Average assumptions used to | ||||||||||||
determine net cost for year ended Dec 31 | ||||||||||||
Discount rate | 5.75% | 6.25% | 6.75% | 5.75% | 6.25% | 6.75% | ||||||
Expected return on plan assets | 9.0 | 9.0 | 9.0 | 9.0 | 9.0 | 9.0 | ||||||
Rate of compensation increase | 4.5 to | 4.5 to | 4.5 to | 4.5 to | 4.5 to | 4.5 to | ||||||
5.0 | 5.0 | 5.0 | 5.0 | 5.0 | 5.0 | |||||||
Assumed health care cost trend rates at Dec 31 | ||||||||||||
Health care cost trend rate assumed for | ||||||||||||
next year | 10 | 10 | 10 | |||||||||
Rate that the cost trend rate gradually | ||||||||||||
declines to | 5 | 5 | 5 | |||||||||
Year that the rate reaches the rate it is | ||||||||||||
assumed to remain at | 2011 | 2010 | 2009 | |||||||||
The expected long-term rate of return on plan assets was 9% in 2005 and 2004. In 2006, the expected rate of return on plan assets will be 8.5%, which is expected to increase pension expense by approximately $3.6 million. This return expectation on plan assets was determined by reviewing actual pension historical returns as well as calculating expected total trust returns using the weighted average of long-term market returns for each of the asset categories utilized in the pension fund.
Other Post-retirement Benefits Plans: We use various Employees' Benefit Trusts to fund a major portion of other post-retirement benefits. The majority of the trusts' assets are mutual funds or commingled indexed funds.
A one-percentage-point change in assumed health care cost trend rates would have the following effects:
1% Increase | 1% Decrease | ||
(Millions of Dollars) | |||
Effect on | |||
Post-retirement benefit obligation | $21.2 | ($19.0) | |
Total of service and interest cost components | $3.1 | ($2.7) | |
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
In 2004, in accordance with FSP 106-2, we chose to recognize the effects of the Act retroactively effective January 1, 2004. Calculated actuarially, the Act resulted in a reduction of $20.6 million in our benefit obligation. In addition, we recorded a reduction to SFAS 106 expense of $4.2 million in 2004. In January 2005, the Centers for Medicare & Medicaid Services released final regulations to implement the new prescription drug benefit under Part D of Medicare. It was determined that the employer sponsored plans meet these regulations and that the previously determined actuarial measurements do not need to be revised.
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 Act, and 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. Due to this change, we remeasured the fair value of our other post-retirement plans in the fourth quarter of 2005 in accordance with SFAS 106, Employers' Accounting for Post-Retirement Benefits Other than Pensions. In 2005, the impact of this remeasurement and the FSP 106-2 benefit was approximately a $4.1 million reduction to SFAS 106 expense.
Plan Assets: In our opinion, current pension trust assets and amounts which are expected to be contributed to the trusts in the future will be adequate to meet pension payment obligations to current and future retirees. Our pension plans asset allocation at December 31, 2005 and 2004, and our target allocation for 2006, by asset category, are as follows:
Target | Actual Allocation | |||||
Asset Category | 2006 | 2005 | 2004 | |||
Equity Securities | 65% | 65% | 73% | |||
Debt Securities | 35% | 35% | 27% | |||
Total | 100% | 100% | 100% | |||
Wisconsin Energy Corporation's common stock is not included in equity securities. Investment managers are specifically prohibited from investing in our securities or any affiliate of ours except if part of a commingled fund.
The target asset allocation was established by an Investment Trust Policy Committee, which oversees investment matters related to all of our funded benefit plans. Asset allocation is monitored by the Investment Trust Policy Committee.
Our other post-retirement benefit plans asset allocation at December 31, 2005 and 2004, and our target allocation for 2006, by asset category, are as follows:
Target | Actual Allocation | |||||
Asset Category | 2006 | 2005 | 2004 | |||
Equity Securities | 34% | 32% | 32% | |||
Debt Securities | 66% | 67% | 68% | |||
Other | - % | 1% | - % | |||
Total | 100% | 100% | 100% | |||
Wisconsin Energy Corporation's common stock is not included in equity securities. Investment managers are specifically prohibited from investing in our securities or any affiliate of ours except if part of a commingled fund.
