ITEM 1.
BUSINESS
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.
We conduct our operations primarily in two operating segments: a utility energy segment and a non-utility energy segment. 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 1,092,400 electric customers in Wisconsin and the Upper Peninsula of Michigan, approximately 446,400 gas customers in Wisconsin and approximately 460 steam customers in metro Milwaukee, Wisconsin; Wisconsin Gas, which serves approximately 583,300 gas customers in Wisconsin and approximately 2,800 water customers in suburban Milwaukee, Wisconsin; and Edison Sault Electric Company (Edison Sault), which serves approximately 22,900 electric customers in the Upper Peninsula of Michigan. Wisconsin Electric and Wisconsin Gas operate under the trade name of "We Energies".
Non-Utility Energy Segment: Our non-utility energy segment consists primarily of We Power. We Power was formed in 2001 to design, construct, own and lease to Wisconsin Electric the new generating capacity included in our Power the Future strategy. See Item 7 for more information on Power the Future.
Discontinued Operations: Effective July 31, 2004, we sold our manufacturing segment. Effective May 31, 2005, we sold our Calumet Energy (Calumet) facility, which was part of our non-utility energy segment. In August 2005, we announced our intent to sell Minergy Neenah, LLC (Minergy Neenah).
Power the Future Strategy: In September 2000, we announced our Power the Future strategy 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. 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.
Our annual and periodical filings to the Securities and Exchange Commission (SEC) are 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 Regarding Forward - Looking Statements: Certain statements contained herein are "Forward-Looking Statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-Looking Statements include, among other things, statements regarding management's expectations and projections regarding completion of construction projects, regulatory matters, fuel costs, sources of electric energy supply, coal and gas deliveries, remediation costs, environmental and other capital expenditures, liquidity and capital resources and other matters. Also, Forward-Looking Statements may be identified by reference to a future period or periods or by the use of forward looking terminology such as "anticipates," "believes," "estimates," "expects," "forecasts," "intends," "may," "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 in Item 1A
ITEM 1A.
RISK FACTORS
Our business is significantly impacted by governmental regulation.
We are subject to significant state, local and federal governmental regulation. We are subject to the regulation of the PSCW as to retail electric, gas and steam rates in the State of Wisconsin, standards of service, issuance of securities, short-term debt obligations, construction of certain new facilities, transactions with affiliates, billing practices and various other matters. In addition, we are subject to the regulation of the MPSC as to the various matters associated with retail electric service in the State of Michigan, except as to issuance of securities, construction of certain new facilities, levels of short-term debt obligations and advance approval of transactions with affiliates. Further, Wisconsin Electric's hydroelectric facilities are regulated by the FERC, and the FERC also regulates our wholesale power service and accounting practices. Our significant level of regulation imposes restrictions on our operations and causes us to incur substantial compliance costs.
We estimate that within our regulated energy segment, 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.
Our ability to obtain rate adjustments in the future is dependent upon regulatory action and there can be no assurance that we will be able to obtain rate adjustments in the future that will allow us to maintain our current authorized rates of return.
Factors beyond our control could adversely affect project costs and completion of the natural gas-fired and coal-fired generating units we are constructing as part of our Power the Future strategy.
Under our Power the Future strategy, we expect to meet a significant portion of our future generation needs through the construction of two 545-megawatt natural gas-fired generating units at our Port Washington Generating Station and two 615-megawatt coal-fired generating units to be located adjacent to our Oak Creek Power Plant. The first of these four units was placed into service in July 2005.
Large construction projects of this type are subject to usual construction risks over which we will have limited or no control and which might adversely affect project costs and completion time. These risks include, but are not limited to, shortages of, the inability to obtain or the cost of labor or materials, the inability of the general contractor or subcontractors to perform under their contracts, strikes, adverse weather conditions, the inability to obtain necessary permits in a timely manner and changes in applicable law or regulations, adverse interpretation or enforcement of permit conditions, laws and regulations by the permitting agencies, governmental actions and events in the global economy.
If final costs for the construction of the Port Washington units exceed the fixed costs allowed in the PSCW order, absent a finding by the PSCW of extraordinary circumstances such as force majeure conditions, this excess will not adjust the amount of the lease payments recovered from Wisconsin Electric. If final costs of the Oak Creek expansion are within 5% of the targeted cost, and the additional costs are deemed prudent by the PSCW, the final lease payments for the Oak Creek expansion recovered from Wisconsin Electric would be adjusted to reflect the actual construction costs. Costs above the 5% cap would not be included in lease payments or recovered from customers absent a finding by the PSCW of extraordinary circumstances such as force majeure conditions.
As required by the Energy Policy Act, FERC developed new rules to implement certain provisions of the Energy Policy Act. Pursuant to these new rules, Wisconsin Electric is required to seek FERC authorization to lease from We Power the three Power the Future units that are currently being constructed by We Power. We are unable to determine at this time the magnitude of this new regulatory requirement on the Power the Future plan, if any.
We face significant costs of compliance with existing and future environmental regulations.
We are subject to extensive environmental regulations relating to, among other things, air emissions such as carbon dioxide, sulfur dioxide, nitrogen oxide, small particulates and mercury, water discharges and management of hazardous and solid waste. We incur significant expenditures in complying with these environmental requirements, including expenditures for the installation of pollution control equipment, environmental monitoring, emissions fees and permits at all of our facilities.
Existing environmental regulations may be revised or new laws or regulations may be adopted which could result in significant additional expenditures and operating restrictions on our facilities. In the event we are not able to recover all of our environmental expenditures from our customers in the future, our results of operations could be adversely affected.
In addition, we may also be responsible for liabilities associated with the environmental condition of the facilities that we have previously owned and operated, regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. The incurrence of a material environmental liability could have a significant adverse effect on our results of operations and financial condition.
Ownership and operation of nuclear generating units involve inherent risks that may result in substantial costs and liabilities.
We own two 518-megawatt nuclear electric generating units at the Point Beach site. The units are operated by NMC, a joint venture of Wisconsin Energy and affiliates of other unaffiliated utilities. During 2005, our nuclear generating units provided 20% of our net electric energy supply. Our nuclear facilities are subject to environmental, health and financial risks, including: handling of nuclear materials, on-site storage of spent nuclear fuel and the current lack of a long-term solution for disposal of materials; mechanical or structural problems; lapses in maintenance procedures; human errors in the operation of the reactors or safety systems; the threat of possible terrorist attacks; limitations on the amounts and types of insurance coverage commercially available; the continued ability of NMC to effectively manage and operate our nuclear facilities; and uncertainties regarding our ability to maintain adequate reserves for decommissioning the units. While we have no reason to anticipate a serious nuclear incident at our units, if an incident were to occur, it could result in substantial costs to us that may significantly exceed the amount of our insurance coverage and reserves.
The NRC has broad authority to impose licensing and safety related requirements for the operation of nuclear generating facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, until compliance is achieved. Further, in the event of a major incident at a nuclear facility anywhere in the world, the NRC could limit or prohibit the operation or licensing of any domestic nuclear unit.
As a result of the September 11, 2001 terrorist attacks, the NRC and the industry have been strengthening security at nuclear power plants. Increased security measures and other safety requirements could require us to make substantial capital expenditures at our nuclear generating units.
Energy sales are impacted by seasonal factors and varying weather conditions from year-to-year.
Our electric and gas utility businesses are generally seasonal businesses. Demand for electricity is greater in the summer and winter months associated with cooling and heating. In addition, demand for natural gas peaks in the winter heating season. As a result, our overall results in the future may fluctuate substantially on a seasonal basis. In addition, we have historically had lower revenues and net income when weather conditions are milder. Our rates in Wisconsin are set by the PSCW based on estimated temperatures which approximate 20-year averages. Below normal temperatures during the summer cooling season, and to a lesser extent, above normal temperatures during the winter heating season will negatively impact the results of operations and cash flows of our electric utility business. In addition, above normal temperatures during the winter heating season negatively impact the results of operations and cash flows of our gas utility business.
Higher natural gas costs may negatively impact our electric and gas utility operations.
Significant increases in the cost of natural gas affect our electric and gas utility operations. Natural gas costs have increased significantly, both because the supply of natural gas in recent years has not kept pace with the demand for natural gas, which has grown throughout the United States as a result of increased reliance on natural gas-fired electric generating facilities, and due to the impacts of hurricanes on offshore Gulf of Mexico natural gas production. We expect that demand for natural gas will remain high into the foreseeable future and that significant price relief will not occur until additional natural gas reserves are developed.
Wisconsin Electric's electric operations burn natural gas in several of its peaking power plants and in the leased Port Washington Generation Station Unit 1 and as a supplemental fuel at several coal-fired plants, and in many instances the cost of purchased power is tied to the cost of natural gas. In addition, higher natural gas costs also can have the effect of increasing demand for other sources of fuel thereby increasing the costs of these fuels as well.
In addition, higher natural gas costs increase our working capital requirements. As a result of gas cost recovery mechanisms, our gas distribution business receives dollar for dollar pass through of the cost of natural gas. However, increased natural gas costs increase the risk that customers will switch to alternative sources of fuel or reduce their usage, which could reduce future gas margins. We have experienced reduced usage of natural gas by our residential customers in 2005 and expect this to continue during the 2006 winter heating season. In addition, higher natural gas costs combined with slower economic conditions also exposes us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills.
We may not be able to obtain an adequate supply of coal, which could limit our ability to operate our facilities.
We are dependent on coal for much of our electric generating capacity. While we have coal supply and transportation contracts in place, there can be no assurance that the counterparties to these agreements will fulfill their obligations to supply coal to us. The suppliers under these agreements may experience financial or operational problems which inhibit their ability to fulfill their obligations to us. In addition, suppliers under these agreements may not be required to supply coal to us under certain circumstances, such as in the event of a natural disaster. If we are unable to obtain our coal requirements under our coal supply and transportation contracts, we may be required to purchase coal at higher prices, or we may be forced to obtain additional megawatt hour purchases through other potentially higher cost generating resources in the MISO Midwest Market. Higher costs to obtain coal increase our working capital requirements.
Our financial performance may be adversely affected if we are unable to successfully operate our facilities.
Our financial performance depends on the successful operation of our electric generating and gas distribution facilities. Operation of these facilities involves many risks, including: operator error and breakdown or failure of equipment processes; fuel supply interruptions; labor disputes; operating limitations that may be imposed by environmental or other regulatory requirements; or catastrophic events such as fires, earthquakes, explosions, floods or other similar occurrences. Unplanned generation outages can result in additional maintenance expenses as well as incremental replacement power costs.
We are exposed to risks related to general economic conditions in our service territories.
Our electric and gas utility businesses are impacted by the economic cycles of the customers we serve. In the event regional economic conditions decline, we may experience reduced demand for electricity or natural gas which could result in decreased earnings and cash flow. In addition, regional economic conditions also impact our collections of accounts receivable.
Our business is dependent on our ability to successfully access capital markets.
We rely on access to short-term and long-term capital markets to support our capital expenditures and other capital requirements, including expenditures for our utility infrastructure and to comply with future regulatory requirements. We and our subsidiaries have historically secured funds from a variety of sources, including the issuance of short-term and long-term debt securities, preferred stock and common stock. Successful implementation of our long-term business strategies is dependent upon the ability of us and our subsidiaries to access the capital markets under competitive terms and rates. If our or our subsidiaries' access to the capital markets were limited due to a ratings downgrade, prevailing market conditions or other factors, our results of operations and financial condition could be significantly adversely affected.
We are a holding company and are subject to restrictions on our ability to pay dividends.
Wisconsin Energy is a holding company and has no significant operations of its own. Accordingly, our ability to meet our financial obligations and pay dividends on our common stock is dependent upon the ability of our subsidiaries to pay amounts to us, whether through dividends or other payments. The ability of our subsidiaries to pay amounts to us will depend on the earnings, cash flows, capital requirements and general financial condition of our subsidiaries and on regulatory limitations. Our subsidiaries have dividend payment restrictions based on the terms of their outstanding preferred stock and regulatory limitations applicable to them. In addition, each of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas bank back-up credit facilities have specified total funded debt to capitalization ratios that must be maintained.
Provisions of the Wisconsin Utility Holding Company Act limit our ability to invest in non-utility activities and could deter takeover attempts by a potential purchaser of our common stock that would be willing to pay a premium for our common stock.
Under the Wisconsin Utility Holding Company Act, we remain subject to certain restrictions that have the potential of limiting our diversification into non-utility activities. Under the 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.
In addition, the Wisconsin Utility Holding Company Act precludes the acquisition of 10% or more of the voting shares of a holding company of a Wisconsin public utility unless the PSCW has first determined that the acquisition is in the best interests of utility customers, stockholders and the public. This provision and other requirements of the Wisconsin Utility Holding Company Act may delay or reduce the likelihood of a sale or change of control of Wisconsin Energy. As a result, you may be deprived of opportunities to sell some or all of your shares of our common stock at prices that represent a premium over market prices.
Repeal of the Public Utility Holding Company Act of 1935 and enactment of the Public Utility Holding Company Act of 2005 may subject us to increased regulation.
Wisconsin Energy and Wisconsin Electric were exempt holding companies under PUHCA 1935, and, accordingly, were exempt from that law's provisions other than with respect to certain acquisitions of securities of a public utility. However, the Energy Policy Act repealed PUHCA 1935 and enacted PUHCA 2005, transferring jurisdiction over holding companies from the SEC to the FERC. Each of Wisconsin Energy and Wisconsin Electric will be required to notify the FERC of its status as a holding company and to seek from FERC the exempt status similar to that held under PUHCA 1935. If Wisconsin Energy and Wisconsin Electric are unable to obtain exempt status from FERC, both companies may become subject to increased regulation as holding companies by FERC.
Restructuring in the regulated energy industry could have a negative impact on our business.
The regulated energy industry continues to experience significant structural changes. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant adverse financial impact on us. The timeline for restructuring and retail access continues to be stretched out, and it is uncertain when retail access will happen in Wisconsin; however, Michigan has adopted retail choice which potentially affects our Michigan operations. Under retail access legislation, customers are permitted to choose their own electric generation supplier. All Michigan electric customers were able to choose their electric generation supplier beginning in January 2002. Although competition and customer switching to alternative suppliers in our service territories in Michigan has been limited, the additional competitive pressures resulting from retail access could lead to a loss of customers and our incurring stranded costs.
The FERC continues to support the existing RTOs which affect the structure of the wholesale market within those RTOs. In connection with its status as a FERC approved RTO, MISO implemented the MISO Midwest Market on April 1, 2005. The MISO Midwest Market rules require that all market participants submit day-ahead and/or real-time bids and offers for energy at locations across the MISO region. MISO then calculates the most efficient solution for all of the bids and offers made into the market that day and establishes a locational marginal price (LMP) which reflects the market price for energy. As a participant in the new MISO Midwest Market, we are required to follow MISO's instructions when dispatching generating units to support MISO's responsibility for maintaining stability of the transmission system.
Additionally, the MISO Midwest Market subjects us to additional costs primarily associated with constraints in the transmission system. MISO implemented the LMP system, a market-based platform for valuing transmission congestion. The LMP system includes the ability to mitigate or eliminate congestion charges through the use of financial transmission rights (FTRs). FTRs are allocated to market participants by MISO. We are presently operating under an FTR allocation that will be in effect through May 31, 2006. To date, our unhedged congestion charges have not been material. However, there can be no assurance that we will be granted an adequate level of FTRs in the future to avoid material unhedged congestion charges.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2.
PROPERTIES
We own our principal properties outright, except that the major portion of electric utility distribution lines, steam utility distribution mains and gas utility distribution mains and services are located, for the most part, on or in streets and highways and on land owned by others.
UTILITY ENERGY SEGMENT
Wisconsin Electric: As of December 31, 2005, Wisconsin Electric owns the following generating stations with dependable capabilities during 2005 as indicated.
(a)
Dependable capability is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. Changing seasonal conditions are responsible for the different capabilities reported for the winter and summer periods in the above table. The values were established by test and may change slightly from year to year.
(b)
Wisconsin Electric has a 25% interest in Edgewater 5 Generating Unit, which is operated by Alliant Energy Corp, an unaffiliated utility.
Effective July 2005, Wisconsin Electric began leasing PWGS Unit 1, a 545-megawatt natural gas-fired generation unit, from We Power under a 25 year lease. In addition, Wisconsin Electric has a power purchase contract with an unaffiliated independent power producer. The contract is for 236-megawatts of firm capacity from a gas-fired cogeneration facility that expires in 2022.
As of December 31, 2005, Wisconsin Electric operated approximately 21,900 pole-miles of overhead distribution lines and 21,700 miles of underground distribution cable, as well as approximately 390 distribution substations and 272,200 line transformers.
As of December 31, 2005, Wisconsin Electric's gas distribution system included approximately 9,100 miles of mains connected at 22 gate stations to the pipeline transmission systems of ANR Pipeline Company, Guardian, Natural Gas Pipeline Company of America, Northern Natural Pipeline Company and Great Lakes Transmission Company. 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.
As of December 31, 2005, the combined steam systems supplied by the Valley and Milwaukee County Power Plants consisted of approximately 43 miles of both high pressure and low pressure steam piping, 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, 2005, included approximately 10,600 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 generation 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 867 miles of primary distribution lines and renders service to its customers through approximately 9,885 line transformers.
NON-UTILITY ENERGY SEGMENT
We Power: We Power completed construction of the first 545-megawatt natural gas unit of the Port Washington Generating Station in July 2005, 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 and commenced construction at this site in June 2005. 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. In May 2005, the 308-megawatt peaking power plant in Chicago, Illinois previously owned by Calumet Energy Team, LLC was sold.
OTHER
Wispark LLC: As of December 31, 2005, 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 and PrairieWood Corporate Park in Kenosha County; and GrandView Business Park in Racine County. Wispark owns other properties located in Wisconsin Electric's service territories that are held for future development or sale. Wispark 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. In August 2005, we announced our intent to sell the Minergy Neenah facility.
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.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
In addition to those legal proceedings discussed below, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these legal proceedings cannot be predicted with certainty, 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 (CERCLA) Section 104(e) for the Solvay Coke and Gas Site located in Milwaukee, Wisconsin. All potentially responsive records and corporate legal files have been reviewed and responsive information was provided in October 2004. A predecessor company of 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. In July 2005, Wisconsin Gas received a general notice letter from the EPA identifying Wisconsin Gas as a potentially responsible party under CERCLA. Wisconsin Electric has not been named as a potentially responsible party at this time. We responded to the EPA in July 2005, stating that Wisconsin Gas will participate in negotiations regarding the site, but that Wisconsin Gas does not admit to any liability for the site. 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 - Proposed Consent Decree 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 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. In May 2005, a stray voltage lawsuit was filed against Wisconsin Electric. We do not believe the lawsuit has merit and we will vigorously defend the case. The claims made against Wisconsin Electric in these cases are not expected to have a material adverse effect on our financial condition or results of operations.
Even though any claims which may be made against Wisconsin Electric with respect to stray voltage and ground currents are not expected to have a material adverse effect on its financial condition, we continue to evaluate various options and strategies to mitigate this risk. For additional information, see 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.
ITEM 4.
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of our security holders during the fourth quarter of 2005.
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages at December 31, 2005 and positions of our executive officers are listed below along with their business experience during the past five years. All officers are appointed until they resign, die or are removed pursuant to the Bylaws. There are no family relationships among these officers, nor is there any agreement or understanding between any officer and any other person pursuant to which the officer was selected. Reference to Wisconsin Gas LLC includes the time spent with the Company prior to its conversion from a corporation to a limited liability company.
Gale E. Klappa. Age 55.
Wisconsin Energy Corporation - Chairman of the Board and Chief Executive Officer since May 2004. President since April 2003.
Wisconsin Electric Power Company - Chairman of the Board since May 2004. President and Chief Executive Officer since August 2003.
Wisconsin Gas LLC - Chairman of the Board since May 2004. President and Chief Executive Officer since August 2003.
The Southern Company - Executive Vice President, Chief Financial Officer and Treasurer from March 2001 to April 2003. Chief Strategic Officer from October 1999 to March 2001. The Southern Company is a public utility holding company serving the southeastern United States.
Director of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas LLC since 2003.
Charles R. Cole. Age 59.
Wisconsin Electric Power Company - Senior Vice President since 2001.
Wisconsin Gas LLC - Senior Vice President since July 2004.
Stephen P. Dickson. Age 45.
Wisconsin Energy Corporation - Vice President since October 2005. Controller since 2000.
Wisconsin Electric Power Company - Vice President since October 2005. Controller since 2000.
Wisconsin Gas LLC - Vice President since October 2005. Controller since 1998.
Frederick D. Kuester. Age 55.
Wisconsin Energy Corporation - Executive Vice President since May 2004.
Wisconsin Electric Power Company - Executive Vice President since May 2004. Chief Operating Officer since October 2003.
Wisconsin Gas LLC - Executive Vice President since May 2004.
Mirant Corporation - Senior Vice President - International from 2001 to October 2003 and Chief Executive Officer of Mirant Asia-Pacific Limited from 1999 to October 2003. Mirant is a multi-national energy company that produces and sells electricity. Mirant Corporation and certain of its subsidiaries voluntarily filed for bankruptcy in July 2003. Other than certain Canadian subsidiaries, none of Mirant's international subsidiaries filed for bankruptcy.
Allen L. Leverett. Age 39.
Wisconsin Energy Corporation - Executive Vice President since May 2004. Chief Financial Officer since July 2003.
Wisconsin Electric Power Company - Executive Vice President since May 2004. Chief Financial Officer since July 2003.
Wisconsin Gas LLC - Executive Vice President since May 2004. Chief Financial Officer since July 2003.
Georgia Power Company - Executive Vice President, Chief Financial Officer and Treasurer from May 2002 to July 2003. Assistant Treasurer from 2000 to 2002. Georgia Power Company is a utility affiliate of The Southern Company, a public utility holding company serving the southeastern United States.
Southern Company Services, Inc. - Vice President and Treasurer from 2000 to 2002. Southern Company Services is also an affiliate of The Southern Company.
Kristine A. Rappé. Age 49.
Wisconsin Energy Corporation - Senior Vice President and Chief Administrative Officer since May 2004. Corporate Secretary from 2001 to August 2004. Vice President from 2003 to April 2004.
Wisconsin Electric Power Company - Senior Vice President and Chief Administrative Officer since May 2004. Corporate Secretary from 2001 to August 2004. Vice President from 2001 to April 2004. Vice President of Customer Services from 1995 to 2001.
Wisconsin Gas LLC - Senior Vice President and Chief Administrative Officer since May 2004. Corporate Secretary from 2001 to August 2004. Vice President from 2001 to April 2004.
Larry Salustro. Age 58.
Wisconsin Energy Corporation - Executive Vice President since May 2004. General Counsel since 2000. Senior Vice President from 2000 to April 2004.
Wisconsin Electric Power Company - Executive Vice President since May 2004. General Counsel since 2000. Senior Vice President from 2000 to April 2004.
Wisconsin Gas LLC - Executive Vice President since May 2004. General Counsel since 2000. Senior Vice President from 2000 to April 2004.
Certain executive officers also hold offices in our non-utility subsidiaries.
In addition, effective January 3, 2006, James C. Fleming was appointed Executive Vice President of Wisconsin Energy Corporation, Wisconsin Electric Power Company and Wisconsin Gas LLC.
James C. Fleming. Age 60.
Wisconsin Energy Corporation - Executive Vice President since January 2006.
Wisconsin Electric Power Company - Executive Vice President since January 2006.
Wisconsin Gas LLC - Executive Vice President since January 2006.
Southern Company Services, Inc. - Vice President and Associate General Counsel from 1998 to December 2005. Southern Company Services is an affiliate of The Southern Company, a public utility holding company serving the southeastern United States.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
NUMBER OF COMMON STOCKHOLDERS
As of December 31, 2005, based upon the number of Wisconsin Energy Corporation stockholder accounts (including accounts in our dividend reinvestment and stock purchase plan), we had 55,532 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 J -- Common Equity in the Notes to Consolidated Financial Statements in Item 8.
On January 18, 2006, our Board of Directors announced that it increased our common stock quarterly dividend rate by 4.5%, to $0.23 per share. With the increase, the new dividend is equivalent to an annual rate of $0.92 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:
ISSUER PURCHASES OF EQUITY SECURITIES
(a)
This table does not include shares purchased by independent agents to satisfy obligations under our employee benefit plans and stock purchase and dividend reinvestment plan.
