ITEM 1. BUSINESS
A. GENERAL
For purposes of this Annual Report on Form 10-K, unless the context otherwise indicates, when we refer to "us," "we," "our" or "ours," we are describing WPS Resources.
WPS Resources Corporation
WPS Resources is domiciled in the United States and was incorporated in Wisconsin in 1993. WPS Resources is a holding company for regulated utility and nonregulated business units. The approximate percentages of revenues and net income for the year ended 2005 and assets as of December 31, 2005 of WPS Resources and each of its principal operating subsidiaries respecting the business as a whole are:
*
The percentages above may not total 100% due to intercompany transactions. Intercompany transactions largely consist of energy sales and purchases between subsidiaries and related intercompany receivables and payables.
For the last three years, the majority of WPS Resources' revenues were earned within the United States and the majority of long-lived assets were located within the United States.
Wisconsin Public Service Corporation
WPSC, a Wisconsin corporation, is domiciled in the United States and began operations in 1883. WPSC is a regulated electric and natural gas utility serving an 11,000 square mile service territory in northeastern Wisconsin and an adjacent portion of the Upper Peninsula of Michigan. In 2005, WPSC served 424,615 electric customers and 307,540 natural gas customers. Wholesale electric service is provided to various customers, including municipal utilities, electric cooperatives, energy marketers, other investor-owned utilities and municipal joint action agencies. For the last three years, all WPSC revenues were earned within the United States and all of its assets were located within the United States. In 2005, retail sales accounted for 90% of total revenues while wholesale sales accounted for 10% of total revenues.
In July 2005, WPSC sold its 59% interest in the Kewaunee nuclear power plant (a pressurized water reactor plant with a nameplate capacity of approximately 600 megawatts) to a subsidiary of Dominion Resources, Inc. In 2005, WPSC also sold a 30% interest in its 500-megawatt Weston 4 power plant (currently under construction) to DPC. On December 16, 2005, WPSC and WPS Investments, LLC entered into an agreement with Allete, Inc. that provides for Allete, through a Wisconsin subsidiary, to invest $60 million in ATC in 2006 related to a portion of the Wausau, Wisconsin to Duluth, Minnesota
transmission line which was previously being financed solely by WPSC. For more information regarding these and other sales, see Management's Discussion and Analysis of Financial Condition and Results of Operation.
For more information regarding revenues, net income and total assets for regulated electric and natural gas operations, see Note 26 to Consolidated Financial Statements - Segments of Business.
Upper Peninsula Power Company
UPPCO, a Michigan corporation, is domiciled in the United States and began operations in 1884. UPPCO is a regulated electric utility serving a 4,500 square mile area of Michigan's Upper Peninsula. In 2005, UPPCO provided retail electric service to 52,130 customers and wholesale electric service to 37 customers. Total revenues consisted of 77% retail sales and 23% wholesale sales.
In December 2005, UPPCO sold 1,366 acres of land along the Bond Falls Reservoir, Boney Falls Basin and Cataract Basin, which was no longer needed for operations of UPPCO. The property was sold for approximately $5.9 million and potentially up to an additional $3 million pending the removal of certain contingencies.
For more information regarding revenues, net income and total assets for regulated electric operations, see Note 26 to Consolidated Financial Statements - Segments of Business.
WPS Investments, LLC
WPS Investments, LLC, a Wisconsin limited liability company organized in 2000, is a nonutility company domiciled in the United States. On December 31, 2005, WPS Investments was owned 24.91% by WPSC, 6.79% by UPPCO and 68.3% by WPS Resources. The principal business of WPS Investments is to hold the investment of WPS Resources and its subsidiaries in ATC and Guardian Pipeline, LLC. At December 31, 2005, WPS Investments owned a 31.0% interest in ATC and a 33.3% interest in Guardian Pipeline. ATC owns, maintains, monitors and operates electric transmission assets in portions of Wisconsin, Michigan and Illinois. Guardian Pipeline is a 141-mile interstate natural gas pipeline that transports natural gas from Joliet, Illinois to Milwaukee Wisconsin.
WPS Energy Services, Inc.
ESI, a Wisconsin corporation, is domiciled in the United States and was established in 1994. ESI is a wholly owned non-regulated indirect subsidiary of WPS Resources. ESI offers nonregulated natural gas, electricity and alternate fuel supplies, as well as energy management and consulting services, to retail and wholesale customers primarily in the northeastern quadrant of the United States and adjacent portions of Canada. In addition, ESI began operations in Texas in 2005. Although ESI has a widening array of products and services, revenues are primarily derived through sales of electricity and natural gas. ESI had 2005 revenues of $5.4 billion (excluding intercompany revenues) and assets of $2.4 billion at December 31, 2005.
ESI currently owns and operates, through its subsidiaries, electric generation facilities in Wisconsin, Maine, Pennsylvania and New York in the United States and New Brunswick in Canada, a 23.3% interest in a synthetic fuel processing facility located in Kentucky, steam production facilities located in Arkansas and Oregon and a gas storage field in Michigan.
For more information regarding revenues, net income and total assets see Note 26 to Consolidated Financial Statements - Segments of Business.
B. REGULATED ELECTRIC OPERATIONS
WPS Resources' regulated electric utility operations are provided through WPSC and UPPCO. WPSC generates and distributes electric energy in northeastern Wisconsin. The cities of Green Bay, Oshkosh, Wausau and Stevens Point are the largest communities served by WPSC at the electric retail level. WPSC also provides retail electric energy to a small portion of Michigan's Upper Peninsula, primarily in the City of Menominee. UPPCO provides electric energy in Michigan's Upper Peninsula. The largest community served by UPPCO at the electric retail level is the Houghton/Hancock area.
Revenues, volumes, customers and plant assets for electric operations of WPSC and UPPCO were as follows:
In 2005, WPSC reached a firm net design peak of 2,189 megawatts on the afternoon of July 13. At the time of this summer peak, WPSC's total firm resources (i.e., generation plus firm purchases) totaled 2,681 megawatts. As a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand, the summer period is the most relevant for WPSC capacity planning purposes. WPSC expects future supply reserves to meet the minimum 18% planning reserve margin criteria through 2006 as required by the PSCW.
In 2005, UPPCO reached a firm net actual peak of 147 megawatts on the afternoon of December 19. At the time of this winter peak, UPPCO's total firm resources totaled 188 megawatts. In 2005, UPPCO purchased 91% of its total energy requirements. Remaining energy requirements were supplied by hydroelectric and combustion turbine facilities owned by UPPCO. During 2005, UPPCO purchased 65 megawatts of firm power from WPSC and 15 megawatts of firm power from a nonaffiliated independent power producer. UPPCO also purchased non-firm power from WPSC and Alliant Energy Corporation, among others. The purchases from WPSC represented 80% of UPPCO's total energy requirements in 2005. UPPCO has contracted for 65 megawatts of capacity and energy from WPSC and 17 megawatts from a nonaffiliated independent power producer for 2006.
Facilities
Weston Unit
In October 2004, WPSC began construction of Weston 4, a 500-megawatt coal-fired generation facility near Wausau, Wisconsin. The facility is estimated to cost approximately $779 million (including the acquisition of coal trains). The plant is expected to be operational in June 2008.
In November 2005, WPSC and DPC closed a transaction in which DPC acquired a 30% ownership share of the Weston 4 power plant. The agreement gives DPC a 150-megawatt share of the plant. Under terms of the agreement, WPSC received $95.1 million in cash from DPC for its share of the construction costs to date. DPC will also provide 30% of all remaining costs to complete the construction of the Weston 4 power plant. In addition, DPC will pay 30% of the cost of the coal train and of future operating and maintenance costs after completion in 2008.
The Weston 4 project is progressing on schedule with commercial operation expected by June 1, 2008. At December 31, 2005, 80% of the project engineering costs were complete and 24% of project construction work was complete. At December 31, 2005, WPSC as contractor for the project had entered into agreements for approximately $640 million of project costs, which includes incurred costs of approximately $381 million.
On November 15, 2004, the Sierra Club filed a petition with the WDNR under Section 285.61, Wis. Stats. seeking a contested case hearing on the air permit issued for the Weston 4 generation station. In February 2006, the Administrative Law Judge affirmed the Weston 4 air permit with modifications to the emission limits for sulfur dioxide and nitrogen oxide from the coal-fired boiler and particulate from the cooling tower. The modifications set limits that are more stringent than those set by the WDNR. WPS Resources is currently evaluating the impact this decision may have on future operating costs. WPS Resources expects construction of the Weston 4 facility to be completed in 2008 as originally scheduled and within expected costs.
Weston Units 1 through 3
WPSC currently owns and operates three coal-fired generation facilities at its Weston location. The plants have a total nameplate capacity of 492 megawatts. Weston 3 is the largest with a nameplate capacity of 350 megawatts.
Pulliam
WPSC also owns and operates six coal-fired generation units at its Pulliam plant located in Green Bay, Wisconsin. The units at the Pulliam site have a combined nameplate capacity of 370 megawatts, with the largest unit having a nameplate capacity of 125 megawatts.
Other Generation Facilities
WPSC has a 31.8% ownership interest in Columbia Units 1 and 2, located in Portage, Wisconsin (each a 527 megawatt generating station operated by Wisconsin Power and Light Company) and a 31.8% ownership interest in Edgewater Unit 4 located in Sheboygan, Wisconsin (a 330 megawatt generating station operated by Wisconsin Power and Light Company). These facilities are jointly owned by WPSC, Wisconsin Power and Light and various other utilities.
In addition to the facilities described above, WPSC and UPPCO own 24 hydroelectric generation facilities and 11 combustion turbine generation units. In addition, WPSC owns a 50% interest in Wisconsin River Power Company. Wisconsin River Power is the owner and operator of a combustion turbine and two hydroelectric plants on the Wisconsin River, which have a forecasted aggregate capacity rating of 70 megawatts. For a complete listing of these facilities, see Item 2 - Properties in this Annual Report on Form 10-K.
Power Purchase Agreements
In conjunction with the 2005 sale of WPSC's 59% interest in the Kewaunee nuclear power plant, WPSC entered into a long-term power purchase agreement with Dominion Energy Kewaunee, a subsidiary of Dominion Resources, to purchase energy and capacity approximately equivalent to WPSC's share of forecasted production had WPSC retained its ownership in Kewaunee. The power purchase agreement will extend through 2013 when the plant's current operating license expires. Monthly payments under the power purchase agreement approximate the expected costs of production had WPSC continued to own the plant.
In April 2004, WPSC entered into an exclusivity agreement with Dominion. Under this agreement, Dominion agreed to an exclusivity period starting with the closing of the sale of Kewaunee and extending to December 21, 2011. If Dominion decides to extend the operating license of Kewaunee, the agreement provides that during the exclusivity period Dominion would negotiate only with WPSC for a new power purchase agreement for 59% of the plant output.
WPSC currently has a power purchase agreement with Calpine Corporation for capacity and energy from the Fox Energy Center Side 1 (a 300 megawatt natural gas-fired combined cycle generation facility near Kaukauna, Wisconsin). The agreement called for WPSC to purchase 150 megawatts of capacity beginning on June 1, 2005, escalating to approximately 500 megawatts of capacity on June 1, 2006, (when a second unit is scheduled for completion) through May 31, 2015, when it decreases to 235 megawatts. The agreement terminates on May 31, 2016. WPSC is responsible for fuel supply to the facility for its portion of contracted generation over the life of the agreement. Although Calpine currently has financial issues (including bankruptcy of Calpine and some of its affiliates) WPSC does not expect any performance issues related to these contracts.
Other Facilities
WPSC, Minnesota Power Company and ATC are currently constructing a 220-mile, 345-kilovolt transmission line from Wausau, Wisconsin, to Duluth, Minnesota. Completion of the line is expected in 2008 at a total cost of approximately $420 million.
For additional information regarding the above and other facilities, see Item 2 - Properties in this Annual Report on Form 10-K.
Fuel Supply
Electric Supply Mix
WPSC's electric supply mix for 2005 and 2004 was:
* Purchased power has increased and nuclear generation decreased as a result of the sale of the Kewaunee plant in 2005 and entering into the Kewaunee and Fox Energy Center power purchase agreements.
Fuel Costs
WPSC's fuel costs for 2005 and 2004 were:
Coal Supply
Coal is the primary fuel source for WPSC, the majority of which is from the Powder River Basin mines located in Wyoming. This low sulfur coal has been our least-cost coal source from any of the subbituminous coal-producing regions in the United States. WPSC's fuel portfolio strategy is to maintain a 25 to 40 day supply of coal at each plant site.
Historically, WPSC has purchased coal directly from the producer. WPSC purchases coal for its wholly owned plants. Wisconsin Power and Light purchases coal for the jointly owned Edgewater and Columbia plants.
Annual coal requirements for WPSC's wholly owned plants generally range between 3.5 to 4.0 million tons. WPSC's fuel portfolio strategy is to purchase coal through a mix of spot, short-term, mid-term and long-term contracts and maintain a broad base of suppliers and mine sources. The fuel portfolio strategy for is as follows:
WPSC currently contracts for coal transportation for its wholly owned plants under contracts of up to five years duration. WPSC has transportation contracts in place for 90% of its 2006 coal transportation requirements for its wholly owned plants.
Obligations related to coal supply and transportation extending through 2016 total $413.9 million.
For more information on coal supply see Management's Discussion and Analysis - Liquidity and Capital Resources - WPS Resources, Other Future Considerations - Coal Supply.
Natural Gas Supply - Generation
WPSC is committed to provide fuel for the 150 megawatt contracted portion of the Fox Energy Center Side 1, a 300-megawatt natural gas-fired combined cycle generation facility. Once fully constructed, the Fox Energy Center Facility (Side 1 and 2) will have a total combined electric capacity of approximately 600 megawatts. Beginning June 1, 2006, WPSC's electric capacity commitment increases to approximately 500 megawatts. WPSC will be committed to provide fuel for the total contracted electric capacity. In 2005, natural gas supplies were purchased in the spot market. WPSC has a 10-year pipeline transportation contract with ANR Pipeline Company to deliver 50% of the forecasted natural gas needs for the 500 megawatts of contracted electric capacity. WPSC has contracted for a 10-day firm storage service to provide natural gas for supply interruptions during the winter months. The storage service can also provide additional supplies or access for real-time electric dispatches of the facility. Estimated 2006 fuel requirements for WPSC's contracted electric capacity is approximately 11.8 million MMBtus.
In addition, WPSC supplies natural gas through its natural gas distribution system to its 480 megawatts of gas-fired combustion turbine generation facilities.
In 2005, WPSC developed an Energy Market Risk Management Policy to govern its activities in the developing MISO energy market and the PJM electric market. The plan was approved by the PSCW in September 2005.
As part of its market activities, in January 2006, WPSC implemented a plan to reduce its exposure to the volatility of natural gas prices affecting its electric generation. The plan provides for the purchase of financial futures contracts for natural gas and the purchase of financial options on the price of natural gas for a portion of WPSC's forecasted natural gas fuel generation requirements.
For additional information, see Note 17 to WPS Resources' Consolidated Financial Statements - Commitments and Contingencies.
Regulatory Matters
Both the PSCW and MPSC regulate retail electric rates for WPSC. The MPSC regulates retail electric rates for UPPCO. The FERC regulates wholesale electric rates of both utility companies.
On April 1, 2005, the MISO market began operation of its "Day 2" energy market. WPSC and UPPCO are members of MISO. Within the Day 2 market, MISO centrally dispatches wholesale electricity and provides transmission service to an area mainly in the Midwest. MISO determines prices in the market based on a locational marginal pricing system determined by the accepted generation bids and offers and the load to be served by all market participants. The MISO dispatching system has provided for more efficient use of the transmission system to serve our load during outages and times of peak load.
For additional information, see Note 23 to WPS Resources' Consolidated Financial Statements - Regulatory Environment.
Hydroelectric Licenses
WPSC, UPPCO and Wisconsin River Power have long-term licenses from FERC for all of their hydroelectric facilities.
In November 2005, UPPCO announced it had not made a final decision whether to restore Silver Lake as a reservoir for power generation or to forego refilling the reservoir and that more time is needed to study the ramifications of design changes recommended by consultants and FERC. UPPCO will undertake additional studies of the new design recommendations to see if there are alternatives that would make restoring the Silver Lake Dam and refilling the reservoir economically beneficial for its customers. UPPCO expects to make its final decision on Silver Lake in the first half of 2006.
For more information on the Dead River Flooding, see Note 17 - Commitments and Contingencies to our Notes to Consolidated Financial Statements.
Other Matters
Research and Development
The only business segment of WPS Resources that incurred noteworthy research and development costs in 2005 was WPSC's electric operations. Electric research and development expenditures for WPSC totaled $0.7 million for 2005, $0.7 million for 2004 and $0.6 million for 2003. These expenditures were primarily charged to electric operations as incurred.
Customer Segmentation
In 2005, paper production facilities and one wholesale customer (a private utility that primarily provides power to other paper mills) accounted for 15.8% of WPS Resources' regulated electric revenues. There is no single customer, the loss of which would have a material adverse effect on the regulated electric operations of WPS Resources in the current regulatory environment.
Seasonality
The electric sales of WPSC follow a seasonal pattern due to the air conditioning requirements of customers that are primarily impacted by the variability of summer temperatures. Although UPPCO hit its electric peak in December, electric sales at UPPCO follow no significant seasonal trend due to cooler climate conditions in the Upper Peninsula of Michigan.
Generally during the winter months, the purchase price of fuel (natural gas and fuel oil) for heating load and generation production is heavily influenced by weather and the availability of baseload generation units within the MISO energy market. Sustained colder-than-normal weather and unexpected extended generation outages can influence fuel supply and demand, impacting the production costs at WPSC's natural gas and oil-fired facilities, as well as gas supply commitments under power purchase agreements.
Competition
The electric energy market in Wisconsin continues to be regulated by the PSCW. Retail electric customers currently do not have the ability to choose their electric supplier. However, in order to increase sales, utilities work to attract new commercial/industrial customers into their service territory. As a result, there is competition among utilities to keep energy rates low. Wisconsin utilities have continued to refine regulated tariffs in order to provide customers with the true cost of electric energy to each class of customer by reducing or eliminating rate subsidies among different ratepayer classes. Although Wisconsin electric energy markets are regulated, utilities still face competition from other energy sources.
Michigan electric energy markets are open to competition, although a competitive market has not yet developed in the Upper Peninsula of Michigan primarily due to a lack of excess generation and transmission system capacity.
Working Capital Requirements
For information on capital requirements related to WPSC, see Management's Discussion and Analysis of Financial Condition and Results of Operation - Liquidity and Capital Resources - Wisconsin Public Service Corporation.
C. REGULATED NATURAL GAS OPERATIONS
WPSC provides regulated natural gas service to nearly 300 municipalities in northeastern Wisconsin and adjacent portions of Michigan's Upper Peninsula.
Revenues, volumes, customers and plant assets for natural gas operations of WPSC were as follows:
Facilities
For information regarding our natural gas facilities, see Item 2 - Properties in this Annual Report on Form 10-K.
Natural Gas Supply
WPSC manages a portfolio of natural gas supply contracts, storage services and pipeline transportation services designed to meet its varying load pattern at the lowest reasonable cost.
Annual natural gas supply needs for WPSC are estimated at approximately 497 million therms. WPSC contracts for fixed-term firm natural gas supplies with approximately 10 natural gas suppliers each year (in the United States and Canada) to meet the December through February peak day demand of firm system sales customers. To supplement natural gas supplies and minimize risk, WPSC purchases additional natural gas supplies on the monthly spot market through fixed-term firm contracts rather than on the daily spot market. As of December 31, 2005, WPSC's domestic natural gas supply contracts had remaining terms of up to two months and its Canadian natural gas supply contracts had remaining terms of up to three months. WPSC intends to contract for domestic natural gas supplies for terms of two years or less to minimize potential stranded natural gas supply contract costs if retail natural gas deregulation should proceed in Wisconsin.
Under current regulatory practice, the PSCW and the MPSC allow WPSC to pass decreases and prudently incurred increases in the cost of natural gas on to customers on a dollar-for-dollar basis through a purchased gas adjustment clause. Changes in the cost of natural gas are reflected in both gas revenues and gas purchases, thus having little or no impact on net income.
WPSC contracts with ANR Pipeline Company for firm underground natural gas storage capacity located in Michigan and with Nexen and People's Energy Resources Corporation in Illinois. WPSC has approximately 116 million therms of firm natural gas storage capacity in Michigan and approximately 17 million therms of firm natural gas storage capacity in Illinois. Besides providing the ability to manage significant changes in daily natural gas demand, storage also provides WPSC with the ability to purchase natural gas at high load factors on a year-round basis, thus lowering supply cost volatility. In 2005, natural gas from storage provided approximately 62% of WPSC's supply on winter peak days, approximately 32% of its winter sales volumes and approximately 22% of its total annual sales volumes under normal weather conditions. WPSC also contracts with third-party natural gas suppliers for high deliverability storage. This high deliverability storage capacity is designed to deliver natural gas when other supplies cannot be delivered during extremely cold weather in the producing areas, which can temporarily limit wellhead natural gas supplies.
WPSC holds firm long-term transportation capacity contracts on the ANR Pipeline. The majority of these contracts expire in 2010. WPSC also holds firm transportation capacity with Viking Gas Transmission Company to deliver natural gas from its interconnection with TransCanada Pipelines near Emerson, Manitoba to the interconnection of Viking Gas Transmission with ANR Pipeline near Marshfield, Wisconsin. The Canadian natural gas suppliers at Emerson hold firm capacity on TransCanada Pipelines from Emerson back into the Canadian production areas in Alberta, Canada. WPSC contracts with Viking Gas Transmission Company expire in 2010. These contracts provide WPSC sufficient contracted pipeline transportation capacity to fully meet the annual and daily requirements of its customers.
Regulatory Matters
The PSCW and the MPSC regulate WPSC's natural gas retail rates.
For additional information, see Note 23 to WPS Resources' Consolidated Financial Statements - Regulatory Environment.
Other Matters
Customer Segmentation
WPSC has no single customer industry segment that accounts for more than 4% of natural gas revenues. The largest industry segment among WPSC's natural gas customers is the paper industry.
Seasonality
The gas throughput of WPSC follows a seasonal pattern due to the heating requirements of customers that is primarily impacted by the variability in winter temperatures.
Competition
WPSC's natural gas operations face competition with other entities and forms of energy in varying degrees, particularly for large commercial and industrial customers who have the ability to switch between natural gas and alternate fuels. Due to the volatility of natural gas prices, WPSC has seen its customers with dual fuel capability switch to alternate fuels for short periods of time, then switch back to natural gas as market rates change. WPSC offers interruptible natural gas sales and natural gas transportation service for these customers to enable them to reduce their energy costs. Transportation customers purchase their natural gas directly from third-party natural gas suppliers at market prices and contract with WPSC to transport the natural gas from ANR Pipeline to their facilities. Additionally, some customers still purchase their natural gas commodity directly from WPSC, but have elected to do so on an interruptible basis, as a means to reduce their costs. Customers continue to switch between firm system supply, interruptible system supply and transportation service each year as the economics and service options change.
Working Capital Requirements
For information on capital requirements related to WPSC, see Management's Discussion and Analysis of Financial Condition and Results of Operation - Liquidity and Capital Resources - Wisconsin Public Service Corporation.
D. NONREGULATED ENERGY SERVICES
WPS Resources' nonregulated energy services operations are provided through ESI. In 2005, WPS Power Development, Inc. was merged into ESI and all of the former assets of WPS Power Development, Inc. were transferred to a newly formed entity, WPS Power Development, LLC. WPS Power Development, LLC is a wholly owned subsidiary of ESI.
ESI is a diversified, energy supply and services company operating in the retail and wholesale non-regulated energy marketplace providing individualized energy supply options and strategies that allow customers to manage energy needs while capitalizing on opportunities resulting from deregulation. Principal operations of ESI are located in the northeastern quadrant of the United States and adjacent portions of Canada. In addition, ESI has a natural gas supply presence in Alberta, Canada and is establishing electric and natural gas supply operations in Texas.
ESI, through its subsidiaries, owns and operates nonregulated electric generation facilities in the northeastern quadrant of the United States and adjacent portions of Canada.
ESI and several of its subsidiaries (Advantage Energy, Quest Energy, WPS Gas Storage and WPS Energy Services of Canada) market energy products in the retail and wholesale markets. Its retail emphasis is on serving commercial and industrial customers, as well as "aggregated" small commercial and residential customers and standard offer service. Aggregated customers are associations or groups of customers, which have joined together to negotiate purchases of electric or natural gas energy as a larger group. Additionally, ESI markets energy products directly to small end users in deregulated markets.
ESI's wholesale focus is on the execution and optimization of structured contracts with large end-users, regulated local distribution companies, pipelines, storage companies and other nonregulated energy marketing and trading companies. ESI utilizes derivative instruments, including forwards, futures, options and swaps, to manage its exposures within defined risk limits.
Energy revenues, volumes and assets are as follows:
*
and 2003 information has been restated to reflect the integration of PDI and ESI as one business segment.
ESI manages its exposure to market risks in accordance with the limits and approvals established in its risk management and credit policies. The Market Risk Oversight Committee, comprised of cross-functional members of senior management, monitors compliance with these policies.
The 2005 merger of WPS Power Development, Inc. and ESI allows for more efficient management of the market risk associated with its generation facilities and related contracts. ESI focuses on effective economic dispatch and risk management strategies in order to enhance the returns of its generation facilities.
For more information on the trading and risk management activities of ESI see Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operation Introduction, WPS Resources - WPS Energy Services and Market Price Risk Management Activities - WPS Resources.
Facilities
In the second quarter of 2005, the allocated emission allowances associated with the Sunbury generation station, located in Shamokin Dam, Pennsylvania were sold for approximately $110 million to multiple counterparties. The Sunbury plant will be operated in the future when market conditions make operations economical. ESI has emission allowances available for expected operations in 2006. ESI will purchase additional emission allowances as needed to support planned operations. As part of the asset management strategy of WPS Resources, ESI continues to explore opportunities regarding the future of its electric generation and natural gas storage facilities. Opportunities include, but are not limited to sales of certain facilities, joint ventures and long-term contracts. Opportunities change and develop with the dynamics of the markets in which we operate.
ESI owns and operates electric generation facilities in the Midwest and Northeast regions of the United States with a total capacity of approximately 825 megawatts. At December 31, 2005, ESI owned 81.5% of a 3 billion cubic foot natural gas storage field in Kimball, Michigan. In February 2006, ESI acquired the remaining 18.5% ownership interest in the facility. The storage field allows for additional flexibility in supplying natural gas retail and wholesale customers, sale of storage services to the market and potential power generation peaking services.
ESI's Beaver Falls generation facility is currently out of service as a result of damage to its turbine blades. ESI is reviewing its options regarding future operations of the facility.
For additional information regarding generation facilities of ESI, see Item 2 - Properties in this Annual Report on Form 10-K.
Fuel Supply
ESI's fuel inventory policy varies for each generation facility depending on the type of fuel used and available storage facilities. ESI's merchant generation facilities (excluding its gas-fired plants) historically, burn in excess of 1.5 million tons of solid fuel annually. Fuel for these facilities includes coal, fluid coke, tire-derived fuel and wood. The majority of these needs will be met through the burning of coal products, including bituminous coal, culm, silt and fluid coke (a petroleum product). Actual fuel needs in 2006 will depend on market conditions and operational capability of these facilities.
The Sunbury facility's inventory policy is to have a 20 to 30 day coal supply on site. ESI has coal supply under contract for all Sunbury committed generation. Fuel needs for any additional generation will be purchased on the spot market. ESI also has sufficient transportation services under contract for all of 2006.
The Niagara facility maintains an eight-day fuel inventory on site, with additional inventory maintained off site. Currently all fuel needs are purchased in the spot market with no long-term fuel contracts in effect.
ESI's Westwood facility burns waste coal left behind by mining operations and has several years supply on site. All fuel is located within a seven-mile radius of the plant.
The Stoneman facility currently has all of its 2006 coal needs under contract with options for 2007 fuel needs.
ESI provides all natural gas supply for the natural gas-fired facilities in Beaver Falls, Syracuse and Combined Locks and currently has adequate transport and supply arrangements for projected 2006 needs.
Licenses
ESI is a FERC licensed power marketer with import/export authorization through the DOE. ESI and certain of its subsidiaries are registered to sell retail electric service in various states including Illinois, Maine, Massachusetts, Michigan, New York, Ohio, Pennsylvania, Rhode Island, and Virginia in the United States and the province of Ontario in Canada. In December 2005, ESI began to develop a presence in the retail electricity market in Texas and expects to be operational before the end of the second quarter of 2006.
ESI is registered to sell natural gas in various states including Illinois, Iowa, Michigan, Ohio, Pennsylvania, New York and Alberta Canada. ESI also sells natural gas in Wisconsin where no license is required. ESI's subsidiary, WPS Energy Services of Canada, is registered in the Canadian provinces of Alberta, British Columbia, Manitoba, Nova Scotia, Ontario, Quebec and Saskatchewan. ESI is also a member of the following regional transmission operators and North American Electric Reliability Council reliability regions:
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Independent Electricity System Operator (located in Ontario);
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Electric Reliability Council of Texas (application pending);
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ISO New England;
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MISO;
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New Brunswick System Operator;
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Northern Maine Independent System Administrator;
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New York Independent System Operator; and
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PJM Interconnection.
Beginning January 1, 2001 and extending to December 31, 2005, Ohio established an electric market development period, after which rates would be set at market-based prices. During this market development period, ESI contracted to be the supplier for approximately 100,000 residential, small commercial and government facilities in the FirstEnergy service areas under the State of Ohio provisions for Opt-out Electric Aggregation Programs.
The Public Utilities Commission of Ohio and FirstEnergy established electric rates for consumers beginning in 2006 because a competitive bid auction ordered by the Public Utilities Commission of Ohio did not produce better benefits. Because the FirstEnergy plan is priced lower than current market power prices, ESI discontinued service to customers of the existing aggregation programs after the expiration of these contracts in December 2005.
The Ohio legislature continues to work on the development of a statewide energy policy. If the regulatory climate and market change ESI may re-enter the electric power market in Ohio.
ESI, through its Michigan subsidiary, has established itself as a significant supplier to the industrial and commercial markets under the Electric Choice program in Michigan. Recent high wholesale energy prices, coupled with approved and pending tariff changes for the Michigan regulated utilities, have significantly lowered the savings customers can obtain from contracting with non-utility suppliers. As a result, many customers have returned to the bundled tariff service of the resident utility. This has caused the Michigan retail electric business at the beginning of 2006 to decline to one-third of what it was at the start of 2005. Future orders of the MPSC should clarify the outlook for Electric Choice. The impact on ESI could range from maintaining Michigan business with little or no growth to an inability to re-contract any business, leading to a possible decision by ESI to exit Michigan's electric market and redirect resources to other markets.
For more information on the legislative activity in Michigan and Ohio and its impact on ESI, see the discussion on Industry Restructuring in Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operation.
All the FERC hydroelectric facility licenses held by ESI subsidiaries are current. The 33-megawatt hydroelectric facility owned in New Brunswick, Canada, is not subject to licensing.
Other Matters
Customer Segmentation
Although ESI is not dependent on any one customer, a significant percentage of its retail sales volume is derived from industries related to:
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Paper and allied products;
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Food and kindred products;
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Chemicals and paint; and
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Steel and foundries.
ESI's concentration of sales in any single market sector is decreasing as it expands into the Texas and northeast United States retail electric markets and eastern Canada retail natural gas markets.
Seasonality
ESI believes that its business, in the aggregate, is not seasonal, even though certain products sell more heavily in some seasons than in others. Sales of natural gas generally peak in the winter months, while sales of electric energy generally peak in the summer months. Generally in the summer months, the demand for electric energy is high, which increases the price at which energy can be sold. In periods of high residential fuel consumption, (generally the winter months) the purchase price of oil and natural gas increases, which increases the production costs at ESI's gas- and oil-fired generation facilities. ESI's business is volatile as a result of market conditions and the related market opportunities available to its customers.
Competition
ESI is a nonregulated energy marketer that competes against regulated utilities, large energy trading companies and other energy marketers. ESI competes with other energy providers on the basis of price, reliability, service, financial strength, consumer convenience, performance and reputation. The nonregulated energy market has seen a decrease in the number of large energy providers and there continues to be consolidation of small energy marketers. The liquidity in the nonregulated energy market continues to improve with the increase of well-capitalized wholesale market participants. Although this increases competition, it also allows ESI to operate more efficiently.
Working Capital
Currently, capital requirements of ESI are provided through equity infusions, long-term debt and short-term debt by its parent company, WPS Resources. The working capital needs of ESI vary significantly over time due to volatility in commodity prices (including margin calls), levels of natural gas inventories, the structure of wholesale transactions, the price of natural gas and alternative energy opportunities available to its customers. WPS Resources provides guarantees for ESI's supply contracts. These guarantees provide the financial strength needed to participate in the nonregulated energy market.
See Management's Discussion and Analysis of Financial Condition and Results of Operation for additional information regarding working capital needs of nonregulated operations.
E. ENVIRONMENTAL MATTERS
For information on environmental matters related to WPS Resources and any of its subsidiaries, see Note 17 - Commitments and Contingencies to our Notes to Consolidated Financial Statements.
F. CAPITAL REQUIREMENTS
For information on capital requirements related to WPS Resources, see Management's Discussion and Analysis of Financial Condition and Results of Operation - Liquidity and Capital Resources - WPS Resources.
For information on capital requirements related to WPSC, see Management's Discussion and Analysis of Financial Condition and Results of Operation - Liquidity and Capital Resources - Wisconsin Public Service Corporation.
G. EMPLOYEES
At December 31, 2005, WPS Resources and its subsidiaries had the following employees:
Local 310 of the International Union of Operating Engineers represents 1,087 WPSC employees. The current Local 310 collective bargaining agreement expires on October 21, 2006.
Local 510 of the International Brotherhood of Electrical Workers, AFL-CIO, represents 126 UPPCO employees. The current Local 510 collective bargaining agreement expires on April 19, 2008.
Local 1600 of the International Brotherhood of Electrical Workers, AFL CIO, represents approximately 93 employees at the Sunbury generation station. The current collective bargaining agreement with Local 1600 expired on May 10, 2005. ESI delivered a final offer on September 7, 2005. On January 27, 2006, ESI declared an impasse in negotiations. Local 1600 is currently deciding whether to bring ESI's final offer to a vote. ESI and Local 1600 continue to operate under the existing labor agreement.
H. Available Information
WPS Resources and WPSC file with the SEC:
·
Annual Reports on Form 10-K;
·
Quarterly Reports on Form 10-Q;
·
WPS Resources proxy statements;
·
Registration statements, including prospectuses;
·
Current Reports on Form 8-K; and
·
Any amendments to these documents.
WPS Resources and WPSC make these reports available free of charge, on WPS Resources' Internet Web site, as soon as reasonably practicable after they are filed with the SEC. WPS Resources' Internet address is www.wpsr.com. Statements and amendments posted on WPS Resources' Web site do not include access to exhibits and supplemental schedules electronically filed with the reports or amendments. WPS Resources and WPSC are not including the information contained on or available through their Web sites as a part of, or incorporating such information by reference into, this Annual Report on Form 10-K.
You may also obtain materials filed with the SEC by WPS Resources and WPSC at the SEC Public Reference Room at 100 F Street, N.E., Washington, DC 20549. To obtain information on the operation of the Public Reference Room, you may call 1-800-SEC-0330. You may also view reports, proxy statements and other information regarding WPS Resources and WPSC (including exhibits), filed with the SEC, at their Web site at www.sec.gov.
ITEM 1A.
ITEM 1A. RISK FACTORS
You should carefully consider the following risk factors, as well as the other information included or incorporated by reference in this Annual Report on Form 10-K, when making an investment decision. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties not presently known or that we currently believe to be immaterial may also adversely affect us.
We may not successfully integrate pending or future acquisitions into our operations or otherwise achieve the anticipated benefits of those acquisitions.
As part of our growth strategy, we continue to pursue a disciplined acquisition strategy. While we expect to identify cost savings and growth opportunities before we acquire companies or assets, we may not be able to achieve these anticipated benefits due to, among other things:
·
Delays or difficulties in completing the integration of acquired companies or assets;
·
Higher than expected costs or a need to allocate additional resources to manage unexpected operating difficulties;
·
Parameters imposed or delays caused by regulatory agencies;
·
Reliance on inaccurate assumptions in evaluating the expected benefits of a given acquisition;
·
Inability to retain key employees or customers of acquired companies; and
·
Assumption of liabilities not identified in the due diligence process.
These risks apply to our pending acquisition of Aquila's Michigan and Minnesota natural gas distribution operations.
We may not complete construction projects within estimated project costs.
WPSC is currently in the process of constructing the 500-megawatt Weston 4 base-load generation facility at an estimated cost of $779 million (including the coal trains). WPSC will be responsible for 70% of these costs. WPSC is also considering the possible construction of additional generation facilities in the future. These and other projects also may be subject to joint ownership or operation agreements, completion of which will impact estimated project costs.
These are very large and complex construction projects, subject to numerous unpredictable events that could affect our ability to timely complete construction of these projects within estimated costs. We may not be able to meet these construction estimates due to, among other things:
·
Fluctuating or unanticipated construction costs;
·
Supply delays;
·
Legal claims; and
·
Environmental regulation.
We may not utilize Section 29 synthetic fuel production tax credits.
We have significantly reduced our consolidated federal income tax liability for the past several years through tax credits available to us under Section 29 of the Internal Revenue Code for the production and sale of solid synthetic fuel from coal. We have not fully utilized Section 29 tax credits previously available to us. Our ability to fully utilize the Section 29 tax credits available to us in connection with our interest in the production facility will depend on whether the amount of our federal taxable income and related income tax liability is sufficient to permit the use of such credits. The Internal Revenue Service strictly enforces compliance with all of the technical requirements of Section 29. Section 29 tax credits are currently scheduled to expire at the end of 2007.
Any disallowance of some or all of those tax credits could materially affect our tax obligations and may also result in a reduction of the level of synthetic fuel production at the facility, thus reducing the likelihood and amount of future payments from other participants in the project. Future tax legislation and Internal
Revenue Service review may also affect the value of the credits and of our share of the facility. At this time, we cannot predict the potential for or the outcome of any Internal Revenue Service review.
We may not earn Section 29 synthetic fuel production tax credits or match related hedge earnings to production due to increasing oil prices.
The Internal Revenue Code provides Section 29 tax credits based on the price of crude oil. As the price of oil rises above certain thresholds, the allowable tax credit decreases. If the price of oil rises high enough, the credit is eliminated. In order to manage exposure to the risk that an increase in oil prices could reduce or eliminate the recognizable amount of Section 29 credits, ESI has entered into a series of derivative contracts (options) covering a specified number of barrels of oil. These derivatives mitigate Section 29 tax credit exposure related to rising oil prices in 2006 (95% hedged) and 2007 (40% hedged). However, the accounting period in which gains on these hedge agreements are recognized may not coincide with the accounting period projected for recognition of tax credits. As a result, if the price of oil rises above the Internal Revenue Code thresholds, income may be recognized in periods other than the period for which the Section 29 tax credits are projected.
Our operations are subject to risks beyond our control, including but not limited to weather, terrorist attacks or related acts of war.
Our revenues are affected by the demand for electricity and natural gas. That demand can vary greatly based upon:
·
Weather conditions, seasonality and temperature extremes;
·
Fluctuations in economic activity and growth in our regulated service areas, as well as Texas, the northeast quadrant of the United States and adjacent portion of Canada; and
·
The amount of additional energy available from current or new competitors.
Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities.
In addition, the cost of repairing damage to our facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events, in excess of reserves established for such repairs, may adversely impact our results of operations, financial condition and cash flows. The occurrence or risk of occurrence of future terrorist activity and the high cost or potential unavailability of insurance to cover such terrorist activity may impact our results of operations and financial condition in unpredictable ways. These actions could also result in disruptions of power and fuel markets. In addition, our natural gas distribution system and pipelines could be directly or indirectly harmed by future terrorist activity.
Costs of environmental compliance, liabilities, fines, penalties and litigation could exceed our estimates.
Compliance with current and future federal and state environmental laws and regulations may result in increased capital, operating and other costs, including remediation and containment expenses and monitoring obligations. Management cannot predict with certainty the amount and timing of all future expenditures (including the potential or magnitude of fines or penalties) related to environmental matters because of the difficulty of estimating clean-up and compliance costs and the possibility that changes will be made to the current environmental laws and regulations. Any future changes in the interpretation of the Clean Air Act's New Source Review provisions could potentially increase our operating and maintenance costs substantially.
On March 15, 2005, the EPA adopted the Clean Air Mercury Rule, which is intended to reduce mercury emissions from coal-fired generation plants. The EPA has also issued the Clean Air Interstate Rule requiring reductions of sulfur dioxide and nitrogen oxide emissions. In addition, the possibility exists of future regulation of greenhouse gases emitted from generation facilities. We cannot be certain how these rules will affect us. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liabilities on all potentially responsible parties.
Citizen groups that feel there are compliance issues not sufficiently enforced by environmental regulatory agencies may bring citizen enforcement actions against us. Such actions could seek penalties, injunctive relief and costs of litigation. The Sierra Club, Inc. and Clean Wisconsin, Inc. recently filed a complaint in the United States District Court, Eastern District of Wisconsin, claiming that WPSC's Pulliam facility violated provisions of its air permit.
On November 15, 2004, the Sierra Club filed a petition with the WDNR under Section 285.61, Wis. Stats. seeking a contested case hearing on the air permit issued for the Weston 4 generation station. In February 2006, the Administrative Law Judge affirmed the Weston 4 air permit with modifications to the emission limits for sulfur dioxide and nitrogen oxide from the coal-fired boiler and particulate from the cooling tower. The modifications set limits that are more stringent than those set by the WDNR. WPS Resources is currently evaluating the impact this decision may have on future operating costs.
Any change in our ability to sell electricity generated from our nonregulated facilities at market-based rates may impact earnings.
The FERC has authorized us to sell generation from our nonregulated facilities at market prices. The FERC retains the authority to modify or withdraw our market based rate authority. If the FERC determines that the market is not workably competitive, that we possess market power or that we are not charging just and reasonable rates, it may require our nonregulated subsidiaries to sell power at a price based upon the costs incurred in producing the power. Our revenues and profit margins may be negatively affected by any reduction by the FERC of the rates we may receive.
Fluctuating commodity prices may reduce regulated and nonregulated energy margins.
Our regulated energy margins are directly affected by commodity costs related to coal, natural gas and other fuels used in the electric generation process. The commodity price of market purchases of electricity also directly affects our regulated energy margins.
Higher commodity prices increase energy prices and may impact customer demand for energy in the nonregulated market and increase counterparty risk. This may stress margins at our nonregulated subsidiaries.
ESI may experience increased expenses, including interest costs and uncollectibles, higher working capital requirements and possibly some reduction in volumes sold as a result of any increase in the cost of fuel or purchased power. If market prices for electric energy decline below the cost of production at our nonregulated facilities, these units may be temporarily shut down and alternative sources of energy found to meet energy commitments.
We are subject to changes in government regulation, which may have a negative impact on our business, financial position and results of operations.
We are subject to comprehensive regulation by several federal and state regulatory agencies, which significantly influences our operating environment and may affect our ability to recover costs from utility customers. In particular, the PSCW, MPSC, FERC, SEC, EPA and the WDNR regulate many aspects of our utility operations, including siting and construction of facilities, conditions of service, the issuance of securities and the rates that we can charge customers. We are required to have numerous permits, approvals and certificates from these agencies to operate our business. Our acquisition of Aquila's natural gas distribution operations in Minnesota is subject to the approval of the regulatory commission in the state.
The rates our regulated utilities are allowed to charge for their retail and wholesale services are some of the most important items influencing our business, financial position, results of operations and liquidity.
We are unable to predict the impact on our business and operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations may
require us to incur additional expenses or change business operations, which may have an adverse impact on our results of operations. In addition, federal regulatory reforms may produce unexpected changes and costs in the public utility industry.
A reduction in our credit ratings could materially and adversely affect our business, financial position, results of operations and liquidity.
We cannot be sure that any of our credit ratings will remain in effect for any given period of time or that a credit rating will not be lowered by a rating agency if, in its judgment, circumstances in the future so warrant. Any downgrade could:
·
Increase our borrowing costs;
·
Require us to pay a higher interest rate in future financings and possibly reduce the potential pool of creditors;
·
Increase our borrowing costs under certain of our existing credit facilities;
·
Limit our access to the commercial paper market; and
·
Limit the availability of adequate credit support for ESI's operations.
Actual results could differ from estimates used to prepare our financial statements.
In preparing the financial statements in accordance with generally accepted accounting principles, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex and actual results could differ from those estimates. For more information about these estimates and assumptions, see ''Management's Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies'' in this Annual Report on Form 10-K.
The use of derivative instruments could result in financial losses and liquidity constraints.
We use derivative instruments, including futures, forwards, options and swaps, to manage our commodity and financial market risks. In addition, we purchase and sell commodity-based contracts in the natural gas and electric energy markets for trading purposes. In the future, we could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these contracts involves management's judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts. Additionally, realized values could differ from values determined by management.
For additional information concerning derivatives and commodity-based trading contracts, see Note 3 - Risk Management Activities in this Annual Report on Form 10-K.
We are subject to provisions that can limit merger and acquisition opportunities for our shareholders.
The Wisconsin Public Utility Holding Company Law 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 consumers, investors and the public. Those interests may, to some extent, be mutually exclusive. This provision and other requirements of the Wisconsin Public Utility Holding Company Law may delay, or reduce the likelihood of, a sale or change of control thus reducing the likelihood that shareholders will receive a takeover premium for their shares.
Provisions of our articles of incorporation and bylaws may delay or frustrate the removal of incumbent directors and may prevent or delay a merger, tender offer or proxy contest involving our company that is not approved by our board of directors, even if the shareholders believe that such events may be beneficial to their interests. In addition, our shareholder rights plan may have anti-takeover effects by
delaying, deferring or preventing an unsolicited acquisition proposal not approved by our board of directors, even if the shareholders believe that the proposal may be beneficial to their interests. Further, the Wisconsin Business Corporation Law contains provisions that may have the effect of delaying or making more difficult attempts by others to obtain control of our company without the approval of our board of directors.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
A. REGULATED
Wisconsin Public Service Facilities
The following table summarizes information on the electric generation facilities of WPSC, including owned or jointly owned facilities as of December 31, 2005:
(a)
Based on capacity ratings for July 2006. As a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand, the summer period is the most relevant for capacity planning purposes.
(b)
These facilities are jointly owned by WPSC and various other utilities. Wisconsin Power and Light Company operates the Columbia and Edgewater units. Wisconsin River Power Company operates the Castle Rock, Petenwell and Juneau units. WPSC and Marshfield Electric and Water Department jointly own West Marinette 33. WPSC is the operator of this facility. The capacity indicated is our portion of total plant capacity based on the percent of ownership.
As of December 31, 2005, WPSC owned 123 distribution substations and 21,029 miles of electric distribution lines. Effective January 1, 2001, all transmission property of WPSC was transferred to ATC.
Natural gas properties include approximately 7,579 miles of main, 86 gate and city regulator stations and 287,104 lateral services. All natural gas facilities are located in Wisconsin except for distribution facilities in and near the City of Menominee, Michigan.
Substantially all of WPSC's utility plant is subject to a first mortgage lien.
Upper Peninsula Power Facilities
The following table summarizes information on the electric generation facilities of UPPCO as of December 31, 2005:
(a)
Based on July 2006 rated capacity.
(b)
The J. H. Warden station was taken out of service on January 1, 1994. The facility was put into service for a short period after the Dead River Flood in 2003 and is now once again in standby or inactive reserve status.
UPPCO owns 3,070 miles of electric distribution lines.
Effective June 28, 2001, all transmission property of UPPCO was transferred to ATC.
Substantially all of UPPCO's utility plant is subject to a first mortgage lien.
B. NONREGULATED
WPS Resources Corporation
Asset Management Strategy
WPS Resources' asset management strategy includes the continual evaluation of all properties and businesses held by WPS Resources to identify their best use. WPS Resources will evaluate whether the best use of the property or business is in current operations or if sale and reinvestment of proceeds is in the best interest of WPS Resources, its shareholders and customers.
As part of this strategy, in December 2005, UPPCO sold 1,366 acres of land along the Bond Falls Reservoir, Boney Falls Basin and Cataract Basin, which were no longer needed for operations of UPPCO. The property was sold for approximately $5.9 million and up to an additional $3 million pending the removal of certain contingencies.
WPS Resources had originally identified approximately 7,300 acres of excess land associated with its UPPCO hydroelectric facilities. UPPCO is currently working with various interested parties to develop a sales strategy for more of these properties.
WPS Energy Services Natural Gas Facilities
At December 31, 2005,ESI owned an 81.5% interest in a 3 billion cubic foot natural gas storage field in Kimball, Michigan. In 2006, ESI acquired the remaining 18.5% interest in the facility.
WPS Energy Services Generation Facilities
The following table summarizes information on the electric generation facilities owned by ESI, including jointly owned facilities as of December 31, 2005:
(a)
Based on summer rated capacity.
(b)
Caribou Steam Unit 1 was reactivated on December 12, 2005 at 9-megawatts. Caribou Steam Unit 2 was reactivated on January 6, 2006 (not included above) for a total (Units 1 and 2) of 21.7-megawatts.
(c)
ESI owns a 3.3455% interest in the Wyman plant. The plant is a 610-megawatt oil-fired facility operated by a subsidiary of FPL Group, Inc.
(d)
ESI also has an additional five megawatts of capacity available at this facility through the lease of an additional steam turbine.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
For information on material legal proceedings and matters related to WPS Resources and its subsidiaries, see Note 17 - Commitments and Contingencies to WPS Resources' Notes to Consolidated Financial Statements.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the security holders of either WPS Resources or WPSC during the fourth quarter of 2005.
ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANTS
*
Prior to joining WPS Resources, Joseph P. O'Leary's responsibilities at United Stationers included leading the finance, treasury and accounting functions. United Stationers was the largest provider of wholesale business office products in North America.
NOTE:
All ages are as of December 31, 2005. None of the executives listed above are related by blood, marriage, or adoption to any of the other officers listed or to any director of the Registrants. Each officer holds office until his or her successor has been duly elected and qualified, or until his or her death, resignation, disqualification, or removal.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANTS' COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
WPS Resources Corporation Common Stock Two-Year Comparison
WPS Resources common stock is traded on the New York Stock Exchange under the ticker symbol "WPS." WPS Resources is the sole holder of WPSC's common stock.