The target asset allocation was established by an Investment Trust Policy Committee, which oversees investment matters related to all of our funded benefit plans. Asset allocation is monitored by the Investment Trust Policy Committee.
Cashflows:
|
| Other | ||
(Millions of Dollars) | ||||
2003 | $1.2 | $15.4 | ||
2004 | $72.4 | $15.7 | ||
2005 | $2.9 | $9.1 | ||
Based on our PSCW approved funding policy and current IRS funding requirements, we expect to contribute $56.6 million to fund pension benefits and $10.0 million to fund other post-retirement benefit plans in 2006. Of the $56.6 million expected to be contributed to fund pension benefits in 2006, we estimate $52.5 million will be for our qualified pension plans. We did not make a contribution to our qualified pension plan during 2005. We contributed $51.7 million to our qualified pension plans during 2004.
The entire contribution to the other post-retirement benefit plans during 2005 was discretionary as the plans are not subject to any minimum regulatory funding requirements.
The following table identifies our expected benefit payments over the next 10 years:
|
| Gross Other | Expected | |||
(Millions of Dollars) | ||||||
2006 | $69.8 | $14.7 | ($1.3) | |||
2007 | $80.1 | $14.7 | ($0.9) | |||
2008 | $76.8 | $15.2 | ($1.0) | |||
2009 | $80.6 | $14.4 | - | |||
2010 | $80.1 | $15.7 | - | |||
2011-2015 | $448.5 | $97.0 | - | |||
Savings Plans: We sponsor savings plans which allow employees to contribute a portion of their pre-tax and or after-tax income in accordance with plan-specified guidelines. Under these plans, we expensed matching contributions of $9.5 million, $9.1 million and $8.8 million during 2005, 2004 and 2003, respectively.
Severance Plans: In 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 of Wisconsin Energy and its subsidiaries who voluntarily resigned in the fourth quarter of 2004. The program was enacted to help reduce the upward pressure on operating expenses.
Approximately 150 employees received severance benefits during 2004. At December 31, 2004, we accrued $6.6 million for severance benefits. As of December 31, 2005, substantially all of the severance related benefits were paid.
M -- GUARANTEES
We enter into various guarantees to provide financial and performance assurance to third parties. As of December 31, 2005, we had the following guarantees:
Maximum |
|
| ||||
(Millions of Dollars) | ||||||
Guarantees | $235.4 | $0.1 | $ - | |||
We guarantee the potential retrospective premiums that could be assessed under our nuclear insurance program (See Note F).
Postemployment benefits: Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability for such benefits was $12.8 million as of December 31, 2005.
N -- COMMON EQUITY
Stock Based Compensation Plans: Employees of Wisconsin Electric participate in the Wisconsin Energy 1993 Omnibus Stock Incentive Plan, as amended (OSIP), as approved by Wisconsin Energy stockholders. The OSIP enables Wisconsin Energy to provide a long-term incentive through equity interests in Wisconsin Energy, to outside directors, selected officers and key employees of Wisconsin Energy and its subsidiaries. The OSIP provides for the granting of Wisconsin Energy stock options, stock appreciation rights, stock awards and performance shares. Awards may be paid in Wisconsin Energy common stock, cash or a combination thereof.
The exercise price of a Wisconsin Energy stock option under the OSIP is to be no less than 100% of the common stock's fair market value on the grant date and options may not be exercised within six months of the grant date except in the event of a change in control. The Wisconsin Energy stock options that were granted prior to 2005 generally vest on a straight line basis over a four year period and expire no later than ten years from the date of grant.
The following is a summary of Wisconsin Energy stock options held by Wisconsin Electric employees and issued through December 31, 2005.
