Exhibit 99.3
See Item 8.01 of the accompanying Current Report on Form 8-K for a detailed discussion of the facts surrounding, rationale for and other matters involving the following disclosure.
The following information replaces portions of Item 7 (Management's Discussion and Analysis of financial Condition and Results of Operation) previously filed in the Annual Report on Form 10-K for the year ended December 31, 2005 for WPS Resources. All other portions of Item 7 are unchanged.
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. For more information on Sunbury, see Note 4, "Sunbury Plant," in WPS Resources' Notes to Consolidated Financial Statements. |
| · | 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. |
| · | |
| · | 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 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.
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. The table excludes volumes under contract for discontinued operations. 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.
Forward Contracted Volumes at 12/31/2005(1) | | 2006 | | 2007 | | After 2007 | |
| | | | | | | | |
| Wholesale sales volumes - billion cubic feet | | | 107.3 | | | 13.2 | | | 4.3 | |
| Retail sales volumes - billion cubic feet | | | 171.1 | | | 39.7 | | | 40.3 | |
| Total natural gas sales volumes | | | 278.4 | | | 52.9 | | | 44.6 | |
| | | | | | | | | | | |
| Wholesale sales volumes - million kilowatt-hours | | | 13,240 | | | 4,144 | | | 3,160 | |
| Retail sales volumes - million kilowatt-hours | | | 1,962 | | | 391 | | | 126 | |
| Total electric sales volumes | | | 15,202 | | | 4,535 | | | 3,286 | |
| (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. The table excludes volumes under contract for discontinued operations. Actual electric and natural gas sales volumes for 2005 are disclosed within Results of Operations - WPS Resources, ESI Segment Operations.
Forward Contracted Volumes at 12/31/2004(1) | | 2005 | | 2006 | | After 2006 | |
| | | | | | | | |
| Wholesale sales volumes - billion cubic feet | | | 98.1 | | | 8.0 | | | 2.2 | |
| Retail sales volumes - billion cubic feet | | | 184.8 | | | 33.1 | | | 8.4 | |
| Total natural gas sales volumes | | | 282.9 | | | 41.1 | | | 10.6 | |
| | | | | | | | | | | |
| Wholesale sales volumes - million kilowatt-hours | | | 5,981 | | | 785 | | | 880 | |
| Retail sales volumes - million kilowatt-hours | | | 3,413 | | | 1,308 | | | 339 | |
| Total electric sales volumes | | | 9,394 | | | 2,093 | | | 1,219 | |
| (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.
Counterparty Rating (Millions)(1) | | Exposure(2) | | Exposure Less Than 1 Year | | Exposure 1 to 3 Years | | Exposure 4 to 5 Years | |
| | | | | | | | | | |
| Investment grade - regulated utility | | $ | 7.6 | | $ | 7.6 | | $ | - | | $ | - | |
| Investment grade - other | | | 244.5 | | | 171.9 | | | 65.5 | | | 7.1 | |
| | | | | | | | | | | | | | |
| Non-investment grade - regulated utility | | | 0.1 | | | 0.1 | | | - | | | - | |
| Non-investment grade - other | | | 10.1 | | | 10.1 | | | - | | | - | |
| | | | | | | | | | | | | | |
Non-rated - regulated utility(3) | | | 1.3 | | | 1.3 | | | - | | | - | |
Non-rated - other(3) | | | 96.5 | | | 82.5 | | | 12.4 | | | 1.6 | |
| | | | | | | | | | | | | | |
| Total Exposure | | $ | 360.1 | | $ | 273.5 | | $ | 77.9 | | $ | 8.7 | |
| (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
2005 Compared with 2004
WPS Resources Overview
WPS Resources' 2005 and 2004 results of operations are shown in the following table:
WPS Resources' Results (Millions, except share amounts) | | 2005 | | 2004 | | Change | |
| | | | | | | | |
| Consolidated operating revenues | | $ | 6,847.3 | | $ | 4,890.6 | | | 40.0 | % |
| Income available for common shareholders | | $ | 157.4 | | $ | 139.7 | | | 12.7 | % |
| Basic earnings per share | | $ | 4.11 | | $ | 3.74 | | | 9.9 | % |
| Diluted earnings per share | | $ | 4.07 | | $ | 3.72 | | | 9.4 | % |
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 $1.7 billion (47.7%) 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):
| · | 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 $43.0 million increase in margin, partially offset by a $16.1 million increase in operating and maintenance expenses, a $22.5 million after-tax increase in results from discontinued operations, 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. |
| · | 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. |
| · | 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. |
| · | 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. |
| · | 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
WPS Resources' Electric Utility Segment Results (Millions) | | 2005 | | 2004 | | Change | |
| | | | | | | | |
| Revenues | | $ | 1,037.1 | | $ | 896.6 | | | 15.7 | % |
| Fuel and purchased power costs | | | 444.2 | | | 295.5 | | | 50.3 | % |
| Margins | | $ | 592.9 | | $ | 601.1 | | | (1.4 | %) |
| | | | | | | | | | | |
| Sales in kilowatt-hours | | | 15,660.1 | | | 14,465.7 | | | 8.3 | % |
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
WPS Resources' Gas Utility Segment Results (Millions) | | 2005 | | 2004 | | Change | |
| | | | | | | | |
| Revenues | | $ | 522.0 | | $ | 420.9 | | | 24.0 | % |
| Purchased gas costs | | | 397.4 | | | 301.9 | | | 31.6 | % |
| Margins | | $ | 124.6 | | $ | 119.0 | | | 4.7 | % |
| | | | | | | | | | | |
| Throughput in therms | | | 827.2 | | | 801.3 | | | 3.2 | % |
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.