Dividend Restrictions
For information on dividend restrictions related to WPS Resources and any of its subsidiaries, see Note 21 - Common Equity to WPS Resources' Notes to Consolidated Financial Statements.
Common Stock
Listed:
New York Stock Exchange
Ticker Symbol:
WPS
Transfer Agent and Registrar:
American Stock Transfer & Trust Company
Maiden Lane
New York, NY
As of February 21, 2006, there were 20,626 common stock shareholders of record.
See Item 11 of this Annual Report on Form 10-K for information regarding our equity compensation plans.
ITEM 7.
ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION - WPS RESOURCES
WPS Resources is a holding company. Our wholly owned subsidiaries include two regulated utilities, WPSC and UPPCO. Another wholly owned subsidiary, WPS Resources Capital Corporation, is a holding company for our nonregulated ESI subsidiary.
Our regulated and nonregulated businesses have distinct competencies and business strategies, offer differing energy and energy related products and services, experience a wide array of risks and challenges, and are viewed uniquely by management. The following summary provides a strategic overview and insight into the operations of our subsidiaries.
Strategic Overview
The focal point of WPS Resources' business plan is the creation of long-term value for our shareholders through growth, operational excellence, asset management, and risk management and the continued emphasis on reliable, competitively priced, and environmentally sound energy and energy related services for our customers. We are seeking growth of our regulated and nonregulated portfolio and placing an emphasis on regulated growth. A discussion of the essential components of our business plan is set forth below:
Maintain and Grow a Strong Regulated Utility Base - We are focusing on growth in our regulated operations. A strong regulated utility base is important in order to maintain a strong balance sheet, more predictable cash flows, a desired risk profile, attractive dividends, and quality credit ratings, which are critical to our success. WPS Resources believes the following recent developments have helped, or will help maintain and grow its regulated utility base:
·
WPSC is expanding its regulated generation fleet in order to meet growing electric demand and ensure continued reliability. Construction of the 500-megawatt coal-fired Weston 4 base-load power plant near Wausau, Wisconsin, is underway, in partnership with DPC. Commercial operation is expected in 2008. WPSC continues to pursue plans to construct other electric generating facilities and will determine the details relating to fuel type and in-service dates in the future.
·
In September 2005, WPS Resources entered into a definitive agreement with Aquila to acquire its natural gas distribution operations in Michigan and Minnesota. The addition of regulated assets in complementary vicinities to WPS Resources' existing regulated electric and natural gas operations in Wisconsin and Michigan will transition WPS Resources to a larger and stronger regional energy company. MPSC approval has already been received for the acquisition of the gas distribution operations in Michigan, while the regulatory process required for approval of the acquisition of the Minnesota operations is progressing on schedule. We expect to complete both transactions in the first half of 2006.
·
At December 31, 2005, WPS Resources owned 31.0% of ATC, which is a utility operation that owns, builds, maintains, and operates high voltage electric transmission lines primarily in Wisconsin and Upper Michigan. We continue to increase our ownership interest in ATC through additional equity interest received as consideration for funding a portion of the Duluth, Minnesota, to Wausau, Wisconsin, transmission line.
·
WPSC continues to invest in environmental projects to improve air quality and meet the requirements set by environmental regulators. Capital projects to construct and upgrade equipment to meet or exceed required environmental standards are planned each year. Throughout the 2006 to 2008 time period, WPSC expects to invest approximately $167 million in various environmental projects.
·
In 2006, WPSC entered into a natural gas transportation precedent agreement with Guardian Pipeline, LLC. The agreement is subject to various approvals, including approvals by WPS Resources' and Guardian's Boards of Directors as well as approval by the PSCW and the FERC. The agreement is also contingent upon Guardian Pipeline obtaining financing. To meet the requirements of the agreement, Guardian Pipeline will expand its current pipeline approximately 106 miles in Wisconsin.
Integrate Resources to Provide Operational Excellence - WPS Resources is committed to integrating resources of its regulated business units and also its nonregulated business units, while maintaining any and all applicable regulatory restrictions, in order to leverage the individual capabilities and expertise of each unit to provide the best value to all customers.
·
This strategy is demonstrated by the integration of resources at our nonregulated subsidiaries. We started the integration by first implementing tolling agreements to move the market management of our plants to our portfolio management group, reducing our merchant generation market risk. Then we restructured the management teams of ESI and PDI so that one team oversees all the operations of our nonregulated businesses.
·
This strategy will also be demonstrated in our regulated business by optimally sourcing work and combining resources to achieve best practices of WPSC and the natural gas distribution operations in Michigan and Minnesota (expected to be acquired in the first half of 2006), operational excellence, and sustainable value for customers and shareholders.
Strategically Grow Nonregulated Businesses - ESI will grow its electric and natural gas business (through strategic acquisitions, market penetration by existing businesses, and new product offerings) by targeting growth in areas where it has the most market expertise and through "strategic hiring" in other areas. ESI also focuses on optimizing the operational efficiency of its existing portfolio of assets and pursues compatible development projects that strategically fit with its customer base and market expertise.
·
The acquisition of Advantage Energy in July 2004 provided ESI with enhanced opportunities to compete in the New York market and had a positive impact on ESI's margin in 2005. In 2005, ESI expanded Advantage Energy's customer base, and began introducing natural gas products to these customers. The increase in Advantage Energy's customer base was aided by expanding its product offering, including offering both fixed and variable priced products. Prior to ESI's acquisition of Advantage Energy, only variable priced products were offered.
·
In the third quarter of 2005, ESI began offering retail electric products primarily to large commercial and industrial customers in Illinois. Previously, ESI was only offering natural gas products and energy management services to customers in Illinois.
·
In the fourth quarter of 2005, ESI began developing a product offering in the Texas retail electric market. Due to the thriving Texas market structure (unencumbered by a regulated offering that is not market based) and having been presented with a good opportunity and approach to enter the Texas retail market, ESI hired experienced personnel in that region and expects to be an approved competitive supplier before the end of the second quarter of 2006. ESI previously had a market presence in Houston with natural gas producer services originators. While historically, ESI limited its retail activities to the northeastern quadrant of the United States and adjacent portion of Canada, the entry into the Texas market offers an opportunity to leverage the infrastructure and capability ESI developed to provide products and services that it believes customers will value.
·
ESI began marketing electric products to customers in Massachusetts in 2005 and has had initial success in signing up commercial and industrial customers.
Place Strong Emphasis on Asset and Risk Management - One aspect of our asset management strategy calls for the continuing acquisition of assets that complement our existing business and strategy. The utilities are the backbone of our earnings. We expect ESI to provide between 20 and 30 percent of our earnings in the future. Another aspect of this strategy calls for the disposition of assets, including plants and entire business units, which are either no longer strategic to ongoing operations or would
reduce our risk profile. The risk management portion of this strategy includes the management of market, credit and operational risk through the normal course of business.
·
The pending acquisitions of Aquila's natural gas distribution operations in Michigan and Minnesota will transition WPS Resources to a larger and stronger regional energy company.
·
The sale of Sunbury's allocated emission allowances was completed in May 2005 for $109.9 million. The proceeds received from the sale enabled Sunbury to eliminate its non-recourse debt obligation, which provides greater flexibility as ESI evaluates its options related to Sunbury. These options range from closing the plant, operating the plant only during favorable economic periods, to a future sale.
·
We also sold WPSC's 59% interest in the Kewaunee plant in July 2005. The major benefits of the Kewaunee sale include transferring financial risk from WPSC's electric customers and WPS Resources' shareholders to Dominion, greater certainty of future energy costs through a fixed price power purchase agreement, and being able to return the non-qualified decommissioning funds to our customers.
·
In the fourth quarter of 2005, WPSC sold a 30% interest in the Weston 4 power plant to DPC. The sale of a portion of this plant reduces construction risk associated with the project, considering its magnitude, and reduces WPSC's funding requirements. Jointly owned plants also reduce the risk profile of WPS Resources.
·
In December 2005, UPPCO sold a portion of real estate no longer needed for operations. The gains from the sale of UPPCO's real estate assets will be shared between customers and shareholders as approved by the MPSC. We continue to evaluate alternatives for the sale of the balance of our identified real estate holdings no longer needed for operation.
·
Forward purchases and sales of electric capacity, energy, natural gas, and other commodities allow for opportunities to secure prices in a volatile price market.
·
An initiative we call "Competitive Excellence" is being deployed across our entire company. Competitive Excellence strives to eliminate work that does not provide value for our customers. This creates more efficient processes, improves the effectiveness of employees, and reduces costs.
Regulated Utilities
Our regulated utilities include WPSC and UPPCO. WPSC derives its revenues primarily from the purchase, production, distribution, and sale of electricity, and the purchase, distribution, and sale of natural gas to retail customers in a service area of approximately 11,000 square miles in northeastern Wisconsin and an adjacent portion of the Upper Peninsula of Michigan. The PSCW and the MPSC regulate these retail sales. UPPCO derives revenues from the purchase, production, distribution, and sale of electricity in a service area of approximately 4,500 square miles in the Upper Peninsula of Michigan and is regulated by the MPSC. WPSC and UPPCO both provide wholesale electric service to numerous utilities and cooperatives for resale. FERC regulates wholesale sales.
The regulatory commissions allow the utilities to earn a return on common stock equity that is commensurate with an investor's expected return, compensating for the risks investors face when providing funds to the utility. The return on common stock equity approved by the PSCW, the FERC, and the MPSC was 11.5%, 11.0%, and 11.4%, respectively, in 2005 and 12.0%, 11.0%, and 11.4%, respectively, in 2004. The utilities bear volume risk as rates are based upon normal sales volumes as projected by the utility. Historically, consumers bear most of the price risk for fuel and purchased power costs as our regulators typically have allowed the utilities to recover most of these costs (to the extent they are prudently incurred), through various cost recovery mechanisms. However, the electric utility is exposed to the risk of not recovering increased fuel costs for Wisconsin retail customers under the current electric fuel recovery rules. Under the Wisconsin fuel recovery mechanism, certain costs are only recoverable on a pro rata basis for the portion of the year after PSCW approval. As such, the ability of our regulated utilities to earn their approved return on equity is dependent upon accurate forecasting, the ability to obtain timely rate increases to account for rising cost structures (while minimizing the required rate increases in order to maintain the competitiveness of our core industrial customer base and keep these customers in our service area), and certain conditions that are outside of their control (such as macroeconomic factors and weather conditions). To mitigate the risk of unrecoverable fuel costs in
due to market price volatility, WPSC is employing risk management techniques pursuant to its risk policy approved by the PSCW, including the use of derivative instruments such as futures and options.
On April 1, 2005, MISO, of which WPSC and UPPCO are members, began operation of its "Day 2" energy market. Within the Day 2 market, MISO centrally dispatches wholesale electricity and provides transmission service to an area mainly in the Midwest. MISO determines prices in the market based on a locational marginal pricing system determined by accepted generation bids and offers and the load to be served by market participants. The introduction of the MISO Day 2 market has shown positive results in that the system allows a more efficient use of the transmission system. In addition to this, the MISO Day 2 market may provide increased opportunities to reduce our generation costs and regulatory risks due to the changes in the regulatory environment explained above. See "Other Future Considerations" in "Liquidity and Capital Resources" below for more information related to MISO.
Uncertainties related to the restructuring of the regulated environment are a risk for our regulated utilities. The restructuring of natural gas service has begun in Wisconsin. Currently, some of the largest natural gas customers are purchasing natural gas from suppliers other than their local utility. Efforts are underway to make it easier for smaller natural gas customers to do the same. Restructuring of electric regulation inside Wisconsin is not currently being pursued. The state is focused on improving reliability by building more generation and transmission facilities and creating fair market rules. Restructuring of electric regulation is present in Michigan. In the Upper Peninsula of Michigan, no customers have chosen an alternative electric supplier and few alternative electric suppliers have offered to serve any customers in Michigan's Upper Peninsula due to lack of transmission access and generating capacity in the areas we serve, which represents a barrier to competitive suppliers entering the market.
We have little or no control over some construction risks associated with projects that can negatively affect completion time and project costs. These risks include, but are not limited to, the shortage of or inability to obtain labor or materials, unfavorable weather conditions, events in the economy, and changes in applicable laws or regulations.
ESI
ESI offers nonregulated natural gas, electric, and alternate fuel supplies, as well as energy management and consulting services, to retail and wholesale customers primarily in the northeastern quadrant of the United States and adjacent portions of Canada. As discussed above, ESI is also developing a product offering in the Texas retail electric market. Although ESI has a wide array of products and services, revenues are primarily derived through sales of electricity and natural gas to retail and wholesale customers.
ESI's marketing and trading operations manage power and natural gas procurement as an integrated portfolio with its retail and wholesale sales commitments and sales of generation from power plants. ESI strives to maintain a low risk portfolio, balancing natural gas and electricity purchase commitments with corresponding sales commitments. In 2005, ESI purchased electricity required to fulfill these sales commitments primarily from independent generators, energy marketers, and organized electric power markets. ESI purchased natural gas from a variety of producers and suppliers under daily, monthly, seasonal, and long-term contracts, with pricing delivery and volume schedules to accommodate customer requirements. ESI's customers include utilities, municipalities, cooperatives, commercial and industrial consumers, aggregators, and other marketing and retail entities. ESI uses derivative financial instruments to provide flexible pricing to customers and suppliers, manage purchase and sales commitments, and reduce exposure relative to volatile market prices.
ESI also owns several merchant electric generation plants, primarily in the Midwest and northeastern United States and adjacent portions of Canada, which are listed in Item 2, "Properties." ESI markets the power from plants not under contract to third parties. ESI utilizes power from its New England and Canadian assets primarily to serve firm load commitments in northern Maine and certain other sales agreements with customers. For most of the remaining capacity available from these plants, ESI utilizes financial tools, including forwards, options, and swaps, to mitigate exposure, as well as to maximize value
from the merchant generation fleet. Power purchase agreements are also in place with third-party customers for approximately 90 megawatts of the total capacity, which includes the Stoneman facility in Cassville, Wisconsin, and the Combined Locks facility in Combined Locks, Wisconsin.
The table below discloses future natural gas and electric sales volumes under contract as of December 31, 2005. Contracts are generally one to three years in duration. ESI expects that its ultimate sales volumes in 2006 and beyond will exceed the volumes shown in the table below as it continues to seek growth opportunities and existing customers who do not have long-term contracts continue to buy their short-term requirements from ESI.
(1)
These tables represent physical sales contracts for natural gas and electric power for delivery or settlement in future periods; however, there is a possibility that some of the contracted volumes reflected in the above table could be net settled. Management has no reason to believe that gross margins that will be generated by these contracts will vary significantly from those experienced historically.
For comparative purposes, future natural gas and electric sales volumes under contract at December 31, 2004 are shown below. Actual electric and natural gas sales volumes for 2005 are disclosed within Results of Operations - WPS Resources, ESI Segment Operations.
(1)
These tables represent physical sales contracts for natural gas and electric power for delivery or settlement in future periods; however, there is a possibility that some of the contracted volumes reflected in the above table could be net settled. Management has no reason to believe that gross margins that will be generated by these contracts will vary significantly from those experienced historically.
Wholesale electric and wholesale natural gas volumes under contract have increased at December 31, 2005, compared to December 31, 2004. Natural gas throughput volumes in Canada continue to increase and more volatile natural gas prices have provided increased structured wholesale natural gas opportunities. The emphasis ESI is placing on its originated wholesale customer electric business is also producing encouraging results, and in the fourth quarter of 2005, ESI added contracts to provide approximately 7,300 million kilowatt-hours of electricity to customers in the future. Despite a challenging price environment, retail natural gas sales volumes under contract have increased slightly, while retail electric volumes under contract have decreased primarily due to a combination of industry restructuring and high energy prices in the Michigan and Ohio retail electric markets (see "Liquidity and Capital Resources - WPS Resources - Other Future Considerations," for more information). ESI continues to look for opportunities that fit within its growth strategy. In 2004, ESI grew its retail electric business through the acquisition of retail operations in New York. As discussed above, ESI also began developing
a product offering in the Texas retail electric market. ESI expects to continue to target acquisitions and increase its customer base in existing markets.
As a company that participates in energy commodity markets, ESI is exposed to a variety of risks, including market, operational, liquidity, and credit risks. Market risk is measured as the potential gain or loss of a portfolio that is associated with a price movement within a given probability over a specific period of time, known as Value-at-Risk. Through the use of derivative financial instruments, ESI believes it manages its Value-at-Risk to acceptable levels (see Item 7A, Quantitative and Qualitative Disclosures About Market Risk, for more information about Value-at-Risk). Operational risk is the risk related to execution of transactions, forecasting, scheduling, or other operational activities and is common to all companies participating in the energy marketing industry. ESI's continued investment in system infrastructure, business process improvement, employee training, and internal controls have helped mitigate operational risk to date. Liquidity risk is risk that has historically been less applicable to ESI than many industry participants because of the financial support provided by WPS Resources in the form of guarantees to counterparties. A significant downgrade in WPS Resources' credit ratings, however, could cause counterparties to demand additional assurances of payment. WPS Resources' Board of Directors imposes restrictions on the amount of guarantees WPS Resources is allowed to provide to these counterparties in order to manage this risk. ESI believes it would have adequate capital to continue core operations unless WPS Resources' credit ratings fall below investment grade (Standard & Poor's rating of BBB- and Moody's rating of Baa3).
The other category of risk mentioned above that ESI faces is credit risk from retail and wholesale counterparties. In order to mitigate its exposure to credit risk, ESI developed credit policies. As a result of these credit policies, ESI has not experienced significant write-offs from its large wholesale counterparties to date. Write-offs pertaining to retail customers were $0.7 million (0.0%) in 2005 and 2004, and $3.1 million (0.2%), in 2003. ESI believes its write-off percentage is within the range experienced by similar energy companies. The table below summarizes wholesale counterparty credit exposure, categorized by maturity date, as of December 31, 2005 (in millions). At December 31, 2005, ESI had net exposure with three investment grade counterparties that were more than 10% of total exposure. Total exposure with these counterparties was $89.3 million and is included in the table below.
(1)
The investment and non-investment grade categories are determined by publicly available credit ratings of the counterparty or the rating of any guarantor, whichever is higher. Investment grade counterparties are those with a senior unsecured Moody's rating of Baa3 or above or a Standard & Poor's rating of BBB- or above.
(2)
Exposure considers netting of accounts receivable and accounts payable where netting agreements are in place as well as netting mark-to-market exposure. Exposure is before consideration of collateral from counterparties. Collateral, in the form of cash and letters of credit, received from counterparties totaled $80.8 million at December 31, 2005, $66.6 million from investment grade counterparties and $14.2 million from non-rated counterparties.
(3)
Non-rated counterparties include stand-alone companies, as well as unrated subsidiaries of rated companies without parental credit support. These counterparties are subject to an internal credit review process.
ESI, through a subsidiary ECO Coal Pelletization #12 LLC, also owns an interest in a synthetic fuel producing facility. See "Other Future Considerations," within the Liquidity section below for more information on the risks related to ESI's investment in this synthetic fuel operation.
ESI is subject to clean air regulations enforced by the EPA and state and local governments. New legislation could require significant capital outlays. See Note 17 "Commitments and Contingencies," in WPS Resources' Notes to Consolidated Financial Statements for more information on ESI's environmental exposure.
RESULTS OF OPERATIONS - WPS RESOURCES
Compared with 2004
WPS Resources Overview
WPS Resources' 2005 and 2004 results of operations are shown in the following table:
The $2.0 billion increase in consolidated operating revenue for the year ended December 31, 2005, compared to the same period in 2004, was primarily related to a $1.8 billion (48.4%) increase in revenue at ESI, driven by a 46% increase in the average price of natural gas, higher natural gas throughput volumes in Canada, and an increase in structured natural gas transactions with wholesale customers. Electric utility revenue increased approximately $140 million (15.7%), largely due to an approved electric rate increase for WPSC's Wisconsin retail customers and an increase in electric sales volumes. Natural gas utility revenue increased approximately $101 million (24.0%), primarily as a result of an increase in the per-unit cost of natural gas, a natural gas rate increase, and higher natural gas throughput volumes.
Income available for common shareholders was $157.4 million ($4.11 basic earnings per share) for the year ended December 31, 2005, compared to $139.7 million ($3.74 basic earnings per share) for the year ended December 31, 2004. Significant factors impacting the change in earnings and earnings per share are as follows (and are discussed in more detail below):
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ESI's earnings increased $32.4 million (77.7%), for the year ended December 31, 2005, compared to 2004. Higher earnings were driven by an $85.6 million increase in margin, partially offset by a $19.5 million increase in operating and maintenance expenses, a $4.6 million decrease in miscellaneous income, a $1.7 million decrease in Section 29 federal tax credits, and the negative impact of a $1.6 million after-tax cumulative effect of change in accounting principle recorded in 2005. ESI's earnings were also negatively impacted by an $80.6 million pre-tax impairment loss that was required to write down Sunbury's long-lived assets to fair market value and the recognition of $9.1 million in interest expense related to the termination of Sunbury's interest rate swap. However, these losses were substantially offset by an $87.1 million pre-tax gain recognized on the sale of Sunbury's allocated emission allowances.
·
Earnings at the Holding Company and Other segment decreased $6 million in 2005, compared to 2004, driven by lower gains from land sales, an income tax benefit recognized in 2004 from the donation of land to the WDNR, and an increase in interest expense. These items were partially offset by higher equity earnings from our investment in ATC.
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Electric utility earnings decreased $4.6 million (6.7%) for the year ended December 31, 2005, compared to 2004. Electric utility earnings were negatively impacted by fuel and purchased power costs that were $13.7 million in excess of what WPSC was allowed to recover from customers due to inefficiencies in the fuel recovery process ($10 million related to retail customers and $3.7 million related to wholesale customers). In addition, the PSCW's ruling in the 2006 rate case, which disallowed recovery of costs that were deferred related to the 2004 Kewaunee nuclear plant outage and a portion of the loss on the Kewaunee sale, resulted in the write-off of $13.7 million of regulatory assets.
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Gas utility earnings for the year ended December 31, 2005 decreased $4.1 million, primarily due to an increase in operating and maintenance expenses and depreciation expense incurred by the gas utility.
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The change in basic earnings per share was also impacted by an increase of 0.9 million shares in the weighted average number of outstanding shares of WPS Resources' common stock for the year ended December 31, 2005, compared to the same period in 2004. Additional shares were issued in 2005 under the Stock Investment Plan and certain stock-based employee benefit plans. WPS Resources' issuance of 1.9 million additional shares of common stock through a public offering in November 2005 also contributed to the increase in the weighted average number of shares outstanding.
Overview of Utility Operations
Utility operations include the electric utility segment, consisting of the electric operations of WPSC and UPPCO, and the gas utility segment comprising the natural gas operations of WPSC. Income available for common shareholders attributable to the electric utility segment was $64.2 million for the year ended December 31, 2005, compared to $68.8 million for the year ended December 31, 2004. Income available for common shareholders attributable to the gas utility segment was $13.2 million for the year ended December 31, 2005, compared to $17.3 million for the year ended December 31, 2004.
Electric Utility Segment Operations
Electric utility revenue increased $140.5 million (15.7%) for the year ended December 31, 2005, compared to the same period in 2004. Electric utility revenue increased largely due to an approved electric rate increase for WPSC's Wisconsin retail customers and an increase in electric sales volumes. On December 21, 2004, the PSCW approved a retail electric rate increase of $60.7 million (8.6%), effective January 1, 2005. The rate increase was required primarily to recover increased costs related to fuel and purchased power, the construction of the Weston 4 power plant, and benefit costs. Electric sales volumes increased 8.3%, primarily due to significantly warmer weather during the 2005 cooling season, compared to the same period in 2004, and new power sales agreements that were entered into with wholesale customers. As a result of the warm weather, both WPSC and UPPCO set all-time records for peak electric demand in the second and third quarters of 2005.
The electric utility margin decreased $8.2 million (1.4%) for the year ended December 31, 2005, compared to the year ended December 31, 2004. The decrease in margin can be attributed to a $9.0 million (1.6%) decrease in WPSC's electric margin, which was largely driven by the sale of Kewaunee on July 5, 2005, and the related power purchase agreement. Prior to the sale of Kewaunee, only nuclear fuel expense was reported as a component of fuel and purchased power costs. Subsequent
to the sale, all payments to Dominion for power purchased from Kewaunee are reported as a component of fuel and purchased power costs. These include both variable payments for energy delivered and fixed payments. As a result of the sale, WPSC no longer incurs operating and maintenance expense, depreciation and decommissioning expense, or interest expense for Kewaunee. Excluding the $43.2 million of fixed payments made to Dominion in 2005, WPSC's electric utility margin increased $34.2 million compared to 2004.
Excluding the fixed payments, the increase in margin was primarily related to the approved 2005 retail electric rate increase discussed above and the warm summer weather conditions, partially offset by higher fuel and purchased power costs associated with high natural gas prices and the PSCW's disallowance of certain costs in its decision on the 2006 rate case for WPSC (these costs were previously approved for deferral). Fuel and purchased power costs incurred in 2005 exceeded the amount recovered from ratepayers by $13.7 million (of which $10 million related to Wisconsin retail customers and $3.7 million related to wholesale customers), negatively impacting margin. The increase in fuel and purchased power costs resulted primarily from the destruction of certain natural gas production facilities in the Gulf of Mexico by hurricanes in the third quarter of 2005, driving up the per-unit cost of natural gas used in generation. The quantity of power generated from WPSC's natural gas-fired units was also up 162% over the prior year, driven by the warm summer weather conditions experienced during 2005, increased dispatch by the MISO for reliability purposes, and purchases through a purchase power agreement from the Fox Energy Center (which began operating in June 2005). Certain costs related to the MISO were approved for deferral. Authorization was requested from the PSCW to defer increased natural gas costs related to the hurricanes, but this request was denied, leaving the Wisconsin fuel recovery mechanism as the only option for recovery. However, because of the way the Wisconsin fuel recovery mechanism works, the increase in fuel and purchased power costs (primarily related to the combination of rising natural gas prices caused by the hurricanes and the increase in natural gas-fired generation) were essentially unrecoverable since they were incurred late in the year. To mitigate the risk of unrecoverable fuel costs in 2006 due to market price volatility, WPSC is employing risk management techniques pursuant to its risk policy approved by the PSCW, including the use of derivative instruments such as futures and options. The PSCW also disallowed recovery of $5.5 million of increased fuel and purchased power costs related to an extended outage at Kewaunee in 2004, resulting in this deferral being written off in the fourth quarter of 2005.
Electric utility earnings decreased $4.6 million (6.7%) for the year ended December 31, 2005, compared to 2004. The decrease in earnings resulted from the high fuel and purchased power costs that WPSC was unable to recover from its Wisconsin retail and wholesale customers, the PSCW's disallowance of previously deferred costs related to Kewaunee, and an increase in operating and maintenance expenses.
Gas Utility Segment Operations
Gas utility revenue increased $101.1 million (24.0%) for the year ended December 31, 2005, compared to 2004. Gas utility revenue increased primarily as a result of an increase in the per-unit cost of natural gas, a natural gas rate increase, and higher natural gas throughput volumes. Natural gas costs increased 24.6% (on a per-unit basis) for the year ended December 31, 2005, compared to 2004. Following regulatory practice, WPSC passes changes in the total cost of natural gas on to customers through a purchased gas adjustment clause, as allowed by the PSCW and the MPSC. The PSCW issued an order authorizing a natural gas rate increase of $5.6 million (1.1%), effective January 1, 2005. The rate increase was primarily driven by higher benefit costs and the cost of natural gas distribution system
improvements. Natural gas throughput volumes increased 3.2%, driven by an increase in interdepartmental sales from the natural gas utility to the electric utility as a result of increased generation from combustion turbines. Higher natural gas throughput volumes from interdepartmental sales to the electric utility were partially offset by lower natural gas throughput volumes to residential customers, driven by milder weather conditions in 2005, compared to 2004. WPSC also believes customers are taking measures to conserve energy as a result of the high natural gas prices.
The natural gas utility margin increased $5.6 million (4.7%) for the year ended December 31, 2005, compared to 2004. The higher natural gas utility margin was largely due to the rate increase mentioned above. The increase in interdepartmental sales volumes to WPSC's electric utility also had a positive impact on the natural gas margin.
Gas utility earnings for the year ended December 31, 2005, decreased $4.1 million, primarily due to an increase in operating and maintenance expenses and depreciation expense incurred by the gas utility.
Overview of ESI Operations
ESI offers nonregulated natural gas, electric, and alternative fuel supplies, as well as energy management and consulting services, to retail and wholesale customers. ESI also owns several merchant electric generation plants, primarily in the Midwest and Northeastern United States and adjacent portions of Canada.
Prior to the fourth quarter of 2005, WPS Resources reported two nonregulated segments, ESI and PDI. In the fourth quarter of 2005, WPS Resources' Chief Executive Officer and its Board of Directors decided to view ESI and PDI as one business, and corresponding changes were made to the segment information reported to them. The change in reportable segments is the culmination of changes over the past two years that caused these businesses to become integrated. These changes included combining the management teams, restructuring the ownership structure of ESI and PDI, and having ESI optimize the value of PDI's merchant generation fleet and reduce market price risk through the use of various financial and physical instruments (such as futures, options, and swaps). Effective in the fourth quarter of 2005, WPS Resources began reporting one nonregulated segment, ESI. Segment information related to prior periods has been reclassified to reflect this change.
Income available for common shareholders attributable to ESI was $74.1 million for the year ended December 31, 2005, compared to $41.7 million for the year ended December 31, 2004.
* Represents gross physical volumes
Revenues
ESI's revenue increased $1.8 billion (48.4%) for the year ended December 31, 2005, compared to 2004. Natural gas revenue increased $1.7 billion (54.8%), driven by a 46% increase in the average price of natural gas, higher natural gas throughput volumes in Canada, and an increase in structured natural gas transactions with wholesale customers. Electric revenue increased approximately $118 million, largely due to an $88 million increase in revenue from retail electric operations in New York, resulting from an increase in the per-unit price of electricity sold and a 115% increase in sales volumes (the New York business had its first full year of operation in 2005). Revenue at ESI's Sunbury generation facility (Sunbury) increased $56 million, due to improved opportunities to sell power into the market (made possible by the expiration of a fixed price outtake contract on December 31, 2004, and higher energy market prices). Revenue also increased due to an increase in structured energy transactions. These items were partially offset by a $78.2 million decrease in wholesale electric revenue related to ESI's prior participation in the New Jersey Basic Generation Services Program, which ended on May 31, 2004, and a $31.1 million decrease in revenue from retail electric operations in Michigan, driven by lower sales volumes in 2005.
Margins
ESI's margins increased $85.6 million (61.7%), from $138.7 million for the year ended December 31, 2004, to $224.3 million for 2005. Many items contributed to the year-over-year net increase in margin and, as a result, a table has been provided to summarize significant changes. Variances included under "Other significant items" in the table below are related to the timing of gain and loss recognition on certain transactions pursuant to generally accepted accounting principles and gains and losses that do not frequently occur in ESI's business. All variances depicted in the table are discussed in more detail below.
ESI's electric and other margins increased $80.5 million (98.1%) for the year ended December 31, 2005, compared to 2004. The following items were the most significant contributors to the net change in ESI's electric and other margins:
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Sunbury generation - The margin at Sunbury increased $43.7 million, primarily due to improved opportunities to sell power into the market (as discussed in "Revenues" above).
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Physical asset management - Optimization strategies related to ESI's generation facilities resulted in a $7.5 million increase in margin. The profitability and volume of transactions related to ESI's optimization strategies were higher due to increased variability in the price of energy in 2005 compared to 2004. In the first quarter of 2004, ESI first implemented the portfolio optimization strategies to optimize the value of the merchant generation fleet to reduce market price risk and extract additional value from these assets through the use of various financial and physical instruments (such as forward contracts and options).
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New York retail - The first full year of retail electric operations in New York (as discussed in "Revenues" above) contributed $3.0 million to the overall margin increase.
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Michigan retail - The margin contributed by retail electric operations in Michigan decreased $15.7 million in 2005, compared to 2004. Higher transmission-related charges resulting from the Seams Elimination Charge Adjustment, which was implemented on December 1, 2004, and continues through March 2006, as ordered by the FERC, have negatively impacted the margin from retail electric operations in Michigan. In addition, tariff changes granted to the regulated utilities in Michigan in 2004, coupled with high wholesale energy prices, have significantly lowered the savings customers can obtain from contracting with non-utility suppliers. The tariff changes enable Michigan utilities to charge a fee to electric customers choosing non-utility suppliers in order to recover certain stranded costs. ESI has experienced significant customer attrition as a result of the tariff changes and higher wholesale prices. Customer attrition, high wholesale energy prices, and the tariff changes have also negatively impacted the margin from retail electric operations in Michigan.
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All other electric operations - A $25.1 million increase in margin was primarily related to realized and unrealized gains on structured power transactions in the latter half of 2005. These transactions included the execution of purchase and sales contracts with municipalities, merchant generators, retail aggregators, and other power marketers made possible by changing market conditions. Additionally, ESI experienced increased margins from its merchant generation fleet as a result of increased dispatch levels due to improved market conditions. Period-by-period variability in the margin contributed by structured transactions and the merchant generation fleet is expected due to constantly changing market conditions and the timing of gain and loss recognition on certain transactions pursuant to generally accepted accounting principles.
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Oil option activity, net - Mark-to-market gains recognized in 2005 on derivative instruments utilized to protect the value of a portion of ESI's Section federal tax credits in 2006 and 2007 contributed $8.4 million to the increase in margin. The derivative contracts have not been designated as hedging instruments and, as a result, changes in the fair value are recorded currently in earnings. This will result in mark-to-market gains being recognized in different periods, compared to any offsetting tax credit phase-outs that may occur. For the year ended December 31, 2005, unrealized mark-to-market gains of $4.0 million and $4.4 million were recognized for the 2006 and 2007 oil options, respectively, while no tax credit phase-out was recognized because 2006 and 2007 tax credits will not be recognized until fuel is produced and sold in those periods. Hedges of 2005 exposure contributed an additional $0.3 million increase in margin ($1.9 million gain on settlement, net of $1.6 million of premium amortization).
·
Liquidation of electric purchase contract - In 2005, an electricity supplier exiting the wholesale market in Maine forced ESI to liquidate a firm contract to buy power in 2006 and 2007. ESI recognized a gain of $8.2 million related to the liquidation of this contract, and entered into a new contract with another supplier for firm power in 2006 and 2007 to supply its customers in Maine. The cost to purchase power under the new contract will be more than the cost under the liquidated contract. As a result, purchased power costs will be $6.4 million higher in 2006 and slightly higher than the original contracted amount in 2007, substantially offsetting the 2005 gain.
The natural gas margin at ESI increased $5.1 million (9.0%) for the year ended December 31, 2005, compared to 2004. The following items were the most significant contributors to the change in ESI's electric margin:
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Gas margins (principally Canada, Michigan and Wisconsin retail) - Major contributors to growth in ESI's gas margins include the continued expansion of our Canadian retail and wholesale business, as well as increased margins from our retail operations in Michigan and Wisconsin.
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Counterparty settlement - The natural gas margin increased $3.3 million as a result of a favorable settlement with a counterparty.
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Unrealized gain on Ohio options - A $2.9 million mark-to-market gain on options utilized to manage supply costs for Ohio customers, which expire in varying months through September 2006, also contributed to the margin increase. These contracts are utilized to reduce the risk of price movements and changes in load requirements during customer signup periods. Earnings volatility results from the application of derivative accounting rules to the options (requiring that these derivative instruments be marked-to-market), without a corresponding offset related to the customer contracts. Full requirements gas contracts with ESI's customers are not considered derivatives and, therefore, no gain or loss is recognized on these contracts until settlement.
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Spot to forward differential - The natural gas storage cycle (described in more detail below) accounted for a $7.2 million decrease in the wholesale natural gas margin (for the year ended December 31, 2005, the natural gas storage cycle had a $5.2 million negative impact on margin, compared with a $2.0 million favorable impact on margin for the same period in 2004).
ESI experiences earnings volatility associated with the natural gas storage cycle, which runs annually from April through March of the next year. Generally, injections of natural gas into storage inventory take place in the summer months and natural gas is withdrawn from storage in the winter months. ESI's policy is to hedge the value of natural gas storage with sales in the over-the-counter and futures markets, effectively locking in a margin on the natural gas in storage. However, fair market value hedge accounting rules require the natural gas in storage to be marked-to-market using spot prices, while the future sales contracts are marked-to-market using forward prices. When the spot price of natural gas changes disproportionately to the forward price of natural gas, ESI experiences volatility in its earnings. Consequently, earnings volatility may occur within the contract period for natural gas in storage. The accounting treatment does not impact the underlying cash flows or economics of these transactions. At December 31, 2005, there was a $5.8 million difference between the market value of natural gas in storage and the market value of future sales contracts (net unrealized loss), related to the 2005/2006 natural gas storage cycle. This difference between the market value of natural gas in storage and the market value of future sales contracts related to the 2005/2006 storage cycle is expected to vary with market conditions, but will reverse entirely and have a positive impact on earnings when all of the natural gas is withdrawn from storage.
Earnings
ESI's earnings increased $32.4 million (77.7%), for the year ended December 31, 2005, compared to 2004. Higher earnings were driven by the $85.6 million increase in margin, partially offset by a $19.5 million increase in operating and maintenance expenses, a $4.6 million decrease in miscellaneous income, a $1.7 million decrease in Section 29 federal tax credits, and the negative impact of a $1.6 million after-tax cumulative effect of change in accounting principle recorded in 2005. ESI's earnings were also negatively impacted by an $80.6 million pre-tax impairment loss that was required to write down Sunbury's long-lived assets to fair market value and the recognition of $9.1 million in interest expense related to the termination of Sunbury's interest rate swap. However, these losses were substantially offset by an $87.1 million pre-tax gain recognized on the sale of Sunbury's allocated emission allowances.
Overview of Holding Company and Other Segment Operations
Holding Company and Other operations include the operations of WPS Resources' and the nonutility activities at WPSC and UPPCO. Holding Company and Other operations recognized earnings of $5.9 million during the year ended December 31, 2005, compared to earnings of $11.9 million in 2004.
The decrease in earnings is primarily due to a $9.4 million decrease in pre-tax gains related to land sales, an income tax benefit recognized in 2004 from the donation of land to the WDNR, and a $5.5 million increase in interest expense. Pre-tax land sale gains of $10.3 million were recognized in 2005, compared to $19.7 million of pre-tax land sale gains in 2004. Interest expense increased primarily as a result of restructuring Sunbury's debt to a WPS Resources' obligation in June 2005 and higher average short-term debt in 2005, compared to 2004. Partially offsetting the items discussed above was a $9.1 million increase in pre-tax equity earnings from ATC and $1.5 million of deferred financing costs that were written off in the first quarter of 2004. Pre-tax equity earnings from ATC were $25.1 million in 2005, compared to $16.0 million in 2004. WPS Resources' ownership interest in ATC increased from approximately 23% at December 31, 2004, to approximately 31.0% at December 31, 2005. The higher ownership interest was primarily the result of WPS Resources continued funding of a portion of the Wausau, Wisconsin, to Duluth, Minnesota, transmission line.
Operating Expenses
Operating and Maintenance Expense
Operating and maintenance expenses increased $30.5 million (5.7%) for the year ended December 31, 2005, compared to 2004. Utility operating and maintenance expenses increased $12.9 million, primarily as a result of a $13.6 million increase in WPSC's operating and maintenance expenses. The following items were the most significant contributors to the change in operating and maintenance expenses at WPSC:
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The combined increase in pension expense, active and postretirement medical expense, salaries, and customer service expense was approximately $25 million.
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Transmission-related expenses increased $9.9 million.
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In WPSC's 2006 rate case, the PSCW concluded that only half of the loss related to the sale of Kewaunee could be collected from ratepayers. As a result, WPSC wrote off $6.1 million of the regulatory asset established for the loss on the sale of Kewaunee.
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In WPSC's 2006 rate case, the PSCW also disallowed recovery of increased operating and maintenance expenses related to the 2004 extended outage at Kewaunee, resulting in a $2.1 million write-off of previously deferred costs.
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The increases discussed above were partially offset by a decrease in operating and maintenance expenses of approximately $28 million related to Kewaunee, due to the sale of this facility on July 5, 2005.
Operating and maintenance expenses at ESI increased $19.5 million. Approximately $11 million of the increase related to higher payroll and benefit costs associated with recent business expansion. Commissions paid to brokers and third-party agents increased $2.4 million and bad debt expense increased $2.3 million, primarily as a result of higher energy prices. Operating and maintenance expenses at Sunbury also increased $2.7 million. Maintenance activities were performed in 2005 to better ensure the plant's ability to capitalize on high market prices.
Depreciation and Decommissioning Expense
Depreciation and decommissioning expense increased $35.8 million (33.5%) for the year ended December 31, 2005, compared to 2004, largely due to an increase of $35.0 million at WPSC. The increase at WPSC was driven by higher gains on decommissioning trust assets prior to the sale of
Kewaunee of approximately $35 million. Realized gains on decommissioning trust assets (included as a component of miscellaneous income) offset the increased decommissioning expense pursuant to regulatory practice. Continued capital investment at WPSC also resulted in an increase in depreciation expense. These items were partially offset by a $7.0 million decrease in depreciation resulting from the sale of the Kewaunee assets in July 2005.
Gain on Sale of Emission Allowances
ESI completed the sale of Sunbury's allocated emission allowances in May 2005. The sales proceeds were $109.9 million, resulting in a pre-tax gain of $85.9 million. ESI also sold other emission allowances throughout the year, recognizing a gain on these additional sales of $1.2 million.
Impairment Loss
The sale of Sunbury's allocated emission allowances in May 2005 provides ESI with more time to evaluate various options related to Sunbury. These options range from closing the plant, retaining the plant and operating it during favorable economic periods, or a future sale. Because ESI is no longer committed to the sale of Sunbury as its only option, generally accepted accounting principles require all long-lived assets that were previously classified as "held for sale" to be reclassified as "held and used" at the lower of their carrying value before they were classified as "held for sale," adjusted for depreciation that would have been recognized had the assets been continuously classified as "held and used," or fair value at the date the "held for sale" criteria was no longer met. Upon reclassification of the Sunbury plant and related assets as "held and used" in the second quarter of 2005, ESI recorded a non-cash, pre-tax impairment charge of $80.6 million. The impairment charge reflects the reduction in the fair value of the Sunbury plant without the related emission allowances.
Other Income (Expense)
Miscellaneous Income
Miscellaneous income increased $34.2 million (65.8%) for the year ended December 31, 2005, compared to 2004. The following items were the largest contributors to the change in miscellaneous income:
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Approximately $35 million of the increase in miscellaneous income related to realized gains on nuclear decommissioning trust assets. The nonqualified decommissioning trust assets were placed in more conservative investments in the second quarter of 2005 in anticipation of the sale of Kewaunee, which was completed on July 5, 2005. Pursuant to regulatory practice, the increase in miscellaneous income related to the realized gains was offset by an increase in decommissioning expense. Overall, the change in the investment strategy for the nonqualified decommissioning trust assets had no impact on income available for common shareholders.
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Pre-tax equity earnings from WPS Resources' investment in ATC increased $9.1 million. Pre-tax equity earnings from ATC were $25.1 million in 2005, compared to $16.0 million in 2004.
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WPSC sold a 30% interest in the Weston 4 power plant to DPC in the fourth quarter of 2005. Proceeds received from the sale included reimbursement for approximately $8 million of carrying costs incurred by WPSC for capital expenditures related to DPC's portion of the facility, which were funded by WPSC in 2004 and 2005. The $8 million reimbursement was recorded as miscellaneous income in 2005.
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Land sale gains of $10.3 million were recognized in 2005, compared to land sale gains of $19.7 million in 2004, resulting in a $9.4 million decrease in miscellaneous income.
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Other income at ESI decreased $4.6 million, primarily related to a $4.4 million termination payment received from Duquesne Power in December 2004 as a result of Duquesne's termination of the former asset purchase agreement for Sunbury.
Interest Expense
Interest expense increased $12.5 million (20.9%) for the year ended December 31, 2005, compared to 2004. The increase in interest expense was primarily related to terminating the interest rate swap pertaining to Sunbury's non-recourse debt obligation in the second quarter of 2005. The interest rate swap was previously designated as a cash flow hedge and, as a result, the mark-to-market losses had been recorded as a component of other comprehensive income. WPS Resources is required to recognize the amount accumulated within other comprehensive income as a component of interest expense when the hedged transactions (future interest payments on the Sunbury debt obligation) are no longer probable of occurring. As a result, the restructuring of the Sunbury non-recourse debt to a WPS Resources' obligation in June 2005 triggered the recognition of $9.1 million of interest expense related to the mark-to-market value of the swap at the date of restructuring. The remaining increase in interest expense was primarily related to an increase in the average level of short-term debt outstanding in 2005, compared to 2004.
Provision for Income Taxes
The effective tax rate was 22.4% for the year ended December 31, 2005, compared to 13.2% for the year ended December 31, 2004. The increase in the effective tax rate was primarily driven by a 26.9% increase in income before taxes, while Section 29 federal tax credits recognized decreased $1.7 million. Other factors contributing to the increase in the effective tax rate in 2005, compared to 2004, were a tax benefit recorded in 2004 for land donated to the WDNR, and a $2.9 million increase in the year-over-year provision for income taxes related to favorable settlements of certain tax audits and refund claims in 2004.
Our ownership interest in the synthetic fuel operation resulted in recognizing the tax benefit of Section 29 federal tax credits totaling $26.1 million in 2005 and $27.8 million in 2004.
Cumulative Effect of Change in Accounting Principles
In March 2005, the FASB issued Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations. This Interpretation clarifies when companies are required to recognize conditional legal asset retirement obligations that result from the acquisition, construction, and normal operation of a long-lived asset. Because the accounting for conditional asset retirement obligations has been interpreted differently between companies, SFAS No. 143, Accounting for Asset Retirement Obligations, had been inconsistently applied in practice.
The adoption of Interpretation No. 47 at ESI on December 31, 2005, resulted in a negative $1.6 million after-tax cumulative effect of change in accounting principle, related to recording a liability for asbestos remediation at certain of ESI's generation plants. For the utility segments of WPS Resources, we concluded it was probable that any differences between expenses under Interpretation No. 47 and expenses currently recovered through customer rates will be recoverable in future customer rates. Accordingly, the adoption of this statement had no impact on the utility segments' income.
Compared with 2003
WPS Resources Overview
WPS Resources' 2004 and 2003 results of operations are shown in the following table:
The $548.3 million increase in consolidated operating revenue for the year ended December 31, 2004, compared to the same period in 2003, was largely driven by a $449.6 million (13.9%), increase in revenue at ESI and an $82.5 million (10.1%), increase in electric utility revenue. Higher natural gas prices, portfolio optimization strategies (implemented in 2004), and expansion of the Canadian retail natural gas business were the primary contributors to increased revenue at ESI. Higher electric utility revenue was primarily the result of authorized retail electric rate increases for WPSC's Wisconsin and Michigan customers. Revenue changes by reportable segment are discussed in more detail below.
Income available for common shareholders was $139.7 million ($3.74 basic earnings per share) for the year ended December 31, 2004, compared to $94.7 million ($2.87 basic earnings per share) for the year ended December 31, 2003. Significant factors impacting the change in earnings and earnings per share are as follows (and are discussed in more detail below).
·
Approved rate increases (including the impact of timely retail electric rate relief in 2004, compared to the delay in receiving retail electric rate relief in 2003) favorably impacted year-over-year margin at the utilities.
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Natural gas utility throughput volumes were 6.2% lower in 2004 due to weather that was 4.3% warmer during the heating season, compared to 2003.
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Higher throughput volumes and improved supply management in Ohio favorably impacted ESI's year-over-year retail natural gas margin.
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Portfolio optimization strategies, better management of retail electric operations in Ohio and positive operating results from Advantage Energy contributed to improved year-over-year electric margins at ESI.
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As part of our overall asset management strategy, WPS Resources realized earnings of $15.0 million from the sale and donation of land in 2004, compared to $6.5 million in 2003.
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Earnings from equity method investments (primarily from ATC) increased in 2004, compared to 2003.
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Earnings were negatively impacted by higher operating and maintenance expenses in 2004.
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Synthetic fuel related tax credits recognized were higher in 2004 when compared to 2003.
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The weighted average number of shares of WPS Resources' common stock increased by 4.4 million shares for the year ended December 31, 2004, compared to the same period in 2003. The increase was largely due to issuing 4,025,000 additional shares of common stock through a public offering in November 2003. Additional shares were also issued under the Stock Investment Plan and certain stock-based employee benefit plans.
Overview of Utility Operations
Income available for common shareholders attributable to the electric utility segment was $68.8 million for the year ended December 31, 2004, compared to $60.0 million for the year ended December 31, 2003. Income available for common shareholders attributable to the gas utility segment was $17.3 million for the year ended December 31, 2004, compared to $15.7 million for the year ended December 31, 2003.
Electric Utility Segment Operations
Electric utility revenue increased $82.5 million (10.1%), for the year ended December 31, 2004, compared to the same period in 2003. Electric utility revenue increased largely due to authorized retail and wholesale electric rate increases for WPSC's Wisconsin and Michigan customers (as summarized below) to recover higher fuel and purchased power costs, increased operating expenses, and expenditures incurred for infrastructure improvements.
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Effective March 21, 2003, the PSCW approved a retail electric rate increase of $21.4 million (3.5%).
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Effective May 11, 2003, the FERC approved a $4.1 million (21%), interim increase in wholesale electric rates.
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Effective July 22, 2003, the MPSC approved a $0.3 million (2.2%), increase in retail electric rates for WPSC's Michigan customers and authorized recovery of $1.0 million of increased transmission costs through the power supply cost recovery process.
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Effective January 1, 2004, the PSCW approved a retail electric rate increase of $59.4 million (9.3%).
Electric utility sales volumes were also slightly higher in 2004, increasing 0.8% over 2003 sales volumes. A 1.6% increase in sales volumes to commercial and industrial customers was partially offset by a 1.2% decrease in sales volumes to residential customers. Higher sales volumes to our commercial and industrial customers reflect an improving economy and growth within our service area, while the decrease in sales volumes to residential customers reflects weather that was 6.6% cooler during the 2004 cooling season, compared to 2003.