(b)
All shares reported in October were surrendered by employees to satisfy tax withholding obligations upon vesting of restricted stock.
ITEM 7.
ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 and its subsidiaries (collectively, We Power). 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 Regarding Forward - Looking Statements: Certain statements contained herein are "Forward-Looking Statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-Looking Statements include, among other things, statements regarding management's expectations and projections regarding completion of construction projects, regulatory matters, fuel costs, sources of electric energy supply, coal and gas deliveries, remediation costs, environmental and other capital expenditures, liquidity and capital resources and other matters. Also, Forward-Looking Statements may be identified by reference to a future period or periods or by the use of forward looking terminology such as "anticipates," "believes," "estimates," "expects," "forecasts," "intends," "may," "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 in Item 1A Risk Factors and under the heading "Cautionary Factors" in this Item 7, 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. We disclaim any obligation to update these forward-looking statements.
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. In July 2005, the first of four new electric generating units under our Power the Future strategy was placed into service. 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. In 2005, we increased our generating capacity by 545-megawatts with the completion of the first unit under the Power the Future strategy, and we plan to continue increasing our generating capacity through three additional electric generating units that We Power is constructing.
Non-Utility Energy Segment: Our primary focus in this segment is to improve the supply of electric generation in Wisconsin. We Power was formed to design, construct, own and lease new generation assets under the Power the Future strategy.
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 approximately $2.6 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 were 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 and lease the new generating capacity. Wisconsin Electric will lease each new generating 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 payments under the plant leases 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 Generating Station (PWGS) and the Oak Creek expansion.
As of December 31, 2005, we:
Received a Certificate of Public Convenience and Necessity (CPCN) from the PSCW to build two 545-megawatt natural gas-fired intermediate load units in Port Washington, Wisconsin. The first unit was placed into service in July 2005 and is fully operational. Unit 1 was completed within the PSCW approved cost parameters. The second unit is expected to be operational in 2008.
Began site preparation for the second 545-megawatt generating unit in Port Washington in May 2004.
Received a CPCN from the PSCW to build two 615-megawatt coal-fired base load units adjacent to the site of our existing Oak Creek Power Plant in Oak Creek, Wisconsin (the Oak Creek expansion), with the first unit expected to be in service in 2009 and the second unit in 2010. The CPCN was granted contingent upon us obtaining the necessary environmental permits. We have received all permits necessary to commence construction. In June 2005, construction commenced at the site.
Completed the planned sale in November 2005 of approximately a 17% ownership interest in the Oak Creek expansion to two co-owners.
Received approval from the PSCW for various leases between We Power and Wisconsin Electric.
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, excluding environmental trust securities that we may issue, 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 construction risks associated with the schedule and costs for both our Oak Creek expansion and the PWGS, continuing legal challenges to permits obtained and changes in applicable laws or regulations, adverse interpretation or enforcement of permit conditions, laws and regulations by the permitting agencies, the inability to obtain necessary operating permits in a timely manner, obtaining the investment capital from outside sources necessary to implement the strategy, governmental actions and events in the global economy.
For further information concerning Power the Future capital requirements, see Liquidity and Capital Resources below. You can find additional information regarding risks associated with the Power the Future strategy, as well as the regulatory process, and specific regulatory approvals in Factors Affecting Results, Liquidity and Capital Resources below.
Divestiture of 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 Wisconsin and a substantial amount of Wispark's real estate portfolio, as well as our manufacturing business. In addition, in 2001 we contributed our transmission assets to the American Transmission Company LLC (ATC) and received cash proceeds of $119.8 million and an economic interest in ATC. Since 2000, we have received total proceeds of approximately $2.1 billion from the divestiture of assets as follows:
RESULTS OF OPERATIONS
CONSOLIDATED EARNINGS
The following table compares our operating income by business segment and our net income for 2005, 2004, and 2003.
(a)
Income from Discontinued Operations, Net of Tax includes: (1) the operations of Minergy Neenah which we began reporting as discontinued operations in the third quarter of 2005, (2) the manufacturing segment, which was sold effective July 31, 2004 and (3) the operations of Calumet which were sold effective May 31, 2005. Prior periods reported in this table have been restated to reflect discontinued operations.
The following table identifies significant items that are included in our Diluted Earnings per Share from Continuing Operations.
An analysis of contributions to operating income by segment and a more detailed analysis of results in 2005, 2004 and 2003 follow.
UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME
2005 vs. 2004: Our utility energy segment contributed $542.4 million of operating income during 2005 compared with $528.6 million of operating income during 2004. During 2005, we experienced an increase in revenues due to favorable weather and pricing increases. Also, during 2004, we recorded severance costs under a voluntary severance program. The year to year increase in operating income was partially offset by higher fuel and purchased power costs and increased operation and maintenance expenses during 2005. We had two scheduled outages at our nuclear plant in 2005 in comparison to one scheduled outage in 2004.
2004 vs. 2003: 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 more than offset by higher pension and medical costs, severance costs recorded during the second half of 2004 and unfavorable weather.
The following table summarizes our utility energy segment's operating income during 2005, 2004 and 2003.
Electric Utility Gross Margin
The following table compares our electric utility gross margin during 2005 with similar information for 2004 and 2003, including a summary of electric operating revenues and electric sales by customer class.
(a)
As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a twenty-year moving average.
Electric Utility Revenues and Sales
2005 vs. 2004: During 2005, our total electric utility operating revenues increased by $250.7 million or 11.9% when compared with 2004 primarily due to favorable weather during the summer of 2005 and pricing increases.
During 2005, we estimate that pricing increases contributed an additional $145.8 million of revenues than in 2004. The most significant impact to rates was a March 2005 interim order received by Wisconsin Electric from the PSCW authorizing an annualized increase in electric rates of approximately $114.9 million due to the increased costs of fuel and purchased power. In November 2005, Wisconsin Electric received the final rate order, which authorized an additional $7.7 million of annual revenues. Additional orders impacting rates in 2005 were the May 2004 and May 2005 orders received by Wisconsin Electric from the PSCW authorizing annualized increases in electric rates of approximately $59.0 million and $59.7 million, respectively, primarily to cover construction costs associated with our Power the Future program.
Total electric sales increased by 821.8 thousand megawatt-hours or 2.6% between 2005 and 2004. Residential sales volumes increased 6.3% due to the favorable summer weather in 2005. Total sales volumes to commercial/industrial customers increased 1.7% between comparative periods. Sales volumes to commercial/industrial customers, excluding our largest customers, two iron ore mines, increased 2.3% due to the favorable weather during the summer of 2005. We estimate that weather increased our electric revenues by approximately $68.8 million during 2005 as compared to the prior year. As measured by cooling degree days, 2005 was 114.7% warmer than in 2004.
Sales volumes in the Resale-Utilities class decreased 52.6% primarily due to the reduced availability of base-load capacity for sale at competitive prices as a result of limited fuel supplies and outages. Sales volumes to municipal utilities, the other retail/municipal customer class, increased 12.8% between the periods due to higher off-peak demand from lower margin municipal wholesale power customers.
2004 vs. 2003: During 2004, our total electric utility operating revenues increased by $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 $59.0 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.
Electric Fuel and Purchased Power Expenses
2005 vs. 2004: Gross fuel and purchased power costs for our electric utilities increased by a total of $260.8 million during 2005 when compared with 2004. During 2005, we deferred $72.8 million of fuel and purchased power costs which resulted in a net increase of fuel and purchased power expense of $188.0 million or 32.1% during 2005 when compared to 2004. The increase in fuel and purchased power expense was driven by a 2.6% increase in megawatt-
hour sales and an increase in our average cost of fuel and purchased power from $17.49 per megawatt-hour in 2004 to $22.44 per megawatt-hour in 2005, or 28.3% between the comparative periods.
The increase in our average cost of fuel and purchased power is due primarily to (1) the reduced availability of nuclear generation due to scheduled refueling outages, (2) higher natural gas prices that increased the cost of power supplied by natural gas, (3) the impact of the implementation of the Midwest Independent Transmission System Operator, Inc.'s (MISO) bid based energy market (MISO Midwest Market) in April 2005 and (4) limitations on coal supplies due to transportation shortfalls.
During 2005, we had two scheduled refueling outages at our nuclear plant and in 2004 we had one scheduled refueling outage. As a result, we had approximately 1,145,000 fewer megawatt hours of nuclear generation in 2005. Our average fuel cost for nuclear generation is approximately $5 per megawatt hour, while the average energy cost for purchased power was approximately $55 per megawatt hour. We estimate that the reduction in nuclear generation resulted in approximately $57 million of increased fuel and purchased power costs in 2005 as compared to 2004. During the 2005 outages we replaced both reactor vessel heads resulting in longer outages. This work, along with other planned maintenance, lasted longer than originally expected due to delays. During 2006, we have one planned refueling outage at our nuclear plant. For more information regarding the scheduled refueling outages, see Factors Affecting Results, Liquidity and Capital Resources -- Nuclear Operations.
In 2005, we experienced significant increases in the cost of natural gas used in our own generating assets and in the price of purchased energy which is highly influenced by the price of natural gas. This increase was most significant in the last six months of 2005 due to market related factors including the hurricanes in the Gulf of Mexico. The average combined cost per megawatt hour of purchased energy and natural gas fired units in 2005 was 47.7% higher than in 2004, increasing total cost by approximately $77.2 million.
In April 2005, we began participating in the MISO Midwest Market which fundamentally changed the way we dispatch our generating units and obtain purchased energy. As part of this new market, we are subject to new types of charges which, among other things, recognize the cost of transmission congestion, megawatt-hour losses and other costs associated with operating the generating units in an uneconomic fashion to support the MISO Midwest Market service territory. Because the State of Wisconsin has a constrained transmission system, we believe these costs are higher for us than in other parts of the MISO Midwest Market service territory. The incremental costs associated with the MISO Midwest Market charges identified above were approximately $28 million in 2005. For more information regarding MISO and the MISO Midwest Market, see Factors Affecting Results, Liquidity and Capital Resources -- Industry Restructuring and Competition -- Electric Transmission and Energy Markets.
Our 2005 operations were also adversely impacted by limitations on deliveries of coal supply due to the failure of our primary rail delivery supplier to deliver contracted quantities of coal to our units. The largest limitation was related to critical rail track maintenance in the Powder River basin. This, in turn, resulted in reduced coal deliveries of the coal which primarily serves our Oak Creek and Pleasant Prairie generating units from June through December 2005. In response to the reduced deliveries, we limited the generating capability of these units in off-peak periods and purchased more expensive replacement power and, where possible, took measures to purchase and transport higher cost coal in place of contracted supplies. We estimate that this increased our costs by approximately $52 million in 2005. For additional information on the decreased coal deliveries, see Factors Affecting Results, Liquidity and Capital Resources -- Market Risks and Other Significant Risks -- Commodity Price Risk below.
Under the State of Wisconsin fuel rules, we are allowed to request recovery in fuel revenues if our projected fuel and purchased power costs exceed bands established by the PSCW. In March 2005, we received a rate order that allowed us to increase our annual revenues by $114.9 million (final order received in November 2005 for an annual increase of $122.6 million) due to increased fuel and purchased power costs. As provided under the Wisconsin rules, we are also allowed to request deferral for the costs associated with adverse events which materially impact fuel and purchased power costs which were not anticipated, or for which costs could not be reasonably estimated at the time of the fuel recovery request for consideration in future rate proceedings. During 2005, we deferred approximately $72.8 million of fuel and purchased power costs due to the extended outage at Point Beach Unit 2, the coal delivery problems and increased costs associated with the MISO Midwest Market. During 2005, we estimate that we under-recovered fuel and purchased power costs by $108.4 million before these deferred items. Adjusted for the allowed deferrals, our net under-recovered fuel and purchased power costs were approximately $35.6 million.
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.
Gas Utility Revenues, Gross Margin and Therm Deliveries
The following table compares our total gas utility operating revenues and gross margin (total gas utility operating revenues less cost of gas sold) during 2005, 2004 and 2003.
We believe gross margin is a better performance indicator than revenues because changes in the cost of gas sold flow through to revenue under gas cost recovery mechanisms. The following table compares our gas utility gross margin and therm deliveries by customer class during 2005, 2004 and 2003.
(a)
As measured at Mitchell International Airport in Milwaukee, Wisconsin. Normal degree days are based upon a twenty-year moving average.
2005 vs. 2004:
Gas utility gross margin increased by $8.7 million or 2.4% between comparative periods. This increase reflects $6.5 million of price increases which reflects the full year's impact of a $25.9 million annual rate increase, which became effective in March 2004. Total therm deliveries were 4.9% higher during 2005 primarily due to increased transport gas deliveries of 124.2 million therms. Transport volumes increased between the comparative periods due to a higher amount of electric generation from natural gas within our service territory. A portion of these sales are eliminated in consolidation. Our margins on these transport gas volumes are significantly lower than our margins for retail gas sales. The price increases and increased transport volumes were offset, in part, by a decrease in residential therm deliveries. Residential therm deliveries decreased 2.3% as compared to 2004, due to slightly warmer weather and a decrease in use per customer that was driven in part by higher commodity prices. As measured by heating degree days, 2005 was less than 1% warmer than 2004.
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 March 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.
Other Operation and Maintenance Expenses
2005 vs. 2004: Other operation and maintenance expenses increased by $47.4 million or 4.9% during 2005 compared with 2004. The most significant changes in our operation and maintenance expense related to increased lease costs and increased nuclear outage costs. Partially offsetting these increases were a charge in 2004 for severance costs related to the voluntary severance program and lower employee costs in 2005 due to fewer employees.
The largest operations and maintenance increase for the utility energy segment related to $50.0 million of costs that we recognized under lease agreements between We Power and Wisconsin Electric in connection with our Power the Future plan. Initially, Wisconsin Electric defers the lease payments and then amortizes the payments to expense as we recover revenues from our customers under specific pricing agreements. As noted in the electric revenue discussion, in May 2004 and May 2005 the PSCW approved pricing increases to recover the Wisconsin retail portion of these lease costs.
In addition to the increased lease costs, our nuclear operating and maintenance expense increased approximately $11.0 million due to two scheduled refueling outages in 2005 where we also replaced the reactor vessel heads. In 2004, we had one scheduled refueling outage and in 2006 we only have one scheduled refueling outage. This increase was partially offset by a $10.0 million settlement we received to resolve a vendor dispute.
Additionally, in 2004 we recognized $28.2 million of severance related costs due to the voluntary severance program that was implemented in the second half of 2004. In 2005, we had approximately 210 fewer employees, which reduced operation and maintenance costs by $12.9 million.
Benefit costs increased $7.0 million between comparative periods due to increased pension and medical costs. In October 2005, we announced that we were offering to our retirees a Medicare Advantage program as an option within our existing post-retirement medical and drug plans. As a result of the Medicare Advantage program we anticipate that our 2006 post-retirement costs will be approximately $13.0 million less than our 2005 costs. However, we expect an increase in our 2006 pension costs to offset this reduction due to lower discount rates and lower than expected historical returns on plan assets.
2004 vs. 2003: Other operation and maintenance expenses increased by $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 our Power the Future plan. In May 2004, the PSCW approved a pricing increase to recover the Wisconsin retail portion of these lease costs. 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 2004, 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 severance program 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.
Depreciation, Decommissioning and Amortization Expense
2005 vs. 2004: Depreciation, decommissioning and amortization expense increased by $8.6 million in 2005 as compared to 2004. This increase was primarily due to increased depreciable plant balances. In November 2005, the PSCW approved new depreciation rates which are effective January 1, 2006. We expect the new depreciation rates to reduce annual depreciation expense by approximately $17 million due to the lengthening of nuclear plant lives.
2004 vs. 2003: Depreciation, decommissioning and amortization expense decreased by $0.7 million in 2004 as compared to 2003. This slight decrease was due to a $7.7 million reduction in decommissioning expense in 2004
due to the tax impacts associated with rebalancing the nuclear decommissioning trusts. This decrease was partially offset by increased depreciation expense on increased depreciable plant balances.
NON-UTILITY ENERGY SEGMENT CONTRIBUTION TO OPERATING INCOME
Effective May 31, 2005, we sold our Calumet facility, which was previously included in the operations of the non-utility energy segment. As a result of this sale, we have determined that the Calumet operations meet the definition of discontinued operations under Statement of Financial Accounting Standards (SFAS) 144, Accounting for the Impairment or Disposal of Long-Lived Assets. All periods presented have been restated to exclude the results of the Calumet operations. See Results of Operations -- Discontinued Operations below for further information.
The most significant subsidiary included in this segment is We Power, which constructs and owns power plants associated with our Power the Future plan and leases them to Wisconsin Electric. This segment reflects revenues billed under the PWGS Unit 1 lease and the depreciation expense related to PWGS Unit 1. The following table compares our non-utility energy segment's operating income (loss) during 2005, 2004 and 2003.
2005 vs. 2004: Our non-utility energy segment had operating income of $19.5 million during 2005 compared with $4.6 million during 2004. The increase in operating income between the comparative periods is primarily due to Unit 1 at PWGS commencing service in July 2005. This unit had operating income of $18.9 million during its six months of operation in 2005.
2004 vs. 2003: Our non-utility energy segment had operating income of $4.6 million during 2004 compared with an operating loss of $55.7 million in 2003. 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.
CORPORATE AND OTHER CONTRIBUTION TO OPERATING INCOME
In August 2005, we announced our intent to sell our Minergy Neenah facility, which was previously included in the operations of corporate and other affiliates. As a result of this announcement, we have determined that the Minergy Neenah operations meet the definition of discontinued operations under SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets. All periods presented have been restated to exclude the results of Minergy Neenah operations. See Results of Operations -- Discontinued Operations below for further information. This segment primarily reflects the operations of Wispark and holding company costs that are not allocated to subsidiaries.
2005 vs. 2004: Corporate and other affiliates had operating income of $1.0 million in 2005 compared with an operating loss of $3.2 million in 2004. The improved results reflect increased earnings from Wispark. However, we are reducing our Wispark assets and we expect to see lower Wispark earnings in the future.
2004 vs. 2003: We had net corporate and other affiliates operating losses of $3.2 million during 2004 compared with net operating losses of $4.3 million in 2003.
CONSOLIDATED OTHER INCOME AND DEDUCTIONS, NET
The following table identifies the components of consolidated other income and deductions, net during 2005, 2004 and 2003.
2005 vs. 2004:
Other income and deductions, net increased by $47.5 million in 2005 compared to 2004. In 2004, we recognized $22.9 million of debt redemption costs associated with the early redemption of approximately $500 million of long-term debt. Similar debt redemption costs were not incurred in 2005. We recognized higher carrying costs on deferred electric transmission costs of $6.6 million. The allowance for funds used during construction increased $6.4 million in 2005 due to a higher average balance of allowance for funds used during construction (AFUDC) - qualifying utility construction projects in 2005.
2004 vs. 2003: Other income and deductions, net decreased by $25.9 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 approximately $500 million of the sales proceeds for early redemption of long-term debt.
CONSOLIDATED INTEREST EXPENSE
2005 vs. 2004: Total interest expense decreased by $20.0 million in 2005 compared with 2004. The decrease in interest expense primarily reflects lower average debt levels in 2005 as compared to 2004. During 2004, we reduced debt levels by $654.2 million primarily with proceeds from the sale of our manufacturing segment. However, due to the increased construction activity our year end debt balances have increased by $291.9 million. To the extent that we incur debt associated with construction in progress, we capitalize the interest costs in accordance with our accounting policies.
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%.
CONSOLIDATED INCOME TAXES
2005 vs. 2004: Our effective tax rate applicable to continuing operations was 33.0% in 2005 compared to 37.7% in 2004. In 2005, we reversed $16.3 million of valuation allowances associated with state net operating loss carry forwards as we concluded that it was more likely than not that we would realize these benefits. Excluding this nonrecurring item, our effective tax rate was 36.6%. For further information see Note H -- Income Taxes in the Notes to Consolidated Financial Statements.
2004 vs. 2003: In 2004, our effective income tax rate from continuing operations was 37.7% compared with a 35.5% rate during 2003. The increase in the effective tax rate is due primarily to the inability to deduct state income taxes on losses of certain non-utility subsidiaries.
DISCONTINUED OPERATIONS
Our discontinued operations include our manufacturing operations which were sold effective July 31, 2004, our Calumet facility which was sold in May 2005 and our Minergy Neenah facility. As of December 31, 2005, we are considering offers to sell our Minergy Neenah facility.
The following table identifies the primary components of income from discontinued operations during 2005, 2004 and 2003.
Our 2005 earnings from discontinued operations reflect a gain on the sale of the Calumet facility, the favorable resolution of liabilities at Calumet and an adjustment to the carrying value of Minergy Neenah.
Our 2004 earnings from discontinued operations reflect an after-tax gain of $152.3 million on the sale of our manufacturing business. Our 2004 earnings from discontinued operations also reflect valuation charges of $79.3 million after-tax related to Calumet and $17.6 million after-tax related to Minergy Neenah.
Our 2003 earnings from discontinued operations reflect net operating earnings of $43.9 million related to our manufacturing segment.
See Note D -- Asset Sales, Divestitures and Discontinued Operations in the Notes to Consolidated Financial Statements for further information regarding the transactions described above.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS
The following table summarizes our cash flows during 2005, 2004 and 2003:
Operating Activities
Cash provided by continuing operating activities decreased to $576.9 million during 2005 compared with $599.0 million during 2004. This decline reflected increased working capital needs for our utility business and an increase in deferred costs, offset in part by lower cash taxes and increased cash earnings. During 2005, we experienced significant increases in natural gas costs which increased our working capital requirements for natural gas in storage. The increased natural gas costs also led to an increase in accounts receivable as the cost of gas is recovered dollar for dollar in our natural gas revenues. During 2005, we also experienced increased deferred costs related to transmission costs and deferred fuel. We would not expect similar levels of deferred transmission costs in 2006 as we received a rate order in January 2006 which increased our recoveries of transmission costs by
approximately $67.5 million per year. The deferred fuel costs related primarily to an extended outage at our nuclear plant, increased costs associated with problems in our vendors' ability to deliver coal via the railroad system and costs related to the implementation of the MISO Midwest Market. During 2005, our cash taxes were lower than 2004 due to the ability to realize tax benefits on the sale of non-utility assets and accelerated tax depreciation on PWGS Unit 1.
Cash provided by operating activities increased to $599.0 million during 2004 compared with $528.9 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.
Investing Activities
During 2005, we had $697.1 million of net cash outflows from investing activities. In 2004, we had net cash inflows from investing activities of $242.8 million and in 2003 we had net cash outflows of $595.2 million. In 2005, capital expenditures increased related to our Power the Future plan at We Power and for compliance with the consent decree entered into with the United States Environmental Protection Agency (EPA) (See Factors Affecting Results, Liquidity and Capital Resources -- Environmental Matters). In addition, expenditures associated with nuclear fuel purchases were higher during 2005. In 2004, we recognized proceeds of $857.0 million for the sale of our manufacturing segment.
The following table identifies capital expenditures by year:
We Power, which is included in the Non-Utility Energy segment, had capital expenditures of $275.1 million, $190.4 million and $162.9 million for the three years ended December 31, 2005, 2004 and 2003.
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. As a result, the sale of assets is a significant component of our investing activities.
The following table identifies cash proceeds from asset sales:
Financing Activities
The following table summarizes our cash flows from financing activities:
During 2005, cash provided by financing activities was $157.8 million compared to $834.3 million of cash used for financing activities during 2004. In 2005, the primary uses of cash were to pay dividends on common stock and to purchase common stock to satisfy benefit plan obligations.
In July 2005, PWGS issued $155.0 million of 4.91% senior notes in a private placement. The senior notes have a mortgage style repayment feature and have an average life approximating 15 years. The final payment is due July 15, 2030. Proceeds from the sale of the senior notes were used primarily to repay short-term debt incurred during construction at PWGS. For further information, see Note E -- Port Washington Generating Station in the Notes to Consolidated Financial Statements.
Wisconsin Gas retired at the scheduled maturity date $65 million of 6-3/8% Notes due November 1, 2005. In November 2005, Wisconsin Gas issued $90 million of 5.90% Debentures due December 1, 2035. The securities were issued under shelf registration statements filed with the SEC. The proceeds from the sale were used to repay a portion of our outstanding commercial paper. The commercial paper was incurred to both retire the $65 million of 6-3/8% Notes and for working capital requirements.
