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Wisconsin Energy 10-K 2005 Documents found in this filing:
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UNITED STATES 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
Securities Registered Pursuant to Section 12(b) of the Act:
Securities Registered Pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’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]
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes [X] No [ ]
The aggregate market value of the common stock of Wisconsin Energy Corporation held by non-affiliates was approximately $3.8 billion based upon the reported last sale price of such securities as of June 30, 2004.
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Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date (January 31, 2005):
Common Stock, $.01 Par Value, 116,985,602 shares outstanding
Documents Incorporated by Reference
Portions of Wisconsin Energy Corporation’s definitive Proxy Statement for its Annual Meeting of Stockholders, to be held on May 5, 2005, are incorporated by reference into Part III hereof.
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FORM 10-K REPORT FOR THE YEAR ENDED DECEMBER 31, 2004
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INTRODUCTION
Wisconsin Energy Corporation was incorporated in the state of Wisconsin in 1981 and became a diversified holding company in 1986. We maintain our principal executive offices in Milwaukee, Wisconsin. Unless qualified by their context when used in this document, the terms Wisconsin Energy, the Company, our, us or we refer to the holding company and all of its subsidiaries.
Historically we conducted our operations primarily in three operating segments: a utility energy segment, a non-utility energy segment and a manufacturing segment. The sale of our manufacturing segment was completed effective July 31, 2004 and this segment is reported as discontinued operations. Our primary subsidiaries are Wisconsin Electric Power Company (Wisconsin Electric), Wisconsin Gas LLC, formerly Wisconsin Gas Company (Wisconsin Gas) and W.E. Power, LLC (We Power).
Utility Energy Segment: Our utility energy segment consists of: Wisconsin Electric, 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; Wisconsin Gas, which serves approximately 577,000 gas customers in Wisconsin and about 2,660 water customers in suburban Milwaukee, Wisconsin; and Edison Sault Electric Company (Edison Sault), which serves approximately 22,700 electric customers in the Upper Peninsula of Michigan. In April 2002, Wisconsin Electric and Wisconsin Gas began doing business under the trade name of “We Energies”.
Non-Utility Energy Segment: Our non-utility energy segment consists of We Power and Wisvest Corporation (Wisvest). We Power was formed in 2001 to design, construct, own, finance and lease the new generating capacity included in our Power the Future strategy. See Item 7 for more information on Power the Future. Wisvest owns an investment in an electric generating facility and has investments in other energy-related entities and assets. We have substantially reduced the operations of Wisvest since 2000.
Manufacturing Segment: Our manufacturing segment consisted of WICOR Industries, LLC (WICOR Industries), an intermediary holding company, and its three primary subsidiaries: Sta-Rite Industries, LLC, SHURflo, LLC and Hypro, LLC, which are manufacturers of pumps, water treatment products and fluid handling equipment with manufacturing, sales and distribution facilities in the United States and several other countries. Effective July 31, 2004, we sold this segment to Pentair, Inc. (Pentair).
Power the Future Strategy: In late February 2001, we 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 our Power the Future strategy, we are: (1) investing in new natural gas-fired and coal-fired electric generating facilities, (2) upgrading Wisconsin Electric’s existing electric generating facilities and (3) investing in upgrades of our existing energy distribution system. Also, as part of this strategy, we announced and began implementing plans to divest non-core assets and operations in our non-utility energy segment and to reduce our real estate operations. Implementation of the Power the Future strategy is subject to a number of state and federal regulatory approvals and judicial review. Additional information concerning Power the Future may be found below under “Non-Utility Energy Segment” and “Environmental Compliance” as well as in Item 7.
For further financial information about our business segments, see “Results of Operations” in Item 7 and “Note Q - Segment Reporting” in the Notes to Consolidated Financial Statements in Item 8.
We have our annual and periodical filings to the Securities and Exchange Commission (SEC) available, free of charge, through our Internet website www.wisconsinenergy.com. These documents are available as soon as reasonably practicable after such materials are filed (or furnished) with the SEC.
Cautionary Factors: Certain statements contained herein are “Forward-Looking Statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-Looking Statements include, among other things, statements regarding management’s expectations and projections regarding completion of construction projects, regulatory matters, fuel costs, sources of electric energy supply, gas deliveries, remediation costs, environmental and
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other capital expenditures, liquidity and capital resources and other matters. Also, Forward-Looking Statements may be identified by reference to a future period or periods or by the use of forward looking terminology such as “anticipates,” “believes,” “estimates,” “expects,” “forecasts,” “intends,” “may,” “objectives,” “plans,” “possible,” “potential,” “projects” or similar terms or variations of these terms. Actual results may differ materially from those set forth in Forward-Looking Statements as a result of certain risks and uncertainties, including but not limited to, those risks and uncertainties described under the heading “Cautionary Factors” in Item 7 of this report, as well as other matters described under the heading “Factors Affecting Results, Liquidity and Capital 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.
UTILITY ENERGY SEGMENT
ELECTRIC UTILITY OPERATIONS
Our electric utility operations consist of the electric operations of Wisconsin Electric and Edison Sault. Wisconsin Electric, which is the largest electric utility in the state of Wisconsin, generates and distributes electric energy in a territory in southeastern (including the metropolitan Milwaukee area), east central and northern Wisconsin and in the Upper Peninsula of Michigan. Edison Sault generates and distributes electric energy in a territory in the eastern Upper Peninsula of Michigan.
Electric Sales
See “Consolidated Selected Utility Operating Data” in Item 6 for certain electric utility operating information by customer class during the period 2000 through 2004.
Wisconsin Electric: Wisconsin Electric is authorized to provide retail electric service in designated territories in the state 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 state of Michigan pursuant to franchises granted by municipalities. Wisconsin Electric also sells wholesale electric power.
Electric energy sales by Wisconsin Electric to all classes of customers totaled approximately 31.6 million megawatt hours (mwh) during 2004, a 1.5% increase from 2003. Approximately 0.4 million of megawatt-hour sales during 2004 were to Edison Sault. Wisconsin Electric had approximately 1,081,400 electric customers at December 31, 2004, an increase of 1.3% since December 31, 2003.
Edison Sault: Edison Sault is authorized to provide retail electric service in certain territories in the state of Michigan pursuant to franchises granted by municipalities. Edison Sault also provides wholesale electric service under contract with one rural cooperative.
Electric energy sales by Edison Sault to all classes of customers totaled approximately 0.9 million megawatt hours during both 2004 and 2003. No significant megawatt-hour sales during 2004 were to Wisconsin Electric. Edison Sault had approximately 22,700 electric customers at December 31, 2004 and 22,000 electric customers at December 31, 2003.
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 electric kilowatt-hour sales of our utility energy segment to grow at an annual rate of 1.5% to 2.0% 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: Wisconsin Electric provides 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. Edison Sault provides electric service to industrial accounts in the paper, crude oil pipeline and limestone quarry industries as well as to several state and federal government facilities.
Our largest retail electric customers are two iron ore mines located in the Upper Peninsula of Michigan. Wisconsin Electric currently has special negotiated power-sales contracts with these mines that expire in December 2007. The
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combined electric energy sales to the two mines accounted for 7.4% and 7.1% of our total electric utility energy sales during 2004 and 2003, respectively.
Sales to Wholesale Customers: During 2004, Wisconsin Electric 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. Wholesale electric energy sales by Wisconsin Electric were also made to 34 other public utilities and power marketers throughout the region under rates approved by the Federal Energy Regulatory Commission (FERC). Edison Sault sold wholesale electric energy to one rural cooperative during 2004. Wholesale sales accounted for approximately 9.1% of our total electric energy sales and 4.7% of total electric operating revenues during 2004 compared with 8.9% of total electric energy sales and 4.6% of total electric operating revenues during 2003.
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 2004 electric peak demand obligation of 5,789 megawatts on July 20, 2004 and our all-time electric peak demand obligation of 6,376 megawatts on August 31, 2003. The summer period is the most relevant period for capacity planning purposes for us as a result of cooling load. Wisconsin Electric is a member of the MAIN reliability council. MAIN guidelines direct members to have a minimum 14.12% planning reserve margin in place prior to the upcoming peak season. PSCW guidelines to electric utilities in Wisconsin advise a minimum 18% planning reserve margin. The Michigan Public Service Commission (MPSC) has not provided guidelines in this area.
We had adequate capacity to meet all of our firm electric load obligations during 2004 and expect to have adequate capacity to meet all of our firm obligations during 2005. For additional information, see “Factors Affecting Results, Liquidity and Capital Resources” in Item 7. For additional information regarding our generation facilities, see “Utility Energy Segment” in Item 2.
Competition
Prior to 2003, the nation’s electric utility industry had been following a trend towards restructuring and increased competition. However, given electric reliability problems experienced in the summer of 2003 and in the state of California in 2001 and 2002, which had previously restructured its electric 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 state of Wisconsin. The state of Michigan implemented electric retail access in 2002, and the FERC continues to strongly support large Regional Transmission Organizations (RTO) such as the Midwest Independent Transmission System Operator, Inc. (Midwest ISO). For additional information, see “Factors Affecting Results, Liquidity and Capital 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, 2004, as well as an estimate for 2005:
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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. Our Power the Future plan, which is discussed further in Item 7, “Power the Future”, includes the addition of 2,320 megawatts of generating capacity over the next seven years. We are currently building two 545-megawatt natural gas units at an existing site in Port Washington, Wisconsin. The first natural gas unit is expected to be operational early in the third quarter of 2005. The second natural gas unit is expected to be operational by the end of the second quarter of 2008. We also have received approval from the PSCW to build two 615-megawatt coal units at an existing site in Oak Creek, Wisconsin. The approval to build these coal units has been challenged, and this matter is to be heard by the Supreme Court of Wisconsin 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).
We believe that our Power the Future plan will allow us to 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 totaled 29.2 million megawatt hours during 2004 compared with 28.0 million megawatt hours during 2003 and 27.8 million megawatt hours during 2002. When compared with the past three years, net generation as a percent of our total electric energy supply is expected to decrease during 2005 in large part due to the Port Washington unit retirements associated with construction of two natural gas-fired generation facilities at the same site, one of which is expected to become operational in 2005, and two nuclear generating facility outages scheduled for 2005. Purchased power is expected to be the primary source of additional electric energy supply required to meet load growth in the next year.
Our average fuel and purchased power costs per megawatt hour by fuel type for the years ended December 31 are shown below.
We use natural gas to fuel our peaking units that are designed to run for short durations. The Port Washington natural gas-fired units under construction as part of Power the Future are combined cycle facilities that are designed to run for longer durations and at a lower operating cost as compared to a peaking unit.
Coal costs in 2004 were adversely affected by 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 existing coal and rail contracts expire at the end of 2005. Based on current market conditions, we expect coal and transportation costs to increase more significantly than our most recent historical trend beginning in 2006.
The costs for natural gas and purchased power, which is primarily natural gas-fired, are more volatile and have experienced significant increases since 2002. Beginning in late 2003 and concurrent with the approval of the PSCW, we established hedging programs to mitigate significant price fluctuations due to gas prices. This hedging program is generally implemented on a 18 month forward-looking basis. Proceeds related to the natural gas hedging program are reflected in the 2004 average costs of Natural Gas and Purchased Power shown above.
Wisconsin Electric’s installed capacity by fuel type for the years ended December 31, is shown below.
Table of Contents2004 Form 10-K
Coal-Fired Generation
Coal Supply: Wisconsin Electric diversifies the coal supply for its power plants by purchasing coal from mines in northern and central Appalachia as well as from various western mines. During 2005, 97.6% of Wisconsin Electric’s projected coal requirements of 10.5 million tons will be under contracts which are not tied to 2005 market pricing fluctuations. Wisconsin Electric does not anticipate any problem in procuring its remaining 2005 coal requirements through short-term or spot purchases and inventory adjustments. Our coal-fired generation consists of six operating plants with a dependable capability of approximately 3,334 megawatts.
Following is a summary of the annual tonnage amounts for Wisconsin Electric’s principal long-term coal contracts by the month and year in which the contracts expire.
As of the beginning of 2005, Wisconsin Electric had approximately a 77-day supply of coal in inventory at its coal-fired facilities.
Coal Deliveries: Approximately 75% of Wisconsin Electric’s 2005 coal requirements are expected to be delivered by Wisconsin Electric-owned or leased unit trains. The unit trains will transport coal for the Oak Creek and Pleasant Prairie Power Plants from Wyoming mines. Coal from Pennsylvania 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 “Environmental Compliance”.
Nuclear Generation
Point Beach Nuclear Plant: Wisconsin Electric owns 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. The Nuclear
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Management Company, LLC (NMC) and Wisconsin Electric filed an application with the NRC in February 2004 to renew the operating licenses for both of Wisconsin Electric’s nuclear reactors for an additional 20 years. Based upon the NRC’s published schedule, we expect the NRC to make a decision on the license extension application by January 2006. For additional information concerning Point Beach, see “Factors Affecting Results, Liquidity and Capital Resources” in Item 7 and “Note H – Nuclear 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 four other unaffiliated investor-owned utilities in the region, operates Point Beach. NMC operates eight nuclear generating units at six sites in the states of Wisconsin, Minnesota, Michigan, and Iowa with a total combined generating capacity of approximately 4,600 megawatts as of December 31, 2004. Wisconsin Electric continues to own Point Beach and retains 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 “Factors Affecting Results, Liquidity and Capital Resources” in Item 7.
Nuclear Fuel Supply: Wisconsin Electric purchases uranium concentrates (Yellowcake) and contracts 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. Wisconsin Electric maintains title to the nuclear fuel until fabricated fuel assemblies are delivered to Point Beach; it is then sold to and leased back from the Wisconsin Electric Fuel Trust. For further information concerning this nuclear fuel lease, see “Note J - Long-Term Debt” in the Notes to Consolidated Financial Statements in Item 8.
Uranium Requirements: Wisconsin Electric requires approximately 400,000 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, which supplies 100% of the annual requirements through 2007, with an option to extend the current contract through 2009.
Conversion: Wisconsin Electric, through NMC, has a long-term contract with a provider of uranium conversion services to supply 100% of the conversion requirements for the Point Beach reactors through 2005. Wisconsin Electric has the option to utilize an NMC fleet contract for conversion services to meet approximately 56% of its conversion requirements through 2006. We are currently pursuing additional contracts for conversion services for Point Beach to meet the remaining 2006 requirements and additional contracts for supply beyond 2006.