2005 | 2004 | 2003 | ||||||||||
|
| Weighted- |
| Weighted- |
| Weighted- | ||||||
Outstanding at January 1 | 5,011,623 | $27.02 | 5,289,762 | $23.91 | 4,201,046 | $22.63 | ||||||
Granted | 793,622 | $34.20 | 1,388,270 | $33.44 | 1,725,869 | $26.50 | ||||||
Exercised | (801,026) | $23.43 | (1,614,022) | $22.33 | (601,722) | $22.47 | ||||||
Forfeited | (5,513) | $32.27 | (52,387) | $28.15 | (35,431) | $22.63 | ||||||
Outstanding at December 31 | 4,998,706 | $28.72 | 5,011,623 | $27.02 | 5,289,762 | $23.91 | ||||||
Exercisable at December 31 | 4,192,238 | $27.70 | 4,805,568 | $27.16 | 1,949,614 | $23.28 | ||||||
In January 2006, the Wisconsin Energy Compensation Committee (the Compensation Committee) awarded 747,508 non-qualified Wisconsin Energy stock options at the average market price of $39.48 to our officers and key employees under its normal schedule of awarding long-term incentive compensation.
In December, 2004, the Compensation Committee approved certain changes to unvested options and to future grants. The Compensation Committee approved the acceleration of vesting of all unvested options awarded to our executive officers and other key employees in 2002, 2003 and 2004 in anticipation of the changes in accounting required under the new accounting standard for share based payments which is effective January 1, 2006. In addition, the Compensation Committee determined that future option grants would be non-qualified stock options and they would vest on a cliff-basis after a three year period. For further information regarding the accounting changes related to stock based compensation see Note A and Note B.
The following table summarizes information about Wisconsin Energy stock options outstanding held by Wisconsin Electric employees at December 31, 2005:
Options Outstanding | Options Exercisable | |||||||||
|
| Average |
|
| Average | |||||
$10.86 to $23.05 | 1,041,189 | $21.41 | 5.4 | 1,037,552 | $21.40 | |||||
$25.41 to $27.65 | 1,268,904 | $25.82 | 7.1 | 1,259,004 | $25.82 | |||||
$29.13 to $34.20 | 2,688,613 | $32.92 | 7.9 | 1,895,682 | $32.40 | |||||
4,998,706 | $28.72 | 7.2 | 4,192,238 | $27.70 | ||||||
The Compensation Committee has also approved Wisconsin Energy restricted stock grants to certain of our employees and directors. The following restricted stock activity related to Wisconsin Electric employees occurred during 2005, 2004 and 2003:
2005 | 2004 | 2003 | ||||||||||
|
| Weighted- |
| Weighted- |
| Weighted- | ||||||
Outstanding at January 1 | 145,055 | 203,507 | 140,980 | |||||||||
Granted | -- | $ -- | -- | $ -- | 64,990 | $29.19 | ||||||
Released / Forfeited | (25,891) | $29.29 | (58,452) | $24.18 | (2,463) | $27.03 | ||||||
Outstanding at December 31 | 119,164 | 145,055 | 203,507 | |||||||||
Recipients of the Wisconsin Energy restricted shares, who have the right to vote the shares and to receive dividends, are not required to provide consideration to us other than rendering service. Forfeiture provisions on the restricted stock generally expire 10 years after award grant subject to an accelerated expiration schedule based on the achievement of certain financial performance goals.
Under the provisions of APB 25, Wisconsin Energy records the market value of the restricted stock awards on the date of grant as a separate unearned compensation component of common stock equity. We then amortize our share of allocated expense over the vesting period of the awards. We also adjust expense for acceleration of vesting due to achievement of performance goals.
In January 2004, the Compensation Committee granted 113,750 Wisconsin Energy performance shares to our officers and other key employees. In January 2006 and 2005, the Compensation Committee granted 88,305 and 65,376 Wisconsin Energy performance units to our officers and other key employees under the Wisconsin Energy Performance Unit Plan. Under the grants, the ultimate number of shares of Wisconsin Energy common stock or cash which will be awarded is dependent upon the achievement of certain financial performance of Wisconsin Energy's common stock over a three year period. Under the terms of the award, participants may earn between 0% and 175% of the base performance award. We are accruing compensation costs over the three year period based on our estimate of the final expected value of the award. The 2004 grant will be settled in Wisconsin Energy common stock. The 2005 and 2006 grants will be settled in cash.
Restrictions: Our January 2006 rate order from the PSCW requires us to maintain a capital structure (i.e., the percentage by which each of common stock, preferred stock and debt constitute the total capital invested in the utility), which has a common equity ratio range of between 48.5% and 53.5% (including certain off-balance sheet obligations and capitalized leases, but excluding the PWGS Unit 1 capitalized lease). Previously in a June 2004 decision, the PSCW determined that we must obtain specific approval to pay dividends that exceed normal levels as long as any tax issue or appeals related to the sale of Wisconsin Energy's manufacturing business and/or the conversion of Wisconsin Gas to a limited liability company remain outstanding. The PSCW may modify such provisions by a future order.