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% senior notes due April 1, 2006.
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.
No new shares of common stock were issued in 2005. 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, we issued approximately 2.7 million new shares of common stock in connection with these plans. In 2004 and 2003, we received payments aggregating $4.8 million and $62.9 million, respectively. In February 2004, we announced that we did not expect to issue new shares under these programs; rather we instructed the independent plan agents to begin purchasing the shares in the open market in lieu of issuing new shares. During 2005 and 2004, our plan agents purchased 2.0 million shares at a cost of $75.1 million and 3.2 million shares at a cost of $102.3 million, respectively, to fulfill exercised stock options. In 2005, we received proceeds of $47.0 million related to the exercise of stock options compared with $66.1 million in 2004. 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 and reduce our debt levels. Our debt to total capital ratio has decreased from 68.3% at September 30, 2000 to 59.5% at December 31, 2005 due primarily to asset sales. Over the next several years, we expect to have some limited asset sales, but at levels significantly lower than the previous six year level.
In 2002, we initiated the construction of the first of our four planned generating units under our Power the Future program. The first unit at PWGS was completed and placed into service in July 2005. We expect to spend approximately $1.9 billion to complete construction of the remaining three generating units. 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 2006 and the next several years primarily through internally generated funds and short-term borrowings, supplemented by the issuance of intermediate or long-term debt securities depending on market conditions and other factors.
We have access to capital markets and have been able to generate funds internally and externally to meet our capital requirements. Our ability to attract the necessary financial capital at reasonable terms is critical to our overall strategic plan. We believe that we have adequate capacity to fund our operations for the foreseeable future through our borrowing arrangements and internally generated cash.
In March 2004, the Governor of Wisconsin signed into law a measure that gives utilities the ability to securitize the portion of customer bills that recovers the cost of certain investments intended to improve the environment. The measure would result in a lower cost to customers when compared to traditional financing and ratemaking. In June 2004, 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 subject to further PSCW approval prior to issuance. We will continue to evaluate the potential issuance of environmental trust bonds.
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, 2005, we had approximately $1.2 billion of available unused lines of bank back-up credit facilities on a consolidated basis and approximately $456.3 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, 2005:
Each of these facilities may be extended for an additional 364 days beyond the date of expiration, subject to lender agreement.
We are currently in the process of renewing Wisconsin Energy's $300 million credit facility which expires on April 8, 2006. In addition, we are also reviewing the possibility of amending and extending the other existing Wisconsin Energy, Wisconsin Electric and Wisconsin Gas credit facilities.
The following table shows our consolidated capitalization structure at December 31:
As described in Note J -- 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, 2005.
On March 29, 2005, S&P affirmed the security ratings of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas and changed the security ratings outlook from stable to negative for all three companies. The security rating outlooks assigned by 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.
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 to. 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+ to.
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
Our current estimated 2006, 2007 and 2008 capital expenditures, excluding the purchase of nuclear fuel, are as follows:
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 estimated capital requirements through 2010 for Power the Future include approximately $2.6 billion to construct 2,120 megawatts of new natural gas-fired and coal-fired generating capacity of which we have expended approximately $673.9 million through the end of 2005. In the fourth quarter of 2005, we completed the sale of approximately a 17% interest (200 megawatts) in the Oak Creek expansion to two parties, at which time we received approximately $34.6 million in cash. The co-owners will share ratably in the construction costs. Total output of all four units, including the two unaffiliated entities' portion, is 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. We Power, a non-utility subsidiary, is constructing the new generating plants, which will be leased to Wisconsin Electric under 25-30 year lease agreements. We expect that Wisconsin Electric will recover the lease payments in its utility rates.
In June 2005, we purchased the development rights to two wind farm projects from Navitas Energy Inc. We plan to develop the wind sites and construct wind turbines with a combined generating capability between 130 to 200-megawatts at a cost in the range of $250 to $320 million. We anticipate the cost to build the wind farm projects would be recovered in our rates. We plan to file the necessary regulatory and environmental applications in 2006.
We expect the turbines to be placed in service between 2007 and 2008 dependent upon the availability of wind turbines and the receipt of necessary regulatory approvals.
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, 2005. 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.
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 as reflected in the table below. 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 G -- 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, 2005:
(a)
The amounts included in the table are calculated using current market prices, forward curves and other estimates. Contracts with multiple unknown variables have been omitted from the analysis.
(b)
Principal and interest payments on our Long-Term Debt and the Long-Term Debt of our affiliates (excluding capital lease obligations).
(c)
Capital Lease Obligations of Wisconsin Electric for nuclear fuel lease and purchase power commitments.
(d)
Operating Lease Obligations for purchased power and rail car leases for Wisconsin Energy and affiliates.
(e)
Purchase Obligations under various contracts for the procurement of fuel, power, gas supply and associated transportation related to utility operations and for construction, information technology and other services for utility and We Power operations.
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. For a discussion of 2006, 2007 and 2008 estimated capital expenditures, see Capital Requirements above.
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 PWGS 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 approved key financial terms of the leased generation contracts including fixed construction costs of the PWGS at $309.6 million and $280.3 million (2001 dollars), respectively, subject to escalation at the GDP inflation rate, force majeure, excused events and event of loss provisions. For additional information, see Power the Future -- Port Washington below.
In addition, in November 2003, the PSCW issued a written order granting a CPCN to commence construction of two 615-megawatt super critical pulverized coal generating units (Oak Creek expansion) adjacent to the site of Wisconsin Electric's existing Oak Creek Power Plant. The order approves key financial terms of the leased generation contracts including a target construction cost of the Oak Creek expansion of $2.191 billion, plus, subject to PSCW approval, cost over-runs of up to 5%, costs attributable to force majeure events, excused events and event of loss provisions. For additional information, see Power the Future -- Oak Creek Expansion 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, continuing legal challenges to permits obtained, changes in applicable laws or regulations, adverse interpretation or enforcement of permit conditions, laws and regulations by the permitting agencies, the inability to obtain necessary operating permits in a timely manner, governmental actions and events in the global economy.
If final costs for the construction of PWGS exceed the fixed costs allowed in the PSCW order, absent a finding by the PSCW of extraordinary circumstances such as force majeure conditions, this excess will not adjust the amount of the lease payments recovered from Wisconsin Electric. If final costs of the Oak Creek expansion are within 5% of the target cost, and the additional costs are deemed to be prudent by the PSCW, the final lease payments for the Oak Creek expansion recovered from Wisconsin Electric would be adjusted to reflect the actual construction costs. Costs above the 5% cap would not be included in lease payments or recovered from customers absent a finding by the PSCW of extraordinary circumstances such as force majeure conditions.
Regulatory Recovery Risk:
The electric operations of Wisconsin Electric burn natural gas in its leased power plants, in several of its peaking power plants and as a supplemental fuel at several coal-fired plants. In addition, the cost of purchased power is generally tied to the cost of natural gas. Wisconsin Electric bears regulatory risk for the recovery of these fuel and purchased power costs when these costs 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. Since our merger with WICOR in 2000 through December 31, 2005, we were allowed to request recovery of fuel and purchased power costs from retail electric customers in the Wisconsin jurisdiction through our rate review process with the PSCW and in interim fuel cost hearings when such annualized costs were expected to be more than 3% higher than the forecasted costs used to establish rates. In January 2006, the PSCW approved a plan for Wisconsin Electric to refund any over-collection of fuel costs on an annual basis for 2006 to Wisconsin ratepayers and any under-collection will be subject to a 2% band. Beginning in 2007, the electric operations of Wisconsin Electric will operate under a fuel cost adjustment clause in the Wisconsin retail jurisdiction for under- and over- collection within a 2% band.
For 2005, 2004 and 2003, actual net fuel and purchased power costs at Wisconsin Electric exceeded fuel costs included in rates by $35.6 million, $0.8 million and $7.6 million, respectively.
Our utility energy segment accounts for its regulated operations in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation. Our rates are determined by regulatory authorities. Our primary regulator is the PSCW. SFAS 71 allows regulated entities to defer certain costs that would otherwise be charged to expense, if the regulated entity believes the recovery of these costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators, and recovery of these deferred costs in future rates is subject to the review and approval of those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of these costs is not approved by our regulators, the costs are charged to income in the current period. We expect to recover our outstanding regulatory assets in rates over a period of no longer than 20 years. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. Under SFAS 71, we record these items as regulatory liabilities.
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 optimize utilization of their available generating capacity and energy during periods when available power resources are projected to be greater than or less than our load obligations. This practice may also include forward contracts for the purchase of power during periods when the anticipated market price of electric energy is below expected incremental power production costs. In addition, effective April 1, 2005, our electric utilities became market participants in the MISO Midwest Market. For additional information on the MISO Midwest Market see Utility Rates and Regulatory Matters -- Other Utility Rate Matters and Industry Restructuring and Competition -- Electric Transmission and Energy Markets below. We manage our fuel and gas supply costs through a portfolio of short- and long-term procurement contracts with various suppliers for the purchase of coal, uranium, natural gas and fuel oil. In addition, we manage our natural gas price risk by utilizing a gas hedging program.
In July 2005, we received a letter from Union Pacific Corporation notifying us that a force majeure event requiring maintenance on a Union Pacific railroad line was expected to result in a 15-20% reduction in the amount of contracted deliveries of Powder River Basin coal to certain of our coal generating facilities from June 2005 through November 2005. In response, we reduced generation at certain coal fueled units, primarily during lower cost off peak periods, to conserve coal inventories. This required us to obtain additional megawatt hour purchases through other potentially higher cost generating resources in the MISO Midwest Market. In August 2005, we requested and received approval from the PSCW to defer incremental fuel costs associated with reduced coal deliveries. Through December 31, 2005, we deferred approximately $26.0 million of incremental fuel costs and we expect to recover these costs in future rates, subject to review and approval of the PSCW. We do not expect to defer any additional costs related to this matter.
Wisconsin'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 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, both because the supply of natural gas in recent years has not kept
pace with the demand for natural gas and due to the impacts of hurricanes on offshore Gulf of Mexico natural gas production. We expect that demand for natural gas will remain high into the foreseeable future and that significant price relief will not occur until additional natural gas is added to the nation's energy supply mix.
Higher natural gas costs increase our working capital requirements and result 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.
In February 2005, the PSCW authorized the use of the escrow method of accounting for bad debt costs allowing for deferral of Wisconsin residential bad debt expense that exceed amounts allowed in rates. In 2004 and 2003, we had approval from the PSCW to defer residential bad debt net write-offs that exceed amounts allowed in rates.
As a result of gas cost recovery mechanisms, our gas distribution subsidiaries receive dollar for dollar recovery on the cost of natural gas. However, increased natural gas costs increase the risk that customers will switch to alternative fuel sources, which could reduce future gas margins. In addition, we are experiencing reduced usage of natural gas by our residential customers, who contribute higher margins than other customer classes, due to the increased natural gas costs. We expect to continue to experience this reduced usage during the 2006 winter heating season.
Weather: 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 2005, 2004 and 2003, as measured by degree-days, may be found above in Results of Operations.
Interest Rate Risk: We have various short-term borrowing arrangements to provide working capital and general corporate funds. We also have variable rate long-term debt outstanding at December 31, 2005. Borrowing levels under these arrangements vary from period to period depending upon capital investments and other factors. Future short-term interest expense and payments will reflect both future short-term interest rates and borrowing levels.
We performed an interest rate sensitivity analysis at December 31, 2005 of our outstanding portfolio of $456.3 million of short-term debt with a weighted average interest rate of 4.39% and $189.8 million of variable-rate long-term debt with a weighted average interest rate of 3.77%. A one-percentage point change in interest rates would cause our annual interest expense to increase or decrease by approximately $4.6 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. Through December 31, 2005, we were operating under a PSCW-ordered, qualified five-year rate restriction period. For further information about the rate restriction, see Utility Rates and Regulatory Matters below.
At December 31, 2005, 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 an 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 8.5%.
Fiduciary oversight for the nuclear decommissioning trust fund investments is also the responsibility of the 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.
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, 2005, we estimate that the potential payments under these agreements that could result from credit rating downgrades totaled approximately $78.2 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 and Risk Factors in Item 1A above.
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 PWGS and the Oak Creek expansion by We Power. We Power will lease the new plants 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 PWGS consisting of two 545-megawatt natural gas-fired combined cycle generating units (PWGS 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, which was completed in December 2004, and American Transmission Company LLC (ATC) to construct required transmission system upgrades to serve PWGS Units 1 and 2 as a result of their concurrent applications. PWGS Unit 1 was completed in July 2005 and placed into service at that time. Unit 1 was completed within the PSCW approved cost parameters. In October 2003, we received approval from the Federal Energy Regulatory Commission (FERC) to transfer by long-term lease certain associated FERC jurisdictional transmission related assets from We Power to Wisconsin Electric. 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 PWGS Units 1 and 2. Key terms of the leased generation contracts include:
Initial lease term of 25 years with the potential for subsequent renewals at reduced rates;
Cost recovery over a 25 year period on a mortgage basis amortization schedule;
Imputed capital structure of 53% equity, 47% debt;
Authorized rate of return of 12.7% on equity;
Fixed construction cost of the PWGS Units 1 and 2 at $309.6 million and $280.3 million (2001 dollars) subject to escalation at the GDP inflation rate;
Recovery of carrying costs during construction; and
Ongoing PSCW supervisory authority over those lease terms and conditions specifically identified in the Port Order, which do not include the key financial terms.
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. 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: There are currently no legal challenges to the construction of the PWGS and all construction permits have been received for Units 1 and 2. As a result of the enactment of the Energy Policy Act of 2005 (the Energy Policy Act) the FERC, through an amendment to Section 203 of the Federal Power Act, has been given jurisdiction over the acquisition of generation (which includes leasing generation), an activity that previously was not subject to the FERC's jurisdiction. Under the FERC's recently issued rules implementing the Energy Policy Act, Wisconsin Electric will be required to seek FERC authorization in order to lease the remaining PWGS unit prior to the unit being placed into service. We are unable to determine at this time the magnitude of the impact of this new regulatory requirement on the Power the Future plan, if any.
Power the Future - Oak Creek Expansion
Background: In November 2003, the PSCW issued an order (the Oak Creek Order) granting Wisconsin Energy, Wisconsin Electric and We Power a CPCN to commence construction of two 615-megawatt coal-fired units (the Oak Creek expansion) to be located adjacent to the site of Wisconsin Electric's existing Oak Creek Power Plant. We anticipate the first unit will be operational in 2009 and the second unit will be operational in 2010. The Oak Creek Order concluded, among other things, that there was a need for additional electric generation for Southeastern Wisconsin and that a diversity of fuel sources best serves the interests of the State. The total cost for the two units was set at $2.191 billion, and the order provided for recovery of excess costs of up to 5% of the total project, subject to a prudence review by the PSCW. The CPCN was granted contingent upon us obtaining the necessary environmental permits. All necessary permits have been received at this time. In June 2005, construction commenced at the site.
In November 2005, we completed the sale of approximately a 17% interest in the project to two unaffiliated entities, who will share ratably in the construction costs.
Lease Terms: In October 2004, the PSCW approved the lease generation contracts between Wisconsin Electric and We Power for the Oak Creek expansion. Key terms of the leased generation contracts include:
Initial lease term of 30 years with the potential for subsequent renewals at reduced rates;
Cost recovery over a 30 year period on a mortgage basis amortization schedule with the potential for subsequent renewals at reduced rates;
Imputed capital structure of 55% equity, 45% debt;
Authorized rate of return of 12.7% on equity;
Recovery of carrying costs during construction; and
Ongoing PSCW supervisory authority over those lease terms and conditions specifically identified in the Oak Creek Order, which do not include the key financial terms.
In April 2004, the PSCW approved the deferral of certain costs related to the Oak Creek expansion for recovery in future rates. (See Limited Rate Adjustment Request below for further information).
Legal and Regulatory Matters: The CPCN granted for the construction of the Oak Creek expansion was the subject of a number of legal challenges by third parties; these legal challenges were resolved in June 2005. We have received all permits necessary to commence construction. Certain of these permits continue to be contested, but remain in effect unless and until overturned by a reviewing court or administrative law judge. The major permits are discussed below.
In November 2004, a Dane County Circuit Court judge reviewing challenges to the PSCW'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. The Dane County Circuit Court's decision was appealed and in June 2005, the Supreme Court of Wisconsin issued its decision which reversed the Dane County Circuit Court's decision that vacated the PSCW order authorizing us to build the Oak Creek expansion and upheld the PSCW's order in all respects. The CPCN granted by the PSCW was reinstated and is in full force and effect.
As a result of the delay to the start of construction caused by litigation, the project cost is expected to increase by $50 to $55 million. This represents an increase of approximately 2.4% to 2.6% in the total cost of the project. We believe these costs are ultimately recoverable under the terms of the lease agreements between We Power and Wisconsin Electric. However, recovery is subject to our final calculation of costs and also to review and approval by the PSCW.
In September 2003, several parties filed a request with the Wisconsin Department of Natural Resources (WDNR) for a contested case hearing in connection with our application to the WDNR for a Chapter 30 permit for wetlands and waterways alterations and construction on the bed of Lake Michigan for the construction of the Oak Creek expansion. That request was granted and assigned to an administrative law judge. The hearing took place in August 2004 and in November 2004, the administrative law judge approved the WDNR's issuance of the Chapter 30 permit for the Oak Creek expansion. In December 2004, 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 based on procedural errors. The WDNR joined in this motion. In March 2005, the court dismissed the appeal. The opponents appealed the court's dismissal to the Wisconsin Court of Appeals. In February 2006, the Wisconsin Court of Appeals affirmed the lower court's dismissal of the case. The opponents can seek reconsideration of the court's decision or can petition the Wisconsin Supreme Court for review.
We applied to the WDNR to modify the existing Wisconsin Pollution Discharge Elimination System (WPDES) permit that is required for operation of the water intake and discharge system for the planned Oak Creek expansion and existing Oak Creek generating units. In March 2005, the WDNR determined that the proposed cooling water intake structure and water discharge system meets regulatory requirements and reissued the WPDES permit with specific limitations and conditions. The opponents filed a petition for judicial review in Dane County Circuit Court and a request for a contested case proceeding with the WDNR. In September 2005, the judicial review proceeding in Dane County Circuit Court was dismissed. All parties to this action agreed to the dismissal. The WDNR granted a contested case hearing and the administrative law judge has scheduled a hearing for March 2006. We anticipate a decision by the administrative law judge in 2006.
In May 2005, we received the Army Corps of Engineers federal permit necessary for the construction of the Oak Creek expansion. Opponents may appeal the permit in federal court.
In January 2004, the WDNR issued the Air Pollution Control Construction Permit (Air Permit) to Wisconsin Electric for the Oak Creek expansion. The permit was opposed and a contested case hearing with the WDNR was held in October 2004. In February 2005, an administrative law judge issued a decision affirming the WDNR January 2004 issuance of the Air Permit. The decision was opposed and project opponents filed a petition for judicial review with the Dane County Circuit Court. In September 2005, the Dane County Circuit Court dismissed with prejudice the appeal of the administrative law judge's decision. All parties to this action agreed to the dismissal. This dismissal is the final resolution of all legal challenges to the issuance of the Air Permit.
In addition, as a result of the enactment of the Energy Policy Act the FERC, through an amendment to Section 203 of the Federal Power Act, has been given jurisdiction over the acquisition of generation (which includes leasing generation), an activity that previously was not subject to the FERC's jurisdiction. Under the FERC's recently issued rules implementing the Energy Policy Act, Wisconsin Electric will be required to seek FERC authorization in order to lease the two units that are part of the Oak Creek expansion prior to the units being placed into service. We are unable to determine at this time the magnitude of the impact of this new regulatory requirement on the Power the Future plan, if any.
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: For the period from March 2000 until December 31, 2005, the rates of We Energies (the trade name of Wisconsin Electric and Wisconsin Gas) were governed by an order from the PSCW in connection with the approval of the WICOR acquisition. Under this order, We Energies was restricted from increasing Wisconsin rates for a five year period ending December 31, 2005, with certain limited exceptions.
Wisconsin Electric: In July 2005, we filed an electric and steam price increase request with the PSCW. Under a limited rate proceeding, we requested an increase in electric rates of $143.6 million for 2006, and an $8.8 million total increase in rates for steam over the two year period of 2006 and 2007. The requested electric rate increase included: (1) costs associated with the continued investment in our Power the Future strategy; (2) recovery of transmission costs incurred that exceed the amount we are currently collecting from customers; (3) additional sources of renewable energy; and (4) a rate freeze for day to day operations of the electric system until 2008. The requested steam rate increase was due to (1) the costs of maintaining the steam system, (2) the cost of fuel and (3) the costs associated with making changes to our steam utility operations as part of the reconstruction of the Marquette Interchange project in downtown Milwaukee, Wisconsin.
Subsequent to the initial filing of this pricing request, we experienced a significant increase in the cost of fuel and purchased power due to the increases in natural gas prices and the reductions in coal deliveries as discussed above. In October 2005, we filed a letter with the PSCW informing them of our need to include the increased cost of natural gas used for generation of electricity in our pending 2006 pricing request. The PSCW considered these additional costs and approved an increase in electric rates of $222.0 million in January 2006. In addition, the PSCW approved an increase in steam rates of $7.8 million or 31.5% to be phased in over the two year period of 2006 and 2007. These rate increases became effective on January 26, 2006 and we anticipate will remain in effect through December 2007.
The January 2006 order also addressed Wisconsin Electric's under- and over-collection of fuel costs in its electric rates. For 2006, the PSCW approved a plan for Wisconsin Electric to refund any over-collection of fuel costs on an annual basis to ratepayers and the band for under-collection of fuel costs will be 2%. Beginning in 2007, the electric operations of Wisconsin Electric will operate under a fuel cost adjustment clause in the Wisconsin retail jurisdiction with a plus or minus 2% band.
In June 2005, we filed with the PSCW a natural gas price increase request of $27.4 million for Wisconsin Electric. The increase was requested to address the higher costs associated with adding and maintaining gas mains and infrastructure to maintain safety and reliability and certain costs related to gas in storage. In January 2006, we received approval from the PSCW for a rate increase of $21.4 million or 2.9% for Wisconsin Electric. This rate increase became effective on January 26, 2006 and we anticipate will remain in effect through December 2007.
The January 2006 order approved a return on equity for Wisconsin Electric operations of 11.2%. In 2005, Wisconsin Electric's approved return on equity was 12.2%.
The table below summarizes the anticipated annualized revenue impact of recent rate changes.
(a)
In January 2006, the PSCW issued a final order authorizing an increase in steam rates of $7.8 million over the two year period of 2006 and 2007.
(b)
In November 2005, the PSCW issued a final order authorizing a fuel surcharge for $7.7 million of additional fuel costs. In March 2005, the PSCW issued an interim order authorizing a fuel surcharge for $114.9 million that was effective until the November 2005 final order was issued by the PSCW. The final November 2005 order for $122.6 million superseded the March 2005 interim order.
(c)
In May 2004, the PSCW issued a final order authorizing an increase in electric rates for costs associated with the PWGS under construction and increased costs associated with low-income energy assistance.
(d)
In October 2003, the PSCW issued a final order authorizing a fuel surcharge for $6.1 million of additional fuel costs. In March 2003, the PSCW issued an interim order authorizing a surcharge for $55.1 million of additional fuel costs on an annualized basis subject to true up.
Wisconsin Gas:
As discussed above, Wisconsin Gas was also under the five year rate restriction period which ended December 31, 2005.
In June 2005, we filed with the PSCW a natural gas price increase request, as well as all materials for the PSCW and other parties to commence the rate review required by the March 2000 order. We requested a rate increase of $53.2 million to address the higher costs associated with adding and maintaining gas mains and infrastructure to maintain safety and reliability and certain costs related to gas in storage. In January 2006, we received approval from the PSCW for a rate increase of $38.7 million or 3.7% for Wisconsin Gas. This rate increase became effective on January 26, 2006 and we anticipate will remain in effect through December 2007.
The January 2006 order approved a return on equity for Wisconsin Gas operations of 11.2%. In 2005, Wisconsin Gas had an approved return on equity of 11.8%.