Enrichment: Wisconsin Electric effectively has 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.
Fabrication: Fabrication of fuel assemblies from enriched uranium for Point Beach is covered under a contract with Westinghouse Electric Company, LLC for the balance of the plant’s current operating licenses.
Used Nuclear Fuel Storage & Disposal: For information concerning used fuel storage and disposal issues, see “Factors Affecting Results, Liquidity and Capital Resources” in Item 7.
Nuclear Decommissioning: Wisconsin Electric provides for costs associated with the eventual decommissioning of Point Beach through the use of an external trust fund. Payments to this fund, together with investment results, brought the balance in the fund at December 31, 2004 to approximately $737.8 million. For additional information regarding decommissioning, see “Note H - Nuclear Operations” in the Notes to Consolidated Financial Statements in Item 8.
Nuclear Plant Insurance: For information regarding nuclear plant insurance, see “Factors Affecting Results, Liquidity and Capital Resources” in Item 7 and “Note H – Nuclear Operations” in the Notes to Consolidated Financial Statements in Item 8.
Table of Contents2004 Form 10-K
Hydroelectric Generation
Wisconsin Electric: Wisconsin Electric’s hydroelectric generating system consists of thirteen operating plants with a total installed capacity of approximately 89 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 twelve licensed plants, eleven plants, representing a total of 85 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 will be completed by 2006.
Edison Sault: Edison Sault’s primary source of generation is its 30-megawatt hydroelectric generating plant located on the St. Marys River in Sault Ste. Marie, Michigan. The water for this facility is leased under a contract with the United States Army Corps of Engineers with tenure to December 31, 2050. However, the Secretary of the Army has the right to terminate the contract after December 2020. Edison Sault pays for all water taken from the St. Marys River at predetermined rates with a minimum annual payment of $0.1 million. The total flow of water taken out of Lake Superior, which in effect is the flow of water in the St. Marys River, is under the direction and control of the International Joint Commission, created by the Boundary Water Treaty of 1909 between the United States and Great Britain, now represented by Canada.
Hydroelectric generation is also purchased by Edison Sault under contract from the United States Army Corps of Engineers’ hydroelectric generating plant located within the Soo Locks complex on the St. Marys River in Sault Ste. Marie, Michigan. This 17-megawatt contract has a tenure to November 1, 2040 and cannot be terminated by the United States government prior to November 1, 2030.
Natural Gas-Fired Generation
Our natural gas-fired generation consists of four operating plants with a dependable capability of approximately 888 megawatts. In addition, early in the third quarter of 2005, we expect to add an additional 545 megawatts of natural gas-fired generation with the first of two units at the Port Washington plant under our Power the Future plan. The second 545-megawatt unit at Port Washington is estimated to come on line in 2008.
We purchase natural gas for these plants on the spot market from gas marketers and producers and we arrange for transportation of the natural gas to our plants. We have an interruptible balancing and storage agreement that is intended to facilitate the variable usage pattern of the plants.
The PSCW has approved a program that allows us to hedge up to 75% of our estimated gas purchases for electric generation. This program is intended to minimize the volatility of natural gas prices to our customers. The costs of this program are included in our fuel and purchased power costs.
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. Our oil-fired generation has a dependable capability of approximately 275 megawatts. The natural gas facilities 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 Wisconsin Electric with inventory tracking and oil market price trends.
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 over the next five years:
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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 the electric utility transmission assets of Wisconsin Electric and Edison Sault to American Transmission Company LLC (ATC) in exchange for ownership interests in this new company. Joining ATC is consistent with the FERC’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. At December 31, 2004, we owned approximately 37.8% of ATC.
ATC’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 Wisconsin Electric and Edison Sault, 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. As of February 1, 2002, operational control of ATC’s transmission system was transferred to the Midwest ISO, and Wisconsin Electric is a non-transmission owning member and customer of the Midwest ISO.
Wisconsin Electric has contracted to provide, at cost, services required by ATC and which ATC is not able to provide itself at this time. 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 provided by Wisconsin Electric was approximately $21 million, $33 million, and $52 million during 2004, 2003, and 2002, respectively, and is expected to continue to decline in future years as ATC provides more of these services itself.
Midwest ISO: In connection with its status as a FERC approved RTO, the Midwest ISO is in the process of developing and implementing a bid-based energy market. In March 2004, Midwest ISO filed a proposed Energy Markets Tariff that 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 is 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
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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, see “Factors Affecting Results, Liquidity and Capital Resources” in Item 7.
Renewable Electric Energy
Our Power 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, Wisconsin Electric has an “Energy For Tomorrow®” renewable energy program to provide our customers the opportunity to purchase energy from renewable resources.
Wisconsin’s public benefits legislation requires that for 2005, retail energy providers supply 1.2% of a 3 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 - Utility Energy Segment” below.
GAS UTILITY OPERATIONS
Our gas utility operations consist of Wisconsin Gas and the gas operations of Wisconsin Electric. Both companies are authorized to provide retail gas distribution service in designated territories in the state of Wisconsin, as established by indeterminate permits, certificates of public convenience and necessity, or boundary agreements with other utilities. The two companies also transport customer-owned gas. Wisconsin Gas, the largest natural gas distribution utility in Wisconsin, operates throughout the state including the City of Milwaukee. Wisconsin Electric’s 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 “Consolidated Selected Utility Operating Data” in Item 6 for selected gas utility operating information by customer class during the period 2000 through 2004.
Wisconsin Gas: In 2004, Wisconsin Gas delivered a total of approximately 1,233.0 million therms, including customer-owned transported gas, a 3.9% decrease compared with 2003. As of December 31, 2004, Wisconsin Gas was transporting gas for approximately 1,105 customers who purchased gas directly from other suppliers. Transported gas accounted for approximately 39% of the total volumes delivered by Wisconsin Gas during 2004, 38% during 2003 and 39% during 2002. Wisconsin Gas had approximately 577,000 customers at December 31, 2004, an increase of approximately 1.3% since December 31, 2003.
The maximum daily send-out of Wisconsin Gas during 2004 was 922,076 dekatherms on January 29, 2004. A dekatherm is equivalent to ten therms or one million British thermal units.
Wisconsin Electric: Total gas therms delivered by Wisconsin Electric, including customer-owned transported gas, were approximately 835.1 million therms during 2004, a 6.0% decrease compared with 2003. At December 31, 2004, Wisconsin Electric was transporting gas for approximately 368 customers who purchased gas directly from other suppliers. Transported gas accounted for approximately 34% of the total volumes delivered by Wisconsin Electric during 2004, 35% during 2003 and 38% during 2002. Wisconsin Electric had approximately 437,800 gas customers at December 31, 2004, an increase of approximately 2.1% since December 31, 2003.
Wisconsin Electric’s maximum daily send-out during 2004 was 682,933 dekatherms on January 29, 2004.
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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 Wisconsin Electric’s 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 3.2% for the combined gas operations of Wisconsin Electric and Wisconsin Gas over the five-year period ending December 31, 2009. This forecast reflects a current year normalized sales level and assumes moderate growth in the economy of our gas utility service territories, normal weather, and incremental Power the Future demand.
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 offer lower-priced interruptible rates and transportation services for these customers to enable them to reduce their energy costs and use gas rather than other fuels. Under gas transportation agreements, customers purchase gas directly from gas marketers and arrange with interstate pipelines and us to have the gas transported to the 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 “Factors Affecting Results, Liquidity and Capital 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 increasingly subject to competition from third parties. However, it 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
Both Wisconsin Gas and the gas operations of Wisconsin Electric have been able to meet their contractual obligations with both their suppliers and their customers despite periods of severe cold and unseasonably warm weather.
Pipeline Capacity and Storage: In addition to Guardian pipeline, in which we have a one-third ownership interest and which receives gas supply in the Joliet, Illinois market hub, the 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 management’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.
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We hold firm daily transportation and storage capacity entitlements from pipelines and other service providers under long-term contracts.
Term Gas Supply: On a combined basis, Wisconsin Gas and the gas operations of Wisconsin Electric currently have contracts for firm supplies with terms in excess of 30 days with suppliers for gas acquired in the Joliet, Illinois market hub and in the three producing areas discussed above. The pricing of the term contracts is based upon first of the month indices. Combined with our storage capability, management 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 Wisconsin Gas and the gas operations of Wisconsin Electric, must contract for capacity and supply sufficient to meet the firm peak day demand of their 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 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 the Wisconsin Electric and Wisconsin Gas gas cost incentive mechanisms pursuant to which the companies have an opportunity to share in the cost savings. See “Factors Affecting Results, Liquidity and Capital Resources - Utility Rates and Regulatory Matters” in Item 7 for information on the gas cost recovery mechanism. During 2004, we continued our active participation in the capacity release market.
Spot Market Gas Supply: Wisconsin Gas and the gas operations of Wisconsin Electric 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: Wisconsin Gas and the gas operations of Wisconsin Electric have PSCW approval to hedge (i) up to 50% of planned flowing gas supply using NYMEX based natural gas options, (ii) up to 10% of planned flowing gas supply using NYMEX based natural gas future contracts and, (iii) up to 33% of planned storage withdrawals using NYMEX based natural gas options. Those approvals allow both companies to pass 100% of the hedging costs (premiums and brokerage fees) and proceeds (gains and losses) through their respective purchase gas adjustment mechanisms. Hedge targets (volumes) are provided annually to the PSCW as part of each company’s five-year gas supply plan filing.
To the extent that opportunities develop and the companies’ physical supply operating plans will support them, Wisconsin Gas and Wisconsin Electric 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 the companies’ gas cost recovery (incentive) mechanisms.
Guardian Pipeline: We have a one-third interest in a joint venture, Guardian Pipeline, L.L.C. (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 precedent agreements to transport 87% of its 750,000 dekatherms per day pipeline design capacity.
Neither Wisconsin Electric nor Wisconsin Gas has an ownership interest in Guardian. However, Wisconsin Gas has committed to purchase 650,000 dekatherms (approximately 87% of the pipeline’s total capacity) per day of capacity on the pipeline over a long-term contract that expires in December 2012.
OTHER UTILITY OPERATIONS
Steam Utility Operations: Wisconsin Electric’s steam utility generates, distributes and sells steam supplied by its Valley and Milwaukee County Power Plants. Wisconsin Electric operates a district steam system in downtown Milwaukee and the near south side of Milwaukee. Steam is supplied to this system from Wisconsin Electric’s Valley Power Plant, a coal-fired cogeneration facility. Wisconsin Electric also operates the steam production and distribution facilities of the Milwaukee County Power Plant located on the Milwaukee County Grounds in Wauwatosa, Wisconsin.
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Annual sales of steam fluctuate from year to year based upon system growth and variations in weather conditions. During 2004, the steam utility had $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. As of December 31, 2004 and 2003, steam was used by approximately 460 customers for processing, space heating, domestic hot water and humidification.
Water Utility Operations: To leverage off of operational similarities with its natural gas business, Wisconsin Gas entered the water utility business in November 1998. As of December 31, 2004, the water utility served about 2,660 water customers in the suburban Milwaukee area compared with approximately 2,600 customers at December 31, 2003. Wisconsin Gas also provides contract services to local municipalities and businesses within its service territory for water system repair and maintenance. During 2004, the water utility had $1.9 million of operating revenues compared with $1.8 million of operating revenues during 2003.
UTILITY RATE MATTERS
See “Factors Affecting Results, Liquidity and Capital Resources - Utility Rates and Regulatory Matters” in Item 7.
NON-UTILITY ENERGY SEGMENT
Our non-utility energy segment is involved in a variety of businesses including the ownership and operation of independent electric generating facilities and investment in other energy-related entities and assets.
During 2000, we performed a comprehensive review of our existing portfolio of businesses and began implementing a strategy of divesting many of our non-utility energy segment businesses, especially those outside of the Midwest region. As we implement our Power the Future strategy, we expect to grow the non-utility energy segment within the state of Wisconsin through our subsidiary We Power.
Since 2000, we have sold our interest in SkyGen Energy Holdings, LLC, our interest in FieldTech, Inc., our interest in Blythe Energy, LLC, our interest in Wisvest-Connecticut LLC, a 500-megawatt natural gas power island, and our interests in Kaztex Energy Management, Inc. and Blackhawk Energy Services, LLC.
We Power
We Power, through wholly owned subsidiaries, plans to design, construct and finance 2,320 megawatts of new generating capacity in the state of Wisconsin proposed as part of our Power the Future plan. We expect that two unaffiliated entities together will own approximately 17% or 200 megawatts of capacity in two coal units to be constructed in Oak Creek, Wisconsin, and We Power will own the remaining 2,120 megawatts of generating capacity and lease this capacity to Wisconsin Electric. At December 31, 2004, We Power had $414.9 million of construction work in progress. For further information about our Power the Future strategy, see “Environmental Compliance” below as well as “Factors Affecting Results, Liquidity and Capital Resources - Power the Future “ in Item 7.
Wisvest Corporation
Wisvest was originally formed to develop, own and operate electric generating facilities and to invest in other energy-related entities. As a result of the change in corporate strategy to focus on our Power the Future strategy, Wisvest has discontinued its development activity. For the year ended December 31, 2004, Wisvest had $13.0 million of operating revenues compared with $11.7 million of operating revenues during 2003. We have divested the majority of Wisvest’s assets. As of December 31, 2004, Wisvest operations and investments included:
Calumet Energy Team, LLC: Calumet Energy owns and operates a 308-megawatt natural gas-fired peaking power plant in Chicago, IL. As of December 31, 2004, Calumet Energy had total assets of $29.7 million. Since May 1, 2004, Calumet has operated under the control of PJM, an RTO that also operates bid based energy and capacity markets. Calumet has a ten-year capacity reservation agreement for 50 megawatts of plant capacity with Midwest
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Generation, LLC, supported by the City of Chicago. The remaining plant capacity is marketed as merchant power. The plant has experienced limited demand for production due to excess capacity in the region and soft electricity market prices. For additional information on Calumet Energy see “Results of Operations” in Item 7 and “Note F - Asset Valuation Charges” in the Notes to Consolidated Financial Statements in Item 8.
Other: We own Wisvest Thermal Energy Services, which provides chilled water services to the Milwaukee Regional Medical Center. We have an interest in a cogeneration facility in the state of Maine, through an equity investment in Androscoggin Energy LLC. We wrote down our investment in Androscoggin to zero in 2003. Androscoggin filed for Chapter 11 bankruptcy protection in November 2004.