We may not pay common dividends to Wisconsin Energy under our Restated Articles of Incorporation if any dividends on our outstanding preferred stock have not been paid. In addition, pursuant to the terms of our 3.60% Serial Preferred Stock, our ability to declare common dividends would be limited to 75% or 50% of net income during a twelve month period if our common stock equity to total capitalization, as defined, is less than 25% and 20%, respectively.
See Note H for discussion of certain financial covenants related to our bank back-up credit agreements.
We do not believe that these restrictions will materially affect our operations or limit any normal dividend payments in the foreseeable future.
O -- SEGMENT REPORTING
We are a wholly-owned subsidiary of Wisconsin Energy and have organized our operating segments according to how we are currently regulated. Our reportable operating segments include electric, natural gas and steam utility segments. The accounting policies of the reportable operating segments are the same as those described in Note A.
Our electric utility engages in the generation, distribution and sale of electric energy in southeastern (including metropolitan Milwaukee), east central and northern Wisconsin and in the Upper Peninsula of Michigan. Our natural gas utility is engaged in the purchase, distribution and sale of natural gas to retail customers and the transportation of customer-owned natural gas in three service areas in southeastern, east central and northern Wisconsin. Our steam utility produces, distributes and sells steam to space heating and processing customers in the Milwaukee, Wisconsin area.
Summarized financial information concerning our reportable operating segments for each of the years ended December 31, 2005, 2004 and 2003, is shown in the following table.
Reportable Operating Segments | ||||||
Year Ended | Electric | Gas | Steam | Other (a) | Total | |
(Millions of Dollars) | ||||||
December 31, 2005 | ||||||
Operating Revenues (b) | $2,320.9 | $593.6 | $23.5 | $ - | $2,938.0 | |
Depreciation, Decommissioning | ||||||
and Amortization | $242.7 | $35.8 | $3.3 | $ - | $281.8 | |
Operating Income (Loss) (c) | $437.5 | $41.5 | ($1.7) | $ - | $477.3 | |
Equity in Earnings | ||||||
of Unconsolidated Affiliate | $30.4 | $ - | $ - | $ - | $30.4 | |
Capital Expenditures | $374.2 | $28.4 | $4.6 | $2.0 | $409.2 | |
Total Assets (d) | $7,020.2 | $709.0 | $58.9 | $121.1 | $7,909.2 | |
Reportable Operating Segments | ||||||
Year Ended | Electric | Gas | Steam | Other (a) | Total | |
(Millions of Dollars) | ||||||
December 31, 2004 | ||||||
Operating Revenues (b) | $2,070.8 | $523.8 | $22.0 | $ - | $2,616.6 | |
Depreciation, Decommissioning | ||||||
and Amortization | $234.9 | $36.1 | $3.1 | $ - | $274.1 | |
Operating Income (Loss) (c) | $427.2 | $33.1 | ($1.1) | $ - | $459.2 | |
Equity in Earnings | ||||||
of Unconsolidated Affiliate | $26.4 | $ - | $ - | $ - | $26.4 | |
Capital Expenditures | $313.7 | $33.2 | $6.7 | $5.3 | $358.9 | |
Total Assets (d) | $6,153.0 | $667.1 | $54.0 | $176.2 | $7,050.3 | |
December 31, 2003 | ||||||
Operating Revenues (b) | $1,986.4 | $513.0 | $22.5 | $ - | $2,521.9 | |
Depreciation, Decommissioning | ||||||
and Amortization | $234.1 | $38.9 | $3.2 | $ - | $276.2 | |
Operating Income (c) | $422.3 | $49.0 | $ - | $ - | $471.3 | |
Equity in Earnings | ||||||
of Unconsolidated Affiliate | $22.8 | $ - | $ - | $ - | $22.8 | |
Capital Expenditures | $271.6 | $56.8 | $2.6 | $12.7 | $343.7 | |
Total Assets (d) | $5,784.9 | $628.7 | $54.5 | $176.5 | $6,644.6 | |
(a) | Other includes primarily non-utility property and investments, materials and supplies, deferred charges and other corporate items. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(b) | We account for intersegment revenues at a tariff rate established by the PSCW. Intersegment revenues are not material. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(c) | We evaluate operating income to manage our utility business. Equity in Earnings of Unconsolidated Affiliate, Interest Expense and Income Tax Expense are not included in segment operating income. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(d) | Common utility plant is allocated to electric, gas and steam utility
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We provide to and receive from certain of our Wisconsin Energy affiliates managerial, financial, accounting, legal, data processing and other services in accordance with service agreements approved by the PSCW. In addition, we make lease payments to We Power for PWGS Unit 1 and the other generating facilities being constructed under Wisconsin Energy's Power the Future strategy, and we sell electric energy to an affiliated utility, Edison Sault Electric Company (Edison Sault). We also receive and/or provide certain services to other associated companies in which we have an equity investment.