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 PWGS and the Oak Creek expansion 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 Oak Creek expansion, we amended this filing to reduce the total revenue request to $52.4 million. In May 2005, the PSCW issued its final written order implementing an annualized increase in electric rates of $59.7 million (3.1%) and an increase of $0.5 million (3.6%) in steam rates.
2005 Fuel Recovery Filing: 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 received approval for the increase in fuel recoveries on an interim basis in March 2005. In November 2005, we received the final rate order, which authorized an additional $7.7 million in rate increases, for a total increase of $122.6 million (6.2%). In December 2005, two parties filed suit against the PSCW in Dane County Circuit Court challenging the PSCW's decision to allow fuel cost recovery, while allowing us to keep the savings that resulted from the WICOR acquisition. As a condition of the PSCW approval of the WICOR acquisition, Wisconsin Electric and Wisconsin Gas were restricted from increasing Wisconsin rates for a five year period ending December 31, 2005, with certain limited exceptions, but we were allowed to keep the savings generated from the merger. We believe the challenge of the PSCW's decision is without merit, however the ultimate outcome of this matter cannot be determined at this time.
Other Utility Rate Matters
Electric Transmission Cost Recovery: Wisconsin Electric divested of its transmission assets with the formation of the ATC in January 2001. We now procure transmission service from ATC at FERC approved tariff rates. In connection with the formation of the ATC, our transmission costs have escalated due to the socialization of costs within the ATC and increased transmission infrastructure requirements in the state. In 2002, in connection with the increased costs experienced by our customers, the PSCW issued an order which allowed the deferral of transmission costs in excess of amounts imbedded in rates. We are allowed to earn a return on the unrecovered transmission costs at our weighted average cost of capital. As of December 31, 2005, we have deferred $169.4 million of unrecovered transmission costs. In January 2006, our rates were increased by approximately $67.5 million annually to recover transmission costs that were not currently in rates. We will continue to accrue carrying costs on the unrecovered balances.
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 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 band, and actual interim costs fall outside of established ranges, then we may file for a change in fuel recoveries on a prospective basis. For 2006, the upper band is 2% and we will refund any over-recovered annual fuel costs. For 2007, the band is plus or minus 2%.
Edison Sault and our Wisconsin Electric operations in Michigan operate under a Power Supply Cost Recovery 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 2005, no additional revenues were earned under the incentive portion of the GCRM and $0.2 million and $9.0 million of additional revenues were earned in 2004 and 2003 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 being collected in rates.
In 2003 and 2004, due to a combination of unusually high natural gas prices, a soft economy within our utility service territories, and limited governmental assistance available to low-income customers, we saw a significant increase in residential uncollectible accounts receivable. Because of this, we requested and received letters from the PSCW which allowed 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 January 2006, the PSCW issued an order approving the amortization over the next five years of the bad debts deferred in 2004 and 2003 for Wisconsin Gas and Wisconsin Electric gas operations. The bad debts deferred in 2004 and 2003 related to electric operations will be considered for recovery in future rates, subject to audit and approval of the PSCW.
In December 2004, we filed with the PSCW a request to implement a pilot program, which, among other things, is designed to better match our collection efforts with the ability of low income customers to pay their bills. Included in this filing was a request to implement escrow accounting for all residential bad debt costs. In February 2005, the PSCW approved our pilot program and our request for the use of escrow accounting. The final decision was received in March 2005. The escrow method of accounting for bad debt costs allows for deferral of Wisconsin residential bad debt expense that exceed amounts allowed in rates. As a result of this approval from the PSCW, we escrowed approximately $17.2 million in 2005 related to bad debt costs. These amounts were not addressed in the January 2006 rate order, and will therefore be considered for recovery in future rates, subject to audit and approval of the PSCW. We will continue following the escrow method of accounting for bad debts as approved in the March 2005 PSCW order.
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 subject to further PSCW approval prior to issuance. We will continue to evaluate the potential issuance of environmental trust bonds.
MISO Midwest Market: In January 2005, we requested deferral accounting treatment from the PSCW for certain incremental costs or benefits that may occur due to the implementation on April 1, 2005 of the MISO Midwest Market. We received approval for this accounting treatment in March 2005. Additionally, in March 2005 we submitted a joint proposal to the PSCW with other utilities requesting escrow accounting treatment for the MISO Midwest Market costs until each utility's first rate case following April 1, 2008. The purpose of the March 2005 request for escrow accounting was to provide clarification on costs not included in the March 2005 approval for deferral accounting treatment. We anticipate receiving a decision on this request in 2006. For additional information see Industry Restructuring and Competition -- Electric Transmission and Energy Markets -- MISO below.
Nuclear Refueling Outages - 2005: In January 2005, we requested deferral accounting treatment for non-fuel operations and maintenance expenses related to the second nuclear refueling outage that occurred in the fall of 2005. In March 2005, the PSCW denied this request. In May 2005, we requested and we received approval from the PSCW to defer replacement power costs incurred after May 30, 2005 due to the longer-than-expected outage at Point Beach Unit 2. We deferred $22.1 million of incremental purchased power costs related to the extended
outage. We expect to recover these deferred costs in future rates, subject to PSCW audit and approval. For additional information see Nuclear Operations below.
Reduced Coal Deliveries: In August 2005, we requested and received approval from the PSCW to defer incremental fuel costs associated with reduced coal deliveries. Through December 31, 2005, we deferred approximately $26.0 million of incremental fuel costs and we expect to recover these costs in future rates, subject to review and approval of the PSCW. We do not anticipate deferring additional costs under this order in 2006. For further information regarding rates see Management's Discussion and Analysis - Factors Affecting Results, Liquidity and Capital Resources -- Market Risks and Other Significant Risks -- Commodity Price Risk.
Depreciation Rates: In January 2005, Wisconsin Electric and Wisconsin Gas filed a joint application with the PSCW for certification of depreciation rates for specific classes of utility plant assets. In November 2005, we received notice from the PSCW that the proposed estimated lives, net salvage values and depreciation rates were approved and became effective January 1, 2006. We expect the new depreciation rates to reduce annual depreciation expense by approximately $17 million due to the lengthening of nuclear plant lives which will reduce annual expense.
ELECTRIC SYSTEM RELIABILITY
In response to customer demand for higher quality power required by modern equipment, we are evaluating and updating our electric distribution system. We are taking 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. For the long-term, we have developed a distribution system asset management strategy that requires increased levels of automation of both substations and line equipment to consistently provide the level of reliability needed for a digital economy.
Wisconsin Electric had adequate capacity to meet all of its firm electric load obligations during 2005. All of Wisconsin Electric's generating plants performed well during the warmest 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 2006. However, extremely hot weather, unexpected equipment failure or unavailability could require Wisconsin Electric to call upon load management procedures during 2006 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 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) adding emission control equipment to existing facilities to comply with new ambient air quality standards and federal clean air rules, (4) entering into agreements with the WDNR and EPA to reduce emissions of SO2 and NOx by more than 65% and mercury by 50% by 2013 from 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 consent decree is estimated to be approximately $600 million over the 10 years ending 2013. Through December 31, 2005, we have spent approximately $216.5 million associated with implementing the EPA agreement. There could be additional costs of compliance with the EPA consent decree should Wisconsin Electric elect to control rather than retire Units 5 and 6 at the Oak Creek Power Plant. We believe this additional cost may add approximately $150 million to $350 million to the estimate. For further information concerning 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 I -- Nuclear Operations in the Notes to Consolidated Financial Statements in this report, respectively.
National Ambient Air Quality Standards: In 2000 and 2001, Michigan and Wisconsin finalized state rules implementing phased emission reductions required to meet the National Ambient Air Quality Standard (NAAQS) for 1-hour ozone. In 2004, the EPA began implementing NAAQS for 8-hour ozone and fine particulate matter (PM 2.5 ). 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. Reductions associated with the 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 until the states develop rules and submit State Implementation Plans to the EPA to demonstrate how they intend to comply with the 8-hour ozone and fine particulate matter NAAQS.
1-hour Ozone Standard: The 1-hour ozone nonattainment rules currently being implemented by the State of Wisconsin and the ozone transport rules implemented by the State of Michigan limit NOx emissions in phases over the 2003 - 2008 time period.
Wisconsin Electric currently expects to incur total annual operation and maintenance costs of $2-3 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 rules, permitting recovery in rates of NOx emission reduction costs over an accelerated 10-year recovery period.
8-hour Ozone Standard: In April 2004, the EPA designated 10 counties in Southeastern Wisconsin as nonattainment areas for the 8-hour ozone NAAQS. States are required to develop and submit State Implementation Plans to the EPA by June 2007 to demonstrate how they intend to comply with the 8-hour ozone NAAQS. We expect that reductions needed to achieve compliance with the 8-hour ozone attainment standard will be implemented in stages from 2007 through 2010, and that some or all of these reductions will be accomplished through implementation of the Clean Air Interstate Rule (CAIR). See below for further information regarding CAIR. 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. However, the timing of the requirements may be impacted by requiring earlier installation of NOx controls at some units, depending on how the states implement the rules.
PM2.5 Standard: In December 2004, the EPA designated PM 2.5 nonattainment areas in the country. All counties in the State of Wisconsin and all counties in the Upper Peninsula of Michigan were designated as in attainment with the standard. It is unknown at this time whether Wisconsin or Michigan will require additional emission reductions as part of state or regional implementation of the PM2.5 standard and what impact those requirements would have on operation of our existing coal-fired generation facilities.
Clean Air Interstate Rule: The EPA issued the final CAIR regulation in March 2005 to facilitate the states in meeting the 8-hour ozone and PM 2.5 standards by addressing the regional transport of SO2 and NOx. CAIR requires NOx and SO2 emission reductions in two phases from electric generating units located in a 28-state region within the eastern United States. Wisconsin and Michigan are affected states under CAIR. The phase 1 compliance deadline is January 1, 2009 for NOx and January 1, 2010 for SO2, and the phase 2 compliance deadline is January 1, 2015 for both NOx and SO2. Overall, the CAIR is expected to result in a 70% reduction in SO2 emissions and a 65% reduction in NOx emissions from 2002 emission levels. The states are required to develop and submit implementation plans by October 2006, and until those plans are in place, it is not possible to estimate the impact of the CAIR. 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.
Clean Air Mercury Rule: The EPA issued the final Clean Air Mercury Rule (CAMR) in March 2005 following the agency's 2000 regulatory determination that utility mercury emissions should be regulated. CAMR limits mercury emissions from new and existing coal-fired power plants, and caps utility mercury emission in two phases, applicable in 2010 and 2018. The caps limit emissions at approximately 20% and ultimately 70% below today's utility mercury levels. The states are required to develop and submit implementation plans by November 2006. Until those plans are in place, it is not possible to estimate the final impact of the CAMR, but additional expenditures are anticipated in order to meet both phases of the federal rule. Because the technology is under development, it is difficult to estimate the cost. We believe the range of possible expenditures could be approximately $50 million to $200 million. The construction air permit issued for the Oak Creek expansion is not impacted by the new rule.
The federal rule is being challenged by a number of states including Wisconsin and Michigan. Depending on the litigation, the timing for compliance may be affected.
The WDNR independently developed mercury emission control rules that affect electric utilities in Wisconsin and issued state-only mercury control rules in October 2004. 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. We anticipate that the state rules will be revised or replaced, consistent with the CAMR requirements, and that no additional emission control investments will be needed as a result of the state-only rules.
Clean Air Visibility Rule: The EPA issued the Clean Air Visibility Rule (CAVR) in June 2005 to address regional haze, or regionally-impaired visibility caused by multiple sources over a wide area. The rule defines Best Available Retrofit Technology (BART) requirements for electric generating units and how BART will be addressed in the 28 states subject to EPA's CAIR. Under CAVR, states are required to identify certain industrial facilities and power plants that affect visibility in the nation's 156 Class I protected areas. States then determine the types of emission controls that those facilities must use to control their emissions. The pollutants from power plants that reduce visibility include particulate matter or compounds that contribute to fine particulate formation, NOx, SO2 and ammonia. States must submit plans to implement CAVR to the EPA by December 2007. The reductions associated with the state plans are scheduled to begin to take effect in 2014 with full implementation before 2018. Wisconsin Electric is currently unable to predict the impact that CAVR might have on the operations of our existing coal-fired generating facilities until the states develop rules and submit implementation plans to the EPA.
Clean Water Act: Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impact. This law dates back to 1972; however, prior to September 2004, 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 Power Plant, We Power's Oak Creek expansion and PWGS have been included in project costs. Studies to determine costs, if any, that may be associated with Wisconsin Electric's other existing facilities are expected to take place over the next three years.
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 - Proposed Consent Decree: Wisconsin Electric entered into a proposed consent decree with the EPA to address all matters relating to information requests received from the EPA 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.
Greenhouse Gases: There have been international efforts seeking legally binding reductions in emissions of greenhouse gases, principally carbon dioxide (CO2), including the United Nations Framework Convention on Climate Change held in Kyoto, Japan. While the Bush Administration has not supported U.S. ratification of the Kyoto Protocol or other legislation requiring reductions in CO2, in 2002, the Bush Administration announced a goal of reducing the greenhouse gas intensity of the U.S. economy by 18% by 2012. In addition, in December 2004, the U.S. Department of Energy announced the Climate VISION program in furtherance of reduced greenhouse gas emissions. We continue to take voluntary measures to reduce our emissions of greenhouse gases; however, the impact of any future legislation that would require reductions in greenhouse gases cannot be assessed at this time.
Wisconsin Electric continues to support flexible, market-based strategies to curb greenhouse gas emissions. These strategies include emissions trading, joint implementation projects and credit for early actions. Wisconsin Electric also supports a voluntary approach that encourages technology development and transfer and includes all sectors of the economy and all significant global emitters.
Wisconsin Electric emissions in future years will continue to be influenced by several actions planned or underway as part of the Power the Future plan, including:
Repowering the Port Washington Power Plant from coal to natural gas combined cycle units.
Adding coal-fired units using state-of-the-art technology as part of the Oak Creek expansion.
Increasing investment in energy efficiency and conservation.
Maintaining and increasing non-emitting generation by potentially adding approximately 130 to 200-megawatts of wind capacity and increasing customer participation in the Energy for Tomorow ® renewable energy program.
Successful renewal of the Point Beach Nuclear units' operating licenses.
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 have reached settlements with an insurance carrier and other third parties. Through litigation, we are continuing to pursue recovery against other third parties.
Arbitration Proceedings: Our largest electric customer owns two mines that operate in the Upper Peninsula of Michigan. The mines represent approximately 7% of our annual electric sales and less than 1% of our annual net income. The mines have special negotiated contracts that expire in December 2007. The contracts have price caps for approximately 80% of the energy sales. The mines are billed at rates reflecting incremental costs and amounts billed that exceed the price caps are refunded without interest in the year following the contract year. We do not recognize revenue on amounts billed that exceed the price caps.
The incremental power costs in the Upper Peninsula of Michigan are now determined by MISO. In April 2005, we began to bill the mines the incremental power costs as quantified by the MISO Midwest Market. The mines have notified us that they are disputing these billings and they have placed the disputed amounts in escrow. In September 2005, the mines notified us that they filed for formal arbitration related to the contracts. We have notified the mines that we believe that they have failed to comply with certain notification provisions related to annual production as specified within the contracts. As of December 31, 2005, the mines have placed $70.6 million in escrow. As noted above, the amounts that have been placed in escrow primarily relate to amounts that would have been refunded without interest in the year following the contract year. At this time, we are unable to predict the outcome of the formal arbitration process, but we believe that it will not have a material impact on our financial condition or results of operations.
Stray Voltage: On July 11, 1996, the PSCW issued a final order regarding the stray voltage policies of Wisconsin'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, awarding $1.2 million to the plaintiffs in a stray voltage lawsuit. The Supreme Court rejected the argument that if a utility company's measurement of stray voltage is below the PSCW "level of concern," that utility could not 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 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 2005, 2004 and 2003, Point Beach provided approximately 20% of Wisconsin Electric's net electric energy supply.
Each Unit at the Plant has a scheduled refueling outage approximately every 18 months. In 2005, Unit 2 had a scheduled refueling outage over the second and third quarters and Unit 1 had a scheduled refueling outage over the third and fourth quarters. During the 2005 scheduled refueling outages we replaced the reactor vessel heads at each Unit. As expected, this work, along with other planned maintenance, resulted in longer than normal outages. During scheduled refueling outages, we incur significant operations and maintenance costs for work performed during the outages and we incur costs associated with replacement power. See Results of Operations for further discussion regarding the costs associated with nuclear outages. In the fourth quarter of 2006, Unit 2 is scheduled to have a refueling outage. In 2004, Unit 1 had a scheduled refueling outage in the second quarter and in 2003, Unit 2 had a scheduled refueling outage over the third and fourth quarters.
In February 2004, NMC and Wisconsin Electric filed an application with the United States Nuclear Regulatory Commission (NRC) to renew the operating license for both Units for an additional 20 years. The NRC approved the license renewal request in December 2005. The new operating licenses expire in October 2030 for Unit 1 and March 2033 for Unit 2.
In February 2006, we announced that we are undertaking a formal review this year regarding our options for the ownership and operation of Point Beach. At December 31, 2005, NMC operated seven nuclear generating units,
down from eight units at December 31, 2004. As of February 2006, that number has decreased to six units and another owner has announced the planned sale of their unit, which would further reduce the size of the fleet operated by NMC. Given these changes, we believe it is prudent to evaluate a range of options for Point Beach. The options that we are planning to evaluate include: (1) continued operation by NMC, (2) continued operation by a third party operator other than NMC, (3) a return to in-house operation of the plant by Wisconsin Electric and (4) a sale of the Point Beach facility. We plan to complete this formal review in the fourth quarter of 2006.
In July 2000, our senior management authorized the commencement of initial design work for the power uprate of both 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 by the PSCW to load and store sufficient dry fuel storage containers to allow Point Beach Units 1 and 2 to operate to the end of their original operating licenses, but not to exceed the original 48-canister capacity of the dry fuel storage facility. The original operating licenses were set to expire in October 2010 for Unit 1 and in March 2013 for Unit 2 before they were renewed by the NRC in December 2005.
Temporary storage alternatives at Point Beach are necessary until the United States Department of Energy takes ownership of and permanently removes the used fuel as mandated by the Nuclear Waste Policy Act of 1982, as amended in 1987. The Nuclear Waste Policy Act established the Nuclear Waste Fund which is composed of payments made by the generators and owners of such waste and fuel. Effective January 31, 1998, the Department of Energy failed to meet its contractual obligation to begin removing used fuel from Point Beach, a responsibility for which Wisconsin Electric has paid a total of $207.4 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. In October 2004, the Court of Federal Claims granted Wisconsin Electric's motion for summary judgment on liability. The Court has subsequently scheduled the trial for March 2007. Wisconsin Electric has incurred substantial damages to date and damages continue to accrue. We are
seeking recovery of our damages in this lawsuit and we expect that any recoveries would be considered in setting future rates.
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 support large regional transmission organizations (RTOs), which will affect the structure of the wholesale market. To this end, the MISO implemented a bid-based market, the MISO Midwest Market, including the use of locational marginal pricing (LMP) to value electric transmission congestion. The MISO Midwest Market commenced operation on April 1, 2005. The timeline for restructuring and retail access continues to be stretched out, and it is uncertain when retail access will happen in Wisconsin; however, Michigan has adopted retail choice which potentially affects our Michigan operations. In August 2005, President Bush signed into law the Energy Policy Act, which impacts the electric utility industry. (See Other Matters below for additional information on the Energy Policy Act). In addition, major issues in industry restructuring, implementation of RTO markets and market power mitigation received substantial attention in 2005. 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:
Addition of new generating capacity in the state;
Modifications to the regulatory process to facilitate development of merchant generating plants;
Development of a regional independent electric transmission system operator; and
Improvements to existing and addition of new electric transmission lines in the state.
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.
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 has not had, and is not expected to have a material impact on Wisconsin Electric's business. Wisconsin Electric had one wholesale customer in Illinois, the City of Geneva, whose contract expired on December 31, 2005.
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.
ATC is regulated by the FERC for all rate terms and conditions of service and is a transmission-owning member of MISO. As of February 1, 2002, operational control of ATC's transmission system was transferred to MISO, and Wisconsin Electric and Edison Sault became non-transmission owning members and customers of MISO.
MISO: In connection with its status as a FERC approved RTO, MISO implemented a bid-based energy market, the MISO Midwest Market, which commenced operations on April 1, 2005. As part of this energy market, the MISO developed a market-based platform for valuing transmission congestion premised upon the LMP system that has been implemented in certain northeastern and mid-Atlantic states. The LMP system includes the ability to mitigate or eliminate congestion costs through the use of Financial Transmission Rights (FTRs). FTRs are allocated to market participants by MISO. The first allocation of FTRs was completed for the period of April 1, 2005 through August 31, 2005. The FTR allocation process was then performed again for the period from September 1, 2005 to May 31, 2006. To date, our unhedged congestion charges have not been material.
MISO deferred the costs to develop and start-up its energy market (new software systems and personnel). Now that the market is operational, the development and start-up costs are charged to MISO 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 certain incremental costs or benefits that may occur due to the implementation of the MISO Midwest Market. Our request excluded LMP energy costs because these costs are subject to recovery under the Wisconsin Fuel Cost Adjustment Procedure. In March 2005, the PSCW accepted our request. We submitted another joint proposal with other utilities in March 2005, requesting escrow accounting treatment for MISO Midwest Market costs until each utility's first rate case following April 1, 2008. The purpose of the March 2005 request for escrow accounting was to provide clarification on costs not included in the March 2005 approval for deferral accounting treatment. For further information on the accounting for MISO transactions see Critical Accounting Estimates below.
In MISO, base transmission costs are currently being paid by load serving entities (LSEs) located in the service territories of each MISO 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 MISO on or around February 1, 2008. In addition, FERC ordered a seams elimination charge to be paid by MISO 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 MISO and PJM Interconnection, L.L.C. The FERC ordered that certain existing transmission transactions continue to pay for through and out service from December 1, 2004 until March 31, 2006. The details of the seams elimination charge and the quantification of the existing transaction charge are the subject of a hearing process initiated by FERC in a February 2005 order. A decision from the hearing process is expected in the second half of 2006. In January 2006, Wisconsin Electric along with certain other parties to the proceeding, submitted an offer of settlement to the presiding administrative law judge that, if approved, will resolve all issues set for hearing that impact Wisconsin Electric with regard to the continued payment of through and out transmission charges as well as the seams elimination charge. To date, neither the administrative law judge nor the FERC has addressed the merits
of the settlement. If the settlement offer is approved by the FERC as submitted, Wisconsin Electric would receive a small refund of transmission charges in excess of the seams elimination charge.
Natural Gas Utility Industry
Restructuring in Wisconsin: The PSCW previously 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.
OTHER MATTERS
In August 2005, President Bush signed into law the Energy Policy Act. Among other things, the Energy Policy Act includes tax subsidies for electric utilities and the repeal of the Public Utility Holding Company Act of 1935 (PUHCA 1935). The Energy Policy Act also amends federal energy laws and provides the FERC with new oversight responsibilities for the electric utility industry. Implementation of the Energy Policy Act requires the development of regulations by federal agencies, including the FERC. As noted above, the Energy Policy Act and corresponding rules require us to seek FERC authorization to allow Wisconsin Electric to lease from We Power the three Power the Future units that are currently being constructed by We Power. Additionally, the Energy Policy Act repealed PUHCA 1935 and enacted the Public Utility Holding Company Act of 2005 (PUHCA 2005), transferring jurisdiction over holding companies from the SEC to the FERC. Wisconsin Energy and Wisconsin Electric will be required to notify the FERC of their status as holding companies and to seek from FERC the exempt status similar to that held under PUHCA 1935. As federal agencies continue to develop new rules to implement the Energy Policy Act, we expect additional impacts on Wisconsin Energy and its subsidiaries in the future.