ESI's Segment Operations
(Millions except natural gas sales volumes) | | 2005 | | 2004 | | Change | |
| | | | | | | | |
| Nonregulated revenues | | $ | 5,336.7 | | $ | 3,614.0 | | | 47.7 | % |
| Nonregulated cost of fuel, natural gas, and purchased power | | | 5,159.1 | | | 3,479.4 | | | 48.3 | % |
| Margins | | $ | 177.6 | | $ | 134.6 | | | 31.9 | % |
| | | | | | | | | | | |
| Wholesale natural gas sales volumes in billion cubic feet * | | | 274.0 | | | 235.4 | | | 16.4 | % |
| Retail natural gas sales volumes in billion cubic feet * | | | 281.2 | | | 276.7 | | | 1.6 | % |
| Wholesale electric sales volumes in kilowatt-hours * | | | 1,154.8 | | | 3,328.1 | | | (65.3 | %) |
| Retail electric sales volumes in kilowatt-hours * | | | 6,626.9 | | | 7,235.7 | | | (8.4 | %) |
* Represents gross physical volumes
Revenues
ESI's revenue increased $1.7 billion (47.7%) 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 $63 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 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 $43.0 million (31.9%), from $134.6 million for the year ended December 31, 2004, to $177.6 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.
(Millions except natural gas sales volumes) | | Increase (Decrease) in Margin in 2005 Compared to 2004 | |
| | | | |
Electric and other margins | | | |
| Physical asset management | | | 7.5 | |
| New York retail | | | 3.0 | |
| Michigan retail | | | (15.7 | ) |
| All other electric operations | | | 26.2 | |
| | | | | |
| Other significant items: | | | | |
| Oil option activity, net | | | 8.7 | |
| Liquidation of electric purchase contract | | | 8.2 | |
| | | | | |
| Net increase in electric and other margins | | | 37.9 | |
| | | | | |
Natural gas margins | | | | |
| Gas margins (principally Canada, Michigan, and Wisconsin retail markets) | | | 6.1 | |
| | | | | |
| Other significant items: | | | | |
| Counterparty settlement | | | 3.3 | |
| Unrealized gain on Ohio options | | | 2.9 | |
| Spot to forward differential | | | (7.2 | ) |
| | | | | |
| Net increase in natural gas margins | | | 5.1 | |
| | | | | |
| Net increase in ESI margin | | $ | 43.0 | |
ESI's electric and other margins increased $37.9 million (48.6%) 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:
| · | 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). |
| · | 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. |
| · | 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. |
| · | All other electric operations - A $26.2 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. |
| · | 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 29 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:
| · | 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. |
| · | Counterparty settlement - The natural gas margin increased $3.3 million as a result of a favorable settlement with a counterparty. |
| · | 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. |
| · | 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 $43.0 million increase in margin, partially offset by a $16.1 million increase in operating and maintenance expenses, a $22.5 million after-tax increase in results from discontinued operations, 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.
