[x] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2004

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________ to __________

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

Indicate by check mark whether the registrants are accelerated filers (as defined in Rule 12b-2 of the Act).

Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of the latest practicable date:

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Except for historical data and statements of current fact, the information contained or incorporated by reference in this document constitutes forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Any references to plans, goals, beliefs or expectations in respect to future events and conditions or to estimates are forward-looking statements. Although we believe that statements of our expectations are based on reasonable assumptions, forward-looking statements are inherently uncertain and subject to risks and should be viewed with caution. Actual results or experience could differ materially from the forward-looking statements as a result of many factors. Forward-looking statements included or incorporated in this document include, but are not limited to statements regarding:

We cannot predict the course of future events or anticipate the interaction of multiple factors beyond our control and their effect on revenues, project timing, and costs. Some risk factors that could cause results different from any forward-looking statement include those described in the Risk Factors Section of our Annual Report on Form 10-K for the year ended December 31, 2003 and the following:

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We have prepared the consolidated financial statements of WPS Resources Corporation and Wisconsin Public Service Corporation under the rules and regulations of the Securities and Exchange Commission. These financial statements have not been audited. Management believes that these financial statements include all adjustments (which unless otherwise noted include only normal recurring adjustments) necessary for a fair presentation of the financial results for each period shown. Certain items from the prior period have been reclassified to conform to the current year presentation. We have condensed or omitted certain financial information and footnote disclosures normally included in our annual audited financial statements. We believe that the disclosures made are adequate to make the information presented not misleading. These financial statements should be read along with the financial statements and notes included with our annual audited financial statements for the year ended December 31, 2003.

In accordance with the requirements of Emerging Issues Task Force Issue No. 02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," WPS Energy Services' gross physical volumes of natural gas and electricity delivered for the three months ended March 31, 2004 and March 31, 2003 are reported in the following table:

We consider short-term investments with an original maturity of three months or less to be cash equivalents.

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As part of our regular operations, WPS Resources enters into contracts, including options, swaps, futures, forwards, and other contractual commitments, to manage market risks such as changes in commodity prices, interest rates, and foreign currency exchange rates.

WPS Resources evaluates its derivative contracts in accordance with Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended and interpreted. Statement No. 133 establishes accounting and financial reporting standards for derivative instruments and requires, in part, that we recognize certain derivative instruments on the balance sheet as assets or liabilities at their fair value. Subsequent changes in fair value of the derivatives are recorded currently in earnings unless certain hedge accounting criteria are met. If the derivatives qualify for regulatory deferral subject to the provisions of Statement No. 71, "Accounting for the Effects of Certain Types of Regulation," the derivatives are marked to fair value pursuant to Statement No. 133 and are offset with a corresponding regulatory asset or liability.

In the fourth quarter of 2003, WPS Resources adopted Emerging Issues Task Force Issue 03-11, "Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133 and Not 'Held for Trading Purposes' as Defined in Issue No. 02-03," which resulted in recording revenues net of cost of fuel, gas and purchased power for energy-related transactions entered into after October 1, 2003 that settle financially and for which the commodity does not physically transfer. Had we applied the provisions of Issue 03-11 to arrangements entered into before October 1, 2003, previously reported nonregulated revenue would have decreased $17.9 million for the three months ended March 31, 2003, with a corresponding $17.9 million decrease to nonregulated cost of fuel, gas, and purchased power. Neither margins, income, nor cash flows were impacted by the adoption of Issue 03-11.

Wisconsin Public Service has entered into a limited number of natural gas purchase agreements and electric purchase and sale contracts to service customers that are accounted for as derivatives. The Public Service Commission of Wisconsin approved recognizing a regulatory asset or liability for the fair value of derivative amounts as a result of these contracts pursuant to Statement No. 71. Thus, management believes any gains or losses resulting from the eventual settlement of these contracts will be collected from or refunded to customers. As of March 31, 2004 and December 31, 2003, we recorded an asset from risk management activities and an offsetting regulatory liability of $8.4 million related to these contracts.

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Our nonregulated segments have also entered into contracts that are accounted for as derivatives under Statement No. 133, as amended and interpreted. At March 31, 2004, those derivatives not designated as hedges are primarily commodity contracts used to manage price risk associated with wholesale and retail natural gas purchase and sale activities and electric energy contracts. Changes in the fair value of the non-hedge derivatives are recognized currently in earnings. At March 31, 2004, the fair value of these contracts was recorded as an asset from risk management activities of $430.0 million and a liability from risk management activities of $418.2 million. At December 31, 2003, the fair value of these contracts was recorded as an asset from risk management activities of $578.1 million and a liability from risk management activities of $582.1 million. 