The electric utility margin increased $53.3 million (9.7%), for the year ended December 31, 2004, compared to 2003. The majority of this increase can be attributed to a $52.3 million (10.5%), increase in WPSC's electric margin. The increase in WPSC's electric margin is primarily related to the retail and wholesale electric rate increases, partially offset by a $20.4 million increase in purchased power costs. The quantity of power purchased in 2004 increased 9.3% over 2003 purchases, and purchased power costs were 17.4% higher (on a per-unit basis) in 2004, compared to 2003. The PSCW, in 2004, allowed WPSC to adjust prospectively the amount billed to Wisconsin retail customers for fuel and purchased power if costs were in excess of plus or minus 2% from approved levels. In response to a request for additional fuel cost recovery filed early in 2004, WPSC was allowed to recover $3.2 million of its increased fuel and purchased power costs during 2004. The PSCW also allowed WPSC to defer $5.4 million of unanticipated fuel and purchased power costs directly associated with the extension of the Kewaunee refueling outage in the fourth quarter of 2004. The Kewaunee outage was extended three weeks due primarily to an unexpected problem encountered with equipment used for lifting internal vessel components to perform a required ten-year in-service inspection. It was anticipated that these costs would be recovered in 2006; however, in the PSCW's final decision allowing WPSC authority to increase retail electric and natural gas rates in 2006, the PSCW determined WPSC could not recover the costs for the 2004 extended outage. For more information on this determination, see Note 23, "Regulatory Environment," in WPS Resources' Notes to Consolidated Financial Statements.
Electric utility earnings increased $8.8 million (14.7%), for the year ended December 31, 2004, compared to 2003. The increased earnings were largely driven by the higher margin at WPSC (including the effect
of timely retail electric rate relief in 2004 compared to a delay in receiving retail electric rate relief in 2003), partially offset by higher operating and maintenance expenses.
Gas Utility Segment Operations
Gas utility revenue increased $16.7 million (4.1%), for the year ended December 31, 2004, compared to 2003. Higher revenue was driven by an authorized rate increase and an increase in the per-unit cost of natural gas, partially offset by an overall 6.2% decrease in natural gas throughput volumes. The PSCW issued a final order authorizing a retail natural gas rate increase of $8.9 million (2.2%), effective January 1, 2004. Natural gas prices increased 14.2% per unit in 2004. Higher natural gas prices reflect higher marketplace natural gas costs in 2004. The PSCW and the MPSC allow WPSC to pass changes in the total cost of natural gas on to customers. As a result, changes in the price of the natural gas commodity do not have a direct impact on WPSC's margin. The decrease in natural gas throughput volumes was driven by weather that was 4.3% warmer during the heating season for the year ended December 31, 2004, compared to 2003.
The natural gas utility margin increased $5.8 million (5.1%), for the year ended December 31, 2004, compared to 2003. The higher natural gas utility margin is largely due to the authorized rate increase mentioned above. The ability of WPSC to realize the full benefit of an authorized rate increase is dependent upon normal throughput volumes; therefore, the decrease in natural gas throughput volumes negatively impacted WPSC's ability to benefit from the full amount of the rate increase.
The higher margin drove a $1.6 million (10.2%), increase in natural gas utility earnings for the year ended December 31, 2004.
Overview of ESI Operations
Income available for common shareholders attributable to ESI was $41.7 million for the year ended December 31, 2004, compared to $21.1 million for the same period in 2003. The increase in income available for common shareholders resulted from higher overall margins, an increase in the amount of tax credits recognized, and a $4.4 million termination payment received from Duquesne Power in December 2004, as a result of Duquesne's termination of the asset sale agreement with Sunbury. These items were offset by an increase in operating and maintenance expenses and a $3.2 million after-tax cumulative effect of change in accounting principles that was recorded in 2003.
* Represents gross physical volumes
Natural gas revenues increased $343.2 million, driven by higher natural gas prices and the expansion of the Canadian retail natural gas business (as a result of obtaining new customers), partially offset by lower sales volumes from physical wholesale transactions. Sales volumes from physical wholesale transactions declined as a result of reduced price volatility of natural gas during the first half of 2004 (volatility provides more opportunity for profitable physical wholesale transactions). Electric and other revenues increased $106.4 million, largely due to higher volumes from portfolio optimization strategies resulting in an $83.7 million increase in revenue. In the first quarter of 2004, ESI first implemented the portfolio optimization strategies to optimize the value of its merchant generation fleet and its retail supply portfolios to reduce market price risk and extract additional value from these assets through the use of various financial and physical instruments (such as forward contracts and options). Electric revenue also increased as a result of the July 1, 2004, acquisition of Advantage Energy and higher energy prices compared to the prior year. These increases were partially offset by a $21.5 million decrease in revenue recognized at Sunbury. The decrease in revenue from Sunbury was driven by fewer opportunities to sell power into the spot market.
The natural gas margin at ESI increased $12.5 million for the year ended December 31, 2004, compared to 2003. The margin related to retail natural gas operations increased $12.3 million, primarily driven by higher natural gas throughput volumes in Ohio (driven by the addition of new customers), operational improvements, and better management of supply for residential and small commercial customers. Customer growth in Canada also contributed to the increase in the retail natural gas margin. The margin attributed to wholesale natural gas operations increased $0.2 million. The increase in wholesale natural gas margin was driven by a $4.6 million margin increase related to the natural gas storage cycle, a $2.2 million increase in the Canadian wholesale natural gas margin, and increased margins from other structured wholesale natural gas transactions. Favorable settlements of liabilities with several counterparties in 2003 (in the amount of $8.4 million) largely offset these increases in the wholesale natural gas margin. For the year ended December 31, 2004, the natural gas storage cycle had a $2.0 million positive impact on margin, compared with a $2.6 million negative impact on margin for the same period in 2003. At December 31, 2004, there was a $0.6 million difference between the market value of natural gas in storage and the market value of future sales contracts (net unrealized loss), related to the 2004/2005 natural gas storage cycle. This difference between the market value of natural gas in storage and the market value of future sales contracts related to the 2004/2005 storage cycle is expected to vary with market conditions, but will reverse entirely and have a positive impact on earnings when all of the natural gas is withdrawn from storage. The increase in the Canadian wholesale natural gas margin is related to higher volumes (more structured wholesale transactions) as ESI continued to increase its wholesale natural gas operations in this region.
The remaining $2.3 million increase in margin at ESI was driven by an increase in the electric and other margin. The higher margin was driven by a $10.3 million increase from portfolio optimization strategies discussed above and a $7.6 million increase in margin related to retail electric operations in Ohio, which can be attributed to better management of retail operations and improved supply procurement. These items were partially offset by an $8.9 million decrease in the margin related to Sunbury and a $5.7 million decrease in margin from ESI no longer participating in the New Jersey Basic Generation Services Program (ESI participated in this program from August 2003 until May 2004, but higher margins were recognized in the summer months). The lower margin at Sunbury was largely due to an increase in the per-ton cost of coal utilized in the generation process and by fewer opportunities to sell power into the spot market in 2004, compared to 2003.
Overview of Holding Company and Other Segment Operations
Holding Company and Other operations had income available for common shareholders of $11.9 million for the year ended December 31, 2004, compared to a net loss of $2.1 million for the year ended December 31, 2003. This favorable variance can be attributed to an increase in earnings recognized from the sale of land located along the Peshtigo River in Wisconsin and an increase in equity earnings from ATC and Wisconsin River Power Company. Equity earnings from ATC were $16.0 million in 2004, compared to $10.1 million in 2003. WPSC nonutility operations recognized a $13.3 million pre-tax gain on the sale of land located near the Peshtigo River in the fourth quarter of 2004, compared to a $6.2 million pre-tax gain that was recognized on the sale of land in the fourth quarter of 2003. WPSC also realized an income tax benefit in the fourth quarter of 2004 from the donation of land to the WDNR.
Operating Expenses
Operating and Maintenance Expense
Operating and maintenance expenses increased $51.4 million (10.6%), for the year ended December 31, 2004, compared to 2003. Utility operating and maintenance expenses increased $36.3 million. Electric transmission and distribution costs were up $15.2 million at the utilities primarily due to an increase in transmission rates. Pension and postretirement medical costs incurred at the utilities increased $11.0 million. Additionally, $6.8 million of the increase was driven by amortization of costs incurred in conjunction with the implementation of the automated meter reading system and the purchase of the De Pere Energy Center (previously deferred as regulatory assets). Maintenance expenses at WPSC's coal-fired generation facilities were $4.2 million higher in 2004, compared to 2003, driven by an extension of the annual planned outage at the Pulliam 6 generation facility in 2004. Higher payroll and other benefit costs also contributed to the increase in operating and maintenance expenses. The fall refueling outage at Kewaunee did not significantly impact the year-over-year change in operating and maintenance expenses as there was also a refueling outage at Kewaunee in spring 2003, and the PSCW approved the deferral of incremental operating and maintenance expenses that were incurred as a direct result of the refueling outage extension ($1.8 million of operating and maintenance expenses were deferred in the fourth quarter of 2004). It was anticipated that these costs would be recovered in 2006; however, in the PSCW's final decision allowing WPSC authority to increase retail electric and natural gas rates in 2006, the PSCW determined WPSC could not recover the costs for the 2004 extended outage. For more information on this determination, see Note 23, "Regulatory Environment," in WPS Resources' Notes to Consolidated Financial Statements."
Operating expenses at ESI increased $9.9 million mostly due to higher payroll, benefits, and other costs associated with continued business expansion.
Depreciation and Decommissioning Expense
Depreciation and decommissioning expense decreased $34.3 million (24.3%), for the year ended December 31, 2004, compared to 2003, due primarily to a decrease of $35.9 million resulting from lower realized gains on decommissioning trust assets and because the decommissioning trust was not funded in 2004 in anticipation of selling Kewaunee. Realized gains on decommissioning trust assets are substantially offset by depreciation expense pursuant to regulatory practice (see detailed discussion in "Miscellaneous Income" below). An increase in depreciation expense from plant asset additions at WPSC partially offset the decrease in decommissioning expense.
Other Income (Expense)
Miscellaneous Income
Miscellaneous income decreased $11.6 million (18.2%), for the year ended December 31, 2004, compared to 2003. The decrease in miscellaneous income is largely due to a decrease in realized gains on decommissioning trust assets of $33.5 million. There were significant realized gains recognized on decommissioning trust assets in the fourth quarter of 2003, which were driven by a change in the investment strategy for WPSC's qualified nuclear decommissioning trust assets. Qualified decommissioning trust assets were placed in more conservative investments in anticipation of the sale of Kewaunee. Pursuant to regulatory practice, realized gains on decommissioning trust assets are substantially offset by depreciation expense. A $1.5 million write-off of previously deferred financing costs associated with the redemption of our trust-preferred securities in the first quarter of 2004 also unfavorably impacted miscellaneous income. Partially offsetting the decreases discussed above were an $8.7 million increase in equity earnings from investments, a $7.1 million increase in income recognized from the sale of land located along the Peshtigo River in Wisconsin(discussed previously), a $4.4 million termination payment received from Duquesne Power in December 2004 as a result of Duquesne's termination of the asset sale agreement for Sunbury, and a combined $3.1 million increase related to higher royalties and a decrease in operating losses realized from ESI's investment in a synthetic fuel producing facility. The increase in equity earnings was primarily related to our investments in ATC, Wisconsin River Power Company, and Wisconsin Valley Improvement Company. Equity earnings from ATC were $16.0 million in 2004, compared to $10.1 million in 2003. Royalty income recognized from the synthetic fuel facility increased as a result of higher production levels at this facility.
Minority Interest
The decrease in minority interest is related to the fact that ESI's partner in its subsidiary, ECO Coal Pelletization #12 LLC, was allocated more production from the synthetic fuel operation in 2003 compared to 2004. ESI's partner was not allocated any production from the synthetic fuel facility in the first quarter of 2004 as they requested additional production in the fourth quarter of 2003.
Provision for Income Taxes
The effective tax rate was 13.2% for the year ended December 31, 2004, compared to 22.2% for the year ended December 31, 2003. The decrease in the effective tax rate was driven by tax deductions pertaining to items that exceed the related book expense (including land donated to the WDNR in the fourth quarter of 2004), resulting in a $5.7 million decrease in the 2004 provision for income taxes compared to 2003, and a $9.6 million increase in the amount of tax credits recognized in 2004 (related to an increase in synthetic fuel tax credits produced in 2004 and the favorable settlement of several tax audits and refund claims related to prior tax years).
Our ownership interest in the synthetic fuel operation resulted in the recognition of $27.8 million of Section 29 federal tax credits for the year ended December 31, 2004, and $18.2 million of tax credits for 2003. The increase in synthetic fuel related tax credits was primarily due to an increase in tax credits produced and allocable to ESI, an increase in the value of the credits produced resulting from the higher Btu content of coal and the annual inflation adjustment allowed, and the favorable settlement of several tax audits and refund claims related to prior tax years.
Cumulative Effect of Change in Accounting Principles
On January 1, 2003, WPS Resources recorded a positive after-tax cumulative effect of a change in accounting principle of $3.5 million (primarily related to the operations of ESI) to income available for common shareholders as a net result of removing from its balance sheet the mark-to-market effects of contracts that do not meet the definition of a derivative. This change in accounting resulted from the decision of the Emerging Issues Task Force to preclude mark-to-market accounting for energy contracts that are not derivatives. The required change in accounting had no impact on the underlying economics or cash flows of the contracts.
In addition, the adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations," at ESI resulted in a $0.3 million negative after-tax cumulative effect of a change in accounting principle in the first quarter of 2003, related to recording a liability for the closure of an ash basin at Sunbury.
BALANCE SHEET - WPS RESOURCES
Compared with 2004
Accounts receivable increased $474.3 million (89.3%), from $531.3 million at December 31, 2004, to $1,005.6 million at December 31, 2005. Accounts receivable at ESI increased $396.5 million (96.0%), largely driven by a 53% increase in the average price of natural gas experienced in the fourth quarter of 2005, compared to the fourth quarter of 2004. A 27.1 % increase in natural gas volumes at ESI in the fourth quarter of 2005, compared to the fourth quarter of 2004, also contributed to the increase in accounts receivable. Accounts receivable at the regulated utilities increased $78.3 million (67.3%), largely due to a 49.7% per-unit increase in natural gas costs in the fourth quarter of 2005, compared to the fourth quarter of 2004. An 8.6% increase in retail electric rates combined with an 8.0% increase in electric sales volumes in the fourth quarter of 2005, compared to the fourth quarter of also contributed to the increase in accounts receivable at the regulated utilities.
Inventories increased $115.3 million (58.8%), from $196.1 million at December 31, 2004, to $311.4 million at December 31, 2005. The increase in inventories was primarily related to an $89.4 million (80.6%) increase in natural gas in storage at ESI and a $20.9 million (34.7%) increase in natural gas in storage at WPSC. Higher natural gas prices and a 22% increase in natural gas volumes in storage at ESI drove the increase in inventory at ESI. Volatility in the price of natural gas in the latter half of 2005 resulted in more natural gas storage opportunities, which drove the volume increase at ESI. The average per-unit price of natural gas purchased by WPSC increased 24.6% in 2005, compared to 2004, driving the increase in natural gas in storage at WPSC.
Current assets from risk management activities increased $529.9 million (140.7%), at December 31, 2005, compared to December 31, 2004, and current liabilities from risk management activities increased $514.2 million (151.9%). Long-term assets from risk management activities increased $151.9 million (203.6%), at December 31, 2005, compared to December 31, 2004, and long-term liabilities from risk management activities increased $125.9 million (201.4%). The increase in short-term and long-term risk management assets and liabilities was primarily related to increases in the forward price of natural gas and electricity. ESI also had more wholesale electric volumes under contract at December 31, 2005, compared to December 31, 2004.
Property, plant, and equipment, net, decreased $27.1 million to $2,049.4 million at December 31, 2005, compared to $2,076.5 million at December 31, 2004. The major contributors to the change in property, plant, and equipment are summarized below:
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Kewaunee was sold in 2005, driving a $165.4 million decrease in property, plant, and equipment.
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Depreciation expense of $142.8 million was recorded in 2005.
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WPSC sold a 30% interest in Weston 4, contributing an $83.9 million decrease to property, plant, and equipment.
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An impairment charge was recorded at Sunbury, contributing a $74.1 million decrease to property, plant, and equipment.
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Substantially offsetting these decreases, capital expenditures recorded in 2005 were $415.2 million, primarily related to the construction of Weston 4.
Nuclear decommissioning trusts decreased from $344.5 million at December 31, 2004 to $0 at December 31, 2005. The qualified decommissioning trust assets were sold along with the other Kewaunee assets (see Note 6, "Acquisitions and Sales of Assets," in WPS Resources' Notes to Consolidated Financial Statements for more information) and the nonqualified decommissioning trust assets were liquidated in connection with the Kewaunee sale.
Regulatory assets increased $111.1 million (69.0%), from $160.9 million at December 31, 2004, to $272.0 million at December 31, 2005, largely due to $56.4 million of costs that were deferred related to the unplanned outage at Kewaunee in 2005, a $26.2 million increase in the regulatory asset related to the minimum pension liability, deferral of $21.2 million of MISO charges, and a $6.3 million deferral of a portion of the loss on the sale of Kewaunee.
Other assets increased $51.9 million (14.9%), from $347.6 million at December 31, 2004, to $399.5 million at December 31, 2005. The increase in other assets was driven by a $72.7 million increase in WPS Resources' investment in ATC.
Accounts payable increased $489.5 million (83.1%), from $589.4 million at December 31, 2004, to $1,078.9 million at December 31, 2005. Accounts payable at ESI increased $403.0 million (91.8%), largely driven by the 53% increase in the average price of natural gas experienced in the fourth quarter of 2005, compared to the fourth quarter of 2004. Natural gas volumes at ESI also increased 27.1% in the fourth quarter of 2005, compared to the fourth quarter of 2004. Accounts payable at the utilities increased $86.2 million (57.6%), driven primarily by higher per-unit natural gas costs and higher per-unit fuel and purchased power costs in 2005, compared to 2004.
Other current liabilities increased $44.6 million (60.9%), from $73.2 million at December 31, 2004, to $117.8 million at December 31, 2005, primarily due to an accrued pension contribution of $25.3 million recorded at December 31, 2005. Accrued employee benefits and wages and customer prepayments also increased at December 31, 2005, compared to December 31, 2004.
Regulatory liabilities increased $84.9 million (29.4%), from $288.3 million at December 31, 2004, to $373.2 million at December 31, 2005, driven by a $126.9 million regulatory liability related to proceeds received from the liquidation of the nonqualified decommissioning trust in connection with the Kewaunee sale. The regulatory liability related to mark-to-market gains on derivative instruments also increased $25.4 million, primarily related to mark-to-market gains recorded on financial transmission rights related to our participation in MISO. These increases were partially offset by a $46.6 million decrease in the regulatory liability pertaining to the asset retirement obligation recorded related to the decommissioning of Kewaunee (as this plant was sold on July 5, 2005), and a $26.8 million reduction in deferred unrealized gains on decommissioning trust assets as the decommissioning trust assets were either liquidated or transferred in the sale of Kewaunee.
Asset retirement obligations decreased from $366.6 million at December 31, 2004, to $14.9 million at December 31, 2005, driven by the termination of our obligation to decommission Kewaunee (as this plant was sold on July 5, 2005).
LIQUIDITY AND CAPITAL RESOURCES - WPS RESOURCES
We believe that our cash balances, liquid assets, operating cash flows, access to equity capital markets and borrowing capacity made available because of strong credit ratings, when taken together, provide adequate resources to fund ongoing operating requirements and future capital expenditures related to expansion of existing businesses and development of new projects. However, our operating cash flow and access to capital markets can be impacted by macroeconomic factors outside of our control. In
addition, our borrowing costs can be impacted by short-term and long-term debt ratings assigned by independent rating agencies. Currently, we believe our ratings are among the best in the energy industry (see "Financing Cash Flows - Credit Ratings" below).
Operating Cash Flows
During 2005, net cash provided by operating activities was $62.4 million, compared to $230.8 million in 2004. The decrease was driven by a $98.2 million increase in cash required to fund working capital requirements, primarily at ESI. Net cash provided by operating activities also decreased due to various expenditures incurred in 2005 at WPSC, which will not be collected from ratepayers until future years. In 2005, expenditures incurred related to the unplanned Kewaunee outage were approximately $56 million, expenditures incurred related to MISO were approximately $21 million, and increased costs related to coal shortages were approximately $6 million (see Note 23, "Regulatory Environment," in WPS Resources' Notes to Consolidated Financial Statements for more information on these regulatory assets).
During 2004, net cash provided by operating activities was $230.8 million, compared with $59.2 million in 2003. The increase was driven by operating activities at ESI and WPSC. In 2003, operating activities at ESI used cash due primarily to increasing working capital requirements resulting from business growth and natural gas storage opportunities near the end of the year. ESI's natural gas operations did not experience the same level of growth in 2004 compared to 2003, and storage opportunities were similar at the end of both years, which enabled ESI to generate additional operating cash flow in 2004. The increase in net cash provided by operating activities at WPSC was driven by improved operating results.
Investing Cash Flows
Net cash used in investing activities decreased $241.1 million (76.5%), from $315.0 million in 2004 to $73.9 million in 2005. The decrease was driven by proceeds of $127.1 million received from the liquidation of the non-qualified decommissioning trust in connection with the Kewaunee sale, $112.5 million of proceeds received from the sale of Kewaunee, $111.5 million of proceeds received from the sale of Sunbury's emission allowances in 2005, and $95.1 million of proceeds received from DPC upon closing of the sale of a 30% ownership interest in Weston 4. The decreases were partially offset by a $122.8 million increase in capital expenditures (primarily related to the construction of Weston 4), purchases of emission allowances of $35.3 million (primarily related to operations at Sunbury), and a $30.3 million increase in the purchase of equity investments and other acquisitions, driven by a $41.3 million increase in WPS Resources' funding of ATC's Wausau, Wisconsin, to Duluth, Minnesota, transmission line in 2005, compared to 2004.
Net cash used for investing activities was $315.0 million in 2004, compared to $247.4 million in 2003. The increase was largely related to a $114.0 million increase in utility capital expenditures (see "Capital Expenditures" below), partially offset by a $50.4 million decrease in cash used for the purchase of equity investments and other acquisitions. Purchase of equity investments and other acquisitions consisted primarily of additional investments in ATC, capital contributions to ECO Coal Pelletization #12 LLC, and the acquisition of Advantage Energy in 2004. In 2003, purchase of equity investments and other acquisitions consisted primarily of WPSC's final payment for the purchase of the De Pere Energy Center, WPSC's purchase of a one-third interest in Guardian Pipeline, additional investments in ATC, and capital contributions to ECO Coal Pelletization. WPS Resources contributed capital of $15.7 million to ECO Coal Pelletization in 2004 and $14.0 million in 2003. See Note 6, "Acquisitions and Sales of Assets," in WPS Resources' Notes to Consolidated Financial Statements for more information.
Capital Expenditures
Capital expenditures by business segment for the years ended December 31, 2005, 2004, and 2003 are as follows:
The increase in capital expenditures at the electric utility in 2005 compared to 2004 is mainly due to higher capital expenditures associated with the construction of Weston 4. Gas utility capital expenditures decreased primarily due to the completion of the automated meter reading project.
The increase in capital expenditures at the electric utility in 2004 as compared to 2003 was mainly due to higher capital expenditures associated with the construction of Weston 4.
Financing Cash Flows
Net cash used for financing activities was $0.8 million in 2005, compared to net cash provided by financing activities of $73.5 million in 2004. Although cash provided by operating activities decreased in 2005, compared to 2004, this decrease was more than offset by a decrease in cash used for investing activities, related to proceeds received from various asset sales in 2005.
Net cash provided by financing activities was $73.5 million in 2004, compared to $195.6 million in 2003.
Less cash was required from financing activities as a result of the increase in cash generated from operating activities in 2004, partially offset by higher capital expenditures incurred in 2004.
Significant Financing Activities
WPS Resources had outstanding commercial paper borrowings of $254.8 million and $279.7 million at December 31, 2005, and 2004, respectively. WPS Resources had other outstanding short-term debt of $10.0 million and $12.7 million as of December 31, 2005, and 2004, respectively.
In 2005, 2004, and 2003 WPS Resources issued new shares of common stock under its Stock Investment Plan and under certain stock-based employee benefit and compensation plans. As a result of these plans, equity increased $29.0 million, $28.3 million, and $31.0 million in 2005, 2004, and 2003, respectively. WPS Resources did not repurchase any existing common stock during 2005 or 2004.
In November 2005, WPS Resources issued and sold 1.9 million shares of common stock at a public offering price of $53.70 per share. The proceeds to us were $98.3 million, net of underwriting discounts and commissions. The proceeds were used to reduce short-term debt, and fund equity contributions to subsidiary companies.
In June 2005, $62.9 million of non-recourse debt at an ESI subsidiary that was used to finance the purchase of Sunbury was restructured to a five-year WPS Resources obligation in connection with the sale of Sunbury's allocated emission allowances. An additional $2.7 million drawn on a line of credit at ESI was rolled into the five-year WPS Resources obligation. The floating interest rate on the total five-year WPS Resources' obligation of $65.6 million was fixed at 4.595% through two interest rate swaps.
In January 2004, WPSC retired $49.9 million of its 7.125% series first mortgage bonds. These bonds had an original maturity date of July 1, 2023.
In January 2004, WPS Resources retired $50.0 million of its 7.0% trust preferred securities. As a result of this transaction, WPSR Capital Trust I, a Delaware business trust, was dissolved.
WPSC issued $125.0 million of 4.80% 10-year senior notes in December 2003. The senior notes are collateralized by a pledge of first mortgage bonds and may become non-collateralized if WPSC retires all of its outstanding first mortgage bonds. The net proceeds from the issuance of the senior notes were used to call $49.9 million of 7.125% first mortgage bonds in January 2004, fund construction costs and capital additions, reduce short-term indebtedness, and for other corporate utility purposes.
In November 2003, 4,025,000 shares of WPS Resources' common stock were sold in a public offering at $43.00 per share, which resulted in a net increase in equity of $166.8 million. Net proceeds from this offering were used to retire the trust preferred securities in January 2004, reduce short-term debt, fund equity contributions to subsidiary companies, and for general corporate purposes.
In November 2003, ESI retired all of its notes payable under a revolving credit note, in the amount of $12.5 million.
WPSC called $9.1 million of 6.125% tax-exempt bonds in May 2003.
In March 2003, UPPCO retired $15.0 million of 7.94% first mortgage bonds that had reached maturity.
WPSC used short-term debt to retire $50.0 million of 6.8% first mortgage bonds on February 1, 2003, that had reached maturity.
Credit Ratings
WPS Resources and WPSC use internally generated funds and commercial paper borrowing to satisfy most of their capital requirements. WPS Resources also periodically issues long-term debt and common stock to reduce short-term debt, maintain desired capitalization ratios, and fund future growth. WPS Resources may seek nonrecourse financing for funding nonregulated acquisitions. WPS Resources' commercial paper borrowing program provides for working capital requirements of the nonregulated businesses and UPPCO. WPSC has its own commercial paper borrowing program. WPSC also periodically issues long-term debt, receives equity contributions from WPS Resources, and makes payments for return of capital to WPS Resources to reduce short-term debt, fund future growth, and maintain capitalization ratios as authorized by the PSCW. The specific forms of long-term financing, amounts, and timing depend on the availability of projects, market conditions, and other factors. The current credit ratings for WPS Resources and WPSC are listed in the table below.
Credit Ratings
Standard & Poor's
Moody's
WPS Resources
Senior unsecured debt
Commercial paper
Credit facility
A
A-1
-
A1
P-1
A1
WPSC
Senior secured debt
Preferred stock
Commercial paper
Credit facility
A+
A-
A-1
-
Aa2
A2
P-1
Aa3
In September 2005, Standard & Poor's had placed all of WPS Resources' and WPSC's credit ratings on CreditWatch with negative implications as a result of WPS Resources' announcement that it entered into a definitive agreement with Aquila to acquire its natural gas distribution operations in Michigan and
Minnesota. However, in January 2006, Standard & Poor's removed WPS Resources and WPSC from CreditWatch and affirmed WPS Resources' "A" corporate credit rating and "A" senior unsecured debt rating. Also, the corporate credit ratings of WPSC were affirmed at "A+" and removed from CreditWatch. Standard & Poor's stated that the consolidated ratings of WPS Resources reflected the strength and cash flow stability of its utility subsidiaries and the two relatively low risk natural gas utilities being acquired. The outlook continues to be negative for WPS Resources and WPSC as the companies have several events that must be successfully completed before the companies' performance can be considered stable. WPS Resources must successfully complete the integration of the retail natural gas operations it is acquiring in Michigan and Minnesota and WPSC must complete the construction of Weston 4 on time and on budget.
In September 2005, Moody's announced no change to the current ratings as a result of WPS Resources' announcement that it entered into a definitive agreement with Aquila to acquire its natural gas distribution operations in Michigan and Minnesota, but changed the rating outlook for WPS Resources and WPSC from stable to negative, citing a potential risk that the company's leverage may increase over the next several years.
In January 2005, Standard & Poor's downgraded its ratings for WPSC one ratings level and established a negative outlook. At the same time, Standard & Poor's affirmed WPS Resources' ratings but changed the outlook from stable to negative. In taking these actions, Standard & Poor's cited WPSC's substantial capital spending program and the risk profile of WPS Resources' nonregulated businesses.
In November 2003, Moody's downgraded its long-term ratings for WPS Resources and WPSC one ratings level, leaving only commercial paper ratings unchanged. Moody's downgrade of WPS Resources was based principally on a gradual shift in the company's financial and business risk profile attributable to the growth of nonregulated businesses, the impact of weaker wholesale power markets, and a relatively high dividend payout. Moody's downgrade of WPSC was based on the expectation that the utility's substantial capital spending program will exceed its retained cash flow through 2007, which is likely to lead to a meaningful increase in debt. Following the 2003 downgrade, Moody's set the ratings outlook at stable for both WPS Resources and WPSC.
We believe these ratings continue to be among the best in the energy industry and allow us to access commercial paper and long-term debt markets on favorable terms. Credit ratings are not recommendations to buy, are subject to change, and each rating should be evaluated independently of any other rating.
Rating agencies use a number of both quantitative and qualitative measures in determining a company's credit rating. These measures include business risk, liquidity risk, competitive position, capital mix, financial condition, predictability of cash flows, management strength, and future direction. Some of the quantitative measures can be analyzed through a few key financial ratios, while the qualitative ones are more subjective.
WPS Resources and WPSC hold credit lines to back 100% of their commercial paper borrowing and letters of credit. These credit facilities are based on a credit rating of A-1/P-1 for both WPS Resources and WPSC. A significant decrease in the commercial paper credit ratings could adversely affect the companies by increasing the interest rates at which they can borrow and potentially limiting the availability of funds to the companies through the commercial paper market. A restriction in the companies' ability to use commercial paper borrowing to meet their working capital needs would require them to secure funds through alternate sources resulting in higher interest expense, higher credit line fees, and a potential delay in the availability of funds.
ESI maintains underlying agreements to support its electric and natural gas trading operations. In the event of a deterioration of WPS Resources' credit rating, many of these agreements allow the counterparty to demand additional assurance of payment. This provision could pertain to existing business, new business, or both with the counterparty. The additional assurance requirements could be met with letters of credit, surety bonds, or cash deposits and would likely result in WPS Resources being
required to maintain increased bank lines of credit or incur additional expenses, and could restrict the amount of business ESI would be able to conduct.
ESI uses the New York Mercantile Exchange (NYMEX) and over-the-counter financial markets to mitigate its exposure to physical customer obligations. These contracts are closely correlated to the customer contracts, but price movements on the contracts may require financial backing. Certain movements in price for contracts through the NYMEX exchange require posting of cash deposits equal to the market move. For the over-the-counter market, the underlying contract may allow the counterparty to require additional collateral to cover the net financial differential between the original contract price and the current forward market. Increased requirements related to market price changes usually only result in a temporary liquidity need that will unwind as the sales contracts are fulfilled.
Future Capital Requirements and Resources
Contractual Obligations
The following table summarizes the contractual obligations of WPS Resources', including its subsidiaries.
Long-term debt principal and interest payments represent bonds issued, notes issued, and loans made to WPS Resources and its subsidiaries. We record all principal obligations on the balance sheet. Commodity purchase obligations represent mainly commodity purchase contracts of WPS Resources and its subsidiaries. Energy supply contracts at ESI included as part of commodity purchase obligations are generally entered into to meet obligations to deliver energy to customers. WPSC and UPPCO expect to recover the costs of their contracts in future customer rates. Purchase orders include obligations related to normal business operations and large construction obligations, including 100% of Weston 4 obligations. The sale of a 30% interest in Weston 4 to DPC was completed in November 2005, but WPSC retains the legal obligation to initially remit payment to third parties for 100% of all construction costs incurred, 30% of which will subsequently be billed to DPC. Capital contributions to equity method investment include our commitment to fund a portion of ATC's Wausau, Wisconsin, to Duluth, Minnesota, transmission line together with ATC. The table above does not reflect obligations under the definitive agreement with Aquila to acquire its natural gas distribution operations in Michigan and Minnesota, which are discussed in Note 6, "Acquisitions and Sales of Assets," in WPS Resources' Notes to Consolidated Financial Statements. Other mainly represents expected pension and postretirement funding obligations.
Capital Requirements
WPSC makes large investments in capital assets. Net construction expenditures are expected to be $856.5 million in the aggregate for the 2006 through 2008 period, not including obligations under the definitive agreement with Aquila. The largest of these expenditures is for the construction of Weston 4. WPSC is expected to incur costs of approximately $278 million from 2006 through 2008 related to its 70% ownership interest in this facility.
As part of its regulated utility operations, on September 26, 2003, WPSC submitted an application for a Certificate of Public Convenience and Necessity to the PSCW seeking approval to construct Weston 4, a 500-megawatt coal-fired generation facility near Wausau, Wisconsin. The facility is estimated to cost approximately $779 million (including the acquisition of coal trains), of which WPSC is responsible for slightly more than 70% (approximately $549 million) of the costs. In November 2005, DPC purchased a 30% ownership interest in Weston 4, remitting proceeds of $95.1 million for its share of the construction costs (including carrying charges) as of the closing date of the sale. WPSC is responsible for slightly more than 70% of the costs because of certain common facilities that will be installed as part of the project. WPSC will have a larger than 70% interest in these common facilities. DPC will be billed by WPSC for 30% of all remaining costs to complete the construction of the plant. As of December 31, 2005, WPSC has incurred a total cost of $271.6 million related to its ownership interest in the project. In addition to the costs discussed above, WPSC expects to incur additional construction costs through the date the plant goes into service of approximately $61 million to fund construction of the transmission facilities required to support Weston 4. ATC will reimburse WPSC for the construction costs of these transmission facilities and related carrying costs when Weston 4 becomes commercially operational, which is expected to occur in June 2008.
Other significant anticipated construction expenditures for WPSC during the three-year period through 2008 include approximately $310 million of electric distribution projects (including replacement of utility poles, transformers, meters, etc.), environmental projects of approximately $167 million, other expenditures at WPSC generation plants to ensure continued reliability of these facilities of approximately $63 million, and corporate services infrastructure projects of approximately $33 million.
On April 18, 2003, the PSCW approved WPSC's request to transfer its interest in the Wausau, Wisconsin, to Duluth, Minnesota, transmission line to ATC. WPS Resources committed to fund 50% of total project costs incurred up to $198 million. WPS Resources will receive additional equity in ATC in exchange for the project funding. WPS Resources may terminate funding if the project extends beyond January 1, 2010. The total cost of the project is estimated at $420.3 million and it is expected that the line will be completed and placed in service in 2008. WPS Resources has the right, but not the obligation, to provide additional funding in excess of $198 million up to 50% of the revised cost estimate. However, WPS Resources' future funding of the line will be reduced by the amount funded by Allete, Inc. Allete has exercised an option to fund a portion of WPS Resources' commitment and is expected to fund $60 million of the project cost in 2006. Considering this, for the period 2006 through 2008, WPS Resources expects to fund up to approximately $61 million for its portion of the Wausau to Duluth transmission line.
WPS Resources expects to provide additional capital contributions to ATC of approximately $78 million for the period 2006 through 2008 for other projects.
UPPCO is expected to incur construction expenditures of about $48 million in the aggregate for the period 2006 through 2008, primarily for electric distribution improvements and repairs and safety measures at hydroelectric facilities.
Capital expenditures identified at ESI for 2006 through 2008 are expected to be approximately $22 million, largely due to scheduled major maintenance projects at ESI's generation facilities, and computer equipment related to business expansion and normal technology upgrades.
All projected capital and investment expenditures are subject to periodic review and revision and may vary significantly from the estimates depending on a number of factors, including, but not limited to, industry restructuring, regulatory constraints, acquisition opportunities, market volatility, and economic trends. Other capital expenditures for WPS Resources and its subsidiaries for 2006 through 2008 could be significant depending on its success in pursuing development and acquisition opportunities. When appropriate, WPS Resources may seek nonrecourse financing for a portion of the cost of these acquisitions.
Capital Resources
As of December 31, 2005, both WPS Resources and WPSC were in compliance with all of the covenants under their lines of credit and other debt obligations.
For the period 2006 through 2008, WPS Resources plans to use internally generated funds net of forecasted dividend payments, cash proceeds from asset sales, and debt and equity financings to fund capital requirements. WPS Resources plans to maintain debt to equity ratios at appropriate levels to support current credit ratings and corporate growth. Management believes WPS Resources has adequate financial flexibility and resources to meet its future needs.
WPS Resources currently has the ability to issue up to $200 million of debt and/or equity under its existing shelf registration statement. WPSC currently has the ability to issue up to an additional $375 million of debt under its existing shelf registration statements. The shelf registrations are subject to the ultimate terms and conditions to be determined prior to the actual issuance of specific securities.
In November 2005, WPS Resources entered into two unsecured revolving credit agreements of $557.5 million and $300 million with J.P. Morgan Chase Bank and Banc of America Securities LLC. These credit facilities are bridge facilities intended to backup commercial paper borrowings related to the purchase of the Michigan and Minnesota natural gas distribution operations from Aquila and to support purchase price adjustments related to working capital at the time of the closing of the transactions. The capacity under the bridge facilities will be reduced by the amount of proceeds from any long-term financing we complete prior to closing, with the exception of proceeds from the November 2005 equity offering. The credit agreements will be further reduced as permanent or replacement financing is secured. Under the $300 million credit agreement, loans cannot exceed the purchase price adjustments in connection with the Aquila acquisitions and no more than $200 million can be borrowed at the time of the first acquisition. Under the $300 million facility, these loan commitments will be reduced by one-third 90 days after the consummation of the applicable acquisition with the remaining two-thirds due 180 days after the consummation of the applicable acquisition (or earlier if long-term financing or replacement credit agreements are executed). Both of these credit agreements mature on September 5, 2007. These credit agreements have representations and covenants that are similar to those in our existing credit facilities.
In November 2005, WPS Resources entered into a forward equity sale agreement with an affiliate of J.P. Morgan Securities, Inc., as forward purchaser, relating to 2.7 million shares of WPS Resources' common stock. In connection with the forward agreement, and at WPS Resources' request, J.P. Morgan Securities borrowed an equal number of shares of WPS Resources' common stock from stock lenders and sold the borrowed shares to the public. Subject to certain exceptions, WPS Resources has the right to elect physical or cash settlement of the forward sale agreement on a date or dates to be specified by WPS Resources within approximately one year of the date of the public offering. WPS Resources expects to physically settle the forward agreement and use the proceeds to partially finance the proposed acquisition of the Michigan and Minnesota natural gas distribution operations from Aquila and for general corporate purposes. If the forward agreement would have been physically settled by delivery of shares at December 31, 2005, WPS Resources would have received $139.3 million, based on the December 31, 2005, forward share price of $51.58 per share for the 2.7 million shares, net of underwriting discounts and commissions. See Note 21, "Common Equity," in WPS Resources' Notes to Consolidated Financial Statements for more information on settlement methods. The use of a forward agreement allowed WPS Resources to avoid market uncertainty by pricing a stock offering under then existing market conditions, while mitigating share dilution by postponing the issuance of stock until funds are needed.
In June 2005, WPS Resources entered into an unsecured $500 million 5-year credit agreement. This revolving credit line replaces the former 364-day credit line facilities, which had a borrowing capacity of $400 million. WPSC also entered into a new 5-year credit facility, for $115 million, to replace its former 364-day credit line facility for the same amount. The credit lines are used to back 100% of WPS Resources' and WPSC's commercial paper borrowing programs and the majority of letters of credit
for WPS Resources and WPSC. As of December 31, 2005, there was a total of $249.1 million and $36.2 million available under WPS Resources' and WPSC's credit lines, respectively.
Other Future Considerations
Agreement to Purchase Aquila's Michigan and Minnesota Natural Gas Distribution Operations
On September 21, 2005, WPS Resources, through wholly owned subsidiaries, entered into two definitive agreements with Aquila to acquire its natural gas distribution operations in Michigan and Minnesota for approximately $558 million, exclusive of direct costs of the acquisition. The purchase price will increase for certain adjustments related to working capital, including accounts receivable, unbilled revenue, inventory, and certain other current assets. The purchase price is also subject to other closing and post-closing adjustments, primarily net plant adjustments.
The Michigan natural gas assets provide natural gas distribution service to about 161,000 customers in 147 cities and communities throughout Otsego, Grand Haven, and Monroe counties. Annual natural gas throughput for the Michigan natural gas assets are approximately half those of the Minnesota natural gas assets. The assets operate under a cost-of-service environment and are currently allowed an 11.4% return on equity on a 45% equity component of the regulatory capital structure.
The Minnesota natural gas assets provide natural gas distribution service to about 200,000 customers throughout the state in 165 cities and communities including Grand Rapids, Pine City, Rochester, and Dakota County. Annual natural gas throughput volumes have historically been just slightly less than throughput volumes experienced by WPSC's natural gas utility. Like Michigan, the assets also operate under a cost-of-service environment and are currently allowed an 11.7% return on equity on a 50% equity component of the regulatory capital structure.
WPS Resources anticipates permanent financing for the acquisition to be raised through the issuance of a combination of equity and long-term debt. See "Capital Resources" above and Note 21, "Common Equity" in WPS Resources' Notes to Consolidated Financial Statements, for a discussion of the forward equity sale agreement entered into to fund a portion this acquisition.
The transaction is subject to various state and other regulatory approvals, such as the MPSC and the Minnesota Public Utilities Commission, and is subject to compliance with the Hart-Scott-Rodino Act. MPSC approval was received in November 2005 and the waiting period under the Hart-Scott-Rodino Act has expired. Assuming an approval from the Minnesota Public Utilities Commission is obtained in a timely manner, WPS Resources anticipates closing both transactions in the first half of 2006.
WPS Resources anticipates maintaining its current dividend policy following the closing.
Sunbury
WPS Resources made capital contributions of $1.0 million to Sunbury in 2005. In 2004, WPS Resources made capital contributions of $24.5 million to Sunbury. Contributions made in 2005 were necessary to meet certain working capital requirements. In 2004, the capital contributions were used to cover operating losses, make principal and interest payments on debt, and purchase emission allowances. In 2004, WPS Resources' Board of Directors granted authorization to contribute up to $32.8 million of capital to Sunbury. At December 31, 2005, $7.3 million of the originally authorized amount remains available for contribution. Financial results for Sunbury have improved in 2005, compared to 2004, primarily due to more opportunities to sell power into the market as the result of the expiration of a fixed price out-take contract on December 31, 2004. Current energy market prices are significantly higher than the fixed price received under the expired contract.
The sale of Sunbury's allocated emission allowances was completed in May 2005. Total sales proceeds of $109.9 million were utilized by Sunbury to eliminate its nonrecourse debt obligation, which was subsequently restructured as a WPS Resources' obligation in 2005, which provides ESI with flexibility to consider various alternatives for the plant. All available solid fuel units at the Sunbury plant were operated for most of 2005, as market conditions were generally favorable. When market conditions are unfavorable, ESI plans to place the plant in a stand-by mode of operation, which serves to minimize future operating expenses while maintaining several options for the plant (including closing the plant, retaining the plant and operating it during favorable economic periods, or a potential future sale of the plant). Dispatching Sunbury in a stand-by mode of operation helps focus production on higher-priced periods, generally in the winter and mid-summer months. The success of a stand-by mode of operation depends on Sunbury's ability to minimize costs during non-operating periods.
Kewaunee
See Note 6, "Acquisitions and Sale of Assets," in WPS Resources' Notes to Consolidated Financial Statements for information related to the Kewaunee sale.
See Note 23, "Regulatory Environment," in WPS Resources' Notes to Consolidated Financial Statements for an update on deferrals related to Kewaunee.
Beaver Falls
ESI's Beaver Falls generation facility in New York has been out of service since late June 2005. The unplanned outage was caused by the failure of the first stage turbine blades. Inclusive of estimated insurance recoveries, ESI estimates, at this time, that it will cost between $3 and $5 million to repair the turbine and replace the damaged blades. Depending on the amount of insurance recovery, ESI could incur significantly higher net out-of-pocket costs than originally estimated to repair the damage. In addition, ESI is attempting to renegotiate an existing steam off-take agreement with a counterparty, which will significantly impact its ability to recover costs. If significant repair costs are not recoverable through insurance or ESI is not able to renegotiate the terms of the steam off-take agreement, then a possibility exists that ESI would not repair the plant, in which case the undiscounted cash flows related to future operations may be insufficient to recover the carrying value of the plant, resulting in impairment. The carrying value of the Beaver Falls generation facility at December 31, 2005 was $18.1 million.
Asset Management Strategy
As a part of our asset management strategy, in December 2005, UPPCO sold a portion of its real estate holdings that were no longer needed for operations. See Note 6, "Acquisitions and Sales of Assets," in WPS Resources Footnotes to Consolidated Financial Statements for more information. WPS Resources continues to evaluate alternatives for the sale of the balance of our identified real estate holdings no longer needed for operation.
Regulatory Matters and Rate Trends
Under the prevailing Wisconsin fuel rules, WPSC's 2006 electric rates are subject to adjustment when electric generation fuel and purchased power costs fall outside of a pre-determined band. This band is set at +2.0% and -0.5%, for 2006 by the PSCW. Because a significant portion of WPSC's electric load is served by natural gas-fired generation, the volatile nature of natural gas prices, and the relatively narrow tolerance band in Wisconsin, the likelihood for an electric rate adjustment in 2006 in Wisconsin is strong. Any such rate adjustment would be on a prospective basis only and could impact WPSC's operating results. To mitigate the risk of the potential for unrecoverable fuel costs in 2006 due to market price volatility, WPSC is employing risk management techniques pursuant to its PSCW approved Risk Policy, including the use of derivative instruments such as futures and options.
The price of natural gas is currently high compared to historical levels. While the WPSC gas utility is authorized one-for-one recovery of prudently incurred natural gas costs in both the Wisconsin and
Michigan jurisdictions, the currently high natural gas rates could impact the ability of retail customers to pay for natural gas service and, therefore, increase WPSC's write-offs during 2006.
In WPSC's 2006 retail electric rate proceeding, the PSCW applied a "financial harm" test when considering the rate recovery of deferred costs previously authorized for accounting purposes. While the application of a financial harm test is authorized, it has not been applied in the past by the PSCW when considering the rate recovery of costs that were previously authorized for deferral. In WPSC's 2006 rate proceeding, after applying the financial harm test, the PSCW disallowed rate recovery of the 2004 extended outage at Kewaunee. The PSCW also disallowed recovery of 50% of the pre-tax loss realized on the sale of Kewaunee. None of these disallowed costs were found to be imprudent by the PSCW. In light of the PSCW's decision, WPSC still believes it is probable that all regulatory assets recorded at December 31, 2005, will be able to be collected from ratepayers.
For a discussion of regulatory filings and decisions, see Note 23, "Regulatory Environment," in WPS Resources' Notes to Consolidated Financial Statements.
See Note 9, "Regulatory Assets and Liabilities," in WPS Resources' Notes to Consolidated Financial Statements for a list of regulatory assets recorded at December 31, 2005.
Industry Restructuring
-Ohio-
In May 1999, the Ohio Legislature passed Senate Bill 3, which introduced market-based rates and instituted competitive retail electric services. The bill also established a market development period beginning January 1, 2001, and extending no later than December 31, 2005, after which rates would be set at market-based prices. During this market development period, ESI contracted to be the supplier for approximately 100,000 residential, small commercial, and government facilities in the FirstEnergy service areas under the State of Ohio provisions for Opt-out Electric Aggregation Programs.
The Public Utilities Commission of Ohio requested the Ohio electric distribution utilities to file rate stabilization plans covering the 2006-2008 time period to avoid rate shock at the end of the market development period. A plan submitted by FirstEnergy established electric rates for consumers beginning in 2006 if a competitive bid auction ordered by the Public Utilities Commission of Ohio did not produce better benefits. The price resulting from an auction conducted on December 8, 2004, was inadequate. Because the FirstEnergy plan is priced lower than current market power prices, ESI took final meter readings and discontinued service to customers of the existing aggregation programs with the expiration of those contracts in December 2005.
On September 23, 2004, an Ohio House Bill was introduced, proposing a change to the electric restructuring law. The bill proposes to give the Public Utilities Commission of Ohio explicit authority to implement rate stabilization plans in certain circumstances. The Ohio Senate held meetings during March 2005 to hear from all parties involved as they develop a statewide energy policy (natural gas and electric). The Senate heard and considered such issues as rolling back Senate Bill 3, pushing ahead with electric deregulation, and the need for rate-based utility construction of new power plants in the state. In addition to the electric issues, the Senate also heard about natural gas issues. ESI participated and testified, urging the Senate to move forward to implement a competitive environment. ESI remains prepared to offer future retail electric service in Ohio as the regulatory climate and market conditions allow.
-Michigan-
Under the current Electric Choice program in Michigan, ESI, through its subsidiary, established itself as a significant supplier to the industrial and commercial markets. However, recent high wholesale energy prices coupled with both approved and pending tariff changes for the regulated utilities significantly lowered the savings customers can obtain from contracting with non-utility suppliers. As a result, many customers returned to the bundled tariff service of the incumbent utility. The high wholesale energy prices and tariff changes caused a reduction in new business and renewals for ESI. ESI's Michigan retail electric business as of the beginning of 2006 declined to approximately one-third the peak megawatts it was at the start of 2005. The MPSC is expected to provide orders in two significant proceedings by the end of 2006 that will clarify the outlook for Electric Choice.
The status of Michigan's electric markets has been the subject of hearings in both the Senate and House Energy Committees. If legislation rolling back the Electric Choice market is enacted, it could diminish the benefits of competitive supply for Michigan business customers. The impact on ESI could range from maintaining Michigan business with little or no growth to an inability to re-contract any business, leading to a possible decision by ESI to exit Michigan's electric market and redirect resources to more vibrant markets. It is not unreasonable to expect changes, either from the legislature or the MPSC, to have some level of negative impact on ESI, but it is unlikely that Michigan customers will lose all of the benefits of competition and revert back to a fully regulated monopoly supply. ESI is actively participating in the legislative and regulatory process in order to protect its interests in Michigan.