OTHER NON-UTILITY OPERATIONS
Minergy Corp.
Minergy is engaged in the development and marketing of proprietary technologies designed to convert high volume industrial and municipal wastes into renewable energy and value-added products. Minergy’s strategic focus is to license that technology and sell equipment to domestic and foreign operators or industrial/municipal users through its patented GlassPack process as a component of larger scale waste processing solutions. We believe this licensing strategy will allow Minergy to recognize the economic benefits of its technology with limited capital requirements. For the year ended December 31, 2004, Minergy had $19.8 million of consolidated operating revenues compared with $22.2 million of consolidated operating revenues during 2003. Minergy’s primary operations and investments include:
Minergy Neenah, LLC: In 1998, Minergy Neenah, LLC opened a facility in Neenah, Wisconsin that recycles paper sludge from area paper mills using our patented Glass Aggregate technology into renewable energy and glass aggregate. The Glass Aggregate technology is a vitrification process that converts the organic fraction of a waste material into heat and also melts the inorganic fraction into an inert glass aggregate material. The plant also provides substantial environmental and economic benefits to the area by providing an alternative to landfilling paper sludge. For additional information on Minergy Neenah, LLC see “Factors Affecting Results, Liquidity and Capital Resources” in Item 7 and “Note F - Asset Valuation Charges” in the Notes to Consolidated Financial Statements in Item 8.
GlassPack, LLC: Minergy has developed and patented our GlassPack technology, which is a smaller, less expensive and environmentally cleaner version of the Neenah facility. The GlassPack technology is suited for smaller wastewater treatment and industrial plants, along with river bed sediment. The first commercial GlassPack facility is being constructed in Zion, Illinois by the North Shore Sanitary District with commercial operation expected in late 2005. Minergy is also pursuing other domestic and foreign GlassPack installations through equipment sales or licensing agreements.
Wispark LLC
Wispark develops and invests in real estate. From September 2000 through December 31, 2004, Wispark has reduced its overall holdings from $373.1 million to $125.4 million. Wispark will maintain its remaining portfolio for investment and potential sale. During the twelve months ended December 31, 2004, Wispark had $17.8 million of consolidated operating revenues compared with $11.6 million during 2003.
Wispark has developed several business parks primarily in southeastern Wisconsin. Wispark’s flagship development, the 1,600-acre LakeView Corporate Park located near Kenosha, Wisconsin is home to 76 companies located in more than 9.1 million square feet of buildings that have been developed on property in excess of 920 acres. Many out-of-state firms have located in this park, creating a significant number of new jobs and growth in electricity and natural gas revenues.
In December 2004 Wispark entered into a joint venture with a major industrial development company whereby Wispark contributed land in its LakeView and GrandView Corporate parks valued at approximately $40.0 million to the joint venture in return for approximately $20.8 million in cash, future development fees and a 36% interest in the joint venture, which includes land contributed by our joint venture partner.
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Other Non-Utility Subsidiaries
Other non-utility subsidiaries primarily include:
Wisconsin Energy Capital Corporation: Wisconsin Energy Capital Corporation engages in investing and financing activities. Activities include advances to affiliated companies and investments in financial instruments and in partnerships developing low- and moderate-income housing projects.
WEC Nuclear Corporation: WEC Nuclear Corporation has a 20% ownership interest in NMC. Formed during the first quarter of 1999, NMC provides services to Wisconsin Electric in connection with Point Beach Nuclear Plant as well as to other unaffiliated companies with nuclear generating facilities. For additional information about NMC, see “Utility Energy Segment” above and “Factors Affecting Results, Liquidity and Capital Resources” in Item 7.
REGULATION
Wisconsin Energy Corporation
Wisconsin Energy is an exempt holding company by order of the SEC under Section 3(a)(1) of the Public Utility Holding Company Act of 1935, as amended, and, accordingly, is exempt from that law’s provisions other than with respect to certain acquisitions of securities of a public utility.
Non-Utility Asset Cap: In October 1999, the Wisconsin State Legislature passed amendments to the non-utility asset cap provisions of Wisconsin’s public utility holding company law as part of the 1999-2001 biennial state budget, 1999 Wisconsin Act 9. As a result, we remain subject to certain restrictions that have the potential of limiting diversification into non-utility activities. Under the amended public utility holding company law, the sum of certain assets of all non-utility affiliates in a holding company system may not exceed 25% of the assets of all public utility affiliates. However, among other items, the amended law exempts energy-related assets and assets, like Minergy’s, used for providing environmental engineering services and for processing waste materials, from being counted against the asset cap provided that they are employed in qualifying businesses. As a result of these exemptions, our non-utility assets are significantly below the non-utility asset cap as of December 31, 2004.
Under our Power the Future plan, the cost of constructing new generating facilities to be owned by We Power is expected to qualify as energy projects under the amended non-utility asset cap and therefore would be entirely exempt from the definition of “non-utility” property for this purpose. The remaining cost of our Power the Future plan represents investments in new and existing energy distribution system assets and upgrades to existing generation assets and has no impact on the amount of non-utility assets under the non-utility asset cap test.
Utility Energy Segment
Wisconsin Electric is an exempt holding company under Section 3(a)(1) of the Public Utility Holding Company Act of 1935, as amended, and Rule 2 thereunder and, accordingly, is exempt from that law’s provisions other than with respect to certain acquisitions of securities of a public utility. For information on how rates are set for our regulated entities see “Utility Rates and Regulatory Matters” in Item 7.
Wisconsin Electric and Wisconsin Gas are subject to the regulation of the PSCW as to retail electric, gas, steam and water rates in the state of Wisconsin, standards of service, issuance of securities, construction of certain new facilities, transactions with affiliates, billing practices and various other matters. Wisconsin Electric is subject to regulation of the PSCW as to certain levels of short-term debt obligations. Wisconsin Electric and Edison Sault are both subject to the regulation of the MPSC as to the various matters associated with retail electric service in the state 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. Wisconsin Electric’s hydroelectric facilities are regulated by the FERC. Wisconsin Electric and Edison Sault are subject to regulation of the FERC with respect to wholesale power service and accounting. Edison Sault is subject to regulation of the FERC with respect to the issuance of certain securities.
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The following table compares the source of our utility energy segment operating revenues by regulatory jurisdiction for each of the three years in the period ended December 31, 2004.
For information concerning the implementation of full electric retail competition in the state of Michigan effective January 1, 2002, see “Factors Affecting Results, Liquidity and Capital Resources” in Item 7.
Operation and construction relating to Wisconsin Electric’s Point Beach Nuclear Plant are subject to regulation by the NRC. Total flow of water to Edison Sault’s hydroelectric generating plant is under the control of the International Joint Commission, created by the Boundary Water Treaty of 1909 between the United States and Great Britain, now represented by Canada. The operations of Wisconsin Electric, Wisconsin Gas and Edison Sault are also subject to regulations, where applicable, of the United States Environmental Protection Agency (EPA), the Wisconsin Department of Natural Resources, 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 Administration (DOA). The law also required utilities to continue to collect the funds at existing levels for low-income, conservation and environmental research and development programs and to transfer the funds for these programs to the DOA. We implemented this change in October 2000. The 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 the two coal units under our Power the Future strategy, the PSCW required us to implement an energy efficiency program for the years 2005-2008 in addition to the DOA administered programs.
This law also requires that for 2005, retail energy providers supply 1.2% of a 3 year average of their Wisconsin retail electric sales from renewable energy. The required minimum percentage increases to 2.2% by the year 2011.
Non-Utility Energy Segment
We Power is a holding company subsidiary of Wisconsin Energy and was formed to design, construct, own, finance and lease the new generating capacity in our Power the Future strategy. We Power owns the interests in the companies constructing this new generating capacity (collectively, the We Power project companies). When complete, these facilities will be leased on a long-term basis to Wisconsin Electric. We Power has received determinations from the FERC that upon the transfer of the facilities by lease to Wisconsin Electric, the We Power project companies will not be deemed public utilities under the Federal Power Act and thus will not be subject to
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FERC’s jurisdiction. For a short period prior to the transfer of each generation unit to Wisconsin Electric, We Power will be engaged in the sale of test power, a FERC jurisdictional transaction. Currently, the We Power project companies have received approval from the FERC for the sale of test power to Wisconsin Electric from Port Washington Unit 1, which sales are expected to commence in March or April 2005, and for the transfer of any FERC jurisdictional facilities at Port Washington to Wisconsin Electric and/or ATC. Under Wisconsin law, We Power is not a “public utility”. Environmental permits necessary for operating the facilities are the responsibility of the operating entity, Wisconsin Electric.
Calumet Energy Team, LLC is an exempt wholesale generator pursuant to Section 32 of the Public Utility Holding Company Act of 1935, as amended. Calumet’s operations are subject to regulation of the FERC with respect to wholesale power service and to regulations, where applicable, of the EPA and the Illinois Department of Environmental Protection.
ENVIRONMENTAL COMPLIANCE
Environmental Expenditures
Expenditures for environmental compliance and remediation issues are included in anticipated capital expenditures described in “Liquidity and Capital 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 “Factors Affecting Results, Liquidity and Capital Resources” in Item 7.
Utility Energy Segment: Compliance with federal, state and local environmental protection requirements resulted in capital expenditures by Wisconsin Electric of approximately $78 million in 2004 compared with $15 million in 2003. Expenditures incurred during 2004 primarily included costs associated with the installation of pollution abatement facilities at Wisconsin Electric’s power plants. These expenditures at Wisconsin Electric are expected to approximate $147 million during 2005, reflecting nitrogen oxide (NOx), sulfer dioxide (SO2) and other pollution control equipment needed to comply with various rules promulgated by the EPA.
Operation, maintenance and depreciation expenses for Wisconsin Electric’s fly ash removal equipment and other environmental protection systems are estimated to have been approximately $52 million during 2004 and $51 million during 2003.
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.
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 Wisconsin Electric has 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 S – Commitments and Contingencies” in the Notes to Consolidated Financial Statements in Item 8. Sites currently undergoing remediation and/or monitoring include:
Lakeside Property: During 2001, Wisconsin Electric 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 also owned by Wisconsin Electric. Future costs for remediation of this site are estimated to be approximately $1.0 million.
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Oak Creek North Landfill: Groundwater impairments at this landfill, located in the City of Oak Creek, Wisconsin, prompted Wisconsin Electric 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. 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.
Manufactured Gas Plant Sites
We are reviewing and addressing environmental conditions at a number of former manufactured gas plant sites. See “Note S - Commitments and 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 nonattainment 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 nonattainment 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 “Factors Affecting Results, Liquidity and Capital Resources” in Item 7 for information concerning National Ambient Air Quality Standards established during 1997 by the EPA and ozone non-attainment rulemaking promulgated by the EPA during 1998.
Our Power the Future strategy provides a plan to meet our growing demand for electricity while using environmentally friendly equipment. We plan to build two coal units (Elm Road) at the site of Wisconsin Electric’s 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 Wisconsin Electric’s existing Port Washington Power Plant site, where older, less efficient coal-fired units installed before 1950 were retired in 2003 and 2004. Implementation of our Power the Future plan also provides for upgrades to 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 our Power the Future strategy, see “Non-Utility Energy Segment” above as well as “Factors Affecting Results, Liquidity and Capital Resources - Power the Future Strategy” in Item 7.
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, 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 Wisconsin Electric’s Oak Creek
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Power Plant, 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 the existing facilities are expected to take place over the next three years.
OTHER
Research and Development: Wisconsin Electric had immaterial research and development expenditures in the last three years, primarily for improvement of service and abatement of air and water pollution by the 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, we had the following number of employees:
The employees represented under labor agreements were with the following bargaining units as of December 31, 2004.
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During 2004, labor and management successfully renegotiated six contracts covering 3,140 employees.
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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.
UTILITY ENERGY SEGMENT
Effective January 1, 2001, Wisconsin Electric and Edison Sault exited the electric transmission business by contributing all of their transmission assets to ATC in exchange for equity interests in this new company. For further information, see “Electric Utility Operations” in Item 1.
Wisconsin Electric: As of December 31, 2004, Wisconsin Electric owns the following generating stations with dependable capabilities during 2004 as indicated.
As of December 31, 2004, Wisconsin Electric operated approximately 21,900 pole-miles of overhead distribution lines and 20,400 miles of underground distribution cable, as well as approximately 352 distribution substations and 267,700 line transformers.
As of December 31, 2004, Wisconsin Electric’s gas distribution system included approximately 8,983 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. Wisconsin Electric has 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. Wisconsin Electric also has 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 distribution lines and services and gas distribution mains and services occupy private property, Wisconsin Electric has obtained consents, permits or easements for these installations from owners of those properties, generally without an examination of ownership records.
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As of December 31, 2004, 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, 9 miles of walkable tunnels and other pressure regulating equipment.
Wisconsin Electric owns various office buildings and service centers throughout its service area.
Wisconsin Gas: Wisconsin Gas owns a distribution system which, as of December 31, 2004, included approximately 10,400 miles of distribution and transmission mains connected at gate stations to the pipeline transmission systems of ANR Pipeline Company, Guardian, Northern Natural Pipeline Company, Viking Gas Transmission and Michigan Consolidated Gas Company. Wisconsin Gas has 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 3,600 dekatherms per day. Wisconsin Gas also has a propane air system for peaking purposes. This propane air system will provide approximately 2,400 dekatherms per day of supply to the system. Wisconsin Gas’ distribution system consists almost entirely of plastic and coated steel pipe. Wisconsin Gas owns office buildings in certain communities in which it serves, gas regulating and metering stations, peaking facilities and its major service centers, including garage and warehouse facilities.
Where distribution mains and services occupy private property, Wisconsin Gas in some, but not all, instances has obtained consents, permits or easements for these installations from the apparent owners or those in possession, generally without an examination of title.
Edison Sault: Edison Sault’s primary source of electric energy is its 30-megawatt hydroelectric generating plant on the St. Marys River in Sault Ste. Marie, Michigan. In addition, Edison Sault owns and operates a 4.8-megawatt diesel-based peaking power plant.
Edison Sault maintains approximately 859 miles of primary distribution lines and renders service to its customers through approximately 9,755 line transformers.