Our nonregulated segments also enter into derivative contracts that are designated as either fair value or cash flow hedges. Fair value hedges are used to mitigate the risk of changes in prices of natural gas held in inventory and changes in fair value of foreign currency denominated assets and liabilities. The changes in the fair value of these hedges are recognized currently in earnings as are the changes in fair value of the hedged items. At March 31, 2004, the fair value of the contracts designated as fair value hedges, excluding foreign exchange contracts, are recorded as a net liability from risk management activities of $2.9 million. Fair value hedge ineffectiveness recorded in nonregulated revenue on the Consolidated Statement of Income was insignificant during the first quarter of 2004 and 2003. At December 31, 2003, the fair value of the contracts designated as fair value hedges, excluding foreign exchange contracts, was recorded as an asset from risk management activities of $0.3 million and a liability from risk management activities of $4.0 million.

Forward foreign exchange contracts designated as fair value hedges are utilized to manage the risk associated with currency fluctuations on certain firm sales and purchase commitments denominated in Canadian dollars and certain Canadian dollar denominated asset and liability positions. The terms of our forward foreign exchange contracts are consistent with the terms of the underlying transactions, generally one year or less. Unrealized gains and losses resulting from the impact of currency exchange rate movements on forward foreign exchange contracts designated to offset certain non-U.S. dollar denominated assets and liabilities are recognized in earnings and offset the foreign currency gains and losses on the underlying exposures being hedged. The contract amounts of forward foreign exchange contracts outstanding at March 31, 2004 are recorded as an asset from risk management activities of $4.8 million and a liability from risk management activities of $2.0 million. The contract amounts of forward foreign exchange contracts outstanding at December 31, 2003 were recorded as an asset from risk management activities of $10.6 million and a liability from risk management activities of $4.3 million. All of the foreign exchange contracts designated as fair value hedges were determined to be perfectly effective.

Cash flow hedges consist of commodity contracts associated with our energy marketing activities and an interest rate swap. At March 31, 2004, the fair value of commodity contracts designated as cash flow hedges is recorded as an asset from risk management activities of $35.5 million and a liability from risk management activities of $13.3 million. These cash flow hedges extend through December 2005. The majority of the commodity contracts were determined to be perfectly effective; therefore, the changes in the values of these contracts are included in other comprehensive income, net of deferred taxes. Amounts recorded in other comprehensive income related to these cash flow hedges will be recognized in earnings as the related contracts are settled or if the hedged transaction is discontinued. In the next 12 months, we expect to recognize $12.7 million in earnings. The portion of these contracts that was determined to be ineffective was not significant at March 31, 2004, and was recorded as a component of nonregulated revenue. When testing for effectiveness, no portion of the derivative instruments were excluded. At December 31, 2003, those commodity contracts designated as cash flow hedges were recorded as an asset from risk management activities of $25.0 million and a liability from risk management activities of $9.0 million.

The interest rate swap designated as a cash flow hedge is used to fix the interest rate for the full term of a variable rate loan due in March 2018. At March 31, 2004, we recorded a liability from risk management activities of $11.9 million related to this swap. At December 31, 2003, we recorded a liability from risk 

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management activities of $10.1 million related to this swap. Because the swap was determined to be perfectly effective, the changes in the value of this contract are included in other comprehensive income, net of deferred taxes. Amounts recorded in other comprehensive income related to this swap will be recognized as expense as the interest is paid. In the next 12 months, we expect to expense $2.2 million, assuming interest rates comparable to those at March 31, 2004. We did not exclude any components of the derivative instrument's change in fair value from the assessment of hedge effectiveness.

WPS Energy Services had been applying the accounting standards of Issue 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," from the first quarter of 2000 until this standard was rescinded by Issue 02-03 in October 2002. WPS Energy Services was defined as a trading company under Issue 98-10 and was required to mark all of its energy related contracts to market. On October 25, 2002, the Emerging Issues Task Force rescinded Issue 98-10, thus precluding mark-to-market accounting for energy trading contracts entered into after that date that are not derivatives and requiring a cumulative change in accounting principle to be recorded effective January 1, 2003 for all nonderivative contracts entered into on or prior to October 25, 2002. On January 1, 2003, WPS Resources recorded an after-tax cumulative effect of a change in accounting principle of $3.5 million (primarily related to the operations of WPS Energy Services) to increase income available for common shareholders as a result of removing from its balance sheet the mark-to-market effects of those contracts entered into on or prior to October 25, 2002 that do not meet the definition of a derivative under Statement No. 133. The required change in accounting had no impact on the underlying economics or cash flows of the contracts.