Expansion of Operations into Texas
In the fourth quarter of 2005, ESI began developing a product offering in the Texas retail electric market. Due to the thriving Texas market structure (unencumbered by a regulated offering that is not market based) and having been presented with a good opportunity and approach to enter the Texas retail market, ESI hired experienced personnel in that region and expects to be an approved competitive supplier before the end of the second quarter of 2006. ESI previously had a market presence in Houston with natural gas producer services originators. While historically, ESI limited its retail activities to the northeastern quadrant of the United States and the adjacent portion of Canada, the entry into the Texas market offers an opportunity to leverage the infrastructure and capability ESI developed to provide products and services that it believes customers will value.
Seams Elimination Charge Adjustment
Through a series of orders issued by the FERC, Regional Through and Out Rates for transmission service between the MISO and the PJM Interconnection were eliminated effective December 1, 2004. To compensate transmission owners for the revenue they will no longer receive due to this elimination, the FERC ordered a transitional pricing mechanism called the Seams Elimination Charge Adjustment (SECA) to be put into place. Load-serving entities will pay these SECA charges during a 16-month transition period from December 1, 2004, through March 31, 2006. ESI is a load-serving entity and will be billed based on its power imports into MISO from PJM during 2002 and 2003. Total exposure for the 16-month transitional period, taken from proposed compliance filings by the transmission owners, is approximately $19 million for ESI, of which approximately $17 million is for Michigan and approximately $2 million is for Ohio. Through December 31, 2005, ESI has made payments totaling $15.3 million for these charges, of which $11.1 million has been expensed.
On February 10, 2005, the FERC issued an order requesting compliance filings from transmission providers implementing the SECA effective December 1, 2004, subject to refund and surcharge, as appropriate. The application and legality of the SECA is being challenged by many load-serving entities, including ESI. On February 28, 2005, ESI filed a motion for a Partial Stay of the February 10, 2005, FERC order, proposing that SECA charges on its Michigan load be postponed until a FERC order approves a decision or settlement in the formal hearing proceeding. The FERC denied this motion on May 4, 2005. On June 3, 2005, ESI filed with the FERC a request for rehearing of the order denying stay. ESI also participated in a joint petition to the District of Columbia Circuit Court in an attempt to obtain a
final order from the FERC on rehearing of the initial SECA order. This joint petition was denied. In the interim, the exposure will be managed through customer charges and other available avenues, where feasible. It is probable that ESI's total exposure will be reduced by at least $4.2 million because of inconsistencies between the FERC's SECA order and the transmission owners' compliance filings (representing the difference between the amount ESI has paid for SECA charges and the amount that has been expensed as of December 31, 2005, as discussed above). ESI anticipates settling a significant portion of its SECA matters through vendor negotiations in the first half of 2006 and reached a $1 million settlement agreement with one of its vendors in January 2006. Resolution of issues to be raised in the SECA hearing offer the possibility of further reductions in ESI's exposure, but the extent is unknown at present. Through existing contracts, ESI has the ability to pass a portion of the SECA charges on to customers and has been doing so. Since SECA is a transition charge ending on March 31, 2006, it does not directly impact ESI's long-term competitiveness.
The SECA is also an issue for WPSC and UPPCO, who have intervened and protested a number of proposals in this docket because those proposals could result in unjust, unreasonable, and discriminatory charges for electric customers. It is anticipated that most of the SECA charges and any refunds will be passed to customers through rates.
Coal Supply
In May 2005, WPSC received notification from its coal transportation suppliers that extensive maintenance was required on the railroad tracks that lead into and out of the Powder River Basin in Wyoming. The extensive maintenance ended on November 23, 2005. During the maintenance efforts, WPSC received approximately 87% of its expected coal deliveries. WPSC took steps to conserve coal usage and secured alternative coal supplies at its affected generation facilities during that time. On September 23, 2005, the PSCW approved WPSC's request for deferred treatment of the incremental fuel costs resulting from the coal supply issues. As of December 31, 2005, $6.4 million was deferred related to this matter. These costs are expected to be addressed in WPSC's next retail electric rate case.
The Union Pacific Railroad experienced a number of force majeure events in December 2005 and January 2006, including a software conversion problem and heavy snow falls. WPSC is closely monitoring the delivery of coal to its power plants and is analyzing options to be prepared if future coal deliveries are constrained.
Income Taxes
-American Jobs Creation Act of 2004-
On October 22, 2004, the President of the United States signed into law the American Jobs Creation Act of 2004 (2004 Jobs Act). The 2004 Jobs Act introduces a new tax deduction, the "United States production activities deduction." This domestic production provision allows as a deduction an amount equal to a specified percent of the lesser of the qualified production activities income of the taxpayer for the taxable year or taxable income for the taxable year. The deduction is phased in, providing a deduction of 3% of income through 2006, 6% of income through 2009, and 9% of income after 2009. On December 8, 2004, the PSCW issued an order authorizing WPSC to defer the revenue requirements impacts resulting from the 2004 Jobs Act. WPSC has recorded the estimated tax impact of this deduction in its financial statements for the year ended December 30, 2005. However, the majority of the tax benefits derived were deferred and will be passed on to customers in future rates.
-Section 29 Federal Tax Credits-
We have significantly reduced our consolidated federal income tax liability through tax credits available to us under Section 29 of the Internal Revenue Code for the production and sale of solid synthetic fuel from coal. These tax credits are scheduled to expire at the end of 2007 and are provided as an incentive for taxpayers to produce fuel from alternate sources and reduce domestic dependence on imported oil. This incentive is not deemed necessary if the price of oil increases sufficiently to provide a natural market for the fuel. Therefore, the tax credits in a given year are subject to phase out if the annual average reference price of oil within that year exceeds a minimum threshold price set by the Internal Revenue Service (IRS) and are eliminated entirely if the average annual reference price increases beyond a maximum threshold price set by the IRS. The reference price of a barrel of oil is an estimate of the annual average wellhead price per barrel for domestic crude oil, which has in recent history been approximately $6 below the NYMEX price of a barrel of oil. The threshold price at which the credit begins to phase out was set in 1980 and is adjusted annually for inflation; the IRS releases the final numbers for a given year in the first part of the following year.
Numerous events have increased domestic crude oil prices, including concerns about terrorism, storm-related supply disruptions, and worldwide demand. Therefore, in order to manage exposure to the risk of an increase in oil prices that could reduce the amount of Section 29 federal tax credits that could be recognized, ESI entered into a series of derivative contracts, beginning in the first quarter of 2005, covering a specified number of barrels of oil. While no apparent phase-out of Section 29 federal tax credits occurred in 2005, ESI had mitigated essentially all of its 2005 phase-out risk at no net cost. Through optimization strategies, ESI realized a $0.3 million gain on oil options entered into to mitigate the 2005 phase-out risk, net of premium amortization. If no phase-out were to occur in 2006 and 2007, ESI would expect to recognize approximately $24 million of Section 29 federal tax credits in each of the next two years. Based upon forward oil prices, we are anticipating significant phase-outs of 2006 and 2007 Section 29 federal tax credits. However, we cannot predict with certainty the future price of a barrel of oil and, therefore, have no way of knowing what portion of our tax credits will be phased out, or if any phase out will result. Based upon the average annual NYMEX price of a barrel of oil, ESI estimates that Section 29 federal tax credits will begin phasing out if the annual average NYMEX price of a barrel of oil reaches approximately $60, with a total phase out if the annual average NYMEX price of a barrel of oil reaches approximately $73.
At December 31, 2005, ESI had derivative contracts that mitigate substantially all of the Section 29 tax credit exposure in 2006 and 40% of the exposure in 2007. The derivative contracts involve purchased and written call options that provide for net cash settlement at expiration based on the average NYMEX trading price of oil in relation to the strike price of each option. Premiums paid for options to mitigate exposure to Section 29 federal tax credit phase out in and 2007 totaled $15.3 million ($12.0 million for 2006 options and $3.3 million for 2007 options), all of which are recorded as risk management assets on the balance sheet. Essentially, ESI has paid $12.0 million for options ($7.2 million after-tax) to protect the value of approximately $24 million of tax credits in 2006 and $3.3 million for options ($2.0 million after-tax) to protect the value of approximately $10 million of tax credits in 2007. ESI has not hedged $14 million of 2007 tax credits; however, ESI will continue to look for opportunities to mitigate the exposure on the remaining 2007 tax credits. As annual average oil prices become more transparent and if opportunities arise, ESI will also look for ways to lower its investment in derivative instruments utilized to protect its Section 29 federal tax credits. The derivative contracts have not been designated as hedging instruments and, as a result, changes in the fair value of the options are recorded currently in earnings. This could result in mark-to-market gains being recognized in earnings in different periods, compared to the offsetting tax credit phase-outs. For example, as of December 31, 2005, unrealized pre-tax mark-to-market gains of $4.0 million and $4.4 million were recorded for the 2006 and 2007 options, respectively, while no tax credit phase-out was recognized because and 2007 tax credits are not recognized until fuel is produced and sold in those periods. In 2006, ESI will only record Section 29 federal tax credits expected to be recognized, based upon the expected annual average price of a barrel of oil.
In addition to exposure to federal tax credits, ESI has also historically received royalties tied to the amount of synthetic fuel produced as well as variable payments from a counterparty related to its 30% sell-down of ECO Coal Pelletization #12 in 2002. Royalties and variable payments contributed $7.1 million, $7.6 million, and $5.9 million to income before taxes in 2005, 2004, and 2003, respectively. Royalties and variable payments received in 2006 and 2007 could decrease if a phase-out occurs and synthetic fuel production is reduced.
The following table shows the total impact ESI's investment in the synthetic fuel production facility had on the Consolidated Statements of Income. See Note 6, "Acquisitions and Sales of Assets," in WPS Resources Notes to Consolidated Financial Statements for more information on these items.
-Peshtigo River Land Donation-
In 2004, WPS Resources submitted a request to have the IRS conduct a pre-filing review of a tax position related to its 2004 tax return. The tax position related to the value of the Peshtigo River land donated to the WDNR in 2004. A pre-filing review of the land donation deduction was initiated by the IRS in the first quarter of 2005; however, in the second quarter, WPS Resources and the IRS mutually agreed to withdraw this issue from the pre-filing review process, citing an inability to reach a consensus on the tax treatment and value of the land donated. In 2004, WPS Resources recorded a $4.1 million income tax benefit related to the Peshtigo River land donation. We believe our position is appropriate and will pursue this matter if challenged by the IRS upon examination of the tax return.
Environmental
See Note 17, "Commitments and Contingencies," in WPS Resources' Notes to Consolidated Financial Statements for a detailed discussion of environmental considerations.
Energy and Capacity Prices
Prices for electric energy and capacity have been extremely volatile over the past three years. WPS Resources' nonregulated entities are impacted by this volatility, which has been driven by the exit of many of the largest speculative traders, equilibrium between natural gas supply and demand, changes in the economy, and significant overbuilding of generation capacity.
Increased natural gas prices for fuel used in electric generation have caused current electric energy prices to increase significantly. Electric capacity prices, however, are expected to be depressed for several years. Pressure on capacity prices will continue until existing reserve margins are depleted either by load growth or capacity retirements. Market structure changes could also significantly influence capacity prices. ESI's generation facilities have been negatively impacted by the depressed capacity prices; however, certain plants within ESI have been positively impacted by the high energy prices discussed above.
Midwest Independent Transmission System Operator
WPSC, UPPCO, and ESI are members of the MISO, which introduced its "Day 2" energy markets on April 1, 2005, when it began centrally dispatching wholesale electricity along with providing transmission service throughout much of the Midwest. The new market is based on a locational marginal pricing system, which is similar to that used by the PJM regional transmission organization. The pricing mechanism expands the existing market from a physical market to also include financial instruments and is intended to send price signals to stakeholders where generation or transmission system expansion is needed. Based upon the early results of the transition, it does not appear that the new market will have a material ongoing impact on the financial results of WPS Resources. WPS Resources will continue to work closely with the MISO and the FERC to ensure that any issues are dealt with such that any adverse financial impacts continue to be minimal. WPSC has been granted approval by the PSCW to defer most costs and benefits related to the new market for inclusion in future rates for its Wisconsin retail electric customers. Most costs and benefits related to WPSC's and UPPCO's Michigan and wholesale electric customers will also flow through fuel adjustment mechanisms.
Although the market is running well so far, there are still market issues that must be resolved. MISO Day 2 has the potential to significantly impact the cost of transmission for eastern Wisconsin and the Upper Peninsula of Michigan system, including WPSC and UPPCO, as well as our marketing affiliates in the MISO footprint, such as ESI. Under this market-based approach, where there is abundant transmission capacity, overall costs should be less due to the ability to access cheaper generation from across the MISO footprint. For areas with narrowly constrained transmission capacity, such as Wisconsin and the Upper Peninsula of Michigan, costs could be higher due to the congestion and marginal loss pricing components. For the utilities in eastern Wisconsin and the Upper Peninsula of Michigan, mechanisms have been deployed to offset these potential increased costs in the first five years of the Day 2 market. If the market works appropriately, the costs to ESI, excluding the SECA (discussed above), should be similar to the pre-Day 2 market costs. If there are incremental costs or savings to WPSC and UPPCO, they will be passed through to our customers under existing tariffs. WPSC and UPPCO received approval from their respective commissions to defer costs associated with implementation of the MISO Day 2 market ($21.2 million has been deferred through December 31, 2005); however, WPSC and UPPCO face regulatory risk associated with being able to collect these costs from customers in future periods.
WPSC has established an energy market risk policy and a risk management plan to facilitate utilization of financial instruments for managing market risks associated with the Day 2 energy market. The PSCW has approved this plan, allowing WPSC to pass the costs and benefits of several specific risk management strategies through the PSCW's fuel rules, deferral, or escrow processes. As of December 31, 2005, risk mitigation opportunities have been limited due to the current high price of energy.
MISO participants offer their generation and bid their demand into the market on an hourly basis. This results in net receipts from or net obligations to MISO for each hour of each day. MISO aggregates these hourly transactions and currently provides updated settlement statements to market participants 7, 14, 55, 105, and days after each operating day. MISO also indicated that it may begin performing a 365-day settlement run on April 1, 2006. The 365-day settlement statements could continue until all operating day transactions from April 1, 2005 through August 31, 2005 have been resettled. These updated settlement statements may reflect billing adjustments, resulting in an increase or decrease to the net receipt from or net obligation to MISO, which may or may not be recovered through the rate recovery process. These updated settlement statements and related charges may be disputed by market participants.
At the end of each month, the amount due from or payable to MISO is estimated for those operating days where a 7-day settlement statement is not yet available, thus significant changes in the estimates and new information provided by MISO in subsequent settlement statements could have a material impact on our results of operations.
New Accounting Pronouncements
See Note 1(w), "New Accounting Pronouncements," in WPS Resources' Notes to Consolidated Financial Statements for a detailed discussion of new accounting pronouncements.
GUARANTEES AND OFF BALANCE SHEET ARRANGEMENTS - WPS RESOURCES
See Note 18, "Guarantees," in WPS Resources' Notes to Consolidated Financial Statements for information regarding guarantees.
See Note 24, "Variable Interest Entities," in WPS Resources' Notes to the Consolidated Financial Statements for information on the implementation of FASB Interpretation No. 46R.
MARKET PRICE RISK MANAGEMENT ACTIVITIES - WPS RESOURCES
Market price risk management activities include the electric and natural gas marketing and related risk management activities of ESI. ESI's marketing and trading operations manage power and natural gas procurement as an integrated portfolio with its retail and wholesale sales commitments. Derivative instruments are utilized in these operations. ESI measures the fair value of derivative instruments (including NYMEX exchange and over-the-counter contracts, options, natural gas and electric power physical fixed price contracts, basis contracts, and related financial instruments) on a mark-to-market basis. The fair value of derivatives are shown as assets or liabilities from risk management activities on WPS Resources' Consolidated Balance Sheets.
The offsetting entry to assets or liabilities from risk management activities is to other comprehensive income or earnings, depending on the use of the derivative, how it is designated, and if it qualifies for hedge accounting. The fair values of derivative instruments are adjusted each reporting period using various market sources and risk management systems. The primary input for natural gas and oil pricing is the settled forward price curve of the NYMEX exchange, which includes outright contracts and options. Basis pricing is derived from published indices and documented broker quotes. ESI bases electric prices on published indices and documented broker quotes. The following table provides an assessment of the factors impacting the change in the net value of ESI's assets and liabilities from risk management activities for the year ended December 31, 2005.
The fair value of contracts at January 1, 2005, and December 31, 2005, reflects the values reported on the balance sheet for net mark-to-market current and long-term risk management assets and liabilities as of those dates. Contracts realized or settled during the period includes the value of contracts in existence at January 1, 2005, that were no longer included in the net mark-to-market assets as of December 31, 2005, along with the amortization of those derivatives later designated as normal purchases and sales under SFAS No. 133. Changes in fair value of existing contracts include unrealized gains and losses on contracts that existed at January 1, 2005, and contracts that were entered into subsequent to January 1, 2005, which are included in ESI's portfolio at December 31, 2005. There were, in many cases, offsetting positions entered into and settled during the period resulting in gains or losses being realized during the current period. The realized gains or losses from these offsetting positions are not reflected in the table above.
Market quotes are more readily available for short duration contracts. The table below shows the sources of fair value and maturity of ESI's risk management instruments.
We derive the pricing for most contracts in the above table from active quotes or external sources. "Prices actively quoted" includes exchange traded contracts such as NYMEX contracts and basis swaps. "Prices provided by external sources" includes electric and natural gas contract positions for which pricing information, used by ESI to calculate fair value, is obtained primarily through broker quotes and other publicly available sources. "Prices based on models and other valuation methods" includes electric contracts for which reliable external pricing information does not exist.
ESI employs a variety of physical and financial instruments offered in the marketplace to limit risk exposure associated with fluctuating commodity prices and volumes, enhance value, and minimize cash flow volatility. However, the application of SFAS No. 133 and its related hedge accounting rules causes ESI to experience earnings volatility associated with electric and natural gas operations, as well as oil options utilized to protect the value of a portion of ESI's Section federal tax credits. While risks associated with power generating capacity and power and natural gas sales are economically hedged, certain transactions do not meet the definition of a derivative or do not qualify for hedge accounting under generally accepted accounting principles. Consequently, gains and losses from these positions may not match with the related physical and financial hedging instruments in some reporting periods. The result can cause volatility in ESI's reported period-by-period earnings; however, the financial impact of this timing difference will reverse at the time of physical delivery and/or settlement. The accounting treatment does not impact the underlying cash flows or economics of these transactions. See "Results of Operations - WPS Resources" above for information regarding earnings volatility caused by the natural gas storage cycle.
CRITICAL ACCOUNTING POLICIES - WPS RESOURCES
We have identified the following accounting policies to be critical to the understanding of our financial statements because their application requires significant judgment and reliance on estimations of matters that are inherently uncertain. WPS Resources' management has discussed these critical accounting policies with the Audit Committee of the Board of Directors.
Risk Management Activities
WPS Resources has entered into contracts that are accounted for as derivatives under the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. At December 31, 2005, those derivatives not designated as hedges are primarily commodity contracts used to manage price risk associated with natural gas and electricity purchase and sale activities, as well as oil options used to manage exposure to the risk of an increase in oil prices that could reduce the amount of Section 29 federal tax credits we could recognize from ESI's investment in a synthetic fuel production facility. Cash flow hedge accounting treatment may be used when WPS Resources contracts to buy or sell a commodity at a fixed price for future delivery to protect future cash flows corresponding with anticipated physical sales or purchases. Fair value hedge accounting may be used when WPS Resources holds assets or firm commitments and enters into transactions that hedge the risk that
the price of a commodity may change between the contract's inception and the physical delivery date of the commodity. To the extent that the hedging instrument is fully effective in offsetting the transaction being hedged, there is no impact on income available for common shareholders prior to settlement of the hedge. In addition, WPS Resources may apply the normal purchases and sales exception, provided by SFAS No. 133, as amended, to certain contracts. The normal purchases and sales exception provides that recognition of the contract's fair value in the Consolidated Financial Statements is not required until the settlement of the contract.
Derivative contracts that are determined to fall within the scope of SFAS No. 133, as amended, are recorded at fair value on the Consolidated Balance Sheets of WPS Resources. Changes in fair value, except those related to derivative instruments designated as cash flow hedges, are generally included in the determination of income available for common shareholders at each financial reporting date until the contracts are ultimately settled. When available, quoted market prices are used to determine a contract's fair value. If no active trading market exists for a commodity or for a contract's duration, fair value is estimated through the use of internally developed valuation techniques or models using external information wherever possible. Such estimates require significant judgment as to assumptions and valuation methodologies deemed appropriate by WPS Resources' management. As a component of the fair value determination, WPS Resources maintains operating reserves to account for the estimated direct costs of servicing and holding certain of its contracts based upon administrative costs, counterparty credit risk, and liquidity risk. The effect of changing the underlying assumptions for these operating reserves is as follows:
Change in Assumption
Effect on Operating Reserve at
December 31, 2005 (Millions)
100% increase
$15.0 increase
50% decrease
$ (7.5) decrease
These potential changes to the operating reserve would be included in current and long-term liabilities from risk management activities on the Consolidated Balance Sheets and as part of the nonregulated cost of fuel, gas and purchased power on the Consolidated Statements of Income unless the related contracts are designated as cash flow hedges, in which case potential changes would be included in Other Comprehensive Income - Cash Flow Hedges on the Consolidated Statements of Common Shareholders' Equity.
Asset Impairment
WPS Resources annually reviews its assets for impairment. SFAS No. 144, "Accounting for the Impairment and Disposal of Long-Lived Assets," and SFAS No. 142, "Goodwill and Other Intangible Assets," form the basis for these analyses.
The review for impairment of tangible assets is more critical to ESI than to our other segments because of its significant investment in property, plant, and equipment and lack of access to regulatory relief that is available to our regulated segments. At December 31, 2005, the carrying value of ESI's property, plant, and equipment totaled $141.6 million. We believe that the accounting estimate related to asset impairment of power plants is a "critical accounting estimate" because: (1) the estimate is susceptible to change from period to period because it requires management to make assumptions about future market sales pricing, production costs, capital expenditures, and generation volumes and (2) the impact of recognizing an impairment could be material to our financial position or results of operations. Management's assumptions about future market sales prices and generation volumes require significant judgment because actual market sales prices and generation volumes have fluctuated in the past as a result of changing fuel costs, environmental changes, and required plant maintenance and are expected to continue to do so in the future.
The primary estimates used at ESI in the impairment analysis are future revenue streams and operating costs. A combination of inputs from both internal and external sources is used to project revenue streams. ESI forecasts future operating costs with input from external sources for fuel costs and forward
energy prices. These estimates are modeled over the projected remaining life of the power plants using the methodology defined in SFAS No. 144. ESI evaluates property, plant, and equipment for impairment whenever indicators of impairment exist. These indicators include a significant underperformance of the assets relative to historical or projected future operating results, a significant change in the use of the assets or business strategy related to such assets, and significant negative industry or economic trends. SFAS No. 144 requires that if the sum of the undiscounted expected future cash flows from a company's asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. For assets held for sale, impairment charges are recorded if the carrying value of such assets exceeds the estimated fair value less costs to sell. The amount of impairment recognized is calculated by reducing the carrying value of the asset to its fair value.
Throughout 2005, ESI tested its power plants for impairment whenever events or changes in circumstances indicated that their carrying amount might not be recoverable. There was an impairment charge recorded on the Sunbury plant in 2005 (see Note 4, "Sunbury Plant," in WPS Resources' Notes to Consolidated Financial Statements for more information). No other impairment charges were recorded in 2005 as a result of the recoverability tests. Results of past impairment tests may not necessarily be an indicator of future tests given the criticality of the accounting estimates involved, as discussed more fully above. Changes in actual results or assumptions could result in an impairment.
WPSC recorded goodwill of $36.4 million in its gas utility segment following the merger of Wisconsin Fuel and Light into WPSC in 2001. The goodwill is tested for impairment annually based on the guidance of SFAS No. 142. The test for impairment includes assumptions about future profitability of the gas utility segment and the correlation between our gas utility segment and published projections for other similar gas utility segments. A significant change in the natural gas utility market and/or our projections of future profitability could result in a loss being recorded on the income statement related to a decrease in the goodwill asset as a result of the impairment test.
Receivables and Reserves
Our regulated natural gas and electric utilities and ESI accrue estimated amounts of revenue for services rendered but not yet billed. Estimated unbilled sales are calculated using actual generation and throughput volumes, recorded sales, and weather factors. The estimated unbilled sales are assigned different rates based on historical customer class allocations. At December 31, 2005 and 2004, the amount of unbilled revenues was $151.3 million and $113.2 million, respectively. Any difference between actual sales and the estimates or weather factors would cause a change in the estimated revenue.
WPS Resources records reserves for potential uncollectible customer accounts as an expense on the income statement and an uncollectible reserve on the balance sheet. WPSC, however, records a regulatory asset to offset its uncollectible reserve. Because the nonregulated energy marketing business involves higher credit risk, the reserve is more critical to ESI than to our other segments. At ESI, the reserve is based on historical uncollectible experience and specific customer identification where practical. If the assumption that historical uncollectible experience matches current customer default is incorrect, or if a specific customer with a large account receivable that has not previously been identified as a risk defaults, there could be significant changes to the expense and uncollectible reserve balance.
Pension and Postretirement Benefits
The costs of providing non-contributory defined benefit pension benefits and other postretirement benefits, described in Note 19, "Employee Benefit Plans," in WPS Resources' Notes to Consolidated Financial Statements, are dependent upon numerous factors resulting from actual plan experience and assumptions regarding future experience.
Pension costs and other postretirement benefit costs are impacted by actual employee demographics (including age, compensation levels, and employment periods), the level of contributions we make to the plan, and earnings on plan assets. Pension and other postretirement benefit costs may be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets,
discount rates used in determining the projected benefit and other postretirement benefit obligation and pension and other postretirement benefit costs, and health care cost trends. Changes made to the plan provisions may also impact current and future pension and other postretirement benefit costs.
WPS Resources' pension plan assets and other postretirement 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 pension costs in future periods. Management believes that such changes in costs would be recovered at our regulated segments through the ratemaking process.
The following chart shows how a given change in certain actuarial assumptions would impact the projected benefit obligation, the net amount recognized on the balance sheet, and the reported annual pension cost on the income statement as they relate to all of our defined benefit pension plans. Each factor below reflects an evaluation of the change based on a change in that assumption only.
The following chart shows how a given change in certain actuarial assumptions would impact the projected other postretirement benefit obligation, the reported other postretirement benefit liability on the balance sheet, and the reported annual other postretirement benefit cost on the income statement. Each factor below reflects an evaluation of the change based on a change in that assumption only.
In selecting an assumed discount rate, we use the Mercer Pension Discount Yield Curve, which considers bonds, rated by Moody's as "Aa" or better, selected from the Lehman Brothers database that are non-callable. Regression analysis is applied to construct a best-fit curve that makes coupon yields to maturity a function of time to maturity. The pension or retiree medical cash flows are then matched to the appropriate spot rates and discounted back to the measurement date.
To select an assumed long-term rate of return on qualified plan assets, we consider the historical returns and the future expectations for returns for each asset class, as well as the target allocation of the benefit trust portfolios. The assumed long-term rate of return was 8.5% in 2005 and 8.75% in 2004 and 2003. For 2005, the actual return on plan assets, net of fees, was a gain of $39.7 million. The actual return on plan assets, net of fees, was a gain of $54.5 million and $92.7 million in 2004 and 2003, respectively.
We base our determination of the expected return on qualified plan assets on a market-related valuation of assets, which reduces year-to-year volatility. Cumulative gains and losses in excess of 10% of the greater of the pension benefit obligation or market-related value are amortized over the average remaining future service to expected retirement ages. Realized and unrealized gains and losses are
recognized over a five-year period. Because of this method, the future value of assets will be impacted as previously deferred gains or losses are recorded.
In selecting assumed health care cost trend rates, we consider past performance and forecasts of health care costs. More information on health care cost trend rates can be found in Note 19, "Employee Benefit Plans," in WPS Resources' Notes to Consolidated Financial Statements.
For a table showing future payments that WPS Resources expects to make for pension and other postretirement benefits, see Note 19, "Employee Benefit Plans," in WPS Resources' Notes to Consolidated Financial Statements.
Regulatory Accounting
The electric and gas utility segments of WPS Resources follow SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," and our financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions regulating these segments. We defer certain items that would otherwise be immediately recognized as expenses and revenues because our regulators have authorized deferral as regulatory assets and regulatory liabilities for future recovery or refund to customers. Future recovery of regulatory assets is not assured, but is generally subject to review by regulators in rate proceedings for matters such as prudence and reasonableness. Management regularly assesses whether these regulatory assets and liabilities are probable of future recovery or refund by considering factors such as regulatory environment changes, earnings at the utility segments, and the status of any pending or potential deregulation legislation. Once approved, we amortize the regulatory assets and liabilities into income over the rate recovery period. If recovery of costs is not approved or is no longer deemed probable, these regulatory assets or liabilities are recognized in current period income.
If our regulated electric and gas utility segments no longer meet the criteria for application of SFAS No. 71, we would discontinue its application as defined under SFAS No. 101, "Regulated Enterprises - Accounting for the Discontinuation of Application of SFAS No. 71." Assets and liabilities recognized solely due to the actions of rate regulation would no longer be recognized on the balance sheet and would be classified as an extraordinary item in income for the period in which the discontinuation occurred. A write-off of all WPS Resources' regulatory assets and regulatory liabilities at December 31, 2005, would result in a 5.0% decrease in total assets, a 9.1% decrease in total liabilities, and a 48.5% increase in income before taxes.
Tax Provision
As part of the process of preparing our Consolidated Financial Statements, we are required to estimate our income taxes for each of the jurisdictions in which we operate. This process involves estimating our actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are included within our Consolidated Balance Sheet. We must also assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that recovery is not likely, we must establish a valuation allowance, which is offset by an expense within the tax provisions in the income statement.
Significant management judgment is required in determining our provision for income taxes, our deferred tax assets and liabilities, and any valuation allowance recorded against our deferred tax assets. The assumptions involved are supported by historical data and reasonable projections. Significant changes in these assumptions could have a material impact on WPS Resources' financial condition and results of operations.
IMPACT OF INFLATION - WPS RESOURCES
Our financial statements are prepared in accordance with accounting principles generally accepted in the United States of America and report operating results in terms of historic cost. The statements provide a reasonable, objective, and quantifiable statement of financial results; but they do not evaluate the impact of inflation. Under rate treatment prescribed by utility regulatory commissions, WPSC's and UPPCO's projected operating costs are recoverable in revenues. Because rate forecasting assumes inflation, most of the inflationary effects on normal operating costs are recoverable in rates. However, in these forecasts, WPSC and UPPCO are only allowed to recover the historic cost of plant via depreciation. Our nonregulated businesses include inflation in forecasted costs. However, any increase from inflation is offset with projected business growth. Therefore, the estimated effect of inflation on our nonregulated businesses is minor.
RESULTS OF OPERATIONS - WPSC
WPSC is a regulated electric and natural gas utility as well as a holding company. Electric operations accounted for approximately 64% of revenues in 2005, while natural gas operations contributed 36% to 2005 revenues.
Compared with 2004
WPSC Overview
WPSC's results of operations for the years ended December 31 are shown in the following table:
Electric utility revenue increased $131.7 million (16.4%), largely due to an approved electric rate increase for WPSC's Wisconsin retail customers and an increase in electric sales volumes. Gas utility revenue increased $101.1 million (24.0%) due to an increase in the per-unit cost of natural gas, higher natural gas throughput volumes, and an approved rate increase. Revenue changes by reportable segment are discussed in more detail below.
WPSC's earnings on common stock were $81.4 million for the year ended December 31, 2005, compared to $104.8 million for the year ended December 31, 2004. As discussed in more detail below, the following factors negatively impacted earnings for the year ended December 31, 2005, compared to the same period in 2004.
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Electric utility earnings decreased $5.1 million for the year ended December 31, 2005, compared to 2004. Electric utility earnings were negatively impacted by fuel and purchased power costs that were $13.7 million in excess of what WPSC was allowed to recover from its customers due to inefficiencies in the fuel recovery process ($10 million related to retail customers and $3.7 million related to wholesale customers). In addition, the PSCW's ruling in the 2006 rate case, which disallowed recovery of costs that were deferred related to the 2004 Kewaunee outage and a portion of the loss on the Kewaunee sale, resulted in the write-off of $13.7 million of regulatory assets.
·
Natural gas utility earnings decreased $4.1 million, driven by higher operating and maintenance expenses and higher depreciation expense.
·
Pre-tax gains on land sales at WPSC decreased $15.0 million in 2005, compared to 2004. WPSC recognized pre-tax land sale gains of $4.6 million in 2005, compared to pre-tax land sale gains of $19.6 million in 2004.
·
WPSC recognized an income tax benefit in 2004 from the donation of land to the WDNR.
Electric Utility Operations
Electric utility revenue increased $131.7 million (16.4%) for the year ended December 31, 2005, compared to the same period in 2004. Electric utility revenue increased largely due to an approved
electric rate increase for WPSC's Wisconsin retail customers and an increase in electric sales volumes. On December 21, 2004, the PSCW approved a retail electric rate increase of $60.7 million (8.6%), effective January 1, 2005. The rate increase was required primarily to recover increased costs related to fuel and purchased power, the construction of the Weston 4 power plant, and benefit costs. Electric sales volumes increased 7.7%, primarily due to significantly warmer weather during the 2005 cooling season, compared to the same period in 2004, and new power sales agreements that were entered into with wholesale customers. As a result of the warm weather, WPSC set all-time records for peak electric demand in the second and third quarters of 2005.
The electric utility margin decreased $9.0 million (1.6%) for the year ended December 31, 2005, compared to the year ended December 31, 2004, largely driven by the sale of Kewaunee on July 5, 2005, and the related power purchase agreement. Prior to the sale of Kewaunee, only nuclear fuel expense was reported as a component of fuel and purchased power costs. Subsequent to the sale, all payments to Dominion for power purchased from Kewaunee are reported as a component of fuel and purchased power costs. These include both variable payments for energy delivered and fixed payments. As a result of the sale, WPSC no longer incurs operating and maintenance expense, depreciation and decommissioning expense, or interest expense for Kewaunee. Excluding the $43.2 million of fixed payments made to Dominion in 2005, WPSC's electric utility margin increased $34.2 million compared to 2004.
Excluding the fixed payments to Dominion, the increase in margin was primarily related to the approved 2005 retail electric rate increase discussed above and the warm summer weather conditions, partially offset by higher fuel and purchased power costs associated with high natural gas prices and the PSCW's disallowance of certain costs in its decision on the 2006 rate case for WPSC (these costs were previously approved for deferral). Fuel and purchased power costs incurred in 2005 exceeded the amount recovered from ratepayers by $13.7 million (of which $10 million related to Wisconsin retail customers and $3.7 million related to wholesale customers), negatively impacting margin. The increase in fuel and purchased power costs resulted primarily from the destruction of certain natural gas production facilities in the Gulf of Mexico by hurricanes in the third quarter of 2005, driving up the per-unit cost of natural gas used in generation. The quantity of power generated from WPSC's natural gas-fired units was also up 162% over the prior year, driven by the warm summer weather conditions experienced during 2005, increased dispatch by the MISO for reliability purposes, and purchases through a power purchase agreement from the Fox Energy Center (which began operating in June 2005). Certain costs related to the MISO were approved for deferral. Authorization was requested from the PSCW to defer increased natural gas costs related to the hurricanes, but this request was denied, leaving the Wisconsin fuel recovery mechanism as the only option for recovery. However, because of the way the Wisconsin fuel recovery mechanism works, the $10 million increase in costs (primarily related to the combination of rising natural gas prices caused by the hurricanes and the increase in natural gas-fired generation) were essentially unrecoverable since they were incurred late in the year. To mitigate the risk of unrecoverable fuel costs in 2006 due to market price volatility, WPSC is employing risk management techniques pursuant to its risk policy approved by the PSCW, including the use of derivative instruments such as futures and options. The PSCW also disallowed recovery of $5.5 million of increased fuel and purchased power costs related to an extended outage at Kewaunee in 2004, resulting in this deferral being written off in the fourth quarter of 2005.
Electric utility earnings decreased $5.1 million (7.8%) for the year ended December 31, 2005, compared to 2004. The decrease in earnings resulted from the high fuel and purchased power costs that WPSC was unable to recover from its Wisconsin retail and wholesale customers, the PSCW's disallowance of previously deferred costs related to Kewaunee, and an increase in operating and maintenance expenses.
Gas Utility Operations
Gas utility revenue increased $101.1 million (24.0%) for the year ended December 31, 2005, compared to 2004. Gas utility revenue increased primarily as a result of an increase in the per-unit cost of natural gas, a natural gas rate increase, and higher natural gas throughput volumes. Natural gas costs increased 24.6% (on a per-unit basis) for the year ended December 31, 2005, compared to 2004. Following regulatory practice, WPSC passes changes in the total cost of natural gas on to customers through a purchased gas adjustment clause, as allowed by the PSCW and the MPSC. The PSCW issued an order authorizing a natural gas rate increase of $5.6 million (1.1%), effective January 1, 2005. The rate increase was primarily driven by higher benefit costs and the cost of natural gas distribution system improvements. Natural gas throughput volumes increased 3.2%, driven by an increase in interdepartmental sales from the natural gas utility to the electric utility as a result of increased generation from combustion turbines. Higher natural gas throughput volumes from interdepartmental sales to the electric utility were partially offset by lower natural gas throughput volumes to residential customers, driven by milder weather conditions in 2005 compared to 2004. WPSC also believes customers are taking measures to conserve energy as a result of the high natural gas prices.
The natural gas utility margin increased $5.6 million (4.7%) for the year ended December 31, 2005, compared to 2004. The higher natural gas utility margin was largely due to the rate increase mentioned above. The increase in interdepartmental sales volumes to WPSC's electric utility also had a positive impact on the natural gas margin.
Gas utility earnings for the year ended December 31, 2005, decreased $4.1 million, primarily due to an increase in operating and maintenance expenses and depreciation expense incurred by the gas utility.
Operating Expenses
Operating and Maintenance Expense
Operating and maintenance expenses increased $13.6 million (3.5%) for the year ended December 31, 2005, compared to 2004. The following items were the most significant contributors to the change in operating and maintenance expenses at WPSC:
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The combined increase in pension expense, active and postretirement medical expense, salaries, and customer service expense was approximately $25 million.
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Transmission-related expenses increased $9.9 million.
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In WPSC's 2006 rate case, the PSCW concluded that only half of the loss related to the sale of Kewaunee could be collected from ratepayers. As a result, WPSC wrote off $6.1 million of the regulatory asset established for the loss on the sale of Kewaunee.
·
In WPSC's 2006 rate case, the PSCW also disallowed recovery of increased operating and maintenance expenses related to the 2004 extended outage at Kewaunee, resulting in a $2.1 million write-off of previously deferred costs.
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The increases discussed above were partially offset by a decrease in operating and maintenance expenses of approximately $28 million related to Kewaunee, due to the sale of this facility on July 5, 2005.
Depreciation and Decommissioning Expense
Depreciation and decommissioning expense increased $35.0 million (38.5%) for the year ended December 31, 2005, compared to 2004, driven by higher gains on decommissioning trust assets prior to the sale of Kewaunee of approximately $35 million. Realized gains on decommissioning trust assets (included as a component of miscellaneous income) offset the increased decommissioning expense pursuant to regulatory practice. Continued capital investment at WPSC also resulted in an increase in depreciation expense. These items were partially offset by a $7.0 million decrease in depreciation resulting from the sale of the Kewaunee assets in July 2005.
Federal Income Taxes/State Income Taxes/Other Income
The period-over-period change in these account balances was primarily related to the increase in realized gains recognized on the nonqualified decommissioning trust assets in 2005. Approximately $35 million of the increase in other income related to the realized gains on the nonqualified decommissioning trust assets. The nonqualified nuclear decommissioning trust assets were placed in more conservative investments in the second quarter of 2005 in anticipation of the sale of Kewaunee, which closed on July 5, 2005. Pursuant to regulatory practice, the increase in miscellaneous income related to the realized gains was offset by an increase in decommissioning expense. Income tax expense related to the realized gains was offset by a deferred tax benefit related to the decommissioning expense. Overall, the change in the investment strategy for the nonqualified decommissioning trust assets had no impact on earnings, as summarized in the table below.
Other income at WPSC increased $9.6 million (29.1%) in 2005 compared to 2004. Excluding the increase in other income related to higher realized gains on the nonqualified decommissioning trust assets in 2005 and the decrease in other income related to higher income taxes related to these realized gains, miscellaneous income decreased approximately $10 million. The remaining decrease was primarily driven by a $15.0 million decrease in pre-tax gains on land sales. WPSC recognized pre-tax land sale gains of $4.6 million in 2005, compared to pre-tax land sale gains of $19.6 million in 2004. This decrease was partially offset by DPC's reimbursement of $8 million of carrying costs incurred by WPSC related to the Weston 4 power plant. The reimbursement was recorded within miscellaneous income. WPSC sold a 30% interest in the Weston power plant to DPC in the fourth quarter of 2005. Proceeds received from the sale included a reimbursement for approximately $8 million of carrying costs incurred by WPSC for capital expenditures related to DPCs portion of the facility, which were funded by WPSC in 2004 and 2005.
Compared with 2003
WPSC Overview
WPSC's results of operations for the years ended December 31 are shown in the following table:
Approved retail and wholesale electric rate increases drove a $76.3 million increase in WPSC's electric revenue. The $16.7 million increase in WPSC's natural gas revenue was driven by an increase in the per-unit cost of natural gas and an authorized retail natural gas rate increase, partially offset by a 6.2% decrease in natural gas throughput volumes resulting from unfavorable weather conditions.
WPSC's earnings on common stock were $104.8 million for the year ended December 31, 2004, compared with $78.9 million for the same period in 2003. As discussed in more detail below, the following factors impacted earnings for the year ended December 31, 2004, compared to the same period in 2003.
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Approved rate increases (including the impact of timely retail electric rate relief in 2004, compared to the delay in receiving retail electric rate relief in 2003) favorably impacted the electric margin.
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An approved retail natural gas rate increase favorably impacted the natural gas margin at WPSC, but a decrease in natural gas throughput volumes partially offset the favorable impact of this rate increase.
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Land sales, land donations, and higher earnings from equity investments favorably impacted earnings.
·
Higher operating and maintenance expense negatively impacted earnings.
Electric Utility Operations
Electric utility revenue increased $76.3 million (10.5%), for the year ended December 31, 2004, compared to the same period in 2003. Electric utility revenue increased largely due to authorized retail and wholesale electric rate increases for WPSC's Wisconsin and Michigan customers (see discussion within "Results of Operations - WPS Resources") to recover higher fuel and purchased power costs, increased operating expenses, and expenditures incurred for infrastructure improvements. Electric utility sales volumes were also slightly higher in 2004, increasing 0.6% over 2003 sales volumes. A 1.5% increase in sales volumes to commercial and industrial customers was partially offset by a 1.2% decrease in sales volumes to residential customers. Higher sales volumes to our commercial and industrial customers reflect an improving economy and growth within our service area, while the decrease in sales volumes to residential customers reflects weather that was 6.6% cooler during the cooling season, compared to 2003.
WPSC's electric margin increased $51.4 million (10.3%), for the year ended December 31, 2004, compared to 2003. The increase in WPSC's electric margin is primarily related to the retail and wholesale electric rate increases, partially offset by a $20.4 million increase in purchased power costs. The quantity of power purchased in 2004 increased 9.3% over 2003 purchases and purchased power costs were 17.4% higher (on a per-unit basis) in 2004, compared to 2003. The PSCW allowed WPSC to adjust prospectively the amount billed to Wisconsin retail customers for fuel and purchased power if costs were in excess of plus or minus 2% from approved levels. In response to a request for additional fuel cost recovery filed early in 2004, WPSC was allowed to recover $3.2 million of its increased fuel and purchased power costs during 2004. The PSCW also allowed WPSC to defer $5.4 million of unanticipated fuel and purchased power costs directly associated with the extension of the Kewaunee refueling outage in the fourth quarter of 2004. The Kewaunee outage was extended three weeks due primarily to difficulties encountered with lifting equipment related to the reactor vessel and procedures to perform the lifts. It was anticipated that these costs would be recovered in 2006; however, in the PSCW's final decision allowing WPSC authority to increase retail electric and natural gas rates in 2006, the PSCW determined WPSC could not recover the costs for the 2004 extended outage. For more information on this determination, see Note 23, "Regulatory Environment," in WPS Resources' Notes to Consolidated Financial Statements."
WPSC's electric earnings increased $12.2 million (22.8%), for the year ended December 31, 2004, compared to 2003. The increased earnings were largely driven by the higher margin (including the effect of timely retail electric rate relief in 2004 compared to a delay in receiving retail electric rate relief in 2003), partially offset by higher operating and maintenance expenses.
Gas Utility Operations
Gas utility revenue increased $16.7 million (4.1%), for the year ended December 31, 2004, compared to 2003. Higher revenue was driven by an authorized rate increase and an increase in the per-unit cost of natural gas, partially offset by an overall 6.2% decrease in natural gas throughput volumes. Natural gas prices increased 14.2% per unit in 2004. Higher natural gas prices reflect higher marketplace natural gas costs in 2004. The PSCW and the MPSC allow WPSC to pass changes in the total cost of natural gas on to customers. As a result, changes in the price of the natural gas commodity do not have a direct impact on WPSC's margin. The decrease in natural gas throughput volumes was driven by weather that was 4.3% warmer during the heating season for the year ended December 31, 2004, compared to 2003.
The natural gas utility margin increased $5.8 million (5.1%), for the year ended December 31, 2004, compared to 2003. The higher natural gas utility margin was largely due to the authorized rate increase mentioned above. The ability of WPSC to realize the full benefit of an authorized rate increase is dependent upon normal throughput volumes; therefore, the decrease in natural gas throughput volumes negatively impacted WPSC's ability to benefit from the full amount of the rate increase.
The higher margin drove a $1.6 million (10.2%), increase in gas utility earnings for the year ended December 31, 2004.
Operating Expenses
Operating and Maintenance Expense
Operating and maintenance expenses at WPSC increased $30.9 million (8.7%), for the year ended December 31, 2004, compared to 2003. Electric transmission and distribution costs were up $13.5 million due primarily to an increase in transmission rates. Pension and postretirement medical costs incurred at WPSC increased $8.9 million. Additionally, $6.8 million of the increase was driven by amortization of costs incurred in conjunction with the implementation of the automated meter reading system and the purchase of the De Pere Energy Center (previously deferred as regulatory assets). Maintenance expenses at WPSC's coal-fired generation facilities were $4.2 million higher in 2004, compared to 2003, driven by an extension of the annual planned outage at the Pulliam 6 generation facility in 2004. Higher payroll and other benefit costs also contributed to the increase in operating and maintenance expenses. The fall refueling outage at Kewaunee did not significantly impact the year-over-year change in operating and maintenance expenses as there was also a refueling outage at Kewaunee in the spring of 2003, and the PSCW approved the deferral of incremental operating and maintenance expenses that were incurred as a direct result of the refueling outage extension ($1.8 million of operating and maintenance expenses were deferred in the fourth quarter of 2004). It was anticipated that these costs would be recovered in 2006; however, in the PSCW's final decision allowing WPSC authority to increase retail electric and natural gas rates in 2006, the PSCW determined WPSC could not recover the costs for the 2004 extended outage. For more information on this determination, see Note 23, "Regulatory Environment," in WPS Resources' Notes to Consolidated Financial Statements.
Depreciation and Decommissioning Expense
Depreciation and decommissioning expense decreased $31.9 million (26.0%), for the year ended December 31, 2004, compared to 2003, due primarily to a decrease of $35.9 million resulting from lower realized gains on decommissioning trust assets and because the decommissioning trust was not funded in 2004 in anticipation of selling Kewaunee. Realized gains on decommissioning trust assets are substantially offset by depreciation expense pursuant to regulatory practice. An increase in depreciation expense from plant asset additions at WPSC partially offset the decrease in decommissioning expense.
Other Income
Other income decreased $22.3 million, from $55.3 million in 2003, to $33.0 million in 2004, largely due to a decrease in realized gains on decommissioning trust assets of $33.5 million. Lower realized gains were substantially offset by lower decommissioning expense, as discussed above. Partially offsetting the lower gains on decommissioning trust assets were higher earnings realized from equity investments and an increase in gains recognized from land sales in 2004, compared to 2003.
BALANCE SHEET - WPSC
Compared with 2004
Net utility plant decreased $298.1 million (14.4%), from $2,066.8 million at December 31, 2004, to $1,768.7 million at December 31, 2005. The major contributors to the change in net utility plant are summarized below:
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Nuclear decommissioning trusts decreased from $344.5 million at December 31, 2004, to $0 at December 31, 2005. The qualified decommissioning trust assets were included in the Kewaunee sale and the nonqualified decommissioning assets were liquidated.
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The Kewaunee plant was sold in 2005, driving a $165.4 million decrease in net utility plant.
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Depreciation expense of $126.0 million was recorded in 2005.
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WPSC sold a 30% interest in Weston 4, driving an $83.9 million decrease in net utility plant.
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Partially offsetting the decreases above, capital expenditures recorded in 2005 were $400.3 million, primarily related to the construction of Weston 4.
Customer and other receivables increased $64.6 million (60.8%), from $106.2 million at December 31, 2004, to $170.8 million at December 31, 2005. The increase was largely due to a 49.7% per-unit increase in natural gas costs in the fourth quarter of 2005, compared to the fourth quarter of 2004. An 8.6% increase in retail electric rates combined with an 8.0% increase in electric sales volumes in the fourth quarter of 2005, compared to the fourth quarter of 2004 also contributed to the increase in customer and other receivables at WPSC.
Natural gas in storage increased $20.9 million (34.7%), from $60.2 million at December 31, 2004, to $81.1 million at December 31, 2005. Natural gas in storage is built up throughout the year and, therefore, the 24.6% increase in the average per-unit cost of natural gas purchased by WPSC in 2005, compared to 2004 was the primary driver of the increase in natural gas in storage.