ACCOUNTING DEVELOPMENTS
New Pronouncements: In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS 123 (revised 2004), Share-Based Payment (SFAS 123R), which amended SFAS 123, Accounting for Stock-Based Compensation. In March 2005, the SEC issued Staff Accounting Bulletin 107 (SAB 107) regarding the SEC's interpretation of SFAS 123R and the valuation of share-based payment for public companies. In April 2005, the SEC deferred the effective date of SFAS 123R to January 1, 2006. This statement requires that the compensation costs relating to such transactions be recognized in the consolidated income statement. We adopted SFAS 123R and SAB 107 effective January 1, 2006 using the modified prospective method. See Note A -- Summary of Significant Accounting Policies and Note B -- Recent Accounting Pronouncements in the Notes to Consolidated Financial Statements in this report for additional information.
In March 2005, the FASB issued Interpretation 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), an interpretation of FASB Statement 143. We adopted FIN 47 effective December 31, 2005. For further information see Note F -- Asset Retirement Obligations.
We adopted FASB Staff Position FIN 46R - 5, Implicit Variable Interests under FASB Interpretation 46 (revised December 2003), in the second quarter of 2005. This statement requires that holdings of implicit variable interests are evaluated when applying Interpretation 46R. See Note G -- Variable Interest Entities for further information.
In May 2005, the FASB issued SFAS 154, Accounting Changes and Error Corrections, a replacement of Accounting Principles Board (APB) Opinion 20 and SFAS 3. This statement requires a retrospective application of direct changes in accounting principles to prior periods' financial statements, unless it is impracticable to determine the period-specific or cumulative effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. In addition, SFAS 154 instructs that a change in depreciation, amortization or depletion method for long-lived, non-financial assets must be recorded as a change in accounting
estimate affected by a change in accounting principle. We adopted SFAS 154, effective January 1, 2006. The adoption of SFAS 154 has not had an impact on our consolidated financial position or results of operations, as we have not had a change in accounting principle that we were required to implement to date in 2006.
CRITICAL ACCOUNTING ESTIMATES
Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles (GAAP) requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions. In addition, the financial and operating environment also may have a significant effect, not only on the operation of our business, but on our results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied have not changed.
The following is a list of accounting policies that are most significant to the portrayal of our financial condition and results of operations and that require management'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 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, 2005, we had $1,025.6 million in regulatory assets and $1,373.2 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.
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.
(a)
The inverse of the change in the actuarial assumption may be expected to have an approximately similar impact in the opposite direction.
In addition to pension plans, we maintain other post-retirement benefit plans which provide health and life insurance benefits for retired employees (described in Note O -- Benefits in the Notes to Consolidated Financial Statements). We account for these plans in accordance with SFAS 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.
(a)
The inverse of the change in the actuarial assumption may be expected to have an approximately similar impact in the opposite direction.
Unbilled Revenues: We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated. This unbilled revenue is estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses and applicable customer rates. Significant fluctuations in energy demand for the unbilled period or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. Total utility operating revenues during 2005 of $3,793.0 million included accrued utility revenues of $262.9 million at December 31, 2005.
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 SFAS 143, Accounting for Asset Retirement Obligations (SFAS 143) and Accounting for Conditional Asset Retirement Obligations (FIN 47), an Interpretation of SFAS 143. SFAS 143 applies primarily to decommissioning costs for our utility energy segment's Point Beach Nuclear Plant. Using a discounted future cash flow methodology, our estimated nuclear asset retirement obligation was
approximately $309.8 million at December 31, 2005. As it relates to our operations, FIN 47 applies primarily to asbestos removal costs. At December 31, 2005, we recorded an obligation of $37.4 million related to asbestos.
Calculation of the nuclear decommissioning asset retirement obligation is based upon projected decommissioning costs calculated by an independent decommissioning consulting firm, as well as several significant assumptions including the timing of future cash flows, future inflation rates and the discount rate applied to future cash flows. Assuming the following changes in key assumptions and holding all other assumptions constant, we estimate that our nuclear asset retirement obligation at December 31, 2005 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 $3.1 million.
For additional information concerning SFAS 143 and our estimated nuclear asset retirement obligation, see Note F -- Asset Retirement Obligations and Note I -- Nuclear Operations in the Notes to Consolidated Financial Statements.
Deferred Tax Assets Valuation Allowance: We record deferred tax asset valuation allowances in accordance with SFAS 109, Accounting for Income Taxes. As of December 31, 2005, we had approximately $11.8 million of valuation allowances that relate to state net operating loss carryforwards (state NOLs) of various non-utility subsidiaries. These NOL's begin to expire in 2008 and it is not likely that we will be able to utilize them.
During 2005, we reduced our valuation allowances by $16.3 million as we were able to conclude that it was likely that we would be able to realize certain state NOL's recorded at the Parent company. This conclusion was based on the favorable decision by the Supreme Court of Wisconsin in June 2005 that allowed the construction of the Oak Creek expansion as part of our Power the Future plan.
The Power the Future generating units will be owned by our subsidiaries organized as limited liability companies (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 taxable losses if all plants are in service. During 2005, the first of the four generating units was put into service. The determination of future state taxable income of the Parent is a significant estimate. Factors affecting the estimate include the 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.
If we would conclude in a future period that it was more likely than not that some or all of the remaining state NOLs would be realized before expiration, GAAP 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.
MISO Bid-Based Energy Market: Effective April 1, 2005, MISO implemented the MISO Midwest Market, a bid-based energy market. The market requires that all market participants submit day-ahead and/or real-time bids and offers for energy at locations across the MISO region. MISO then calculates the most efficient solution for all the bids and offers made into the market that day and establishes a LMP which reflects the market price for energy. As a participant in the new MISO Midwest Market, we are required to follow MISO's instructions when dispatching generating units to support MISO's responsibility for maintaining stability of the transmission system. To the extent the established LMP price for energy is not sufficient to recover the cost of running a generating unit dispatched at MISO's request, the tariff provides a mechanism for us to recover the deficiency (the "make-whole payment"). Since the start of the MISO Midwest Market, MISO has significantly increased the amount of generation provided by our higher cost combustion turbines. We have recorded a receivable from MISO for the make-whole payments
associated with this operation. A reserve has been established for a portion of these receivables that are currently in dispute. Additionally, the MISO Midwest Market subjects us to additional costs primarily associated with constraints in the transmission system. We expect to recover these deferred costs in future rates, subject to PSCW audit and approval.
MISO settles each Operating Day a minimum of four times. A settlement statement is issued at 7, 14, 55 and 105 days after each Operating Day. In addition, since the market start, MISO has employed a non-standard settlement statement at 155 days after the Operating Day. MISO has also announced plans to issue a non-standard statement at 365 days after the Operating Day for days April 1, 2005 through August 31, 2005. Each subsequent statement may contain billing adjustments which alter our obligation to MISO.
CAUTIONARY FACTORS
This report and other documents or oral presentations contain or may contain forward-looking statements made by or on behalf of Wisconsin 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 "anticipates," "believes," "estimates," "expects," "forecasts," "intends," "may," "objectives," "plans," "possible," "potential," "projects" and similar expressions are intended to identify forward-looking statements. In addition to the assumptions and other factors referred to specifically in connection with these statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statements or otherwise affect our future results of operations and financial condition include, among others, the following:
Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related or terrorism-related damage; availability of electric generating facilities; unscheduled generation outages, or unplanned maintenance or repairs; unanticipated events causing scheduled generation outages to last longer than expected; unanticipated changes in fossil fuel, nuclear fuel, purchased power, coal supply, gas supply or water supply costs or availability due to higher demand, shortages, transportation problems or other developments; nonperformance by electric energy or natural gas suppliers under existing power purchase or gas supply contracts; nuclear or environmental incidents; resolution of used nuclear fuel storage and disposal issues; electric transmission or gas pipeline system constraints; unanticipated organizational structure or key personnel changes; collective bargaining agreements with union employees or work stoppages; inflation rates; or demographic and economic factors affecting utility service territories or operating environment.
Regulatory factors such as unanticipated changes in rate-setting policies or procedures; unanticipated changes in regulatory accounting policies and practices; industry restructuring initiatives; transmission or distribution system operation and/or administration initiatives; recovery of costs of previous investments made under traditional regulation; recovery of costs associated with adoption of changed accounting standards; required changes in facilities or operations to reduce the risks or impacts of potential terrorist activities; required approvals for new construction; changes in the United States Nuclear Regulatory Commission's regulations related to Point Beach Nuclear Plant or a permanent repository for used nuclear fuel; changes in the regulations of the United States Environmental Protection Agency as well as the Wisconsin or Michigan Departments of Natural Resources, including but not limited to regulations relating to the release of emissions from fossil-fueled power plants such as carbon dioxide, sulfur dioxide, nitrogen oxide, small particulates or mercury; the siting approval process for new generation and transmission facilities; recovery of costs associated with implementation of a bid-based energy market; or changes in the regulations from the Wisconsin Department of Natural Resources related to the siting approval process for new pipeline construction.
The changing electric and gas utility environment as market-based forces replace strict industry regulation and other competitors enter the electric and gas markets resulting in increased wholesale and retail competition.
Unanticipated operational and/or financial consequences related to implementation of the Midwest Independent Transmission System Operator, Inc. bid-based energy market that started in April 2005, the associated outcome of our March 2005 request of the Public Service Commission of Wisconsin to escrow potential future rate
recovery for the incremental costs or benefits resulting from this new energy market and the ultimate determination by the Federal Energy Regulatory Commission on the details of the seams elimination charges.
Consolidation of the industry as a result of the combination and acquisition of utilities in the Midwest, nationally and globally as a result of the repeal of the Public Utility Holding Company Act of 1935 or otherwise.
Factors which impede execution of our Power the Future strategy, including receipt of necessary state and federal regulatory approvals, timely and successful resolution of legal challenges, local opposition to siting of new generating facilities, construction risks, including the adverse interpretation or enforcement of permit conditions by the permitting agencies, and obtaining the investment capital from outside sources necessary to implement the strategy.
Restrictions imposed by various financing arrangements and regulatory requirements on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans or advances.
Changes in social attitudes regarding the utility and power industries.
Customer business conditions including demand for their products or services and supply of labor and material used in creating their products and services.
The cost and other effects of legal and administrative proceedings, settlements, investigations and claims and changes in those matters.
Factors affecting the availability or cost of capital such as: changes in interest rates and other general capital market conditions; our capitalization structure; market perceptions of the utility industry, us or any of our subsidiaries; or security ratings.
Federal, state or local legislative factors such as changes in tax laws or rates; changes in trade, monetary and fiscal policies, laws and regulations; electric and gas industry restructuring initiatives; changes in the Price-Anderson Act; changes in environmental laws and regulations; or changes in allocation of energy assistance, including state public benefits funds.
Implementation of the Energy Policy Act and the effect of state level proceedings and the development of regulations by federal and other agencies, including the Federal Energy Regulatory Commission, as well as the ultimate authorization of the Federal Energy Regulatory Commission to allow Wisconsin Electric to lease the three Power the Future units that are currently being constructed by We Power.
Authoritative generally accepted accounting principle or policy changes from such standard setting bodies as the Financial Accounting Standards Board, the Securities and Exchange Commission and the Public Company Accounting Oversight Board.
Unanticipated technological developments that result in competitive disadvantages and create the potential for impairment of existing assets.
Possible risks associated with non-utility operations and investments, such as: general economic conditions; competition; operating risks; dependence upon certain suppliers and customers; the cyclical nature of property values that could affect real estate investments; unanticipated changes in environmental or energy regulations; and risks associated with minority investments, where there is a limited ability to control the development, management or operation of the project.
Legislative or regulatory restrictions or caps on non-utility acquisitions, investments or projects, including the State of Wisconsin's amended public utility holding company law.
Other business or investment considerations that may be disclosed from time to time in our Securities and Exchange Commission filings or in other publicly disseminated written documents.
We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
ITEM 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See Factors Affecting Results, Liquidity and Capital Resources -- Market Risks and Other Significant Risks in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in this report for information concerning potential market risks to which Wisconsin Energy and its subsidiaries are exposed.
WISCONSIN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General:
Our consolidated financial statements include the accounts of Wisconsin Energy Corporation (Wisconsin Energy, the Company, our, we or us), a diversified holding company, as well as our principal subsidiaries in the following operating segments:
Utility Energy Segment
-- Consisting of Wisconsin Electric Power Company (Wisconsin Electric), Wisconsin Gas LLC (Wisconsin Gas) and Edison Sault Electric Company (Edison Sault) engaged primarily in the generation of electricity and the distribution of electricity and natural gas; and
Non-Utility Energy Segment
-- Consisting primarily of W.E. Power, LLC (We Power); engaged principally in the design, development, construction and ownership of electric power generating facilities for long term lease to Wisconsin Electric. Our other non-utility segment primarily includes Wispark LLC (Wispark), which develops and invests in real estate. We have eliminated all significant intercompany transactions and balances from the consolidated financial statements.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Reclassifications: We have reclassified certain prior year financial statement amounts to conform to their current year presentation. These reclassifications had no effect on total assets, net income or earnings per share.
The most significant reclassifications relate to the reporting of discontinued operations pursuant to Statement of Financial Accounting Standards (SFAS) 144, Accounting for the Impairment or Disposal of Long-Lived Assets. The footnotes contained herein reflect continuing operations for all periods presented. For further information see Note D.
We have changed the presentation of the investments within our nuclear decommissioning trusts on the Consolidated Statement of Cash Flows for the three years ended December 31, 2005, to present proceeds from investments within the nuclear decommissioning trusts and purchases of investments within the nuclear decommissioning trusts. Previously these items were excluded from the Consolidated Statement of Cash Flows as the nuclear decommissioning trusts are restricted investments. This change had no impact to net cash provided by (used in) operating, investing or financing activities.
Revenues: We recognize energy revenues on the accrual basis and include estimated amounts for service rendered but not billed.
Wisconsin Electric's Wisconsin retail rates are established by the Public Service Commission of Wisconsin (PSCW) and include base amounts for fuel and purchase power costs. The Wisconsin electric fuel rules allow Wisconsin Electric to request rate increases if fuel and purchased power costs exceed bands established by the PSCW. In a rate order issued in January 2006, the PSCW approved a plan to refund any over-collected fuel on an annual basis for 2006. In 2006, any under-collection will be subject to a 2% band. For 2007, the band will be plus or minus 2%.
Wisconsin Electric's and Wisconsin Gas' retail gas rates include monthly adjustments which permit the recovery or refund of actual purchased gas costs. We defer any difference between actual gas costs incurred (adjusted for a sharing mechanism) and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year.
Property and Depreciation: We record property, plant and equipment at cost. Cost includes material, labor, overheads and capitalized interest. Utility property also includes allowance for equity funds used during construction. Additions to and significant replacements of property are charged to property, plant and equipment at cost; minor items are charged to maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.
We had the following property in service by segment at December 31:
We include capitalized software costs associated with our utility energy segment under the caption "Property, Plant and Equipment" on the Consolidated Balance Sheets. As of December 31, 2005 and 2004, the net book value of regulated capitalized software totaled $22.3 million and $28.8 million, respectively. The net book value of other capitalized software was approximately $2.4 million and $2.6 million as of December 31, 2005 and 2004, respectively.
Our utility depreciation rates are certified by the state regulatory commissions and include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 3.9% in 2005, 4.0% in 2004, and 4.1% in 2003. Nuclear plant decommissioning costs are accrued and included in depreciation expense (see Note I). In November 2005, the PSCW approved new depreciation rates, which became effective January 1, 2006. We estimate that the 2006 composite rate will be approximately 3.7% with the new depreciation rates.
For assets other than our regulated assets, we accrue depreciation expense at straight-line rates over the estimated useful lives of the assets. Estimated useful lives for non-regulated assets are 3 to 40 years for furniture and equipment, 2 to 5 years for software and 30 to 40 years for buildings.
Our regulated utilities collect in their rates future removal costs for many assets that do not have an associated asset retirement obligation. W
e record a regulatory liability on our balance sheet for the estimated amounts we have collected in rates for future removal costs less amounts we have spent in removal activities. This regulatory liability was $604.2 million as of December 31, 2005 and $599.3 million as of December 31, 2004.
We had the following Construction Work in Progress (CWIP) by segment at December 31:
Allowance For Funds Used During Construction - Regulated:
Allowance for funds used during construction (AFUDC) is included in utility plant accounts and represents the cost of borrowed funds (AFUDC - debt) used during plant construction and a return on stockholders' capital (AFUDC - equity) used for construction purposes. AFUDC - debt is recorded as a reduction of interest expense and AFUDC - equity is recorded in Other Income and Deductions, Net.
As approved by the PSCW, Wisconsin Electric capitalized AFUDC - debt and equity at 10.18% during the periods reported.
In a rate order dated August 30, 2000, the PSCW authorized Wisconsin Electric to accrue AFUDC on all electric utility nitrogen oxide (NOx) remediation construction work in progress at a rate of 10.18%, and provided a full current return on electric safety and reliability construction work in progress so that no AFUDC accrual is required on these projects. In addition, the August 2000 PSCW order provided a current return on half of other utility construction work in progress and authorized AFUDC accruals on the remaining 50% of these projects.
As approved by the PSCW, Wisconsin Gas is allowed to accrue AFUDC on specific large construction projects at a rate of 10.32%.
Our regulated segment recorded the following AFUDC for the years ended December 31:
Capitalized Interest and Carrying Costs - Non-Regulated Energy:
As part of the construction of the power plants under our Power the Future program, we capitalize interest during construction in accordance with SFAS 34, Capitalization of Interest Cost. For the years ended December 31, 2005, 2004, and 2003 we capitalized $24.3 million, $17.9 million and $6.5 million of interest costs, at an average rate of 6.5%, 6.1% and 5.7%.
Under the lease agreements associated with our Power the Future power plants, we are able to collect from utility customers the carrying costs associated with the construction of these power plants. We defer these carrying costs on our balance sheet and they will be amortized to revenue over the individual lease term. For the years ended December 31, 2005, 2004 and 2003, we have deferred $54.7 million, $38.2 million and $17.1 million of carrying costs related to the Power the Future power plants.
Earnings Per Common Share: We compute basic earnings per common share by dividing net earnings by the weighted average number of common shares outstanding. Diluted earnings per share is less than basic earnings per share due to the dilutive effects of stock options.
Materials, Supplies and Inventories: Our inventory at December 31 consists of:
We price substantially all fossil fuel, materials and supplies and natural gas in storage inventories using the weighted-average method of accounting.
Regulatory Accounting: Our utility energy segment accounts for its regulated operations in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation. This statement sets forth the application of generally accepted accounting principles to those companies whose rates are determined by an independent third-party regulator. The economic effects of regulation can result in regulated companies recording costs that have been or are expected to be allowed in the rate making process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses in the periods when those same amounts are reflected in rates. We defer all of our regulatory assets pursuant to specific orders or by a generic order issued by our primary regulator. Additionally, regulators can impose liabilities upon a regulated company for amounts previously
collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities). We expect to recover our outstanding regulatory assets in rates over a period of no longer than 20 years. For further information, see Note C.
Derivative Financial Instruments: We have derivative physical and financial instruments as defined by SFAS 133, Accounting for Derivative Instruments and Hedging Activities. However, our use of financial instruments is limited. For further information, see Note M.
Cash and Cash Equivalents: Cash and cash equivalents include marketable debt securities acquired three months or less from maturity.
We have nuclear decommissioning trusts that hold investments in debt and equity securities. All assets within the nuclear decommissioning trusts are restricted to nuclear decommissioning activities as set forth by regulations promulgated by the Internal Revenue Service (IRS) and by the PSCW. The accompanying Consolidated Statement of Cash Flows includes proceeds from investments within the nuclear decommissioning trusts and purchases of investments within the nuclear decommissioning trusts.
Asset Retirement Obligations: We adopted SFAS 143, Accounting for Asset Retirement Obligations, effective January 1, 2003. In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), an interpretation of FASB Statement 143. FIN 47 defines the term conditional asset retirement obligation as used in Statement 143. As defined in FIN 47, a conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. We adopted FIN 47 effective December 31, 2005. Consistent with SFAS 143, we record a liability at fair value for a legal asset retirement obligation in the period in which it is incurred. When a new legal obligation is recorded, we capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. We accrete the liability to its present value each period and depreciate the capitalized cost over the useful life of the related asset. At the end of the asset's useful life, we settle the obligation for its recorded amount or incur a gain or loss. As it relates to our regulated operations, we apply SFAS 71 and recognize regulatory assets or liabilities for the timing differences between when we recover legal asset retirement obligations in rates and when we would recognize these costs under SFAS 143. For further information see Note F.
Goodwill and Intangible Assets: We account for goodwill and other intangible assets following SFAS 142, Goodwill and Other Intangible Assets, effective January 1, 2002. As of December 31, 2005 and 2004, we had $441.9 million of goodwill recorded at the Utility Energy Segment, which related to our acquisition of Wisconsin Gas in 2000.
Under SFAS 142, goodwill and other intangibles with indefinite lives are not subject to amortization. However, goodwill and other intangibles are subject to fair value-based rules for measuring impairment, and resulting write-downs, if any, are to be reflected in operating expense. We assess the fair value of our SFAS 142 reporting unit by considering future discounted cash flows, a comparison of fair value based on public company trading multiples, and merger and acquisition transaction multiples for similar companies. This evaluation utilizes the information available under the circumstances, including reasonable and supportable assumptions and projections. We perform our annual impairment test for the reporting unit as of August 31. There was no impairment to the recorded goodwill balance as of our annual 2005 impairment test date for our reporting unit.
Impairment or Disposal of Long Lived Assets: We carry property, equipment and goodwill related to businesses held for sale at the lower of cost or estimated fair value less costs to sell. As of December 31, 2005, we have classified the assets and liabilities of Minergy Neenah as Held for Sale. Consistent with SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, long-lived assets are tested for recoverability whenever events or changes in circumstances indicate that their carrying value may not be recoverable from the use and eventual disposition of the asset based on the remaining useful life. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset. For further information, see Note D.
Investments: We account for investments in other affiliated companies in which we do not maintain control using the equity method. As of December 31, 2005 and 2004, we had a total ownership interest of approximately 33.5% and 37.8%, in American Transmission Company LLC (ATC). We are represented by one out of ten ATC board members, each of whom has one vote. Due to the voting requirements, no individual member has more than 10% of the voting control. For further information regarding such investments, see Note R.
Income Taxes: We follow the liability method in accounting for income taxes as prescribed by SFAS 109, Accounting for Income Taxes (SFAS 109). SFAS 109 requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. We have established a valuation allowance against certain deferred tax assets. Generally accepted accounting principles require that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, 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 in income tax expense.
Tax credits associated with regulated operations are deferred and amortized over the life of the assets. We file a consolidated Federal income tax return. Accordingly, we allocate Federal current tax expense benefits and credits to our subsidiaries based on their separate tax computations. For further information, see Note H.
Stock Options: Prior to 2006, we accounted for stock-based compensation using the intrinsic value method provided by Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees, and related interpretations under which no compensation cost has been recognized for stock option grants. Effective January 1, 2006, we adopted SFAS 123R, Share-Based Payment (Revised). See Note B for further discussion of this new standard and the impacts to our consolidated financial statements.
We previously adopted the disclosure provisions of SFAS 123, Accounting for Stock-Based Compensation, as amended by SFAS 148, Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of SFAS 123. The fair value of options at date of grant was estimated using the Black-Scholes option-pricing model with the following weighted average assumptions:
As described more fully in the following table, our diluted earnings would have been reduced by $0.02, $0.24 and $0.06 per share, respectively, had we expensed the 2005, 2004 and 2003 grants for stock-based compensation plans under SFAS 123. In 2004, the pro forma expense increased, in part, due to the effect of accelerating the vesting of stock options, which resulted in a pro forma expense of $0.16 per share. For further information regarding equity based compensation see Note B and Note J.
Nuclear Fuel Amortization: We amortize our nuclear fuel inventory to fuel expense as the power is generated, generally over a period of 60 months.
B -- RECENT ACCOUNTING PRONOUNCEMENTS
Conditional Asset Retirement Obligations: In March 2005, the FASB issued Interpretation 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), an interpretation of FASB Statement 143. We adopted FIN 47 effective December 31, 2005. For further information see Note F.
Implicit Variable Interests: We adopted FASB Staff Position FIN 46R - 5, Implicit Variable Interests under FASB Interpretation 46 (revised December 2003), in the second quarter of 2005. This statement requires that holdings of implicit variable interests are evaluated when applying Interpretation 46R. See Note G for further information.