On October 24, 2003, WPS Power Development entered into a definitive agreement to sell its Sunbury generation plant located in Pennsylvania. This facility currently sells power on a wholesale basis, and provides energy for a 200-megawatt around-the-clock outtake contract that expires on December 31, 2004. The sale will enable WPS Resources to reduce uncontracted merchant exposure and redeploy capital into markets with different risk profiles. Based on the terms of the asset sale agreement, the sale price is anticipated to be approximately $120 million, subject to various working capital adjustments. WPS Power Development has also entered into an agreement for the sale of certain silt reserves that were utilized in the operations of the Sunbury generation plant.

At March 31, 2004 and December 31, 2003, the assets and liabilities associated with the Sunbury generation plant that will be transferred to the buyer, as well as the silt reserves, have been classified as held for sale in accordance with Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." Statement No. 144 requires that a long-lived asset classified as held for sale be measured at the lower of its carrying amount or fair value, less costs to sell, and cease being depreciated. No adjustments to write down assets held for sale were required during the first quarter of 2004. WPS Resources plans to complete the sale of the Sunbury generation plant in the summer of 2004 and the sale of the silt reserves is anticipated to close in the second quarter of 2004. The major classes of assets and liabilities held for sale are as follows:

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WPS Power Development financed Sunbury with equity from WPS Resources and debt financing, including non-recourse debt and a related interest rate swap. The interest rate swap is designated as a cash flow hedge and, as a result, the mark-to-market loss has been recorded as a component of other comprehensive income. If management determines that the hedged transactions (i.e., future interest payments on the debt) will not continue after the sale, WPS Resources will be required to recognize the amount accumulated within other comprehensive income ($7.1 million net of tax at March 31, 2004) currently in earnings. No such determination had been made at March 31, 2004.

WPS Power Development has an obligation to service a 200-megawatt outtake contract through December 31, 2004. WPS Power Development entered into the contract in conjunction with the acquisition of the Sunbury generating assets. At March 31, 2004, WPS Power Development hedged its obligation to service its 200-megawatt outtake contract subsequent to the date of the anticipated sale of Sunbury. The revenues from the outtake contract are $2.7 million less than the hedged cost of purchased power. This loss will be included as a component of the loss from discontinued operations in the Consolidated Statements of Income when realized. The amount of the loss is subject to change depending on the closing date of the sale.

A summary of the components of discontinued operations recorded in the Consolidated Statements of Income for the quarters ended March 31 are as follows:

Interest expense represents the nonrecourse term loans directly related to Sunbury.

A summary of the components of the change in cash and cash equivalents related to discontinued operations recorded in the Consolidated Statements of Cash Flows for the quarters ended March 31 are as follows:

On November 7, 2003, Wisconsin Public Service entered into a definitive agreement to sell its 59% ownership interest in the Kewaunee nuclear power plant 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 approval from various regulatory agencies, including the Public Service Commission of Wisconsin, the Federal Energy Regulatory Commission, the Nuclear Regulatory Commission, and several other state utility regulatory agencies and is projected to close in 2004. Approval has already been obtained from the Federal Trade Commission, the Iowa Utilities Board, and the Minnesota Public Utilities Commission, and certain approvals have been obtained from the Federal Energy Regulatory Commission.

Wisconsin Public Service 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 Wisconsin Public Service assets being sold. In addition to the cash proceeds, Wisconsin Public Service 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 

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Kewaunee. The pretax fair value of the non-qualified decommissioning trust's assets at March 31, 2004 was $118.1 million. Dominion will assume responsibility for the eventual decommissioning of Kewaunee and will receive Wisconsin Public Service's qualified decommissioning trust assets that had a pretax fair value of $240.1 million at March 31, 2004. Wisconsin Public Service has requested deferral of the gain expected to result from this transaction and related costs from the Public Service Commission of Wisconsin. Accordingly, Wisconsin Public Service anticipates most of the gain on the sale of the plant assets and the related non-qualified decommissioning trust assets will be returned to customers under future rate orders. As of March 31, 2004, Wisconsin Public Service's share of the carrying value of the assets and liabilities included within the sale agreement were as follows:

The assets and liabilities disclosed above do not meet the criteria to be classified as held for sale on the Consolidated Balance Sheets under the provisions of FASB Statement No. 144 due to uncertainties inherent in the regulatory approval process.

Upon the closing of the sale, Wisconsin Public Service will enter into a long-term power purchase agreement with Dominion to purchase energy and capacity equivalent to the amounts that would have been received had current ownership in the Kewaunee nuclear power plant continued. The power purchase agreement, which also will require regulatory approval, will extend through 2013 when the plant's current operating license will expire. Fixed monthly payments under the power purchase agreement will approximate the expected costs of production had Wisconsin Public Service continued to own the plant. Therefore, management believes that the sale of Kewaunee and the related power purchase agreement will provide more price certainty for Wisconsin Public Service's customers and reduce our risk profile. In April 2004, Wisconsin Public Service entered into an exclusivity agreement with Dominion. Under this agreement, if Dominion decides to extend the operating license of Kewaunee, Dominion agreed to negotiate only with Wisconsin Public Service for a new power purchase agreement that would extend beyond Kewaunee's current operating license termination date. Our current co-owner in the Kewaunee plant negotiated a similar agreement with Dominion for their share of output of the plant. The exclusivity period will start on the closing date of the sale and extend through December 21, 2011.