Assets from risk management activities increased $23.6 million (414.0%), from $5.7 million at December 31, 2004, to $29.3 million at December 31, 2005, primarily related to mark-to-market gains recorded on financial transmission rights related to our participation in MISO. Mark-to-market gains on these derivative instruments are deferred as a regulatory liability pursuant to regulatory approval.
Regulatory assets increased $109.9 million (70.2%), from $156.5 million at December 31, 2004, to $266.4 million at December 31, 2005, largely due to $56.4 million of costs that were deferred related to the unplanned outage at Kewaunee in 2005, a $25.9 million increase in the regulatory asset related to the minimum pension liability, deferral of $21.2 million of MISO Day 2 charges, and a $6.3 million deferral of a portion of the loss on the sale of Kewaunee.
Accounts payable increased $69.5 million (47.9%), from $145.1 million at December 31, 2004, to $214.6 million at December 31, 2005. The increase was driven by higher per-unit natural gas costs and higher per-unit fuel and purchased power costs in 2005 compared to 2004.
Regulatory liabilities increased $83.5 million (30.8%), from $271.1 million at December 31, 2004, to $354.6 million at December 31, 2005, driven by a $126.9 million regulatory liability related to proceeds received from the liquidation of the nonqualified decommissioning trust in connection with the Kewaunee sale. The regulatory liability related to mark-to-market gains on derivative instruments also increased $24.6 million, primarily related to mark-to-market gains recorded on financial transmission rights related to our participation in MISO. These increases were partially offset by a $46.6 million decrease in the regulatory liability pertaining to the asset retirement obligation recorded related to the decommissioning of Kewaunee (as this plant was sold on July 5, 2005), and a $26.8 million reduction in deferred unrealized gains on decommissioning trust assets as the trust assets were either liquidated or transferred in the sale of Kewaunee.
Asset retirement obligations decreased from $364.4 million at December 31, 2004, to $7.7 million at December 31, 2005, driven by the transfer of our obligation to decommission Kewaunee (as this plant was sold on July 5, 2005).
LIQUIDITY AND CAPITAL RESOURCES - WPSC
WPSC believes that its cash, operating cash flows, and borrowing ability because of strong credit ratings, when taken together, provide adequate resources to fund ongoing operating requirements and future capital expenditures related to expansion of existing businesses and development of new projects. However, WPSC's operating cash flow and access to capital markets can be impacted by macroeconomic factors outside its control. In addition, WPSC's borrowing costs can be impacted by its short-term and long-term debt ratings assigned by independent rating agencies, which in part are based on certain credit measures such as interest coverage and leverage ratios. Currently, WPSC believes
these ratings continue to be among the best in the energy industry (see "Liquidity and Capital Resources - WPS Resources" for more information).
Operating Cash Flows
During 2005, net cash provided by operating activities was $87.5 million, compared with $213.9 million in 2004. The decrease in cash provided by operating activities was driven by various expenditures incurred in 2005, which will not be collected from ratepayers until future years. In 2005, expenditures incurred related to the unplanned Kewaunee outage were approximately $56 million, expenditures incurred related to MISO were approximately $21 million, and increased costs related to coal shortages were approximately $6 million (see Note 23, "Regulatory Environment," in WPS Resources' Notes to Consolidated Financial Statements for more information on these regulatory assets). A $26.8 million increase in cash required to fund working capital requirements also contributed to the decrease in cash provided by operating activities. An increase in the per-unit cost of natural gas drove the higher working capital requirements. Pension and postretirement funding also increased $10.8 million in 2005, compared to 2004.
During 2004, net cash provided by operating activities was $213.9 million, compared with $152.6 million in 2003. The increase was driven by improved operating results.
Investing Cash Flows
Net cash used for investing activities was $64.5 million in 2005, compared to $252.0 million in 2004. The $187.5 million decrease in cash used for investing activities was driven by proceeds of $127.1 million received from the liquidation of the non-qualified decommissioning trust in connection with the Kewaunee sale, $112.5 million of proceeds received from the sale of Kewaunee, and $95.1 million of proceeds received from DPC upon closing of the sale of a 30% ownership interest in Weston 4. The decrease was partially offset by a $127.5 million increase in capital expenditures, primarily related to the construction of Weston 4.
Net cash used for investing activities was $252.0 million in 2004 compared to $182.2 million in 2003. The increase was largely related to a $111.2 million increase in utility capital expenditures (see "Capital Expenditures" below), partially offset by a $48.4 million decrease in cash used for the purchase of equity investments and other acquisitions. The final payment in the amount of $48.4 million related to the De Pere Energy Center was made in December 2003.
Capital Expenditures
Capital expenditures by business segment for the years ended December 31, 2005, 2004, and 2003 are as follows:
The increase in capital expenditures at the electric utility in 2005, as compared to 2004, is mainly due to higher capital expenditures associated with the construction of Weston 4. Gas utility capital expenditures decreased primarily due to completion of the automated meter reading project.
The increase in capital expenditures at the electric utility in 2004 as compared to 2003 is mainly due to higher capital expenditures associated with the construction of Weston 4. Gas utility capital expenditures
increased primarily due to the installation of automated meter reading. See "Liquidity and Capital Resources - WPS Resources," for more information regarding construction of Weston 4.
Financing Cash Flows
Net cash used for financing activities was $24.0 million in 2005, compared to net cash provided by financing activities of $36.9 million in 2004. Although cash provided by operating activities decreased in 2005, compared to 2004, this decrease was more than offset by a decrease in cash used for investing activities, related to proceeds received from various asset sales in 2005.
Net cash provided by financing activities was $36.9 million in 2004 compared to $30.9 million in 2003. Although cash provided by operating activities increased significantly in 2004, additional borrowings were required to fund WPSC's capital expenditures, primarily related to the construction of Weston 4.
Under a PSCW order, WPSC may not pay normal common stock dividends of more than 109% of the previous year's common stock dividend without the PSCW's approval. In addition, WPSC's Restated Articles of Incorporation limit the amount of common stock dividends that WPSC can pay to certain percentages of its prior 12-month net income, if its common stock and common stock surplus accounts constitute less than 25% of its total capitalization.
Significant Financing Activities
See "Liquidity and Capital Resources - WPS Resources" for detailed information on significant financing activities for WPSC.
Credit Ratings
See "Liquidity and Capital Resources - WPS Resources" for detailed information on WPSC's credit ratings.
Future Capital Requirements and Resources
Contractual Obligations
The following table summarizes the contractual obligations of WPSC, including its subsidiaries.
Long-term debt principal and interest payments represent bonds issued, notes issued, and loans made to WPSC. We record all principal obligations on the balance sheet. Commodity purchase obligations represent mainly commodity purchase contracts. WPSC expects to recover the costs of its contracts in future customer rates. Purchase orders include obligations related to normal business operations and large construction obligations, including 100% of Weston 4 obligations. The sale of a 30% interest in Weston 4 to DPC was completed in November 2005, but WPSC retains the legal obligation to initially remit payment to third parties for 100% of all construction costs incurred, 30% of which will subsequently
be billed to DPC. Capital contributions to equity method investment include our commitment to fund a portion of ATC's Wausau, Wisconsin, to Duluth, Minnesota, transmission line.
Capital Requirements
See "Liquidity and Capital Resources - WPS Resources," for detailed information on capital requirements for WPSC.
Capital Resources
See "Liquidity and Capital Resources - WPS Resources," for detailed information on capital resources for WPSC.
Other Future Considerations
Kewaunee
See Note 6, "Acquisitions and Sales of Assets," in WPS Resources' Notes to Consolidated Financial Statements for detailed information on the sale of WPSC's interest in Kewaunee.
Asset Management Strategy
See "Liquidity and Capital Resources - WPS Resources," for detailed information on WPS Resources' asset management strategy.
Regulatory Matters and Significant Rate Trends
See "Liquidity and Capital Resources - WPS Resources," for detailed information on regulatory matters and significant rate trends.
Seams Elimination Charge Adjustment
See "Liquidity and Capital Resources - WPS Resources," for detailed information on the Seams Elimination Charge Adjustment.
Coal Supply
See "Liquidity and Capital Resources - WPS Resources," for detailed information on coal matters.
Income Taxes
See "Liquidity and Capital Resources - WPS Resources," for detailed information on income tax matters applicable to WPSC.
Environmental
See Note 17, "Commitments and Contingencies," in WPS Resources' Notes to Consolidated Financial Statements for a detailed discussion of environmental considerations.
Midwest Independent Transmission System Operator
See "Liquidity and Capital Resources - WPS Resources," for detailed information on MISO.
New Accounting Pronouncements
See Note 1(w), "New Accounting Pronouncements," in WPS Resources Notes to Consolidated Financial Statements for a detailed discussion of new accounting pronouncements.
OFF BALANCE SHEET ARRANGEMENTS - WPSC
See Note 18, "Guarantees," in WPS Resources' Notes to Consolidated Financial Statements for information regarding WPSC's guarantees.
CRITICAL ACCOUNTING POLICIES - WPSC
See "Critical Accounting Policies - WPS Resources," for information regarding WPSC's critical accounting policies.
IMPACT OF INFLATION - WPSC
See "Impact of Inflation - WPS Resources," for information regarding the impact of inflation on WPSC.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market Risks and Other Significant Risks
WPS Resources has potential market risk exposure related to commodity price risk (including regulatory recovery risk), interest rate risk, equity return risk, and principal preservation risk. WPS Resources is also exposed to other significant risks due to the nature of our subsidiaries' business and the environment from which we operate. WPS Resources has risk management policies in place to monitor and assist in controlling these risks and may use derivative and other instruments to manage some of these exposures, as further described below.
Commodity Price Risk and Regulatory Recovery Risk
WPSC burns natural gas in several of its peaking power plants, as a supplemental fuel at several coal-fired plants, and supplies natural gas as fuel to generate energy as part of a purchased power agreement with Fox Energy Center. Natural gas costs typically impact the cost of fuel used in electric generation as well as purchased power costs.
Regulatory commissions allow utilities to earn a return on common stock equity that is commensurate with an investor's expected return, compensating for the risks investors face when providing funds to the utility. The return on common stock equity approved by the PSCW, the FERC, and the MPSC was 11.5%, 11.0%, and 11.4%, respectively, in 2005 and 12.0%, 11.0%, and 11.4%, respectively, in 2004. The utilities bear volume risk as rates are based upon normal sales volumes as projected by the utility. Historically, consumers bear most of the price risk for fuel and purchased power costs as our regulators typically have allowed the utilities to recover most of these costs (to the extent they are prudently incurred), through various cost recovery mechanisms. However, WPSC is exposed to the risk of not recovering increased fuel costs for Wisconsin retail customers under the current electric fuel recovery rules. Under the Wisconsin fuel recovery mechanism, certain costs are only recoverable on a pro rata basis for the portion of the year after PSCW approval. As such, the ability of our regulated utilities to earn their approved return on equity is dependent upon accurate forecasting, the ability to obtain timely rate increases to account for rising cost structures (while minimizing the required rate increases in order to maintain the competitiveness of our core industrial customer base and keep these customers in our service area), and certain conditions that are outside of their control (such as macroeconomic factors and weather conditions). To mitigate the risk of unrecoverable fuel costs in 2006 due to market price volatility, WPSC is employing risk management techniques pursuant to its risk policy approved by the PSCW, including the use of derivative instruments such as futures and options.
An additional risk within the ratemaking process, regulatory lag risk, occurs between the time we submit rate proceedings and the time we receive the final approval or denial from the PSCW, MPSC, or FERC. The regulatory lag risk may increase or decrease with any change in commodity prices, unplanned outages, or unscheduled maintenance during the approval period. Although the PSCW grants WPSC the ability to defer costs related to fuel and purchased power, the PSCW does not guarantee us the ability to recover the deferred costs from the ratepayers at a later point in time. To further manage commodity price risk and the associated regulatory lag risk, our regulated utilities enter into contracts of various durations for the purchase and/or sale of natural gas, fuel for electric generation, and electricity.
For purposes of risk management disclosure, ESI's activities are classified as non-trading. ESI has the ability to reduce market price risk and extract additional value from its merchant generation plants through the use of various financial and physical tools (including forward contracts and options). ESI also utilizes derivative financial instruments to manage market risks related to its retail supply portfolio.
Value-at-Risk
A Value-at-Risk analysis is utilized in order to measure commodity price risk exposure at ESI. ESI's Value-at-Risk calculation is utilized to quantify exposure to market risk associated with its marketing and trading portfolio (primarily natural gas and power positions), which includes near term positions managed
under its asset management strategy through tolling agreements with the merchant generating fleet, but excludes the long-dated positions created by the merchant generating fleet and associated coal, sulfur dioxide emission allowances, and other ancillary fuels.
Value-at-Risk is used to describe a probabilistic approach to quantifying the exposure to market risk. The Value-at-Risk amount represents an estimate of the potential change in fair value that could occur from changes in market factors, within a given confidence level, if an instrument or portfolio is held for a specified time period. Value-at-Risk models are relatively sophisticated. However, the quantitative risk information is limited by the parameters established in creating the model. The instruments being used may have features that could trigger a potential loss in excess of the calculated amount if the changes in the underlying commodity price exceed the confidence level of the model used. Value-at-Risk is not necessarily indicative of actual results that may occur. In addition to Value-at-Risk, ESI employs other risk measurements including mark-to-market valuations and stress testing. In conjunction with the Value-at-Risk, these other risk measurements provide the risk management analysis for ESI's risk exposure.
ESI's Value-at-Risk is estimated using a delta-normal approximation based on a one-day holding period and a 95% confidence level. The delta-normal approximation is based on the assumption that changes in the value of the portfolio over short time periods, such as one day, are normally distributed. ESI's Value-at-Risk calculation includes derivative financial and commodity instruments, such as forwards, futures, swaps, and options as well as commodities held in inventory, such as natural gas held in storage to the extent such positions are significant.
The Value-at-Risk for ESI's trading portfolio is presented in the following table:
Value-at-Risk (VaR) Disclosure for ESI
The Value-at-Risk amount for ESI increased $1.2 million from December 31, 2004, to December 31, 2005, due to extreme price volatility in the market, post hurricane production shut-ins, and unusual fluctuations in the various portfolios. The average, high, and low amounts were computed using the Value-at-Risk amounts at the beginning of the reporting period and the four quarter-end amounts.
Interest Rate Risk
WPS Resources and WPSC are exposed to interest rate risk resulting from their variable rate long-term debt and short-term commercial paper borrowing. Exposure to interest rate risk is managed by limiting the amount of variable rate obligations and continually monitoring the effects of market changes in interest rates. WPS Resources and WPSC enter into long-term fixed rate debt when it is advantageous to do so. WPS Resources and WPSC may also enter into derivative financial instruments, such as swaps, to mitigate interest rate exposure. In the second quarter of 2005, a variable rate non-recourse debt instrument used to finance the purchase of Sunbury was restructured to a WPS Resources obligation. An interest rate swap used to fix the interest rate on the Sunbury non-recourse debt was previously designated as a cash flow hedge. Subsequent to the restructuring, the interest rate swap was re-designated as a cash flow hedge, along with an additional interest rate swap, to fix the interest rate on the WPS Resources obligation.
Based on the variable rate debt of WPS Resources and WPSC outstanding at December 31, 2005, a hypothetical increase in market interest rates of 100 basis points in 2005 would have increased annual
interest expense in 2005 by approximately $2.9 million at WPS Resources and $0.9 million at WPSC. Comparatively, based on the variable rate debt outstanding at December 31, 2004, an increase in interest rates of 100 basis points would have increased interest expense in 2004 by approximately $3.2 million at WPS Resources and $1.0 million at WPSC. These amounts were determined by performing a sensitivity analysis on the impact of a hypothetical 100 basis points increase in interest rates on the variable rate debt of WPS Resources and WPSC outstanding as of December 31, 2005 and 2004. The sensitivity analysis was performed assuming a constant level of variable rate debt during the period and an immediate increase in the levels of interest rates, with no other subsequent changes for the remainder of the period. In the event of a significant change in interest rates, management would take action to mitigate WPS Resources’ and WPSC's exposure to the change.
Equity Return and Principal Preservation Risk
WPS Resources and WPSC currently fund liabilities (accumulated benefit obligations) related to employee benefits through various external trust funds. The trust funds are managed by numerous investment managers and hold investments in debt and equity securities. Changes in the market value of these investments can have an impact on the future expenses related to these liabilities. WPS Resources maintains a qualified pension plan for employees' retirement. The liability (accumulated benefit obligation) of the qualified plan was less than the value of the qualified plan's assets by $35.8 million at December 31, 2005, and WPS Resources was required to recognize a minimum pension liability as prescribed by SFAS No. 87. Declines in the equity markets or declines in interest rates may result in increased future pension costs for the plan and possible future required contributions. Changes in the market value of investments related to other employee benefits could also impact future contributions. WPS Resources monitors the trust fund portfolio by benchmarking the performance of the investments against certain security indices. Most of the employee benefit costs relate to WPS Resources' regulated utilities. As such, the majority of these costs are recovered in customers' rates, mitigating the equity return and principal preservation risk on these exposures.
Foreign Currency Exchange Rate Risk
WPS Resources is exposed to foreign currency risk as a result of foreign operations owned and operated in Canada and transactions denominated in Canadian dollars for the purchase and sale of natural gas and electricity by our nonregulated subsidiaries. Forward foreign exchange contracts are utilized to manage the risk associated with currency fluctuations on certain firm sales and sales commitments denominated in Canadian dollars and certain Canadian dollar denominated asset and liability positions. WPS Resources’ exposure to foreign currency risk was not significant at December 31, 2005, or 2004.
Construction Risk
Large construction projects, such as Weston 4, are subject to various construction risks, which we have little or no control over, and can negatively affect completion time and project costs. These risks include, but are not limited to, the shortage of or inability to obtain labor or materials, unfavorable weather conditions, events in the economy, and changes in applicable laws or regulations.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
WPS RESOURCES CORPORATION
A. MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of WPS Resources and its subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting. WPS Resources' control systems were designed to provide reasonable assurance to WPS Resources' management and Board of Directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
WPS Resources' management assessed the effectiveness of its internal control over financial reporting as of December 31, 2005. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, management believes that, as of December 31, 2005, WPS Resources' internal control over financial reporting is effective based on those criteria.
WPS Resources Corporation's independent registered public accounting firm has issued an audit report on management's assessment of WPS Resources' internal control over financial reporting.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
WPS RESOURCES CORPORATION
B. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of WPS Resources Corporation
We have audited management's assessment, included in the accompanying Management Report on Internal Control over Financial Reporting, that WPS Resources Corporation and subsidiaries (the "Company") maintained effective internal control over financial reporting as of December 31, 2005, based on 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 financial statements and financial statement schedules as of and for the year ended December 31, 2005 of the Company and our report dated February 28, 2006 expressed an unqualified opinion on those financial statements and financial statement schedules and included an explanatory paragraph regarding the Company's adoption of new accounting standards.
/s/ Deloitte & Touche LLP
Milwaukee, Wisconsin
February 28,
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
WPS RESOURCES
G. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Notes to the Consolidated Financial Statements that follow include consolidated WPS Resources footnotes and certain combined footnotes for both WPS Resources and its wholly owned subsidiary registrant, WPSC. WPSC's financial statements also include supplemental footnotes related to WPSC. Refer to Item 8, Section P for a listing of the combined footnotes included in the WPS Resources notes and the supplemental footnotes that are applicable to the WPSC registrant.
NOTE 1--SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) Nature of Operations--WPS Resources is a holding company. Our wholly owned subsidiary, WPSC, is an electric and natural gas utility. WPSC supplies and distributes electric power and natural gas in its franchised service territory in northeastern Wisconsin and an adjacent portion of the Upper Peninsula of Michigan. Our other wholly owned utility subsidiary, UPPCO, is an electric utility. UPPCO supplies and distributes electric energy to a portion of the Upper Peninsula of Michigan. Our wholly owned nonregulated subsidiary, ESI, offers nonregulated natural gas, electric, and alternative fuel supplies, as well as energy management and consulting services to retail and wholesale customers. ESI also owns several merchant electric generation plants, primarily in the Midwest and Northeastern United States and adjacent portions of Canada.
The term "utility" refers to the regulated activities of WPSC and UPPCO, while the term "nonutility" refers to the activities of WPSC and UPPCO that are not regulated. The term "nonregulated" refers to activities other than those of WPSC and UPPCO.
(b) Consolidation Basis of Presentation--The Consolidated Financial Statements include the accounts of WPS Resources and all majority owned subsidiaries, after eliminating significant intercompany transactions and balances. If a minority owner's equity is reduced to zero, our policy is to record 100% of the subsidiary's losses until the minority owner makes capital contributions or commitments to fund its share of the operating costs. The cost method of accounting is used for investments when WPS Resources owns less than 20% of the voting equity of the company, unless other evidence indicates we have significant influence over the operating and financial policies of the investee. Investments in businesses not controlled by WPS Resources, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method. For additional information on our equity method investments see Note 10, "Investments in Affiliates, at Equity Method."
(c) Use of Estimates--We prepare our financial statements in conformity with accounting principles generally accepted in the United States of America. We make estimates and assumptions that affect reported amounts. These estimates and assumptions affect assets, liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates.
(d) Cash and Cash Equivalents--We consider short-term investments with an original maturity of three months or less to be cash equivalents.
Cash paid for taxes during 2005, 2004, and 2003 was $50.4 million, $37.0 million, and $21.9 million, respectively. During 2005, 2004, and 2003, cash paid for interest totaled $59.6 million, $54.4 million, and $57.9 million, respectively.
Non-cash transactions were as follows:
(e) Revenue and Customer Receivables--Revenues are recognized on the accrual basis and include estimated amounts for electric and natural gas services rendered but not billed. Of WPS Resources’ total revenue, 6.3%, 6.5%, and 5.7% was from companies in the paper products industry in 2005, 2004, and 2003, respectively. Of WPSC’s total revenue, 11.2%, 10.1%, and 8.6% was from companies in the paper products industry in 2005, 2004, and 2003, respectively.
WPSC and UPPCO use automatic fuel and purchased power adjustment clauses for the MPSC retail electric portions of their business. WPSC also uses automatic fuel and purchased power adjustment clauses for its FERC wholesale electric business; however, at UPPCO, most wholesale electric contracts are special contracts and have no automatic fuel and purchased power adjustment clauses. The Wisconsin retail electric portion of WPSC's business uses a "cost variance range" approach, based on a specific estimated fuel and purchased power cost for the forecast year. If WPSC's actual fuel and purchased power costs fall outside this range, the PSCW can authorize an adjustment to future rates. Decreases to rates can be implemented without a hearing, unless requested by WPSC, PSCW staff, or interveners, while increases to rates are generally subject to a hearing.
Billings to UPPCO's customers under the MPSC's jurisdiction include base rate charges and a power supply cost recovery factor. Power supply cost recovery factors are established annually to recover projected power supply costs approved by the MPSC. The MPSC reconciles these factors to actual costs annually and permits 100% recovery of allowed power supply costs. UPPCO recognizes any over or under recovery currently in its revenues, and the payable or receivable is recognized on the balance sheet until settlement. The deferrals are relieved with additional billings or refunds.
The PSCW approved a modified one-for-one gas cost recovery plan for WPSC. This plan allows WPSC to pass changes in the cost of natural gas on to system natural gas customers, subject to regulatory review by the PSCW for reasonableness.
The MPSC has approved one-for-one recovery of prudently incurred natural gas costs for WPSC, subject to regulatory review. The MPSC also approved a natural gas cost recovery factor adjustment mechanism for WPSC for the period November 2005 through October 2006. This adjustment mechanism allows WPSC to adjust the maximum natural gas rates that can be charged to customers in Michigan based on upward or downward changes to the NYMEX natural gas futures price without further MPSC action.
WPSC and UPPCO are required to provide service and grant credit to customers within their service territories. The two companies continually review their customers' credit-worthiness and obtain or refund deposits accordingly. Both utilities are precluded from discontinuing service to residential customers during winter moratorium months. The regulated segments calculate a reserve for potential uncollectible customer receivables using a four-year average of bad debts net of recoveries as a percentage of total accounts receivable. The historical percentage is reviewed in light of the current year conditions, and an appropriate percentage is applied to the current year-end accounts receivable balance to determine the required reserve balance.
For ESI's merchant electric generation plants, electric power revenues related to fixed-price contracts are recognized at the lower of amounts billable under the contract or an amount equal to the volume of the capacity made available or the energy delivered during the period multiplied by the estimated average
revenue per kilowatt-hour per the terms of the contract. Under floating-price contracts, electric power revenues are recognized when capacity is provided or energy is delivered.
For its nonregulated business of supplying energy, management, and consulting services to retail and wholesale customers, ESI accrues revenues in the month that energy is delivered and/or services are rendered. With the January 1, 2003, adoption of Emerging Issues Task Force Issue No. 02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," revenues related to derivative instruments classified as trading are reported net of related cost of sales for all periods presented. Most revenues in 2005, 2004, and 2003 continue to be reported on a gross basis. See Note 1(u), "Cumulative Effect of Change in Accounting Principles," for more information.
In the fourth quarter of 2003, WPS Resources adopted Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments that are Subject to SFAS No. 133 and Not 'Held for Trading Purposes' as Defined in Issue No. 02-03," which resulted in recording nonregulated revenues net of cost of fuel, natural gas, and purchased power for energy-related transactions entered into after October 1, 2003, that settle financially and for which the commodity does not physically transfer. Had the provisions of Issue No. 03-11 been applied to arrangements entered into prior to October 1, 2003, previously reported nonregulated revenue would have decreased $62.9 million for the nine months ended September 30, 2003, with a corresponding $62.9 million decrease to nonregulated cost of fuel, natural gas, and purchased power. Previously reported wholesale natural gas sales volumes for the nine months ended September 30, 2003 would have decreased 10.8 billion cubic feet. Neither margins, income, or cash flows were impacted by the adoption of Issue No. 03-11.
ESI calculates the reserve for potential uncollectible customer receivable balances by applying an estimated bad debt experience rate to each past due aging category and reserving for 100% of specific customer receivable balances deemed to be uncollectible. The basis for calculating the reserve for receivables from wholesale counterparties considers netting agreements, collateral, and guarantees.
(f) Inventories--Inventories consist of natural gas in storage and fossil fuels, including coal. Average cost is used to value fossil fuels and natural gas in storage for our regulated segments. Inventories at ESI are valued at the lower of cost or market unless hedged pursuant to a fair value hedge, in which case it is marked to the spot rate.
(g) Risk Management Activities--As part of our regular operations, WPS Resources enters into contracts, including options, swaps, futures, forwards, and other contractual commitments, to manage market risks such as changes in commodity prices and interest rates.
WPS Resources accounts for its derivative contracts in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended and interpreted. SFAS No. 133 establishes accounting and financial reporting standards for derivative instruments and requires, in part, that we recognize certain derivative instruments on the balance sheet as assets or liabilities at their fair value. Subsequent changes in fair value of the derivatives are recorded currently in earnings unless certain hedge accounting criteria are met. If the derivatives qualify for regulatory deferral subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," the derivatives are marked to fair value pursuant to SFAS No. 133 and are offset with a corresponding regulatory asset or liability.
WPS Resources classifies mark-to-market gains and losses on derivative instruments not qualifying for hedge accounting as a component of revenues.
(h) Emission Allowances--ESI accounts for emission allowances using an intangible asset model, with cash inflows and outflows related to purchases and sales of emission allowances recorded as investing activities in the Consolidated Statements of Cash Flows. ESI uses the guidance in SFAS No. 144, "Accounting for the Impairment and Disposal of Long-Lived Assets," to test for impairment. The utilities generally do not purchase or sell emission allowances, but use the inventory accounting model for emission allowances granted at zero cost and utilized in operating the utilities' generation plants.
(i) Property, Plant, and Equipment--Utility plant is stated at the original cost of construction including an allowance for funds used during construction. The cost of renewals and betterments of units of property (as distinguished from minor items of property) is capitalized as an addition to the utility plant accounts. Except for land, no gain or loss is recognized in connection with ordinary retirements of utility property units. Maintenance, repair, replacement, and renewal costs associated with items not qualifying as units of property are considered operating expenses. The utility charges the cost of units of property retired, sold, or otherwise disposed of, less salvage, to the accumulated provision for depreciation. The cost of removal associated with the retirement is charged to a regulatory liability.
We record straight-line depreciation expense over the estimated useful life of utility property and include amounts for estimated removal and salvage. The PSCW approved new depreciation rates for WPSC effective January 1, 2005, which have not had a material impact on annual depreciation expense. Depreciation rates for UPPCO were approved by the MPSC effective January 1, 2002. Annual utility composite depreciation rates are shown below.
Nonutility property interest capitalization takes place during construction, and gain and loss recognition occurs in connection with retirements. Nonutility property is depreciated using straight-line depreciation. Asset lives range from 3 to 20 years.
Nonregulated plant is stated at the original construction cost, which includes capitalized interest, or estimated fair value at the time of acquisition pursuant to a business combination. The costs of renewals, betterments, and major overhauls are capitalized as an addition to plant. The gains or losses associated with ordinary retirements are recorded in the period of retirement. Maintenance, repair, and minor replacement costs are expensed as incurred.
Most of the nonregulated subsidiaries compute depreciation using the straight-line method over the following estimated useful lives:
Structures and improvements
to 40 years
Office and plant equipment
to 35 years
Office furniture and fixtures
to 10 years
Vehicles
years
Computer equipment
years
Leasehold improvements
Shorter of: life of the lease or life of the asset
The Combined Locks Energy Center uses the units of production depreciation method for selected pieces of equipment having defined lives stated in terms of hours of production.
WPS Resources capitalizes certain costs related to software developed or obtained for internal use and amortizes those costs to operating expense over the estimated useful life of the related software, which is usually three to seven years.
(j) Capitalized Interest and Allowance for Funds Used During Construction--Our nonregulated subsidiaries capitalize interest for construction projects, while our utilities use an allowance for funds used during construction (AFUDC) calculation, which includes both a debt and an equity component as required by regulatory accounting.
Approximately 50% of WPSC's retail jurisdictional construction work-in-progress expenditures are subject to AFUDC, except on specific projects approved by the PSCW. For 2005, WPSC's AFUDC retail rate was
9.0%. A current return for construction funds related to Weston 4 is being recovered from ratepayers as incurred.
WPSC's construction work-in-progress AFUDC debt and equity percentage formula for the wholesale jurisdiction is specified in the FERC's Uniform System of Accounts. The 2005 average AFUDC wholesale rate was 7.13%.
WPSC's allowance for equity funds used during construction for 2005, 2004, and 2003 was $1.5 million, $2.0 million, and $2.4 million, respectively. WPSC's allowance for borrowed funds used during construction for 2005, 2004, and 2003 was $0.4 million, $0.7 million, and $1.0 million, respectively. UPPCO did not record AFUDC for 2005, 2004, or 2003, as UPPCO did not have significant construction projects during these years.
Our nonregulated subsidiaries calculate capitalized interest on long-term construction projects for periods during which financing is provided by WPS Resources through interim debt. The interest rate capitalized is based upon the monthly short-term borrowing rate WPS Resources incurs for such funds. The amount of interest capitalized during 2005, 2004, and 2003 was not significant.
(k) Asset Impairment--We review the recoverability of long-lived tangible and intangible assets, excluding goodwill, other indefinite lived intangible assets, and regulatory assets, in accordance with SFAS No. 144. This Statement requires review of assets when circumstances indicate that the carrying amount may not be recoverable. The carrying amount of assets held and used is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset's carrying value over its fair value. The carrying value of assets held for sale is not recoverable if it exceeds the fair value less cost to sell the asset. An impairment charge is recorded for any excess of the carrying value over the fair value less cost to sell. If events or circumstances indicate the carrying value of investments accounted for under the equity method of accounting may not be recoverable, potential impairment is assessed by comparing the future anticipated cash flows from these investments to their carrying values. Impairment charges are recorded if the carrying value of such assets exceeds the future anticipated cash flows. See Note 4, "Sunbury Plant," for information related to the impairment charge recorded at Sunbury in 2005.
(l) Regulatory Assets and Liabilities--WPSC and UPPCO are subject to the provisions of SFAS No. 71. Regulatory assets represent probable future revenue associated with certain incurred costs that will be recovered from customers through the ratemaking process. Regulatory liabilities represent amounts that are refundable in future customer rates. Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, we believe that future recovery of our regulatory assets is probable.
(m) Goodwill and Other Intangible Assets--In accordance with SFAS No. 142, "Goodwill and Other Intangible Assets," goodwill and other assets with indefinite lives are not amortized, but are subject to annual impairment tests. WPSC performs its impairment test during the second quarter of each year, while ESI performs its impairment test annually during the third quarter. The impairment tests are updated whenever events or changes in circumstances indicate that the assets might be impaired. Based upon the results of testing, no impairments were noted in 2005, 2004, or 2003.
Other intangible assets with definite lives, consisting primarily of emission allowances and customer related intangible assets, are amortized over periods from 1 to years. For more information on WPS Resources' intangible assets, see Note 11, "Goodwill and Other Intangible Assets."
(n) Retirement of Debt--Premiums, discounts, and expenses incurred with the issuance of outstanding long-term debt are amortized over the terms of the debt issues. Any call premiums or unamortized expenses associated with refinancing higher-cost debt obligations used to finance regulated assets and operations are amortized consistent with regulatory treatment of those items, where appropriate.
(o) Research and Development--Electric research and development expenditures for WPSC totaled $0.7 million, $0.7 million, and $0.6 million, in 2005, 2004, and 2003, respectively. No other research and development expenditures were significant.
(p) Asset Retirement Obligations--Effective January 1, 2003, WPS Resources adopted SFAS No. 143, "Accounting for Asset Retirement Obligations." Under this accounting standard, WPS Resources recognized, at fair value, legal obligations associated with the retirement of tangible long-lived assets that resulted from the acquisition, construction or development, and/or normal operation of the asset. The asset retirement obligation is accreted using a credit-adjusted risk-free interest rate commensurate with the expected settlement date of the asset retirement obligation. The associated retirement costs were capitalized as part of the related long-lived asset and depreciated over the useful life of the asset. The total of the depreciation and accretion from the initial date of obligation through the adoption date of SFAS No. 143 were recorded as a cumulative effect of change in accounting principle for ESI and as a net regulatory asset for our regulated operations.
In March 2005, the FASB issued Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations." SFAS No. 143 had been inconsistently applied in practice because the accounting for conditional asset retirement obligations was interpreted differently among companies. An asset retirement obligation is conditional when the timing and/or method of settling the obligation is conditioned on a future event. Many companies, including WPS Resources, did not record a liability for conditional asset retirement obligations under the guidance of SFAS No. 143, concluding that either (1) the conditional nature of the obligation did not create a liability until the retirement activity occurred or (2) the timing and/or method of settling the obligation was unknown.
Interpretation No. 47 concludes that, if required legally, an obligation associated with an asset's retirement is inevitable, even though uncertainties may exist regarding the timing and/or method of settling the obligation. According to the Interpretation, these uncertainties affect the fair value of the liability, rather than negate the need to record one at all. Additionally, the ability of a company to indefinitely postpone settlement of the obligation, or to sell the asset prior to its retirement, does not relieve a company of its present duty to settle the obligation. Therefore, the Interpretation concluded that conditional asset retirement obligations are within the scope of SFAS No. 143. WPS Resources adopted Interpretation No. 47 as of December 31, 2005. Asset retirement obligations included within the scope of Interpretation No. 47 are calculated and recorded utilizing the methodology in SFAS No. 143. See Note 1(u), "Cumulative Effect of Change in Accounting Principles," and Note 15, "Asset Retirement Obligations," for additional information regarding SFAS No. 143 and Interpretation No. 47.
(q) Income Taxes--We account for income taxes using the liability method as prescribed by SFAS No. 109, "Accounting for Income Taxes." Under this method, deferred income taxes have been recorded using currently enacted tax rates for the differences between the tax basis of assets and liabilities and the basis reported in the financial statements. Due to the effects of regulation on WPSC and UPPCO, certain adjustments made to defer income taxes are, in turn, recorded as regulatory assets or liabilities.
Investment tax credits, which have been used to reduce our federal income taxes payable, have been deferred for financial reporting purposes. These deferred investment tax credits are being amortized over the useful lives of the property to which they relate.
WPS Resources is an indirect part owner of a facility that produces synthetic fuel that qualifies for tax credits under Section 29 if certain requirements are satisfied. Section 29 tax credits are currently scheduled to expire at the end of 2007. Tax credits that are not used to reduce tax expense as a result of alternative minimum tax rules relating to United States federal income taxes are carried forward as alternative minimum tax credits to reduce current tax expense in future years. Under current federal law, alternative minimum tax credits do not expire. In the fourth quarter of 2005, WPS Resources was informed that partnership returns for the facility filed for the 2002 and tax years were under review by the IRS. It is our understanding that this review of the partnership returns is part of the examination the IRS is conducting of the consolidated corporate filings of one of the partners for the same period.
WPS Resources files a consolidated United States income tax return that includes domestic subsidiaries of which its ownership is 80% or more. WPS Resources and its consolidated subsidiaries are parties to a tax allocation arrangement under which each entity determines its income tax provision on a stand-alone basis, after which the effects of federal consolidation are accounted for. In several states, combined or consolidated filing is required for certain members of the WPS Resources group doing business in that state. The tax allocation arrangement is used to equitably allocate the state taxes associated with these combined or consolidated filings.
WPS Resources records a reserve for uncertain tax positions based upon management's assessment of the probabilities that certain deductions or income tax positions may not be sustained when income tax returns are audited by taxing jurisdictions. Our identified tax exposures are discussed below.
WPS Resources and its subsidiaries have routinely been subject to examination by various taxing jurisdictions, including the IRS, Wisconsin Department of Revenue, and other state and local taxing jurisdictions. At any given time there might be several of these audits open covering multiple tax years. Management has not been informed by any taxing jurisdictions of any material adjustment to any filed or proposed tax position as a result of the on-going examinations.
WPS Resources had submitted a request to have the IRS conduct a pre-filing review of a tax position related to the 2004 tax return. The tax position related to the value of land located near the Peshtigo River that was donated to the WDNR. A pre-filing review of the land donation deduction was initiated by the IRS in the first quarter of 2005; however, in the second quarter, WPS Resources and the IRS mutually agreed to withdraw this issue from the pre-filing review process, citing an inability to reach a consensus on the tax treatment and value of the land donated. WPS Resources believes the value placed on the donated land was reasonable and will continue to pursue this matter if challenged by the IRS upon examination of the tax return.
The combined current benefit of Section 29 tax credits and the deferred benefit of alternative minimum tax credits (arising from Section 29 tax credits) is limited to an amount equal to the WPS Resources regular consolidated federal tax liability. In 2004, and in some previous years, this limitation has impacted the amount of the tax benefit recorded as compared to actual Section 29 tax credits produced. For 2005, this limitation did not impact the tax benefit recorded.
Section 29 tax credits are subject to phase out if the reference price of oil within that year exceeds a threshold price set by the IRS and is eliminated entirely if the reference price increases beyond a phase-out price. WPS Resources does not believe a phase-out will be applicable to 2005. WPS Resources records a tax benefit with respect to Section 29 tax credits based upon its assessment of the probability of sustaining the filing position for federal tax returns and its judgment related to the potential for a phase-out of credits.
(r) Excise Taxes--WPS Resources presents revenue net of pass-through taxes on the Consolidated Statements of Income.
(s) Guarantees--FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees Including Indirect Guarantees of Indebtedness of Others," requires that the guarantor recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. See Note 18, "Guarantees," for additional information on Interpretation
No. 45.
(t) Stock-Based Employee Compensation--WPS Resources has stock-based employee compensation plans, which are described more fully in Note 22, "Stock-Based Compensation." WPS Resources accounts for these plans under the recognition and measurement provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. Upon grant of stock options, no stock-based employee compensation cost is reflected in net income, as all options granted under these plans had an exercise price equal to the market value of
the underlying common stock on the date of grant. The following table illustrates the effect on income available for common shareholders and earnings per share if WPS Resources had applied the fair value recognition provisions of SFAS No. 123, "Accounting for Stock-Based Compensation," to stock-based employee compensation:
The fair value of each stock option grant is estimated on the date of grant using the Black-Scholes stock option pricing model assuming:
(u) Cumulative Effect of Change in Accounting Principles--The adoption of Interpretation No. 47 on December 31, 2005, resulted in a $1.6 million after-tax cumulative effect of change in accounting principle, decreasing income available for common shareholders, related to recording a liability for asbestos remediation at certain ESI generating plants. The adoption of SFAS No. 143 on January 1, 2003, resulted in a $0.3 million after-tax cumulative effect of change in accounting principle, decreasing income available for common shareholders, related to recording a liability for the closure of an ash basin at Sunbury. For the utility segments of WPS Resources, we concluded it was probable that any differences between expenses under Interpretation No. 47 and SFAS No. 143, and expenses currently recovered through customer rates, will be recoverable or refundable in future customer rates. Accordingly, neither the adoption of Interpretation No. 47 nor the adoption of SFAS No. 143 had any impact on the utility segments' income, as its effect is offset by the establishment of regulatory assets or liabilities pursuant to SFAS No. 71.
Prior to its rescission in 2002, ESI had been applying the accounting standards of Issue No. 98-10. ESI was defined as a trading company under Issue No. 98-10 and was required to mark all of its energy-related contracts to market. On October 25, 2002, the Emerging Issues Task Force rescinded Issue No. 98-10, thus precluding mark-to-market accounting for energy trading contracts entered into after that date that are not derivatives and requiring a cumulative effect of change in accounting principle to be recorded effective January 1, 2003, for all nonderivative contracts entered into on or prior to October 25, 2002. On January 1, 2003, WPS Resources recorded an after-tax cumulative effect of a change in accounting principle of $3.5 million (related to ESI operations) to increase income available for common shareholders as a result of removing from its balance sheet the mark-to-market effects of those contracts entered into on or prior to October 25, 2002, that do not meet the definition of a derivative under SFAS
No. 133. The required change in accounting had no impact on the underlying economics or cash flows of the contracts.
(v) Reclassifications--We reclassified certain prior year financial statement amounts to conform to the current year presentation.
(w) New Accounting Pronouncements--In December 2004, the FASB issued SFAS No. 123R, "Share-Based Payment," which addresses the accounting for share-based payment transactions. SFAS No. 123R eliminates the ability to account for share-based compensation transactions using Accounting Principles Board Opinion No. 25, and requires companies to measure the cost of share-based awards at their grant date fair value. That cost is recognized over the period during which an employee is required to provide service in exchange for the award. SFAS No. 123R is effective for WPS Resources beginning in the first quarter of 2006. WPS Resources has chosen the modified prospective method of adopting the Statement. Under this method, all share-based payment awards granted after December 31, 2005, will be measured at fair value and recognized as a component of income available for common shareholders over the requisite service period of the award. Additionally, compensation cost for the portion of awards granted on or before December 31, 2005, for which the requisite service has not been rendered, but which are outstanding as of the beginning of the first quarter of 2006 will be recognized as the remaining requisite service is rendered. The impact on WPS Resources' financial position and results of operations will be dependent upon a number of factors, including share-based awards granted in 2006. Because we do not know the number of share-based awards that will be granted in 2006, we cannot estimate the precise effect that SFAS No. 123R will have on our financial position and results of operations. However, assuming the number of share-based awards granted in 2006 remains consistent with prior years, we do not anticipate that the incremental impact to income available for common shareholders of adopting SFAS No. 123R in 2006 will differ significantly from the pro-forma amounts disclosed in Note 1(t), "Stock-Based Compensation," for prior years.
NOTE 2--FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each class of financial instrument for which it is practicable to estimate such value:
Cash, Short-Term Investments, Energy Conservation Loans, Notes Payable, and Outstanding Commercial Paper: The carrying amount approximates fair value due to the short maturity of these investments and obligations.
Nuclear Decommissioning Trusts: Nuclear decommissioning trust investments were recorded at fair value, net of taxes payable on unrealized gains and losses. In 2005, the qualified nuclear decommissioning trust assets were sold in conjunction with the sale of Kewaunee and the nonqualified nuclear decommissioning trust assets were liquidated. See Note 6, "Acquisitions and Sales of Assets," for more information.
Long-Term Debt and Preferred Stock: The fair values of long-term debt and preferred stock are estimated based on the quoted market price for the same or similar issues or on the current rates offered to WPS Resources for debt of the same remaining maturity.
Risk Management Activities: Assets and liabilities from risk management activities are recorded at fair value pursuant to SFAS No. 133.
The estimated fair values of our financial instruments as of December 31 were:
NOTE 3--RISK MANAGEMENT ACTIVITIES
The following table shows WPS Resources' assets and liabilities from risk management activities as of December 31, 2005, and 2004:
Assets and liabilities from risk management activities are classified as current or long-term based upon the maturities of the underlying financial instruments.
Utility Segments
WPSC has entered into a limited number of electric purchase contracts that are accounted for as derivatives and are shown in the above table. Financial transmission rights in the above table include financial instruments used to manage the transmission congestion costs of the electric utilities. In 2005, WPSC's portion of the assets and liabilities related to financial transmission rights was $13.6 million and $1.7 million, respectively. In 2004, all of the utility segments' financial transmission rights belonged to WPSC. The PSCW approved the recognition of a regulatory asset or liability for the fair value of derivative instruments. Thus, management believes any gains or losses resulting from the eventual settlement of these derivative instruments will be collected from or refunded to customers.
Nonregulated Segments
The derivatives in the nonregulated segments not designated as hedges under generally accepted accounting principles are primarily commodity contracts used to manage price risk associated with natural gas and electric energy purchase and sale activities, and foreign currency contracts used to manage foreign currency exposure related to ESI's Canadian operations. In addition, ESI entered into a series of derivative contracts (options) covering a specified number of barrels of oil in order to manage exposure to the risk of an increase in oil prices that could result in a phase-out of Section 29 federal tax credits that can be recognized from ESI's investment in a synthetic fuel production facility for 2006 and 2007. See Note 1(q), "Income Taxes," and Note 17, "Commitments and Contingencies," for more information. Changes in the fair value of non-hedge derivatives are recognized currently in earnings.
Our nonregulated segments also enter into derivative contracts that are designated as either fair value or cash flow hedges. Fair value hedges are used to mitigate the risk of changes in the price of natural gas held in storage. The changes in the fair value of these hedges are recognized currently in earnings, as are the changes in fair value of the hedged items. Fair value hedge ineffectiveness recorded in nonregulated revenue on the Consolidated Statements of Income was a pre-tax loss of $2.5 million in 2005 and was not significant in 2004 or 2003. At December 31, 2005, and 2004, pre-tax mark-to-market losses of $5.8 million and $0.6 million, respectively, related to changes in the difference between the spot and forward prices of natural gas were excluded from the assessment of hedge effectiveness. These losses were reported directly in earnings.
Commodity contracts that are designated as cash flow hedges extend through December 2007 and are used to mitigate the risk of cash flow variability associated with the future purchases and sales of natural gas and electricity. To the extent they are effective, the changes in the values of these contracts are included in other comprehensive income, net of taxes. Cash flow hedge ineffectiveness recorded in nonregulated revenue on the Consolidated Statements of Income was a pre-tax loss of $2.6 million in 2005 and was not significant in 2004 or 2003. When testing for effectiveness, no portion of the derivative instruments was excluded. Amounts recorded in other comprehensive income related to these cash flow hedges will be recognized in earnings as the related contracts are settled, or if it is probable that the hedged transaction will not occur. During 2005 and 2004, we reclassified after-tax gains of $3.1 million and $1.9 million, respectively, from other comprehensive income into earnings as a result of the discontinuance of cash flow hedge accounting for certain hedge transactions. The amount reclassified in 2003 was not significant. In the next 12 months, subject to changes in market prices of natural gas and electricity, we expect that an after-tax loss of $8.6 million will be recognized in earnings as contracts are settled. We expect this amount to be substantially offset by settlement of the related nonderivative contracts that are being hedged.
In the second quarter of 2005, a variable rate non-recourse debt instrument used to finance the purchase of Sunbury was restructured to a WPS Resources obligation. An interest rate swap used to fix the interest rate on the Sunbury non-recourse debt had been previously designated as a cash flow hedge. As a result of the debt restructuring, the hedged transaction will no longer occur. This resulted in the recognition of a $9.1 million pre-tax loss (equivalent to the mark-to-market value of the swap at the date of restructuring), which was recorded as a component of interest expense in the second quarter of 2005. This loss was previously deferred as a component of other comprehensive income pursuant to hedge accounting rules. Subsequent to the restructuring, the interest rate swap was re-designated as a cash flow hedge, along with an additional interest rate swap, to fix the interest rate on the WPS Resources obligation. The changes in the fair value of the effective portion of these swaps are included in other comprehensive income, net of deferred taxes, while the changes related to the ineffective portion are recorded in earnings. During the year ended December 31, 2005, cash flow hedge ineffectiveness recorded in earnings related to these swaps was not significant. Amounts recorded in other comprehensive income related to these swaps will be recognized as a component of interest expense as the interest becomes due. In the next 12 months, we expect to recognize a $0.2 million pre-tax reduction to interest expense related to these swaps, assuming interest rates comparable to those at December 31, 2005. We did not
exclude any component of the derivative instruments' change in fair value from the assessment of hedge effectiveness.
NOTE 4--SUNBURY PLANT
In the second quarter of 2005, ESI sold all of Sunbury's allocated emission allowances. Prior to this decision, ESI had marketed for sale the Sunbury plant and certain other related assets (primarily inventory and unallocated emission allowances) in combination with the allocated emission allowances. The Sunbury facility sells power on a wholesale basis and is located in the PJM. Following Duquesne Power, L.P.'s termination of the previously announced agreement to sell Sunbury to Duquesne for approximately $120 million, ESI continued to pursue the sale of Sunbury with the assistance of an investment banking firm, but a suitable buyer was not found.
Total sales proceeds from the sale of Sunbury's emission allowances were $109.9 million, resulting in a pre-tax gain of $85.9 million. The sale of the emission allowances provides ESI with more time to consider various alternatives for the Sunbury plant. All available solid fuel units at the Sunbury plant were operated for most of 2005, as market conditions were generally favorable. When market conditions are unfavorable, ESI plans to place the plant in a stand-by mode of operation, which serves to minimize future operating expenses while maintaining several options for the plant (including closing the plant, retaining the plant and operating it during favorable economic periods, repowering the plant, or a potential future sale of the plant). Dispatching Sunbury in a stand-by mode of operation helps focus production on higher-priced periods, generally in the winter and mid-summer months. The success of a stand-by mode of operation depends on Sunbury's ability to minimize costs during non-operating periods.