NON-UTILITY ENERGY SEGMENT
We Power: We Power commenced construction of the first 545-megawatt natural gas unit of the Port Washington Generating Station in July 2003, and commenced site preparation for construction of the second 545-megawatt natural gas unit in May 2004. We Power also received authorization from the PSCW to build two 615-megawatt coal plants at our Oak Creek site. This authorization has been vacated by the Dane County Circuit Court. For information about Power the Future, see “Factors Affecting Results, Liquidity and Capital Resources - Power the Future” in Item 7.
Wisvest Corporation: Wisvest owns a chilled water production and distribution facility located in Milwaukee County, Wisconsin. Calumet Energy Team, LLC owns a 308-megawatt peaking power plant in Chicago, Illinois.
OTHER
Wispark LLC: As of December 31, 2004, Wispark properties, owned in full or through minority interests in joint ventures, included the following commercial and industrial parks in the state of Wisconsin: LakeView Corporate Park located near Kenosha, Wisconsin; Business Park of Kenosha and PrairieWood Corporate Park in Kenosha County; GrandView Business Park in Racine County; and Mitchell International Business Park in Milwaukee County. Wispark developed Gaslight Pointe, a residential and commercial complex located in Racine. Wispark owns the Radisson Hotel and Conference Center near Kenosha, as well as other properties located in Wisconsin Electric’s service territories that are held for future development or sale. Wispark also owns property in Northwest Business Park in Elgin, Illinois and is a minority owner in an industrial park located in Gurnee, Illinois.
Minergy Corp.: Minergy owns a Glass Aggregate facility located in Neenah, Wisconsin and a GlassPack facility in Winneconne, Wisconsin.
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Wisconsin Energy Capital Corporation: WECC owns a commercial office building in Milwaukee, Wisconsin. WECC, in combination with Wispark, owns three low income housing developments located in Milwaukee, Kenosha and Neenah, Wisconsin.
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, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material adverse effect on our financial statements.
ENVIRONMENTAL MATTERS
We are subject to federal, state and certain local laws and regulations governing the environmental aspects of our operations. Management believes that, perhaps with immaterial exceptions, our existing facilities are in compliance with applicable environmental requirements.
EPA Information Requests: Wisconsin Electric and Wisconsin Gas responded to an EPA request for information pursuant to Comprehensive Environmental Response, Compensation and Liability Act 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 Wisconsin Electric owned a parcel of property that is within the property boundaries of the site. A predecessor company of Wisconsin Gas had a customer and corporate relationship with the entity that owned and operated the site, Milwaukee Solvay Coke Company. Although neither company has 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 S - Commitments and Contingencies” in the Notes to Consolidated Financial Statements in Item 8.
See “Environmental Compliance” in Item 1 and “Environmental Matters,” “Manufactured Gas Plant Sites,” “Ash Landfill Sites” and “EPA Information Requests” in Note S- “Commitments and 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 “Factors Affecting Results, Liquidity and Capital Resources - Utility Rates and Regulatory Matters” and “Power the Future” in Item 7 for information concerning rate matters in the jurisdictions where Wisconsin Electric, Wisconsin Gas and Edison Sault do business.
OTHER MATTERS
Used Nuclear Fuel Storage and Removal: See “Factors Affecting Results, Liquidity and Capital Resources – Nuclear Operations” in Item 7 for information concerning the United States Department of Energy’s breach of a contract with Wisconsin Electric 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 Wisconsin Electric for loss of milk production and other damages to livestock allegedly caused by stray voltage resulting from the operation of its electrical system.
On June 25, 2003, the Wisconsin Supreme Court upheld a Court of Appeals decision that affirmed a jury’s verdict against Wisconsin Electric, awarding $1.2 million to the plaintiffs in a stray voltage lawsuit. The Wisconsin
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Supreme Court rejected the argument that if a utility company’s measurement of stray voltage is below the PSCW “level of concern,” such 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 Wisconsin Electric 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 Wisconsin Electric’s distribution system caused damages to his livestock. Wisconsin Electric has filed an appeal in this decision. The claim made against Wisconsin Electric in this case is not expected to have a material adverse effect on our financial statements. One other stray voltage case is pending against Wisconsin Electric and is currently scheduled for trial in the summer of 2005. For additional information, see “Factors Affecting Results, Liquidity and Capital Resources - Legal 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. Wisconsin Electric and Edison Sault believe that their facilities are constructed and operated in accordance with applicable legal requirements and standards. Currently, there are no cases pending or threatened against Wisconsin Electric or Edison Sault with respect to damage caused by electromagnetic fields.
For information regarding additional legal matters, see “Factors Affecting Results, Liquidity and Capital Resources - Legal Matters” in Item 7.
No matters were submitted to a vote of our security holders during the fourth quarter of 2004.
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages at December 31, 2004 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 its predecessor, Wisconsin Gas Company.
Gale E. Klappa. Age 54.
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EXECUTIVE OFFICERS OF THE REGISTRANT – (Cont’d)
Charles R. Cole. Age 58.
Stephen P. Dickson. Age 44.
Frederick D. Kuester. Age 54.
Allen L. Leverett. Age 38.
Kristine A. Rappé. Age 48.
Larry Salustro. Age 57.
Certain executive officers also hold offices in our non-utility subsidiaries.
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PART II
NUMBER OF COMMON STOCKHOLDERS
As of December 31, 2004, based upon the number of Wisconsin Energy Corporation stockholder accounts (including accounts in our dividend reinvestment and stock purchase plan), we had 58,168 registered stockholders.
COMMON STOCK LISTING AND TRADING
Our common stock is listed on the New York Stock Exchange. The ticker symbol is “WEC”. Daily trading prices and volume can be found in the “NYSE Composite” section of most major newspapers, usually abbreviated as WI Engy.
DIVIDENDS AND COMMON STOCK PRICES
Common Stock Dividends of Wisconsin Energy: Cash dividends on our common stock, as declared by the Board of Directors, are normally paid on or about the first day of March, June, September and December of each year. We review our dividend policy on a regular basis. Subject to any regulatory restrictions 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. For information regarding restrictions on the ability of our subsidiaries to pay us dividends see “Note I - Common Equity” in the Notes to Consolidated Financial Statements in Item 8.
On January 20, 2005, our Board of Directors announced that it increased our common stock quarterly dividend rate by 4.8%, to $0.22 per share. With the increase, the new annual dividend rate will be $0.88 per share. The Board has established a goal of increasing the annual dividend at a rate of approximately half of the expected rate of growth in earnings, subject to the factors referred to above.
Range of Wisconsin Energy Common Stock Prices and Dividends:
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ISSUER PURCHASES OF EQUITY SECURITIES
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WISCONSIN ENERGY CORPORATION CONSOLIDATED SELECTED FINANCIAL AND STATISTICAL DATA
CONSOLIDATED SELECTED QUARTERLY FINANCIAL DATA (Unaudited)
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WISCONSIN ENERGY CORPORATION CONSOLIDATED SELECTED UTILITY OPERATING DATA
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CORPORATE DEVELOPMENTS
INTRODUCTION
Wisconsin Energy Corporation is a diversified holding company with subsidiaries primarily in a utility energy segment and a non-utility energy segment. Unless qualified by their context, when used in this document the terms Wisconsin Energy, the Company, our, us or we refer to the holding company and all of our subsidiaries.
Our utility energy segment, consisting of Wisconsin Electric Power Company (Wisconsin Electric) and Wisconsin Gas LLC (Wisconsin Gas), both doing business under the trade name of “We Energies”, and Edison Sault Electric Company (Edison Sault), is engaged primarily in the business of generating electricity and distributing electricity and natural gas in Wisconsin and the Upper Peninsula of Michigan. Our non-utility energy segment primarily consists of W.E. Power, LLC (We Power) and Wisvest Corporation (Wisvest). We Power is principally engaged in the engineering, construction and development of electric power generating facilities for long-term lease to Wisconsin Electric.
Cautionary Factors: Certain statements contained herein are “Forward-Looking Statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-Looking Statements include, among other things, statements regarding management’s expectations and projections regarding completion of construction projects, regulatory matters, fuel costs, sources of electric energy supply, gas deliveries, remediation costs, environmental and other capital expenditures, liquidity and capital resources and other matters. Also, Forward-Looking Statements may be identified by reference to a future period or periods or by the use of forward looking terminology such as “anticipates,” “believes,” “estimates,” “expects,” “forecasts,” “intends,” “may,” “objectives,” “plans,” “possible,” “potential,” “projects” or similar terms or variations of these terms. Actual results may differ materially from those set forth in Forward-Looking Statements as a result of certain risks and uncertainties, including but not limited to, those risks and uncertainties described under the heading “Cautionary Factors” in this Item 7, as well as other matters described under the heading “Factors Affecting Results, Liquidity and Capital 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.
CORPORATE STRATEGY
Business Opportunities
We seek to increase shareholder value by leveraging on our core competencies. Our key corporate strategy, announced in September 2000, is Power the Future. This strategy is designed to address Wisconsin’s growing electric supply needs by increasing the electric generating capacity in the state while maintaining a fuel-diverse, reasonably priced electric supply. It is also 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. Our Power the Future strategy, which is discussed further below, is expected to have a significant impact on our utility and non-utility energy segments. Since 2000, we have been selling our non-core assets to direct more attention to the utility business and to finance Power the Future while reducing our debt.
Utility Energy Segment: We are realizing operating efficiencies in this segment through the integration of the operations of Wisconsin Electric and Wisconsin Gas. These operating efficiencies should increase customer satisfaction and reduce operating costs. In connection with our Power the Future strategy, we are improving our existing energy distribution systems and upgrading existing electric generating assets. We plan to increase our generating capacity through the new facilities that We Power is constructing.
Non-Utility Energy Segment: We are primarily focusing this segment on improving the supply of electric generation in Wisconsin. We Power was formed to design, construct, own, finance and lease new generation assets under the Power the Future strategy. We have divested of the majority of Wisvest’s assets in order to direct capital and management’s attention to Power the Future.
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Power the Future Strategy: In February 2001, we filed a petition with the Public Service Commission of Wisconsin (PSCW) that would allow us to begin implementing our 10-year Power 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. Under Power the Future, we plan to add new coal-fired and natural gas-fired generating capacity to the state’s power portfolio which would allow Wisconsin Electric to maintain approximately the same fuel mix as exists today. As part of our Power the Future strategy, we plan to (1) invest a net of approximately $2.5 billion in 2,120 megawatts of new natural gas-fired and coal-fired generating capacity at existing sites; (2) upgrade Wisconsin Electric’s existing electric generating facilities and (3) invest in upgrades of our existing energy distribution system.
Subsequent to our February 2001 filing, the state legislature amended several laws, making changes which are critical to the implementation of Power the Future. In October 2001, the PSCW issued a declaratory ruling finding, among other things, that it was prudent to proceed with Power the Future and for us 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, we created We Power to design, construct, own, finance and lease the new generating capacity. Wisconsin Electric will lease each new facility from We Power as well as operate and maintain the new plants under 25 to 30-year lease agreements approved by the PSCW. Based upon the structure of the leases, we expect to recover the initial investments in We Power’s new facilities over the initial lease term. At the end of the leases, Wisconsin Electric will have the right to acquire the plants outright at market value or to renew the leases. Wisconsin Electric expects that all lease payments and operating costs of the plants will be recoverable in rates under the provisions of the Wisconsin Leased Generation Law.
Under our Power the Future strategy, we expect to meet a significant portion of our future generation needs through We Power’s construction of the Port Washington and Elm Road generating stations.
As of December 31, 2004, we:
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We expect to finance the majority of our Power the Future strategy with internally generated cash and debt financings. Additionally, in the future we expect to have some limited asset sales, but at levels significantly below the prior five year level. We expect to maintain our debt to total capital ratio at no more than 61.5% during the period we are constructing our new gas- and coal- fired generation plants. We currently do not plan to issue any new equity as part of our Power the Future financing plan.
Our primary risks under Power the Future are associated with successful, timely resolution of court challenges of our Elm Road facility, timely receipt of remaining permits for Elm Road, and construction risks associated with the schedule and costs for both our Elm Road and Port Washington generating stations.
For further information concerning Power the Future capital requirements, see “Liquidity and Capital Resources.” You can find additional information regarding risks associated with the Power the Future strategy, as well as the regulatory process, specific regulatory approvals and associated legal challenges in “Factors Affecting Results, Liquidity and Capital Resources” below.
Divestiture of Non-Core Assets
Our Power the Future strategy led to a decision to divest non-core businesses. These non-core businesses primarily included non-utility generation assets located outside of the Midwest and a substantial amount of Wispark’s real estate portfolio, as well as the manufacturing business. Since 2000, we have received total proceeds of approximately $1.97 billion from the divestiture of non-core assets as follows:
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RESULTS OF OPERATIONS
CONSOLIDATED EARNINGS
The following table compares our operating income by business segment and our net income for 2004, 2003 and 2002.
2004 vs. 2003: Our diluted earnings per share were $2.57 during 2004 compared with $2.06 per share during 2003. During 2004, our diluted earnings per share were positively impacted by $1.28 per share due to the gain on the sale of our manufacturing business offset in part by non-cash, non-utility asset valuation charges of $0.81 per share, severance costs of $0.16 per share primarily in our utility energy segment, and debt redemption costs of $0.13 per share. During 2003, our diluted earnings per share were negatively impacted by non-cash, non-utility asset valuation charges of $0.32 per share partially offset by $0.07 of gain on the sale of non-utility investments.
2003 vs. 2002: Our diluted earnings per share of $2.06 during 2003 was $0.62 per share higher than the $1.44 per share earned during 2002. As noted above, our 2003 earnings were negatively impacted by non-cash, non-utility asset valuation charges of $0.32 per share partially offset by $0.07 of gain on non-utility investments. During 2002, our diluted earnings per share were negatively impacted by non-cash, non-utility asset valuation charges of $0.79 per share.
An analysis of contributions to operating income by segment follows.
UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME
2004 vs. 2003: Our utility energy segment contributed $528.6 million of operating income during 2004 compared with $544.1 million of operating income during 2003. 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: Utility energy segment operating income during 2003 decreased by $18.0 million compared with 2002. The decline in utility operating income was 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 our Power the Future growth strategy. This decline was somewhat mitigated by a March 2003 rate increase associated with fuel and purchased power expenses, higher gas margins, growth in our base electric
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business and litigation settlements in 2002 compared with the receipt of insurance recoveries in 2003, primarily related to the Giddings & Lewis/City of West Allis litigation.