Goodwill recorded by WPS Resources Corporation was $36.4 million at March 31, 2004 and December 31, 2003. The goodwill is recorded in Wisconsin Public Service's natural gas segment relating to its merger with Wisconsin Fuel and Light.

Goodwill and purchased intangible assets are included in other assets on the Consolidated Balance Sheet of WPS Resources. Information in the tables below relates to total purchased identifiable intangible assets for the years indicated (excluding assets held for sale).

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Intangible asset amortization expense, in the aggregate, for the quarter ended March 31, 2004 was $0.3 million.

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On January 19, 2004, Wisconsin Public Service retired $49.9 million of its 7.125% series first mortgage bonds. These bonds had an original maturity date of July 1, 2023.

On July 30, 1998, WPSR Capital Trust I, a Delaware business trust, issued $50.0 million of trust preferred securities to the public. WPS Resources owned all of the outstanding trust common securities of the Trust, and the only asset of the Trust was $51.5 million of subordinated debentures issued by WPS Resources. The debentures were due on June 30, 2038 and bore interest at 7% per year. The terms and interest payments on the debentures corresponded to the terms and distributions on the trust preferred securities. On January 8, 2004, WPS Resources redeemed all of the subordinated debentures that were initially issued to the Trust for $51.5 million.

Legal retirement obligations, as defined by the provisions of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations," identified at Wisconsin Public Service relate primarily to the final decommissioning of the Kewaunee nuclear plant. Wisconsin Public Service has a legal obligation to decommission the irradiated portions of the Kewaunee nuclear plant in accordance with the Nuclear Regulatory Commission's minimum decommissioning requirements. The liability, calculated under the provisions of Statement No. 143, is based on several significant assumptions, including the scope of decommissioning work to be performed, the timing of the future cash flows, and inflation and discount rates. Some of these assumptions differ significantly from the assumptions authorized by the Public Service Commission of Wisconsin to calculate the nuclear decommissioning liability for funding purposes. In accordance with Statement No. 71, Wisconsin Public Service established a regulatory liability to record the differences between ongoing expense recognition under Statement No. 143 and the ratemaking practices for retirement costs authorized by the Public Service Commission of Wisconsin. As of March 31, 2004, the market value of external nuclear decommissioning trusts established for future retirement costs, authorized by the Public Service Commission of Wisconsin, was approximately $358.1 million. See Note 6, "Acquisitions and Sales of Assets" for information on the pending sale of the Kewaunee nuclear plant. We have also identified other legal retirement obligations related to utility plant assets that are not currently significant to the financial statements.

WPS Power Development has identified a legal retirement obligation related to the closure of an ash basin located at the Sunbury generation plant. The adoption of Statement No. 143 at WPS Power Development resulted in a $0.3 million negative after-tax cumulative effect of change in accounting principle in the first quarter of 2003 related to recording a liability for the closure of an ash basin at the Sunbury generation plant. See Note 5, "Assets Held for Sale" for information on the pending sale of the Sunbury plant.

The following table describes all changes to the asset retirement obligation liabilities of WPS Resources.

The provision for income taxes is based on the estimated annual effective tax rate, which differs from the federal tax rate of 35% primarily due to the effects of tax credits and state income taxes.

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WPS Resources routinely enters into long-term purchase and sale commitments that have various quantity requirements and durations. The commitments described below are as of March 31, 2004.

WPS Energy Services has unconditional purchase obligations related to energy supply contracts that total $1.9 billion. The majority of these obligations extend through 2008, but there are firm transport obligations that extend through 2012. WPS Energy Services total obligations from 2009 through 2012 are $0.5 million. The energy supply obligations generally have offsetting energy sales contracts.

Wisconsin Public Service has obligations related to nuclear fuel, coal, purchased power, and natural gas. Nuclear fuel contracts total $50.0 million and extend through 2010. Obligations related to coal supply extend through 2016 and total $498.9 million. Through 2015, Wisconsin Public Service has obligations totaling $382.1 million for either capacity or energy related to purchased power. Also, there are natural gas supply and transportation contracts with total estimated demand payments of $138.0 million through 2010. Wisconsin Public Service expects to recover these costs in future customer rates. Additionally, Wisconsin Public Service has contracts to sell electricity and natural gas to customers.