Share Based Compensation: In December 2004, the FASB issued SFAS 123 (revised 2004), Share-Based Payment (SFAS 123R), which is a revision of SFAS 123. SFAS 123R supersedes APB Opinion 25, and amends SFAS 95, Statement of Cash Flows. Generally, the approach in SFAS 123R is similar to the approach described in SFAS 123. However, SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative under the new standard.
We adopted SFAS 123R effective January 1, 2006 using the modified prospective method. We will use the binomial pricing model to estimate the fair value of stock options granted subsequent to December 31, 2005. We estimate that our 2006 earnings will reflect stock option expense of $0.04 per share. Prior to 2006 and the adoption of SFAS 123R, we presented all tax benefits resulting from the exercise of stock options as operating cash flows in the Consolidated Statement of Cash Flows. SFAS 123R requires that cash flows resulting from tax deductions in excess of the cumulative compensation cost recognized for options exercised be classified as financing cash flows.
C -- REGULATORY ASSETS AND LIABILITIES
Our utility energy segment accounts for its regulated operations in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation.
Our primary regulator considers our regulatory assets and liabilities in two categories, escrowed and deferred. In escrow accounting we expense amounts that are included in rates. If actual costs exceed, or are less than the amounts that are allowed in rates, the difference in cost is escrowed on the balance sheet as a regulatory asset or regulatory liability and the escrowed balance is considered in setting future rates. Under deferred cost accounting, we defer amounts to our balance sheet based upon specific orders or correspondence with our primary regulator. These deferred costs will be considered in future rate setting proceedings. As of December 31, 2005, we had approximately $59.0 million of net regulatory assets that were not earning a return.
Our regulatory assets and liabilities as of December 31 consist of:
We record a minimum pension liability to reflect the funded status of our pension plans (see Note O). We have concluded that substantially all of the unrecognized pension costs resulting from the recognition of our minimum pension liability that relate to our utility energy segment qualify as a regulatory asset.
Our regulated subsidiaries record deferred regulatory assets and liabilities representing the future expected impact of deferred taxes on utility revenues (see Note A).
In October 2002, the PSCW issued an order authorizing Wisconsin Electric to implement a surcharge for recovery of annual electric transmission costs projected through 2005. In addition, the PSCW order authorized escrow accounting treatment for transmission costs.
Consistent with a generic order from and past rate-making practices of the PSCW, we defer as a regulatory asset costs associated with the remediation of former manufactured gas plant sites. As of December 31, 2005, we have recorded $64.2 million of environmental costs associated with manufactured gas plant sites as a regulatory asset, including $36.8 million of deferrals for actual remediation costs incurred and a $27.4 million accrual for estimated future site remediation (See Note S). In addition, we have deferred $6.8 million of insurance recoveries associated with the environmental costs as regulatory liabilities. We included total actual remediation costs incurred net of the related insurance recoveries in our 2006 rate case. We began amortizing these costs upon receiving PSCW approval. These costs will be amortized over the next five years.
As part of our Power the Future initiative, the PSCW approved the retirement and removal of the Port Washington Power Plant coal units to make way for construction of gas fired facilities. In a September 27, 2003 order, the PSCW authorized transferring the undepreciated costs and related removal amounts to a regulatory asset account. The escrowed unrecovered plant costs totaled $56.5 million at December 31, 2005.
As of December 31, 2005, we have deferred $72.8 million of fuel related costs. The costs resulted from an extended outage at our nuclear plant, increased costs associated with reduced coal deliveries due to a railroad transportation problem and increased costs associated with the Midwest Independent Transmission System Operator, Inc. (MISO) bid-based energy market (MISO Midwest Market).
As of December 31, 2005, we have $58.1 million of escrowed bad debt costs. Prior to October 2002, Wisconsin Gas used the escrow method of accounting for bad debt costs whereby it deferred actual bad debt write-offs that exceeded amounts that were allowed in its rates. In 2005 and 2004, the PSCW approved our request to account for residential bad debt costs on an escrow basis at Wisconsin Gas and Wisconsin Electric.
In connection with the WICOR acquisition, we recorded the funded status of the Wisconsin Gas pension and post-retirement medical plans at fair value at the acquisition date. Due to the expected regulatory treatment of these items, we recorded a regulatory liability (Deferred pension and post-retirement benefits) that is being amortized over an average remaining service life of 15 years ending 2015.
D -- ASSET SALES, DIVESTITURES AND DISCONTINUED OPERATIONS
We have been pursuing a corporate strategy since September 2000, which, among other things, identified the divestiture of non-core investments. These assets primarily related to our manufacturing business and non-utility energy investments.
Minergy Neenah: In August 2005, we announced our intent to sell Minergy Neenah. The primary assets of Minergy Neenah are the Glass Aggregate plant and related operating contracts. The plant recycles paper sludge from area paper mills into renewable energy and glass aggregate using our patented Glass Aggregate technology.
As a result of the announced intent to sell Minergy Neenah, we have reclassified the assets and liabilities of Minergy Neenah as Assets held for sale in the accompanying Consolidated Balance Sheets. In addition, we have recorded the operating results of Minergy Neenah as Discontinued Operations in the accompanying Consolidated Income Statements. Previously, Minergy Neenah's results were included in corporate and other affiliates. Total assets held for sale for Minergy Neenah were $17.4 million and $24.4 million at December 31, 2005 and 2004, respectively. See below for a summary of the components of Discontinued Operations for the operations of Minergy Neenah in our Consolidated Income Statements.
One of Minergy Neenah's key revenue sources is a long-term steam contract with a paper company whereby Minergy Neenah sells steam to the paper company's facility in Neenah. The paper company contacted Minergy Neenah to request a renegotiation of the steam contract to help sustain the long-term viability of the paper company's facility. Given the importance of the long-term steam contract to Minergy Neenah, we believed it was important to help maintain the viability of the paper company's facility. In October 2004, we signed an amendment to the steam contract which will reduce estimated steam revenues through 2017. We concluded the asset was impaired and recorded a non-cash asset valuation charge of $27.0 million ($17.6 million after tax) in the third quarter of 2004.
Wisvest - Calumet: Effective May 31, 2005, we sold our Calumet facility for approximately $37.0 million in cash to Tenaska Power Fund, L.P. (Tenaska). The primary assets of Calumet were a 308-megawatt natural gas-fired peaking power facility in Chicago, Illinois and related operating contracts. The transaction generated an after tax gain of approximately $4.7 million upon closing and generated approximately $32.0 million in cash tax benefits.
Pursuant to the terms of the sales agreement, Wisvest has agreed to customary indemnification provisions related to environmental conditions and other matters. Except for retention of the full exposure to indemnify Tenaska for environmental claims related to certain property no longer leased or owned by Wisvest or any of its subsidiaries,
Wisvest's maximum aggregate exposure under the indemnification provisions is $35 million. Pursuant to the terms of the agreement, we have guaranteed post-closing obligations under the agreement, including indemnity obligations.
In accordance with SFAS 144, we have reclassified the assets and liabilities of Calumet as Assets held for sale in the accompanying December 31, 2004 Consolidated Balance Sheet. In addition, we have recorded the operating results of Calumet as Discontinued Operations in the accompanying Consolidated Income Statements for December 31, 2005, 2004 and 2003. Total assets held for sale for Calumet were $29.8 million at December 31, 2004. See below for a summary of the components of Discontinued Operations for the operations of Calumet in our Consolidated Income Statements. Previously, Calumet's results were included in the non-utility energy segment.
Subsequent to May 1, 2004, Calumet operated under the control of PJM Interconnection, L.L.C. (PJM), a regional transmission organization that also operates bid-based energy and capacity markets. In the third quarter of 2004, we determined that (i) Calumet had significant risk associated with liquidated damages for certain energy sales within the PJM market, (ii) the elimination of the risk was not guaranteed via assumption of the risk by a third party marketer or through the availability of appropriate insurance, and (iii) nonacceptance of, or failure to arrange for, coverage of the risk greatly diminished the ability to viably sell merchant capacity, which resulted in a change in the anticipated economics of the facility and the determination of an impairment of the facility. We concluded that this asset was impaired and recorded a non-cash asset valuation charge of $122.0 million ($79.3 million after tax) in the third quarter of 2004.
Manufacturing: Effective July 31, 2004, we sold WICOR, Inc. to Pentair, Inc. and received cash proceeds of $857 million, and Pentair, Inc. assumed approximately $25 million of third party debt.
WICOR's only asset at the time of the sale consisted of its interest in WICOR Industries. As a condition of the sale, WICOR transferred its ownership of Wisconsin Gas to Wisconsin Energy through a stock redemption. Prior to the transaction, Wisconsin Gas converted from a corporation to a limited liability company (collectively the "Wisconsin Gas transfer"). We expect the final determination of cash taxes to be approximately $105 million as a result of the stock redemption described above. However, we also expect to receive future tax deductions from a step-up in the tax basis of the Wisconsin Gas assets as a result of the Wisconsin Gas transfer. We therefore expect that substantially all of the cash taxes paid on the stock redemption will be recovered as deferred income tax assets through future deductions.
Pursuant to the terms of the sales agreement, Wisconsin Energy agreed to customary indemnification provisions related to certain environmental, asbestos, and product liability matters associated with the manufacturing business. In addition, the amount of cash taxes and future deferred income tax benefits are subject to a number of factors including appraisals of the fair value of Wisconsin Gas assets and applicable tax laws. Any changes in the estimates of taxes and indemnification matters will be recorded as an adjustment to the gain on sale and reported in discontinued operations in the period the adjustment is determined. We have established reserves related to these customary indemnification and tax matters.
In accordance with SFAS 144, we reclassified our manufacturing segment as discontinued operations in the accompanying income statements. Included in discontinued operations is interest expense associated with third-party debt that was assumed by the buyer upon completion of the sale.
A summary of the components of Discontinued Operations for the operations of WICOR, Calumet and Minergy Neenah in our Consolidated Income Statements follows:
(a) Includes the results of Calumet through May 31, 2005.
(b) Includes the results of our manufacturing segment through July 31, 2004.
A summary of the components of cash flows from the discontinued operations of WICOR, Calumet and Minergy Neenah follows. The majority of the cash flow activity in 2004 and 2003 related to WICOR.
Supplemental cash flow information:
Interest
$ -
$0.5
$1.0
Income taxes, net of refunds
$ -
$8.5
$7.8
(a) Includes the results of Calumet through May 31, 2005.
(b) Includes the results of our manufacturing segment through July 31, 2004.
Assets held for sale in the Consolidated Balance Sheets does not include any cash or temporary cash investments related to discontinued operations as of December 31, 2005 and 2004.
2003 Non-Utility Sales: During 2003, we sold our investment in two energy marketing companies, a small investment in assets of a Minergy Corp. project, a 500 megawatt natural gas power island and miscellaneous small real estate and other sales. These sales resulted in net cash proceeds of approximately $56.0 million and $32.0 million in tax benefits. In addition, we received $15.0 million in dividends from certain of these companies at closing.
During 2003, we recorded asset valuation charges totaling $59.5 million, of which $19.4 million related to the write-off of our remaining investment in an independent power project (Androscoggin LLC) and $40.1 million related to
our investment in a power island. Wisvest had purchased a 500 megawatt power island consisting of gas turbine generators and related equipment. This power island was not identified for a specific project. In 2002, we took possession of the power island and put it in storage. In the third quarter of 2003, we recorded a non-cash asset valuation charge of $40.1 million ($26.0 million after tax) to reflect the impairment of this asset. We determined in the third quarter of 2003 based on information obtained from our efforts to market the power island, that the carrying value of this asset exceeded market values. We estimated the fair market value of our 500 megawatt power island based upon a definitive agreement we entered into to sell the asset. This asset was sold in the fourth quarter of 2003 with no additional loss.
E -- PORT WASHINGTON GENERATING STATION (PWGS)
In July 2005, the first unit at PWGS, a 545-megawatt natural gas-fired generation unit, was placed in service. This asset has a cost of approximately $364.3 million which includes approximately $31.1 million of capitalized interest. The asset will be depreciated over its estimated useful life of 37 years. The cost of the plant is expected to be recovered through Wisconsin Electric's rates over a 25 year period at an annual amount of approximately $48 million.
During the construction of the first unit, we collected in rates approximately $72.5 million of carrying costs and recorded this amount as deferred revenues. In July 2005, we began to amortize these deferred revenues to income on a straight-line basis over 25 years.
In July 2005, PWGS issued $155 million of 4.91% senior notes in a private placement. The senior notes have a mortgage style repayment feature with monthly payments of approximately $0.9 million including principal and interest. The final payment is due July 15, 2030. The senior notes are secured by a collateral assignment of the leases between PWGS and Wisconsin Electric relating to the first unit.
F -- ASSET RETIREMENT OBLIGATIONS
We follow SFAS 143, Accounting for Asset Retirement Obligations (SFAS 143) and Accounting for Conditional Asset Retirement Obligations (FIN 47).
The following table presents the change in our asset retirement obligations during 2005.
(a) Increase in asset retirement obligation for the initial adoption of FIN 47.
SFAS 143 primarily applies to the future decommissioning costs for our Point Beach Nuclear Plant (Point Beach). Prior to January 2003, we recorded a long-term liability for accrued nuclear decommissioning costs. In 2005, due to an updated Nuclear Decommissioning Cost Study and approval of our application for license renewal, we adjusted the long-term liability accrued for nuclear decommissioning costs. See Note I for further information about the nuclear decommissioning of Point Beach including our investments in Nuclear Decommissioning Trusts that are restricted to nuclear decommissioning.
In March 2005, the FASB issued FIN 47, an interpretation of FASB Statement 143. FIN 47 defines a conditional asset retirement obligation as a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. We adopted FIN 47 effective December 31, 2005. At adoption, we recorded additional asset retirement obligations of $38.4 million, of which $37.4 million related to asbestos removal costs.
The adoption of FIN 47 had no impact on our net income in 2005. As it relates to our regulated operations, we apply SFAS 71 and recognize regulatory assets or liabilities for the timing differences between when we recover legal asset retirement obligations in rates and when we would recognize these costs under FIN 47. This treatment is consistent with the adoption of SFAS 143 for our regulated operations.
If we had adopted interpretation FIN 47 at the beginning of fiscal 2004, we would have reported the following asset retirement obligations on our Consolidated Balance Sheets in "Asset Retirement Obligations" as of December 31:
(b) The 2004 reported balance represents the liability recorded under SFAS 143, which is primarily related to nuclear decommissioning costs.
G -- VARIABLE INTEREST ENTITIES
In January 2003, the FASB issued Interpretation 46, Consolidation of Variable Interest Entities (FIN 46). This standard requires an enterprise that is the primary beneficiary of a variable interest entity to consolidate that entity. We applied the Interpretation to any existing interests in variable interest entities beginning in the third quarter of 2003. In October 2003, the FASB deferred the adoption of FIN 46 for all entities commonly referred to as special-purpose entities to the first reporting period ending after December 15, 2003. In December 2003, the FASB issued FIN 46R, which revised FIN 46 and deferred the effective date for interests held in variable interest entities other than special purpose entities to financial statements for periods ending after March 15, 2004. We adopted FIN 46R in the first quarter of 2004.
We continue to evaluate our tolling and purchased power agreements with third parties on a quarterly basis. After making an exhaustive effort, we concluded that for three of these agreements, we are unable to obtain the information necessary to determine whether we are the primary beneficiary of these variable interest entities. Pursuant to the terms of two of the three agreements, we deliver fuel to the entity's facilities and receive electric power. We pay the entity a "toll" to convert our fuel into the electric energy. The output of the facility is available for us to dispatch during the term of the respective agreement. In the other agreement, we have rights to the firm capacity of the entity's facility. We have approximately $667.5 million of required payments over the remaining term of these three agreements, which expire over the next 17 years. We believe the required payments will continue to be recoverable in rates. We account for one of these agreements as a capital lease.
In March 2005, the FASB issued FASB Staff Position FIN 46R-5, Implicit Variable Interests under FASB Interpretation 46 (revised December 2003). This statement requires that holdings of implicit variable interests are evaluated when applying Interpretation 46R. An implicit variable interest is defined as an implied pecuniary interest in an entity that changes with changes in the fair value of the entity's net assets exclusive of variable interests. An implicit variable interest acts the same as an explicit variable interest except it involves the absorbing and/or receiving of variability indirectly from the entity (rather than directly). FIN 46R-5 was effective for the first reporting period beginning after March 3, 2005 for entities that had already adopted FIN 46R; accordingly, we adopted FIN 46R-5 in the second quarter of 2005. We have concluded that we currently do not have any implicit variable interests.
H -- INCOME TAXES
The following table is a summary of income tax expense for each of the years ended December 31:
The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable U.S. statutory federal income tax rate to income before income taxes as a result of the following:
The components of SFAS 109 deferred income taxes classified as net current assets and net long-term liabilities at December 31 are as follows:
As of December 31, 2005 and 2004, we had recorded $11.8 million and $40.5 million of valuation allowances primarily related to the uncertainty of our ability to benefit from state loss carryforwards in the future. As of December 31, 2004, we had concluded that it was more likely than not that we would not ultimately realize these tax benefits. In connection with the favorable decision by the Supreme Court of Wisconsin in June 2005 to uphold the CPCN granted by the PSCW for the construction of the Oak Creek expansion, we have concluded that it is more likely than not that we will be able to utilize certain tax benefits associated with state net operating losses of the Parent that have been carried forward from prior years. As such, in 2005 we reversed $16.3 million of valuation allowances associated with the state tax net operating losses that have been carried forward to future years. The remaining state loss carryforwards begin to expire in 2008 and have been reduced by a valuation allowance.
I -- NUCLEAR OPERATIONS
Point Beach Nuclear Plant: Wisconsin Electric owns two 518-megawatt electric generating units at Point Beach Nuclear Plant in Two Rivers, Wisconsin, which are operated by Nuclear Management Company (NMC). In February 2004, NMC and Wisconsin Electric filed an application with the United States Nuclear Regulatory Commission (NRC) to renew the operating license for both Units for an additional 20 years. The NRC approved the license renewal request in December 2005. The new operating licenses expire in October 2030 for Unit 1 and March 2033 for Unit 2. The previous operating licenses expired in October 2010 for Unit 1 and in March 2013 for Unit 2.
Nuclear Insurance: The Price-Anderson Act currently limits the total public liability for damages arising from a nuclear incident at a nuclear power plant to approximately $10.8 billion, of which $300 million is covered by liability insurance purchased from private sources. The remaining $10.5 billion is covered by an industry retrospective loss sharing plan whereby in the event of a nuclear incident resulting in damages exceeding the private insurance coverage, each owner of a nuclear plant would be assessed a deferred premium of up to $100.6 million per reactor (Wisconsin Electric owns two) with a limit of $15 million per reactor within one calendar year. As the owner of Point Beach, Wisconsin Electric would be obligated to pay its proportionate share of any such assessment.
Wisconsin Electric, through its membership in Nuclear Electric Insurance Limited (NEIL), carries decontamination, property damage and decommissioning shortfall insurance covering losses of up to $2.1 billion at Point Beach. Under policies issued by NEIL, the insured member may be liable for a retrospective premium in the event of catastrophic losses exceeding the full financial resources of NEIL. Wisconsin Electric's maximum retrospective liability under the above policies is $17.9 million.
Wisconsin Electric also maintains insurance with NEIL through which it can recover up to $3.5 million per week, subject to a total limit of $490 million, during any prolonged outage at Point Beach caused by accidental property damage. Wisconsin Electric's maximum retrospective liability under this policy is $9.9 million.
It should not be assumed that, in the event of a major nuclear incident, any insurance or statutory limitation of liability would protect Wisconsin Electric from material adverse impact.
Nuclear Decommissioning: We record decommissioning expense in amounts equal to the amounts collected in rates and funded to the external trusts. Nuclear decommissioning costs are accrued over the expected service lives of the nuclear generating units and are included in electric rates. Decommissioning funding was $17.6 million for each of the years ended 2005, 2004 and 2003. As of December 31, 2005 and 2004, we had the following investments in Nuclear Decommissioning Trusts, stated at fair value.
As of December 31, 2005 approximately 66% of the trusts were invested in equity securities and 34% were invested in debt securities. In accordance with SFAS 115, Accounting for Certain Investments in Debt and Equity Securities, Wisconsin Electric's debt and equity security investments in the Nuclear Decommissioning Trust Fund are classified as available for sale. Gains and losses on the fund are determined on the basis of specific identification; net unrealized gains on the fund are recorded as part of the fund. We fair value our investment in the Nuclear Decommissioning Trust Fund and we are allowed regulatory treatment for the fair value adjustment. Realized gains and losses for the years ended December 31, 2005 and 2004 were as follows:
The PSCW requires us to perform periodic Decommissioning Cost Studies to evaluate the funded status of our Nuclear Decommissioning Trusts as compared with the estimated costs to perform the decommissioning work. In June 2005, we filed a new Decommissioning Cost Study with the PSCW. The study was performed by an outside consultant and it included several assumptions as to the timing and scope of the decommissioning work. This study estimated that the cost to decommission the plant would be $712.5 million in 2004 dollars. A prior study had estimated the costs to be $1.1 billion in 2003 dollars. The reduction in the estimated costs to decommission the plant was driven by several factors including the timing and the scope of the work to be performed.
The June 2005 Decommissioning Cost Study was also used to estimate our Asset Retirement Obligation (ARO) for nuclear decommissioning. We record an ARO for future decommissioning costs based upon the net present value of the expected cash flows associated with our legal obligation to decommission our plants. Under SFAS 143, certain costs included in the June 2005 Decommissioning Cost Study that related to fuel management and non-nuclear demolition were excluded from the ARO calculation. Using the June 2005 study, our estimated costs for decommissioning, following SFAS 143, were $473.2 million. After increasing these costs for inflation and then discounting the costs for the time value of money, we calculated our ARO for nuclear decommissioning to be $309.8 million as of December 31, 2005 as compared to $745.3 million as of December 31, 2004.
We recover decommissioning costs in our regulated rates. We have established a regulatory liability to reflect the difference between nuclear decommissioning costs recovered in rates and cumulative investment gains (our nuclear trust investments) in comparison to the ARO for nuclear decommissioning that is calculated under SFAS 143. As of December 31, 2005, we have increased our nuclear decommissioning regulatory liability by $439.7 million in comparison to the liability at December 31, 2004, to reflect the reduction of the ARO for nuclear decommissioning as described above. For further information on ARO's see Note F.
The ultimate timing and amount of future cash flows associated with nuclear decommissioning is dependent upon many significant variables including the scope of work involved, the ability to relicense the plants in the future, future inflation rates and discount rates. However, based on the license renewal received by the NRC in December 2005, we do not expect to make any significant nuclear decommissioning expenditures before the year 2030.
Decontamination and Decommissioning Fund: The Energy Policy Act of 1992 established a Uranium Enrichment Decontamination and Decommissioning Fund (D&D Fund) for the United States Department of Energy's nuclear fuel enrichment facilities. Deposits to the D&D Fund are derived in part from special assessments on utilities using enrichment services. As of December 31, 2005, Wisconsin Electric recorded its remaining estimated liability equal to projected special assessments of $3.7 million. The deferred regulatory asset will be amortized to nuclear fuel expense and included in utility rates over the next two years ending in 2007.
J -- COMMON EQUITY
Stock Based Compensation Plans: Our 1993 Omnibus Stock Incentive Plan, as amended (OSIP), as approved by stockholders, enables us to provide a long-term incentive through equity interests in Wisconsin Energy, to outside directors, selected officers and key employees of the Company. The OSIP provides for the granting of stock options, stock appreciation rights, stock awards and performance shares. Awards may be paid in common stock, cash or a combination thereof.
The exercise price of a stock option under the OSIP is to be no less than 100% of the common stock's fair market value on the grant date and options may not be exercised within six months of the grant date except in the event of a
change in control. The stock options that were granted prior to 2005 generally vest on a straight line basis over a four year period and expire no later than ten years from the date of grant.
The following is a summary of our stock options issued through December 31, 2005.
In January 2006, the Compensation Committee awarded 1,292,275 non-qualified stock options at the average market price of $39.48 to our officers and key employees under its normal schedule of awarding long-term incentive compensation.