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
WPS Resources' Operating Expenses (Millions) | | 2005 | | 2004 | | Change | |
| | | | | | | | |
| Operating and maintenance expense | | $ | 540.3 | | $ | 513.2 | | | 5.3 | % |
| Depreciation and decommissioning expense | | | 142.6 | | | 107.0 | | | 33.3 | % |
| Taxes other than income | | | 47.5 | | | 46.1 | | | 3.0 | % |
Operating and Maintenance Expense
Operating and maintenance expenses increased $27.1 million (5.3%) 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:
| · | The combined increase in pension expense, active and postretirement medical expense, salaries, and customer service expense was approximately $25 million. |
| · | Transmission-related expenses increased $9.9 million. |
| · | 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. |
| · | 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 $16.1 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.
Depreciation and Decommissioning Expense
Depreciation and decommissioning expense increased $35.6 million (33.3%) 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.
Other Income (Expense)
WPS Resources' Other Income (Expense) (Millions) | | 2005 | | 2004 | | Change | |
| | | | | | | | |
| Miscellaneous income | | $ | 86.2 | | $ | 47.7 | | | 80.7 | % |
| Interest expense | | | (62.0 | ) | | (54.2 | ) | | 14.4 | % |
| Minority interest | | | 4.5 | | | 3.4 | | | 32.4 | % |
| Other (expense) income | | $ | 28.7 | | $ | (3.1 | ) | | - | |
Miscellaneous Income
Miscellaneous income increased $38.5 million (80.7%) for the year ended December 31, 2005, compared to 2004. The following items were the largest contributors to the change in miscellaneous income:
| · | 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. |
| · | 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. |
| · | 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. |
| · | 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. |
Interest Expense
The 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 21.3% for the year ended December 31, 2005, compared to 16.1% for the year ended December 31, 2004. The increase in the effective tax rate was primarily driven by a 4.4% 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.
Discontinued Operations, net of tax
Discontinued operations, net of tax, increased $22.5 million, from an after-tax net loss of $13.4 million in 2004 to after tax income of $9.1 million in 2005. The margin at Sunbury increased $42.6 million, primarily 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). ESI's earnings were 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 items were substantially offset by an $86.8 million pre-tax gain recognized on the sale of Sunbury's allocation emission allowances. The year-over-year change in discontinued operations was also negatively impacted by 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. For more information on Sunbury, see Note 4, "Sunbury Plant," in WPS Resources' Notes to Consolidated Financial Statements.
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.
2004 Compared with 2003
WPS Resources Overview
WPS Resources' 2004 and 2003 results of operations are shown in the following table:
WPS Resources' Results (Millions, except share amounts) | | 2004 | | 2003 | | Change | |
| | | | | | | | |
| Consolidated operating revenues | | $ | 4,890.6 | | $ | 4,321.3 | | | 13.2 | % |
| Income available for common shareholders | | $ | 139.7 | | $ | 94.7 | | | 47.5 | % |
| Basic earnings per share | | $ | 3.74 | | $ | 2.87 | | | 30.3 | % |
| Diluted earnings per share | | $ | 3.72 | | $ | 2.85 | | | 30.5 | % |
The $569.3 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 $470.6 million (15.0%), 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. |
| · | 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. |
| · | Higher throughput volumes and improved supply management in Ohio favorably impacted ESI's year-over-year retail natural gas margin. |
| · | 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. |
| · | 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. |
| · | Earnings from equity method investments (primarily from ATC) increased in 2004, compared to 2003. |
| · | Earnings were negatively impacted by higher operating and maintenance expenses in 2004. |
| · | Synthetic fuel related tax credits recognized were higher in 2004 when compared to 2003. |
| · | 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
WPS Resources' Electric Utility Segment Results (Millions) | | 2004 | | 2003 | | Change | |
| | | | | | | | |
| Revenues | | $ | 896.6 | | $ | 814.1 | | | 10.1 | % |
| Fuel and purchased power costs | | | 295.5 | | | 266.3 | | | 11.0 | % |
| Margins | | $ | 601.1 | | $ | 547.8 | | | 9.7 | % |
| | | | | | | | | | | |
| Sales in kilowatt-hours | | | 14,465.7 | | | 14,346.7 | | | 0.8 | % |
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.
| · | Effective March 21, 2003, the PSCW approved a retail electric rate increase of $21.4 million (3.5%). |
| · | Effective May 11, 2003, the FERC approved a $4.1 million (21%), interim increase in wholesale electric rates. |
| · | 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. |
| · | 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
WPS Resources' Gas Utility Segment Results (Millions) | | 2004 | | 2003 | | Change | |
| | | | | | | | |
| Revenues | | $ | 420.9 | | $ | 404.2 | | | 4.1 | % |
| Purchased gas costs | | | 301.9 | | | 291.0 | | | 3.7 | % |
| Margins | | $ | 119.0 | | $ | 113.2 | | | 5.1 | % |
| | | | | | | | | | | |
| Throughput in therms | | | 801.3 | | | 854.5 | | | (6.2 | %) |
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 a $24.3 million increase in margin, a $9.6 million increase in the amount of tax credits recognized, and a $2.6 million decrease in the loss from discontinued operations. 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.