Prior to the decision to sell the emission allowances separately, the Sunbury plant, allocated emission allowances, and other related assets had been classified as held for sale as a combined asset disposal group. However, because ESI is no longer committed to the sale of Sunbury as its only option, those assets and liabilities previously classified as held for sale that no longer meet the held for sale criteria outlined in SFAS No. 144, were required to be reclassified to the appropriate held and used categories for all periods presented. As a result, the allocated emission allowances that were sold in May 2005 remain classified as held for sale at December 31, 2004, but the Sunbury plant, unallocated emission allowances, and other related assets and liabilities were reclassified as held and used.
All long-lived assets reclassified as held and used are required to be recorded individually at the lower of their carrying value before they were classified as assets held for sale (adjusted for any depreciation expense that would have been recognized had they been continuously classified as held and used) or fair value at the date the held for sale criteria were no longer met. Upon reclassification of the Sunbury plant and related assets as held and used in 2005, ESI recorded a non-cash, pre-tax impairment charge of $80.6 million. The impairment charge substantially offsets the gain on the sale of the emission allowances.
The major classes of assets held for sale at December 31, 2004, were as follows:
NOTE 5--PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment consist of the following utility, nonutility, and nonregulated assets.
The accumulated provision for nuclear fuel, which represents nuclear fuel purchases and amortization, totaled approximately $273 million at December 31, 2004.
NOTE 6--ACQUISITIONS AND SALES OF ASSETS
Agreement to Purchase Aquila's Michigan and Minnesota Natural Gas Distribution Operations
On September 21, 2005, WPS Resources, through wholly owned subsidiaries, entered into two definitive agreements with Aquila to acquire its natural gas distribution operations in Michigan and Minnesota for approximately $558 million, exclusive of direct costs of the acquisition. The purchase price will increase for certain adjustments related to working capital, including accounts receivable, unbilled revenue, inventory, and certain other current assets. The purchase price is also subject to other closing and post-closing adjustments, primarily net plant adjustments. The purchase price will be paid in cash at the time of closing.
The Michigan natural gas assets provide natural gas distribution service in 147 cities and communities throughout Otsego, Grand Haven, and Monroe counties. The assets operate under a cost-of-service environment and are currently allowed an 11.4% return on equity on a 45% equity component of the regulatory capital structure.
The Minnesota natural gas assets provide natural gas distribution service throughout the state in 165 cities and communities including Grand Rapids, Pine City, Rochester, and Dakota County. Like Michigan, the assets also operate under a cost-of-service environment and are currently allowed an 11.7% return on equity on a 50% equity component of the regulatory capital structure.
WPS Resources anticipates permanent financing for the acquisition to be raised through the issuance of a combination of equity and long-term debt. See Note 21, "Common Equity," for a discussion of the forward equity sale agreement entered into to fund a portion this acquisition.
The transaction is subject to various state and other regulatory approvals, such as the MPSC and the Minnesota Public Utilities Commission, and is subject to compliance with the Hart-Scott-Rodino Act. MPSC approval was received in November 2005 and the waiting period under the Hart-Scott-Rodino Act has expired. Assuming an approval from the Minnesota Public Utilities Commission is obtained in a timely manner, WPS Resources anticipates closing both transactions in the first half of 2006.
Sale of UPPCO Lands
In December 2005, UPPCO sold a portion of its real estate holdings that were no longer needed for operations for $5.9 million and recognized a pre-tax gain of $5.5 million in 2005, with the possibility of recognizing up to an additional $3.0 million of pre-tax gains related to these sales, as certain contingencies are resolved. See Note 23, "Regulatory Environment," for details on how the MPSC has agreed to handle these land sales.
DPC
In November 2005, WPSC and DPC closed a transaction in which DPC acquired a 30% ownership interest in Weston 4. Under terms of the agreement, WPSC received $95.1 million in cash from DPC for its share of the costs through the date of the closing. DPC will also remit payments to WPSC for its 30% share of all remaining costs to complete the construction of Weston 4 as well as reimburse WPSC for its share of operating costs after the plant is completed and operational, which is anticipated in 2008.
Kewaunee
In July 2005, Kewaunee returned to service following an unplanned outage that began in February 2005. On July 5, 2005, WPSC completed the sale of its 59% ownership interest in Kewaunee to Dominion Energy Kewaunee, LLC, a subsidiary of Dominion Resources, Inc. At the same time, Wisconsin Power and Light Company sold its 41% ownership interest in Kewaunee to Dominion.
WPSC's share of the cash proceeds from the sale was $112.5 million. Dominion received the assets in WPSC's qualified decommissioning trust and assumed responsibility for the eventual decommissioning of Kewaunee. These trust assets had a pre-tax fair value of $243.6 million at closing. The sale of Kewaunee resulted in a loss of $12.5 million, which includes the proceeds from the sale less the net assets sold, adjusted by several additional items. The most significant of these adjustments is the fair value of an indemnity issued to cover certain costs Dominion may incur related to the recent unplanned outage (see Note 18, "Guarantees," for more information). In addition, the adjustments include certain costs related to the termination of the plant operating agreement and withdrawal from WPS Resources' investment in the Nuclear Management Company (NMC), which served as the licensed operator of Kewaunee.
As part of the sale, WPSC retained ownership of the assets contained in its nonqualified decommissioning trust. Proceeds received from the liquidation of the nonqualified decommissioning trust were $127.1 million and will be refunded to ratepayers. See Note 23, "Regulatory Environment," for details regarding regulatory treatment of the proceeds received from the nonqualified decommissioning trust and the loss on the sale of Kewaunee.
At the closing date, WPSC's share of the carrying value of the assets and liabilities that were included within the sale agreement, or that were otherwise eliminated pursuant to the sale, were as follows:
Upon the closing of the sale, WPSC entered into a long-term power purchase agreement with Dominion to purchase energy and capacity consistent with volumes available when WPSC owned Kewaunee. The power purchase agreement extends through 2013 when the plant's current operating license will expire. Fixed monthly payments under the power purchase agreement will approximate the expected costs of production had WPSC continued to own the plant. Therefore, management believes that the sale of Kewaunee and the related power purchase agreement provides more price certainty for WPSC's customers and reduces WPSC's risk profile. In April 2004, WPSC entered into an exclusivity agreement with Dominion. Under this agreement, if Dominion decides to extend the operating license of Kewaunee, Dominion can negotiate only with WPSC during the exclusivity period for 59% of the plant output under a new power purchase agreement that would extend beyond Kewaunee's current operating license termination date. The exclusivity period started on the closing date of the sale, July 5, 2005, and extends through December 21, 2011, after which Dominion can negotiate with other parties.
Wausau, Wisconsin, to Duluth, Minnesota, Transmission Line
On April 18, 2003, the PSCW approved WPSC's request to transfer its interest in the Wausau, Wisconsin, to Duluth, Minnesota, transmission line to ATC in exchange for an ownership interest in ATC. ATC is a for-profit transmission-only company created by the transfer of transmission assets previously owned by multiple electric utilities serving the upper Midwest. WPSC sold, at book value, $20.1 million of assets related to the Wausau to Duluth transmission line to ATC in June 2003. No gain or loss was recognized on the transaction. In December 2003, WPSC also transferred other transmission assets to ATC, increasing its investment an additional $5.9 million. In 2005, 2004, and 2003, WPS Resources invested $57.0 million, $15.7 million, and $14.0 million, respectively, in ATC, related to its agreement to fund approximately half of the Wausau, Wisconsin, to Duluth, Minnesota, transmission line. At December 31, 2005, WPS Resources' ownership interest in ATC (held through its WPS Investments, LLC subsidiary) was 31.0%. Our investment in ATC is described more fully in Note 10, "Investments in Affiliates, at Equity Method."
Sale of Peshtigo River Lands
On October 5, 2004, WPSC sold at auction 279 acres of Peshtigo River development lands located in Wisconsin for $12.2 million. Under terms of a multi-phase agreement reached with the WDNR in 2001 related to lands near the Peshtigo River, the WDNR bought more than 5,000 acres of land for $13.5 million in 2001. In December 2003, WPSC sold an additional 542 acres of land to the WDNR for $6.5 million. WPSC completed the multi-phase agreement with the sale of 179 acres for $5.0 million to the WDNR on December 9, 2004. Following the close of this final phase of the WDNR agreement, WPSC donated an additional 5,176 acres to the state of Wisconsin.
Advantage Energy Inc.
On July 1, 2004, ESI acquired all of the outstanding stock of Advantage Energy Inc., a New York based energy-marketing company founded in 1997. On the date of acquisition, Advantage served approximately 8,200 residential and commercial customers with a peak load of approximately 275 megawatts. Consideration for the purchase consisted of an initial cash payment for the tangible and intangible net worth of the company and an earn-out with a maximum cap and a declining percentage to the seller.
Guardian Pipeline
On May 30, 2003, WPS Resources purchased a one-third interest in Guardian Pipeline, LLC from CMS Gas Transmission Company for approximately $26 million. Guardian Pipeline owns a natural gas pipeline, which began operating in 2002, that stretches about 140 miles from near Joliet, Illinois, into southern Wisconsin. The pipeline can transport up to 750 million cubic feet of natural gas daily. Our interest in Guardian Pipeline is accounted for as an equity method investment and is described more fully in Note 10, "Investments in Affiliates, at Equity Method."
De Pere Energy Center
On December 16, 2002, WPSC completed the purchase of the 180-megawatt De Pere Energy Center from Calpine Corporation, a California-based independent power producer. Prior to this purchase, the power from the De Pere Energy Center was under long-term contract to WPSC and was accounted for as a capital lease. This power purchase agreement required Calpine to expand the facility in the future. The contract was terminated concurrent with the purchase of the De Pere Energy Center. The $120.4 million purchase included a $72.0 million payment upon closing and a $48.4 million payment in December 2003. As a result of the purchase, the capital lease obligation was reversed and the difference between the capital lease asset and the $120.4 million purchase price was recorded as a regulatory asset. Of the $47.8 million regulatory asset initially recorded, $45.6 million is under the jurisdiction of the PSCW and is being amortized over a 20-year period beginning on January 1, 2004. Amortization of the remaining regulatory asset, which is under the jurisdiction of the FERC and the MPSC, began in 2003 and will also occur over 20 years.
ECO Coal Pelletization #12
At December 31, 2005, ESI holds a 70% ownership interest in ECO Coal Pelletization #12, LLC, which holds an investment in an entity that produces synthetic fuel for tax credits under Section 29 of the Internal Revenue Code.
As a result of prior transactions in which ECO #12 sold synthetic fuel producing machinery to a third party, ESI held $3.5 million in escrow at December 31, 2002. As a result of the expiration of contingencies in the sale agreement and related matters, ESI recognized this as a gain in 2003.
On December 19, 2002, ESI sold approximately 30% interest in ECO #12 to a third party. The buyer purchased the Class A interest in ECO #12, giving the buyer a preferential allocation of tons of synthetic fuel produced and sold annually. The buyer may be allocated additional tons of synthetic fuel if ESI makes them available, but neither party is obligated beyond the required annual allocation of tons. The buyer's share of operating losses generated from the synthetic fuel operation, $4.7 million, $3.4 million, and $5.6 million, in 2005, 2004, and 2003, respectively, are recorded as minority interest in the Consolidated Statements of Income.
ESI received consideration of $3.0 million cash, as well as a fixed and variable note for this sale transaction. Payments under the variable Note are contingent upon the achievement of specified levels of synthetic fuel production by the facility. In conjunction with the sale, ESI agreed to make certain payments to a third-party broker, consisting of an up-front payment of $1.5 million (which was paid at the time of closing), $1.4 million in 2003, $1.9 million in 2004, and $0.5 million in 2005. A deferred gain of $4.6 million and $6.9 million was reflected on ESI's balance sheet at December 31, 2005, and 2004, respectively.
This deferred gain represents the present value of future payments under the fixed Note and the up-front cash payments net of transaction costs. It does not include an amount for the variable note, which is contingent upon the synthetic fuel production. Payments on the variable note are a function of fuel production and recognized as a component of the gain when received. Pre-tax gains of $7.1 million, $7.5 million, and 7.6 million were recognized as a component of miscellaneous income in 2005, 2004, and 2003, respectively, related to the 2002 transaction.
NOTE 7--JOINTLY OWNED UTILITY FACILITIES
Information regarding WPSC's share of significant jointly owned electric-generating facilities in service at December 31, 2005, is set forth below:
WPSC's share of direct expenses for these plants is included in the corresponding operating expenses in the Consolidated Statements of Income. WPSC has supplied its own financing for all jointly-owned projects.
NOTE 8--NUCLEAR DECOMMISSIONING TRUST
In conjunction with the sale of Kewaunee in July 2005 (see Note 6, "Acquisitions and Sales of Assets," for details regarding the sale of Kewaunee), the qualified decommissioning trust assets were transferred to Dominion and WPSC liquidated the assets contained in the nonqualified decommissioning trust. Proceeds received from the liquidation of the nonqualified decommissioning trust will be refunded to ratepayers. See Note 23, "Regulatory Environment," for details regarding regulatory treatment of the proceeds received from the nonqualified decommissioning trust. As of December 31, 2004, the market value of the external nuclear decommissioning trusts totaled $344.5 million, net of tax.
Investments in the nuclear decommissioning trusts were recorded at fair value at December 31, 2004. The investments were presented net of related income tax effects on unrealized gains, and represented the amount of assets that were available to accomplish decommissioning. The nonqualified trust investments designated to pay income taxes when unrealized gains became realized were classified as other assets. At December 31, 2004, the amount classified as other assets was $26.8 million with an offsetting regulatory liability of the same amount reflecting the expected reduction in future rates as unrealized gains in the nonqualified trust would have been realized. Information regarding the cost and fair value of the nuclear decommissioning trusts at December 31, 2004, net of tax, is set forth below:
Decommissioning costs collected in customer rates and charges for realized earnings from the trusts were included in depreciation expense. Realized after-tax trust earnings totaled $41.0 million in 2005 as the trust assets were liquidated due to the sale of Kewaunee. Realized after-tax trust earnings totaled $5.5 million in 2004 and $38.7 million in 2003.
NOTE 9--REGULATORY ASSETS AND LIABILITIES
The following regulatory assets and liabilities are reflected in our Consolidated Balance Sheets as of December 31:
Our utility subsidiaries expect to recover their regulatory assets and return their regulatory liabilities through rates charged to customers based on specific ratemaking decisions or precedent for each item over periods specified by the regulators or over the normal operating period of the assets and liabilities to which they relate. Except for amounts expended for manufactured gas plant remediation, WPSC is recovering carrying costs for all regulatory assets. Historically, WPSC has recognized carrying costs at its weighted average cost of capital; however, pursuant to PSCW order, carrying costs related to some regulatory assets such as the 2005 Kewaunee outage and MISO costs are being recovered based on the composite short-term debt rate. UPPCO may recover carrying costs on environmental regulatory assets. Based on prior and current rate treatment for such costs, we believe it is probable that WPSC and UPPCO will continue to recover from customers the regulatory assets described above.
See Note 3, "Risk Management Activities"; Note 6, "Acquisitions and Sales of Assets"; Note 15, "Asset Retirement Obligations"; Note 17, "Commitments and Contingencies"; Note 19, "Employee Benefit Plans," and Note 23, "Regulatory Environment," for more information on some of the more significant regulatory assets and liabilities listed in the above table.
NOTE 10--INVESTMENTS IN AFFILIATES, AT EQUITY METHOD
Investments in corporate joint ventures and other companies accounted for under the equity method at December 31, 2005, and 2004 follow.
Investments in affiliates under the equity method are a component of other assets on the Consolidated Balance Sheets, and the equity income is recorded in miscellaneous income on the Consolidated Statements of Income. Most of the equity income is taxable to the investor, rather than the investees, due to the flow through nature of several of the investees' business structures. Accordingly, the provision for income taxes includes our taxes on this equity income.
ATC
WPS Investments, LLC, a consolidated subsidiary of WPS Resources, had a 31.0% ownership interest in ATC at December 31, 2005. ATC is a for-profit, transmission-only company. It owns, maintains, monitors, and operates, electric transmission assets in portions of Wisconsin, Michigan, and Illinois. Its assets previously were owned and operated by multiple electric utilities serving the upper Midwest, all of which transferred their transmission assets to ATC in exchange for an ownership interest. A Wisconsin law encouraged utilities in the state to transfer ownership and control of their transmission assets to a state-wide transmission company. The MISO directs ATC's operation of the transmission system.
During 2003, WPSC transferred its interest in the Wausau, Wisconsin, to Duluth, Minnesota, transmission line to ATC. WPS Resources has funded 50% of the construction expenditures for this line through 2005, resulting in an increased investment in ATC. See Note 6, "Acquisitions and Sales of Assets," for more information on these transactions.
WPSC and UPPCO record related-party transactions for services provided to and network transmission services received from ATC. The charges to ATC for services provided by WPSC were $8.7 million, $9.3 million, and $14.4 million in 2005, 2004, and 2003, respectively. UPPCO charged $2.6 million, $6.7 million, and $4.8 million in 2005, 2004, and 2003, respectively for services provided. Network transmission service costs paid to ATC by WPSC were $50.8 million, $42.6 million, and $33.6 million in 2005, 2004, and 2003, respectively. UPPCO recorded network transmission service costs of $3.4 million, $4.0 million, and $4.2 million in 2005, 2004, and 2003, respectively.
WPS Resources recorded dividends received of $17.8 million, $11.7 million, and $7.5 million from ATC in 2005, 2004, and 2003 respectively.
Guardian Pipeline
WPS Investments, LLC, a consolidated subsidiary of WPS Resources, purchased a 33% ownership interest in Guardian Pipeline, LLC on May 30, 2003. Guardian Pipeline owns a natural gas pipeline, which began operating in 2002, that stretches about miles from near Joliet, Illinois, into southern Wisconsin. It can transport up to 750 million cubic feet of natural gas daily.
ESI records related party transactions for purchases from Guardian Pipeline. These purchases amounted to $0.6 million, $0.4 million, and $0.1 million in 2005, 2004, and 2003, respectively.
Wisconsin River Power Company
WPSC owns 50% of the voting stock of Wisconsin River Power Company, which operates two hydroelectric plants on the Wisconsin River and an oil-fired combustion turbine. Two-thirds of the energy output of the hydroelectric plants is sold to WPSC, and the remaining one-third is sold to Wisconsin Power and Light. The electric power from the combustion turbine is sold in equal parts to WPSC and Wisconsin Power and Light.
WPSC records related party transactions for sales to and purchases from Wisconsin River Power. Revenues from services provided to Wisconsin River Power were $1.8 million, $1.1 million, and $1.4 million for 2005, 2004, and 2003, respectively. Purchases from Wisconsin River Power by WPSC were $4.3 million, $3.2 million, and $2.3 million for 2005, 2004, and 2003, respectively.
WPSC recorded dividends received of $7.8 million, $6.0 million, and $1.5 million from Wisconsin River Power in 2005, 2004, and 2003 respectively.
Other Investments
Other investments accounted for under the equity method include various investments, including a 20% investment in the NMC at December 31, 2004. After the sale of Kewaunee, WPS Resources' investment in the NMC was liquidated. The NMC operates nuclear power plants in the upper Midwest. WPSC recorded related party transactions for services provided by the NMC for the management and operation of Kewaunee prior to its sale to Dominion in July 2005. Management service fees paid to the NMC by WPSC were $15.1 million, $26.7 million, and $25.6 million in 2005, 2004, and 2003, respectively.
Other investments accounted for under the equity method are not significant at December 31, 2005.
Financial Data
Combined financial data of ATC, Wisconsin River Power, and Guardian Pipeline follows.
Of WPS Resources' equity in net income disclosed above, $4.9 million, $6.2 million, and $4.7 million relates to WPSC's investment in Wisconsin River Power in 2005, 2004, and 2003 respectively.
NOTE 11--GOODWILL AND OTHER INTANGIBLE ASSETS
Goodwill recorded by WPS Resources was $36.8 million at December 31, 2005, 2004, and 2003. Of this amount, $36.4 million is recorded in WPSC's natural gas segment relating to its merger with Wisconsin Fuel and Light. The remaining $0.4 million of goodwill relates to ESI.
Goodwill and purchased intangible assets are included in other assets on the Consolidated Balance Sheets. Information in the tables below relates to total purchased identifiable intangible assets for the years indicated (excluding assets held for sale).
An impairment charge related to Sunbury, which was recorded in the second quarter of 2005, included the write-down of $6.6 million of unallocated emission allowances. These emission allowances were reflected in the above table at December 31, 2004 (see Note 4, "Sunbury Plant," for more information). Because ESI sold all of Sunbury's allocated emission allowances in the first half of 2005, emission allowances are currently purchased in the market as needed for the operation of this plant, which resulted in the increase in emission allowances at December 31, 2005, compared to December 31, 2004.
A customer related intangible asset in the amount of $7.3 million was recorded in conjunction with a 2004 acquisition. This intangible asset was adjusted to $7.0 million in 2005 as a result of certain purchase price adjustments. The asset is being amortized over a period of eight years.
Intangible asset amortization expense, in the aggregate, for the years ended December 31, 2005, 2004, and 2003, was $24.1 million, $2.4 million, and $1.7 million, respectively. Amortization expense increased in 2005 due to Sunbury's current policy of purchasing emission allowances as required to operate the plant. The purchased emission allowances are amortized to expense as they are used in the production of power.
Amortization expense for the next five fiscal years is estimated as follows:
NOTE 12--LEASES
WPS Resources leases various property, plant, and equipment. Terms of the leases vary, but generally require WPS Resources to pay property taxes, insurance premiums, and maintenance costs associated with the leased property. Rental expense attributable to operating leases was $6.6 million, $5.7 million, and $5.2 million in 2005, 2004, and 2003 respectively. Future minimum rental obligations under non-cancelable operating leases, are payable as follows:
NOTE 13--SHORT-TERM DEBT AND LINES OF CREDIT
WPS Resources has a syndicated $500 million five-year revolving credit facility which expires in June 2010. WPSC has a syndicated $115 million five-year revolving credit facility containing annual trigger date provisions to provide short-term borrowing flexibility and security for commercial paper outstanding.
In November 2005, WPS Resources entered into two unsecured revolving credit agreements of $557.5 million and $300 million with J.P. Morgan Chase Bank and Banc of America Securities LLC. These credit facilities are bridge facilities intended to backup commercial paper borrowings related to the purchase of the Michigan and Minnesota natural gas distribution operations from Aquila and to support purchase price adjustments related to working capital at the time of the closing of the transactions. The capacity under the bridge facilities will be reduced by the amount of proceeds from any long-term financing we complete prior to closing, with the exception of proceeds from the November 2005 equity offering. The credit agreements will be further reduced as permanent or replacement financing is secured. Under the $300 million credit agreement, loans cannot exceed the purchase price adjustments in connection with the Aquila acquisitions and no more than $200 million can be borrowed at the time of the first acquisition. Under the $300 million facility, these loan commitments will be reduced by one-third 90 days after the consummation of the applicable acquisition with the remaining two-thirds due 180 days after the consummation of the applicable acquisition (or earlier if long-term financing or replacement credit agreements are executed). Both of these credit agreements mature on September 5, 2007. These credit agreements have representations and covenants that are similar to those in our existing credit facilities.
The information in the table below relates to short-term debt and lines of credit for the years indicated.
1Amount does not include bridge credit facilities of $857.5 million
The commercial paper has varying maturity dates ranging from January 5, 2006 through January 20, 2006.
NOTE 14--LONG-TERM DEBT
On June 17, 2005, $62.9 million of non-recourse debt at ESI collateralized by nonregulated assets was restructured to a five-year WPS Resources obligation as a result of the sale of Sunbury's allocated
emission allowances. In addition, $2.7 million drawn on a line of credit at ESI was rolled into the five-year WPS Resources obligation. The floating interest rate on the total five-year WPS Resources' obligation of $65.6 million has been fixed at 4.595% through two interest rate swaps.
All of WPSC's debt securities are subject to the terms and conditions of WPSC's First Mortgage Indenture. Under the terms of the indenture, substantially all property owned by WPSC is pledged as collateral for these outstanding debt securities. All these debt securities require semiannual payments of interest. All principal payments are due on the maturity date of each series. All WPSC senior notes become non-collateralized if WPSC retires all of its outstanding first mortgage bonds.
Under the terms of UPPCO's First Mortgage Indenture, substantially all property owned by UPPCO is pledged as collateral for this outstanding debt series. Interest payments are due semiannually on May 1 and November 1 with a sinking fund payment of $900,000 due each November 1. The final sinking fund payment due November 1, 2021, will completely retire the series.
Borrowings by ESI under term loans and collateralized by nonregulated assets totaled $16.4 million at December 31, 2005. The assets of WPS New England Generation, Inc. and WPS Canada Generation, Inc., subsidiaries of ESI, collateralize $4.7 million and $11.7 million, respectively, of the total outstanding amount. Both have semiannual installment payments, an interest rate of 8.75%, and mature in May 2010.
In April 2001, the Schuylkill County Industrial Development Authority issued $27.0 million of refunding tax-exempt bonds. At the time of issuance of the refunding bonds, WPS Westwood Generation, LLC, a subsidiary of ESI, owned the original bonds, the proceeds of which were used in substantial part to purchase facilities. Upon issuance of the refunding bonds, the original bonds were paid off. WPS Westwood Generation was paid $27.0 million from the proceeds of the refunding bonds for the retirement of the original bonds plus accrued interest. WPS Westwood Generation is now obligated to pay the refunding bonds with monthly payments that have a floating interest rate that is reset weekly. At December 31, 2005, the interest rate was 3.5%. The bonds mature in April 2021. WPS Resources agreed to guarantee WPS Westwood Generation's obligation to provide sufficient funds to pay the refunding bonds and the related obligations and indemnities.
Upper Peninsula Building Development Corporation has a senior secured Note of $2.4 million as of December 31, 2005, which requires semiannual payments at an interest rate of 9.25%, and matures in 2011. The Note is secured by a first mortgage lien on the building they own, which is also leased to UPPCO for use as their corporate headquarters.
At December 31, 2005, WPS Resources and its subsidiaries were in compliance with all covenants relating to outstanding debt. A schedule of all principal debt payment amounts, including bond maturities and early retirements, for WPS Resources is as follows:
NOTE 15--ASSET RETIREMENT OBLIGATIONS
Adoption of SFAS No. 143
Legal retirement obligations previously identified at WPSC under the provisions of SFAS No. 143, "Accounting for Asset Retirement Obligations," related primarily to the final decommissioning of Kewaunee. As discussed in Note 6, "Acquisitions and Sales of Assets," the sale of Kewaunee to Dominion was completed on July 5, 2005. As a result of the sale, Dominion assumed the asset retirement obligation related to Kewaunee. Upon adoption of SFAS No. 143, other legal obligations were also identified related to WPSC, but these obligations were not significant.
In connection with the implementation of SFAS No. 143, ESI identified a legal retirement obligation related to the closure of an ash basin located at Sunbury. The asset retirement obligation associated with Sunbury is recorded as a liability on the Consolidated Balance Sheet. The adoption of SFAS No. 143 at ESI resulted in a $0.3 million negative after-tax cumulative effect of change in accounting principle in the first quarter of 2003 related to recording a liability for the closure of this ash basin.
Adoption of Interpretation No. 47
WPS Resources adopted the provisions of Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations," as of December 31, 2005. Upon adoption of this interpretation, WPS Resources recorded liabilities for conditional asset retirement obligations, which previously we believed to be outside the scope of SFAS No. 143.
The utility segments identified conditional asset retirement obligations related to asbestos abatement at certain generation facilities, office buildings, and service centers; disposal of PCB-contaminated transformers; and closure of fly-ash landfills at certain generation facilities. Upon implementation of Interpretation No. 47 on December 31, 2005, the utility segments recorded a net asset retirement cost of $1.5 million and an asset retirement obligation of $8.2 million. This resulted in a $6.7 million cumulative effect of change in accounting principle before taxes. This amount was deferred as a regulatory asset as we obtained approval to defer the cumulative effect of adopting the Interpretation and believe it is probable that the actual cost to dispose of the assets will be recoverable in future rates. At December 31, 2005, the utilities had already recorded a $3.1 million regulatory liability related to the conditional asset retirement obligations discussed above, pertaining to amounts previously recovered in customer rates for the disposal of these assets. This $3.1 million regulatory liability was netted against the regulatory assets recorded upon adoption of the Interpretation.
Conditional asset retirement obligations identified at ESI relate to asbestos abatement at certain generation facilities. Upon implementation of Interpretation No. 47 on December 31, 2005, ESI recorded a net asset retirement cost of $1.3 million and an asset retirement obligation of $3.9 million, resulting in an after-tax cumulative effect of change in accounting principles of $1.6 million ($2.6 million before taxes).
If WPS Resources and WPSC had applied the provisions of Interpretation No.47 as of January 1, 2003, the pro forma impacts on prior periods' Consolidated Balance Sheets would not differ materially from the conditional asset retirement obligations recorded as of December 31, 2005, and the pro forma impacts on income available for common shareholders, as well as basic and diluted earnings per common share, would not be material.
Changes to Asset Retirement Obligation Liabilities
The following table describes all changes to the asset retirement obligations of WPS Resources through December 31, 2005, including the adoption of Interpretation No. 47.
NOTE 16--INCOME TAXES
The principal components of our deferred tax assets and liabilities recognized in the balance sheets as of December 31 are as follows:
Deferred tax credit carryforwards include $63.7 million of alternative minimum tax credits related to tax credits available under Section 29 of the Internal Revenue Code. These alternative minimum tax credit carryforwards can be carried forward indefinitely. Carryforward periods for state capital and operating loss carryforwards vary, but in the majority of states in which we do business, the period is 15 years or more. The balance of the carryforwards of state net operating losses is $235.0 million for all states. Valuation
allowances have been established for certain state operating and capital loss carryforwards due to the uncertainty of the ability to realize the benefit of these losses in the future.
The following table presents a reconciliation of federal income taxes (which are calculated by multiplying the statutory federal income tax rate by book income before federal income tax) to the provision for income taxes reported in the Consolidated Statements of Income.
Foreign income before taxes was $10.2 million in 2005, $8.3 million in 2004, and $4.3 million in 2003.
As the related temporary differences reverse, WPSC and UPPCO are prospectively refunding taxes to customers for which deferred taxes were recorded in prior years at rates different than current rates. The regulatory liability for these refunds and other regulatory tax effects totaled $8.8 million as of December 31, 2005, and $11.2 million as of December 31, 2004.
NOTE 17--COMMITMENTS AND CONTINGENCIES
Commodity and Purchase Order Commitments
WPS Resources routinely enters into long-term purchase and sale commitments that have various quantity requirements and durations. The commitments described below are as of December 31, 2005.
ESI has unconditional purchase obligations related to energy supply contracts that total $4.8 billion. Substantially all of these obligations end by 2008, with obligations totaling $154.6 million extending from 2009 through 2016. The majority of the energy supply contracts are to meet ESI's obligations to deliver energy to its customers.
WPSC has obligations related to coal, purchased power, and natural gas. Obligations related to coal supply and transportation extend through 2016 and total $413.9 million. Through 2016, WPSC has obligations totaling $1.4 billion for either capacity or energy related to purchased power, including the obligation under the power purchase agreement with Dominion. Also, there are natural gas supply and transportation contracts with total estimated demand payments of $128.5 million through 2017. WPSC expects to recover these costs in future customer rates. Additionally, WPSC has contracts to sell electricity and natural gas to customers.
UPPCO has made commitments for the purchase of commodities, mainly capacity or energy related to purchased power, which total $42.3 million and extend through 2010.
WPS Resources also has commitments in the form of purchase orders issued to various vendors. At December 31, 2005, these purchase orders totaled $476.1 million and $462.0 million for WPS Resources and WPSC, respectively. The majority of these commitments relate to large construction projects, including construction of the 500-megawatt Weston 4 coal-fired generation facility near Wausau, Wisconsin.
Environmental
EPA Section 114 Request
In December 2000, WPSC received from the EPA a request for information under Section 114 of the Clean Air Act. The EPA sought information and documents relating to work performed on the coal-fired boilers located at WPSC's Pulliam and Weston electric generation stations. WPSC filed a response with the EPA in early 2001.
On May 22, 2002, WPSC received a follow-up request from the EPA seeking additional information regarding specific boiler-related work performed on Pulliam Units 3, 5, and 7, as well as information on WPSC's life extension program for Pulliam Units 3 through 8 and Weston Units 1 and 2. WPSC made an initial response to the EPA's follow-up information request on June 12, 2002, and filed a final response on June 27, 2002.
In 2000 and 2002, Wisconsin Power and Light Company received a similar series of EPA information requests relating to work performed on certain coal-fired boilers and related equipment at the Columbia generation station (a facility located in Portage, Wisconsin, jointly owned by Wisconsin Power and Light Company, Madison Gas and Electric Company, and WPSC). Wisconsin Power and Light Company is the operator of the plant and is responsible for responding to governmental inquiries relating to the operation of the facility. Wisconsin Power and Light Company filed its most recent response for the Columbia facility on July 12, 2002.
Depending upon the results of the EPA's review of the information provided by WPSC and Wisconsin Power and Light Company, the EPA may issue "notices of violation" or "findings of violation" asserting that a violation of the Clean Air Act occurred and/or seek additional information from WPSC and/or third parties who have information relating to the boilers or close out the investigation. To date, the EPA has not responded to the filings made by WPSC and Wisconsin Power and Light. In addition, under the federal Clean Air Act, citizen groups may pursue a claim. WPSC has no notice of such a claim based on the information submitted to the EPA.
In response to the EPA's Clean Air Act enforcement initiative, several utilities have elected to settle with the EPA, while others are in litigation. In general, those utilities that have settled have entered into consent decrees which require the companies to pay fines and penalties, undertake supplemental environmental projects, and either upgrade or replace pollution controls at existing generating units or shut down existing units and replace these units with new electric generating facilities. Several of the settlements involve multiple facilities. The fines and penalties (including the capital costs of supplemental environmental projects) associated with these settlements range between $7 million and $30 million. The regulatory interpretations upon which the lawsuits or settlements are based may change based on future court decisions that may be rendered in the pending litigations.
In May 2003, WPSC initiated discussions with the EPA Region V aimed at negotiating a settlement. The discussions were preliminary and did not progress. No further action has been taken by the EPA.
If the federal government decided to bring a claim against WPSC and if it were determined by a court that historic projects at WPSC's Pulliam and Weston plants required either a state or federal Clean Air Act permit, WPSC may, under the applicable statutes, be required to:
·
shut down any unit found to be operating in non-compliance,
·
install additional pollution control equipment,
·
pay a fine, and/or
·
pay a fine and conduct a supplemental environmental project in order to resolve any such claim.
Pulliam Air Permit Violation Lawsuit
The Sierra Club and Clean Wisconsin filed a complaint in the Eastern District of Wisconsin on October 19, 2005. The lawsuit was filed pursuant to the citizen suit provisions of the Clean Air Act. The complaint references opacity exceedances reported by the Pulliam facility located in Green Bay, Wisconsin, from 1999 through the first quarter of 2005. The notice also alleges monitoring violations from through 2004, exceedances of the Clean Air Act operating permit in 2002, exceedances of the permit issued for eight diesel generators in 2001, and exceedances of the permit for the combustion turbine, P32. The lawsuit seeks penalties, injunctive relief, and the costs of litigation. The Sierra Club and Clean Wisconsin have stated a willingness to discuss the alleged violations and the parties have engaged in settlement negotiations.
Weston 4 Air Permit
On November 15, 2004, the Sierra Club filed a petition with the WDNR under Section 285.61, Wis. Stats., seeking a contested case hearing on the air permit issued for the Weston 4 generation station. On December 2, 2004, the WDNR granted the petition and forwarded the matter to the Division of Hearings and Appeals. In its petition, Sierra Club raised legal and factual issues with the permit and with the process used by the WDNR to develop the air emission limits and conditions. In addition, both WPSC and the Sierra Club filed motions for summary judgment on certain of the issues. A decision regarding summary judgment was issued. In the ruling, the Administrative Law Judge denied the motion of Sierra Club and granted summary judgment to WPSC with respect to certain claims of Sierra Club consistent with the rulings rendered in Wisconsin Energy's Elm Road proceeding. The contested case hearing in the matter was held during the last week of September 2005. The hearing addressed the remaining issues, which are generally related to the emission limits specified in the permit and the pollution controls to be used to achieve these limits. In February 2006, the Administrative Law Judge affirmed the Weston 4 air permit with modifications to the emission limits for sulfur dioxide and nitrogen oxide from the coal-fired boiler and particulate from the cooling tower. The modifications set limits that are more stringent than those set by the WDNR. WPS Resources is currently evaluating the impact this decision may have on future operating costs.
Weston Site Operating Permit
On April 18 and April 26, 2005, WPS Resources notified the WDNR that the existing Weston facility was not in compliance with certain provisions of the "Title V" air operating permit that was issued to the facility in October 2004. These provisions include: (1) the particulate emission limits applicable to the coal handling equipment; (2) the carbon monoxide (CO) limit for Weston combustion turbines; and (3) the limitation on the sulfur content of the fuel oil stored at the Weston facility. On July 25, 2005, WPSC received a notice of violation (NOV) from the WDNR asserting that the existing Weston facility is not in compliance with certain provisions of the permit. In response to the NOV, a compliance plan was submitted to the WDNR. Subsequently, stack testing was performed, which indicated continuing exceedances of the particulate limits from the coal handling equipment. On January 19, 2006, WPSC received from the WDNR a Notice of Noncompliance (NON) seeking further information about the alleged non-compliance event. WPSC provided a response to the WDNR and is in the process of seeking to have the permit revised. On February 20, 2005, the WDNR issued an NOV which incorporated most of the alleged noncompliance events described above (the alleged exceedances of the CO limit was not included) and added issues relating to opacity monitoring and the operation of a particulate source for
three days without a functioning baghouse. Under the WDNR's stepped enforcement process, an NOV is the first step in the WDNR's enforcement procedure. If the WDNR decides to continue the enforcement process, the next step is a "referral" of the matter to the Wisconsin Attorney General's Office. In addition, citizen groups may seek to initiate enforcement or may seek to initiate enforcement prior to the filing of any lawsuit by the Wisconsin Attorney General's Office or may seek to intervene in the Title V operating permit revision process. WPSC is seeking to amend the applicable permit limits and is taking corrective action. At this time, we believe that our exposure to fines or penalties related to this noncompliance would not have a material impact on our financial results.
Mercury and Interstate Air Quality Rules
On October 1, 2004, the mercury emission control rule became effective in Wisconsin. The rule requires WPSC to control annual system mercury emissions in phases. The first phase will occur in 2008 and 2009. In this phase, the annual mercury emissions are capped at the average annual system mercury emissions for the period 2002 through 2004. The next phase will run from 2010 through 2014 and requires a 40% reduction from average annual 2002 through 2004 mercury input amounts. After 2015, a 75% reduction is required with a goal of an 80% reduction by 2018. Because federal regulations were promulgated in March 2005, we believe the State of Wisconsin will revise the Wisconsin rule to be consistent with the federal rule. However, the State of Wisconsin has filed suit against the federal government along with other states in opposition to the rule. WPSC estimates capital costs of approximately $14 million to achieve the proposed 75% reductions. The capital costs are expected to be recovered in a future rate case.
In December 2003, the EPA proposed mercury "maximum achievable control technology" standards and an alternative mercury "cap and trade" program substantially modeled on the Clear Skies legislation initiative. The EPA also proposed the Clean Air Interstate Rule (formerly known as the Interstate Air Quality Rule), which would reduce sulfur dioxide and nitrogen oxide emissions from utility boilers located in 29 states, including Wisconsin, Michigan, Pennsylvania, and New York. In March 2005, the EPA finalized both the mercury rule and the Clean Air Interstate Rule.
The final mercury rule establishes New Source Performance Standards for new units based upon the type of coal burned. Weston 4 will install and operate mercury control technology with the aim of achieving a mercury emission rate less than that in the final EPA mercury rule.
The final mercury rule also establishes a mercury cap and trade program, which requires a 21% reduction in national mercury emissions in 2010 and a 70% reduction in national mercury emissions beginning in 2018. Based on the final rule and current projections, WPSC anticipates meeting the mercury rule cap and trade requirements at a cost similar to the cost to comply with the Wisconsin rule.
ESI's current analysis indicates that additional emission control equipment on its existing units may be required. Excluding Sunbury, ESI estimates the capital cost for the remaining units to be approximately $1 million to achieve a 70% reduction. Including Sunbury, the total ESI mercury control costs could approximate $33 million, depending upon how this facility is operated.
The final Clean Air Interstate Rule requires reduction of sulfur dioxide and nitrogen oxide emissions in two phases. The first phase requires about a 50% reduction beginning in 2009 for nitrogen oxide and beginning in 2010 for sulfur dioxide. The second phase begins in 2015 for both pollutants and requires about a 65% reduction in emissions. The rule allows the affected states (including Wisconsin, Michigan, Pennsylvania, and New York) to either require utilities located in the state to participate in the EPA's interstate cap and trade program or meet the state's emission budget for sulfur dioxide and nitrogen oxide through measures to be determined by the state. The states have not adopted a preference as to which option they would select, but the states are investigating the cap and trade program, as well as alternatives or additional requirements. Consequently, the effect of the rule on WPSC's and ESI's facilities is uncertain, since it depends upon how the states choose to implement the final Clean Air Interstate Rule.
Currently, WPSC is evaluating a number of options that include using the cap and trade program and/or installing controls. For planning purposes, it is assumed that additional sulfur dioxide and nitrogen oxide controls will be needed on existing units or the existing units will need to be converted to natural gas by 2015. The installation of any controls and/or any conversion to natural gas will need to be scheduled as part of WPSC's long-term maintenance plan for its existing units. As such, controls or conversions may need to take place before 2015. On a preliminary basis and assuming controls or conversion are required, WPSC estimates capital costs of $257 million in order to meet an assumed 2015 compliance date. This estimate is based on costs of current control technology and current information regarding the final EPA rule. The costs may change based on the requirements of the final state rules.
ESI is evaluating the compliance options for the Clean Air Interstate Rule. Additional nitrogen oxide controls on some of ESI's facilities may be necessary, and would cost approximately $40 million. The cost estimate is largely dependent upon how Sunbury will be operated going forward. See Note 4, "Sunbury Plant," for additional information on Sunbury. Additional sulfur dioxide reductions are unlikely. Also, ESI will evaluate a number of options including using the cap and trade program, fuel switching, and/or installing controls.
Clean Air Regulations
Most of the generation facilities owned by ESI are located in an ozone transport region. As a result, these generation facilities are subject to additional restrictions on emissions of nitrogen oxide and sulfur dioxide. ESI began 2005 with 17,000 sulfur dioxide emission allowances for its generation facilities that are required to participate in the sulfur dioxide emission program. However, a majority of these allowances were sold in the second quarter of 2005, requiring a higher level of purchases for the remainder of the year. In future years, ESI expects to purchase sulfur dioxide and nitrogen oxide emission allowances at market rates, as needed, to meet its requirements for the Sunbury generation facility.
Spent Nuclear Fuel Disposal
The federal government is responsible for the disposal or permanent storage of spent nuclear fuel. The DOE is currently preparing an application to license a permanent spent nuclear fuel storage facility in the Yucca Mountain area of Nevada.
Spent nuclear fuel is currently being stored at the Kewaunee plant. At current production levels, the plant has sufficient storage for all fuel assemblies until 2009 with full core offload. Additional capacity will be needed by 2010 to maintain full core offload capability.
The United States government through the DOE was under contract with WPSC for the pick up and long-term storage of Kewaunee's spent nuclear fuel. Because the DOE has failed to begin scheduled pickup of the spent nuclear fuel, WPSC incurred costs for the storage of the spent nuclear fuel. WPSC is a participant in a suit filed against the federal government for breach of contract and failure to pick up and store the spent nuclear fuel. The case was filed on January 22, 2004, in the United States Court of Federal Claims. The case has been temporarily stayed until June 30, 2006.
In July 2005, WPSC sold Kewaunee to a subsidiary of Dominion Resources, Inc. Pursuant to the terms of the sale, Dominion has the right to pursue the spent nuclear fuel claim and WPSC will retain the contractual right to an equitable share of any future settlement or verdict. The total amount of damages sought are unknown at this time.
Other Environmental Issues
Groundwater testing at a former ash disposal site of UPPCO indicated elevated levels of boron and lithium. Supplemental remedial investigations were performed, and a revised remedial action plan was developed. The Michigan Department of Environmental Quality approved the plan in January 2003. UPPCO received an order from the MPSC permitting deferral and future recovery of these costs. A liability of $1.3 million and an associated regulatory asset of $1.3 million were recorded at December 31,
2005, for estimated future expenditures associated with remediation of the site. UPPCO has an informal agreement, with the owner of another landfill, under which UPPCO has agreed to pay 17% of the investigation and remedial costs. It is estimated that the cost of addressing the site over the next year will be $1.8 million. UPPCO has recorded $0.3 million of this amount as its share of the liability as of December 31, 2005.
There is increasing concern over the issue of climate change and the effect of emissions of greenhouse gases. WPS Resources is evaluating both the technical and cost implications, which may result from a future greenhouse gas regulatory program. This evaluation indicates that it is probable that any regulatory program that caps emissions or imposes a carbon tax will increase costs for WPS Resources and its customers. At this time, there is no commercially available technology for removing carbon dioxide from a pulverized coal-fired plant, but significant research is in progress. Efforts are underway within the utility industry to develop cleaner ways to burn coal. The use of alternate fuels is also being explored by the industry, but there are many cost and availability issues. Based on the complexity and uncertainty of the climate issues, a risk exists that future carbon regulation will increase the cost of electricity produced at coal-fired generation units. However, we believe the capital expenditures we are making at our generation units are appropriate under any reasonable mandatory greenhouse gas program. WPS Resources will continue to monitor and manage potential risks and opportunities associated with future greenhouse gas regulatory actions.
Manufactured Gas Plant Remediation
WPSC continues to investigate the environmental cleanup of ten manufactured gas plant sites. Cleanup of the land portion of the Oshkosh, Stevens Point, Green Bay, Manitowoc, and two Sheboygan sites in Wisconsin is completed. Groundwater treatment and monitoring at these sites will continue into the future. Cleanup of the land portion of four sites will be addressed in the future. River sediment remains to be addressed at sites with sediment contamination, and priorities will be determined in consultation with the EPA. The additional work at the sites remains to be scheduled.
WPSC is currently in the process of transferring sites with sediment contamination formally under WDNR jurisdiction to the EPA Superfund Alternatives Program. WPSC received special notice letters that initiated the transfer process. Under the EPA's program, the remedy decision will be based on risk-based criteria typically used at Superfund sites. WPSC estimated the future undiscounted investigation and cleanup costs as of December 31, 2005, to be $66 million. WPSC may adjust these estimates in the future contingent upon remedial technology, regulatory requirements, remedy determinations, and the assessment of natural resource damages. WPSC has received $12.7 million to date in insurance recoveries. WPSC expects to recover actual cleanup costs, net of insurance recoveries, in future customer rates. Under current PSCW policies, WPSC will not recover carrying costs associated with the cleanup expenditures.
Flood Damage
On May 14, 2003, a fuse plug at the Silver Lake reservoir owned by UPPCO was breached. This breach resulted in subsequent flooding downstream on the Dead River, which is located in Michigan's Upper Peninsula near Marquette, Michigan.
A dam owned by Marquette Board of Light and Power, which is located downstream from the Silver Lake reservoir near the mouth of the Dead River, also failed during this event. In addition, high water conditions and siltation resulted in damage at the Presque Isle Power Plant owned by Wisconsin Electric Power Company. Presque Isle, which is located downstream from the Marquette Board of Light and Power dam, was ultimately forced into a temporary shutdown.
The FERC's Independent Board of Review issued its report in December 2003 and concluded that the root cause of the incident was the failure of the design of the fuse plug to take into account the highly erodible nature of the fuse plug's foundation materials and spillway channel, resulting in the complete loss of the fuse plug, foundation, and spillway channel, which caused the release of Silver Lake far beyond the
intended design of the fuse plug. The fuse plug for the Silver Lake reservoir was designed by an outside engineering firm.
UPPCO has worked with federal and state agencies in their investigations. UPPCO is still in the process of investigating the incident. WPS Resources maintains a comprehensive insurance program that includes UPPCO and which provides both property insurance for its facilities and liability insurance for liability to third parties. WPS Resources is insured in amounts that it believes are sufficient to cover its responsibilities in connection with this event. Deductibles and self-insured retentions on these policies are not material to WPS Resources.
As of May 13, 2005, several lawsuits were filed by the claimants and putative defendants relating to this incident. The suits that have been filed against UPPCO, WPS Resources, and WPSC include the following claimants: WE Energies, Cleveland Cliffs, Inc., Board of Light and Power of the City of Marquette, the City of Marquette, the County of Marquette, Dead River Campers, Inc., Marquette County Road Commission, SBC, ATC, and various land and homeowners along the Silver Lake reservoir and Dead River system. UPPCO filed a suit against the engineering company that designed the fuse plug (MWH Americas, Inc.) and the contractor who built it (Moyle Construction, Inc.). UPPCO has reached a confidential settlement with WE Energies resolving WE Energies' claims. The settlement payment will be reimbursed by WPS Resource's insurer and, therefore, did not have a material impact on the Consolidated Financial Statements. WPS Resources is defending the remaining lawsuits filed against it and is seeking resolution of all claims and litigation where possible.
In November 2003, UPPCO received approval from the MPSC and the FERC for deferral of costs that are not reimbursable through insurance or recoverable through the power supply cost recovery mechanism. Recovery of costs deferred will be addressed in future rate proceedings.
In November 2005, UPPCO announced it had not made a final decision whether to restore Silver Lake as a reservoir for power generation or to forego refilling the reservoir and that more time is needed to study the ramifications of design changes recommended by consultants and FERC. UPPCO will undertake additional studies of the new design recommendations to see if there are alternatives that would make restoring the Silver Lake Dam and refilling the reservoir economically beneficial for its customers. UPPCO expects to make its final decision on Silver Lake in the first half of 2006.
Stray Voltage Claims
From time to time, WPSC has been sued by dairy farmers who allege that they have suffered loss of milk production and other damages supposedly due to "stray voltage" from the operation of WPSC's electrical system. One case, Allen v. WPSC, has been remanded from the court of appeals to the trial court for a determination of whether a post-verdict injunction is warranted. A second case, Pollack v. WPSC, was tried and ended in a defense verdict on May 5, 2005, and that case is concluded. A third case, Seidl v. WPSC, was dismissed on June 21, 2005, when the trial judge granted WPSC's motion for a directed verdict. The Seidl plaintiffs have filed a notice of appeal of that dismissal. WPSC believes it has meritorious arguments supporting the dismissal and WPSC plans to vigorously contest the appeal.
On February 15, 2005, the Court of Appeals affirmed the jury verdict in Allen v. WPSC, which awarded the plaintiff $0.8 million for economic damages and $1 million for nuisance. All appeals have been exhausted and the judgment has been paid to the plaintiff, but the plaintiff is still seeking an injunction. The injunction issues are scheduled to be tried in September 2006. The expert witnesses retained by WPSC do not believe that there is any scientific basis for concluding that electricity from the utility system is currently creating any problem on the plaintiff's land. Accordingly, WPSC does not believe there is any basis for issuing an injunction, and intends to contest the plaintiff's claim.
Three cases, Theuerkauf v. WPSC, Wojciehowski Brothers Farms v. WPSC, and Schmoker v. WPSC were filed in the fourth quarter of 2005 and are still in the pleadings stage and it is too early to predict their outcomes. The Theuerkauf case was brought by Michigan farmers and is being heard in federal court in Green Bay. We believe Michigan law will govern this action. The Wojciehowski case was brought in state
court in Wisconsin in Marinette County. The Schmoker case was brought in Wisconsin state court in Winnebago County. WPSC believes it has meritorious defenses to the plaintiffs' claims in these cases, and intends to vigorously defend them.
The PSCW has established certain requirements regarding stray voltage for all utilities subject to its jurisdiction. The PSCW has defined what constitutes "stray voltage," established a level of concern at which some utility corrective action is required, and set forth test protocols to be employed in evaluating whether a stray voltage problem exists. However, in 2003, the Supreme Court of Wisconsin ruled in the case Hoffmann v. WEPCO that a utility could be liable in tort to a farmer for damage from stray voltage even though the utility had complied with the PSCW's established level of concern. Thus, despite the fact that WPSC believes it abides by the applicable PSCW requirements, it is not immune from the tort suits such as these under Wisconsin law.
WPSC has insurance coverage for the pending claims, but the policies have customary self-insured retentions per occurrence. Based upon the information known at this time and the availability of insurance, WPSC believes that the total cost to it of resolving these five actions will not be material.
Wausau, Wisconsin, to Duluth, Minnesota, Transmission Line
Construction of the 220-mile, 345-kilovolt Wausau, Wisconsin, to Duluth, Minnesota, transmission line began in the first quarter of 2004 with the Minnesota portion completed in early 2005. Construction in Wisconsin began on August 8, 2005.
ATC has assumed primary responsibility for the overall management of the project and will own and operate the completed line. WPSC received approval from the PSCW and the FERC to transfer ownership of the project to ATC. WPSC will continue to manage obtaining the private property rights, design, and construction of the Wisconsin portion of the project.
The Certificate of Public Convenience and Necessity and other permits needed for construction have been received and are final. In addition, on August 5, 2005, the new law allowing condemnation of county land for transmission lines approved by the PSCW became effective. In light of this legislation, Douglas County negotiated an easement agreement with ATC that allows the project to be constructed across county land on the route originally selected by the PSCW. On September 15, 2005, the Douglas County Board approved that agreement. Accordingly, the lawsuit against Douglas County to force it to provide easements for the project is being dismissed as moot, and ATC has asked the PSCW to close the docket, which was opened to examine alternative routes in Douglas County.
WPS Resources committed to fund 50% of total project costs incurred up to $198 million and will receive additional equity in ATC in exchange for the project funding. Under its agreement, WPS Resources invested $57.0 million in ATC in 2005, bringing WPS Resources' investment in ATC related to the project to $86.7 million since inception. WPS Resources may terminate funding if the project extends beyond January 1, 2010. On December 19, 2003, WPSC and ATC received approval from the PSCW to continue the project at a revised cost estimate of $420.3 million to reflect additional costs for the project resulting from time delays, added regulatory requirements, changes and additions to the scope of the project, and ATC overhead costs. The final portion of the line is expected to be placed in service in 2008. WPS Resources has the right, but not the obligation, to provide additional funding in excess of $198 million for up to 50% of the revised cost estimate. Allete has exercised its option to fund a portion of the Wausau to Duluth transmission line. WPSC and Allete agreed that Allete will fund up to $60 million of the 2006 capital calls for the line in 2006. Considering this, for the period January 2006 through November 2008, WPS Resources expects to fund up to approximately $61 million for its portion of the Wausau to Duluth transmission line.
Beaver Falls
ESI's Beaver Falls generation facility in New York has been out of service since late June 2005. The unplanned outage was caused by the failure of the first stage turbine blades. Inclusive of estimated
insurance recoveries, ESI estimates at this time that it will cost between $3 and $5 million to repair the turbine and replace the damaged blades. Depending on the amount of insurance recovery, ESI could incur significantly higher net out-of-pocket costs than originally estimated to repair the damage. In addition, ESI is attempting to renegotiate an existing steam off-take agreement with a counterparty, which will significantly impact its ability to recover costs. If significant repair costs are not recoverable through insurance or ESI is not able to renegotiate the terms of the steam off-take agreement, then a possibility exists that ESI would not repair the plant, in which case undiscounted cash flows related to future operations may be insufficient to recover the carrying value of the plant, resulting in impairment. The carrying value of the Beaver Falls generation facility at December 31, 2005, was $18.1 million.
Synthetic Fuel Production Facility
We have significantly reduced our consolidated federal income tax liability over past years through tax credits available to us under Section 29 of the Internal Revenue Code for the production and sale of solid synthetic fuel from coal. These tax credits are scheduled to expire at the end of 2007 and are provided as an incentive for taxpayers to produce fuel from alternate sources and reduce domestic dependence on imported oil. This incentive is not deemed necessary if the price of oil increases sufficiently to provide a natural market for the fuel. Therefore, the tax credits in a given year are subject to phase out if the annual average reference price of oil within that year exceeds a minimum threshold price set by the IRS and are eliminated entirely if the average annual reference price increases beyond a maximum threshold price set by the IRS. The reference price of a barrel of oil is an estimate of the annual average wellhead price per barrel for domestic crude oil, which has in recent history been approximately $6 below the NYMEX price of a barrel of oil. The threshold price at which the credit begins to phase out was set in 1980 and is adjusted annually for inflation; the IRS releases the final numbers for a given year in the first part of the following year.
Numerous events have increased domestic crude oil prices, including concerns about terrorism, storm-related supply disruptions, and worldwide demand. Therefore, in order to manage exposure to the risk of an increase in oil prices that could reduce the amount of Section 29 federal tax credits that could be recognized, ESI entered into a series of derivative contracts, beginning in the first quarter of 2005, covering a specified number of barrels of oil. While no apparent phase-out of Section 29 federal tax credits occurred in 2005, ESI had mitigated essentially all of its 2005 phase-out risk at no net cost. Through optimization strategies, ESI realized a $0.3 million gain on oil options entered into to mitigate the 2005 phase-out risk, net of premium amortization. If no phase-out were to occur in 2006 and 2007, ESI would expect to recognize approximately $24 million of Section 29 federal tax credits in each of the next two years. Based upon forward oil prices, we are anticipating significant phase-outs of 2006 and 2007 Section 29 federal tax credits. However, we cannot predict with certainty the future price of a barrel of oil and, therefore, have no way of knowing what portion of our tax credits will be phased out, or if any phase-out will result. Based upon the average annual NYMEX price of a barrel of oil, ESI estimates that Section 29 federal tax credits will begin phasing out if the annual average NYMEX price of a barrel of oil reaches approximately $60, with a total phase-out if the annual average NYMEX price of a barrel of oil reaches approximately $73.
At December 31, 2005, ESI had derivative contracts that mitigate substantially all of the Section 29 tax credit exposure in 2006 and 40% of the exposure in 2007. The derivative contracts involve purchased and written call options that provide for net cash settlement at expiration based on the average NYMEX trading price of oil in relation to the strike price of each option. Premiums paid for options to mitigate exposure to Section 29 federal tax credit phase-out in and 2007 totaled $15.3 million ($12.0 million for 2006 options and $3.3 million for 2007 options), all of which are recorded as risk management assets on the balance sheet. Essentially, ESI has paid $12.0 million for options ($7.2 million after-tax) to protect the value of approximately $24 million of tax credits in 2006 and $3.3 million for options ($2.0 million after-tax) to protect the value of approximately $10 million of tax credits in 2007. ESI has not hedged $14 million of 2007 tax credits. The derivative contracts have not been designated as hedging instruments and, as a result, changes in the fair value of the options are recorded currently in earnings. This could result in mark-to-market gains being recognized in earnings in different periods, compared to the offsetting tax credit phase-outs. For example, as of December 31, 2005, unrealized pre-tax
mark-to-market gains of $4.0 million and $4.4 million were recorded for the 2006 and 2007 options, respectively, while no tax credit phase-out was recognized because 2006 and 2007 tax credits are not recognized until fuel is produced and sold in those periods. In 2006, ESI will only record Section 29 federal tax credits expected to be recognized, based upon the expected annual average price of a barrel of oil.
In addition to exposure to federal tax credits, ESI has also historically received royalties tied to the amount of synthetic fuel produced as well as variable payments from a counterparty related to its 30% sell-down of ECO Coal Pelletization #12 in 2002. Royalties and variable payments contributed $7.1 million, $7.6 million, and $5.9 million to income before taxes in 2005, 2004, and 2003, respectively. Royalties and variable payments received in 2006 and 2007 could decrease if a phase-out occurs and synthetic fuel production is reduced.
NOTE 18--GUARANTEES
As part of normal business, WPS Resources and its subsidiaries enter into various guarantees providing financial or performance assurance to third parties on behalf of certain subsidiaries. These guarantees are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries' intended commercial purposes.
Most of the guarantees issued by WPS Resources include inter-company guarantees between parents and their subsidiaries, which are eliminated in consolidation, and guarantees of the subsidiaries' own performance. As such, these guarantees are excluded from the recognition and measurement requirements of FASB Interpretation No. 45, "Guarantors' Accounting and Disclosure Requirements for Guarantees, including Indirect Guarantees of Indebtedness of Others."
At December 31, 2005, 2004, and 2003, outstanding guarantees totaled $1,310.6 million, $977.9 million, and $981.8 million, respectively, as follows:
At December 31, 2005, WPS Resources had outstanding $27.2 million in corporate guarantees supporting indebtedness. Of that total, $27.0 million supports outstanding debt at one of ESI's subsidiaries. The underlying debt related to these guarantees is reflected on WPS Resources' Consolidated Balance Sheet.
WPS Resources' Board of Directors has authorized management to issue corporate guarantees in the aggregate amount of up to $1.35 billion to support the business operations of ESI. WPS Resources primarily issues the guarantees to counterparties in the wholesale electric and natural gas marketplace to provide them assurance that ESI will perform on its obligations and permit ESI to operate within these markets. At December 31, 2005, WPS Resources provided parental guarantees in the amount of $1,150.0 million, reflected in the above table, for ESI's indemnification obligations for business operations, including $8.1 million of guarantees that received specific authorization from WPS Resources' Board of Directors and are not included in the $1.35 billion general authorized amount. Of the parental guarantees provided by WPS Resources, the outstanding balance at December 31, 2005, which WPS Resources would be obligated to support, is approximately $299 million.
Another $4.7 million of corporate guarantees support energy and transmission supply at UPPCO and are not reflected on WPS Resources' Consolidated Balance Sheet. In February 2005, WPS Resources' Board of Directors authorized management to issue corporate guarantees in the aggregate amount of up to $15.0 million to support the business operations of UPPCO. Corporate guarantees issued in the future under the Board authorized limit may or may not be reflected on WPS Resources' Consolidated Balance Sheet, depending on the nature of the guarantee.
At WPS Resources' request, financial institutions have issued $114.3 million in standby letters of credit for the benefit of third parties that have extended credit to certain subsidiaries. If a subsidiary does not pay amounts when due under a covered contract, the counterparty may present its claim for payment to the financial institution, which will request payment from WPS Resources. Any amounts owed by our subsidiaries are reflected in WPS Resources' Consolidated Balance Sheet.
At December 31, 2005, WPS Resources furnished $0.8 million of surety bonds for various reasons including worker compensation coverage and obtaining various licenses, permits, and rights-of-way. Liabilities incurred as a result of activities covered by surety bonds are included in the WPS Resources' Consolidated Balance Sheet.
A guarantee of $4.7 million listed in the above table under other guarantees was issued by WPSC to indemnify a third party for exposures related to the construction of utility assets. This amount is not reflected on the WPS Resources' Consolidated Balance Sheet, as this agreement was entered into prior to the effective date of FASB Interpretation No. 45.
In conjunction with the sale of Kewaunee, WPSC and WP&L agreed to indemnify Dominion for 70% of any and all reasonable costs asserted or initiated against, suffered, or otherwise existing, incurred or accrued, resulting from or arising from the resolution of any design bases documentation issues that are
incurred prior to completion of Kewaunee's scheduled maintenance period for 2009 up to a maximum combined exposure of $15 million for WPSC and WP&L. WPSC believes that it will expend its share of costs related to this indemnification and, as a result, recorded the fair value of the liability, or $8.9 million, as a component of the loss on the sale of Kewaunee.
WPSC also agreed to indemnify Dominion for losses resulting from potential breaches of WPSC's representations and warranties under the sale agreement. The indemnification is limited to approximately $18 million and expires in July 2006. WPSC believes the likelihood of having to make any material cash payments under the sale agreement as a result of breaches of representations and warranties is remote.
NOTE 19--EMPLOYEE BENEFIT PLANS
WPS Resources has a non-contributory-qualified retirement plan covering substantially all employees. WPS Resources also sponsors several nonqualified retirement plans, which are not funded.
WPS Resources also currently offers medical, dental, and life insurance benefits to employees and their dependents. We expense these items for active employees as incurred. We fund benefits for retirees through irrevocable trusts as allowed for income tax purposes.
WPSC serves as plan sponsor and administrator for the qualified retirement plan and the postretirement plans. Accordingly, WPSC's Consolidated Balance Sheets reflect the assets and liabilities associated with these plans. With the exception of UPPCO's Supplemental Employee Retirement Plan, the assets and liabilities related to the non-qualified pension plans are also recorded on WPSC's Consolidated Balance Sheets. The net periodic benefit cost associated with the plans is allocated among WPS Resources' subsidiaries. Actuarial calculations are performed (based upon specific employees and their related years of service) in order to determine the appropriate benefit cost allocation.
The costs of pension and postretirement benefits are expensed over the period in which the employee renders service. The transition obligation for postretirement benefits of current and future retirees is being recognized over a 20-year period beginning in 1993. WPS Resources uses a December 31 measurement date for the majority of its plans.
The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) provides a prescription drug benefit under Medicare Part D as well as a federal subsidy to sponsors of certain retiree health care benefit plans. In May 2004, the FASB staff issued FSP 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003."
WPS Resources and its actuarial advisors determined that benefits provided by the plan as of the date of enactment were at least actuarially equivalent to Medicare Part D, and, accordingly, WPS Resources will be entitled to the federal subsidy. WPS Resources performed a measurement of the effects of the Act on its accumulated postretirement benefit obligation as of July 1, 2004 (the date FSP 106-2 was adopted). As of July 1, 2004, WPS Resources' and WPSC's accumulated postretirement benefit obligation decreased $40.3 million and $33.5 million, respectively, as a result of the Act. The change in the accumulated postretirement benefit obligation due to the Act is considered an actuarial gain that will be recognized in future periods and, therefore, had no cumulative effect on WPS Resources or WPSC's retained earnings as of July 1, 2004. The effect of the subsidy served to reduce the net postretirement benefit cost by $6.5 million and $2.6 million for WPS Resources for the years ended December 31, 2005, and 2004, respectively.
The following tables provide a reconciliation of the changes in the plan's benefit obligations and fair value of assets during 2005, 2004, and 2003, as well as a statement of the funded status as of December 31 for each year.
Amounts recognized in the Consolidated Balance Sheets related to the benefit plans consist of:
We record a minimum pension liability to reflect the funded status of our pension plans. Substantially all of the minimum pension liability relates to unrecognized pension costs of the utilities. Regulatory assets are recorded for costs that are probable of recovery when recognized.
Included in the above table is an accrued benefit cost of $1.6 million at December 31, 2005, and $1.7 million at December 31, 2004, related to UPPCO's Supplemental Employee Retirement Plan.
The accumulated benefit obligation for all defined benefit pension plans was $646.5 million and $634.8 million at December 31, 2005, and 2004, respectively. Information for pension plans with an accumulated benefit obligation in excess of plan assets is presented in the following table.
The following table presents the components of the consolidated net periodic benefit cost (credit) for the plans for 2005, 2004, and 2003:
Net periodic benefit cost recorded by WPSC related to pension benefits was $25.2 million in 2005, $16.3 million in 2004, and $6.7 million in 2003. Net periodic benefit cost recorded by WPSC related to other benefits was $13.6 million in 2005, $12.4 million in 2004, and $12.0 million in 2003.
Assumptions
The weighted average assumptions used at December 31 in accounting for the plans are as follows:
The assumptions used for WPS Resources' medical and dental cost trend rates are shown in the following table:
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% change in assumed health care cost trend rates would have the following effects:
Plan Assets
Weighted-average asset allocations of the plans at December 31, 2005, and 2004, are as follows:
The Board of Directors has established the Employee Benefits Administrator Committee to manage the operations and administration of all benefit plans and related trusts. The Committee has investment policies for the plan assets that establish target asset allocations for the above listed asset classes as follows: pension plan - equity securities 60%, debt securities 35%, and real estate 5%; postretirement plan - equity securities 65%, and debt securities 35%. Because of market volatility, the Committee periodically reviews the asset allocation and the portfolio is rebalanced when considered appropriate.
Cash Flows
WPS Resources' funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes. We expect to contribute $25.3 million to our pension plans and $19.8 million to our other postretirement benefit plans in 2006.
The following table shows the payments, reflecting expected future service, which WPS Resources expects to make for pension and other postretirement benefits. In addition, the table shows the expected
federal subsidies under Medicare Part D, which will partially offset other postretirement benefits, as discussed earlier.
Defined Contribution Benefit Plans
WPS Resources maintains a 401(k) Savings Plan for substantially all full-time employees. Employees generally may contribute from 1% to 30% of their base compensation to individual accounts within the 401(k) Savings Plan. Participation in this plan automatically qualifies eligible non-union employees for participation in the ESOP. The company match, in the form of shares of WPS Resources' common stock, is contributed to an employee's ESOP account. The plan requires a match equivalent to 100% of the first 4% and 50% of the next 2% contributed by non-union employees. Certain union employees receive a contribution to their ESOP account regardless of their participation in the 401(k) Savings Plan. The ESOP held 2.2 million shares of WPS Resources' common stock (market value of $120.8 million) at December 31, 2005. Total costs incurred under these plans were $8.2 million in 2005, $7.7 million in 2004, and $5.7 million in 2003. WPSC's share of the total costs was $6.8 million in 2005, $6.5 million in 2004, and $4.6 million in 2003.
WPS Resources maintains a deferred compensation plan that enables certain key employees and non-employee directors to defer a portion of their compensation or fees on a pre-tax basis. Non-employee directors can defer up to 100% of their director fees. There are essentially two separate investment programs available to plan participants. The first program (Program 1) offers WPS Resources' common stock as a hypothetical investment option for participants; deemed dividends paid on the common stock are automatically reinvested; and all distributions must be made in WPS Resources' common stock. The second program (Program 2) offers a variety of hypothetical investment options indexed to mutual funds, WPS Resources' return on equity, and WPS Resources' common stock. Participants may not redirect investments between the two programs. All employee deferrals are remitted to WPSC and, therefore, the liabilities and costs associated with the deferred compensation plans are included on WPSC's Consolidated Balance Sheets and Consolidated Statements of Income, respectively.
Program 1 is accounted for as a plan that does not permit diversification. As a result, the deferred compensation arrangement is classified as an equity instrument and changes in the fair value of the deferred compensation obligation are not recognized. The deferred compensation obligation associated with Program 1 was $16.1 million at December 31, 2005, and $13.0 million at December 31, 2004.
Program 2 is accounted for as a plan that permits diversification. As a result, the deferred compensation obligation associated with this program is classified as a liability in the Consolidated Balance Sheets and adjusted, with a charge or credit to expense, to reflect changes in the fair value of the deferred compensation obligation. The obligation, classified within other long-term liabilities, was $23.6 million at December 31, 2005, and $21.0 million at December 31, 2004. The costs incurred under Program 2 were $2.6 million in 2005, $2.1 million in 2004, and $2.4 million in 2003.
The deferred compensation programs are partially funded through shares of WPS Resources' common stock that is held in a rabbi trust. The common stock held in the rabbi trust is classified in equity in a manner similar to accounting for treasury stock. The total cost of WPS Resources' common stock held in the rabbi trust was $10.9 million at December 31, 2005, and $8.4 million at December 31, 2004.
NOTE 20--PREFERRED STOCK OF SUBSIDIARY
WPSC has 1,000,000 authorized shares of preferred stock with no mandatory redemption and a $100 par value. Outstanding shares are as follows at December 31:
All shares of preferred stock of all series are of equal rank except as to dividend rates and redemption terms. Payment of dividends from any earned surplus or other available surplus is not restricted by the terms of any indenture or other undertaking by WPSC. Each series of outstanding preferred stock is redeemable in whole or in part at WPSC's option at any time on 30 days' notice at the respective redemption prices. WPSC may not redeem less than all, nor purchase any, of its preferred stock during the existence of any dividend default.
In the event of WPSC's dissolution or liquidation, the holders of preferred stock are entitled to receive (a) the par value of their preferred stock out of the corporate assets other than profits before any of such assets are paid or distributed to the holders of common stock and (b) the amount of dividends accumulated and unpaid on their preferred stock out of the surplus or net profits before any of such surplus or net profits are paid to the holders of common stock. Thereafter, the remainder of the corporate assets, surplus, and net profits shall be paid to the holders of common stock.
The preferred stock has no pre-emptive, subscription, or conversion rights, and has no sinking fund provisions.
NOTE 21--COMMON EQUITY
Treasury shares at December 31, 2005, relate to our Non-Employee Directors Stock Option Plan. The number of stock options granted under this plan may not exceed 100,000 shares. All options under this plan have a ten-year life, but may not be exercised until one year after the date of grant.
Effective January 2001, we began issuing new stock under our Stock Investment Plan and under certain of our stock-based employee benefit plans. These stock issuances increased equity $29.0 million, $28.3 million, and $31.0 million in 2005, 2004, and 2003, respectively.
In November 2005, 1,900,000 shares of WPS Resources' common stock were issued at $53.70 per share and resulted in a net increase in equity of $98.3 million, inclusive of underwriting commissions and other expenses directly related to the issuance.
In November 2003, 4,025,000 shares of WPS Resources' common stock were issued at $43.00 per share and resulted in a net increase in equity of $166.8 million, inclusive of underwriting commissions and other expenses directly related to the issuance.
Shareholder Rights Plan
In December 1996, we adopted a Shareholder Rights Plan. The plan is designed to enhance the ability of the Board of Directors to protect shareholders of WPS Resources if efforts are made to gain control of our company in a manner that the Board of Directors determines is not in the best interests of our shareholders. The plan gives our existing shareholders, under certain circumstances, the right to purchase stock at a discounted price. The rights expire on December 11, 2006.
Dividends
WPS Resources is a holding company and our ability to pay dividends is largely dependent upon the ability of our subsidiaries to pay dividends to us. The PSCW has by order restricted our principal subsidiary, WPSC, to paying normal dividends on its common stock of no more than 109% of the previous year's common stock dividend. The PSCW also requires WPSC to maintain a capital structure (i.e., the percentages by which each of common stock, preferred stock and debt constitute the total capital invested in a utility), which has a common equity range of 50% to 55%. Each of these limitations may be modified by a future order of the PSCW. Our right to receive dividends on the common stock of WPSC is also subject to the prior rights of WPSC's preferred shareholders and to provisions in WPSC's restated articles of incorporation which limit the amount of common stock dividends which WPSC may pay if its common stock and common stock surplus accounts constitute less than 25% of its total capitalization. These limitations are not expected to limit any dividend payments in the foreseeable future.
UPPCO's indentures relating to its first mortgage bonds contain certain limitations on the payment of cash dividends on its common stock, which is held solely by WPS Resources. Under the most restrictive of these provisions, $27.7 million of retained earnings were available at December 31, 2005, for the payment of common stock cash dividends by UPPCO.
At December 31, 2005, WPS Resources had $551.4 million of retained earnings available for dividends.
Forward Equity Transaction
In November 2005, WPS Resources entered into a forward equity sale agreement with an affiliate of J.P. Morgan Securities, Inc., as forward purchaser, relating to 2.7 million shares of WPS Resources' common stock. In connection with the forward agreement, J.P. Morgan Securities borrowed an equal number of shares of WPS Resources' common stock from stock lenders and, at WPS Resources' request, sold the borrowed shares to the public. WPS Resources will not receive any proceeds from J.P. Morgan Securities' sale of the common shares until the forward agreement is settled, which may occur any time prior to November 21, 2006. Except in specified circumstances or events that would require physical share settlement, WPS Resources may elect to settle the forward agreement by means of physical shares or through cash settlement. Under a physical share settlement, the maximum number of shares deliverable by WPS Resources is 2.7 million shares. Depending upon the share price at the date of settlement, we could either owe or be owed funds if we elect the cash settlement option. If the cash settlement option was elected, the forward purchaser would purchase shares in the market and return those shares to the lenders. The amount we would receive or be required to pay would be dependent upon the price at which the forward purchaser acquired the shares in the open market in relation to the contracted forward price. Generally, if the forward purchase price is lower than the price at which the forward purchaser is able to acquire the shares, then we would owe cash; and if the price at which the forward purchaser is able to acquire shares is less than the forward share price, we would receive cash. At December 31, 2005, the forward price was $51.58 per share, representing the initial public offering price of $53.70 per share, net of underwriting discounts and commissions. The forward sale price is increased daily based on a floating interest factor equal to the federal funds rate, less a 75 basis point fixed spread. The federal funds rate was 4.25% at December 31, 2005. The forward sales price will also be subject to decrease by $0.565 on February 28, 2006, $0.565 on May 31, 2006, and $0.575 on August 31, 2006. If the forward agreement had been settled by delivery of shares at December 31, 2005, WPS Resources would have received $139.3 million, based on the December 31, 2005, forward share price of $51.58 for the 2.7 million shares.
The forward equity agreement had no initial fair value. At settlement, the forward equity sale agreement will be recorded within equity. The use of a forward agreement allows WPS Resources to avoid market uncertainty by pricing a stock offering under then existing market conditions, while mitigating share dilution by postponing the issuance of stock until funds are needed. WPS Resources currently anticipates settling the forward equity transaction through physical share settlement and expects to use proceeds received under the forward equity agreement to partially finance the proposed acquisition of the Minnesota and Michigan natural gas distribution operations of Aquila and for general corporate purposes.
Earnings Per Share
Earnings per share is computed by dividing income available for common shareholders by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share is computed by dividing income available for common shareholders by the weighted average number of shares of common stock outstanding during the period adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive items include in-the-money stock options, restricted shares, performance share grants, and shares related to the forward equity transaction discussed above. The calculation of diluted earnings per share for the years shown excludes some stock option plan shares that had an anti-dilutive effect. The shares having an anti-dilutive effect are not significant for any of the years shown. The following table reconciles the computation of basic and diluted earnings per share:
NOTE 22--STOCK-BASED COMPENSATION
WPS Resources has four stock-based compensation plans: the 2005 Omnibus Incentive Compensation Plan (2005 Omnibus Plan), the 2001 Omnibus Incentive Compensation Plan (2001 Omnibus Plan), the 1999 Stock Option Plan (Employee Plan), and the 1999 Non-Employee Directors Stock Option Plan (Director Plan). No additional stock options will be issued under the 2001 Omnibus Plan or the Employee Plan, although the plans will continue to exist for purposes of the existing outstanding stock-based compensation. The number of shares issuable under each of the aforementioned stock-based compensation plans, each outstanding award, and stock option exercise prices are subject to adjustment in the event of any stock split, stock dividend, or other similar transaction.
Stock Options
Under the provisions of the 2005 Omnibus Plan, the number of shares for which stock options may be granted may not exceed 2 million, and no single employee that is the chief executive officer of WPS Resources or any of the other four highest compensated officers of WPS Resources and its subsidiaries can be granted options for more than 150,000 shares during any calendar year. Stock options are granted by the Compensation Committee of the Board of Directors and may be granted at any time. No stock options will have a term longer than ten years. The exercise price of each stock option is equal to the fair market value of the stock on the date the stock option was granted. One-fourth of the stock options granted under the 2005 and 2001 Omnibus Plans and the Employee Plan will become vested and exercisable each year on the anniversary date of the grant.
The number of stock options granted under the Director Plan may not exceed 100,000, and the shares to be delivered will consist solely of treasury shares. Stock options are granted at the discretion of the Board of Directors. No options may be granted under this plan after December 31, 2008. All options have a ten-year life, but they may not be exercised until one year after the date of grant. Options granted under this plan are immediately vested. The exercise price of each option is equal to the fair market value of the stock on the date the stock options were granted.
A summary of the activity of the stock option plans for 2005 is presented below:
A summary of the activity of the stock option plans for 2004 is presented below:
A summary of the activity of the stock option plans for 2003 is presented below:
The following table summarizes the status of the stock options outstanding and exercisable at December 31, 2005, under the 2005 Omnibus Plan.
The following table summarizes the status of the stock options outstanding and exercisable at December 31, 2005, under the 2001 Omnibus Plan.
The following table summarizes the status of the stock options outstanding and exercisable at December 31, 2005, under the Employee Plan.
The following table summarizes the status of the stock options outstanding and exercisable at December 31, 2005, under the Director Plan.
Other Stock-Based Compensation Awards
A portion of the long-term incentive is awarded in the form of performance stock rights. These stock rights vest over a three-year performance period and are paid out in shares of WPS Resources' common stock. The number of shares paid out is calculated by multiplying a performance percentage by a target number of shares. The performance multiplier is based on the performance of WPS Resources' common stock relative to the stock performance of a specific peer group of companies. The payout may range from 0% to 200% of target. Based upon these criteria, 177,426 shares are included in the denominator of the diluted earnings per share computation at December 31, 2005. In accordance with Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," WPS Resources accrues the plan expense over the three-year period in which the services are performed. Pre-tax compensation cost recorded was $3.4 million in 2005, $2.3 million in 2004, and $3.3 million in 2003.
The following table summarizes the performance stock rights granted in 2005, 2004, and 2003.
Restricted stock shares granted on April 18, 2002, totaled 12,186 shares and had a one-year vesting period. Beginning April 18, 2003, 15% of the shares became unrestricted, with an additional 15% release of restriction at each six-month interval thereafter until fully unrestricted. Restricted shares have a value equal to the fair market value of the shares on the grant date. Compensation cost was recorded for these shares over their one-year vesting period.
NOTE 23--REGULATORY ENVIRONMENT
Wisconsin
On December 22, 2005, the PSCW issued a final written order authorizing a retail electric rate increase of $79.9 million (10.1%) and a retail natural gas rate increase of $7.2 million (1.1%), effective January 1, 2006. The 2006 rates reflect an 11.0% return on common equity. The PSCW also approved a common equity ratio of 59.7%. The retail electric rate increase was required because of higher fuel and purchased power costs (including costs associated with the Fox Energy Center power purchase agreement), costs related to the construction of Weston 4, increased transmission costs, and costs related to the 2005 Kewaunee outage and 50% of the loss on the Kewaunee sale. The rates also reflect the refund of a portion of the proceeds received from the liquidation of the nonqualified decommissioning trust fund. The retail natural gas rate increase was driven by infrastructure improvements necessary to ensure the reliability of the natural gas distribution system.
On June 7, 2005, WPSC filed with the PSCW and the FERC a request for establishment of a cooperative joint proceeding for approval of the Kewaunee wind-up plan. The wind-up plan proposed that the refunds due to both retail and wholesale customers related to proceeds received from the liquidation of the nonqualified decommissioning trust fund be offset by the net loss on the sale of the plant and also by certain costs related to the 2004 and 2005 Kewaunee outages. The wind-up plan proposed to begin the amortization of the net regulatory liability as a credit to customer rates as of the effective date of the PSCW's order (expected to be January 1, 2006). The FERC subsequently denied the request for joint proceeding with the PSCW. The wind-up plan was addressed by the PSCW in WPSC's 2006 rate case (discussed above). The PSCW ruled in the 2006 rate case that the deferred assets and liabilities related to the Kewaunee matters should be treated separately and not netted as WPSC initially proposed in its wind-up plan. In the 2006 rate case, the PSCW determined that Wisconsin retail customers were entitled to be refunded approximately 85% of the proceeds received from the liquidation of the nonqualified decommissioning trust fund based on a historical allocation methodology, or approximately $108 million of
the total $127.1 million of proceeds received, over a two-year period beginning on January 1, 2006 (including the refund of carrying costs on the unamortized balance at the authorized pre-tax weighted average cost of capital). In 2005, the MPSC ruled that WPSC's Michigan customers were entitled to be refunded approximately 2% of the proceeds received from the liquidation of the nonqualified decommissioning fund and refunding to Michigan customers began in 2005. The $126.9 million regulatory liability recorded at December 31, 2005, related to the required refunding of proceeds received from the liquidation of the nonqualified decommissioning trust fund to both retail and wholesale customers. The proposal to refund the nonqualified decommissioning trust fund to wholesale customers was also approved by the FERC with no specification of the details for distribution. On August 8, 2005, the FERC accepted the proposed refund plan for filing and implemented the plan effective January 1, 2006, subject to refund upon final resolution. A preliminary settlement discussion between WPSC and parties contesting WPSC's refund plan was held in the fourth quarter of 2005, but a final resolution has not been determined on this matter. The PSCW's treatment of costs related to the 2004 and 2005 Kewaunee outages, as well as the loss on the sale of Kewaunee are discussed below.
The PSCW disallowed recovery of 50% of the loss on the sale of Kewaunee. The entire loss had previously been approved for deferral, resulting in WPSC writing off $6.1 million of the regulatory asset previously recorded. WPSC petitioned the PSCW for rehearing on this matter; however, the request for rehearing was denied and this decision is now final.
On February 20, 2005, Kewaunee was temporarily removed from service after a potential design weakness was identified in its auxiliary feedwater system. On March 17, 2005, the PSCW authorized WPSC to defer replacement fuel costs related to the outage. On April 8, 2005, the PSCW approved deferral of the operating and maintenance costs, including carrying costs at the most recently authorized pre-tax weighted average cost of capital. In the order granted for WPSC's rate case, which was finalized on December 22, 2005 (discussed above), the PSCW determined that it was reasonable for WPSC to recover all deferred costs related to the 2005 Kewaunee forced outage over a five-year period, beginning on January 1, 2006, including carrying costs on the unamortized balance at the composite short-term debt rate. Because the PSCW had initially approved deferral of carrying costs based upon the weighted average cost of capital, WPSC was required to write-off $2.2 million of carrying costs in the fourth quarter of 2005. WPSC also filed with the FERC for approval to defer these costs in the wholesale jurisdiction. The FERC is in the process of investigating the justness and reasonableness of the recovery of the costs and will subsequently rule on the filing. WPSC believes recovery of the FERC portion of these costs is probable. For WPSC's Michigan retail customers, fuel costs are recovered through a pass through fuel adjustment clause and no deferral request is needed. Through December 31, 2005, WPSC had deferred $56.4 million of replacement power costs and operating and maintenance expenses related to this outage. On July 5, 2005, WPSC sold its 59% share of Kewaunee to Dominion. See Note 6, "Acquisitions and Sales of Assets," for further information on the sale of Kewaunee.
In WPSC's 2006 rate case, the PSCW determined that it was reasonable for WPSC to continue to defer the MISO Day 2 charges associated with net congestion and financial transmission rights costs and revenues, and the cost differences between marginal losses and average losses. At December 31, 2005, WPSC had deferred $21.2 million of costs related to these matters.
In May 2005, WPSC received notification from its coal transportation suppliers that extensive maintenance was required on the railroad tracks that lead into and out of the Powder River Basin. The extensive maintenance ended on November 23, 2005. During the maintenance efforts, WPSC received approximately 87% of the expected coal deliveries. WPSC took steps to conserve coal usage and secured alternative coal supplies at its affected generation facilities during that time. On September 23, 2005, the PSCW approved WPSC's request for deferred treatment of the incremental fuel costs resulting from the coal supply issues. As of December 31, 2005, $6.4 million was deferred related to this matter. These costs are expected to be addressed in WPSC's next retail electric rate case.
On November 5, 2004, WPSC filed an application with the PSCW to defer all incremental costs, including carrying costs, resulting from unexpected problems encountered in the 2004 refueling outage at Kewaunee. During the refueling outage, an unexpected problem was encountered with equipment used
for lifting the reactor vessel internal components to perform a required 10-year inspection. These equipment problems caused the outage to be extended by approximately three weeks. On November 11, 2004, the PSCW authorized WPSC to defer the replacement fuel costs related to the extended outage. On November 23, 2004, the PSCW authorized WPSC to defer purchased power costs and operating and maintenance expenses related to the extended outage, effective from when the problems were discovered, including carrying costs at WPSC's authorized weighted average cost of capital. Kewaunee returned to service on December 4, 2004. In the order granted for WPSC's 2006 rate case, which was finalized on December 22, 2005 (discussed above), the PSCW disallowed recovery of these costs, resulting in the write-off of the $7.6 million regulatory asset WPSC had previously recorded. WPSC petitioned the PSCW for rehearing on this matter; however, the request for rehearing was denied and this decision is now final.
On December 21, 2004, the PSCW issued a final written order authorizing a retail electric rate increase of $60.7 million (8.6%) and a retail natural gas rate increase of $5.6 million (1.1%), effective January 1, 2005. The 2005 rates reflected an 11.5% return on equity. The PSCW also approved a common equity ratio of 57.35% in the utility's regulatory capital structure. The retail electric rate increase was related to increased costs pertaining to fuel and purchased power, construction of Weston 4, benefit costs, and the MISO costs. The natural gas rate increase was primarily related to increases in benefit costs and the cost of distribution system improvements.
Michigan
On January 3, 2006, UPPCO filed a request to increase its retail electric rates by $6.6 million (8.1%), with an 11.5% return on equity, and a 55% common equity ratio. It is anticipated that the MPSC will act on this request in the third quarter of 2006. UPPCO asked for the new rates to go into effect in the second quarter, subject to refund, while the MPSC reviews the entire request. The retail electric rate increase is required in order to improve service quality and reliability, upgrade technology, and manage rising employee and retiree benefit costs. UPPCO's last retail electric rate increase was in December 2002.
On December 8, 2004, UPPCO submitted a request to the MPSC to approve UPPCO's proposed treatment of the pre-tax gains from certain sales of undeveloped and partially developed land located in the Upper Peninsula of Michigan as appropriate for ratemaking purposes. On February 4, 2005, UPPCO submitted an application to the MPSC for a 7.6% increase in retail electric rates ($5.7 million in revenues). UPPCO also requested interim rate recovery of 6.0% ($4.5 million in revenues) to allow UPPCO to recover costs during the time the MPSC was reviewing the full case. On April 28, 2005, the MPSC issued an order authorizing UPPCO to retain 100% of the pre-tax gains on certain lands owned up to $18.5 million and 73% of any pre-tax gains over that amount, so UPPCO withdrew the rate increase request.
Federal
Through a series of orders issued by the FERC, Regional Through and Out Rates for transmission service between the MISO and the PJM Interconnection were eliminated effective December 1, 2004. To compensate transmission owners for the revenue they will no longer receive due to this elimination, the FERC ordered a transitional pricing mechanism called SECA to be put into place. Load serving entities will pay these SECA charges during a 16-month transition period from December 1, 2004, through March 31, 2006. Total exposure for the 16-month transitional period, taken from proposed compliance filings by the transmission owners, is approximately $19 million for ESI, of which approximately $17 million relates to its Michigan operations and $2 million relates to its Ohio operations. Through December 31, 2005, ESI has received billings totaling $15.3 million, of which $11.1 million have been expensed.
The application and legality of the SECA is being challenged by many load-serving entities, including ESI. ESI has been and will continue pursuing all avenues to appeal and/or reduce the SECA obligations. It is probable that ESI's total exposure will be reduced by at least $4.2 million because of inconsistencies between the FERC's SECA order and the transmission owners' compliance filings (representing the difference between the amount ESI has paid for SECA charges and the amount that has been expensed
as of December 31, 2005, as discussed above). ESI anticipates settling a significant portion of its SECA matters through vendor negotiations in the first half of 2006 and reached a $1 million settlement agreement with one of its vendors in January 2006. Resolution of issues to be raised in an upcoming SECA hearing offer the possibility of further reductions in ESI's exposure, but the extent is unknown at present. Through existing contracts, ESI has the ability to pass a portion of the SECA charges on to customers and has been doing so. Since SECA is a transition charge ending on March 31, 2006, it does not directly impact ESI's long-term competitiveness.
The SECA is also an issue for WPSC and UPPCO, who have intervened and protested a number of proposals in this docket because those proposals could result in unjust, unreasonable, and discriminatory charges for customers. It is anticipated that most of the SECA charges incurred by WPSC and UPPCO and any refunds will be passed on to customers through rates.
Other
On September 21, 2005, WPS Resources announced the acquisition of the Michigan and Minnesota natural gas distribution operations of Aquila. See Note 6, "Acquisitions and Sales of Assets," for further information on the acquisition of these assets. In relation to the acquisition, WPS Michigan Utilities, Inc. (which subsequently changed its name to Michigan Gas Utilities Corporation) and Aquila jointly filed with the MPSC on October 10, 2005, for approval of the termination of Aquila's duty to provide natural gas service in Michigan and for WPS Michigan Utilities to provide natural gas service in the Michigan service territory of Aquila pursuant to the rates, terms, and conditions in Aquila's current tariff book. Also in relation to the acquisition, on October 17, 2005, WPS Minnesota Utilities, Inc. (which subsequently changed its name to Minnesota Energy Resources Corporation) and Aquila jointly filed with the Minnesota Public Utilities Commission to approve the sale of the Minnesota assets of Aquila's two divisions, Aquila Networks-PNG and Aquila Networks-NMU, to WPS Minnesota Utilities pursuant to the Asset Purchase Agreement dated September 21, 2005. On November 10, 2005, approval was obtained from the MPSC for the Michigan transaction. The Minnesota Public Utilities Commission has not yet ruled on this matter.
NOTE 24--VARIABLE INTEREST ENTITIES
The FASB has issued Interpretation No. 46R (as revised), "Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51," in order to improve financial reporting by companies involved with variable interest entities. Interpretation No. 46R requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional financial support from other parties. The primary beneficiary is the party that absorbs the majority of the expected losses and/or receives the majority of the expected residual returns of the variable interest entity's activities.
The application of Interpretation No. 46R was required for financial statements of public entities that have interests in special-purpose entities for periods ending after December 15, 2003. WPS Resources identified WPSR Capital Trust I as a special purpose entity that is within the scope of Interpretation No. 46R. Refer to Note 25, "Company-Obligated Mandatorily Redeemable Trust Preferred Securities of Preferred Stock Trust," for further discussion of the impacts of implementing this portion of Interpretation No. 46R on the financial statement of WPS Resources.
WPS Resources adopted the provisions of Interpretation No. 46R for variable interest entities not defined as special purpose entities effective March 31, 2004. The required adoption had no impact on our Consolidated Financial Statements, as we did not identify significant variable interests in any unconsolidated variable interest entities where we were determined to be the primary beneficiary. We have identified our equity ownership in a synthetic fuel producing facility as a variable interest in a variable interest entity. Through an affiliate of ESI, WPS Resources owns a partial interest in a synthetic fuel facility located in Kentucky and receives tax credits pursuant to Section 29 of the Internal Revenue Code based on sales to unaffiliated third-party purchasers of synthetic fuel produced from coal. At December 31, 2005, WPS Resources had a 23% ownership interest in the synthetic fuel facility. No other variable interests were identified. WPS Resources' maximum exposure to loss as a result of our
involvement with this variable interest entity is limited to our investment in this entity, which was not significant at December 31, 2005. We were not identified as the primary beneficiary of this entity and, therefore, were not required to consolidate the synthetic fuel facility into our financial statements at December 31, 2005. The adoption of Interpretation No. 46R also included an analysis of our power purchase and sale agreements. We do not believe that any of our power purchase or sale agreements constitute significant variable interests that would lead us to consolidate entities not currently consolidated or deconsolidate any entities currently consolidated.
NOTE 25--COMPANY-OBLIGATED MANDATORILY REDEEMABLE TRUST PREFERRED SECURITIES OF PREFERRED STOCK TRUST
On July 30, 1998, WPSR Capital Trust I, a Delaware business trust, issued $50.0 million of trust preferred securities to the public. WPS Resources owned all of the outstanding trust common securities of the Trust, and the only asset of the Trust was $51.5 million of subordinated debentures issued by WPS Resources. The debentures were due on June 30, 2038, and bore interest at 7% per year. The terms and interest payments on the debentures corresponded to the terms and distributions on the trust preferred securities.
As discussed in Note 24, "Variable Interest Entities," it was determined that WPSR Capital Trust I qualified as a special purpose entity and, therefore, the provisions of Interpretation No. 46R were applied to the Trust at December 31, 2003. Prior to this date, we consolidated the preferred securities of the Trust into our financial statements as we held all of the voting securities. Per the provisions of Interpretation No. 46R, however, it was determined that the preferred security holders held the majority of the residual economic risks associated with WPSR Capital Trust I and, therefore, the Trust was deconsolidated effective December 31, 2003. As a result of the deconsolidation, WPS Resources recorded a $1.5 million investment in trust within other current assets and a $51.5 million Note payable to preferred stock trust, respectively, within the Consolidated Balance Sheet at December 31, 2003.
On January 8, 2004, WPS Resources redeemed all of the subordinated debentures that were initially issued to the Trust for $51.5 million and paid accrued interest of $0.1 million. This action required the Trust to redeem an equal amount of trust securities at face value plus any accrued interest and unpaid distributions. As a result of these transactions, the Trust was dissolved effective January 8, 2004.
NOTE 26--SEGMENTS OF BUSINESS
SFAS No. 131, "Disclosures About Segments of an Enterprise and Related Information," requires that companies disclose segment information based on how management makes decisions about allocating resources to segments and measuring their performance.
Prior to the fourth quarter of 2005, WPS Resources reported two nonregulated segments, ESI and PDI. In the fourth quarter of 2005, WPS Resources' Chief Executive Officer and its Board of Directors decided to view ESI and PDI as one business, and corresponding changes were made to the segment information reported to them. The change in reportable segments is the culmination of changes over the past two years that caused these businesses to become integrated. These changes included combining the management teams, restructuring the ownership structure of ESI and PDI, and having ESI optimize the value of PDI's merchant generation fleet and reduce market price risk through the use of various financial and physical instruments (such as futures, options, and swaps) in order to provide more predictable revenues and margins. Effective in the fourth quarter of 2005, WPS Resources began reporting to the Chief Executive Officer and Board of Directors one nonregulated segment, ESI. Segment information related to prior periods has been reclassified to reflect this change. Currently, WPS Resources reports four segments, which are described below.
Our two regulated segments include the regulated electric utility operations of WPSC and UPPCO, and the regulated natural gas utility operations of WPSC. WPSC's revenues are primarily derived from the service of electric and natural gas retail customers in northeastern and central Wisconsin and an adjacent portion of Upper Michigan. WPSC also provides wholesale electric service to various customers, including
municipal utilities, electric cooperatives, energy marketers, other investor-owned utilities, and a municipal joint action agency. Portions of WPSC's electric and natural gas operations cannot be specifically identified as electric or natural gas and instead are allocated using either actual labor hours, revenues, number of customers, or number of meters. UPPCO derives revenues from the sale of electric energy in the Upper Peninsula of Michigan.
ESI is our primary nonregulated segment. ESI offers nonregulated natural gas, electric, and alternate fuel supplies as well as energy management and consulting services to retail and wholesale customers and competes in the wholesale merchant electric power generation industry, primarily in the northeastern quadrant of the United States, adjacent portions of Canada, and now Texas. Although ESI has a widening array of products and services, revenues are primarily derived through sales of electricity and natural gas to retail and wholesale customers. ESI's marketing and trading operations manage power and natural gas procurement as an integrated portfolio with its retail and wholesale sales commitments. Electricity required to fulfill these sales commitments is procured from both ESI merchant electric power generation and from independent generators, energy marketers, and organized electric power markets. Natural gas is purchased from a variety of suppliers under daily, monthly, seasonal and long-term contracts with pricing delivery and volume schedules to accommodate customer requirements. ESI's customers include utilities, municipalities, cooperatives, commercial and industrial consumers, aggregators, and other marketing and retail entities.
ESI also owns several merchant electric generation plants, primarily in the Midwest and northeastern United States and adjacent portions of Canada. ESI markets power from these plants that is not under contract to third parties. ESI utilizes power from its New England and Canadian assets primarily to serve firm load commitments in northern Maine and certain other sales agreements with customers. For most of the remaining capacity available from these plants, ESI utilizes financial tools, including forwards, options, and swaps to mitigate exposure, as well as to maximize value from the merchant generation fleet. Power purchase agreements are also in place with third-party customers for approximately megawatts of capacity, which includes the Stoneman facility in Cassville, Wisconsin, and the Combined Locks facility in Combined Locks, Wisconsin.
The Holding Company and Other segment, another nonregulated segment, includes the operations of WPS Resources and WPS Resources Capital Corporation as holding companies and the nonutility activities at WPSC and UPPCO. Equity earnings from our investments in ATC, Wisconsin River Power Company, and Guardian Pipeline, LLC are included in the Holding Company and Other Segment.
The tables below present information for the respective years pertaining to our operations segmented by lines of business.
(1) Includes only utility operations. Nonutility operations are included in the Other column.
(1)
Includes only utility operations. Nonutility operations are included in the Other column.
(1)
Includes only utility operations. Nonutility operations are included in the Other column.
(1)
Revenues and assets of Canadian subsidiaries.
NOTE 27--QUARTERLY FINANCIAL INFORMATION (Unaudited)
(1) Earnings per share for the individual quarters do not total the year ended earnings per share amount because of changes to the average number of shares outstanding and changes in incremental issuable shares throughout the year.
Because of various factors, the quarterly results of operations are not necessarily comparable.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
WPS RESOURCES CORPORATION
H. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of WPS Resources Corporation
We have audited the accompanying consolidated balance sheets of WPS Resources Corporation and subsidiaries (the "Company") as of December 31, 2005 and 2004, and the related consolidated statements of income, shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules 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 WPS Resources Corporation and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement 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.
As discussed in Note 1 to the consolidated financial statements, effective January 1, 2003 the Company changed its method of accounting for certain energy trading contracts to adopt EITF 02-3, "Issues Involved in Accounting for Derivatives Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." As discussed in Notes 1 and 15 to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations to adopt Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations." As discussed in Notes 1 and 15 to the consolidated financial statements, effective December 31, 2005, the Company changed its method of accounting for conditional asset retirement obligations to adopt FASB Interpretation No. 47, "Conditional Asset Retirement Obligations."
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 28, 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
Milwaukee, Wisconsin
February 28,
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
WISCONSIN PUBLIC SERVICE CORPORATION
I. MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of WPSC and its subsidiary is responsible for establishing and maintaining adequate internal control over financial reporting. WPSC's control systems were designed to provide reasonable assurance to WPSC's management and Board of Directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
WPSC's management assessed the effectiveness of its internal control over financial reporting as of December 31, 2005. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, management believes that, as of December 31, 2005, WPSC's internal control over financial reporting is effective based on those criteria.
WPSC's independent registered public accounting firm has issued an audit report on management's assessment of WPSC's internal control over financial reporting.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
WISCONSIN PUBLIC SERVICE CORPORATION
J. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Wisconsin Public Service Corporation
We have audited management's assessment, included in the accompanying Management Report on Internal Control over Financial Reporting, that Wisconsin Public Service Corporation and subsidiary (the "Company") maintained effective internal control over financial reporting as of December 31, 2005, based on 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 financial statements and financial statement schedules as of and for the year ended December 31, 2005 of the Company and our report dated February 28, 2006 expressed an unqualified opinion on those financial statements and financial statement schedules and included an explanatory paragraph regarding the Company's adoption of new accounting standards.
/s/ Deloitte & Touche LLP
Milwaukee, Wisconsin
February 28,
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
WISCONSIN PUBLIC SERVICE CORPORATION
P. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Certain notes to WPSC's financial statements are combined with the notes to the financial statements of WPS Resources in Item 8, Section E. The combined notes are listed below.
In addition to the combined notes, the following are supplemental notes for WPSC. These notes should be read in conjunction with WPS Resources' consolidated financial statements and the related notes. WPSC is subject to regulation by the FERC under the Federal Power Act and follows the Uniform System of Accounts prescribed by the FERC.
NOTE 1--CASH AND CASH EQUIVALENTS
Cash paid for taxes during 2005, 2004, and 2003 was $45.3 million, $38.4 million, and $29.7 million, respectively. During 2005, 2004, and 2003, cash paid for interest totaled $30.4 million, $28.7 million, and $28.4 million, respectively.
Non-cash transactions were as follows:
NOTE 2--FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of WPSC's financial instruments as of December 31 were:
NOTE 3--REGULATORY ASSETS AND LIABILITIES
The following regulatory assets and liabilities were reflected in WPSC's consolidated balance sheets as of December 31:
NOTE 4--LEASES
WPSC leases various property, plant, and equipment. Terms of the leases vary but generally require WPSC to pay property taxes, insurance premiums, and maintenance costs associated with the leased property. Rental expense attributable to operating leases was $5.2 million, $4.2 million, and $3.9 million in 2005, 2004, and 2003 respectively. Future minimum rental obligations under non-cancelable operating leases are payable as follows:
NOTE 5--COMMON EQUITY
WPSC is restricted by a PSCW order to paying normal common stock dividends of no more than 109% of the previous year's common stock dividend without the PSCW's approval. WPS Resources may provide equity contributions or request a return of capital in order to maintain utility common equity levels consistent with those allowed by the regulators. Wisconsin law prohibits WPSC from making loans to or guaranteeing obligations of WPS Resources or its other subsidiaries.
During 2005, WPSC received equity contributions of $75.0 million from WPS Resources. WPSC paid common dividends of $81.0 million to WPS Resources in 2005. The equity contributions allowed WPSC's average equity capitalization ratio for ratemaking to remain within the target range as established by the PSCW in its most recent rate order.
NOTE 6--PREFERRED STOCK
WPSC has issued preferred stock with no mandatory redemption and a $100 par value. The following table shows the carrying value and shares outstanding at December 31, 2004, and 2005 of the 1,000,000 shares authorized:
NOTE 7--SHORT-TERM DEBT AND LINES OF CREDIT
The information in the table below relates to short-term debt and lines of credit for the years indicated:
The commercial paper had varying maturity dates ranging from January 5, 2006 through January 12, 2006.
NOTE 8--LONG-TERM DEBT
At December 31, 2005, WPSC was in compliance with all covenants relating to outstanding debt. A schedule of all principal debt payment amounts, including bond maturities and early retirement payments is as follows:
NOTE 9 - ASSET RETIREMENT OBLIGATIONS
Effective January 1, 2003, WPSC adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," and recorded a net asset retirement cost of $90.8 million and an asset retirement obligation of $324.8 million. The difference between the previously recorded liabilities of $290.5 million and the cumulative effect of adopting SFAS No. 143 was deferred as a regulatory liability pursuant to SFAS No. 71. The asset retirement obligations related primarily to the final decommissioning of Kewaunee. As a result of the sale of Kewaunee to Dominion on July 5, 2005, Dominion assumed the asset retirement obligation related to Kewaunee.
WPSC adopted the provisions of Interpretation No.47, "Accounting for Conditional Asset Retirement Obligations" as of December 31, 2005, and recorded a net asset retirement cost of $1.2 million and an asset retirement obligation of $7.3 million. This resulted in a cumulative effect of adopting the Interpretation of $6.1 million before taxes, which was deferred as a regulatory asset as WPSC obtained approval to defer the cumulative effect of adopting the Interpretation and believes it is probable that the actual cost to dispose of the assets will be recoverable in future rates. At December 31, 2005, WPSC had already recorded a $2.9 million regulatory liability related to the conditional asset retirement obligations, pertaining to amounts previously recovered in customer rates for the disposal of these assets. This $2.9 million regulatory liability was netted against the regulatory assets recorded upon adoption of the Interpretation.
NOTE 10 - INCOME TAXES
The principal components of WPSC's deferred tax assets and liabilities recognized in the balance sheet as of December 31 are as follows:
The following table presents a reconciliation of federal income taxes (which are calculated by multiplying the statutory federal income tax rate by book income before federal income tax) to the federal income tax expense reported in the Consolidated Statements of Income for the periods ended December 31.
As the related temporary differences reverse, WPSC is prospectively refunding taxes to customers for which deferred taxes were recorded in prior years at rates different than current rates. The regulatory liability for these refunds and other regulatory tax effects totaled $4.1 million and $6.6 million as of December 31, 2005, and 2004, respectively.
NOTE 11 - SEGMENTS OF BUSINESS
WPSC manages its reportable segments separately due to their different operating and regulatory environments. Its principal business segments are the regulated electric utility operations and the regulated gas utility operations. The tables below present information for the respective years pertaining to the operations of WPSC segmented by lines of business.
1Nonutility operations are included in the Other column.
1Nonutility operations are included in the Other column.
1Nonutility operations are included in the Other column.
NOTE 12 - QUARTERLY FINANCIAL INFORMATION (Unaudited)
Because of various factors that affect the utility business, the quarterly results of operations are not necessarily comparable.
NOTE 13 - RELATED PARTY TRANSACTIONS
WPSC routinely enters into transactions with related parties, including WPS Resources, its subsidiaries, and other entities in which WPSC has material interests.
The following table shows purchases from and sales to related parties:
WPS Leasing, a consolidated subsidiary of WPSC, has a note payable to WPSC's parent company, WPS Resources. The balance of the payable was $11.5 million and $12.0 million at December 31, 2005, and 2004, respectively. Interest expense on the note totaled $1.0 million per year in 2005, 2004, and 2003.
With the exception of UPPCO's Supplemental Employee Retirement Plan, the assets and liabilities related to the qualified and non-qualified pension plans and the postretirement plans of WPS Resources are recorded on WPSC's Consolidated Balance Sheets. The net periodic benefit cost associated with the plans is allocated among WPS Resources' subsidiaries. At December 31, 2005, and 2004, WPSC's Consolidated Balance Sheets included $1.7 million and $1.4 million, respectively, in receivables from related parties related to these benefit plans.
WPS Resources and its consolidated subsidiaries file consolidated federal income tax returns. WPSC pays the income taxes, which are then allocated to the appropriate entities. The tax allocable to each subsidiary is the amount of tax it would have paid had it filed a separate return for the tax year in question, after application of any credit to which it would be entitled on a separate return basis. At December 31, 2005, WPSC's Consolidated Balance Sheet included intercompany taxes payable of $19.1 million. At December 31, 2004, WPSC's Consolidated Balance Sheet included intercompany taxes receivable of $3.1 million and intercompany taxes payable of $24.4 million.
At December 31, 2005, WPSC had a 24.91% interest in WPS Investments accounted for under the equity method. WPS Investments is a consolidated subsidiary of WPS Resources that is jointly owned by WPS Resources, WPSC, and UPPCO. Prior to 2003, WPS Investments was a consolidated subsidiary of WPSC, but capital contributions during 2003 resulted in majority ownership by WPS Resources. The ownership interests have varied throughout 2005, 2004, and 2003 and will continue to change as cash is contributed by WPS Resources or additional assets are contributed by the utilities. Equity income recorded by WPSC during 2005, 2004, and 2003 was $7.6 million, $6.9 million, and $5.8 million respectively.
WPSC also provides and receives other services, property, and things of value to and from its parent, WPS Resources, and other subsidiaries of WPS Resources. All such transactions are made pursuant to a master affiliated interest agreement approved by the PSCW. The agreement provides that WPSC receives payment equal to the higher of its cost or fair value for services and property and other things of value which WPSC provides to WPS Resources or its other nonregulated subsidiaries, and WPSC makes payments equal to the lower of the provider's cost or fair value for property, services, and other things of value which WPS Resources or its other nonregulated subsidiaries provide to WPSC. The agreement further provides that any services, property, or other things of value provided to or from WPSC to or for any other regulated subsidiary of WPS Resources be provided at cost. Modification or amendment to the master agreement requires the approval of the PSCW.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
WISCONSIN PUBLIC SERVICE CORPORATION
Q. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Wisconsin Public Service Corporation
We have audited the accompanying consolidated balance sheets and statements of capitalization of Wisconsin Public Service Corporation and subsidiary (the "Company") as of December 31, 2005 and 2004, and the related consolidated statements of income, shareholder's equity, and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules 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 Wisconsin Public Service Corporation and subsidiary as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement 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.
As discussed in Note 9 to the consolidated financial statements, effective January 1, 2003 the Company changed its method of accounting for asset retirement obligations to adopt Statement of Financial Accounting Standard No. 143, "Accounting for Asset Retirement Obligations." As discussed in Note 9 to the consolidated financial statements, effective December 31, 2005, the Company changed its method of accounting for conditional asset retirement obligations to adopt FASB Interpretation No. 47, "Conditional Asset Retirement Obligations."
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 28, 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
Milwaukee, Wisconsin
February 28,
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this Annual Report on Form 10-K, WPS Resources' and WPSC's management evaluated, with the participation of WPS Resources' and WPSC's Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of WPS Resources' and WPSC's disclosure controls and procedures (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e)) and have concluded that, WPS Resources' and WPSC's disclosure controls and procedures were effective as of the date of such evaluation in timely alerting them to material information relating to WPS Resources and WPSC (including their consolidated subsidiaries) required to be included in their periodic SEC filings, particularly during the period in which this Annual Report on Form 10-K was being prepared.
Changes in Internal Controls
On April 1, 2005, the MISO "Day 2" Market became effective which impacted electric generation and purchased power practices and systems of WPS Resources' subsidiaries (including WPSC, UPPCO and ESI). In conjunction with WPS Resources' participation in the MISO Day 2 Market, certain changes in internal controls over financial reporting were made that have materially affected, or are reasonably likely to materially affect, WPS Resources', WPSC's and ESI's internal control over financial reporting. In the fourth quarter of 2005, WPS Resources, WPSC and ESI made changes in internal controls, primarily related to revenue and cost recognition associated with electric generation and purchased power, in response to changes made by MISO in its controls and procedures as a result of issues raised by FERC, market participants and MISO's review of its internal controls.
In October 2005, our regulated utilities converted to a new customer billing and information system. Changes in internal control over financial reporting were made as a result of implementing the new system. Some of these changes have materially affected, or are reasonably likely to materially affect, our regulated utilities' internal control over financial reporting. The internal controls affected primarily relate to the billing process and revenue recognition associated with electric and natural gas energy sales at the regulated utilities.
Other than the matters discussed in the preceding paragraphs, there were no changes in WPS Resources' and WPSC's internal controls over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) that occurred during the quarter ended December 31, 2005, that have materially affected, or are reasonably likely to materially affect, the internal control over financial reporting.
Management Reports on Internal Control over Financial Reporting
For the WPS Resources' and WPSC's Management Report on Internal Control Over Financial Reporting see Sections A and I of Item 8.
Reports of Independent Registered Public Accounting Firm
For the WPS Resources' and WPSC's Reports of Independent Registered Public Accounting Firm see Sections B and J of Item 8.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
Information required by this Item regarding the directors of WPS Resources, Section 16 compliance and the members of the Audit Committee and the Audit Committee financial expert can be found in WPS Resources' Proxy Statement for its Annual Meeting of Shareholders to be held May 18, 2006, under the captions "Election of Directors," "Ownership of Voting Securities-Section 16(a) Beneficial Ownership Reporting Compliance" and "Committees of the Board of Directors," respectively. Such information is incorporated by reference as if fully set forth herein. The directors of WPS Resources are also the directors of WPSC.
Information regarding the executive officers of WPS Resources and WPSC can be found in this Annual Report on Form 10-K in Item 4A.
WPS Resources has adopted a Code of Conduct, which serves as our Code of Business Conduct and Ethics. The Code of Conduct applies to all of our directors, officers, and employees, including the Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer and Controller and any other persons performing similar functions. The Code of Conduct also applies to WPSC and all of its directors, officers, and employees. WPS Resources has also adopted corporate governance guidelines.
WPS Resources' Code of Conduct, Corporate Governance Guidelines and charters of the board committees may be accessed on the WPS Resources web site, www.wpsr.com under "Investor Information" then select "Corporate Governance." Copies of WPS Resources' Code of Conduct, Corporate Governance Guidelines and charters of the board committees can also be obtained by writing to WPS Resources Corporation, Attention: Barth J. Wolf, Secretary and Manager - Legal Services, P.O. Box 19001, Green Bay, Wisconsin 54307-9001. Any amendments to, or waivers from, our Code of Conduct will be disclosed on our web site within the prescribed time period.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
WPS Resources Corporation
Information required by this Item regarding compensation paid by WPS Resources to its directors and its "named executive officers" can be found in WPS Resources' Proxy Statement for its Annual Meeting of Shareholders to be held May 18, 2006, under the captions "Board Compensation" and "Executive Compensation." Such information is incorporated by reference as if fully set forth herein. Named executive officers include the Chief Executive Officer and the next four most highly compensated executive officers for 2005.
Wisconsin Public Service Corporation
Summary Compensation Table
The following table sets forth cash and other compensation paid to or earned by each of the named executive officers of WPSC for the last three fiscal years. Named executive officers include the Chief Executive Officer and the next four most highly compensated executive officers for 2005. Compensation amounts for those WPSC named executive officers also reported as named executive officers of WPS Resources are repeated in this table and do not reflect additional compensation.
(1)
In addition to base salary, these amounts include elective deferred compensation in a reserve account for each individual.
(2)
These amounts reflect above-market earnings on elective deferred compensation. Perquisites for the Chief Executive Officer and the four other named executive officers were less than $50,000 or 10% of the total of salary and bonus for the year and, accordingly, are not listed.
(3)
Performance shares of WPS Resources' Common Stock have been awarded to each of the named executive officers as reported in the Long-Term Incentive Plan table presented below. At December 31, 2005, the closing stock price of WPS Resources common stock was $55.31. Based on this valuation, an award of the performance shares at target would have a value at year-end of $2,380,708 for Larry L. Weyers, $464,383 for Joseph P. O'Leary, $315,212 for Charles A. Schrock, $265,543 for Thomas P. Meinz, and $170,521 for Bernard J. Treml.
(4)
All Other Compensation for 2005 as reported in the table above is:
Name and Title
Year
Contributions to Employee Stock Ownership Plan
($)
Deferred Compensation Contribution for ESOP Restoration Benefit
($)
Life Insurance Premiums
($)
Above Market Earnings on Mandatory Deferred Compensation
($)
Larry L. Weyers
11,065
-
4,350
19,663
Joseph P. O'Leary
10,686
-
2,338
-
Thomas P. Meinz
10,957
-
1,587
8,278
Charles A. Schrock
10,580
-
2,033
9,296
Bernard J. Treml
8,475
2,066
1,514
8,790
Agreements with Named Executive Officers
Individual employment and severance agreements exist with each of the named executive officers. The agreements are intended to retain the services of these executive officers in the event of a change in control of WPS Resources. Each agreement entitles the executive officer to a continuation of salary and benefits for a maximum period of three years after a change in control. Each employment and severance agreement also provides a cash termination payment should there be a termination of the executive officer's employment after a change in control or in anticipation of a change in control. Generally, any such cash termination payment will not exceed the present value of 2.99 times the executive officer's average annual salary and annual bonuses for the five years immediately preceding a change in control. Larry L. Weyers may receive cash termination payments, plus a tax gross up payment exceeding 2.99 times average annual salary, portions of which WPS Resources may not be able to deduct for income tax purposes. The cash termination payments replace all other severance payments to which the executive officer may be entitled under the existing severance agreements.
Option Grants to Named Executives in Last Fiscal Year
All options reported above will vest at a rate of 25% per year beginning December 7, 2006, and ending December 7, 2009. On December 31, 2005, the closing price of WPS Resources stock was $55.31. There were no stock appreciation rights granted to any employee in 2005.
The grant date present value above is based on option values of $3.30 per option granted on December 7, 2005. This value was calculated using a closed-form binomial lattice model. For purposes of determining the value of these options, the following assumptions were made:
Annual dividend yield
4.29%
Volatility
12.02%
Risk free rate of return (Yield Curve)
1.50% to 4.50%
Time of exercise
6.25 years
The annual dividend yield assumption was based on actual dividends and stock prices of WPS Resources' common stock over the prior 12-month period to determine an annualized 12-month yield. Volatility is based on the monthly price changes of WPS Resources' common stock over the 36 months prior to the grant date. The risk free rate of return assumption employs a yield curve based on the yield of a 30-year treasury with a remaining term equal to the respective point in the option's life. The expected life of the option was calculated using the SEC "safe harbor" formula of full option term plus vesting divided by two.
Aggregated Option Exercises in Last Fiscal Year and Fiscal Year End Option Values for the Named Executive Officers
Number of securities underlying unexercised options/SARs at fiscal year end
Value of unexercised
in-the-money options/SARs at fiscal year end (1)
(#)
($)
Name
Shares acquired on exercise (#)
Value realized ($)
Exercisable/
Unexercisable
Exercisable/
Unexercisable
Larry L. Weyers
-
-
311,636 / 278,674
5,368,785 / 1,601,398
Joseph P. O'Leary
-
-
56,443 / 54,563
968,763 / 305,869
Thomas P. Meinz
5,638
94,662
36,013 / 31,008
616,793 / 191,838
Charles A. Schrock
7,500
188,438
52,026 / 37,029
970,509 / 242,445
Bernard J. Treml
-
-
22,944 / 20,079
401,810 / 109,162
(1)
Amounts represent the excess fair market value of the underlying stock at year-end and the exercise price of each option. The year-end stock price was $55.31.
Performance Share (Long-Term Incentive Plan) Awards to the Named Executive Officers
Performance shares are issued under the WPS Resources' 2005 Omnibus Incentive Compensation Plan. Under the Plan, the Compensation Committee sets performance goals, based on Total Shareholder Return (TSR), at the start of each three-year period. The Compensation Committee determines if the performance share awards are ultimately issued, and if so, how many, by comparing WPS Resources' total shareholder return with the shareholder return of a peer group of major publicly traded energy companies. The number of performance shares initially awarded individuals is based on market levels of incentive compensation and competitiveness of the total compensation package. Award levels are targeted to meet the median of the range of similar awards paid by comparable companies. To obtain a threshold payout requires a TSR peer group ranking at the 35th percentile. If TSR results are lower than the 35th percentile, no payout is made. Target and maximum payouts are based on a TSR result at the 50th and 90th percentiles, respectively.
Pension Plans
The tables below show the lump sum retirement benefit payable to a covered participant for specified salary levels and years of service under the provisions of the WPSC Retirement Plan and the WPS Resources Corporation Pension Restoration and Supplemental Retirement Plan in effect January 1, 2006, assuming termination of employment on that date:
(1)
The Pension Plan provides a lump sum benefit, which may be converted into an actuarially equivalent annuity with monthly payments. The benefit is not subject to any deduction for Social Security or other offset.
(2)
"Final Average Pay" is the average of the last 60 months or the 5 highest calendar years' compensation within the 10-year period immediately proceeding the participant's termination of employment, whichever is greater.
(1)
The pension plan provides a lump sum benefit, which may be converted into an actuarially equivalent annuity with monthly payments. The benefit is not subject to any deduction for Social Security or other offset.
"Final Average Pay" is the average of the last 60 months or the 5 highest calendar years' compensation within the 10-year period immediately proceeding the participant's termination of employment, whichever is greater.
Named executive officers' compensation for pension purposes differs from annual compensation reported in the Summary Compensation Table. Pension compensation for the named executive officers is:
Name
Pension Compensation ($)
Years of Service
Larry L. Weyers
1,406,868
Joseph P. O'Leary
443,587
Thomas P. Meinz
308,612
Charles A. Schrock
394,012
Bernard J. Treml
283,974
Annual benefits payable from the pension plan were subject to a maximum limitation of $170,000 for 2005 under the Internal Revenue Code. The amount of compensation considered for purposes of the pension plan was limited to $210,000 for 2005 under the Internal Revenue Code. The pension restoration plan provides additional pension benefits for pension restoration plan participants to compensate for any loss of benefit payable under the pension plan caused by the maximum benefit limitation, compensation limitation, or any salary deferral under the WPS Resources Deferred Compensation Plan. Retirement benefits presented in the pension plan tables include the pension restoration benefit.
The WPS Resources Supplemental Retirement Plan provides supplemental monthly payments to its participants. Certain executive officers, including the Chief Executive Officer and each of the other named executive officers, participate in the supplemental retirement plan. Retirement benefits presented in the pension plan tables do not include benefits under the supplemental retirement plan.
Benefits under the supplemental retirement plan are payable if the participant retires or terminates employment after reaching age 55 and completing at least 10 years of credited service or 5 years in the event of termination following a change in control. An eligible participant with 15 or more years of credited service will receive a monthly benefit equal to 60 percent of the participant's "Final Average Earnings," reduced by the monthly pension plan benefit and restoration plan benefit to which the participant is entitled or would be entitled had the participant elected an annuity form of payment. "Final Average Earnings" mean 1/36th of the base salary and annual bonus paid to the participant during the month in which the participant's employment is terminated and the immediately preceding 35 months, or during the 3 calendar years immediately preceding the calendar year in which the participant's employment is terminated. If the participant has fewer than 15 years of credited service, the 60 percent target benefit percentage is reduced by 4 percent for each year by which the participant's years of credited service is less than 15 years.
Estimated annual benefits to be received by each of the named executive officers under the Supplemental Retirement Plan upon normal retirement are as follows:
Name
Estimated Supplemental
Retirement Benefit ($)
Larry L. Weyers
$431,126
Joseph P. O'Leary
-
Thomas P. Meinz
57,234
Charles A. Schrock
113,168
Bernard J. Treml
63,177
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
WPS Resources Corporation
Information required by this Item regarding the principal securities holders of WPS Resources and the security holdings of its directors and executive officers can be found in WPS Resources' Proxy Statement for its Annual Meeting of Shareholders to be held May 18, 2006 under the caption "Ownership of Voting Securities--Beneficial Ownership." Such information is incorporated by reference as if fully set forth herein.
Wisconsin Public Service Corporation
Ownership of Voting Securities
All of the common stock of WPSC is held by WPS Resources.
Listed in the following table are the shares of WPS Resources' common stock owned as of February 15, 2006 by the directors and named executive officers of WPSC, who are not directors or named executive officers of WPS Resources, as well as the number of shares owned by the directors and executive officers of WPSC as a group as of February 15, 2006.
* Less than 1% of WPS Resources outstanding shares of common stock
(1)
Aggregate Number of Shares Beneficially Owned includes shares of common stock held in the Employee Stock Ownership Plan and Trust, the WPSC Deferred Compensation Trust, and all stock options, which are exercisable within 60 days of February 15, 2006. Each director or officer has sole voting and investment power with respect to the shares reported, unless otherwise noted. No voting or investment power exists related to the stock options reported until exercised.
None of the persons listed beneficially owns shares of any other class of WPS Resources' equity securities.
Equity Compensation Plan Information
Information required by this Item regarding equity compensation plans of WPS Resources can be found in WPS Resources' Proxy Statement for its Annual Meeting of Shareholders to be held May 18, 2006, under the caption "Ownership of Voting Securities--Equity Compensation Plan Information." Such information is incorporated by reference as if fully set forth herein.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
WPSC provides and receives services, property, and other things of value to and from its parent, WPS Resources, and other subsidiaries of WPS Resources. All such transactions are made pursuant to a master affiliated interest agreement approved by the PSCW. The agreement provides that WPSC receives payment equal to the higher of its cost or fair value for services and property and other things of value which WPSC provides to WPS Resources or its other nonregulated subsidiaries, and WPSC makes payments equal to the lower of the provider's cost or fair value for property, services, and other things of value which WPS Resources or its other nonregulated subsidiaries provide to WPSC. The agreement further provides that any services, property, or other things of value provided to or from WPSC to or for any other regulated subsidiary of WPS Resources be provided at cost. Modification or amendment to the master agreement requires the approval of the PSCW.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The following is a summary of the fees billed to WPS Resources and WPSC by Deloitte & Touche LLP for professional services performed for 2005 and 2004:
Fees
Audit Fees (a)
$2,169,279
$2,050,083
Audit Related Fees (b)
80,250
197,415
Tax Fees (c)
-
-
All Other Fees (d)
19,523
14,345
Total Fees
$2,269,052
$2,261,843
a)
Audit Fees. Consists of aggregate fees billed to WPS Resources and WPSC by Deloitte & Touche LLP for professional services rendered for the audits of the annual consolidated financial statements, reviews of the interim consolidated financial statements included in quarterly reports and audits of the effectiveness of, and management's assessment of the effectiveness of, internal control over financial reporting, of WPS Resources and its subsidiaries. Audit fees also include services that are normally provided by Deloitte & Touche in connection with statutory and regulatory filings or engagements, including comfort letters, consents and other services related to SEC matters, and consultations arising during the course of the audits and reviews concerning financial accounting and reporting standards.
b)
Audit Related Fees. Consists of fees billed for assurance and related services that are reasonably related to the performance of the audit or review of the consolidated financial statements or internal control over financial reporting and are not reported under "Audit Fees." These services include employee benefit plan audits, accounting consultations in connection with potential transactions, and consultations concerning financial accounting and reporting standards.
c)
Tax Fees. Consists of fees billed for professional services for tax compliance, tax advice and tax planning. These services include assistance regarding federal and state tax compliance, tax audit issues, mergers and acquisitions, and tax planning.
d)
All Other Fees. Consists of other fees billed to WPS Resources and WPSC by Deloitte & Touche LLP for products and services other than the services reported above. All Other Fees are for software licensing provided in 2005 and 2004. The nature of the software license fees, which include support and learning services, have been deemed to be permissible non-attest services.
In considering the nature of the services provided by the independent auditor, the Audit Committee determined that such services are compatible with the provision of independent audit services. The Audit Committee discussed these services with the independent auditor and WPS Resources management and determined that they are permitted under the rules and regulations concerning auditor independence promulgated by the SEC to implement the Sarbanes-Oxley Act of 2002, as well as those of the American Institute of Certified Public Accountants. The Audit Committee has approved in advance 100% of the services, if any, described in the table above under "Audit-Related Fees," "Tax Fees" and "All Other Fees" in accordance with its pre-approval policy.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Exhibit
Number
Description of Documents
2.1*
Asset Contribution Agreement between ATC and Wisconsin Electric Power Company, Wisconsin Power and Light Company, WPSC, Madison Gas & Electric Co., Edison Sault Electric Company, South Beloit Water, Gas and Electric Company, dated as of December 15, 2000. (Incorporated by reference to Exhibit 2A-3 to WPS Resources' and WPSC's Form 10-K for the year ended December 31, 2000.)
2.2*
Asset Purchase Agreement by and between Aquila, Inc. and WPS Michigan Utilities, Inc. (n/k/a Michigan Gas Utilities Corporation) dated September 21, 2005. (Incorporated by reference to Exhibit 2.1 to WPS Resources' Form 8-K filed September 27, 2005.)
2.3*
Asset Purchase Agreement by and between Aquila, Inc. and WPS Minnesota Utilities, Inc. (n/k/a Minnesota Energy Resources Corporation) dated September 21, 2005. (Incorporated by reference to Exhibit 2.2 to WPS Resources' Form 8-K filed September 27, 2005.)
3.1
Restated Articles of Incorporation of WPS Resources. (Incorporated by reference to Exhibit 3(i).(2) to WPS Resources' Form 10-Q for the quarter ended September 30, 2002.)
3.2
Articles of Incorporation of WPSC as effective May 26, 1972 and amended through May 31, 1988 (Incorporated by reference to Exhibit 3A to Form 10-K for the year ended December 31, 1991); Articles of Amendment to Articles of Incorporation dated June 9, 1993. (Incorporated by reference to Exhibit 3 to Form 8-K filed June 10, 1993.)
3.3
By-Laws of WPS Resources, as amended through April 1, 2004. (Incorporated by reference to Exhibit 3.1 to WPS Resources' and WPSC's Form 10-Q for the quarterly period ended March 31, 2004.)
3.4
By-Laws of WPSC, as in effect August 15, 2004. (Incorporated by reference to Exhibit 3.1 to WPS Resources' and WPSC's Form 10-Q for the quarterly period ended September 30, 2005.)
4.1
Rights Agreement, dated December 12, 1996, between WPS Resources and U.S. Bank National Association (successor to Firstar Trust Company). (Incorporated by reference to Exhibit 4.1 to WPS Resources' Form 8-A filed December 13, 1996 [File No.1-11337].)
4.2
Amendment to Rights Agreement, effective as of October 9, 2002, by and among WPS Resources, U.S. Bank National Association and American Stock Transfer & Trust Company. (Incorporated by reference to Exhibit 4(h) to WPS Resources' Form S-3 filed on April 28, 2003, File No. 333-104787.)
4.3
First Mortgage and Deed of Trust, dated as of January 1, 1941 from WPSC to U.S. Bank National Association (successor to First Wisconsin Trust Company), Trustee (Incorporated by reference to Exhibit 7.01 - File No. 2-7229); Supplemental Indenture, dated as of November 1, 1947 (Incorporated by reference to Exhibit 7.02 - File No. 2-7602); Supplemental Indenture, dated as of November 1, 1950 (Incorporated by reference to Exhibit 4.04 - File No. 2-10174); Supplemental Indenture, dated as of May 1, 1953 (Incorporated by reference to Exhibit 4.03 - File No. 2-10716); Supplemental Indenture, dated as of October 1, 1954 (Incorporated by reference to Exhibit 4.03 - File No. 2-13572); Supplemental Indenture, dated as of December 1, 1957 (Incorporated by reference to Exhibit 4.03 - File No. 2-14527); Supplemental Indenture, dated as of October 1, 1963 (Incorporated by reference to Exhibit 2.02B - File No. 2-65710); Supplemental Indenture, dated as of June 1, 1964 (Incorporated by reference to Exhibit 2.02B - File No. 2-65710); Supplemental Indenture, dated as of November 1, 1967 (Incorporated by reference to Exhibit 2.02B - File No. 2-65710); Supplemental Indenture, dated as of April 1, 1969 (Incorporated by reference to Exhibit 2.02B - File No. 2-65710); Fifteenth Supplemental Indenture, dated as of May 1, 1971 (Incorporated by reference to Exhibit 2.02B - File No. 2-65710); Sixteenth Supplemental Indenture, dated as of August 1, 1973 (Incorporated by reference to Exhibit 2.02B - File No. 2-65710); Seventeenth Supplemental Indenture, dated as of September 1, 1973 (Incorporated by reference to Exhibit 2.02B - File No. 2-65710); Eighteenth Supplemental Indenture, dated as of October 1, 1975 (Incorporated by reference to Exhibit 2.02B - File No. 2-65710); Nineteenth Supplemental Indenture, dated as of February 1, 1977 (Incorporated by reference to Exhibit 2.02B - File No. 2-65710); Twentieth Supplemental Indenture, dated as of July 15, 1980 (Incorporated by reference to Exhibit 4B to Form 10-K for the year ended December 31, 1980); Twenty-First Supplemental Indenture, dated as of December 1, 1980 (Incorporated by reference to Exhibit 4B to Form 10-K for the year ended December 31, 1980); Twenty-Second Supplemental Indenture dated as of April 1, 1981 (Incorporated by reference to Exhibit 4B to Form 10-K for the year ended December 31, 1981); Twenty-Third Supplemental Indenture, dated as of February 1, 1984 (Incorporated by reference to Exhibit 4B to Form 10-K for the year ended December 31, 1983); Twenty-Fourth Supplemental Indenture, dated as of March 15, 1984 (Incorporated by reference to Exhibit 1 to Form 10-Q for the quarter ended June 30, 1984); Twenty-Fifth Supplemental Indenture, dated as of October 1, 1985 (Incorporated by reference to Exhibit 1 to Form 10-Q for the quarter ended September 30, 1985); Twenty-Sixth Supplemental Indenture, dated as of December 1, 1987 (Incorporated by reference to Exhibit 4A-1 to Form 10-K for the year ended December 31, 1987); Twenty-Seventh Supplemental Indenture, dated as of September 1, 1991 (Incorporated by reference to Exhibit 4 to Form 8-K filed September 18, 1991); Twenty-Eighth Supplemental Indenture, dated as of July 1, 1992 (Incorporated by reference to Exhibit 4B - File No. 33-51428); Twenty-Ninth Supplemental Indenture, dated as of October 1, 1992 (Incorporated by reference to Exhibit 4 to Form 8-K filed October 22, 1992); Thirtieth Supplemental Indenture, dated as of February 1, (Incorporated by reference to Exhibit 4 to Form 8-K filed January 27, 1993); Thirty-First Supplemental Indenture, dated as of July 1, 1993 (Incorporated by reference to Exhibit 4 to Form 8-K filed July 7, 1993); Thirty-Second Supplemental Indenture, dated as of November 1, 1993 (Incorporated by reference to Exhibit 4 to Form 10-Q for the quarter ended September 30, 1993); Thirty-Third Supplemental Indenture, dated as of December 1, 1998 (Incorporated by reference to Exhibit 4D to Form 8-K filed December 18, 1998); Thirty-Fourth Supplemental Indenture, dated as of August 1, 2001 (Incorporated by reference to Exhibit 4D to Form 8-K filed August 24, 2001); Thirty-Fifth Supplemental Indenture, dated as of December 1, 2002 (Incorporated by reference to Exhibit 4D to Form 8-K filed December 16, 2002); and Thirty-Sixth Supplemental Indenture, dated as of December 8, 2003 (Incorporated by reference to Exhibit 4.2 to Form 8-K filed December 9, 2003.)
All references to periodic reports are to those of WPSC (File No. 1-3016).
4.4
Indenture, dated as of December 1, 1998, between WPSC and U.S. Bank National Association (successor to Firstar Bank Milwaukee, N.A., National Association) (Incorporated by reference to Exhibit 4A to Form 8-K filed December 18, 1998); First Supplemental Indenture, dated as of December 1, 1998 between WPSC and Firstar Bank Milwaukee, N.A., National Association (Incorporated by reference to Exhibit 4C to Form 8-K filed December 18, 1998); Second Supplemental Indenture, dated as of August 1, 2001 between WPSC and Firstar Bank, National Association (Incorporated by reference to Exhibit 4C of Form 8-K filed August 24, 2001); Third Supplemental Indenture, dated as of December 1, 2002 between WPSC and U.S. Bank National Association (Incorporated by reference to Exhibit 4C of Form 8-K filed December 16, 2002); and Fourth Supplemental Indenture, dated as of December 8, 2003, by and between WPSC and U.S. Bank National Association (successor to Firstar Bank, National Association and Firstar Bank Milwaukee, N.A., National Association). (Incorporated by reference to Exhibit 4.1 to Form 8-K filed December 9, 2003). References to periodic reports are to those of WPSC (File No. 1-3016).
4.5
Indenture, dated as of October 1, 1999, between WPS Resources and U.S. Bank National Association (successor to Firstar Bank Milwaukee, N.A., National Association) (Incorporated by reference to Exhibit 4(b) to Amendment No. 1 to Form S-3 filed October 21, 1999 [Reg. No. 333-88525]); First Supplemental Indenture, dated as of November 1, 1999 between WPS Resources and Firstar Bank, National Association (Incorporated by reference to Exhibit 4A of Form 8-K filed November 12, 1999); and Second Supplemental Indenture, dated as of November 1, 2002 between WPS Resources and U.S. Bank National Association. (Incorporated by reference to Exhibit 4A of Form 8-K filed November 25, 2002). All references to filings are those of WPS Resources (File No. 1-11337).
10.1
Joint Power Supply Agreement among WPSC, Wisconsin Power and Light Company, and Madison Gas and Electric Company, dated February 2, 1967. (Incorporated by reference to Exhibit 4.09 in File No. 2-27308.)
10.2
Joint Power Supply Agreement (Exclusive of Exhibits) among WPSC, Wisconsin Power and Light Company, and Madison Gas and Electric Company dated July 26, 1973. (Incorporated by reference to Exhibit 5.04A in File No. 2-48781.)
10.3* #
Joint Plant Agreement by and between WPSC and Dairyland Power Cooperative, dated as of November 23, 2004. (Incorporated by reference to Exhibit 10.19 to WPS Resources' and WPSC's Form 10-K for the year ended December 31, 2004.)
10.4
Basic Generating Agreement, Unit 4, Edgewater Generating Station, dated June 5, 1967, between Wisconsin Power and Light Company and WPSC. (Incorporated by reference to Exhibit 4.10 in File No. 2-27308.)
10.5
Agreement for Construction and Operation of Edgewater 5 Generating Unit, dated February 24, 1983, between Wisconsin Power and Light Company, Wisconsin Electric Power Company, and WPSC. (Incorporated by reference to Exhibit 10C-1 to WPSC's Form 10-K for the year ended December 31, 1983.)
10.6
Amendment No. 1 to Agreement for Construction and Operation of Edgewater 5 Generating Unit, dated December 1, 1988. (Incorporated by reference to Exhibit 10C-2 to WPSC's Form 10-K for the year ended December 31, 1988.)
10.7
Revised Agreement for Construction and Operation of Columbia Generating Plant among WPSC, Wisconsin Power and Light Company, and Madison Gas and Electric Company, dated July 26, 1973. (Incorporated by reference to Exhibit 5.07 in File No. 2-48781.)
10.8+
Form of Key Executive Employment and Severance Agreement entered into between WPS Resources and each of the following: Phillip M. Mikulsky and Larry L. Weyers. (Incorporated by reference to Exhibit 10.8 to WPS Resources' and WPSC's Form 10-K for the year ended December 31, 2002.)
10.9+
Form of Key Executive Employment and Severance Agreement entered into between WPS Resources and each of the following: Larry B. Borgard, Diane L. Ford, David W. Harpole, Richard E. James, Bradley A. Johnson, Thomas P. Meinz, Barbara A. Nick, Joseph P. O'Leary, Mark A. Radtke, Charles A. Schrock, Bernard J. Treml and Daniel J Verbanac. (Incorporated by reference to Exhibit 10.9 to WPS Resources' and WPSC's Form 10-K for the year ended December 31, 2002.)
10.10+
Form of Key Executive Employment and Severance Agreement entered into between WPS Resources and each of the following: Barth J. Wolf. (Incorporated by reference to Exhibit 10.10 to WPS Resources' and WPSC's Form 10-K for the year ended December 31, 2002.)
10.11+
Form of WPS Resources NonQualified Stock Option Agreement. (Incorporated by reference to Exhibit 10.1 to WPS Resources' and WPSC's Form 8-K filed December 13, 2005.)
10.12+
Form of WPS Resources Performance Stock Right Agreement. (Incorporated by reference to Exhibit 10.2 to WPS Resources' and WPSC's Form 8-K filed December 13, 2005.)
10.13+
WPS Resources 1999 Stock Option Plan. (Incorporated by reference to Exhibit 10-2 in WPS Resources' Form 10-Q for the quarter ended June 30, 1999, filed August 11, 1999.)
10.14+
WPS Resources 1999 Non-Employee Directors Stock Option Plan. (Incorporated by reference to Exhibit 4.2 in WPS Resources' Form S-8, filed December 21, 1999. [Reg. No. 333-93193].)
10.15+
WPS Resources Deferred Compensation Plan as Amended and Restated Effective January 1, 2005. (Incorporated by reference to Exhibit 10.10 to Annual Report on Form 10-K for the period ended December 31, 2004, filed March 9, 2005 [File No. 1-11337].)
10.16+
WPS Resources 2001 Omnibus Incentive Compensation Plan.
10.17+
WPS Resources Corporation 2005 Omnibus Incentive Compensation Plan. (Incorporated by reference to Exhibit 10.1 to WPS Resources' and WPSC's Form 10-Q filed August 4, 2005.)
10.18
Term Loan Agreement, dated as of November 5, 1999 among PDI New England, Inc., PDI Canada, Inc., and Bayerische Landesbank Girozentrale. (Incorporated by reference to Exhibit 4H to WPS Resources' and WPSC's Form 10-K for the year ended December 31, 1999.)
10.19
Five Year Credit Agreement among WPS Resources Corporation and the lenders identified herein, Citibank, N.A., Wells Fargo Bank National Association, J P Morgan Chase Bank, N.A., UBS Securities LLC, U.S. Bank National Association, and U.S. Bank National Association and Citigroup Global Markets Inc., dated as of June 2, 2005. (Incorporated by reference to Exhibit 10.1 to WPS Resources' and WPSC's Form 10-Q for the quarter ended June 30, 2005, filed August 4, 2005.)
10.20
Credit Agreement among WPS Resources Corporation, as Borrower, the Lenders Identified Therein, Bank of America, N.A., as Syndication Agent, JPMorgan Chase Bank, N.A., as Agent and J. P. Morgan Securities Inc. and Banc of America Securities LLC, as Co-Lead Arrangers and Book Managers Dated as of November 9, 2005. (Incorporated by reference to Exhibit 99.1 to WPS Resources' Form 8-K filed November 16, 2005.)
10.21
Credit Agreement among WPS Resources Corporation, as Borrower, the Lenders Identified Therein, Bank of America, N.A., as Syndication Agent, JPMorgan Chase Bank, N.A., as Agent and J. P. Morgan Securities Inc. and Banc of America Securities LLC, as Co-Lead Arrangers and Book Managers Dated as of November 9, 2005. (Incorporated by reference to Exhibit 99.2 to WPS Resources' Form 8-K filed November 16, 2005.)
10.22
Forward Sale Agreement, dated as of November 15, 2005, by and between WPS Resources and J.P. Morgan Securities Inc., as agent for J.P. Morgan Chase Bank, National Association, London Branch. (Incorporated by reference to Exhibit 99.2 to WPS Resources' Form 8-K filed November 17, 2005.)
12.1
WPS Resources Ratio of Earnings to Fixed Charges
12.2
WPSC Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed Charges and Preferred Dividends
Subsidiaries of the Registrants
23.1
Consent of Independent Registered Public Accounting Firm for WPS Resources
23.2
Consent of Independent Registered Public Accounting Firm for WPSC
Powers of Attorney
31.1
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for WPS Resources
31.2
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for WPS Resources
31.3
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for WPSC
31.4
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for WPSC
32.1
Written Statement of the Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350 for WPS Resources
32.2
Written Statement of the Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350 for WPSC
Proxy Statement for WPS Resources' 2006 Annual Meeting of Shareholders [To be filed with the SEC under Regulation 14A within 120 days after December 31, 2005; except to the extent specifically incorporated by reference, the Proxy Statement for the 2006 Annual Meeting of Shareholders shall not be deemed to be filed with the SEC as part of this Annual Report on Form 10-K]
*
Schedules and exhibits to this document are not filed therewith. The registrant agrees to furnish supplementally a copy of any such schedule or exhibit to the SEC upon request.
+
A management contract or compensatory plan or arrangement.
#
Portions of this exhibit have been redacted and are subject to a confidential treatment request filed with the Secretary of SEC pursuant to Rule 24b-2 under the Securities and Exchange Act of 1934, as amended. The redacted material is being filed separately with the SEC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized, on this 28th day of February, 2006.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of each of the Registrants and in the capacities and on the dates indicated.
Signature
Title
Date
Richard A. Bemis*
Director
Albert J. Budney, Jr.*
Director
Ellen Carnahan*
Director
Robert C. Gallagher*
Director
Kathryn M. Hasselblad-Pascale*
Director
James L. Kemerling*
Director
John C. Meng*
Director
William F. Protz, Jr.*
Director
/s/ Larry L. Weyers
Chairman, President, Chief Executive Officer and Director
(principal executive officer)
February 28,
Larry L. Weyers
/s/ Joseph P. O'Leary
Senior Vice President and Chief Financial Officer
(principal financial officer)
February 28,
Joseph P. O'Leary
/s/ Diane L. Ford
Vice President - Controller and Chief Accounting Officer
(principal accounting officer)
February 28,
Diane L. Ford
*By: /s/ Joseph P. O'Leary
Joseph P. O'Leary
Attorney-in-Fact
February 28,
SCHEDULE I - CONDENSED
PARENT COMPANY FINANCIAL STATEMENTS
WPS RESOURCES CORPORATION (PARENT COMPANY ONLY)
D. NOTES TO PARENT COMPANY FINANCIAL STATEMENTS
The following are supplemental notes to the WPS Resources Corporation (parent company only) financial statements and should be read in conjunction with our consolidated financial statements and the related notes.
The information in the table below relates to short-term debt and lines of credit for the years:
The commercial paper had varying maturity dates ranging from January 5, 2006 through January 20, 2006.
On June 17, 2005, $62.9 million of non-recourse debt at WPS Energy Services collateralized by nonregulated assets was restructured to a five-year WPS Resources obligation as a result of the sale of Sunbury’s allocated emission allowances. In addition, $2.7 million drawn on a line of credit at ESI was rolled into the five-year WPS Resources obligation. The floating interest rate on the total five-year WPS Resources’ obligation of $65.6 million has been fixed at 4.595% through two interest rate swaps.
WPS Resources has a long-term note payable to WPS Energy Services at December 31, 2005 and 2004 of $21.0 million. The notes bear interest at a rate that approximates current market rates and are due in 2021. We also have guaranteed other long-term debt and obligations of our subsidiaries arising in the normal course of business for both years as described in Note 5.
NOTE
GUARANTEES
As part of normal business, WPS Resources enters into various guarantees providing financial or performance assurance to third parties on behalf of certain subsidiaries. These guarantees are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries' intended commercial purposes.
Most of the guarantees issued by WPS Resources include inter-company guarantees between parents and their subsidiaries, which are eliminated in consolidation, and guarantees of the subsidiaries' own performance. As such, these guarantees are excluded from the recognition and measurement requirements of FASB Interpretation No. 45, "Guarantors' Accounting and Disclosure Requirements for Guarantees, including Indirect Guarantees of Indebtedness of Others."
At December 31, 2005, 2004, and 2003, outstanding guarantees totaled $1,292.2 million, $967.8 million, and $976.3 million, respectively, as follows:
WPS Resources'
Outstanding Guarantees
(Millions)
Commitments Expiring
Total Amounts Committed At December 31, 2005
Less Than
Year
to 3
Years
to 5
Years
Over
Years
Guarantees of subsidiary debt
$ 27.2
$ -
$ -
$ -
$27.2
Guarantees supporting commodity transactions of subsidiaries
1,154.7
1,063.0
33.1
15.0
43.6
Standby letters of credit
109.5
104.8
4.7
-
-
Surety bonds
0.8
0.8
-
-
-
Total guarantees
$1,292.2
$1,168.6
$37.8
$15.0
$70.8
At December 31, 2005, WPS Resources had outstanding $27.2 million in corporate guarantees supporting indebtedness. Of that total, $27.0 million supports outstanding debt at one of ESI's subsidiaries. The underlying debt related to these guarantees is reflected on the Consolidated Balance Sheet of WPS Resources.
WPS Resources' Board of Directors has authorized management to issue corporate guarantees in the aggregate amount of up to $1.35 billion to support the business operations of ESI. WPS Resources primarily issues the guarantees to counterparties in the wholesale electric and natural gas marketplace to provide them assurance that ESI will perform on its obligations and permit ESI to operate within these markets. At December 31, 2005, WPS Resources provided parental guarantees in the amount of $1,150.0 million, reflected in the above table, for ESI's indemnification obligations for business operations, including $8.1 million of guarantees that received specific authorization from WPS Resources' Board of Directors and are not included in the $1.35 billion general authorized amount. Of the parental guarantees provided by WPS Resources, the outstanding balance at December 31, 2005, which WPS Resources would be obligated to support, is approximately $299 million.
Another $4.7 million of corporate guarantees support energy and transmission supply at UPPCO and are not reflected on WPS Resources' consolidated balance sheet. In February 2005, WPS Resources' Board of Directors authorized management to issue corporate guarantees in the aggregate amount of up to $15.0 million to support the business operations of UPPCO. Corporate guarantees issued in the future under the Board authorized limit may or may not be reflected on WPS Resources' consolidated balance sheet, depending on the nature of the guarantee.
At WPS Resources' request, financial institutions have issued $109.5 million in standby letters of credit for the benefit of third parties that have extended credit to certain subsidiaries. If a subsidiary does not pay amounts when due under a covered contract, the counterparty may present its claim for payment to the financial institution, which will request payment from WPS Resources. Any amounts owed by our subsidiaries are reflected in the Consolidated Balance Sheet of WPS Resources.
At December 31, 2005, WPS Resources furnished $0.8 million of surety bonds for various reasons including worker compensation coverage and obtaining various licenses, permits, and rights-of-way. Liabilities incurred as a result of activities covered by surety bonds are included in the Consolidated Balance Sheet of WPS Resources.
NOTE 6 FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of WPS Resources’ financial instruments as of December 31 were: