Integrys Holding (TEG) 8-K Other Events

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, 2004 of WPS Resources. All other sections of Item 7 are unchanged.

ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
                CONDITION AND RESULTS OF OPERATION

INTRODUCTION - WPS RESOURCES 

WPS Resources is a holding company that is exempt from the Public Utility Holding Company Act of 1935. Our wholly owned subsidiaries include two regulated utilities, WPSC (which is an operating entity as well as a holding company exempt from the Public Utility Holding Company Act of 1935) and UPPCO. Another wholly owned subsidiary, WPS Resources Capital Corporation, is a holding company for our nonregulated businesses, including ESI and PDI.

Our regulated and nonregulated businesses have distinct competencies and business strategies, offer differing 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, and asset management) and the continued emphasis on reliable, competitively priced, and environmentally sound energy services for our customers. We are seeking a balanced portfolio of utility and nonregulated growth, but we are placing emphasis on regulated growth.A discussion of the essential components of our business plan is set forth below:

Maintain a Strong Utility Base - As discussed above, we are focusing on growth in our utility operations. A strong utility base is important in order to maintain quality credit ratings, which are critical to our success. In 2004, WPSC signed contracts with several wholesale customers in order to bolster growth beyond our normal utility growth rate, and WPSC is also expanding its generation fleet in order to meet growing electric demand and ensure the continued reliability of our energy services.

• WPSC entered into long-term power sale agreements with two wholesale customers in 2004. One is for Consolidated Water Power Company's full requirements service (between 65 and 125 megawatts of firm load) through December 31, 2017. The other is a 50-megawatt agreement with Wisconsin Public Power Inc. beginning May 1, 2006, and ending April 30, 2021.
• In October 2004, WPSC began construction of its 500-megawatt coal-fired Weston 4 base-load power plant near Wausau, Wisconsin, and announced in May 2004 that it would pursue plans to build a jointly owned 500-megawatt base-load electric plant with Wisconsin Power and Light. The Weston 4 power plant is expected to be operational in 2008.
• Calpine Corporation's 560-megawatt, combined cycle, natural gas-fired generating facility (Fox Energy Center) in Kaukauna, Wisconsin, is expected to be placed in service in June 2005. WPSC has contracted for approximately 470 megawatts of this plant's output over a 10-year period. WPSC also contracted to purchase 70 megawatts of wind generation over a 20-year period from the Forward Energy Wind Project in Brownsville, Wisconsin. Both of these agreements were signed as a means of seeking the most cost effective mix of energy resources to meet growing electric demand.

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Integrate Resources to Provide Operational Excellence - - WPS Resources is committed to integrating the resources of its business units (in accordance with any applicable regulatory restrictions) by leveraging their individual capabilities and expertise across the company.

• Effective August 2004, in an effort to better manage the market risks associated with PDI's merchant generation plants, we restructured the management of our two nonregulated business units (ESI and PDI) and currently have one executive management team overseeing the operations of these two business units.
• In January 2004, ESI implemented strategies to optimize the value of PDI's merchant generation fleet and has reduced the market price risk while extracting additional value from these plants, through the use of various financial and physical instruments (such as forward contracts, options, and swaps). Prior to leveraging ESI's energy marketing expertise, PDI sold uncontracted energy into liquid financial markets at spot prices or day ahead prices, which provided less predictable revenue and margin.

Strategically Grow Nonregulated Businesses - - ESI looks to grow its electric and natural gas business, targeting growth in the northeastern United States and adjacent portions of Canada (through strategic acquisitions, market penetration of existing businesses, and new product offerings), which is where ESI has the most market expertise. As discussed above, our utilities are our core businesses and as such we are placing a strong emphasis on growth of utility operations in order to balance our regulated and nonregulated growth. PDI focuses on optimizing the operational efficiency of its existing portfolio of assets and pursues compatible power development projects and the acquisition of generation assets that "fit" in well with ESI's customer base and market expertise.

• In July 2004, ESI completed the acquisition of Advantage Energy, a privately held nonregulated electric power marketer based in Buffalo, New York. This acquisition provides ESI with enhanced opportunities to participate in the New York market, where we believe there is good opportunity for further penetration and the sale of new products.
• ESI continues to grow its business in the energy management sector by providing customers the expertise needed to manage their energy needs in volatile energy markets.

Place Strong Emphasis on Asset Management - - Our asset management strategy calls for the continuing disposition and acquisition of assets in a manner that enhances our earnings capability. The acquisition portion of this strategy calls for the acquisition of assets that compliment our existing assets and strategy such as Advantage Energy. Another portion of the asset management strategy calls for the disposition of assets, including plants and entire business units, which are no longer required for operations.

• We continue to pursue the sale of Sunbury and expect to have a completed sale in 2005. The sale of Sunbury fits well within our asset management strategy. Included in this strategy is the desire to reduce risk associated with uncontracted merchant exposure. For an update on the sale of Sunbury, see Note 4, "Assets Held for Sale," to WPS Resources' Notes to Consolidated Financial Statements.
• We continue to pursue the sale of Kewaunee to a subsidiary of Dominion Resources.
• Our Peshtigo River land sale initiative (which included land sales and donations to the WDNR and the sale of land at public auction) was completed in 2004. We continue to identify alternatives for the sale of the balance of our identified excess real-estate holdings.

Regulated Utilities

Our regulated utilities include WPSC and UPPCO. WPSC derives its revenues primarily from the 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 

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adjacent portion of the Upper Peninsula of Michigan. The PSCW and the MPSC regulate these retail sales. WPSC also provides wholesale electric service to numerous utilities and cooperatives for resale. FERC regulates wholesale sales. UPPCO derives revenues from the sale of electric energy in a service area of approximately 4,500 square miles in the Upper Peninsula of Michigan and is regulated by the MPSC.

The regulatory commissions allow the utilities to earn a return on common stock equity that is commensurate with an investor's desired return, compensating for the risks investors face when providing funds to the utility. The return on common stock equity approved by the PSCW, FERC, and the MPSC was 12.0%, 11.0%, and 11.4%, respectively, in 2004. Generally, consumers bear the price risk for fuel and purchased power costs as regulators allow the utility to recover substantially all of these costs (to the extent they are prudently incurred), through various cost recovery mechanisms, but utilities bear volume risk as rates are based upon normal sales volumes as projected by the utility. The utilities may also be able to defer certain unexpected costs that are incurred during the year for recovery in future rate proceedings (examples include WPSC's deferral of costs associated with the extended Kewaunee outage in 2004 and deferral of costs incurred by UPPCO related to the Dead River flood); however, these costs must be prudently incurred as determined by the regulatory commissions. As such, the ability of our regulated utilities to earn their approved return on equity is dependent upon accurate forecasting techniques, their 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. Unfavorable weather conditions compared to normal for both electric and natural gas utility operations and increased operating expenses contributed to WPSC's inability to earn its approved rate of return in 2004.

Uncertainties related to the deregulation process are a risk for our regulated utilities. Deregulation of natural gas service has begun in Wisconsin. Currently, the largest natural gas customers can purchase 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. We believe electric deregulation inside Wisconsin is at least several years off as the state is focused on improving reliability by building more generation and transmission facilities and creating fair market rules. If electric choice occurs, we believe we could lose some generation load but would retain the delivery revenues and margin. Also, the capacity that would be freed up should be competitive in our marketplace. Deregulation of electricity is present in Michigan; however, in the Upper Peninsula of Michigan, no customers have chosen an alternative electric supplier and no alternative electric suppliers have offered to serve any customers in Michigan's Upper Peninsula due to the lack of excess transmission and generation system capacity in the areas we serve, which is a barrier to competitive suppliers entering the market.

The utilities are also exposed to costs associated with increasingly stringent environmental rules and regulations to the extent recovery of these costs is disallowed in rate proceedings. WPSC and UPPCO are also members of the Midwest Independent System Operator, which is in the process of restructuring the electric market in its footprint. For further discussion of environmental risks, see Note 17 to WPS Resources' Notes to Consolidated Financial Statements and for further discussion of the Midwest Independent System Operator, see Trends - WPS Resources.

WPS Energy Services 

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. Although ESI has a widening array of products and services, revenues are primarily derived through sales of electricity and natural gas to retail and wholesale customers.

ESI's marketing and trading operations manage power and natural gas procurement as an integrated portfolio with its retail and wholesale sales commitments. ESI strives to maintain a low risk portfolio with relatively few open positions, balancing natural gas and electricity purchase commitments with 

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corresponding sales commitments. In 2004, ESI purchased electricity required to fulfill these sales commitments primarily from independent generators, energy marketers, and organized electric power markets and 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.

The table below discloses future natural gas and electric sales volumes under contract as of December 31, 2004. Contracts are generally one to three years in duration. ESI expects that its ultimate sales volumes in 2005 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 12/31/2004(1)	2005	2006 to 2008	2009 to 2010
Wholesale sales volumes - billion cubic feet	98.1	10.2	-
Retail sales volumes - billion cubic feet	184.8	39.6	2.0
Total natural gas sales volumes	282.9	49.8	2.0
Wholesale sales volumes - million kilowatt-hours	5,981	1,665	-
Retail sales volumes - million kilowatt-hours	3,413	1,575	73
Total electric sales volumes	9,394	3,240	73

(1) These tables represent physical sales contracts for natural gas and electric power for delivery or settlement in future periods. 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, 2003 are shown below. Actual electric and natural gas sales volumes for 2004 are disclosed within Results of Operations - WPS Resources, ESI Segment Operations.

Forward Contracted Volumes at 12/31/2003(1)	2004	2005 to 2007	2008 to 2009
Wholesale sales volumes - billion cubic feet	95.8	15.1	-
Retail sales volumes - billion cubic feet	173.4	63.2	-
Total natural gas sales volumes	269.2	78.3	-
Wholesale sales volumes - million kilowatt-hours	3,176	238	-
Retail sales volumes - million kilowatt-hours	5,133	3,623	37
Total electric sales volumes	8,309	3,861	37

(1) These tables represent physical sales contracts for natural gas and electric power for delivery or settlement in future periods. Management has no reason to believe that gross margins that will be generated by these contracts will vary significantly from those experienced historically.

ESI has experienced steady increases in electric and natural gas sales volumes since its inception, and expects this trend to continue as it 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 and through portfolio optimization strategies utilized to maximize the value of PDI's merchant generation fleet and ESI's retail supply portfolio. Natural gas volumes increased as a result of the continued expansion of ESI's retail natural gas business in Canada. ESI expects to continue to target acquisitions and participate in generation service programs within the area it serves.

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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, we believe we have reduced our 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 of loss from less than flawless 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 computational infrastructure, business process improvement, employee training, and internal controls has helped mitigate operational risk to date. Liquidity risk is an emerging risk and one 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 protect its credit ratings, and ESI believes it would have adequate capital to continue core operations unless WPS Resources' credit ratings fell 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 has implemented stringent 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 counterparties were $0.7 million, or 0.0%, in 2004, compared to $3.1 million, or 0.2%, in 2003. ESI believes its write-off percentage is within the range experienced by most energy companies. The table below summarizes wholesale counterparty credit exposure, categorized by maturity date, as of December 31, 2004 (in millions):

Counterparty Rating (Millions)(1)	Exposure(2)	Exposure Less Than  1 Year	Exposure  1 to 3  Years	Net Exposure of Counterparties Greater Than  10% of Net Exposure
Investment grade -- regulated utility	$ 18.8	$ 13.7	$ 5.1	$ -
Investment grade -- other	86.6	79.1	7.5
Non-investment grade -- regulated utility	-	-	-	-
Non-investment grade -- other	4.0	4.0	-	-
Non-rated -- regulated utility	-	-	-	-
Non-rated -- other	36.3	28.2	8.1	-
Total Exposure	$145.7	$125.0	$20.7	$ -

(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 $11.7 million at December 31, 2004, $3.2 million from non-investment grade counterparties and $8.5 million from non-rated counterparties.

A risk that became more prevalent in 2004 is industry restructuring. There is some concern over the status of the nonregulated energy market in Michigan and Ohio, which are two states in which ESI operates. ESI is also a member of the Midwest Independent System Operator, which is in the process of 

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restructuring the electric power market in its footprint. For more information on these risks, see Trends - WPS Resources.

WPS Power Development 

PDI competes in the wholesale merchant electric power generation industry, primarily in the midwest and northeastern United States and adjacent portions of Canada. PDI's core competencies include power plant operation and maintenance and material condition assessment of assets. In order to enable PDI to focus on its core competencies and improve the efficiency and reliability of its existing fleet of power plants, ESI has assumed much of the market price risk associated with these plants. Through several tolling agreements and power purchase agreements, ESI has contracted for approximately 330 of PDI's 830 megawatts of total capacity. ESI utilizes power from PDI's New England and Canadian assets primarily to serve its firm load commitments in northern Maine and certain other sale agreements with customers. For the remaining capacity contracted from PDI, ESI utilizes financial tools, including forwards, options, and swaps to limit exposure, as well as to extract additional value from PDI's merchant generation fleet. These activities had a positive impact on ESI's margin in 2004 and benefited PDI by providing more stable revenue streams.

PDI has power purchase agreements in place with third-party customers for the 95 megawatts of capacity that is not contracted to ESI, which includes its Stoneman facility in Cassville, Wisconsin, and its Combined Locks facility in Combined Locks, Wisconsin.

Oversupply of capacity, low spark spreads (spark spread is the difference between the market price of electricity and its cost of production), and high fuel costs have led to lower than anticipated results for PDI's merchant generation business in recent years. In response to these market conditions, PDI has taken steps to adjust to the current wholesale merchant environment. As discussed above, beginning in January 2004, ESI began assuming much of the market price risk for PDI's merchant generation fleet. Prior to the capacity and power contracts with ESI, risk management activities (i.e., hedging activities) were sparsely utilized, leaving PDI's generation fleet more exposed to market price risk. PDI also continues to pursue the sale of Sunbury and anticipates that the plant will be sold in 2005. The objectives of the Sunbury sale are to allow PDI to reduce its uncontracted merchant exposure and enable WPS Resources to redeploy capital into business opportunities with different risk profiles. See Note 4, "Assets Held for Sale," to WPS Resources' Notes to Consolidated Financial Statements for an update on the Sunbury sale.

PDI, through its subsidiary ECO Coal Pelletization #12 LLC, also owns an interest in a synthetic fuel producing facility. See Trends - WPS Resources, Synthetic Fuel Operation for more information on the risks related to PDI's investment in this synthetic fuel operation.

PDI 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 to WPS Resources' Notes to Consolidated Financial Statements for more information on PDI's environmental exposure.

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RESULTS OF OPERATIONS - WPS RESOURCES

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	$4,950.8	$4,402.5	12.5%
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 $548.3 million increase in consolidated operating revenue for the year ended December 31, 2004, compared to the same period in 2003, was largely driven by a $475.3 million, or 15.4%, increase in revenue at ESI and an $82.5 million, or 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 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. 

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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

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 at WPSC. 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, or 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, or 3.5%.
• Effective May 11, 2003, FERC approved a $4.1 million, or 21%, interim increase in wholesale electric rates.
• Effective July 22, 2003, the MPSC approved a $0.3 million, or 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, or 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, or 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, or 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 

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costs were 17.4% higher (on a per-unit basis) in 2004, compared to 2003. The PSCW allows WPSC to adjust prospectively the amount billed to Wisconsin retail customers for fuel and purchased power if costs are 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 is anticipated that these costs will be recovered in 2006, pending final approval.

Electric utility earnings increased $8.8 million, or 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, or 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, or 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, or 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, or 10.2% increase in natural gas utility earnings for the year ended December 31, 2004.

Overview of Nonregulated Operations

Nonregulated operations consist of natural gas, electric, and other sales at ESI, a diversified energy supply and services company, and the operations of PDI, an electric generation company. ESI and PDI are both reportable segments.

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Income available for common shareholders attributable to ESI was $36.7 million for the year ended December 31, 2004, compared to $29.0 million for the same period in 2003. Higher overall margins were offset by an increase in operating expenses and a $3.3 million after-tax cumulative effect of change in accounting principles that was recorded at ESI in 2003.

PDI reported income available for common shareholders of $5.0 million for the year ended December 31, 2004, compared to a $7.9 million net loss for the year ended December 31, 2003, largely due to an increase in the amount of tax credits recognized and a $4.4 million termination payment received from Duquesne Power in December 2004, as a result of Duquesne's termination of the asset sale agreement with Sunbury, partially offset by higher operating and maintenance expenses and a lower overall margin.

ESI's Segment Operations

Total segment revenues at ESI were $3,556.9 million for the year ended December 31, 2004, compared to $3,081.6 million for the year ended December 31, 2003. The total margin at ESI was $112.2 million for the year ended December 31, 2004 compared to $87.2 million for the year ended December 31, 2003. ESI's nonregulated natural gas and electric operations are the primary contributors to revenues and margins and are discussed below.

ESI's Natural Gas Results (Millions except sales volumes)	2004	2003	Change
Nonregulated natural gas revenues	$3,035.1	$2,696.6	12.6%
Nonregulated natural gas cost of sales	2,978.5	2,652.5	12.3%
Margins	$ 56.6	$ 44.1	28.3%
Wholesale sales volumes in billion cubic feet *	236.3	252.4	(6.4%)
Retail sales volumes in billion cubic feet *	276.7	240.6	15.0%

* Represents gross physical volumes

Natural gas revenue increased $338.5 million, driven by higher natural gas prices and the expansion of the Canadian retail natural gas business (due to 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).

The natural gas margin at ESI increased $12.5 million, or 28.3%, 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. The increase in the Canadian wholesale natural gas margin is related to higher volumes (more structured wholesale transactions) as ESI continues to increase its wholesale natural gas operations in this region.

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 

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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, 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 risk management liability), related to the 2004/2005 natural gas storage cycle. At December 31, 2003, there was a $2.6 million difference (net risk management liability) related to the 2003/2004 natural gas storage cycle. The 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 when all of the natural gas is withdrawn from storage.

ESI's Electric Results (Millions)	2004	2003	Change
Nonregulated electric revenues	$519.5	$382.6	35.8%
Nonregulated electric cost of sales	466.1	341.8	36.4%
Margins	$ 53.4	$ 40.8	30.9%
Wholesale sales volumes in kilowatt-hours *	3,181.5	2,768.0	14.9%
Retail sales volumes in kilowatt-hours *	7,202.9	6,435.3	11.9%

* Represents gross physical volumes

Electric revenue increased $136.9 million, largely due to an $83.7 million increase resulting from higher volumes from portfolio optimization strategies. In the first quarter of 2004, ESI first implemented the portfolio optimization strategies to optimize the value of PDI's merchant generation fleet and its own retail supply portfolios to reduce market price risk and extract additional value from these assets through the use of various financial and physical instruments (such as forward contracts and options). Electric revenue also increased as a result of the July 1, 2004, acquisition of Advantage Energy and higher energy prices compared to the prior year. These increases were partially offset by lower sales volumes from participation in the New Jersey Basic Generation Services Program, as ESI's participation in this program ended in May 2004.

ESI's electric margin increased $12.6 million, or 30.9%, for the year ended December 31, 2004, compared to 2003. The 2004 retail electric margin increased $7.8 million compared to 2003. The margin related to retail electric operations in Ohio increased $7.6 million, which can be attributed to better management of retail operations and improved supply procurement. Also contributing to the increase in retail electric margin was a $2.6 million favorable settlement of a counterparty pricing dispute and positive operating results from Advantage Energy. The increase in the retail electric margin was partially offset by a decrease in margin from retail electric operations in Maine. The lower margin in Maine was anticipated due to the sales price and supply cost associated with the new provider of last resort in northern Maine (which became effective in March 2004). The margin from retail electric operations in Michigan also decreased, driven by higher wholesale electricity prices, higher transmission related charges, and an increase in competition. The margin attributed to wholesale electric operations increased $4.8 million. The higher wholesale electric margin was driven by a $10.3 million increase from the portfolio optimization strategies discussed above. This increase was partially offset by a $5.7 million decrease in margin from ESI's participation in the New Jersey Basic Generation Services Program, which began in August 2003 and ended in May 2004. Under the program, ESI realized greater margins in 2003, compared to 2004.

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PDI's Segment Operations

PDI's Production Results (Millions)	2004	2003	Change
Nonregulated other revenues	$131.0	$164.2	(20.2%)
Nonregulated other cost of sales	104.2	125.5	(17.0%)
Margins	$26.8	$38.7	(30.7%)

PDI's revenue decreased $33.2 million, or 20.2%, for the year ended December 31, 2004, compared to 2003, largely due to lower revenue from its Sunbury generation facility in Pennsylvania, reduced generation from its Beaver Falls facility in New York, lower revenue from its Combined Locks Energy Center in Wisconsin, lower revenue from its steam boiler in Oregon, and lower revenue from its Wyman generation facility in Maine. The decrease in revenue at Sunbury was driven by fewer opportunities to sell power into the spot market. The Beaver Falls facility experienced an unplanned plant outage that began in October 2003, with the facility returning to service in April 2004. This facility continued to experience lower volumes after returning to service as PDI has been more conservative in the dispatch of this unit to preserve the limited remaining service life of the turbine blades for higher margin opportunities. The decrease in revenue at the Combined Locks Energy Center was driven by lower demand for energy by the counterparty to a power purchase agreement in place at this facility and an unplanned plant outage that began in March 2004, and continued through May 2004. The decrease in revenue from the steam boiler in Oregon was largely due to a 30-day planned outage to perform repairs on the boiler, which took place in the second quarter of 2004. A power purchase agreement in place at the Wyman facility in 2003 was not renewed in 2004. As a result, energy from the Wyman facility was sold into short-term power markets in 2004, but unfavorable energy prices and lack of demand for capacity resulted in a decline in the amount of power generated at this facility in 2004, compared to 2003. The decline in revenue was partially offset by higher sales volumes at the Stoneman generation facility in Cassville, Wisconsin, related to a new power purchase agreement in place at this facility. 

PDI's margin for the year ended December 31, 2004, decreased $11.9 million, or 30.7%, compared to 2003. The Sunbury, Niagara, Beaver Falls, and Wyman generating facilities experienced a combined $15.3 million decrease in margin. The lower margins at the Sunbury and Niagara generating facilities were largely due to an increase in the per ton cost of coal utilized in the generation process. Sunbury's margin was also negatively impacted by fewer opportunities to sell power into the spot market in 2004, compared to 2003. The unplanned plant outage experienced at the Beaver Falls facility and lower volumes related to PDI's decision to only dispatch the facility at times when energy prices are at a very favorable level, drove the decrease in margin at this facility. Unfavorable energy prices and lack of demand for capacity negatively impacted sales volumes at the Wyman generation facility (there was a power purchase agreement in place at this facility in 2003). These decreases were partially offset by a combined $2.9 million increase in margins at the Combined Locks Energy Center and the Stoneman generation facility. The higher margin at the Combined Locks Energy Center was driven by a negotiated increase in the dispatch flexibility of steam sold under a supply agreement with a counterparty, resulting in an increase in the value of electricity produced from this facility. The increase in margin at the Stoneman generation facility was due to higher sales volumes.

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Overview of Holding Company and Other Segment Operations

Holding Company and Other operations include the operations of WPS Resources and WPS Resources Capital as holding companies and the nonutility activities at WPSC and UPPCO. 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 Wisconsin land located along the Peshtigo River 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	$537.6	$486.2	10.6%
Depreciation and decommissioning expense	107.0	141.3	(24.3%)
Taxes other than income	46.1	44.3	4.1%

Operating and Maintenance Expense

Operating and maintenance expenses increased $51.4 million, or 10.6%, for the year ended December 31, 2004, compared to 2003. Utility operating and maintenance expenses increased $36.3 million. Electric transmission and distribution costs were up $15.2 million at the utilities due primarily 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 and collection is anticipated in 2006). Operating expenses at ESI increased $10.5 million mostly due to higher payroll, benefits, and other costs associated with continued business expansion. Operating and maintenance expenses at PDI decreased $0.8 million, primarily due to higher repair and maintenance expenses in 2003 due to mechanical difficulties related to fuel delivery systems at Sunbury. The decrease in repairs and maintenance at Sunbury was partially offset by higher operating and maintenance expenses as a result of repairs and maintenance expenses incurred in conjunction with outages at its Beaver Falls generation facility, the Combined Locks Energy Center, and the Westwood Generation Station.

Depreciation and Decommissioning Expense

Depreciation and decommissioning expense decreased $34.3 million, or 24.3%, for the year ended December 31, 2004, compared to 2003, due primarily to a decrease of $35.9 million resulting from lower realized gains on decommissioning trust assets and because the decommissioning trust was not funded in 2004 in anticipation of selling Kewaunee. Realized gains on decommissioning trust assets are substantially offset by depreciation expense pursuant to regulatory practice (see detailed discussion in "Miscellaneous Income" below). An increase in depreciation expense from plant asset additions at WPSC partially offset the decrease in decommissioning expense.

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Other Income (Expense)

WPS Resources' Other Income (Expense) (Millions)	2004	2003	Change
Miscellaneous income	$52.0	$63.6	(18.2%)
Interest expense and distributions of preferred securities	(59.9)	(61.8)	(3.1%)
Minority interest	3.4	5.6	(39.3%)
Other (expense) income	$ (4.5)	$ 7.4	-

Miscellaneous Income

Miscellaneous income decreased $11.6 million, or 18.2%, for the year ended December 31, 2004, compared to 2003. The decrease in miscellaneous income is largely due to a decrease in realized gains on decommissioning trust assets of $33.5 million. There were significant realized gains recognized on decommissioning trust assets in the fourth quarter of 2003, which were driven by a change in the investment strategy for WPSC's qualified nuclear decommissioning trust assets. Qualified decommissioning trust assets were placed in more conservative investments in anticipation of the sale of Kewaunee. Pursuant to regulatory practice, realized gains on decommissioning trust assets are substantially offset by depreciation expense. A $1.5 million write-off of previously deferred financing costs associated with the redemption of our trust preferred securities in the first quarter of 2004 also unfavorably impacted miscellaneous income. Partially offsetting the decreases discussed above were an $8.7 million increase in equity earnings from investments, a $7.1 million increase in income recognized from the sale of Wisconsin land located along the Peshtigo River (discussed previously), a $4.4 million termination payment received from Duquesne Power in December 2004 as a result of Duquesne's termination of the asset sale agreement for Sunbury, and a combined $3.1 million increase related to higher royalties and a decrease in operating losses realized from our 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 PDI's partner in its subsidiary, ECO Coal Pellitization #12 LLC, was allocated more production from the synthetic fuel operation in 2003 compared to 2004. PDI's partner was not allocated any production from the synthetic fuel facility in the first quarter of 2004 as they requested additional production in the fourth quarter of 2003.

Provision for Income Taxes

The effective tax rate was 13.2% for the year ended December 31, 2004, compared to 22.2% for the year ended December 31, 2003. The decrease in the effective tax rate was driven by tax deductions pertaining to items that exceed the related book expense (including land donated to the WDNR in the fourth quarter of 2004), resulting in a $5.7 million decrease in the 2004 provision for income taxes compared to 2003, and a $9.6 million increase in the amount of tax credits recognized in 2004 (related to an increase in synthetic fuel tax credits produced in 2004 and the favorable settlement of several federal 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 PDI, 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.

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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 PDI 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.

2003 Compared with 2002

WPS Resources Overview

WPS Resources' 2003 and 2002 results of operations are shown in the following table:

WPS Resources' Results (Millions, except share amounts)	2003	2002	Change
Consolidated operating revenues	$4,402.5	$1,548.3	184%
Income available for common shareholders	$94.7	$109.4	(13%)
Basic earnings per share	$2.87	$3.45	(17%)
Diluted earnings per share	$2.85	$3.42	(17%)

Total revenues increased significantly due to the required reclassification of previously reported 2002 revenues and cost of sales (see ESI's Segment Operations below for further information). Total revenues also increased due to sales volume growth at ESI, electric utility rate increases, and higher natural gas prices.

Income available for common shareholders was $94.7 million ($2.87 basic earnings per share) for the year ended December 31, 2003, compared to $109.4 million ($3.45 basic earnings per share) for the year ended December 31, 2002. Significant factors impacting the change in earnings and earnings per share are as follows (and are discussed in more detail below):

• Approved rate increases and a change in electric utility sales mix favorably impacted margins at the utilities.
  
• Cooler weather during the cooling season in 2003 negatively impacted electric utility margins.
  
• Colder weather during the heating season in 2003 positively impacted natural gas throughput volumes.
  
• Rising operating expenses (primarily pension and medical costs), together with a delay in receiving 2003 retail electric rate relief, negatively impacted electric utility earnings.
  
• ESI's November 2002 acquisition of a retail natural gas business in Canada and favorable settlements with several counterparties drove an increased year-over-year retail natural gas margin.
  

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• ESI's electric margin improved as a result of acquisition synergies, improved management of retail operations in Michigan, and participation in the New Jersey Basic Generation Service Program.
  
• PDI's earnings were significantly lower in 2003, primarily as a result of an $18.2 million decrease in after-tax gains recognized from sales of portions of its interest in a synthetic fuel operation, lower margins, and a $5.1 million reduction in tax credits recognized from the synthetic fuel operation.
  
• Consolidated operating expenses increased in 2003.
  
• Also impacting basic earnings per share was an increase of 1.3 million in the weighted average number of outstanding shares of WPS Resources' common stock in 2003 compared to 2002. The increase was largely due to issuing 4,025,000 additional shares through a public offering in November 2003. Additional shares were also issued in 2003 under the Stock Investment Plan.

Overview of Utility Operations

Income available for common shareholders attributable to the electric utility segment was $60.0 million in 2003 compared to $61.0 million in 2002. Income available for common shareholders attributable to the gas utility segment was $15.7 million in 2003 compared to $18.4 million in 2002.

Electric Utility Segment Operations

WPS Resources' Electric Utility Segment Results (Millions)	2003	2002	Change
Revenues	$814.1	$763.1	7%
Fuel and purchased power costs	266.3	242.7	10%
Margins	$547.8	$520.4	5%
Sales in kilowatt-hours	14,346.7	14,547.6	(1%)

Electric utility segment revenues increased $51.0 million, or 7%, for the year ended December 31, 2003, compared to the year ended December 31, 2002. The increase was largely due to retail and wholesale electric rate increases for our Wisconsin and Michigan customers in accordance with new rate orders.

The electric utility margin increased $27.4 million, or 5%, in 2003 compared to 2002. Due primarily to the electric rate increases, electric margins at WPSC increased $20.2 million, or 4%. Electric margins at WPSC were also impacted favorably by a change in sales mix in 2003. While total sales volumes remained basically unchanged in 2003 compared to 2002, sales volumes to higher margin residential, and commercial and industrial customers increased slightly. The increase in sales volumes to these higher margin customer classes reflects growth within WPSC's service area and changes in the economy. These increases were partially offset by cooler weather during the cooling season for the year ended December 31, 2003, compared to the year ended December 31, 2002. Electric margins at UPPCO increased $7.2 million, or 17%, due primarily to retail electric rate increases, partially offset by a 3% decrease in sales volumes. The decrease in sales volumes was attributed to less favorable weather conditions for the year ended December 31, 2003, compared to the year ended December 31, 2002, and customer conservation of electricity made necessary due to a flood that occurred earlier in 2003.