ESI's Segment Operations (Millions except natural gas sales volumes) | | 2004 | | 2003 | | Change | |
| | | | | | | | |
| Nonregulated revenues | | $ | 3,614.0 | | $ | 3,143.4 | | | 15.0 | % |
| Nonregulated cost of fuel, natural gas, and purchased power | | | 3,479.4 | | | 3,033.1 | | | 14.7 | % |
| Margins | | $ | 134.6 | | $ | 110.3 | | | 22.0 | % |
| | | | | | | | | | | |
| Wholesale natural gas sales volumes in billion cubic feet * | | | 235.4 | | | 250.8 | | | (6.1 | %) |
| Retail natural gas sales volumes in billion cubic feet * | | | 276.7 | | | 240.6 | | | 15.0 | % |
| Wholesale electric sales volumes in kilowatt-hours * | | | 3,328.1 | | | 3,570.3 | | | (6.8 | %) |
| Retail electric sales volumes in kilowatt-hours * | | | 7,235.7 | | | 6,468.9 | | | 11.9 | % |
* 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 $127.4 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.
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 $11.8 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 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).
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
WPS Resources' Operating Expenses (Millions) | | 2004 | | 2003 | | Change | |
| | | | | | | | |
| Operating and maintenance expense | | $ | 513.2 | | $ | 459.5 | | | 11.7 | % |
| Depreciation and decommissioning expense | | | 107.0 | | | 138.4 | | | (22.7 | %) |
| Taxes other than income | | | 46.1 | | | 43.8 | | | 5.3 | % |
Operating and Maintenance Expense
Operating and maintenance expenses increased $53.7 million (11.7%), 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 $12.2 million mostly due to higher payroll, benefits, and other costs associated with continued business expansion.
Depreciation and Decommissioning Expense
Depreciation and decommissioning expense decreased $31.4 million (22.7%), 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)
WPS Resources' Other Income (Expense) (Millions) | 2004 | 2003 | Change |
| | | | |
| Miscellaneous income | $47.7 | $ 63.6 | (25.0%) |
| Interest expense and distributions of preferred securities | (54.2) | (55.6) | (2.5%) |
| Minority interest | 3.4 | 5.6 | (39.3%) |
| Other (expense) income | $ (3.1) | $ 13.6 | - |
Miscellaneous Income
Miscellaneous income decreased $15.9 million (25.0%), 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), 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 16.1% for the year ended December 31, 2004, compared to 23.4% 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.
Discontinued Operations
The after-tax loss from discontinued operations was $13.4 million for the year ended December 31, 2004, compared to $16.0 million in 2003. The decrease in the loss from discontinued operations was driven by a $4.4 million termination payment that was received from Duquesne Power in December 2004 as a result of Duquesne's termination of the asset sale agreement for Sunbury, a $2.9 million decrease in depreciation expense and a $2.3 million decrease in operating and maintenance expenses. The decreased depreciation expense resulted from the discontinuance of depreciation on those assets classified as held for sale effective December 2003. Sunbury's results of operations were classified as discontinued operations in December 2003. In the second quarter of 2005, Sunbury's results of operations were reclassified to continuing operations. For more information see Note 4, "Sunbury Plant," in WPS Resources' Notes to Consolidated Financial Statements. In the second quarter of 2005, operating and maintenance expenses decreased as repair and maintenance expenses were higher in 2003 because of mechanical difficulties related to fuel delivery systems. Sunbury's margin decreased in 2004, compared to 2003, partially offsetting the favorable variances discussed above. The margin was
negatively impacted by an increase in the per ton cost of coal utilized to service a fixed price outtake contract and a decrease in opportunities to sell power into the spot market. In anticipation of the sale, Sunbury did not enter into staggered term coal contracts in accordance with its normal procurement practice.
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
2005 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 2004 also contributed to the increase in accounts receivable at the regulated utilities.