WPS Power Development also enters into long-term commodity purchase contracts, which total $11.8 million and extend through 2007.

Upper Peninsula Power has made commitments for the purchase of commodities, mainly capacity or energy related to purchased power, which total $16.6 million and extend through 2006.

WPS Resources also has commitments in the form of purchase orders issued to various vendors. At March 31, 2004, these purchase orders totaled $450.5 million for WPS Resources and Wisconsin Public Service committed $445.5 of the total. The majority of these commitments relate to large construction projects including the construction of the 500-megawatt coal-fired generation facility near Wausau, Wisconsin.

In accordance with Nuclear Regulatory Commission industry requirements, during the completed spring 2003 refueling outage, a visual inspection of the Kewaunee plant reactor vessel head was conducted. There were no problems with the vessel head during the most recently completed operating cycle.

After evaluating the cost of continued required inspections of the existing reactor vessel head and the cost to replace the reactor vessel head, the Kewaunee nuclear power plant owners submitted a construction authorization request to the Public Service Commission of Wisconsin for replacement of the reactor vessel head. Approval of the request was received in 2003. The replacement is scheduled to occur during the fall 2004 refueling outage at a cost of up to $14.2 million for Wisconsin Public Service's share of the project.

The Price Anderson Act ensures that funds will be available to pay for public liability claims arising out of a nuclear incident. This Act may require Wisconsin Public Service to pay up to a maximum of $59.4 million per incident. The payments will not exceed $5.9 million per incident in a given calendar year. These amounts correspond to Wisconsin Public Service's 59% ownership in the Kewaunee nuclear power plant.

See Note 6, "Acquisitions and Sales of Assets," for information on the sale of the Kewaunee nuclear plant.

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The United States Environmental Protection Agency has designated southeastern Wisconsin as an ozone non-attainment area. Under the Clean Air Act, the State of Wisconsin developed a nitrogen oxide reduction plan for Wisconsin's ozone non-attainment area. The nitrogen oxide reductions began in 2003 and will gradually increase through 2007. Wisconsin Public Service owns 31.8% of Edgewater Unit 4, which is located in the ozone non-attainment area. A compliance plan for this unit was initiated in 2000. Wisconsin Public Service's share of the costs of this project is expected to be approximately $5.3 million. The project is nearly complete. Wisconsin Public Service has incurred approximately $5.0 million on this project as of March 31, 2004.

The State of Wisconsin is also seeking voluntary reductions from utility power plants outside the ozone non-attainment area, which may lead to additional expenditures for nitrogen oxide reductions at other plants. Wisconsin Public Service is participating in voluntary efforts to reduce nitrogen oxide levels at the Columbia Energy Center. Wisconsin Public Service owns 31.8% of the Columbia facility. The Public Service Commission of Wisconsin has approved recovery of the costs associated with voluntary nitrogen oxide reductions.

Air quality modeling by the Wisconsin Department of Natural Resources revealed that Weston Units 1 and 2 contribute to a modeled exceedance of the sulfur dioxide ambient air quality standard. Wisconsin Public Service expects that compliance with a future limit can be achieved by managing the coal supply quality and does not expect these changes to have a material impact on the operations of Wisconsin Public Service. Wisconsin Public Service is cooperating with the Wisconsin Department of Natural Resources to develop an approach to resolve this issue.

In November 1999, the United States Environmental Protection Agency announced the commencement of a Clean Air Act enforcement initiative targeting the utility industry. This initiative resulted in the issuance of several notices of violation/findings of violation and the filing of lawsuits against other unaffiliated utilities. In these enforcement proceedings, the United States Environmental Protection Agency claims that the utilities made modifications to the coal-fired boilers and related equipment at the utilities' electric generating stations without first obtaining appropriate permits under the United States Environmental Protection Agency's pre-construction permit program and without installing appropriate air pollution control equipment. In addition, the United States Environmental Protection Agency is claiming, in certain situations, that there were violations of the Clean Air Act's "new source performance standards." In the matters where actions have been commenced, the federal government is seeking penalties and the installation of pollution control equipment.

In December 2000, Wisconsin Public Service received from the United States Environmental Protection Agency a request for information under Section 114 of the Clean Air Act. The United States Environmental Protection Agency sought information and documents relating to work performed on the coal-fired boilers located at the Pulliam and Weston electric generating stations of Wisconsin Public Service. Wisconsin Public Service filed a response with the United States Environmental Protection Agency in early 2001.

On May 22, 2002, Wisconsin Public Service received a follow-up request from the United States Environmental Protection Agency seeking additional information regarding specific boiler-related work performed on Pulliam Units 3, 5 and 7, as well as information on Wisconsin Public Service's life extension program for Pulliam Units 3-8 and Weston Units 1 and 2. Wisconsin Public Service made an initial response to the United States Environmental Protection Agency's follow-up information request on June 12, 2002, and filed a final response on June 27, 2002.

In 2000, 2001, and 2002, Wisconsin Power and Light Company received a similar series of United States Environmental Protection Agency information requests relating to work performed on certain coal-fired boilers and related equipment at the Columbia generating station (a facility located in Portage, Wisconsin jointly owned by Wisconsin Power and Light Company, Madison Gas and Electric Company, and 

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Wisconsin Public Service). Wisconsin Power and Light Company is the operator of the plant and is responsible for responding to governmental inquiries relating to the operation of the facility. Wisconsin Power and Light filed its most recent response for the Columbia facility on July 12, 2002.

Depending upon the results of the United States Environmental Protection Agency's review of the information, the United States Environmental Protection Agency may seek additional information from Wisconsin Public Service and/or third parties who have information relating to the boilers, close out the investigation, or issue a "notice of violation" or "finding of violation" asserting that a violation of the Clean Air Act occurred. To date, the United States Environmental Protection Agency has not responded to the 2002 follow-up filings made by Wisconsin Public Service and Wisconsin Power and Light Company.

In response to the United States Environmental Protection Agency Clean Air Act enforcement initiative, several utilities elected to settle with the United States Environmental Protection Agency, while others are in litigation. In general, those utilities that settled entered into consent decrees which require the companies to pay fines and penalties, undertake supplemental environmental projects and either upgrade or replace pollution controls at existing generating units or shut down existing units and replace these units with new electric generating facilities. Several of the settlements involve multiple facilities. The fines and penalties (including the capital costs of supplemental environmental projects) associated with these settlements range between $7 million and $30 million. Factors typically considered in settlements include, but are not necessarily limited to, the size and number of facilities, as well as the duration of alleged violations, and the presence or absence of aggravating circumstances. The regulatory interpretations upon which the lawsuits or settlements are based may change based on future court decisions that may be rendered in pending litigations.

If the federal government decided to bring a claim against Wisconsin Public Service and if it were determined by a court that historic projects at the Pulliam and Weston electric generating stations required either a state or federal Clean Air Act permit, Wisconsin Public Service may, under the applicable statutes, be required to:

At the end of December 2002, the United States Environmental Protection Agency issued new rules governing the federal new source review program. The rules are not yet effective in Wisconsin. They are also not retroactive. Wisconsin has proposed amending its new source review program to substantially conform to the federal regulations. The rules are anticipated to be finalized in the second half of 2004.

In 2001, the Wisconsin Department of Natural Resources initiated a rulemaking effort to control mercury emissions. Coal-fired generation plants are the primary targets of this effort. The proposed rule was open to comment in October 2001. As proposed, the rule requires phased-in mercury emission reductions reaching 90% reduction in 15 years. Wisconsin Public Service estimates that it could cost approximately $168 million to achieve the proposed 90% reductions. Presently, the proposed rule is on hold, and it is uncertain if the state will proceed to finalize the regulations.

In December 2003, the United States Environmental Protection Agency proposed mercury "maximum achievable control technology" standards and an alternative mercury "cap and trade" program substantially modeled on the Clear Skies legislation initiative. In addition, the United States Environmental Protection Agency proposed the Interstate Air Quality rule, which would reduce sulfur dioxide and nitrogen oxide emissions from utility boilers located in 29 states, including Wisconsin. Wisconsin Public Service is in the process of studying the proposed rules. As to the mercury maximum achievable control technology proposal, it requires existing units burning sub-bituminous coal to achieve an annual average mercury emission rate limit of 5.8 pounds per trillion Btu on a unit-by-unit or plant-wide basis. New units must achieve an emission rate limit of 0.020 pounds per gigawatt-hour. If the proposed 

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rule is promulgated, Wisconsin Public Service's current analysis indicates that the emission control equipment on the existing units may be sufficient to achieve the proposed limitation. New units will require additional mercury control techniques to reduce mercury emissions by 65% to 85%. Mercury control technology is still in development. Wisconsin Public Service is assessing potential mercury control technologies for application to future new coal-fired units.

As to the Interstate Air Quality rule proposal, the proposal allows the affected states (including Wisconsin) to either require utilities located in the state to participate in an interstate cap and trade program or meet the state's emission budget for nitrogen oxides and sulfur dioxide through measures to be determined by the state. Wisconsin has not stated a preference as to which option it would select in the event the rule becomes final. While the effect of the rule on Wisconsin Public Service's facilities is uncertain, for planning purposes, it is assumed that additional expenditures for nitrogen oxide and sulfur dioxide controls will be needed on existing units or the existing units will need to be converted to natural gas by 2010. The installation of any controls and/or any conversion to natural gas will need to be scheduled as part of Wisconsin Public Service's long-term maintenance plan for its existing units. As such, controls or conversions may need to take place before the proposed 2010 compliance date. On a preliminary basis and assuming controls or conversion is required, Wisconsin Public Service estimates a cost of $288 million in order to meet a 2010 compliance date. This estimate is based on costs of current control technology.