The following table summarizes our utility energy segment’s operating income during 2004, 2003 and 2002.
Electric Utility Gross Margin
The following table compares our electric utility gross margin during 2004 with similar information for 2003 and 2002, including a summary of electric operating revenues and electric sales by customer class.
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Electric Utility Revenues and Sales
2004 vs. 2003: During 2004, our total electric utility operating revenues increased by $85.4 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, Wisconsin Electric received an order from the PSCW authorizing an annualized increase in electric rates of approximately $59.5 million to cover construction costs associated with our Power the Future program and to recover low income uncollectible expenses transferred to Wisconsin’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 465.0 thousand megawatt-hours or 1.5% between 2004 and 2003. Residential sales were down 0.6%, and small commercial/industrial sales were up just 1.1% 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 1.5%. Sales to municipal utilities, the other retail/municipal customer class, increased 8.1% between the periods due to higher off-peak demand from low-margin municipal wholesale power customers.
2003 vs. 2002: During 2003, total electric utility operating revenues increased by $102.8 million or 5.4% when compared with 2002, primarily due to the impact of rate increases related to fuel and purchased power costs and to a surcharge related to transmission costs. The total rate impact was approximately $83.3 million in 2003. In March 2003, Wisconsin Electric received an interim increase in rates of $55.1 million annually to recover increases in fuel and purchased power costs. In October 2003, we received the final rate order, which authorized an additional $6.1 million of annual revenues. In spite of the interim fuel order, we under recovered fuel costs by approximately $7.6 million during 2003, which is approximately $5.3 million worse than our under recovery during 2002. Much of our under recovery of fuel costs during 2003 can be attributed to the need to purchase replacement power in May and June of 2003 due to a flood at 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 million between the comparative periods.
Total electric megawatt-hour sales increased by 1.0% during 2003. Residential sales fell 2.5% due to the impact of unfavorable weather conditions on cooling load during the second and third quarters of 2003. Sales to Wisconsin Electric’s 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 sales in the second and fourth quarters of 2003 resulting from a flood-related outage at our Presque Isle Power Plant 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 0.4%. Sales to municipal utilities, the other retail/municipal customer class, increased 8.5% between the periods due to higher off-peak demand from low-margin municipal wholesale power customers.
Electric Fuel and Purchased Power Expenses
2004 vs. 2003: Total fuel and purchased power expenses for our electric utilities increased by $22.2 million or 3.9% 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 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.
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2003 vs. 2002: During 2003, total fuel and purchased power expenses increased $72.8 million or 14.9% 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 2004, 2003 and 2002.
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 2004, 2003 and 2002.
2004 vs. 2003: Our total gas utility gross margin fell slightly from $362.8 million in 2003 to $361.5 million in 2004 due largely to a decrease in therm deliveries resulting from less favorable weather. Total therm deliveries were 4.7% 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 $12.9 million between the comparative periods. Our gas margins were favorably impacted by a price increase that became effective in February 2004. This annual price increase of $25.9 million favorably impacted gas margins by $19.6 million in 2004. However, in 2004, we recognized $8.8 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 $19.6 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 $7.4 million increase in gas cost incentive revenues during 2003 under our gas cost recovery mechanism
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also contributed to the increased gross margin and operating revenues between the comparative periods. Total therm deliveries of natural gas increased by 2.4% during 2003 but varied within customer classes. Volume deliveries for the residential and commercial/industrial customer classes increased by 4.5% and 6.3%, respectively, reflecting the colder weather.
Other Operation and Maintenance Expenses
2004 vs. 2003: Other operation and maintenance expenses increased by $72.0 million or 8.1% 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 our Power the Future plan. Under the lease agreement, Wisconsin Electric is 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. In addition to the lease costs, we also recognized $12.8 million of increased public benefits costs which were also included in the May 2004 price increase.
In addition, our benefit costs increased $15.0 million due to increased pension and medical costs. We also incurred $28.2 million of severance-related costs during 2004, primarily due to a Voluntary Separation Plan which was offered to certain management and represented employees in the second half of 2004. Partially offsetting these increases was an $11.9 million reduction in bad debt costs due to improved collections and the timing of a deferral order.
2003 vs. 2002: During 2003, our other operation and maintenance expenses increased by $60.8 million or 7.3% when compared with 2002. The increase was primarily attributable to approximately $39.4 million of higher electric transmission expenses. A surcharge for transmission costs that was approved by the PSCW in October 2002 offset the impact of higher transmission expenses. Pension, medical and other benefit costs increased by approximately $30 million during 2003. Overall, nuclear costs were $8.7 million higher during 2003 compared with 2002 due to an extended outage and costs associated with supplemental inspections at Point Beach 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 2002 on the implementation of our Power the Future strategy.
NON-UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME
As part of our ongoing efforts to divest non-core assets, we have significantly reduced Wisvest’s operations since 2002. The following table compares our non-utility energy segment’s operating loss during 2004, 2003 and 2002.
2004 vs. 2003: Our non-utility energy operating losses increased from $61.5 million during 2003 to $120.4 million during 2004, primarily because of a non-cash asset valuation charge of $122.0 million in the third quarter of 2004
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associated with our Calumet Energy facility. During 2003, we recorded $59.5 million of non-cash asset valuation charges related to our investment in an entity that owns a co-generation plant in Maine (Androscoggin) and to a natural gas power island which we sold in the fourth quarter of 2003. In 2003, we also realized gains on the sale of non-utility energy assets of $10.5 million.
2003 vs. 2002: The significant decline in operating revenues, fuel and purchased power and other operation and maintenance expenses during 2003 is directly related to our sale of Wisvest-Connecticut in December 2002, which had operating earnings of $16.8 million in 2002.
The operating loss incurred in 2003 included total asset valuation charges of $59.5 million offset in part by gains on the sale of assets of $10.5 million. The asset valuation charges recorded in 2003 relate to our investment in Androscoggin and to costs associated with a 500-megawatt natural gas power island. In 2002 we recorded a non-cash asset valuation charge of which $125.1 million related to the non-utility energy segment.
CORPORATE AND OTHER CONTRIBUTION TO OPERATING INCOME
The following table identifies the components of operating loss attributable to our corporate operations and to other affiliates during 2004, 2003 and 2002.
2004 vs. 2003: We had net corporate and other affiliate operating losses of $28.4 million during 2004 compared with net operating losses of $0.4 million in 2003. The change reflects a non-cash valuation charge of $27.0 million in the third quarter of 2004 related to our Minergy-Neenah facility.
2003 vs. 2002: We realized net operating losses of $0.4 million in 2003 from corporate and other affiliate operations compared to a net operating loss of $29.7 million in 2002. This change primarily reflects a $2.7 million gain from the sale of investment assets in the third quarter of 2003 and a non-cash asset valuation charge of $16.4 million recorded in 2002 related to the decline in value of a venture capital investment.
CONSOLIDATED OTHER INCOME AND DEDUCTIONS, NET
2004 vs. 2003: Net consolidated other income and deductions decreased by $26.1 million in 2004 compared to 2003, primarily due to $22.9 million of debt redemption costs incurred during 2004. In connection with the sale of our manufacturing business, we used most of the proceeds to retire short and long-term debt. These increased costs were partially offset by an $8.7 million increase in our interest in the earnings of unconsolidated affiliates during 2004.
2003 vs. 2002: Net consolidated other income and deductions decreased by $1.5 million in 2003 compared to 2002. This decrease is primarily due to $21.1 million ($12.7 million after tax) in Statement of Financial Accounting Standard (SFAS) 133 gains recognized in 2002 on fuel oil contracts at Wisvest-Connecticut’s two power plants which were sold in December 2002, a $3.2 million civil penalty we agreed to pay in 2003 pursuant to the terms of a consent decree with the U.S. Environmental Protection Agency (EPA) and higher returns associated with investments in rabbi trusts.
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CONSOLIDATED INTEREST EXPENSE
2004 vs. 2003: Total interest expense decreased by $20.4 million in 2004 compared with 2003. This decrease primarily reflects the reduction in debt levels due to the retirement of debt with the proceeds from the sale of our manufacturing business, which was effective July 31, 2004. From December 31, 2003 to December 31, 2004, we reduced our debt levels by $654.2 million or 15%.
2003 vs. 2002: Total interest expense decreased by $13.3 million in 2003 compared to 2002. This decline was due to a combination of reduced average debt levels, increased capitalized interest and lower interest rates.
CONSOLIDATED INCOME TAXES
2004 vs. 2003: In 2004, our effective income tax rate from continuing operations was 39.6% compared with a 35.5% rate during 2003. The increase in the effective income tax rate is due primarily to the inability to receive a state tax benefit from the $150.4 million of asset valuation charges which were recorded in 2004.
2003 vs. 2002: Our effective tax rate applicable to continuing operations was 35.5% compared with a 39.3% rate during 2002. This decrease was primarily related to the inability to deduct state income taxes on losses of certain non-utility subsidiaries. In 2002, we had $141.5 million of asset impairment charges which did not receive a state tax benefit as compared with $45.6 million of net impairment charges in 2003.
DISCONTINUED OPERATIONS
In 2004, we showed our manufacturing business as a discontinued operation, and it was sold effective July 31, 2004. All prior years have been restated to show the manufacturing business as a discontinued operation. During 2004, this business earned $31.9 million of net income from operations for the seven months that we owned this business. This compares with net income of $43.9 million and $35.3 million for twelve months of operations during 2003 and 2002, respectively. In 2004, we recorded a gain of $152.3 million on the sale of the manufacturing business.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS
The following table summarizes our cash flows during 2004, 2003 and 2002:
Operating Activities
Cash provided by operating activities increased to $598.7 million during 2004 compared with $529.9 million during the same period in 2003. This increase was due in large part to stronger cash earnings (net earnings plus non-cash valuation charges) as well as improvements in working capital.
Cash provided by operating activities decreased to $529.9 million during 2003 compared with $660.9 million during the same period in 2002. This decrease was primarily due to a $116 million refund received in the first quarter of 2002 from a favorable court ruling in the Giddings & Lewis/City of West Allis litigation and an increase in the use of working capital in 2003.
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Investing Activities
During 2004, we had $243.1 million of net cash inflows from investing activities. In 2003 and 2002, we had net cash outflows from investing activities of $596.2 million and $382.5 million, respectively. The most significant investing activities relate to the sale of assets, particularly the sale of the manufacturing business, and capital expenditures. In connection with our growth strategy which was announced in 2000, we have been focusing on divesting non-core assets and investing in core regulated assets.
The following table identifies capital expenditure by year:
The increase in capital expenditures at We Power reflects the increased construction activity related to the first unit at Port Washington which is expected to be in service early in the third quarter of 2005. In addition, during 2004 we incurred expenditures for the second unit at Port Washington, as well as limited expenditures associated with the Elm Road coal units.
The following table identifies cash proceeds from asset sales:
A significant amount of the net proceeds from asset sales was used to retire debt.
Financing Activities
The following table summarizes our cash flows from financing activities:
During 2004, the proceeds from asset sales as well as improved cash flows from operations allowed us to retire $654.2 million of debt, including $200 million of 6.85% Trust Preferred Securities and $300 million of 5.875%
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senior notes due April 1, 2006. For further information regarding our long-term debt issuances, redemptions and refinancings, see “Note J - Long-Term Debt” in the Notes to Consolidated Financial Statements.
In September 2000, the Board of Directors amended the common stock repurchase program to authorize us to purchase up to $400 million of our shares of common stock in the open market. In March 2004, we announced that under this plan we would resume purchasing approximately $50 million of our common shares in the open market with the proceeds from the sale of the manufacturing business, which was effective July 31, 2004. During 2004, we purchased approximately 1.6 million shares of common stock for $50.4 million under this plan. We ceased repurchasing shares in October 2004. The program expired in December 2004. Over the life of the plan we repurchased and retired 14.9 million shares at a cost of $344.0 million.
During January and February 2004, we issued approximately 0.2 million new shares of common stock in connection with our dividend reinvestment plan and various employee benefit plans. In 2003 and 2002, we issued approximately 2.7 million new shares of common stock in each of those years in connection with these plans. In 2004, 2003 and 2002, we received payments aggregating $4.8 million, $62.9 million and $52.6 million, respectively. In February 2004, we announced that we did not expect to issue new shares under these programs; rather we instructed the plan agents to begin purchasing the shares in the open market in lieu of issuing new shares. During 2004, our plan agents purchased 3.2 million shares at a cost of $102.3 million to fulfill exercised stock options. In 2004, we received proceeds of $66.1 million related to the exercise of stock options. Prior to February 2004, we issued new shares to fulfill these obligations.
CAPITAL RESOURCES AND REQUIREMENTS
In 2000, we announced a growth strategy which, among other things, called for us to sell non-core assets. The proceeds from these asset sales were used to retire debt and help fund capital expenditures in our other businesses. During the five years ended December 31, 2004, we received $1.97 billion in proceeds from asset sales. Since announcing the growth strategy in September 2000, our debt to total capital ratio has decreased from 68.3% at September 30, 2000 to 59.3% at December 31, 2004. Over the next several years, we expect to have some limited asset sales, but at levels significantly below the prior five year level.
In 2002, we initiated the construction of the first of our four planned power plants under our Power the Future program. We expect to spend over $2.8 billion if all four plants are approved. We expect that two unaffiliated entities will collectively invest approximately $330 million in the Power the Future coal units and receive an ownership interest of approximately 17% in the units or 200 megawatts. If the two unaffiliated entities choose to participate in the coal units, our net investment would be approximately $2.5 billion. Over the next several years, we expect to fund these plants with cash from operations and debt offerings.
Capital Resources
We anticipate meeting our capital requirements during 2005 primarily through internally generated funds and short-term borrowings, supplemented by the issuance of intermediate or long-term debt securities depending on market conditions and other factors. Beyond 2005, we anticipate meeting our capital requirements through internally generated funds supplemented, when required, by the issuance of debt securities and construction financing.
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, Wisconsin Electric 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 Wisconsin Electric 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
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subject to further PSCW approval prior to issuance. In January 2005, we notified the PSCW that we would not issue environmental trust bonds until the satisfactory resolution of tax rulings associated with the proposed securitization and the resolution of the Elm Road proceedings before the Wisconsin State Supreme Court. The issuance would also be dependent upon market conditions.