In December 2004, the Compensation Committee of the Board of Directors approved certain changes to unvested options and to future grants. The Compensation Committee approved the acceleration of vesting of all unvested options awarded to executive officers and other key employees in 2002, 2003 and 2004 in anticipation of the changes in accounting required under the new accounting standard for share based payments which became effective January 1, 2006. In addition, the Compensation Committee determined that future option grants would be non-qualified stock options and they would vest on a cliff-basis after a three year period. In 2004, we recorded a $0.4 million charge, net of tax, in connection with the accelerated vesting of unvested stock options. For further information regarding the accounting changes related to stock based compensation see Note A and Note B.
The following table summarizes information about stock options outstanding at December 31, 2005:
The Compensation Committee has also approved restricted stock grants to certain key employees and directors. The following restricted stock activity occurred during 2005, 2004 and 2003:
Recipients of the restricted shares, who have the right to vote the shares and to receive dividends, are not required to provide consideration to us other than rendering service. Forfeiture provisions on the restricted stock generally expire 10 years after award grant subject to an accelerated expiration schedule based on the achievement of certain financial performance goals.
Under the provisions of APB 25, we record the market value of the restricted stock awards on the date of grant as a separate unearned compensation component of common stock equity and then we charge their value to expense over the vesting period of the awards. We also adjust expense for acceleration of vesting due to achievement of performance goals.
In January 2004, the Compensation Committee granted 159,159 performance shares to officers and other key employees. In January 2006 and 2005 the Compensation Committee granted 150,281 and 101,834 performance units to officers and other key employees under the Wisconsin Energy Performance Unit Plan. Under the grants, the ultimate number of shares of our common stock or cash which will be awarded is dependent upon the achievement of certain financial performance of the Company's stock over a three year period. Under the terms of the award, participants may earn between 0% and 175% of the base performance award. We are accruing compensation costs over the three year period based on our estimate of the final expected value of the award. The 2004 grant will be settled in common stock. The 2005 and 2006 grants will be settled in cash instead of shares of our common stock.
Common Stock Activity: In September 2000, the Board of Directors amended the common stock repurchase plan to authorize us to purchase up to $400 million of our shares of common stock in the open market. In 2004, we purchased and retired approximately 1.6 million shares of common stock for $50.4 million. The repurchase plan expired on December 31, 2004. Over the life of the repurchase plan we purchased and retired approximately 14.9 million shares of common stock for $344.0 million.
No new shares of common stock were issued in 2005. Prior to February 2004, we issued shares of our common stock to fulfill obligations under various employee benefit plans and the dividend reinvestment plan. We received proceeds of approximately $4.8 million and $62.9 million during 2004 and 2003, related to these share issuances. In February 2004, we announced that we did not expect to issue new shares under these programs; rather we instructed the independent plan agents to begin purchasing the shares in the open market in lieu of issuing new shares. During 2005 and 2004, our plan agents purchased 2.0 million shares at a cost of $75.1 million and 3.2 million shares at a cost of $102.3 million, respectively, to fulfill exercised stock options. In 2005 and 2004, we received proceeds of $47.0 million and $66.1 million, respectively, related to the exercise of stock options.
Restrictions: Wisconsin Energy's ability as a holding company to pay common dividends primarily depends on the availability of funds received from our principal utility subsidiaries, Wisconsin Electric and Wisconsin Gas. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our principal utility subsidiaries to transfer funds to Wisconsin Energy in the form of cash dividends, loans or advances. In addition, under Wisconsin law, Wisconsin Electric and Wisconsin Gas are prohibited from loaning funds, either directly or indirectly, to Wisconsin Energy.
The Wisconsin Electric and Wisconsin Gas January 2006 rate order from the PSCW requires each company to maintain a capital structure (i.e., the percentage by which each of common stock, preferred stock and debt constitute the total capital invested in the utility), which has a common equity ratio range of between 48.5% and 53.5% (including certain off-balance sheet obligations and capitalized leases, but excluding the PWGS Unit 1 capitalized lease) for both companies. Previously in a June 2004 decision, the PSCW determined that both Wisconsin Electric
and Wisconsin Gas must obtain specific approval to pay dividends that exceed normal levels as long as any tax issue or appeals related to the sale of the manufacturing business and/or the conversion of Wisconsin Gas to a limited liability company remain outstanding. The PSCW may modify such provisions by a future order.
Wisconsin Electric may not pay common dividends to Wisconsin Energy under Wisconsin Electric's Restated Articles of Incorporation if any dividends on Wisconsin Electric's outstanding preferred stock have not been paid. In addition, pursuant to the terms of Wisconsin Electric's 3.60% Serial Preferred Stock, Wisconsin Electric's ability to declare common dividends would be limited to 75% or 50% of net income during a twelve month period if Wisconsin Electric's common stock equity to total capitalization, as defined, is less than 25% and 20%, respectively.
See Note L for discussion of certain financial covenants related to the bank back-up credit agreements of Wisconsin Energy, Wisconsin Electric and Wisconsin Gas.
We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.
K -- LONG-TERM DEBT
Debentures and Notes: As of December 31, 2005, the maturities and sinking fund requirements of our long-term debt outstanding (excluding obligations under capital leases) were as follows:
We amortize debt premiums, discounts and debt issuance costs over the lives of the debt and we include the costs in interest expense.
In July 2005, PWGS issued $155 million of 4.91% senior notes in a private placement. The senior notes have a mortgage style repayment feature with monthly payments of approximately $0.9 million including principal and interest. The final payment is due July 15, 2030. The senior notes are secured by a collateral assignment of the leases between PWGS and Wisconsin Electric relating to the first PWGS gas unit that went into service in July 2005.
Wisconsin Gas retired at the scheduled maturity date $65 million of 6-3/8% Notes due November 1, 2005. In November 2005, Wisconsin Gas issued $90 million of 5.90% Debentures due December 1, 2035. The securities were issued under shelf registration statements filed with the Securities and Exchange Commission (SEC). The proceeds from the sale were used to repay a portion of our outstanding commercial paper. The commercial paper was incurred to both retire the $65 million of 6-3/8% Notes and for working capital requirements.
In August 2004, Wisconsin Electric retired $140 million of 7-1/4% First Mortgage Bonds at their scheduled maturity. Wisconsin Electric financed this retirement through the issuance of short-term commercial paper.
In September 2004, we used cash proceeds from the sale of WICOR Industries for the redemption of $300 million of Wisconsin Energy 5.875% senior notes due April 1, 2006. In September 2004, we recorded approximately $17.0 million of costs associated with this early redemption, which are included in Other Income and Deductions, Net in our Consolidated Income Statement for the year ended December 31, 2004.
In November 2004, Wisconsin Electric sold $250 million of unsecured 3.50% Debentures due December 1, 2007. The securities were issued under an existing $665 million shelf registration statement filed with the SEC. The proceeds from the sale were used to repay our outstanding commercial paper.
In December 2004, Wisconsin Electric refinanced $147 million of the $165 million aggregate principal amount of unsecured variable rate putable weekly reset tax-exempt debt with new "auction" non-putable unsecured variable rate weekly reset tax-exempt debt.
Obligations Under Capital Leases: In 1997, Wisconsin Electric entered into a 25-year power purchase contract with an unaffiliated independent power producer. The contract, for 236 megawatts of firm capacity from a gas-fired cogeneration facility, includes no minimum energy requirements. When the contract expires in 2022, Wisconsin Electric may, at its option and with proper notice, renew for another ten years or purchase the generating facility at fair value or allow the contract to expire. We account for this contract as a capital lease and recorded the leased facility and corresponding obligation under the capital lease at the estimated fair value of the plant's electric generating facilities. We are amortizing the leased facility on a straight-line basis over the original 25-year term of the contract.
We treat the long-term power purchase contract as an operating lease for rate-making purposes and we record our minimum lease payments as purchased power expense on the Consolidated Income Statements. We paid a total of $25.2 million, $24.3 million and $23.4 million in minimum lease payments during 2005, 2004, and 2003, respectively. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on our Consolidated Balance Sheets (see deferred regulatory assets - deferred plant related - capital lease in Note C). Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $78.5 million by the year 2009 at which time the regulatory asset will be reduced to zero over the remaining life of the contract. The total obligation under the capital lease increased to $160.2 million at December 31, 2005 and will now be reduced to zero over the remaining life of the contract.
Wisconsin Electric also has a nuclear fuel leasing arrangement with Wisconsin Electric Fuel Trust (Trust) which is treated as a capital lease. We lease and amortize the nuclear fuel to fuel expense as power is generated, generally over a period of 60 months. Lease payments include charges for the cost of fuel burned, financing costs and management fees. In the event that Wisconsin Electric or the Trust terminates the lease, the Trust would recover its unamortized cost of nuclear fuel from Wisconsin Electric. Under the lease terms, Wisconsin Electric is in effect the ultimate guarantor of the Trust's commercial paper and line of credit borrowings that finance the investment in nuclear fuel. We recorded $1.7 million of interest expense on the nuclear fuel lease in fuel expense during 2005 and $1.4 million during 2004 and 2003.
Following is a summary of our capitalized leased facilities and nuclear fuel as of December 31.
Future minimum lease payments under our capital leases and the present value of our net minimum lease payments as of December 31, 2005 are as follows:
L -- SHORT-TERM DEBT
Short-term notes payable balances and their corresponding weighted-average interest rates as of December 31 consist of:
On December 31, 2005, we had approximately $1.2 billion of available unused lines of bank back-up credit facilities on a consolidated basis. We had approximately $456.3 million of total consolidated short-term debt outstanding on such date. Our bank back-up credit facilities mature beginning April 2006 through November 2007.
The following information relates to Short-Term Debt for the years ending December 31, 2005 and 2004:
Wisconsin Energy, Wisconsin Electric and Wisconsin Gas have entered into various bank back-up credit agreements to maintain short-term credit liquidity which, among other terms, require the companies to maintain, subject to certain exceptions, a minimum total funded debt to capitalization ratio of less than 70%, 65% and 65%, respectively.
Wisconsin Energy's bank back-up credit facilities require us to maintain a minimum ratio of consolidated EBITDA (Earnings before interest, taxes, depreciation and amortization) to consolidated interest expense.
The Wisconsin Energy, Wisconsin Electric and Wisconsin Gas bank back-up credit agreements contain customary covenants, including certain limitations on the respective companies' ability to sell assets. The credit agreements also contain customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, ERISA defaults and change of control.
At December 31, 2005, we were in compliance with all covenants.
M -- DERIVATIVE INSTRUMENTS
We follow SFAS 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, effective July 1, 2003, which requires that every derivative instrument be recorded on the balance sheet as an asset or liability measured at its fair value and that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives under SFAS 133, the PSCW allows the effects of the fair market value accounting to be offset to regulatory assets and liabilities.
We have a limited number of financial contracts that are defined as derivatives under SFAS 133 and qualify for cash flow hedge accounting. These contracts are utilized to manage the cost of gas for utility operations. In addition, these contracts were utilized in 2004 and the first half of 2005 for gas used in testing PWGS Unit 1. Changes in the fair market values of these instruments are recorded in Accumulated Other Comprehensive Income. At the date the underlying transaction occurs, the amounts in Accumulated Other Comprehensive Income for utility operations are reported in earnings and amounts related to PWGS Unit 1 test gas were capitalized.
For the years ended December 31, 2005 and 2004 the amount of hedge ineffectiveness was immaterial. We did not exclude any components of derivative gains or losses from the assessment of hedge effectiveness.
During March 2003, we settled several treasury lock agreements entered into earlier in the first quarter of 2003 and during the third quarter of 2002 to mitigate interest rate risk associated with the issuance of $200 million of long-term unsecured senior notes in March 2003. As these agreements qualified for cash flow hedging accounting treatment under SFAS 133, the payment made upon settlement of these agreements is deferred in Accumulated Other Comprehensive Income and is being amortized as an increase to Interest Expense over the same period in which the interest cost is recognized in income.
For the years ended December 31, 2005, 2004 and 2003, we reclassified $0.6 million, $0.8 million and $0.8 million in treasury lock agreement settlement payments deferred in Accumulated Other Comprehensive Income as an increase to Interest Expense. We estimate that during the next twelve months, $0.4 million will be reclassified from Accumulated Other Comprehensive Income as a reduction in earnings.
In addition, during 2004, in conjunction with the redemption of $300 million of Wisconsin Energy 5.875% senior notes due April 1, 2006, $0.6 million of a treasury lock agreement settlement payment previously deferred in Accumulated Other Comprehensive Income was reclassified to Other Income and Deductions, Net.
N -- FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amount and estimated fair value of certain of our recorded financial instruments as of December 31 are as follows:
The carrying value of cash and cash equivalents, net accounts receivable, accounts payable and short-term borrowings approximates fair value due to the short term nature of these instruments. The nuclear decommissioning trust fund is carried at fair value as reported by the trustee (see Note I). The fair value of our preferred stock is estimated based upon the quoted market value for the same or similar issues. The fair value of our long-term debt, including the current portion of long-term debt but excluding capitalized leases, is estimated based upon quoted market value for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows. The fair values of gas commodity instruments are equal to their carrying values as of December 31, 2005.
O -- BENEFITS
Pensions and Other Post-retirement Benefits: We have funded and unfunded noncontributory defined benefit pension plans that together cover substantially all of our employees. The plans provide defined benefits based upon years of service and final average salary.
We also have other post-retirement benefit plans covering substantially all of our employees. The health care plans are contributory with participants' contributions adjusted annually; the life insurance plans are noncontributory. The accounting for the health care plans anticipates future cost-sharing changes to the written plans that are consistent with our expressed intent to maintain the current cost sharing levels. The post-retirement health care plans include a limit on our share of costs for recent and future retirees. We use a year end measurement date for all of our pension and other post-retirement benefit plans.
The accumulated benefit obligation for all defined benefit plans was $1,251.6 million and $1,195.5 million as of December 31, 2005 and 2004, respectively.
Information for pension plans with an accumulated benefit obligation in excess of the fair value of assets is as follows:
The components of net periodic pension and other post-retirement benefit costs are:
The expected long-term rate of return on plan assets was 9% in 2005 and 2004. In 2006, the expected rate of return on plan assets will be 8.5%, which is expected to increase pension expense by approximately $5.0 million. This return expectation on plan assets was determined by reviewing actual pension historical returns as well as calculating expected total trust returns using the weighted average of long-term market returns for each of the asset categories utilized in the pension fund.
Other Post-retirement Benefits Plans: We use various Employees' Benefit Trusts to fund a major portion of other post-retirement benefits. The majority of the trusts' assets are mutual funds or commingled indexed funds.
A one-percentage-point change in assumed health care cost trend rates would have the following effects:
In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act) was signed into law. The Act introduced a prescription drug benefit program under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans. In 2004, the FASB issued FASB Staff Position (FSP) SFAS 106-2,
Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.
In 2004, in accordance with FSP 106-2, we chose to recognize the effects of the Act retroactively effective January 1, 2004. Calculated actuarially, the Act resulted in a reduction of $24.1 million in our benefit obligation. In addition, we recorded a reduction to SFAS 106 expense of $4.7 million in 2004. In January 2005, the Centers for Medicare & Medicaid Services released final regulations to implement the new prescription drug benefit under Part D of Medicare. It was determined that the employer sponsored plans meet these regulations and that the previously determined actuarial measurements do not need to be revised.
In October 2005, we announced that we were offering to our retirees a Medicare Advantage program as an option within our existing post-retirement medical and drug plans. The Medicare Advantage program is part of the Act, and offers post-65 medical and drug benefits through private insurance carriers. The Medicare Advantage program is expected to reduce the cost of post-65 medical and drug costs for our retirees and the Company. Due to this change, we remeasured the fair value of our other post-retirement plans in the fourth quarter of 2005 in accordance with SFAS 106, Employers' Accounting for Post-Retirement Benefits Other than Pensions. In 2005, the impact of this remeasurement and the FSP 106-2 benefit was approximately a $4.4 million reduction to SFAS 106 expense.
Plan Assets: In our opinion, current pension trust assets and amounts which are expected to be contributed to the trusts in the future will be adequate to meet pension payment obligations to current and future retirees. Our pension plans asset allocation at December 31, 2005 and 2004, and our target allocation for 2006, by asset category, are as follows:
Our common stock is not included in equity securities. Investment managers are specifically prohibited from investing in our securities or any affiliate of ours except if part of a commingled fund.
The target asset allocation was established by our Investment Trust Policy Committee, which oversees investment matters related to all of our funded benefit plans. Asset allocation is monitored by the Investment Trust Policy Committee.
Our other post-retirement benefit plans asset allocation at December 31, 2005 and 2004, and our target allocation for 2006, by asset category, are as follows:
Our common stock is not included in equity securities. Investment managers are specifically prohibited from investing in our securities or any affiliate of ours except if part of a commingled fund.
The target asset allocation was established by our Investment Trust Policy Committee, which oversees investment matters related to all of our funded benefit plans. Asset allocation is monitored by the Investment Trust Policy Committee.
Cashflows:
Based on our PSCW approved funding policy and current IRS funding requirements, we expect to contribute $58.2 million to fund pension benefits and $13.2 million to fund other post-retirement benefit plans in 2006. Of the $58.2 million expected to be contributed to fund pension benefits in 2006, we estimate $53.0 million will be for our qualified pension plans. We did not make a contribution to our qualified pension plan during 2005. We contributed $55.7 million to our qualified pension plans during 2004.
The entire contribution to the other post-retirement benefit plans during 2005 was discretionary as the plans are not subject to any minimum regulatory funding requirements.
The following table identifies our expected benefit payments over the next 10 years:
Savings Plans: We sponsor savings plans which allow employees to contribute a portion of their pre-tax and or after-tax income in accordance with plan-specified guidelines. Under these plans we expensed matching contributions of $10.7 million, $10.5 million and $10.1 million during 2005, 2004 and 2003, respectively.
Severance Plans: In 2004, we incurred $30.5 million ($18.3 million after-tax) of severance costs. The majority of the severance costs related to an enhanced severance package offered to selected management employees of Wisconsin Energy and its subsidiaries who voluntarily resigned in the fourth quarter of 2004. The program was enacted to help reduce the upward pressure on operating expenses.
Approximately 200 employees received severance benefits during 2004. At December 31, 2004, we accrued $6.6 million for severance benefits. As of December 31, 2005, substantially all of the severance related benefits were paid.
P -- GUARANTEES
We enter into various guarantees to provide financial and performance assurance to third parties on behalf of our affiliates. As of December 31, 2005, we had the following guarantees:
A Non-Utility Energy segment guarantee in support of Wisvest-Connecticut, which we sold in December 2002 to PSEG, provides financial assurance for potential obligations relating to environmental remediation under the original purchase agreement for Wisvest-Connecticut with United Illuminating. The potential obligations for environmental remediation, which are unlimited, are reimbursable by PSEG under the terms of the sale agreement in the event that we are required to perform under the guarantee.
Other guarantees support obligations of our affiliates to third parties under loan agreements and surety bonds. In the event our affiliates fail to perform, we would be responsible for the obligations.
Wisconsin Electric guarantees the potential retrospective premiums that could be assessed under Wisconsin Electric's nuclear insurance program (See Note I).
Subsidiary guarantees support loan obligations and surety bonds between our affiliates and third parties. In the event our affiliates fail to perform, our subsidiary would be responsible for the obligations.
Postemployment benefits: Postemployment benefits provided to former or inactive employees are recognized when an event occurs. The estimated liability, excluding severance benefits, for such benefits was $17.3 million as of December 31, 2005.
Q -- SEGMENT REPORTING
Our reportable operating segments at December 31, 2005 include a utility energy segment and a non-utility energy segment. In July 2004, our manufacturing segment was sold to Pentair, Inc. We have organized our reportable operating segments based in part upon the regulatory environment in which our utility subsidiaries operate. In addition, the segments are managed separately because each business requires different technology and marketing strategies. The accounting policies of the reportable operating segments are the same as those described in Note A.
Our utility energy segment primarily includes our electric and natural gas utility operations. Our electric utility operation engages in the generation, distribution and sale of electric energy in southeastern (including metropolitan Milwaukee), east central and northern Wisconsin and in the Upper Peninsula of Michigan. Our natural gas utility operation is engaged in the purchase, distribution and sale of natural gas to retail customers and the transportation of customer-owned natural gas throughout Wisconsin. Our non-utility energy segment derives its revenues primarily from the ownership of electric power generating facilities for long-term lease to Wisconsin Electric and economic interests in other energy-related entities.
Summarized financial information concerning our reportable operating segments for each of the years ended December 31, 2005, 2004 and 2003, is shown in the following table. The segment information below includes non-cash impairment charges of $149.0 million ($96.9 million after tax or $0.81 per share) in 2004, which are now included in income from discontinued operations as the sale of these businesses was announced or completed in 2005. In 2003, the segment information includes non-cash impairment charges, net of gains of $45.6 million
($29.7 million after tax or $0.25 per share). These impairment charges primarily related to the Non-Utility Energy segment (See Note D). Substantially all of our long-lived assets and operations are domestic.
(a)
The non-utility energy segment includes discontinued operations for the Calumet operations. The sale of Calumet was completed effective May 31, 2005. In 2005, Calumet is reported as discontinued operations for the five months ended May 31, 2005. The after tax gain of $4.7 million recorded for the sale is included in Income from Discontinued Operations, Net. Certain overheads reported for Calumet continue to exist following the sale and are reported in continuing operations. Certain other costs are directly attributable to the discontinued operations. Total assets in the non-utility segment include the assets held for sale of Calumet of $29.8 million and $155.1 million at December 31, 2004 and 2003, respectively.
(b)
The sale of our manufacturing segment was completed effective July 31, 2004. The financial information presented for the manufacturing segment in 2004 is for the seven months ended July 31, 2004. The gain on the sale of the manufacturing segment is reflected in Corporate and Other. Certain corporate overheads reported in the manufacturing segment continue to exist following the sale and are reported in continuing operations. Certain other corporate costs are directly attributable to the discontinued operations.
(c)
Other includes all other non-utility activities, primarily non-utility real estate investment and development by Wispark, non-utility investment in renewable energy and recycling technologies by Minergy as well as interest on corporate debt and in 2004, the gain on the sale of the manufacturing segment. In August 2005, we announced our intent to sell Minergy Neenah. The operations of Minergy Neenah are currently classified as discontinued operations in other. Certain overheads reported for Minergy Neenah will continue to exist following the sale and are reported in continuing operations. Certain other costs are directly attributable to the discontinued operations. Total assets in other includes Minergy Neenah assets held for sale of $17.4 million, $24.4 million and $51.0 million at December 31, 2005, 2004 and 2003, respectively.
(d)
An elimination for intersegment revenues is included in Operating Revenues of $36.3 million, $6.8 million and $5.9 million for 2005, 2004 and 2003, respectively.
R -- RELATED PARTIES
We receive and/or provide certain services to other associated companies in which we have an equity investment.
American Transmission Company LLC: We have a 33.5% interest in ATC, a regional transmission company established in 2000 under Wisconsin legislation. We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance and project management work for ATC, which are reimbursed to us by ATC. Under our Power the Future plan, we are required to pay the cost of needed transmission infrastructure upgrades. ATC will reimburse us for these costs when the units are placed into service. At December 31, 2005 and 2004 we had a receivable of $19.4 million and $4.9 million for these items.
Guardian Pipeline: We have a one third ownership interest in Guardian Pipeline, L.L.C., which owns and operates an interstate natural gas pipeline. We have committed to purchase 650,000 dekatherms per day of capacity (approximately 87% of the pipeline's total capacity) under the terms of a 10 year transportation agreement expiring December 2012.
Nuclear Management Company: At December 31, 2005, NMC, which operates Point Beach, was owned by our affiliate, WEC Nuclear Corporation, and the affiliates of three other unaffiliated investor-owned utilities in the region. Wisconsin Electric pays NMC a plant operating charge.
We provided and received services from the following associated companies during 2005, 2004 and 2003:
At December 31, 2005 and 2004 our consolidated balance sheets included receivable and payable balances with the following associated companies:
S -- COMMITMENTS AND CONTINGENCIES
Capital Expenditures: We have made certain commitments in connection with 2006 capital expenditures. During 2006, we estimate that total capital expenditures will be approximately $1,020.0 million, excluding the purchase of nuclear fuel.
Operating Leases: We enter into long-term purchase power contracts to meet a portion of our anticipated increase in future electric energy supply needs. These contracts expire at various times through 2013. Certain of these contracts were deemed to qualify as operating leases.
Future minimum payments for the next five years and thereafter for these contracts are as follows:
Environmental Matters:
We periodically review our exposure for environmental remediation costs as evidence becomes available indicating that our liability has changed. Given current information, including the following, we believe that future costs in excess of the amounts accrued and/or disclosed on all presently known and quantifiable environmental contingencies will not be material to our financial position or results of operations.
We have a program of comprehensive environmental remediation planning for former manufactured gas plant sites and coal-ash disposal sites. We perform ongoing assessments of manufactured gas plant sites and related disposal sites previously used by Wisconsin Electric or Wisconsin Gas, and coal ash disposal/landfill sites used by Wisconsin Electric, as discussed below. We are working with the Wisconsin Department of Natural Resources in our investigation and remediation planning. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.
Manufactured Gas Plant Sites: We have identified sixteen sites at which Wisconsin Electric, Wisconsin Gas, or a predecessor company historically owned or operated a manufactured gas plant. We have substantially completed planned remediation activities at eight of those sites and certain sites are subject to ongoing monitoring. Remediation at additional sites is currently being performed, and other sites are being investigated or monitored. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Based upon ongoing analysis, we estimate that the future costs for detailed site investigation and future remediation costs may range from $25 to $50 million over the next ten years. This estimate is dependent upon several variables including, among other things, the extent of remediation, changes in technology and changes in regulation. As of December 31, 2005, we have established reserves of $27.4 million related to future remediation costs.
The PSCW has allowed Wisconsin utilities, including Wisconsin Electric and Wisconsin Gas, to defer the costs spent on the remediation of manufactured gas plant sites, and has allowed for these costs to be recovered in rates over five years. Accordingly, we have recorded a regulatory asset for remediation costs.
Ash Landfill Sites: Wisconsin Electric aggressively seeks environmentally acceptable, beneficial uses for its coal combustion by-products. However, these coal-ash by-products have been, and to a small degree, continue to be disposed in company-owned, licensed landfills. Some early designed and constructed landfills may allow the release of low levels of constituents resulting in the need for various levels of monitoring or adjusting. Where 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. The costs of these efforts are included in the fuel costs of Wisconsin Electric. During 2005, 2004 and 2003, Wisconsin Electric incurred $0.1 million, $1.8 million and $2.1 million, respectively, in coal-ash remediation expenses. As of December 31, 2005, we have no reserves established related to ash landfill sites.
EPA - Proposed Consent Decree: Wisconsin Electric received a request for information in December 2000 from the United States Environmental Protection Agency (EPA) regional office pursuant to Section 114(a) of the Clean Air Act and a supplemental request in December 2002. In April 2003, Wisconsin Electric and EPA announced that a consent decree had been reached that resolved all issues related to this matter. In July 2003, the court granted the State of Michigan and EPA's joint motion to amend the consent decree to allow Michigan to become a party. Under the consent decree, Wisconsin Electric is required to significantly reduce its air emissions from its coal-fired generating facilities. The reductions are expected to be achieved by 2013 through a combination of installing new pollution control equipment, upgrading existing equipment, and retiring certain older units. The capital cost of implementing this agreement is estimated to be approximately $600 million over the 10 years ending 2013. Through December 31, 2005, we have spent approximately $216.5 million associated with implementing the EPA agreement. There may be additional costs of compliance should Wisconsin Electric elect to control rather than retire Units 5 and 6 at the Oak Creek Power Plant. We believe this additional cost may add approximately $150 million to $350 million to the estimate. Under the agreement with EPA, Wisconsin Electric is conducting a full scale demonstration at its Presque Isle facility, in cooperation with the United States Department of Energy (DOE), to test new mercury reduction technologies. The DOE is contributing $24.8 million in addition to the $20 to $25 million Wisconsin Electric is spending to implement this project. These steps and the associated costs are consistent with our cost projections for implementing our Wisconsin Multi-Emission Cooperative Agreement and our Power the Future plan. Wisconsin Electric also agreed to pay a civil penalty of $3.2 million which was charged to earnings in the second quarter of 2003.
The agreement has gone through the public comment period. In October 2003, three citizen groups filed a motion with the court to intervene in the proceeding to contest the consent decree; the court granted their motion. Also, in
October 2003, the government filed its response to public comments and a motion asking the court to approve the amended consent decree. The intervenor groups subsequently filed a motion requesting that the court stay the government's motion for approval of the decree to allow the intervenors to conduct discovery. Briefing was completed and the judge heard oral arguments from the parties in August 2004. In September 2004, the court granted the intervenors' request for limited discovery with respect to two facilities within our generation fleet, and ordered that discovery be completed by December 2004. Final briefing concluded in March 2005. The court may convene additional hearings.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Wisconsin Energy Corporation:
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Wisconsin Energy Corporation and subsidiaries (the "Company") as of December 31, 2005 and 2004, and the related consolidated statements of income, common equity and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2006 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
/s/DELOITTE & TOUCHE LLP
Deloitte & Touche LLP
Milwaukee, Wisconsin
February 27, 2006
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Wisconsin Energy Corporation:
We have audited management's assessment, included in the accompanying Management's Report on Internal Control Over Financial Reporting, that Wisconsin Energy Corporation and subsidiaries (the "Company") maintained effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and consolidated statement of capitalization as of December 31, 2005, and the related consolidated statements of income, common equity and cash flows for the year ended December 31, 2005 of the Company and our report dated February 27, 2006 expressed an unqualified opinion on those financial statements.
/s/DELOITTE & TOUCHE LLP
Deloitte & Touche LLP
Milwaukee, Wisconsin
February 27, 2006
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Wisconsin Energy Corporation's and subsidiaries disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period covered by this report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, Wisconsin Energy Corporation's and subsidiaries disclosure controls and procedures are effective in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act.
Management's Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of Wisconsin Energy Corporation's and subsidiaries internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal Control - Integrated Framework, our management concluded that Wisconsin Energy Corporation's and subsidiaries internal control over financial reporting was effective as of December 31, 2005.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of our financial statements has issued an attestation report on management's assessment of the effectiveness of Wisconsin Energy Corporation's and subsidiaries internal control over financial reporting as of December 31, 2005. Deloitte & Touche's report is included in this report.
Changes in Internal Control Over Financial Reporting
During the fourth quarter of 2005, management implemented federal and state tax software that increased the functionality of ongoing tax estimates and enabled more frequent and reliable analyses of federal and state income tax balances. Apart from this change, there has not been any change in Wisconsin Energy Corporation's and subsidiaries internal control over financial reporting during the fourth quarter of 2005 that has materially affected, or is reasonably likely to materially affect, Wisconsin Energy Corporation's and subsidiaries internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10.
DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information under "Proposal 1: Election of Directors - Terms Expiring in 2007", "Section 16(a) Beneficial Ownership Reporting Compliance", "Corporate Governance - Frequently Asked Questions: Are the Audit and Oversight, Corporate Governance and Compensation Committees comprised solely of independent directors?", "Corporate Governance - Frequently Asked Questions: Are all the members of the audit committee financially literate and does the committee have an audit committee financial expert?" and "Committees of the Board of Directors - Audit and Oversight" in our definitive Proxy Statement to be filed with the SEC for our Annual Meeting of Stockholders to be held May 4, 2006 (the "2006 Annual Meeting Proxy Statement") is incorporated herein by reference. Also see "Executive Officers of the Registrant" in Part I of this report.
We have adopted a written code of ethics, referred to as our Code of Business Conduct, that all of our directors, executive officers and employees, including the principal executive officer, principal financial officer and principal accounting officer, must comply with. We have posted our Code of Business Conduct on our Internet website, www.wisconsinenergy.com. We have not provided any waiver to the Code for any director, executive officer or other employee. Any amendments to, or waivers for directors and executive officers from, the Code of Business Conduct will be disclosed on our website or in a current report on Form 8-K.
Our Internet website, www.wisconsinenergy.com, also contains our Corporate Governance Guidelines and the charters of our Audit and Oversight, Corporate Governance and Compensation Committees.
Our Code of Business Conduct, Corporate Governance Guidelines and committee charters are also available without charge to any stockholder of record or beneficial owner of our common stock by writing to the corporate secretary, Anne K. Klisurich, at our principal business office, 231 West Michigan Street, P.O. Box 1331, Milwaukee, Wisconsin 53201.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
The information under "Compensation of the Board of Directors," "Executive Officers' Compensation," "Employment and Severance Arrangements" and "Retirement Plans" in the 2006 Annual Meeting Proxy Statement is incorporated herein by reference.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The security ownership information called for by Item 12 of Form 10-K is incorporated herein by reference to this information included under "WEC Common Stock Ownership" in the 2006 Annual Meeting Proxy Statement.
EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth information about our equity compensation plans as of December 31, 2005.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information under "Certain Relationships and Related Transactions" in the 2006 Annual Meeting Proxy Statement is incorporated herein by reference.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information regarding the fees paid to, and services performed by, our independent auditors and the pre-approval policy of our audit and oversight committee under "Independent Auditors' Fees and Services" in the 2006 Annual Meeting Proxy Statement is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) 1.
FINANCIAL STATEMENTS AND REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM INCLUDED IN PART II OF THIS REPORT
Consolidated Income Statements for the three years ended December 31, 2005.
Consolidated Balance Sheets at December 31, 2005 and 2004.
Consolidated Statements of Cash Flows for the three years ended December 31, 2005.
Consolidated Statements of Common Equity for the three years ended December 31, 2005.
Consolidated Statements of Capitalization at December 31, 2005 and 2004.
Notes to Consolidated Financial Statements.
Reports of Independent Registered Public Accounting Firm.
2.
FINANCIAL STATEMENT SCHEDULES INCLUDED IN PART IV OF THIS REPORT
Schedule I Condensed Parent Company Financial Statements, including Income Statements and Cash Flows for the three years ended December 31, 2005 and Balance Sheets at December 31, 2005 and 2004. Schedule II, Valuation and Qualifying Accounts, for the three years ended December 31, 2005. Other schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto.
3.
EXHIBITS AND EXHIBIT INDEX
See the Exhibit Index included as the last part of this report, which is incorporated herein by reference. Each management contract and compensatory plan or arrangement required to be filed as an exhibit to this report is identified in the Exhibit Index by two asterisks (**) following the description of the exhibit.
WISCONSIN ENERGY CORPORATION
INCOME STATEMENTS
(Parent Company Only)
SCHEDULE I -- CONDENSED PARENT COMPANY
FINANCIAL STATEMENTS
WISCONSIN ENERGY CORPORATION
STATEMENTS OF CASH FLOWS
(Parent Company Only)
SCHEDULE I - CONDENSED PARENT COMPANY
FINANCIAL STATEMENTS - (Cont'd)
WISCONSIN ENERGY CORPORATION
BALANCE SHEETS
(Parent Company Only)
SCHEDULE I - CONDENSED PARENT COMPANY
FINANCIAL STATEMENTS - (Cont'd)
WISCONSIN ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS
(Parent Company Only)
SCHEDULE I - CONDENSED PARENT COMPANY
FINANCIAL STATEMENTS - (Cont'd)
1. The consolidated financial statements of Wisconsin Energy Corporation reflect certain businesses as discontinued operations. The related assets for these discontinued operations are recorded as assets held for sale in the consolidated financial statements. For Parent Company only presentation, the investments in discontinued operations are recorded in Investment in subsidiary companies. In the Wisconsin Energy Corporation consolidated financial statements, we have reported assets held for sale of $17.4 million and $54.2 million as of December 31, 2005 and 2004, respectively. The condensed parent company income statements and cashflow statements report the earnings of these businesses as discontinued operations. For Parent Company only presentation, investment in subsidiaries are accounted for using the equity method. The condensed parent company financial statements and notes should be read in conjunction with the consolidated financial statements and notes of Wisconsin Energy Corporation appearing in this Annual Report on Form 10-K.
2. Wisconsin Energy's ability as a holding company to pay common dividends primarily depends on the availability of funds received from our principal utility subsidiaries, Wisconsin Electric Power Company and Wisconsin Gas LLC. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our principal utility subsidiaries to transfer funds to the Parent Company in the form of cash dividends or advances. In addition, under Wisconsin law, Wisconsin Electric and Wisconsin Gas are prohibited from loaning funds, either directly or indirectly, to the Parent Company.
We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.
3. In September 2004, the Parent Company used cash proceeds from the sale of WICOR Industries for the redemption of $300 million of Wisconsin Energy 5.875% senior notes due April 1, 2006. In September 2004, we recorded $17.0 million of costs associated with this early redemption, which are included in Other Income and Deductions, net for the year ended December 31, 2004.
4. Wisconsin Energy allocates the service cost component of pension costs to participating companies based on labor dollars. The assets, obligations and the components of SFAS 87 pension costs other than service cost (including the minimum pension liability) are allocated by the Company's actuary to each of the participating companies as if each participating company had its own plan. The Parent Company only balance sheets reflect the unallocated amounts.
As of December 31, 2005 and 2004, the Parent Company recorded a minimum pension liability of $130.8 million and $127.8 million, respectively, to reflect the funded status of the unallocated portion of the pension plans. Wisconsin Energy has concluded that substantially all of the unrecognized pension costs which arose from recording the minimum pension liability under Statement of Financial Accounting Standard (SFAS) 87, Employers' Accounting for Pensions, related to utility operations qualify as a regulatory asset. As such, as of December 31, 2005 and 2004, Wisconsin Energy recorded pre-tax regulatory assets totaling $127.0 million and $130.6 million, respectively.
5. As of December 31, 2005, the maturities of our long-term debt outstanding were as follows:
We amortize debt premiums, discounts and debt issuance costs over the lives of the debt and we include the costs in interest expense.
We have entered into various bank back-up credit agreements to maintain short-term liquidity which, among other terms, require the company to maintain, subject to certain exceptions, a minimum total funded debt to capitalization ratio of less than 70%.
Wisconsin Energy's bank back-up credit facilities require us to maintain a minimum ratio of consolidated EBITDA (Earnings before interest, taxes, depreciation and amortization) to consolidated interest expense.
Our bank back-up credit agreements contain customary covenants, including certain limitations on our ability to sell assets. The credit agreements also contain customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, ERISA defaults and change of control.
At December 31, 2005, we were in compliance with all covenants.
6. Wisconsin Energy and certain of its subsidiaries enter into various guarantees to provide financial and performance assurance to third parties on behalf of affiliates. As of December 31, 2005, Wisconsin Energy had the following guarantees:
Utility guarantees support obligations of the utility segment under surety bonds and worker's compensation.
Wisconsin Energy's guarantees in support of our Non-Utility Energy segment guaranty performance and payment obligations of We Power and Wisvest. A guarantee in support of Wisvest-Connecticut which we sold in December 2002 to PSEG provides financial assurance for potential obligations relating to environmental remediation under the original purchase agreement with United Illuminating. The potential obligations for environmental remediation, which are unlimited, are reimbursable by PSEG under the terms of the sale agreement in the event that Wisconsin Energy is required to perform under the guarantee. Guarantees also support obligations to third parties under the agreement with PSEG for the sale of Wisvest - Connecticut and post-closing obligations
including indemnity obligations related to environmental condition and other matters under the Calumet facility sale agreement which was effective May 31, 2005. Wisconsin Energy's maximum aggregate exposure under the indemnification provisions of the Calumet facility sale agreement, except for retention of the full exposure to indemnify for environmental claims related to certain property no longer leased or owned by Wisconsin Energy or its subsidiaries, is $35 million.
The guarantees which support We Power are for obligations under purchase, construction and lease agreements with the utility segment and third parties.
Wisconsin Energy's other guarantees support obligations to third parties under purchase and loan agreements and surety bonds. In the event the guarantee fails to perform, Wisconsin Energy would be responsible for the obligations.
SCHEDULE II -
VALUATION AND QUALIFYING ACCOUNTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Wisconsin Energy Corporation:
We have audited the consolidated financial statements of Wisconsin Energy Corporation and subsidiaries (the "Company") as of December 31, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, management's assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2005, and the effectiveness of the Company's internal control over financial reporting as of December 31, 2005, and have issued our reports thereon dated February 27, 2006; such consolidated financial statements and reports are included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedules of the Company listed in Item 15(a)(2). These consolidated financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
/s/DELOITTE & TOUCHE LLP
Deloitte & Touche LLP
Milwaukee, Wisconsin
February 27, 2006
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
WISCONSIN ENERGY CORPORATION
By
/s/GALE E. KLAPPA
Date:
March 2, 2006
Gale E. Klappa, Chairman of the Board, President
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
/s/GALE E. KLAPPA
March 2, 2006
Gale E. Klappa, Chairman of the Board, President and Chief
Executive Officer and Director -- Principal Executive Officer
/s/ALLEN L. LEVERETT
March 2, 2006
Allen L. Leverett, Executive Vice President and Chief
Financial Officer -- Principal Financial Officer
/s/STEPHEN P. DICKSON
March 2, 2006
Stephen P. Dickson, Vice President and
Controller -- Principal Accounting Officer
/s/JOHN F. AHEARNE
March 2, 2006
John F. Ahearne, Director
/s/JOHN F. BERGSTROM
March 2, 2006
John F. Bergstrom, Director
/s/BARBARA L. BOWLES
March 2, 2006
Barbara L. Bowles, Director
/s/ROBERT A. CORNOG
March 2, 2006
Robert A. Cornog, Director
/s/CURT S. CULVER
March 2, 2006
Curt S. Culver, Director
/s/THOMAS J. FISCHER
March 2, 2006
Thomas J. Fischer, Director
/s/ULICE PAYNE, JR.
March 2, 2006
Ulice Payne, Jr., Director
/s/FREDERICK P. STRATTON, JR.
March 2, 2006
Frederick P. Stratton, Jr., Director
/s/GEORGE E. WARDEBERG
March 2, 2006
George E. Wardeberg, Director
WISCONSIN ENERGY CORPORATION
(Commission File No. 001-09057)
EXHIBIT INDEX
to
Annual Report on Form 10-K
For the year ended December 31, 2005
The following exhibits are filed or furnished with or incorporated by reference in the report with respect to Wisconsin Energy Corporation. (An asterisk (*) indicates incorporation by reference pursuant to Exchange Act Rule 12b-32.)
E-1
E-2
10.5*
Amendment to the Stock Purchase Agreement dated July 28, 2004. (Exhibit 2.2 to Wisconsin Energy Corporation's 06/30/04 Form 10-Q.)
10.6*
Membership Interest Purchase Agreement between CET Two, LLC and Tenaska Power Fund L.P., dated as of March 24, 2005 (the "Membership Purchase Agreement"). (Exhibit 10.1 to Wisconsin Energy Corporation's 03/31/05
Form 10-Q.)
10.7*
First Amendment to the Membership Purchase Agreement dated as of May 31, 2005. (Exhibit 10.1 to Wisconsin Energy Corporation's 06/30/05 Form 10-Q.)
10.8*
First Amended and Restated Three Year Credit Agreement among Wisconsin Energy Corporation, as Borrower, the Lenders identified therein, J.P. Morgan Securities Inc., as Lead Arranger and Bank Manager, Citibank, N.A. and U.S. Bank National Association, as Syndication Agents, Credit Suisse First Boston, as Documentation Agent, and JPMorgan Chase Bank, as Administrative Agent, dated as of April 8, 2003 (the "First Amended and Restated Three Year Credit Agreement"). (Exhibit 10.1 to Wisconsin Energy Corporation's 12/31/04
Form 10-K.)
10.9*
Amendment to the First Amended and Restated Three Year Credit Agreement, dated as of November 1, 2004. (Exhibit 10.2 to Wisconsin Energy Corporation's 12/31/04 Form 10-K.)
10.10*
Credit Agreement, dated as of June 23, 2004, among Wisconsin Energy Corporation, as Borrower, the Lenders identified therein, and JPMorgan Chase Bank, as Agent. (Exhibit 10.3 to Wisconsin Energy Corporation's 12/31/04
Form 10-K.)
10.11*
Credit Agreement, dated as of June 23, 2004, among Wisconsin Gas Company (n/k/a Wisconsin Gas LLC), as Borrower, the Lenders identified therein, Citibank, N.A., as Administrative Agent, and U.S. Bank National Association, as Fronting Bank. (Exhibit 10.4 to Wisconsin Energy Corporation's 12/31/04 Form 10-K.)
10.12*
Credit Agreement, dated as of June 23, 2004, among Wisconsin Electric Power Company, as Borrower, the Lenders identified therein, and U.S. Bank National Association, as Administrative Agent. (Exhibit 10.5 to Wisconsin Energy Corporation's 12/31/04 Form 10-K.)
10.13*
Credit Agreement, dated as of November 1, 2004, among Wisconsin Electric Power Company, as Borrower, the Lenders identified therein, and JPMorgan Chase Bank, as Administrative Agent. (Exhibit 10.6 to Wisconsin Energy Corporation's 12/31/04 Form 10-K.)
10.14*
Supplemental Executive Retirement Plan of Wisconsin Energy Corporation, as amended and restated as of April 1, 2004. (Exhibit 10.4 to Wisconsin Energy Corporation's 06/30/04 Form 10-Q.)** See Note.
E-3
E-4
E-5
10.40*
Form of Director Nonstatutory Stock Option Agreement for February 2000 Option Grants under the WICOR, Inc. 1992 Director Stock Option Plan. (Exhibit 4.8 to Wisconsin Energy Corporation's Registration Statement on Form S-8 (Reg. No. 333-35798).)** See Note.
10.41*
2001 Revised forms of award agreements under 1993 Omnibus Stock Incentive Plan, as amended, for restricted stock awards, incentive stock option awards and non-qualified stock option awards. (Exhibit 10.3 to Wisconsin Energy Corporation's 03/31/01 Form 10-Q.)** See Note.
10.42*
1993 Omnibus Stock Incentive Plan, as amended and restated, as approved by the stockholders at the 2001 annual meeting of stockholders. (Appendix A to Wisconsin Energy Corporation's Proxy Statement dated March 20, 2001 for the 2001 annual meeting of stockholders.)** See Note.
10.43*
2005 Terms and Conditions Governing Non-Qualified Stock Option Award under 1993 Omnibus Stock Incentive Plan, as amended. (Exhibit 10.1 to Wisconsin Energy Corporation's 12/28/04 Form 8-K.)** See Note.
10.44*
Wisconsin Gas Company (n/k/a Wisconsin Gas LLC) Supplemental Retirement Income Program. (Exhibit 10.8 to Wisconsin Gas Company's 12/31/98 Form 10-K (File No. 001-07530).)** See Note.
10.45*
WICOR, Inc. 1994 Long-Term Performance Plan, as amended. (Exhibit 10.1 to WICOR, Inc.'s 06/30/98 Form 10-Q (File No. 001-07951).)** See Note.
10.46*
Special Severance Benefits Protection Agreement between Wisconsin Energy Corporation and James Donnelly, effective August 26, 2002. (Exhibit 10.1 to Wisconsin Energy Corporation's 09/30/02 Form 10-Q.)** See Note.
10.47(a)*
Resignation and Release Agreement between Wisconsin Energy Corporation and James Donnelly, effective May 1, 2004. (Exhibit 10.41 to Wisconsin Energy Corporation's 12/31/03 Form 10-K.)** See Note.
10.47(b)*
Amendment of Resignation and Release Agreement between Wisconsin Energy Corporation and James Donnelly, dated as of April 30, 2004. (Exhibit 10.3(b) to Wisconsin Energy Corporation's 03/31/04 Form 10-Q.)** See Note.
10.48*
Form of Performance Share Agreement under 1993 Omnibus Stock Incentive Plan, as amended. (Exhibit 10.42 to Wisconsin Energy Corporation's 12/31/03
Form 10-K.)** See Note.
10.49*
Wisconsin Energy Corporation Performance Unit Plan. (Exhibit 10.1 to Wisconsin Energy Corporation's 12/06/04 Form 8-K.)** See Note.
10.50*
Form of Award of Performance Units under the Wisconsin Energy Corporation Performance Unit Plan. (Exhibit 10.2 to Wisconsin Energy Corporation's 12/06/04 Form 8-K.)** See Note.
10.51*
Port Washington I Facility Lease Agreement between Port Washington Generating Station, LLC, as Lessor, and Wisconsin Electric Power Company, as Lessee, dated as of May 28, 2003. (Exhibit 10.7 to Wisconsin Electric Power Company's 06/30/03 Form 10-Q (File No. 001-01245).)
E-6
E-7