We provided and received services from and past rate-making practices of the PSCW, we defer as a regulatory asset costs associated with the remediation of former manufactured gas plant sites. As of December 31, 2004, we have recorded $45.5 million of environmental costs associated with manufactured gas plant sites as a regulatory asset, including $29.3 million of deferrals for actual remediation expenditures and a $16.2 million accrual for estimated future site remediation (See Note P). In addition, we have deferred $10.6 million of insurance recoveries associated with the environmental costs as regulatory liabilities. We expect to include total actual remediation costs incurred net of the related insurance recoveries in our next rate case at which time we would begin amortizing these costs over the following associated companies during 2005, 2004 and 2003:
Company | 2005 | 2004 | 2003 | |||
(Millions of Dollars) | ||||||
Wisconsin Energy Affiliate | ||||||
Net Services Provided | ||||||
-We Power (excluding lease payments) | $3.8 | $3.3 | $5.3 | |||
-Wisconsin Gas | $48.8 | $50.4 | $42.4 | |||
-Edison Sault (including electric energy sold) | $21.5 | $15.6 | $15.4 | |||
-Minergy | $8.1 | $7.3 | $4.7 | |||
-Other | $1.5 | $1.9 | $2.3 | |||
Net Services Received | ||||||
-We Power (lease payments) | $79.8 | $59.0 | $21.8 | |||
-Wisconsin Energy | $6.6 | $2.9 | $3.0 | |||
Equity Investee | ||||||
Services provided | ||||||
-American Transmission Company | $20.0 | $20.7 | $30.9 | |||
Services received | ||||||
-American Transmission Company | $126.8 | $112.5 | $94.4 | |||
-Nuclear Management Company | $61.2 | $58.1 | $57.1 | |||
-Guardian Pipeline | $12.0 | $11.4 | $3.2 | |||
At December 31, 2005 and 2004, our consolidated balance sheets included receivable and payable balances with the following equity investee companies:
Company | 2005 | 2004 | ||
(Millions of Dollars) | ||||
Equity Investee | ||||
Accounts Receivable | ||||
-American Transmission Company | $1.2 | $2.1 | ||
Accounts Payable | ||||
-American Transmission Company | $10.3 | $9.3 | ||
-Nuclear Management Company | $2.5 | $3.3 | ||
-Guardian Pipeline | $1.0 | $1.1 | ||
In addition, under Wisconsin Energy'sPower the Futureplan, we are required to pay the cost of needed transmission infrastructure upgrades. ATC will reimburse us for these costs when the units are placed into service. At December 31, 2005 and 2004, we had a receivable of $19.4 million and $4.9 million for these items.
Q -- COMMITMENTS AND CONTINGENCIES
Capital Expenditures: We have made certain commitments in connection with 2006 capital expenditures. During 2006, we estimate that total capital expenditures will be approximately $444.0 million, excluding the purchase of nuclear fuel.
Operating Leases: We enter into long-term purchase power contracts to meet a portion of our anticipated increase in future electric energy supply needs. These contracts expire at various times through 2013. Certain of these contracts were deemed to qualify as operating leases.
Future minimum payments for the next five years and thereafter for these contracts are as follows:
(Millions of Dollars) | |
2006 | $51.1 |
2007 | 50.4 |
2008 | 34.5 |
2009 | 21.4 |
2010 | 19.4 |
Thereafter | 48.3 |
$225.1 | |
Environmental Matters: We periodically review our exposure for environmental remediation costs as evidence becomes available indicating that our liability has changed. Given current information, including the following, we believe that future costs in excess of the amounts accrued and/or disclosed on all presently known and quantifiable environmental contingencies will not be material to our financial position or results of operations.
We have a program of comprehensive environmental remediation planning for former manufactured gas plant sites and coal-ash disposal sites. We perform ongoing assessments of manufactured gas plant sites and related disposal sites previously used by us, as well as coal ash disposal/landfill sites used by us, as discussed below. We are working with the Wisconsin Department of Natural Resources in our investigation and remediation planning. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.
Manufactured Gas Plant Sites: We have identified thirteen sites at which we or a predecessor company historically owned or operated a manufactured gas plant. We have substantially completed planned remediation activities at seven of those sites and certain sites are subject to ongoing monitoring. Remediation at additional sites is currently being performed, and other sites are being investigated or monitored. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Based upon ongoing analysis, we estimate that the future costs for detailed site investigation and future remediation costs may range from $13 to $30 million over the next ten years. This estimate is dependent upon several variables including, among other things, the extent of remediation, changes in technology and changes in regulation. As of December 31, 2005, we have established reserves of $13.9 million related to future remediat ion costs.
The PSCW has allowed Wisconsin utilities, including us, to defer the costs spent on the remediation of manufactured gas plant sites, and has allowed for these costs to be recovered in rates over five years. Accordingly, we have recorded a regulatory asset for remediation costs.
Ash Landfill Sites: We aggressively seek environmentally acceptable, beneficial uses for our coal combustion by-products. However, these coal-ash by-products have been, and to a small degree, continue to be disposed in company-owned, licensed landfills. Some early designed and constructed landfills may allow the release of low levels of constituents resulting in the need for various levels of monitoring or adjusting. Where we have become aware of these conditions, efforts have been expended to define the nature and extent of any release, and work has been performed to address these conditions. The costs of these efforts are included in our fuel costs. During 2005, 2004 and 2003, we incurred $0.1 million, $1.8 million and $2.1 million, respectively, in coal-ash remediation expenses. As of December 31, 2005, we have no reserves established related to ash landfill sites.
EPA - Proposed Consent Decree: We received a request for information in December 2000 from the United States Environmental Protection Agency (EPA) regional office pursuant to Section 114(a) of the Clean Air Act and a supplemental request in December 2002. In April 2003, we and EPA announced that a consent decree had been reached that resolved all issues related to this matter. In July 2003, the court granted the State of Michigan and EPA's joint motion to amend the consent decree to allow Michigan to become a party. Under the consent decree we are required to significantly reduce our air emissions from our coal-fired generating facilities. The reductions are expected to be achieved by 2013 through a combination of installing new pollution control equipment, upgrading existing equipment, and retiring certain older units. The capital cost of implementing this agreement is estimated to be approximately $600 million over the 10 years endin g 2013. Through December 31, 2005, we have spent approximately $216.5 million associated with implementing the EPA agreement. There may be additional costs of
The agreement has gone through the public comment period. In October 2003, three citizen groups filed a motion with the court to intervene in the proceeding to contest the consent decree; the court granted their motion. Also, in October 2003, the government filed its response to public comments and a motion asking the court to approve the amended consent decree. The intervenor groups subsequently filed a motion requesting that the court stay the government's motion for approval of the decree to allow the interveners to conduct discovery. Briefing was completed and the judge heard oral arguments from the parties in August 2004. In September 2004, the court granted the interveners' request for limited discovery with respect to two facilities within our generation fleet, and ordered that discovery be completed by December 2004. Final briefing concluded in March 2005. The court may convene additional hearings.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Wisconsin Electric Power Company:
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Wisconsin Electric Power Company and subsidiary as of December 31, 2005 and 2004, and the related consolidated statements of income, common equity, and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as we ll as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Wisconsin Electric Power Company and subsidiary at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/DELOITTE & TOUCHE LLP
Deloitte & Touche LLP
Milwaukee, Wisconsin
February 27, 2006