Wisconsin Energy, Wisconsin Electric and Wisconsin Gas credit agreements provide liquidity support for each company’s obligations with respect to commercial paper.
As of December 31, 2004, we had approximately $1.2 billion of available unused lines of bank back-up credit facilities on a consolidated basis and approximately $338 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:
On June 23, 2004, Wisconsin Energy entered into an unsecured three year $300 million bank back-up credit facility to replace a $300 million 364 day credit facility that was expiring. This facility will expire in June 2007 and may be extended for an additional 364 days, subject to lender agreement.
On June 23, 2004, Wisconsin Electric 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 and may be extended for an additional 364 days, subject to lender agreement.
On June 23, 2004, Wisconsin Gas entered into an unsecured three year $200 million bank back-up credit facility to replace a $200 million 364 day credit facility that was expiring. This facility will expire in June 2007 and may be extended for an additional 364 days, subject to lender agreement.
On November 1, 2004, Wisconsin Electric entered into an unsecured three year $125 million bank back-up 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.
The following table shows our consolidated capitalization structure at December 31:
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As described in “Note I - Common Equity” in the Notes to Consolidated Financial Statements, certain restrictions exist on the ability of our subsidiaries to transfer funds to us. We do not expect these restrictions to have any material effect on our operations or ability to meet our cash obligations.
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 the debt securities and preferred stock of our subsidiaries by Standard & Poors Corporation (S&P), Moody’s Investors Service (Moody’s) and Fitch as of December 31, 2004.
The security rating outlooks assigned by S&P, Moody’s and Fitch for Wisconsin Energy, Wisconsin Electric, Wisconsin Gas and Wisconsin Energy Capital Corporation are all stable.
In March 2003, S&P lowered its corporate credit ratings for us from A- to BBB+ and for Wisconsin Electric and Wisconsin Gas, both from A to A-. S&P lowered its ratings for our senior unsecured debt from A- to BBB+; for Wisconsin Electric’s senior secured debt from A to A- and for Wisconsin Gas’ senior unsecured debt from A to A-. S&P affirmed Wisconsin Electric’s A- senior unsecured debt rating. S&P lowered the rating for our preferred stock from BBB to BBB- and for Wisconsin Electric’s preferred stock from BBB+ to BBB. S&P affirmed the A-2 short-term rating of us and lowered the short-term ratings of both Wisconsin Electric and Wisconsin Gas from A-1 to A-2. Wisconsin Electric’s senior secured and senior unsecured debt are both rated A- by S&P. S&P assigned a stable outlook.
In October 2003, Moody’s downgraded certain of our security ratings and the security ratings of our subsidiaries. Moody’s lowered the senior unsecured debt ratings of Wisconsin Energy and Wisconsin Energy Capital Corporation from A2 to A3 and our commercial paper rating from P-1 to P-2. Moody’s lowered Wisconsin Electric’s senior secured debt rating from Aa2 to Aa3, senior unsecured debt rating from Aa3 to A1 and preferred stock rating from A2 to A3. Moody’s lowered Wisconsin Gas’ senior unsecured debt rating from Aa2 to A1. Moody’s confirmed the P-1 commercial paper ratings of Wisconsin Electric and Wisconsin Gas. In February 2004, Moody’s changed the rating outlook for Wisconsin Energy and Wisconsin Energy Capital Corporation to stable from negative. The rating outlook for Wisconsin Electric and Wisconsin Gas is stable.
In October 2003, Fitch downgraded certain of our security ratings and the security ratings of our subsidiaries. Fitch lowered the senior unsecured debt ratings of Wisconsin Energy and Wisconsin Energy Capital Corporation from A to A- and the commercial paper rating of Wisconsin Energy from F1 to F2. Fitch lowered Wisconsin Electric’s senior secured debt rating from AA to AA-, senior unsecured rating from AA- to A+ and preferred stock rating from AA- to A. Fitch lowered Wisconsin Gas’ senior unsecured debt rating from AA- to A+. Fitch lowered the commercial paper ratings of Wisconsin Electric and Wisconsin Gas from F1+ to F1. The rating outlook for Wisconsin Energy, Wisconsin Electric, Wisconsin Gas and Wisconsin Energy Capital Corporation is stable.
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We believe these security ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agencies only. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell or hold securities, but rather an indication of creditworthiness. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating should be evaluated independently of any other rating.
Capital Requirements
Total capital expenditures, excluding the purchase of nuclear fuel, are currently estimated to be $823.7 million during 2005 attributable to the following operating segments:
Due to changing environmental and other regulations such as air quality standards and electric reliability initiatives that impact our utility energy segments, future long-term capital requirements may vary from recent capital requirements. Our utility energy segment currently expects capital expenditures, excluding the purchase of nuclear fuel and expenditures for new generating capacity contained in our Power the Future strategy described below, to be between $400 million and $500 million per year during the next five years.
Our estimated capital requirements through 2010 for Power the Future include a net of approximately $2.5 billion to construct 2,120 megawatts of new natural gas-fired and coal-fired generating capacity of which we have expended approximately $414.9 million through the end of 2004. We expect that two unaffiliated entities will collectively invest approximately $330 million in the Power the Future coal units and receive an ownership interest of approximately 17% in the units or 200 megawatts. Total cost of all four units, including the two unaffiliated entities’ portion, is estimated to be $2.8 billion with total output at 2,320 megawatts.
We expect the capital requirements to support our investment in new generation under Power the Future to come from a combination of internal and external sources. The new generating plants will be constructed by We Power, a non-utility subsidiary, and leased to Wisconsin Electric under 25-30 year lease agreements. We expect that Wisconsin Electric will recover the lease payments in its utility rates. We anticipate that we will need external debt financing as the plants are constructed. We believe that the construction debt, cash flows from the lease payments and strong internal cash flow will be sufficient to fund our Power the Future capital expenditures.
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 that exceeded $1.9 billion as of December 31, 2004. These trusts hold investments that are subject to the volatility of the stock market and interest rates. For further information see “Note O – Benefits” in the Notes to Consolidated Financial Statements.
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 construction projects, commodity contracts and other payment obligations. We believe that these agreements do not have, and are not reasonably likely to have, a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to our investors. For further information, see “Note P – Guarantees” in the Notes to Consolidated Financial Statements.
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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. We have included our contractual obligations under all three of these contracts in our “Contractual Obligations/Commercial Commitments” disclosure that follows. For additional information, see “Note D - Variable Interest 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:
Obligations for utility operations by our utility affiliates have historically been included as part of the rate making process and therefore are generally recoverable from customers.
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 the Port Washington Generating Station (Port Washington units) consisting of two 545-megawatt natural gas-fired combined cycle generating units on the site of Wisconsin Electric’s existing Port Washington Power Plant. The order approves key financial terms of the leased generation contracts including fixed construction cost of the two Port Washington units at $309.6 million and $280.3 million (2001 dollars), respectively, subject to escalation at the GDP inflation rate and force majeure and excused events provisions.
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In addition, in November 2003, the PSCW issued a written order granting a CPCN to commence construction of two 615-megawatt super critical pulverized coal generating units (Elm Road units) on the site of Wisconsin Electric’s existing Oak Creek Power Plant. The order approves key financial terms of the leased generation contracts including fixed construction cost of the two Elm Road units. For additional information, see “Power the Future - Elm Road” below.
Large construction projects of this type are subject to usual construction risks over which we will have limited or no control and which might adversely affect project costs and completion time. These risks include, but are not limited to, shortages of, the inability to obtain or the cost of labor or materials, the inability of the general contractor or subcontractors to perform under their contracts, strikes, adverse weather conditions, the inability to obtain necessary permits in a timely manner and changes in applicable laws or regulations, governmental actions and events in the global economy. If final costs for the construction of the Port Washington units or the Elm Road units exceed the fixed costs allowed in the PSCW order, this excess cannot be recovered from Wisconsin Electric or its customers unless specifically allowed by the PSCW. Project costs above the authorized amount, but below the 5% cap will be subject to a prudence determination by the PSCW.
Regulatory Recovery Risk: The electric operations of Wisconsin Electric burn natural gas in several of its peaking power plants or as a supplemental fuel at several coal-fired plants, and the cost of purchased power is tied to the cost of natural gas in many instances. Wisconsin Electric bears regulatory risk for the recovery of these fuel and purchased power costs when they are higher than the base rate established in its rate structure.
As noted below in Commodity Price Risk, the electric operations of Wisconsin Electric 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 for fuel and purchased power costs, and Wisconsin Electric assumes the risks and benefits of fuel cost variances that are within 3% of the fuel base. Wisconsin Electric is 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 rules to be implemented in the Wisconsin retail jurisdiction. The new rules will not be effective for Wisconsin Electric until January 2006, the end of a five year rate freeze associated with the WICOR Merger Order. Until this time, Wisconsin Electric will operate under an approved transaction mechanism similar to the old fuel cost adjustment procedure. For 2004, 2003 and 2002, actual fuel and purchased power costs at Wisconsin Electric exceeded fuel base rates by $0.8 million, $7.6 million and $2.3 million, respectively. In 2004, 2003 and 2002, the electric rates included a fuel surcharge.
Commodity Price Risk: In the normal course of business, our utility and non-utility power generation subsidiaries utilize contracts of various duration for the forward sale and purchase of electricity. This is done to effectively manage utilization of their available generating capacity and energy during periods when available power resources are expected to exceed the requirements of their 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. We manage our fuel and gas supply costs through a portfolio of short and long-term procurement contracts with various suppliers for the purchase of coal, uranium, natural gas and fuel oil.
Wisconsin’s retail electric fuel cost adjustment procedure mitigates some of Wisconsin Electric’s 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 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 electrical utility gas costs. During 2003, a gas hedging program was approved by the PSCW and implemented by Wisconsin Electric.
The PSCW has authorized dollar for dollar recovery for the majority of natural gas costs for the gas utility operations of Wisconsin Electric and Wisconsin Gas through gas cost recovery mechanisms, which mitigates most of the risk of gas cost variations. For additional information concerning the electric utility fuel cost adjustment
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procedure and the natural gas utilities’ gas cost recovery mechanisms, see “Utility Rates and Regulatory 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 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. 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’s energy supply mix.
Higher natural gas costs increase our working capital requirements, resulting in higher gross receipts taxes in the state 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 has increased.
As a result of gas cost recovery mechanisms, our gas distribution subsidiaries receive dollar for dollar pass through 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.
Weather: The rates of Wisconsin Electric and Wisconsin Gas are set by the PSCW based upon estimated temperatures which approximate 20-year averages. Wisconsin Electric’s 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. The gas revenues of Wisconsin Electric and Wisconsin Gas are unfavorably sensitive to above normal temperatures during the winter heating season. A summary of actual weather information in the utility segment’s service territory during 2004, 2003 and 2002, as measured by degree-days, may be found above in “Results of Operations”.
Temperature can also impact demand for electricity in regions where we have invested in non-utility energy assets or projects.
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. 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, 2004 of our outstanding portfolio of $338.0 million short-term debt with a weighted average interest rate of 2.35% and $187.5 million of variable-rate long-term debt with a weighted average interest rate of 1.88%. A one-percentage point change in interest rates would cause our annual interest expense to increase or decrease by approximately $3.4 million before taxes from short-term borrowings and $1.9 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 utility regulators. However, we are currently operating under a PSCW-ordered, qualified five-year rate restriction period through 2005. For further information about the rate restriction, see “Utility Rates and Regulatory Matters” below.
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At December 31, 2004, we held the following total trust fund assets at fair value, primarily consisting of publicly traded debt and equity security investments.
Fiduciary oversight of the pension and other post-retirement plan trust fund investments is the responsibility of a Chairman-appointed 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%.
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.
Wisconsin Electric insures 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 Wisconsin Electric.
Credit Rating Risk: We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. We do have certain agreements in the form of commodity and energy services contracts and employee benefit plans that could require, in the event of a credit ratings change to below investment grade, a termination payment if collateral is not provided or an accelerated payment. At December 31, 2004, we estimate that the potential payments under these agreements that could result from credit rating downgrades totaled approximately $118.7 million.
Economic Risk. We are exposed to market risks in the regional midwest economy for our utility energy segment.
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.
POWER THE FUTURE
Under our Power the Future strategy, we expect to meet a significant portion of our future generation needs through the construction of the Port Washington and Elm Road generating stations by We Power. The new plants will be leased by We Power to Wisconsin Electric under long-term leases, and we expect Wisconsin Electric to recover the lease payments in its electric rates.
Power the Future - Port Washington
Background: In December 2002, the PSCW issued a written order (the Port Order) granting Wisconsin Energy, Wisconsin Electric and We Power a CPCN to commence construction of the Port Washington Generating Station
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consisting of two 545-megawatt natural gas-fired combined cycle generating units (Port Units 1 and 2) on the site of Wisconsin Electric’s existing Port Washington Power Plant. The Port Order also authorized Wisconsin Gas to proceed with the construction of a connecting natural gas lateral and American Transmission Company LLC (ATC) to construct required transmission system upgrades to serve Port Units 1 and 2 as a result of their concurrent applications. In January 2003, Wisconsin Electric commenced demolition of two of its existing coal-fired units on the site to make room for the new units. In July 2003, We Power began construction of Unit 1, and we expect the unit to be operational early in the third quarter of 2005. In October 2003, we received approval from the Federal Energy Regulatory Commission (FERC) to transfer by long-term lease certain associated FERC jurisdictional assets from We Power to Wisconsin Electric. In May 2004, we 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 Wisconsin Electric will staff, operate and maintain Port Units 1 and 2. Key terms of the leased generation contracts include:
In January 2003, Wisconsin Electric 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 Request” below for further information.) We Power began collecting certain costs from Wisconsin Electric 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 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 request of the individual, dismissed 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 Port Units 1 and 2, we needed the approval from the Wisconsin Department of Natural Resources (WDNR) for the construction of a natural gas lateral which will deliver fuel to the Units. After several discussions with the WDNR, we agreed to modify the planned route and mitigate certain environmental impacts. In July 2003, we received approval for construction for the natural gas lateral and the lateral was completed in December 2004.
Power the Future - Elm Road:
Background: In November 2003, the PSCW issued an order (the Elm Road Order) granting Wisconsin Energy, Wisconsin Electric, and We Power a CPCN to commence construction of two 615-megawatt coal-fired units (the Elm Road units) to be located near the site of Wisconsin Electric’s existing Oak Creek Power Plant. The first unit was scheduled to be operational in 2009 and the second unit was scheduled to be operational in 2010. The Elm Road 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. The total cost for the two units was set at $2.19 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. In April 2004, we entered into a contract with Bechtel to secure necessary
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engineering, design and construction services and major equipment components for these units. We expect that we will have co-owners that will have an interest in the project of approximately 17%.
Lease Terms: In October 2004, the PSCW approved the lease generation contracts between Wisconsin Electric and We Power for the Elm Road units. Key terms of the leased generation contracts include:
In April 2004, the PSCW approved the deferral of certain costs related to the Elm Road units for recovery in future rates. In May 2004, we filed a request with the PSCW 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.
Legal and Regulatory Matters: The construction of the Elm Road units is subject to a number of regulatory approvals and legal challenges by third parties. The most notable remaining legal challenges relate to the Elm Road CPCN.
In November 2004, a Dane County Circuit Court judge reviewing challenges to the PSCW’s order authorizing us to build 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 our application and in its decisions on several other points.
We, 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 Dane County decision specifically addresses the Oak Creek expansion, we believe this order would make it very difficult for any new generation facilities to be built anywhere in the state. In addition to serious questions of reliability and availability of power, this decision also poses increased costs to customers. In January 2005, the Supreme Court of Wisconsin agreed to hear the appeal. The Supreme Court scheduled oral arguments in this matter for March 30, 2005. We anticipate a decision to be issued no later than June 30, 2005.
We continue to work with the PSCW, the WDNR and other agencies to obtain all required permits and project approvals. The major permits and the status regarding these permits are discussed below.
In September 2003, several parties filed a request with the WDNR for a contested case hearing in connection with our application to the WDNR for a permit for wetlands and waterways alterations and construction on the bed of Lake Michigan for the construction of the Elm Road units. That request was granted and assigned to an administrative law judge. The hearing took place in August 2004 and post hearing briefing concluded in September 2004. In November 2004, the administrative law judge approved the WDNR’s issuance of the wetlands and waterways permit (Chapter 30 permit) for the Elm Road units. In December 2004, two opponents filed a petition for review of the decision in Dane County Circuit Court. In January 2005, we filed a motion to dismiss the opponents’ petition. The WDNR has joined in this motion.
We have applied to the WDNR to modify the existing Wisconsin Pollution Discharge Elimination System (WPDES) permit at this location that is required for operation of the water intake and discharge system for the planned Elm Road and existing Oak Creek generating units. In January 2005, the WDNR published its notice of intent to issue a WPDES permit with a public comment period ending in February 2005. Additionally, we have applied to the Army Corps of Engineers for the federal permits necessary for the construction of the Elm Road units. We anticipate decisions on these permits in the first half of 2005. Decisions favorable to the project may be contested by project opponents.
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In January 2004, the WDNR issued the Air Pollution Control and Construction Permit to Wisconsin Electric for the Elm Road units. In February 2004, certain project opponents filed a petition for judicial review in the Dane County Circuit Court. At the same time, the project opponents submitted a request for a contested case hearing with the WDNR which was granted. Petitioners subsequently agreed to dismiss their petition for judicial review. The contested case hearing was held in October 2004. In February 2005, an administrative law judge issued a decision affirming the WDNR January 2004 issuance of the Air Pollution Control and Construction Permit. In February 2005, the project opponents filed a petition for judicial review of the decision with the Dane County Circuit Court.
The terms of our construction contract with Bechtel for the Elm Road units presently provide that full notice to proceed must be given to Bechtel by July 1, 2005. In order for Bechtel to be able to proceed on July 1, it must begin site mobilization activities in May. We are unable to state whether the project could proceed if delayed beyond July 1, 2005.
In July 2004, we entered into an environmental and economic agreement with the Town of Caledonia (the community immediately adjacent to the Oak Creek plant site), covering our plans for expansion of the Oak Creek plant site and the associated increase in train and vehicular traffic that would result in the community. The agreement was approved by the Town Board in July 2004. The initial discussions were held at the suggestion of the PSCW in its decision approving the Elm Road Order. Under the agreement, we will take certain actions to mitigate the impact on the Town of construction of the Elm Road units, as well as pay the Town to mitigate certain community health and safety impacts. The Town will cooperate with us in the issuance of necessary local permits and dismiss its judicial appeal of the PSCW permits issued. The Town’s appeal was dismissed at the Town’s request in September 2004. Portions of the agreement concerning the impact payments are subject to review and approval by the PSCW. Our direct obligations under the agreement are not expected to have a material impact on our financial condition or results of operations.
UTILITY RATES AND REGULATORY MATTERS
The PSCW regulates our retail electric, natural gas, steam and water rates in the state of Wisconsin, while the FERC regulates wholesale power, electric transmission and interstate gas transportation service rates. The Michigan Public Service Commission (MPSC) regulates retail electric rates in the state of Michigan. Within our regulated segment, we estimate that approximately 87% of our electric revenues are regulated by the PSCW, 8% are regulated by the MPSC and the balance of our electric revenues are regulated by the FERC. All of our natural gas 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: In the state of Wisconsin, We Energies, (the trade name of Wisconsin Electric and Wisconsin Gas) rates are governed by an order from the PSCW issued in March 2000 in connection with the approval of the WICOR acquisition. Under this order, We Energies is restricted from increasing Wisconsin rates for a five year period ending December 31, 2005, with certain exceptions. We may seek biennial rate reviews during the five-year rate restriction as a result of:
In addition, the PSCW found that electric fuel cost adjustment procedures as well as gas cost recovery mechanisms would not be subject to the five-year rate restriction period and that it was reasonable to allow us to retain efficiency gains associated with the merger. As identified below, 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 by the PSCW for rates beginning in January 1, 2006. We expect to make a filing in 2005 in connection with this PSCW review.
Wisconsin Electric: The table below summarizes the anticipated annualized revenue impact of recent rate changes. Wisconsin Electric’s current Wisconsin rates are based on an authorized return on common equity of 12.2%.
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Wisconsin Gas: As discussed above, Wisconsin Gas is also under the five year rate restriction period which ends December 31, 2005. In March 2004, the PSCW approved an annual rate increase of $25.9 million related to increased costs associated with the construction of the Ixonia lateral and for increased costs associated with low-income energy assistance.
Limited Rate Adjustment Requests
2005 Revenue Deficiencies: In May 2004, Wisconsin Electric filed an application with the PSCW for an increase in electric and steam rates for anticipated 2005 revenue deficiencies associated with (1) costs for the new Port Washington Generating Station and the Elm Road Generating Station being constructed as part of our Power the Future strategy, (2) costs associated with our energy efficiency procurement plan and (3) costs associated with making changes to our steam utility systems as part of the reconstruction of the Marquette Interchange highway project in downtown Milwaukee, Wisconsin. The filing identified anticipated revenue deficiencies in 2005 attributable to Wisconsin in the amount of $84.8 million (4.5%) for the electric operations of Wisconsin Electric, and $0.5 million (3.6%) for Wisconsin Electric’s steam operations. In January 2005, as a result of the litigation involving our Elm Road units, we amended this filing to reduce the total revenue request to $52.4 million. We anticipate receiving an order from the PSCW before April 2005.
2005 Fuel Recovery Filing: In February 2005, Wisconsin Electric 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 receive approval of the increase in fuel recoveries on an interim basis in March 2005. The revenues associated with this filing will be subject to refund and the costs associated with the filing will be audited by the PSCW. Under the fuel
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rules, Wisconsin Electric would have to refund to customers any over recoveries of fuel costs plus interest at a rate of 12.2%.
Other Utility Rate Matters
Electric Transmission Cost Recovery: Wisconsin Electric divested of its transmission assets with the formation of the ATC in January 2001. 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 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, we have deferred $109.6 million of unrecovered transmission costs and we expect to begin to recover these costs beginning in 2006.
Fuel Cost Adjustment Procedure: Within the state of Wisconsin, Wisconsin Electric operates 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 its 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.
Edison Sault and our Wisconsin Electric operations in Michigan operate 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. During 2004, $0.2 million of additional revenues were earned under the incentive portion of the GCRM and $9.0 million and $1.6 million of additional revenues were earned in 2003 and 2002 under the GCRM.
Bad Debt Costs: Prior to October 2002, Wisconsin Gas expensed amounts included in rates for bad debt expense. If actual bad debt costs exceeded amounts allowed in rates, these amounts were deferred as a regulatory asset. Effective October 2002, the PSCW issued an order which eliminated escrow accounting for bad debts. The escrow amount accumulated at September 30, 2002 of approximately $6.9 million is expected to be collected in future rates, but future bad debt expense at Wisconsin Gas will no longer be subject to this separate true-up mechanism.
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 a letter from the PSCW which allowed Wisconsin Electric and Wisconsin Gas 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 $21.2 million and $15.6 million in 2004 and 2003 related to bad debt costs.
In December 2004, we filed with the PSCW a request to implement a pilot program, which, among other things, is designed to better match our collection efforts with the ability of low income customers to pay their bills. Included in this filing is a request to implement escrow accounting for all residential bad debt costs. In February 2005, the PSCW approved our pilot program and our request for escrow accounting.
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, Wisconsin Electric 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 Wisconsin Electric to issue environmental trust bonds to finance the recovery
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of $425 million of environmental control costs plus up-front financing costs. The proposed terms of the bonds are subject to further PSCW approval prior to issuance. In January 2005, we notified the PSCW that we would not issue environmental trust bonds until the satisfactory resolution of tax rulings associated with the proposed securitization and the resolution of the Elm Road proceedings before the Wisconsin State Supreme Court. The issuance would also be dependent upon market conditions.
Midwest Independent Transmission System Operator, Inc. (Midwest ISO) Day 2: In January 2005, we requested deferral accounting treatment from the PSCW for incremental costs or benefits that may occur due to the implementation of the Midwest ISO Day 2 energy markets, except for locational marginal pricing (LMP) energy costs. We anticipate receiving a decision related to this request prior to the scheduled start of the Midwest ISO energy market on April 1, 2005.
Nuclear Refueling Outages - 2005: In January 2005, we requested deferral accounting treatment for non-fuel operations and maintenance expenses related to the second nuclear refueling outage expected to occur in the fall of 2005. We estimate that the additional non-fuel operation and maintenance expense associated with the fall nuclear outage is approximately $15.0 million. We anticipate receiving a decision related to this request in the first quarter of 2005.
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 our Power the Future strategy. 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. In the long-term, we are initiating a new asset management strategy that is expected 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 our Power the Future strategy is subject to a number of state and federal regulatory approvals. For additional information, see “Power the Future” above.
Wisconsin Electric had adequate capacity to meet all of its firm electric load obligations during 2004. All of Wisconsin Electric’s generating plants performed well during the hottest 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 the 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 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 connecting Wisconsin to the Upper Peninsula of Michigan. This incident also resulted in short outages to some firm customers.
Wisconsin Electric expects to have adequate capacity to meet all of its firm load obligations during 2005. However, extremely hot weather, unexpected equipment failure or unavailability could require Wisconsin Electric to call upon load management procedures during 2005 as it 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 and non-utility energy segments include but are not limited to (1) air emissions such as carbon
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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 our Power the Future strategy, (2) developing additional sources of renewable electric energy supply, (3) participating in regional initiatives to reduce the emissions of NOx from our fossil fuel-based generating facilities, (4) entering into agreements with the WDNR and EPA to reduce emissions of SO2 and NOx by more than 65% and mercury by 50% within 10 years from Wisconsin Electric’s coal-fired power plants in Wisconsin and Michigan, (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 agreement is estimated to be approximately $600 million over the 10 years ending 2013. For further information concerning the consent decree, see “Note S - Commitments and Contingencies” in the Notes to Consolidated Financial Statements in this report. For further information concerning disposal of used nuclear fuel and nuclear power plant decommissioning, see “Nuclear Operations” below and “Note H - Nuclear Operations” in the Notes to Consolidated Financial Statements in this report, respectively.
National Ambient Air Quality Standards: In 2004, EPA began implementing the National Ambient Air Quality Standards (NAAQS) for 8-hour ozone and fine particulate matter (PM 2.5 ) by designating nonattainment areas in the country. The states are currently developing rules to implement the new standards. Although specific emission control requirements are not yet defined, Wisconsin Electric believes that the revised standards will likely require significant reductions in SO2 and NOx emissions from coal-fired generating facilities. Wisconsin Electric expects that reductions needed to achieve compliance with the 8-hour ozone attainment standard will be implemented in stages from 2007 through 2010, beginning with the 1-hour ozone reductions. 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. Wisconsin Electric is currently unable to predict the impact that the revised air quality standards might have on the operations of our existing coal-fired generating facilities.
Ozone Non-Attainment Standards: The 1-hour ozone nonattainment rules currently being implemented by the state of Wisconsin and ozone transport rules implemented by the state of Michigan limit NOx emissions in phases over the next five years.
Wisconsin Electric currently expects to incur total annual operation and maintenance costs of $1-2 million during the period 2004 through 2007 to comply with the Michigan and Wisconsin rules. In January 2000, the PSCW approved Wisconsin Electric’s comprehensive plan to meet the Wisconsin regulations, permitting recovery in rates of NOx emission reduction costs over an accelerated 10-year recovery period.
In April 2004, the EPA designated 10 counties in Southeastern Wisconsin as nonattainment areas for the 8-hour ozone NAAQS. States will be required to develop and submit State Implementation Plans to the EPA to demonstrate how they intend to comply with the 8-hour ozone NAAQS by June 2007. Reductions needed to achieve compliance with the 8-hour ozone attainment standard will be implemented in stages from 2007 through 2010. Wisconsin Electric believes 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’s 8-hour ozone NAAQS.
In December 2004, the EPA designated PM 2.5 nonattainment areas in the country. All counties in the state of Wisconsin were designated as attainment with the standard. EPA published proposed regulations called the Clean Air Interstate Rule (CAIR) in January 2004 to facilitate the states in meeting the 8-hour ozone and PM 2.5 standards by addressing the regional transport of SO2 and NOx. The proposed rules would require NOx and SO2 emission reductions in two phases from electric generating units located in a 28-state region within the eastern U.S. Wisconsin and Michigan are affected states under CAIR. The EPA is planning to issue the final CAIR regulations by March 15, 2005. Wisconsin Electric believes 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, the EPA issued a regulatory determination in December 2000 that utility mercury emissions should be regulated. The
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EPA issued draft rules in December 2003 and is expected to issue final rules by March 15, 2005. The compliance date for the final federal rules cannot be predicted at this time, but could be as early as 2008.
The WDNR independently developed mercury emission control rules that affect electric utilities in Wisconsin. The mercury control rules became effective in October 2004. The rules require emission reductions of 40% by 2010 and 75% by 2015. The rules explicitly recognize an underlying state statutory restriction that state regulations cannot be more stringent than those included in any federal program. The rules state that the WDNR must adopt state rule changes within 18 months of publication of any federal rules. State rules are to be changed to be consistent with, and no more restrictive than, any federal rules. Our compliance planning estimates show that no additional emission control investments are likely to be needed to meet the state mercury rules. This is because the federal rules are very likely to be in place prior to the compliance dates contained in the state rule. 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 rulemakings might have on the operations of our existing or anticipated coal-fired generating facilities.
Manufactured Gas Plant Sites: Wisconsin Electric and Wisconsin Gas are voluntarily reviewing and addressing environmental conditions at a number of former manufactured gas plant sites. For further information, see “Note S - Commitments and Contingencies” in the Notes to Consolidated Financial Statements.
Ash Landfill Sites: Wisconsin Electric aggressively seeks environmentally acceptable, beneficial uses for its combustion byproducts. For further information, see “Note S - Commitments and Contingencies” in the Notes to Consolidated Financial Statements.
EPA Information Requests: Wisconsin Electric received requests for information from the EPA regional offices pursuant to Section 114(a) of the Clean Air Act. For further information, see “Note S - Commitments and Contingencies” in the Notes to Consolidated Financial Statements.
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, we reached settlements with an insurance carrier for approximately $9.1 million. We are continuing to pursue recovery against the remaining insurance carriers and other third parties. We are continuing to analyze and refine the costs associated with this matter.
Stray Voltage: On July 11, 1996, the PSCW issued a final order regarding the stray voltage policies of Wisconsin’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 Wisconsin Electric 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 its electrical system, even though that electrical system has been operated within the parameters of the PSCW’s order. In 2003, the Wisconsin Supreme Court upheld a Court of Appeals’ affirmance of a jury verdict against Wisconsin Electric in a stray voltage lawsuit and held that even though a utility company’s measurement of stray voltage is below the PSCW “level of concern,” that utility could still 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
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Wisconsin Electric with respect to stray voltage and ground currents are not expected to have a material adverse effect on its financial statements, we continue to evaluate various options and strategies to mitigate this risk.
NUCLEAR OPERATIONS
Point Beach Nuclear Plant: Wisconsin Electric owns two 518-megawatt electric generating units (Unit 1 and Unit 2) at Point Beach Nuclear Plant in Two Rivers, Wisconsin. The Plant is operated by Nuclear Management Company, LLC (NMC), a joint venture of the Company and affiliates of other unaffiliated utilities. During 2004, 2003 and 2002, Point Beach provided approximately 25% of Wisconsin Electric’s net electric energy supply.
Each Unit at the Plant has a scheduled refueling outage approximately every 18 months. In 2004, Unit 1 had a scheduled refueling outage in the second quarter 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 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, we incur significant operations and maintenance costs for work performed during the outages 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, NMC and Wisconsin Electric filed an application with the NRC to renew the operating license for both Units for an additional 20 years. The NRC has indicated that they expect to act on the license renewal request before January 2006.
In July 2000, our senior management authorized the commencement of initial design work for the power uprate of both Units 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 7 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’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: Wisconsin Electric is authorized to load and store sufficient dry fuel storage containers to allow Point Beach Units 1 and 2 to operate to the end of their current operating licenses, but not to exceed the original 48-canister capacity of the dry fuel storage facility.
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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 Wisconsin Electric has paid a total of $200.3 million into the Nuclear Waste Fund over the life of the 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’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, Wisconsin Electric filed a complaint on November 16, 2000 against the Department of Energy in the Court of Federal Claims. The matter is pending. Wisconsin Electric has incurred substantial damages to date and damages continue to accrue. We are seeking recovery of our damages in this lawsuit.
In July 2002, the President 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, 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 Organizations (RTOs), which will affect the structure of the wholesale market. To this end, the Midwest ISO is expected to implement a bid-based market including the use of LMPs to value electric transmission congestion. The Midwest ISO energy markets are currently slated to commence 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, Michigan has adopted retail choice which potentially affects our Michigan operations. Deliberations are expected to continue in Congress on a federal energy bill containing changes that would impact the electric utility industry. In the past few years bills have passed the U. S. House of Representatives, but were not passed by the Senate. Major issues in industry restructuring, implementation of RTO markets and market power mitigation received substantial attention in 2004. We continue to focus on infrastructure issues through our Power 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’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 state 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. No such legislation has been introduced in Wisconsin to date.
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Restructuring in Michigan: Electric utility revenues are regulated by the MPSC. In June 2000, the Governor of Michigan signed the “Customer Choice and Electric Reliability 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 for those who want it and protection for those who need it.”
As of January 1, 2002, Michigan retail customers of Wisconsin Electric and Edison Sault 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’s power supplier.
Competition and customer switching to alternative suppliers in the companies’ service territories in Michigan has been limited. With the exception of two general inquiries, no alternate supplier activity has occurred in our service territories in 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 state of Illinois passed legislation that introduced retail electric choice for large customers and introduced choice for all retail customers in May 2002. This legislation is not expected to have a material impact on Wisconsin Electric’s business. Wisconsin Electric has one wholesale customer in Illinois, the City of Geneva, whose contract is scheduled to expire on December 31, 2005. However, Wisvest’s wholly-owned subsidiary, Calumet Energy Team, LLC, does compete in the Illinois electric generation market with power produced from its 308-megawatt gas based peaking plant that entered commercial operation in 2002. Since May 1, 2004, Calumet has operated under the control of PJM Interconnection, L.L.C. (PJM), an RTO that also operates bid based energy and capacity markets. Since operating under PJM, there has been a change in the anticipated economics of the facility and the determination of an impairment of the facility. An impairment charge was recorded in the third quarter of 2004. For further information see “Note F - Asset Valuation Charges” - in the Notes to the Consolidated Financial Statements.
Electric Transmission and Energy Markets
American Transmission Company: Effective January 1, 2001, we transferred all of the electric utility transmission assets of Wisconsin Electric and Edison Sault to ATC in exchange for ownership interests in this new company. Joining ATC is consistent with the FERC’s Order No. 2000, designed 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. As of February 1, 2002, operational control of ATC’s transmission system was transferred to the Midwest ISO, and Wisconsin Electric became a non-transmission owning member and customer of the Midwest ISO.
Midwest ISO: In connection with its status as a FERC approved RTO, the Midwest ISO is in the process of implementing a bid-based energy market which is currently scheduled to be implemented on April 1, 2005. As part of this energy market, the Midwest ISO is developing 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, the LMP system will include the ability to mitigate or eliminate congestion costs through the use of Financial Transmission Rights (FTRs), which will be initially allocated by the Midwest ISO, and, it is anticipated, will be available through an auction-based system run by the Midwest ISO. Currently, there are several different estimates, 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 Wisconsin Electric 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
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in highly congested areas such as WUMS. 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 Wisconsin Electric and Edison Sault. The Midwest ISO recently completed its first allocation of FTRs for the period starting April 1, 2005 and ending August 31, 2005. Wisconsin Electric received 94% of the FTRs that it requested in the allocation process. The FTR allocation process will be performed again for the period from September 1, 2005 to May 31, 2006, and it is unknown how many FTRs Wisconsin Electric will be granted during that allocation process.
The Midwest ISO is currently deferring the costs to develop and start-up its energy market (new software systems and personnel). Once the market is operational, the development and start-up costs will be charged to the Midwest ISO’s market participants, including Wisconsin Electric and Edison Sault.
To mitigate the risks of this new bid-based energy market, we requested deferral accounting treatment from the PSCW in January 2005 for incremental costs or benefits that may occur due to the implementation of the Midwest ISO Day 2 energy markets. Our request excluded LMP energy costs which will be recoverable under Wisconsin’s Fuel Cost Adjustment Procedure. We anticipate receiving a decision related to this request prior to the scheduled start of the Midwest ISO market 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 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 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 least February 1, 2008. In addition, FERC ordered a seams elimination charge to be paid by Midwest ISO 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’s elimination of through and out transmission charges between the Midwest ISO and PJM. The FERC ordered that certain existing transmission transactions continue to pay for through and out service from December 1, 2004 until March 31, 2006. The details of the seams elimination charge and the quantification of the existing transaction charge are the subject of a hearing process initiated by FERC in a February 2005 order. We are currently unable to determine the impacts on Wisconsin Electric and Edison Sault.
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.
Discussions as to appropriate lost revenue charges with regard to several entities’ decisions, including that of Commonwealth Edison Company, a non-affiliated Illinois utility that provides Wisconsin Electric transmission service, to place their transmission facilities under the control of PJM were terminated in September 2004. In lieu of charging the previously ordered seam elimination cost adjustment, the FERC permitted the Midwest ISO, PJM and the affected entities, including Commonwealth Edison Company, to continue to charge their existing rates for transmission to adjoining areas until December 1, 2004, after which the affected entities as directed by the FERC, were required to develop a new rate design that will eliminate the multiple charges between the service territories 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.
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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. Wisconsin Electric was allocated FTRs for virtually all of its 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, Wisconsin Electric has experienced minimal net congestion costs associated with its 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 has 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, Wisconsin Electric and Wisconsin Gas are unable to predict the impact of potential future deregulation on our results of operations or financial position.
ACCOUNTING DEVELOPMENTS
New Pronouncements: In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123 (revised 2004), Share-Based Payment (SFAS 123R), which amended SFAS 123, Accounting for Stock-Based Compensation. This statement requires that the compensation costs relating to such transactions be recognized in the consolidated income statement. We are currently evaluating the provisions of SFAS 123R and expect to adopt it on July 1, 2005. We have not yet determined the method of transition. See “Note B - Recent Accounting Pronouncements” and “Note I - Common Equity” in the Notes to Consolidated Financial Statements in this report for additional information.
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’s most difficult, subjective or complex judgments.
Regulatory Accounting: Our utility subsidiaries 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 the utilities’ books, as allowed under Statement of Financial Accounting Standards 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, we had $849.4 million in regulatory assets and $922.4 million in regulatory liabilities. We continually review the applicability of SFAS 71 and have determined that it is currently appropriate to continue following SFAS 71. See “Note C - Regulatory Assets and Liabilities” in the Notes to Consolidated Financial Statements for additional information.
Table of Contents2004 Form 10-K
Pension and Other Post-retirement Benefits: Our reported costs of providing non-contributory defined pension benefits (described in “Note O - 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’ 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.
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 O - Benefits” in the Notes to Consolidated Financial Statements). We account for these plans in accordance with SFAS No. 106, Employers’ Accounting for Post-retirement Benefits Other Than 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-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, the regulators of our utility segment 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.
Table of Contents2004 Form 10-K
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 2004 of $3.4 billion included accrued utility revenues of $245.1 million at December 31, 2004.
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. 143, Accounting for Asset Retirement Obligations (SFAS 143). SFAS 143 applies primarily to decommissioning costs for our utility energy segment’s Point Beach Nuclear Plant. Using a discounted future cash flow methodology, our estimated nuclear asset retirement obligation was approximately $745 million at December 31, 2004.
Calculation of this 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, the discount rate applied to future cash flows and an 85% probability of plant relicensing. Assuming the following changes in key assumptions and holding all other assumptions constant, we estimate that our nuclear asset retirement obligation at December 31, 2004 would have changed by the following amounts:
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 million.
For additional information concerning SFAS 143 and our estimated nuclear asset retirement obligation, see “Note L - Asset Retirement Obligations” and “Note H - Nuclear Operations” in the Notes to Consolidated Financial Statements.
Deferred Tax Assets Valuation Allowance: At December 31, 2004, we had a valuation allowance of approximately $40.5 million of which approximately $22.0 million related to state net operating loss carryforwards (state NOLs), and the remainder related primarily to potential state tax benefits of asset impairment charges. Of the $22.0 million, $15.1 million relates to state NOLs of the parent company that begin to expire in 2010, and
Table of Contents2004 Form 10-K
$6.9 million relates to state NOLs of various other non-utility subsidiaries that begin to expire in 2008. The state NOLs have been generated over a period of many years due to taxable losses in the separate state income tax returns. The losses at the Parent were primarily due to interest expense. We had established the valuation allowance against the state NOLs each year as the taxable losses occurred because management concluded that it was more likely than not that the state NOLs would not be realized prior to expiration.
The Power the Future generating units will be owned by our subsidiaries organized as Limited Liability Corporations (LLCs). Once the plants become operational, taxable income or loss of the LLCs will flow through to and be reported in the separate state income tax return of the Parent. As a result, the Parent no longer expects to generate large state losses if all plants are in service. The determination of future state taxable income of the Parent is a significant estimate. Factors affecting the estimate include the ultimate resolution of legal challenges to the construction of the plants, amounts spent and timing for construction of the Power the Future generating units, the amount of debt and interest expense at the Parent and the consideration of available tax planning strategies. We concluded at December 31, 2004 it was more likely than not that all of the deferred tax assets related to state NOLs would expire before being realized.
If we would conclude in a future period that it was more likely than not that some or all of the state NOLs would be realized before expiration, generally accepted accounting principles would require that we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported as an increase or decrease in income.
CAUTIONARY FACTORS
This report and other documents or oral presentations contain or may contain forward-looking statements made by or on behalf of Wisconsin Energy. These statements are based upon management’s current expectations and are subject to risks and uncertainties that could cause our actual results to differ materially from those contemplated in the statements. Readers are cautioned not to place undue reliance on the forward-looking statements. When used in written documents or oral presentations, the terms “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “intends,” “may,” “objective,” “plan,” “possible,” “potential,” “project” and similar expressions are intended to identify forward-looking statements. In addition to the assumptions and other factors referred to specifically in connection with these statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statements or otherwise affect our future results of operations and financial condition include, among others, the following:
Table of Contents2004 Form 10-K
Table of Contents2004 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.
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