Although the electric utility margin increased, electric utility segment earnings for the year ended December 31, 2003, decreased $1.0 million compared to the year ended December 31, 2002. The primary reason for the decrease in electric utility segment earnings was due to a decrease in earnings at WPSC attributed to a delay in receiving 2003 retail electric rate relief, together with rising operating 

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expenses (primarily pension and medical costs). Rate relief for our increasing operating costs was expected on January 1, 2003; however, the increase in retail electric rates granted by the PSCW was not effective until March 21, 2003. The delay in receiving rate relief was a significant factor in our inability to achieve our authorized 12% return on equity in 2003. The decrease in earnings experienced by WPSC was partially offset by a modest increase in earnings at UPPCO due to the increase in rates.

Gas Utility Segment Operations

WPS Resources' Gas Utility Segment Results (Millions)	2003	2002	Change
Revenues	$404.2	$310.7	30%
Purchased gas costs	291.0	198.6	47%
Margins	$113.2	$112.1	1%
Throughput in therms	854.5	845.4	1%

Gas utility segment revenues increased $93.5 million, or 30%, for the year ended December 31, 2003, compared to the year ended December 31, 2002. The increase in gas utility revenues is mostly due to a 39% increase in the average cost of natural gas for the year ended December 31, 2003, compared to the prior year, partially offset by the 0.3% decrease in retail natural gas rates ordered by the PSCW, effective March 21, 2003.

The natural gas utility margin for the year ended December 31, 2003, increased $1.1 million, or 1%, compared to the year ended December 31, 2002. The increase in the natural gas utility margin can be attributed to a 1% increase in natural gas throughput volumes in 2003 compared to 2002. Natural gas throughput volumes to our higher margin residential and commercial and industrial customers increased 6% in the aggregate, mostly as a result of colder weather in 2003 compared to 2002. Natural gas throughput volumes to our lower margin transport customers decreased 5% due to the rising price of natural gas together with their ability to use alternate fuel sources.

Despite the modest increase in gas utility margins, gas utility earnings for the year ended December 31, 2003, decreased $2.7 million compared to 2002. The decline is primarily due to rising operating expenses (primarily pension and medical costs) together with the decrease in natural gas rates mentioned above.

Overview of Nonregulated Operations

ESI's income available for common shareholders increased to $29.0 million in 2003 compared with $11.0 million in 2002, primarily as a result of increased electric and natural gas margins discussed below. 

PDI recognized a net loss of $7.9 million in 2003 compared to income available for common shareholders of $24.0 million in 2002. PDI's earnings were negatively impacted by a decrease in gains recognized from the sale of portions of its interest in a synthetic fuel operation, lower margins, and a decrease in the amount of tax credits recognized.

ESI's Segment Operations

Total segment revenues at ESI were $3,081.6 million in 2003 compared to $362.8 million in 2002. The total margin at ESI was $87.2 million in 2003 compared to $50.0 million in 2002. ESI's nonregulated natural gas and electric operations are the primary contributors to revenues and margins and are discussed below.

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ESI's Natural Gas Results (Millions except sales volumes)	2003	2002	Change
Nonregulated natural gas revenues	$2,696.6	$245.1	1,000%
Nonregulated natural gas cost of sales	2,652.5	210.2	1,162%
Margins	$ 44.1	$ 34.9	26%
Wholesale sales volumes in billion cubic feet *	252.4	233.8	8%
Retail sales volumes in billion cubic feet *	240.6	135.7	77%

* Represents gross physical volumes

ESI's nonregulated natural gas revenues increased $2,451.5 million for the year ended December 31, 2003, compared to the prior year. Approximately $997 million of the increase related to the required adoption of Issue No. 02-03, effective January 1, 2003 (see Trends - WPS Resources for more information about this accounting change). Volume growth driven by the acquisition of a retail natural gas business in Canada accounted for approximately $500 million of the increase in revenues in 2003. Most of the remaining increase was attributed to higher natural gas prices compared to the prior year.

Natural gas margins at ESI increased $9.2 million, or 26%, in 2003 compared to 2002. Approximately $6 million of the increase related to the November 1, 2002, acquisition of a retail natural gas business in Canada. The remaining increase related to favorable settlements of pending liabilities with several counterparties, partially offset by the change in accounting prescribed by the required adoption of Issue 02-03. See Cumulative Effect of Change in Accounting Principles below for further discussion.

ESI's Electric Results (Millions)	2003	2002	Change
Nonregulated electric revenues	$382.6	$115.3	232%
Nonregulated electric cost of sales	341.8	102.6	233%
Margins	$ 40.8	$ 12.7	221%
Wholesale sales volumes in kilowatt-hours *	2,768.0	4,250.0	(35%)
Retail sales volumes in kilowatt-hours *	6,435.3	2,703.6	138%

* Represents gross physical volumes

ESI's nonregulated electric revenues increased $267.3 million for the year ended December 31, 2003, compared to the prior year. Approximately $130 million of the increase related to the required adoption of Issue 02-03. Another $88 million of the increase was attributed to participation in the New Jersey Basic Generation Services Program. ESI acquired 700 megawatts of fixed price load and 250 megawatts of variable priced load for the period from August 1, 2003, to May 31, 2004, as a result of its participation in this program. The remaining increase in nonregulated electric revenues was attributed to increased prices and expansion within existing service territories. ESI also acquired retail electric operations in Michigan in 2003. Prior to the acquisition, this operation was an electric wholesale customer of ESI; therefore, the acquisition did not have a significant impact on total revenues in 2003 compared to 2002. The acquisition did, however, account for most of the increase in retail sales volumes and related decrease in wholesale sales volumes in 2003 compared to 2002.

ESI's electric margin increased $28.1 million, or 221%, in 2003 compared to 2002. Approximately $26 million of the increase was due to acquisition synergies and improved management of retail operations in Michigan and participation in the New Jersey Basic Generation Service Program. The remaining increase in ESI's electric margins was largely due to the impact of the change in accounting prescribed by the required adoption of Issue 02-03, which precluded mark-to-market accounting for nonderivative trading contracts.

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PDI's Segment Operations

PDI's Production Results (Millions)	2003	2002	Change
Nonregulated other revenues	$164.2	$146.0	12%
Nonregulated other cost of sales	125.5	93.7	34%
Margins	$38.7	$52.3	(26)%

PDI's revenues increased $18.2 million, or 12%, in 2003 compared to 2002. PDI's margin decreased $13.6 million, or 26%, in 2003 compared to 2002. The increase in revenues was primarily the result of increased generation from generating assets acquired in New York on June 1, 2002, revenues from the Combined Locks Energy Center that became fully operational in the second quarter of 2002, and an increase in generation at the hydroelectric plants in Maine and Canada as a result of increased rainfall, higher capacity revenues, and increased pricing on a renegotiated outtake contract. The decrease in margin was largely due to a decrease in capacity sales at Sunbury in 2003 due to the expiration of a sales contract and an increase in variable production expenses related to higher emission costs. Operations at PDI's Stoneman generating facility in Cassville, Wisconsin also contributed to the lower margin as a result of the expiration of an energy and capacity outtake contract that was not renewed.

Overview of Holding Company and Other Segment Operations

Holding Company and Other operations experienced a net loss of $2.1 million in 2003 compared to a net loss of $5.0 million in 2002. The decrease in the net loss experienced was largely related to an increase in gains recognized on hydroelectric land sales in 2003 compared to 2002 (recorded as a component of miscellaneous income), primarily due to a $6.2 million pre-tax gain recognized in 2003 from land sales to the WDNR. The sale of these hydroelectric lands was part of our asset management strategy, which was initiated in 2001, and was intended to optimize shareholder return from the sale, development, or use of certain assets or entire business units.

Operating Expenses

WPS Resources' Operating Expenses (Millions)	2003	2002	Change
Operating and maintenance expense	$486.2	$444.5	9%
Depreciation and decommissioning expense	141.3	98.0	44%
Taxes other than income	44.3	40.1	10%

Operating and Maintenance Expense

Operating expenses increased $41.7 million, or 9%, for the year ended December 31, 2003, compared to the year ended December 31, 2002. Utility operating expenses increased $30.7 million, or 9%, in 2003 compared to 2002. Approximately $18 million of the increase reflects higher pension, postretirement medical, and active medical costs. The remaining increase pertains to costs incurred for plant maintenance related to Kewaunee's scheduled refueling outage in 2003 (there was no refueling outage in 2002), additional operating expenses at Kewaunee, and wage increases. Operating expenses at ESI increased $12.0 million, or 40%, in 2003 compared to 2002, largely due to costs associated with business expansion, including the acquisition of a retail natural gas business in Canada and a retail electric business in Michigan.

Depreciation and Decommissioning Expense

Depreciation and decommissioning expense increased $43.3 million, or 44%, due primarily to an increase of $37.4 million from increased realized gains on the decommissioning trust assets that resulted in recording decommissioning expense approximately equal to the gains recognized in miscellaneous income pursuant to regulatory practice. The increase in realized gains was due primarily to the change in investment strategy for WPSC's qualified nuclear decommissioning trust assets. Qualified 

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decommissioning trust assets were transferred to more conservative investments in 2003 pending the sale of Kewaunee, thus triggering realized gains. Most of the remaining increase resulted from plant asset additions at WPSC and PDI.

Taxes Other Than Income

Taxes other than income increased $4.2 million, or 10%, primarily due to an increase in gross receipts taxes paid by WPSC as a result of increased revenues.

Other Income (Expense)

WPS Resources' Other Income (Expense) (Millions)	2003	2002	Change
Miscellaneous income	$63.6	$47.8	33%
Interest expense and distributions of preferred securities	(61.8)	(61.6)	-%
Minority interest	5.6	-	-
Other income (expense)	$7.4	$ (13.8)	-

Miscellaneous Income

Miscellaneous income increased $15.8 million for the year ended December 31, 2003, compared to the year ended December 31, 2002. The increase in miscellaneous income was largely due to an increase in realized gains on the decommissioning trust assets of $36.4 million, which was primarily the result of the change in investment strategy for the qualified nuclear decommissioning trust assets. The realized gains were offset by increased decommissioning expense, as discussed above. Miscellaneous income also increased $6.2 million as a result of the sale of land to the WDNR and $8.1 million resulting from an increase in earnings from equity investments.

The increases in miscellaneous income were partially offset by lower gains from sales of ownership interests in PDI's synthetic fuel operation. PDI recognized a $7.6 million pre-tax gain in 2003 compared with a $38.0 million pre-tax gain in 2002 related to these sales. An increase in operating losses generated by the synthetic fuel operation due to increased production decreased miscellaneous income by approximately $3.5 million in 2003. The increased operating losses were driven by our partner's ability to utilize tax credits in 2003 and were offset by minority interest, which is discussed below. In the aggregate, the items mentioned above relating to the synthetic fuel operation resulted in a $33.9 million decrease in miscellaneous income.

The 2003 gain resulted from the 2002 sale of a portion of PDI's interest in its synthetic fuel operation. Similar gains from the 2002 sale are expected to be recognized annually through 2007, dependent upon production at the synthetic fuel facility. The gain reported in 2002 resulted from a 2001 sale of a portion of PDI's interest in a synthetic fuel operation, which was recognized in its entirety by December 31, 2002.

Minority Interest

As a result of PDI's sale of an approximate 30% interest in its subsidiary, ECO Coal Pelletization #12 LLC, on December 19, 2002, $5.6 million of losses related to the synthetic fuel operation and reported in miscellaneous income were allocated to PDI's partner and reported as a minority interest.

Provision for Income Taxes

The effective tax rate was 22.2% in 2003 compared to 18.1% in 2002. The increase in the effective tax rate in 2003 compared to 2002 was largely due to a decrease in tax credits that could be recognized from our ownership interest in a synthetic fuel operation. Tax credits recognized during the year ended December 31, 2003, decreased $5.1 million compared to the prior year, due to the sale of a portion of our interest in the synthetic fuel operation on December 19, 2002. Lower taxable income in 2003 also reduced the amount of tax credits that could be claimed. Our ownership interest in the synthetic fuel 

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operation resulted in the recognition of $18.1 million of Section 29 tax credits as a reduction of federal income tax expense in 2003 compared to $23.2 million in 2002. 

BALANCE SHEET - WPS RESOURCES

2004 Compared with 2003

Current assets from risk management activities decreased $141.6 million, or 27.3%, at December 31, 2004, compared to December 31, 2003, and current liabilities from risk management activities decreased $178.7 million, or 34.5%. Long-term assets from risk management activities decreased $29.7 million, or 28.5%, at December 31, 2004, compared to December 31, 2003, and long-term liabilities from risk management activities decreased $29.7 million, or 32.2%. The decrease in short-term risk management assets and liabilities was primarily related to changes in the forward price curve of natural gas. The decrease in long-term risk management assets and liabilities was driven by lower natural gas volumes under contract beyond one year and changes in the forward price curve for natural gas.

Property, plant, and equipment, net, increased $176.3 million to $2,076.5 million at December 31, 2004, compared to $1,900.2 million at December 31, 2003. This increase was mostly due to a $174.3 million increase in property, plant, and equipment at WPSC primarily related to capital expenditures associated with the construction of Weston 4 and the installation of automated meter reading.

Regulatory assets increased $33.2 million, from $127.7 million at December 31, 2003, to $160.9 million at December 31, 2004, largely due to the increase in environmental remediation liabilities related to manufactured gas plants at WPSC, as discussed below. WPSC expects to recover cleanup costs related to the manufactured gas plants, net of insurance recoveries, in future rates.

Short-term debt increased $254.4 million, from $38.0 million at December 31, 2003, to $292.4 million at December 31, 2004. Retirements of long-term debt and increased capital expenditures (primarily related to Weston 4) drove the increase in short-term debt.

Current portion of long-term debt decreased from $56.6 million at December 31, 2003, to $6.7 million at December 31, 2004. On January 19, 2004, WPSC retired early $49.9 million of its 7.125% series first mortgage bonds. These bonds had an original maturity date of July 1, 2023.

Accounts payable increased $78.7 million, from $510.7 million at December 31, 2003, to $589.4 million at December 31, 2004. Accounts payable at WPSC increased $40.2 million, driven by expenditures related to Weston 4. Accounts payable at ESI increased $38.0 million, primarily as a result of higher natural gas prices compared to the prior year.

The environmental remediation liability increased $30.5 million from December 31, 2003, to December 31, 2004. This liability primarily relates to clean-up costs associated with several manufactured gas plant sites at WPSC (see Note 17 to WPS Resources' Consolidated Financial Statements - Commitments and Contingencies, for more information). WPSC's estimate of future clean-up costs required to remediate these sites increased significantly to reflect the WDNR's application of sediment guidance that was recently issued.

Pension and postretirement benefit obligations decreased $43.1 million, or 31.3%, from December 31, 2003, to December 31, 2004, primarily due to a reduction in the minimum pension liability. The decrease in the minimum pension liability was driven by WPS Resources' merger of its two non-contributory qualified retirement plans. On a combined basis, the minimum pension liability and related pension asset were reduced pursuant to generally accepted accounting principles.

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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- and long-term debt ratings assigned by independent rating agencies. Currently, we believe these ratings are among the best in the energy industry (see Financing Cash Flows, Credit Ratings below).

Operating Cash Flows 

During 2004, net cash provided by operating activities was $230.8 million, compared to $59.2 million in 2003. The increase was driven by operating activities at ESI and WPSC. In 2003, operating activities at ESI used cash due primarily to increasing working capital requirements resulting from business growth and gas storage opportunities near the end of the year. ESI's natural gas operations did not experience the same level of growth in 2004 as they did in 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.

During 2003, net cash provided by operating activities was $59.2 million, compared with $194.0 million in 2002. The decrease was primarily due to increased working capital requirements, specifically at ESI and WPSC. Inventories increased due to high natural gas prices at both ESI and WPSC, as well as business growth at ESI. The inventory increase was also the result of ESI taking advantage of opportunities to put additional gas into storage at favorable relationships to forward prices. The change in receivables and payables was also attributable to the high natural gas prices as well as the business growth at ESI.

Investing Cash Flows 

Net cash used for investing activities was $315.0 million in 2004, compared to $247.4 million in 2003. The increase was largely related to a $114.0 million increase in utility capital expenditures (see Capital Expenditures below), partially offset by a $50.4 million decrease in cash used for the purchase of equity investments and other acquisitions. Purchase of equity investments and other acquisitions consisted primarily of additional investments in ATC, capital contributions to ECO Coal Pelletization #12 LLC, and the acquisition of Advantage Energy in 2004. In 2003, purchase of equity investments and other acquisitions consisted primarily of WPSC's final payment for the purchase of the De Pere Energy Center, WPSC's purchase of a one-third interest in Guardian Pipeline, additional investments in ATC, and capital contributions to ECO Coal Pelletization. WPS Resources contributed capital of $15.7 million to ECO Coal Pelletization in 2004 and $14.0 million in 2003. See WPS Resources' Notes to Consolidated Financial Statements, Note 6 - Acquisitions and Sales of Asset for more information.

Net cash used for investing activities was $247.4 million in 2003 compared to $284.8 million in 2002, a decrease of $37.4 million. The decrease is largely attributed to a $51.4 million decrease in capital expenditures, mainly at the utilities and PDI (see Capital Expenditures below), as well as a $24.2 million increase in cash received from the sale of property, plant, and equipment. The majority of the increase in the sale of property, plant, and equipment was the result of WPSC's sale of $20.1 million of assets at book value related to the Wausau, Wisconsin, to Duluth, Minnesota, transmission line to ATC in June 2003. Partially offsetting this decrease was a $30.4 million increase in cash used for the purchase of equity investments and other acquisitions. The composition of purchase of equity investments and other acquisitions in 2003 is discussed above. In 2002, the purchase of equity investments and other acquisitions primarily related to PDI's acquisition of CH Resources and a $11.7 million capital contribution to ECO Coal Pelletization. See WPS Resources' Notes to Consolidated Financial Statements, Note 6 - Acquisitions and Sales of Assets for more information.

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Capital Expenditures

Capital expenditures by business segment for the years ended December 31, 2004, 2003, and 2002 are as follows:

Millions

Years Ended December 31,

2004

2003

2002

Electric utility

$223.0

$131.0

$164.3

Gas utility

62.7

40.7

34.0

ESI

1.6

1.4

0.8

PDI

4.8

4.9

27.1

Other

0.3

(0.2)

3.0

WPS Resources Consolidated

$292.4

$177.8

$229.2

The increase in capital expenditures at the electric utility in 2004 as compared to 2003 is mainly due to higher capital expenditures associated with the construction of a 500-megawatt coal-fired Weston 4 generation facility located near Wausau, Wisconsin. Gas utility capital expenditures increased primarily due to the installation of automated meter reading. Capital expenditures at PDI and ESI remained fairly consistent between 2004 and 2003.

Capital expenditures in the electric utility were higher in 2002, as compared to 2003, mainly due to the construction of portions of the Pulliam combustion turbine at WPSC in 2002. Gas utility capital expenditures increased due to the installation of automated meter reading in 2003. PDI's capital expenditures were higher in 2002 compared to 2003 due to the installation of a low nitrogen oxide burner at Sunbury in 2002, as well as the conversion of the Combined Locks Energy Center to a combined cycle system in 2002. Capital expenditures at ESI remained fairly consistent between 2003 and 2002. 

Financing Cash Flows 

Net cash provided by financing activities was $73.5 million in 2004, compared to $195.6 million in 2003. Less cash was required from financing activities as a result of the increase in cash generated from operating activities in 2004, partially offset by higher capital expenditures incurred in 2004.

Net cash provided by financing activities was $195.6 million in 2003, compared to $90.2 million in 2002. The $105.4 million increase in cash provided by financing activities in 2003 is primarily related to the decrease in cash provided by operating activities in 2003 compared to 2002. A larger amount of investing activities was financed through common stock and debt issuances in 2003 as compared to the prior year.

Significant Financing Activities

WPS Resources had outstanding commercial paper borrowings of $279.7 million and $28.0 million at December 31, 2004, and 2003, respectively. WPS Resources had other outstanding short-term debt of $12.7 million and $10.0 million as of December 31, 2004, and 2003, respectively. Short-term borrowings in 2004 were used primarily to fund capital expenditures related to Weston 4.

In 2004, 2003 and 2002 we issued new shares of common stock under our Stock Investment Plan and under certain stock-based employee benefit and compensation plans. As a result of these plans, equity increased $28.3 million, $31.0 million, and $28.3 million in 2004, 2003, and 2002, respectively.

On January 19, 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.

On January 8, 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.

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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 on January 19, 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, PDI 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.

WPSC issued $150.0 million of 4.875% 10-year senior notes in December 2002. 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. WPSC used approximately $72 million of the net proceeds from the issuance of the senior notes to acquire the De Pere Energy Center and $69 million to retire short-term debt. The balance of the net proceeds was used for other corporate utility purposes.

WPS Resources issued $100.0 million of 5.375% 10-year senior non-collateralized notes in November 2002. We used approximately $55 million of the net proceeds from the issuance of these notes to repay short-term debt incurred to provide equity capital to our subsidiaries and the remainder for other corporate purposes. 

In October 2002, WPSC retired $50.0 million of 7.30% first mortgage bonds 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.

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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 line syndication	A A-1 -	A1 P-1 A1
WPSC    Bonds    Preferred stock    Commercial paper    Credit line syndication	A+ A- A-1 -	Aa2 A2 P-1 Aa3

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 WPSR's 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 WPS Resources and A-1/P-1 for 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 can conduct.

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ESI uses the NYMEX and over-the-counter financial markets to hedge its exposure to physical customer obligations. These hedges are closely correlated to the customer contracts, but price movements on the hedge contracts may require financial backing. Certain movements in price for contracts through the NYMEX exchange require posting of cash deposits equal to the market move. For the over-the-counter market, the underlying contract may allow the counterparty to require additional collateral to cover the net financial differential between the original contract price and the current forward market. Increased requirements related to market price changes usually only result in a temporary liquidity need that will unwind as the sales contracts are fulfilled.

Future Capital Requirements and Resources

Contractual Obligations

The following table summarizes the contractual obligations of WPS Resources, including its subsidiaries.

		Payments Due By Period
Contractual Obligations As of December 31, 2004 (Millions)	Total Amounts Committed	Less Than 1 Year	1 to 3 Years	3 to 5 Years	Over 5 Years
Long-term debt principal and interest payments	$1,316.6	$ 58.9	$ 118.8	$269.7	$ 869.2
Operating leases	18.2	4.2	4.5	3.6	5.9
Commodity purchase obligations	3,600.4	2,243.7	696.6	212.6	447.5
Purchase orders	499.6	305.7	163.3	30.6	-
Capital contributions to equity method investment	175.3	56.2	97.5	21.6	-
Other	221.7	32.6	48.2	46.6	94.3
Total contractual cash obligations	$5,831.8	$2,701.3	$1,128.9	$584.7	$1,416.9

Long-term debt principal and interest payments represent bonds issued, notes issued, and loans made to WPS Resources and its subsidiaries. We record all principal obligations on the balance sheet. Commodity purchase obligations represent mainly commodity purchase contracts of WPS Resources and its subsidiaries. Energy supply contracts at ESI included as part of commodity purchase obligations are generally entered into to meet obligations to deliver energy to customers. WPSC and UPPCO expect to recover the costs of their contracts in future customer rates. Purchase orders include obligations related to normal business operations and large construction obligations, including 100% of Weston 4 obligations even though we expect 30% of these costs to be paid by Dairyland Power Cooperative after certain conditions are met. Capital contributions to equity method investment include our commitment to fund a portion of the Wausau, Wisconsin, to Duluth, Minnesota, transmission line. Other mainly represents expected pension and post-retirement funding obligations.

Capital Requirements

WPSC makes large investments in capital assets. Net construction expenditures are expected to be approximately $1.2 billion in the aggregate for the 2005 through 2007 period (upon the closing of the sale of Kewaunee, expenditures would decrease approximately $73.8 million during this period). The largest of these expenditures is for the construction of Weston 4, in which WPSC is expected to incur costs of $432 million between 2005 through 2007, assuming 100% ownership in 2005, and 70% ownership in 2006 and 2007 after the expected purchase of a 30% interest in Weston 4 by Dairyland Power Cooperative.

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 $770 million (including the acquisition of coal trains). As of December 31, 2004, WPSC 

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has incurred a total cost of $94.9 million related to this project. In addition, WPSC expects to incur additional construction costs through the date the plant goes into service of approximately $41 million to fund construction of the transmission facilities required to support Weston 4. ATC will reimburse WPSC for the construction costs of the interconnection and related carrying costs when Weston 4 becomes commercially operational which is expected to occur in June 2008.

On October 7, 2004, we received the final PSCW order granting authority to proceed with construction of Weston 4 contingent upon receipt of an air permit. The air permit was issued by the WDNR on October 19, 2004. We believe the air permit is one of the most stringent in the nation, which means that Weston 4 will be one of the cleanest plants of its kind in the United States. Construction began in October 2004, and on November 15, 2004, a petition was filed with the WDNR contesting the air permit issued. On December 2, 2004, the WDNR granted the petition and forwarded the matter to the Division of Hearings and Appeals. Construction continues and it is anticipated that the contested case hearing will be held in the second half of 2005.

Other significant anticipated expenditures during this three-year period (2005 to 2007) include:

• mercury and pollution control projects - $188 million
  
• corporate services infrastructures - $34 million
  
• jointly owned 500-megawatt base-load plant - $65 million
  
• nuclear fuel - $43 million

Other capital requirements for the three-year period include a potential contribution of $3.3 million to the Kewaunee decommissioning trust fund if the sale of Kewaunee is not completed. 

On April 18, 2003, the PSCW approved WPSC's request to transfer its interest in the Wausau, Wisconsin, to Duluth, Minnesota, transmission line to the ATC. WPS Resources committed to fund 50% of total project costs incurred up to $198 million, and receive additional equity in ATC. WPS Resources may terminate funding if the project extends beyond January 1, 2010. On December 19, 2003, WPSC and ATC received approval to continue the project at a new cost estimate of $420.3 million. The updated cost estimate reflects additional costs for the project resulting from time delays, added regulatory requirements, changes and additions to the project at the request of local governments, and ATC overhead costs. Completion of the line is expected in 2008. WPS Resources has the right, but not the obligation, to provide additional funding in excess of $198 million up to its portion of the revised cost estimate. For the period 2005 through 2008, we expect to make capital contributions of approximately $175 million for our portion of the Wausau to Duluth transmission line. Our commitment to fund this transmission line could decrease up to 50% if Minnesota Power exercises its option to fund a portion of the project.

WPS Resources expects to provide additional capital contributions to ATC of approximately $36 million for the period 2005 through 2007 for other projects.

UPPCO is expected to incur construction expenditures of about $47 million in the aggregate for the period 2005 through 2007, primarily for electric distribution improvements and repairs and safety measures at hydroelectric facilities.

Capital expenditures identified at PDI for 2005 through 2007 are expected to be approximately $7.4 million, primarily for fuel improvements and blade replacement at WPS Empire State.

Capital expenditures identified at ESI for 2005 through 2007 are expected to be approximately $7.0 million, largely due to the Advantage Energy acquisition and computer equipment related to business expansion and normal technology upgrades.

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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 2005 through 2007 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, 2004, 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 2005 through 2007, WPS Resources plans to use internally generated funds net of forecasted dividend payments, cash proceeds from pending 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 ratings and corporate growth. Management believes WPS Resources has adequate financial flexibility and resources to meet its future needs.

WPS Resources has the ability to issue up to an additional $176.9 million of debt or equity under its currently effective shelf registration statement. WPSC has the ability to issue up to an additional $375.0 million of debt under its currently effective 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.

WPS Resources and WPSC have 364-day credit line facilities for $400.0 million and $115.0 million, respectively. The credit lines are used to back 100% of WPS Resources' and WPSC's commercial paper borrowing programs and letters of credit for WPS Resources. As of December 31, 2004, there was a total of $141.7 million and $20.2 million available under WPS Resources' and WPSC's credit lines, respectively.

In 2003, WPS Resources announced its plan to sell Sunbury, and WPSC announced its plan to sell its portion of Kewaunee. We anticipate being able to complete the sale of Sunbury in 2005. See the Kewaunee paragraph below for a discussion on this potential sale. A portion of the proceeds related to the Sunbury sale may be used to pay the non-recourse debt related to the plant. A portion of the proceeds related to the Kewaunee sale will be used to retire debt at WPSC. The remainder of the proceeds from both the Sunbury and Kewaunee sales will be used by WPS Resources for investing activities and general corporate purposes of its subsidiaries, including reducing the amount of outstanding debt. For more information regarding the Kewaunee sale, see the discussion below. For an update on the sale of Sunbury, see Note 4, "Assets Held for Sale," to WPS Resources' Notes to Consolidated Financial Statements.

Other Future Considerations

Sunbury

WPS Resources made capital contributions of $24.5 million to Sunbury in 2004 to compensate for the impact of lower capacity revenues, as well as adjustments to Sunbury's operating plan. These funds have been used to cover operating losses, make principal and interest payments, and purchase emission allowances. In 2004, WPS Resources' Board of Directors granted authorization to contribute up to $32.8 million of additional capital to Sunbury. Of that amount, $8.3 million remains available in 2005, as authorized by WPS Resources' Board of Directors.

On September 30, 2004, PDI received a letter of termination from Duquesne Power, L.P. related to the previously announced agreement to sell Sunbury to Duquesne for approximately $120 million. Duquesne issued its letter of termination following a determination by the Pennsylvania Public Utility Commission not 

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to reconsider its earlier approved Provider of Last Resort plan, which Duquesne believed did not satisfy a closing condition in the agreement. PDI is continuing its efforts to sell Sunbury. The carrying value of Sunbury is about $117 million, and this project carries approximately $66 million of project-financed debt. Based upon consideration of all information available at this time, management determined that no adjustment to the carrying value of Sunbury was required in 2004. Although management cannot predict the precise timetable or ultimate outcome, PDI is progressing with the sale process, and anticipates being able to complete the sale of Sunbury in 2005. For an update on the sale of Sunbury, see Note 4, "Assets Held for Sale," to WPS Resources' Notes to Consolidated Financial Statements.

Kewaunee

On November 7, 2003, WPSC entered into a definitive agreement to sell its 59% ownership interest in Kewaunee to a subsidiary of Dominion Resources, Inc. The other joint owner of Kewanee, Wisconsin Power and Light Company, also agreed to sell its 41% ownership interest in Kewaunee to Dominion. The transaction is subject to approvals from various regulatory agencies, of which all major approvals have been obtained, except for approval by the PSCW. The PSCW rejected the sale on November 19, 2004. However, WPSC, Wisconsin Power and Light Company, and Dominion Resources, Inc. offered a proposal addressing the PSCW's concerns in December 2004. In January 2005, the PSCW agreed to reconsider its decision on this transaction and we expect a decision to be rendered in March 2005.

WPSC estimates that its share of the cash proceeds from the sale will approximate $130 million, subject to various post-closing adjustments. The cash proceeds from the sale are expected to slightly exceed the carrying value of the WPSC assets being sold. In addition to the cash proceeds, WPSC will retain ownership of the assets contained in its non-qualified decommissioning trust, one of two funds that were established to cover the eventual decommissioning of Kewaunee. The net of tax fair value of the non-qualified decommissioning trust's assets at December 31, 2004, was $102.5 million. Dominion will assume responsibility for the eventual decommissioning of Kewaunee and will receive WPSC's qualified decommissioning trust assets that had a net of tax fair value of $242.0 million at December 31, 2004. WPSC has requested deferral of the gain or loss resulting from this transaction and related costs from the PSCW. Accordingly, the gain or loss on the sale of the plant assets and the related non-qualified decommissioning trust assets are expected to be returned to customers under future rate orders.

On February 20, 2005, Kewaunee was temporarily removed from service after a potential design weakness was identified in a backup cooling system. Plant engineering staff identified the concern and the unit was shutdown in accordance with the plant license. A modification is being made to resolve the issue and it is anticipated that the unit will be back in service at 100% power by mid April. WPSC intends to file a request with the PSCW for recovery of incremental costs associated with fuel, purchased power, and operating and maintenance costs. WPSC and Dominion remain committed to the sale of Kewaunee.

Asset Management Strategy

WPS Resources is finalizing its sales strategy for the balance of its identified excess real estate holdings. This strategy is expected to provide for WPS Resources to meet its average annualized earnings per share goal.

Regulatory

For a discussion of regulatory considerations, see Note 22, Regulatory Environment, to WPS Resources' Notes to Consolidated Financial Statements.

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 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 

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year or taxable income for the taxable year. The deduction is phased in, providing a deduction of three percent of income through 2006, a six percent deduction through 2009, and a nine percent deduction after 2009. On December 21, 2004, the FASB issued final staff position ("FSP") 109-1, effective the same day, on accounting for the effects of the domestic production deduction provisions. The FSP  109-1 said the deduction should be accounted for as a special deduction rather than a tax rate reduction. The FSP  109-1 also said the special deduction should be considered by an enterprise in measuring deferred taxes when graduated tax rates are a significant factor and also in assessing if a valuation allowance is necessary. On December 8, 2004, the PSCW issued an order authorizing WPSC to defer of the revenue requirements impacts resulting from the 2004 Jobs Act. The Internal Revenue Service and Department of Treasury issued interim guidance on January 19, 2005, covering the implementation of the domestic production provision of the 2004 Jobs Act. WPS Resources is currently reviewing this guidance in order to quantify the tax impact of this deduction or identify all potential tax issues related to the 2004 Jobs Act. However, pursuant to regulatory treatment, WPS Resources expects any tax benefits derived from utility operations to be deferred and passed on to customers in future rates.

Section 29 Federal Tax Credits

The current rise in oil prices may result in a reduction or elimination of the Section 29 federal tax credits expected for future years. A phase out or elimination of the Section 29 federal tax credits would have no impact on the value of alternative minimum tax credits WPS Resources is carrying forward as a result of prior production of Section 29 federal tax credits. WPS Resources is assessing the impact of this issue on future operations and evaluating alternatives to potentially protect the ongoing economic benefits of the synthetic fuel facility. 

GUARANTEES AND OFF BALANCE SHEET ARRANGEMENTS - WPS RESOURCES

As part of normal business, WPS Resources and its subsidiaries enter into various guarantees providing financial or performance assurance to third parties on behalf of certain subsidiaries. These guarantees are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries' intended commercial purposes. 

The guarantees issued by WPS Resources include inter-company guarantees between parents and their subsidiaries, which are eliminated in consolidation, and guarantees of the subsidiaries' own performance. As such, these guarantees are excluded from the recognition, measurement, and disclosure requirements of FIN No. 45, "Guarantors' Accounting and Disclosure Requirements for Guarantees, including Indirect Guarantees of Indebtedness of Others."

At December 31, 2004, 2003, and 2002, outstanding guarantees totaled $977.9 million, $981.8 million, and $652.2 million, respectively, as follows:

WPS Resources' Outstanding Guarantees (Millions)	December 31, 2004	December 31,  2003	December 31,  2002
Guarantees of subsidiary debt	$ 27.2	$ 39.7	$ 38.8
Guarantees supporting commodity    transactions of subsidiaries	863.9	874.4	584.3
Standby letters of credit	80.9	61.1	22.7
Surety bonds	0.6	1.1	6.4
Other guarantee	5.3	5.5	-
Total guarantees	$977.9	$981.8	$652.2

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WPS Resources' Outstanding Guarantees (Millions) Commitments Expiring	Total Amounts Committed At December 31, 2004	Less Than 1 Year	1 to 3 Years	4 to 5 Years	Over 5 Years
Guarantees of subsidiary debt	$ 27.2	$ -	$ -	$ -	$ 27.2
Guarantees supporting commodity transactions of subsidiaries	863.9	812.6	22.4	12.9	16.0
Standby letters of credit	80.9	68.0	12.9	-	-
Surety bonds	0.6	0.6	-	-	-
Other guarantee	5.3	-	-	-	5.3
Total guarantees	$977.9	$881.2	$35.3	$12.9	$48.5

At December 31, 2004, WPS Resources had outstanding $27.2 million in corporate guarantees supporting indebtedness. Of that total, $27.0 million supports outstanding debt at one of PDI's subsidiaries. The underlying debt related to these guarantees is reflected on the consolidated balance sheet.

WPS Resources' Board of Directors has authorized management to issue corporate guarantees in the aggregate amount of up to $1.2 billion to support the business operations of ESI. WPS Resources primarily issues the guarantees to counterparties in the wholesale electric and natural gas marketplace to provide counterparties the assurance that ESI will perform on its obligations and permit ESI to operate within these markets. The amount of guarantees actually issued by WPS Resources to support the business operations at ESI at December 31, 2004, was $817.7 million, and this is reflected in the table above. These guarantees reflect the amount of outstanding business ESI could have with the counterparties holding the guarantees at any point in time. At December 31, 2004, the actual amount of ESI's obligations to counterparties supported by WPS Resources' parental guarantees was $132.6 million.

At December 31, 2004, WPS Resources had issued $38.3 million in corporate guarantees to support the business operation of PDI, which are reflected in the above table. WPS Resources issues the guarantees for indemnification obligations related to business purchase agreements and counterparties in the wholesale electric marketplace to meet their credit requirements and permit PDI to operate within these markets. The amount supported is dependent on the amount of the outstanding obligations that PDI has with the parties holding the guarantees at any point in time. At December 31, 2004, the amount of PDI's obligations supported by WPS Resources' parental guarantees was $4.7 million. In February 2004, WPS Resources' Board of Directors authorized management to issue corporate guarantees in the aggregate amount of up to $30.0 million to support business operations at PDI in addition to guarantees that receive specific WPS Resources Board authorization.

Another $7.9 million of corporate guarantees support energy and transmission supply at UPPCO and are not reflected on WPS Resources' consolidated balance sheet. In February 2004, WPS Resources' Board of Directors authorized management to issue corporate guarantees in the aggregate amount of up to $15.0 million to support the business operations of UPPCO. Corporate guarantees issued in the future under the Board authorized limit may or may not be reflected on WPS Resources' consolidated balance sheet, depending on the nature of the guarantee.

At WPS Resources' request, financial institutions have issued $80.9 million in standby letters of credit for the benefit of third parties that have extended credit to certain subsidiaries. If a subsidiary does not pay amounts when due under a covered contract, the counterparty may present its claim for payment to the financial institution, which will request payment from WPS Resources. Any amounts owed by our subsidiaries are reflected in the consolidated balance sheet.

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At December 31, 2004, WPS Resources furnished $0.6 million of surety bonds for various reasons including worker compensation coverage and obtaining various licenses, permits, and rights-of-way. Liabilities incurred as a result of activities covered by surety bonds are included in the consolidated balance sheet.

The other guarantee of $5.3 million listed on the above table was issued by WPSC to indemnify a third party for exposures related to the construction of utility assets. This amount is not reflected on the consolidated balance sheet.

WPS Resources guarantees the potential retrospective premiums that could be addressed under WPS Resources' nuclear insurance program.

See Note 23, "Variable Interest Entities," to WPS Resources' Notes to the Consolidated Financial Statements for information on the implementation of Interpretation No. 46R. Interpretation No. 46R requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional financial support from other parties.

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, natural gas 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 is shown as "assets or liabilities from risk management activities" in the 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 pricing is the settled forward price curve of the NYMEX exchange, which includes 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 12 months ended December 31, 2004.

ESI Mark-to-Market Roll Forward (Millions)	Natural Gas	Electric	Total
Fair value of contracts at January 1, 2004	$13.3	$ 6.3	$19.6
Less - contracts realized or settled during period	10.9	(2.0)	8.9
Plus - changes in fair value of contracts in existence at   December 31, 2004	29.2	5.4	34.6
Fair value of contracts at December 31, 2004	$31.6	$13.7	$45.3

The fair value of contracts at January 1, 2004, and December 31, 2004, 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, 2004, that were no longer included in the net mark-to-market assets as of December 31, 2004, 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, 2004, and contracts that were entered into subsequent to January 1, 

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2004, which are included in ESI's portfolio at December 31, 2004. 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, 2004
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	$27.4	$1.8	-	-	$29.2
Prices provided by external sources	8.1	5.1	-	-	13.2
Prices based on models and other valuation methods	2.8	0.1	-	-	2.9
Total fair value	$38.3	$7.0	-	-	$45.3

We derive the pricing for most contracts in the above table from active quotes or external sources. "Prices actively quoted" includes NYMEX contracts and basis swaps. "Prices provided by external sources" includes electric and natural gas contract positions for which pricing information is obtained primarily through broker quotes. "Prices based on models and other valuation methods" includes electric contracts for which reliable external pricing information does not exist.

ESI, as a result of PDI's ownership of generating assets in New York, has acquired transmission congestion contracts, which are financial contracts, that hedge price risk between zones within the New York Independent System Operator. The contracts were marked to fair value using a combination of modeled forward prices and market quotes. The fair market value of the contracts at December 31, 2004, was $0.7 million.

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 hedge accounting rules causes ESI to experience earnings volatility associated with electric and natural gas operations. While risks associated with power generating capacity and power sales are economically hedged, certain transactions do not meet the definition of a derivative or qualify for hedge accounting under generally accepted accounting principles. Consequently, gains and losses from the generating capacity do not always 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 of the hedge transaction. The accounting treatment does not impact the underlying cash flows or economics of these transactions. At December 31, 2004, the unrealized mark-to-market gains were $5.4 million for ESI's electric operations and related hedges that did not qualify for cash flow hedge treatment under SFAS No. 133. See Results of Operations - Overview of Nonregulated Operations - ESI's Segment Operations for information regarding earnings volatility associated with 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.

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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, 2004, those derivatives not designated as hedges are primarily commodity contracts to manage price risk associated with wholesale and retail natural gas purchase and sale activities and electric energy contracts. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction, and as a result, such expectations and intentions are documented. 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 corresponding with anticipated physical sales or purchases. Fair value hedge accounting may be used when WPS Resources holds 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 fair value of a hedge 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 exemption, provided by SFAS No. 133, as amended, to certain contracts. The normal purchases and sales exception provides that no recognition of the contract's fair value in the consolidated financial statements is 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 Sheet 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 record 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. 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 reserves to account for the estimated direct costs of servicing and holding certain of its contracts based upon administrative costs, credit/counterparty risk, and servicing margin with both fixed and variable components. The effect of changing the underlying servicing and credit/counterparty risk assumptions is as follows:

Change in Assumption (Millions)	Effect to Operating Reserve at December 31, 2004
100% increase	$ 11.4
50% decrease	$(5.7)

These potential changes to the operating reserve would be shown as part of the Nonregulated cost of fuel, gas and purchased power on the Consolidated Statements of Income and current and long-term Assets/Liabilities from risk management activities on the Consolidated Balance Sheets.

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 PDI 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, 2004, the carrying value of PDI's property, plant, and equipment totaled $212.0 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. 

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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 PDI in the impairment analysis are future revenue streams and operating costs. A combination of input from both internal and external sources is used to project revenue streams. PDI's operations group 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. PDI 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 2004, PDI tested its power plants for impairment whenever events or changes in circumstances indicated that their carrying amount may not be recoverable. No impairment charges were recorded in 2004 as a result of these 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 yearly 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, 2004, 2003, and 2002, the amount of unbilled revenues was $113.2 million, $90.0 million, and $105.9 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 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.

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Pension and Postretirement Benefits

The costs of providing non-contributory defined benefit pension benefits and other postretirement benefits, described in Note 18 to the 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. Other postretirement benefit costs are also impacted by health care cost trends. 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)	$ 44.2	$(3.7)	$ 3.7
Discount rate	0.5	(41.6)	3.7	(3.7)
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)	$23.8	$(1.9)	$ 1.9
Discount rate	0.5	(20.5)	1.6	(1.6)
Health care cost trend rate	(1.0)	(34.7)	4.8	(4.8)
Health care cost trend rate	1.0	42.0	(5.2)	5.2
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 consider long-term Corporate Aa rated bond yield rates. To select an assumed rate of return on 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. In selecting assumed health care cost trend rates, we consider past performance and forecasts of health care costs.

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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 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 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, 2004, would result in a 3.6% decrease in total assets, an 8.7% decrease in total liabilities, and a 68.4% 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. 

RELATED PARTY TRANSACTIONS - WPS RESOURCES

WPS Resources has investments in related parties that are accounted for under the equity method of accounting. These include WPS Investments, LLC's (a consolidated subsidiary of WPS Resources) investments in ATC and Guardian Pipeline; WPSC's investment in Wisconsin River Power Company; and WPS Nuclear Corporation's (a consolidated subsidiary of WPS Resources) investment in Nuclear Management Company. WPS Resources also had an investment in WPSR Capital Trust I, which was dissolved January 8, 2004. See Note 10 of WPS Resources' Notes to the Consolidated Financial Statements, "Investments in Affiliates, at Equity Method," for information regarding related party transactions involving ATC, Guardian Pipeline, and Nuclear Management Company. Note 24, "Company-Obligated Mandatorily Redeemable Trust Preferred Securities of Preferred Stock Trust," contains information regarding WPSR Capital Trust I.

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TRENDS - WPS RESOURCES

Environmental

See Note 17, "Commitments and Contingencies," to the WPS Resources' Notes to Consolidated Financial Statements for a detailed discussion of WPS Resources' environmental commitments and contingencies.

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.

Although electric energy prices are currently high due to increased natural gas prices, we expect that electric capacity prices will continue 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. PDI has been negatively impacted by the depressed capacity prices and volatile energy prices discussed above, and as a result we have taken certain steps to reduce our exposure to the merchant marketplace.

In 2004, PDI entered into tolling agreements with ESI to market electric production from its facilities and to manage natural gas costs for its gas-fired generation facilities. ESI is utilizing various financial tools, including forwards and options, to limit exposure and extract additional value from volatile commodity prices. PDI continues to manage costs of fuel for its coal-fired facilities.

Synthetic Fuel Operation

See Note 17, "Commitments and Contingencies," for a detailed discussion of WPS Resources' synthetic fuel production facility. 

Industry Restructuring

The Ohio Legislature passed a Senate Bill in May 1999 instituting market-based rates, competitive retail electric services and establishing a market development period that began January 1, 2001, and was to end no later than December 31, 2005. This bill required Ohio electric distribution companies to file electric transition plans, including the collection of transition costs and freezing generation rates at a 5% discount during the course of the market development period. At the end of the market development period, rates would be set at a market-based price. However, the Public Utilities Commission of Ohio, recognizing the competitive electric market has not developed as envisioned and fearing rate shock at the end of the market development period, requested the Ohio electric distribution utilities to file rate stabilization plans covering the 2006-2008 time period. The 2006-2008 rate stabilization plans are expected to provide rate certainty, financial stability for the electric distribution utilities, and to further develop the competitive market.

Since 2001, ESI has been the supplier to 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. On June 9, 2004, the Public Utilities Commission of Ohio ordered a competitive bid auction be developed and conducted and approved a modified version of the rate stabilization plan submitted by FirstEnergy. The FirstEnergy Rate Stabilization Plan would establish electric rates consumers would pay beginning in 2006 if the auction does not produce better benefits.

ESI participated as an intervener in the FirstEnergy Rate Stabilization Plan and competitive bid process cases in an effort to preserve the competitive electric business established in the FirstEnergy service areas in the 2006-2008 time period. ESI filed comments requesting modifications to the competitive bid process to allow for fair competition. In October 2004, the Public Utilities Commission of Ohio issued 

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orders directing FirstEnergy to modify the competitive bid process based on filed comments and direction from independent consultants and scheduled the auction for December 8, 2004.

The competitive bid process was conducted on December 8, 2004, concluding the same day. On December 9, 2004, the Public Utility Commission of Ohio rejected the auction price citing the clearing price of 5.45 cents per kilowatt-hour was inadequate in comparison to the FirstEnergy Rate Stabilization Plan. While the details of the rate comparison and auction results have not been made public; the Public Utility Commission of Ohio requested stakeholder comments relative to what information to maintain as confidential and for what period of time. The Public Utility Commission of Ohio intends to conduct a similar auction next year, believing the economy of the power market will improve, increasing the probability of an acceptable auction clearing price.

Given the auction results, the FirstEnergy Rate Stabilization Plan will be implemented. ESI participated in recent case developments relative to the price to be paid by customers who return from competitive supply to default service during the Rate Stabilization Plan period. Continued service by ESI beyond December 31, 2005, to customers of the existing aggregation programs will be dependent on the ability of the communities to comply with the FirstEnergy Rate Stabilization Plan requirements imposed on governmental aggregation programs and improved market power prices.

Meanwhile, on September 23, 2004, an Ohio House Bill was introduced, proposing change to the electric restructuring law. The bill proposes to give the Public Utilities Commission of Ohio explicit authority to implement rate stabilization plans, where it has been determined that there is insufficient development of the generation market or lack of effective competition in an electric utility's service area and ensuring against any undue competitive disadvantage between Ohio and regional customers of an electric utility of its affiliates. Recent news releases indicate an increased momentum in the Ohio General Assembly for legislation that would make major changes to Senate Bill 3 in 2005.

On July 1, 2004, Senate Bills 1331-1336 were introduced in Michigan to amend legislation enacted in June 2000, which initially established a competitive supply alternative for customers in the state's electricity market. On October 6, 2004, Senate Bill S-1 was introduced as a substitute for Senate Bill 1331. As the Michigan legislature closed out 2004 with this package of bills not being voted out of the Senate Energy and Technology Committee, they must be reintroduced and sponsored again, if they are to be addressed in 2005. It is our expectation that such a move will be initiated early in 2005.

Under current legislation, Michigan's regulated utilities were able to securitize overrun costs associated with large generation assets and the MPSC was provided the authority to administer the Electric Choice program to ensure the interests of all stakeholders were met. Under the current Electric Choice program, ESI, through its subsidiary Quest Energy, LLC, has established itself as a significant supplier to the industrial and commercial markets, achieving contract demand levels of approximately 900 megawatts, and annual sales volumes of 3.6 million megawatt-hours. The initial Senate bills contained provisions that would have substantially harmed the Electric Choice market and returned Michigan to a model of the regulated supply monopoly. If similar legislation is proposed and passed in 2005, 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 that will have some level of negative impact on ESI, but it would be 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.

WPSC, UPPCO, and ESI are members of the Midwest Independent System Operator (ISO), which is in the process of restructuring the bulk electric power market across its footprint. The implementation of market restructuring by the Midwest ISO is currently expected to occur April 1, 2005. Such restructuring could have an impact on the costs associated with serving utility customers' energy requirements; however, given the anticipated regulatory treatment of any potential cost differences, WPSC does not currently expect the ultimate outcome will have a material impact on its results of operations or financial 

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condition. WPSC, UPPCO, and ESI are working closely with the Midwest ISO and the FERC to ensure that there is a smooth transition to the new market in order to minimize any impact on them and their customers. ESI currently participates in markets that have gone through comparable transitions. We believe this past experience has prepared ESI for the Midwest ISO transition and positions ESI to manage the risk and pursue the opportunities that will exist.

Seams Elimination Charge Adjustment

ESI has identified an issue that could create financial exposure through March 2006. Through a series of orders issued by FERC, Regional Through and Out Rates for transmission service between the Midwest ISO and the PJM Interconnection have been eliminated effective December 1, 2004. The FERC ordered a transitional pricing mechanism called the Seams Elimination Charge Adjustment (SECA) to be put into place on December 1, 2004, through March 31, 2006, which would be paid by load serving entities. The purpose of the SECA is to compensate transmission owners (during the 16-month transition period) for the revenue they would no longer receive due to the elimination of the Regional Through and Out Rates. Because ESI is a load serving entity, it will be billed for SECA charges based on its power imports during 2002 and 2003. Although actual SECA charges have only been calculated for the first 4 months of the 16-month period, total exposure for the 16-month transitional period is estimated to be approximately $13 million for Michigan and $2 million for Ohio.

On February 10, 2005, FERC issued an order accepting compliance filings implementing the SECA effective December 1, 2004, subject to refund and surcharge, as appropriate, and setting the case in its entirety for a formal hearing. It is anticipated that the case could take a year or more to reach a final decision. In addition, matters related to the justness and reasonableness and other legal challenges to the SECA itself remain pending before FERC on rehearing. It is not known when FERC will issue an order on these requests for rehearing. It appears that ESI will be required to pay the SECA charges during this process, subject to refund. ESI has actively participated in the SECA case since its beginning and believes its position has strong merits. The application and legality of the SECA is being challenged by many other load serving entities and ESI will continue to pursue all avenues to appeal and/or reduce the SECA obligations. In the interim, the exposure will be managed through customer charges and other available avenues, where feasible. Through existing contracts, ESI has the ability to pass SECA charges on to customers. However, doing so may hinder ESI's competitiveness in the marketplace.

New Accounting Pronouncements

See Note 1(v), "New Accounting Pronouncements," for a detailed discussion of new accounting pronouncements.

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.

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