Inventories increased $116.0 million (61.4%), from $188.8 million at December 31, 2004, to $304.8 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, increased $45.5 million to $2,048.1 million at December 31, 2005, compared to $2,002.6 million at December 31, 2004. The major contributors to the change in property, plant, and equipment are summarized below:
| · | Kewaunee was sold in 2005, driving a $165.4 million decrease in property, plant, and equipment. |
| · | Depreciation expense of $142.6 million was recorded in 2005. |
| · | WPSC sold a 30% interest in Weston 4, contributing an $83.9 million decrease to property, plant, and equipment. |
| · | Capital expenditures recorded in 2005 were $414.5 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 (15.0%), from $345.7 million at December 31, 2004, to $397.6 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 $44.9 million (62.4%), from $71.9 million at December 31, 2004, to $116.8 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 $364.4 million at December 31, 2004, to $9.3 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 $79.6 million, compared to $243.0 million in 2004. The decrease was driven by an $83.3 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 $243.0 million, compared with $62.4 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 $163.2 million (52.2%), from $312.6 million in 2004 to $149.4 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, 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 $124.5 million increase in capital expenditures (primarily related to the construction of Weston 4) 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 $312.6 million in 2004, compared to $244.0 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:
Millions | | Years Ended December 31, | |
| | | 2005 | | 2004 | | 2003 | |
| Electric utility | | $ | 373.9 | | $ | 223.0 | | $ | 131.0 | |
| Gas utility | | | 36.4 | | | 62.7 | | | 40.7 | |
| ESI | | | 3.3 | | | 4.0 | | | 4.7 | |
| Other | | | 0.9 | | | 0.3 | | | (0.2 | ) |
| WPS Resources' consolidated | | $ | 414.5 | | $ | 290.0 | | $ | 176.2 | |
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 related to financing activities was $0 in 2005, compared to net cash provided by financing activities of $76.8 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 (primarily related to proceeds received from various asset sales in 2005) and an increase in cash provided by discontinued operations.
Net cash provided by financing activities was $76.8 million in 2004, compared to $198.6 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. See Note 4, "Sunbury Plant," in WPS Resources' Notes to Consolidated Financial Statements for more information related to Sunbury.
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.
Discontinued Operations
Net cash provided by discontinued operations was $57.5 million in 2005, compared to net cash used for discontinued operations of $17.9 million in 2004. The increase in cash provided by discontinued operations in 2005 was driven by $110.9 million of proceeds received from the sale of Sunbury's allocated emission allowances in the second quarter of 2005, partially offset by income taxes paid related to the gain on the sale of these emission allowances.
Net cash used for discontinued operations was $17.9 million in 2004, compared to $9.6 million in 2003. The increase in cash used for discontinued operations was due to an increase in cash required for working capital purposes at Sunbury.
Future Capital Requirements and Resources
Contractual Obligations
The following table summarizes the contractual obligations of WPS Resources', including its subsidiaries.
| | | | | | | | | | | | |
| Contractual Obligations | | Total | | Payments Due By Period | |
As of December 31, 2005 (Millions) | | Amounts Committed | | 2006 | | 2007-2008 | | 2009-2010 | | 2011 and Thereafter | |
| | | | | | | | | | | | |
| Long-term debt principal and interest payments | | $ | 1,276.2 | | $ | 28.1 | | $ | 111.0 | | $ | 262.0 | | $ | 875.1 | |
| Operating leases | | | 24.3 | | | 5.1 | | | 7.4 | | | 4.9 | | | 6.9 | |
| Commodity purchase obligations | | | 6,857.6 | | | 4,000.6 | | | 1,528.8 | | | 610.7 | | | 717.5 | |
| Purchase orders | | | 476.1 | | | 352.4 | | | 122.9 | | | 0.8 | | | - | |
| Capital contributions to equity method investment | | | 79.0 | | | 39.9 | | | 39.1 | | | - | | | - | |
| Other | | | 384.1 | | | 45.1 | | | 72.5 | | | 38.9 | | | 227.6 | |
| Total contractual cash obligations | | $ | 9,097.3 | | $ | 4,471.2 | | $ | 1,881.7 | | $ | 917.3 | | $ | 1,827.1 | |
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. Included in the above table are commodity purchase obligations related to energy supply contracts at Sunbury, primarily obligations to purchase coal, totaling $26.1 million. The coal contracts extend until December 31, 2006 and were assumed by Corona Power, LLC. See Note 4, "Sunbury Plant," for more information related to Sunbury. 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 2006 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. See Note 4, "Sunbury Plant," in WPS Resources' Notes to Consolidated Financial Statements for more information.
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 2006 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 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.
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.
Amounts are pre-tax, except tax credits | | Income (loss) | |
| | | 2005 | | 2004 | | 2003 | |
| Provision for income taxes: | | | | | | | |
| Section 29 federal tax credits recognized | | $ | 26.1 | | $ | 27.8 | | $ | 18.2 | |
| | | | | | | | | | | |
| Miscellaneous income: | | | | | | | | | | |
| Operating losses - synthetic fuel facility | | | (16.8 | ) | | (14.1 | ) | | (15.5 | ) |
| Variable payments received | | | 3.6 | | | 3.5 | | | 3.3 | |
| Royalty income recognized | | | 3.5 | | | 4.1 | | | 2.6 | |
| Deferred gain recognized | | | 2.3 | | | 2.3 | | | 2.3 | |
| Interest received on fixed note receivable | | | 1.2 | | | 1.7 | | | 2.0 | |
| | | | | | | | | | | |
| Minority interest | | | 4.7 | | | 3.4 | | | 5.6 | |
-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 155 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.
ESI Mark-to-Market Roll Forward (Millions) | | Oil Options | | Natural Gas | | Electric | | Total | |
| | | | | | | | | | |
| Fair value of contracts at January 1, 2005 | | $ | - | | $ | 31.6 | | $ | 13.7 | | $ | 45.3 | |
| Less contracts realized or settled during period | | | - | | | (26.6 | ) | | (4.9 | ) | | (31.5 | ) |
| Plus changes in fair value of contracts in existence at December 31, 2005 | | | 23.6 | | | (50.0 | ) | | 11.211.9 | | | (15.2 | ) |
| Fair value of contracts at December 31, 2005 | | $ | 23.6 | | $ | 8.2 | | $ | 29.8 | | $ | 61.6 | |
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.
ESI Risk Management Contract Aging at Fair Value As of December 31, 2005 | | | | | | | | | |
Source of Fair Value (Millions) | | Maturity Less Than 1 Year | | Maturity 1 to 3 Years | | Maturity 4 to 5 Years | | Maturity in Excess of 5 Years | | Total Fair Value | |
| Prices actively quoted | | $ | (6.6 | ) | $ | 9.0 | | $ | 1.1 | | $ | - | | $ | 3.5 | |
| Prices provided by external sources | | | 30.1 | | | 20.4 | | | 7.5 | | | - | | | 58.0 | |
| Prices based on models and other valuation methods | | | 0.1 | | | - | | | - | | | - | | | 0.1 | |
| Total fair value | | $ | 23.6 | | $ | 29.4 | | $ | 8.6 | | $ | - | | $ | 61.6 | |
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 29 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 that is reported in discontinued operations (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.
Actuarial Assumption (Millions, except percentages) | | Percent Change in Assumption | | Impact on Projected Benefit Obligation | | Impact on Net Amount Recognized | | Impact on Pension Cost | |
| Discount rate | | | (0.5 | ) | $ | 45.0 | | $ | (4.1 | ) | $ | 4.1 | |
| Discount rate | | | 0.5 | | | (42.5 | ) | | 4.0 | | | (4.0 | ) |
| Rate of return on plan assets | | | (0.5 | ) | | N/A | | | (2.6 | ) | | 2.6 | |
| Rate of return on plan assets | | | 0.5 | | | N/A | | | 2.6 | | | (2.6 | ) |
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.
Actuarial Assumption (Millions, except percentages) | | Percent Change in Assumption | | Impact on Postretirement Benefit Obligation | | Impact on Postretirement Benefit Liability | | Impact on Postretirement Benefit Cost | |
| Discount rate | | | (0.5 | ) | $ | 20.6 | | $ | (2.2 | ) | $ | 2.2 | |
| Discount rate | | | 0.5 | | | (18.2 | ) | | 1.9 | | | (1.9 | ) |
| Health care cost trend rate | | | (1.0 | ) | | (33.0 | ) | | 5.4 | | | (5.4 | ) |
| Health care cost trend rate | | | 1.0 | | | 37.0 | | | (6.0 | ) | | 6.0 | |
| Rate of return on plan assets | | | (0.5 | ) | | N/A | | | (0.7 | ) | | 0.7 | |
| Rate of return on plan assets | | | 0.5 | | | N/A | | | 0.7 | | | (0.7 | ) |
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.