The generation assets of WPS Power Development are subject to regulations on sulfur dioxide and nitrogen oxide emissions similar to those that apply to Wisconsin Public Service. In addition, the Sunbury generation facilities of WPS Power Development are located in an ozone transport region. As a result, these generation facilities are subject to additional restrictions on emissions of nitrogen oxide. Although WPS Power Development has some emission allowances for 2004 for the Sunbury facility, approximately 10,000 to 15,000 additional allowances may need to be purchased, at market rates, to meet its 2004 requirements.

In the fourth quarter of 2003, the Wisconsin Environmental Law Advocates filed a complaint in the United States District Court for the Western District of Wisconsin against Wisconsin Power and Light Company and its parent, Alliant Energy Corporation, alleging violations of the federal Clean Water Act at the Columbia generating station (a facility jointly owned by Wisconsin Power and Light, Madison Gas and Electric Company and Wisconsin Public Service that is operated by Wisconsin Power and Light). The complaint seeks certain upgrades to the Columbia facility's wastewater treatment program, as well as unspecified penalties and attorney fees. In addition, the Wisconsin Department of Natural Resources has been pursuing enforcement of this same matter and has recently referred the matter to the Wisconsin Attorney General's office. In March 2004, the Wisconsin Attorney General's office filed a civil complaint against Alliant Energy Corporation and Wisconsin Power and Light for violating the terms of the wastewater discharge permit for the Columbia generating station. We believe that the total cost to resolve any potential penalties in this matter will not be material.

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Groundwater testing at a former ash disposal site of Upper Peninsula Power indicated elevated levels of boron and lithium. Supplemental remedial investigations were performed, and a revised remedial action plan was developed. The Michigan Department of Environmental Quality approved the plan in January 2003. A liability of $1.4 million and an associated regulatory asset of $1.4 million were recorded for estimated future expenditures associated with remediation of the site. Upper Peninsula Power received an order permitting deferral and future recovery of these costs. Upper Peninsula Power has an informal agreement, with the owner of another landfill, under which it has agreed to pay 17% of the investigation and remedial costs. It is estimated that the cost of addressing the site over the next three years is $1.7 million. Upper Peninsula Power has recorded $0.3 million of this amount as a liability as of March 31, 2004.

Wisconsin Public Service continues to investigate the environmental cleanup of ten manufactured gas plant sites. As of the fall of 2003, cleanup of the land portion of the Oshkosh, Stevens Point, Green Bay, and two Sheboygan sites was substantially complete. Groundwater treatment and monitoring at these sites will continue into the future. River sediment remains to be addressed at six sites with sediment contamination. Remedial investigation work commenced on the sediment portion of the Sheboygan site in the first quarter of 2004. Sediment removal work at the Marinette site is scheduled for the fall of 2004. Work at the other sites remains to be scheduled.

Costs of these cleanups are within the range expected for these sites. Wisconsin Public Service estimates future undiscounted investigation and cleanup costs to be in the range of $35.9 million to $40.6 million. Wisconsin Public Service may adjust these estimates in the future contingent upon remedial technology, regulatory requirements and the assessment of natural resource damages.

Wisconsin Public Service currently has a $35.9 million liability recorded for cleanup with an offsetting regulatory asset (deferred charge). Wisconsin Public Service has received $12.7 million in insurance recoveries that we recorded as a reduction to the regulatory asset. Wisconsin Public Service expects to recover cleanup costs, net of insurance recoveries, in future customer rates. Under current Public Service Commission of Wisconsin policies, Wisconsin Public Service will not recover carrying costs associated with the cleanup expenditures. Wisconsin Public Service will include long-term operation and maintenance costs associated with these sites in future rate requests.

On May 14, 2003, a fuse plug at the Silver Lake reservoir owned by Upper Peninsula Power was breached. This breach resulted in subsequent flooding downstream on the Dead River, which is located in Michigan's Upper Peninsula near Marquette, Michigan.

A dam owned by Marquette Board of Light and Power, which is located downstream from the Silver Lake reservoir near the mouth of the Dead River, also failed during this event. In addition, high water conditions and siltation resulted in damage at the Presque Isle Power Plant owned by Wisconsin Electric Power Company. Presque Isle, which is located downstream from the Marquette Board of Light and Power dam, was ultimately forced into a temporary shutdown.

The Federal Energy Regulatory Commission's Independent Board of Review issued its report in December of 2003 and concluded that the root cause of the incident was the failure of the design to take into account the highly erodible nature of the fuse plug's foundation materials and spillway channel, resulting in the complete loss of the fuse plug, foundation and spillway channel which caused the release of Silver Lake far beyond the intended design of the fuse plug. The fuse plug was designed for the Silver Lake reservoir by an outside engineering firm.

WPS Resources maintains a comprehensive insurance program that includes Upper Peninsula Power and which provides both property insurance for its facilities and liability insurance for liability to third 

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parties. WPS Resources is insured in amounts that it believes are sufficient to cover its responsibilities in connection with this event. Deductibles and self-insured retentions on these policies are not material to WPS Resources.

In November 2003, Upper Peninsula Power received approval from the Michigan Public Service Commission and the Federal Energy Regulatory Commission for deferral of costs that are not reimbursable through insurance or recoverable through the power supply cost recovery mechanism. Recovery of costs deferred will be addressed in future rate proceedings. As of March 31, 2004, Upper Peninsula Power has deferred $2.9 million pretax and expensed $1.0 million pretax of costs for damages resulting from the flood. In addition, Upper Peninsula Power has recorded a $1.9 million insurance receivable at March 31, 2004.

Construction of the 220-mile, 345-kilovolt Wausau, Wisconsin, to Duluth, Minnesota transmission line began in the first quarter of 2004.

American Transmission Company has agreed to assume primary responsibility for the overall management of the project and will own and operate the completed line. Wisconsin Public Service received approval from the Public Service Commission of Wisconsin and the Federal Energy Regulatory Commission to transfer ownership of the project to the American Transmission Company. Wisconsin Public Service will continue to manage construction of the project and be responsible for obtaining property rights in Wisconsin necessary for the construction of the project. As part of the ownership transfer, Wisconsin Public Service received approximately $20.1 million for the sale of its construction expenditures in June 2003.

WPS Resources committed to fund 50% of total project costs incurred up to $198 million. WPS Resources will receive additional equity in American Transmission Company in exchange for a portion of the project funding. In the quarter ended March 31, 2004, WPS Resources invested $1.4 million in American Transmission Company, related to its agreement to fund approximately half of the Wausau to Duluth transmission line. WPS Resources may terminate funding if the project extends beyond January 1, 2010. On December 19, 2003, Wisconsin Public Service and American Transmission Company received approval to continue the project with the 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 American Transmission Company's management, and 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 2004 through 2006, we expect to fund up to $128 million for our portion of the Wausau to Duluth transmission line.

We have significantly reduced our consolidated federal income tax liability for the past four years through tax credits available to us under Section 29 of the Internal Revenue Code for the production and sale of solid synthetic fuel from coal. In order to maximize the value of our synthetic fuel production facility, we have reduced our interest in the facility from 67% to 23% through sales to third parties. Our ability to fully utilize the Section 29 tax credits that remain available to us in connection with our remaining interest in the facility will depend on whether the amount of our federal income tax liability is sufficient to permit the use of such credits. The Internal Revenue Service strictly enforces compliance with all of the technical requirements of Section 29. Section 29 tax credits are currently scheduled to expire at the end of 2007.  The Permanent Subcommittee on Investigations of the Senate Committee on Governmental Affairs has been conducting an investigation of the synthetic fuel industry and their use of Section 29 tax credits. It is not known when the investigation will be completed and what impact, if any, such investigation may have on future legislation or the enforcement policy of the Internal Revenue Service. Other future tax legislation and Internal Revenue Service review may also affect the value of the credits and the value of our share of the facility.

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We have recorded the tax benefit of approximately $87.2 million of Section 29 tax credits as reductions of income tax expense from the project's inception in June 1998 through March 31, 2004. As a result of alternative minimum tax rules, approximately $52.3 million of this tax benefit has been carried forward as a deferred tax asset as of March 31, 2004. The tax benefit recorded with respect to WPS Resources' share of tax credits from the facility is based on our expected consolidated tax liability for all open tax years including the current year, and all future years in which we expect to utilize deferred tax credits to offset its future tax liability. Reductions in our expected consolidated tax liability for any of these years could result in disallowance of previously recorded credits, and/or a change in the amount of the tax benefit deferred to future periods. A reduction in our expected consolidated tax liability for the current year may result in a reduction of the level of synthetic fuel production at the facility. A portion of future payments under one of the agreements covering the sale of a portion of our interest in the facility are contingent on the facility's continued production of synthetic fuel. Pre-tax gains approximating $7 million annually are expected to be realized through 2007 from this sell-down.

The following table provides the components of net periodic benefit cost (credit) for WPS Resources' benefit plans for the quarters ended March 31: