Integrys Holding (TEG) 8-K Other Events

		Exhibit 99.6
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 in Part I of Item 1 (Financial Statements) previously filed in the Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 of WPS Resources. All other sections of Item 1 are unchanged.
Item 1. Financial Statements
WPS RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)	Three Months Ended
	March 31
(Millions, except per share amounts)	2005	2004
Nonregulated revenue	$1,076.0	$1,000.3
Utility revenue	410.9	386.7
Total revenues	1,486.9	1,387.0
Nonregulated cost of fuel, gas, and purchased power	1,017.9	953.4
Utility cost of fuel, gas, and purchased power	201.6	197.0
Operating and maintenance expense	133.3	131.5
Depreciation and decommissioning expense	29.2	25.7
Taxes other than income	12.0	11.8
Operating income	92.9	67.6
Miscellaneous income	7.7	4.8
Interest expense	(16.2)	(14.9)
Minority interest	1.0	-
Other expense	(7.5)	(10.1)
Income before taxes	85.4	57.5
Provision for income taxes	18.7	14.1
Net income before preferred stock dividends of subsidiary	66.7	43.4
Preferred stock dividends of subsidiary	0.8	0.8
Income available for common shareholders	$65.9	$42.6
Average shares of common stock
Basic	37.8	37.1
Diluted	38.1	37.3
Earnings per common share (basic)	$1.74	$1.15
Earnings per common share (diluted)	$1.73	$1.14
Dividends per common share declared	$0.555	$0.545
The accompanying condensed notes are an integral part of these statements.

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WPS RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS (Unaudited)	March 31	December 31
(Millions)	2005	2004
Assets
Cash and cash equivalents	$49.1	$40.0
Accounts receivable - net of reserves of $8.2 and $8.0, respectively	525.6	531.3
Accrued unbilled revenues	115.5	113.2
Inventories	165.8	196.1
Current assets from risk management activities	513.2	376.5
Assets held for sale	24.0	24.1
Other current assets	72.8	91.5
Current assets	1,466.0	1,372.7
Property, plant, and equipment, net of reserves of $1,608.0 and $1,588.5, respectively	2,135.0	2,076.5
Nuclear decommissioning trusts	345.0	344.5
Regulatory assets	175.4	160.9
Long-term assets from risk management activities	108.5	74.6
Other	360.6	347.6
Total assets	$4,590.5	$4,376.8
Liabilities and Shareholders' Equity
Short-term debt	$215.6	$292.4
Current portion of long-term debt	6.7	6.7
Accounts payable	606.2	589.4
Current liabilities from risk management activities	499.7	338.6
Current deferred income taxes	9.8	9.1
Other current liabilities	125.8	73.2
Current liabilities	1,463.8	1,309.4
Long-term debt	864.9	865.7
Long-term deferred income taxes	66.9	71.0
Deferred investment tax credits	15.8	16.2
Regulatory liabilities	287.7	288.3
Environmental remediation liabilities	68.1	68.4
Pension and postretirement benefit obligations	76.6	94.6
Long-term liabilities from risk management activities	88.4	62.5
Asset retirement obligations	371.9	366.6
Other	99.5	91.2
Long-term liabilities	1,939.8	1,924.5
Commitments and contingencies
Preferred stock of subsidiary with no mandatory redemption	51.1	51.1
Common stock equity	1,135.8	1,091.8
Total liabilities and shareholders' equity	$4,590.5	$4,376.8
The accompanying condensed notes are an integral part of these statements.

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WPS RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)			Three Months Ended
			March 31
(Millions)			2005	2004
Operating Activities
Net income before preferred stock dividends of subsidiary			$66.7	$43.4
Adjustments to reconcile net income to net cash provided by operating activities
	Depreciation and decommissioning		29.2	25.7
	Amortization of nuclear fuel and other		12.2	9.3
	Unrealized gain on investments		(2.0)	(0.7)
	Pension and post retirement expense		12.5	11.2
	Pension and post retirement funding		(3.0)	-
	Deferred income taxes and investment tax credit		3.1	2.1
	Unrealized (gains) losses on nonregulated energy contracts		0.5	(2.8)
	Gain on sale of partial interest in synthetic fuel operation		(1.7)	(1.9)
	Other		(25.7)	(5.8)
	Changes in working capital
		Receivables, net	4.9	59.3
		Inventories	45.2	80.3
		Other current assets	13.3	13.4
		Accounts payable	(14.3)	(39.4)
		Other current liabilities	28.7	4.7
Net cash provided by operating activities			169.6	198.8
Investing Activities
Capital expenditures			(60.2)	(41.1)
Sale of property, plant, and equipment			1.1	1.9
Purchase of equity investments and other acquisitions			(16.5)	(9.5)
Decommissioning funding			-	(0.3)
Other			(0.8)	6.5
Net cash used for investing activities			(76.4)	(42.5)
Financing Activities
Short-term debt, net			(76.8)	(28.0)
Repayment of long-term debt and note to preferred stock trust			(0.8)	(103.1)
Payment of dividends
	Preferred stock		(0.8)	(0.8)
	Common stock		(20.8)	(20.1)
Issuance of common stock			9.9	10.3
Other			5.2	(3.9)
Net cash used for financing activities			(84.1)	(145.6)
Change in cash and cash equivalents			9.1	10.7
Cash and cash equivalents at beginning of period			40.0	50.7
Cash and cash equivalents at end of period			$49.1	$61.4
The accompanying condensed notes are an integral part of these statements.

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WPS RESOURCES CORPORATION AND SUBSIDIARIES
WISCONSIN PUBLIC SERVICE CORPORATION AND SUBSIDIARY
CONDENSED NOTES TO FINANCIAL STATEMENTS
March 31, 2005

NOTE 1--FINANCIAL INFORMATION

We have prepared the consolidated financial statements of WPS Resources and WPSC under the rules and regulations of the SEC. 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. These financial statements should be read along with the audited financial statements and notes for the year ended December 31, 2004 included in this Current Report on Form 8-K.

NOTE 2--CASH AND CASH EQUIVALENTS

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

The following is supplemental disclosure to the WPS Resources and WPSC Consolidated Statements of Cash Flows:

(Millions)	Three Months Ended March 31
WPS Resources	2005	2004
Cash paid for interest	$8.7	$7.3
Cash paid for income taxes	$0.5	$9.7
WPSC
Cash paid for interest	$ 6.2	$5.7
Cash paid (received) for income taxes	$(3.0)	$0.5

During the quarter ended March 31, 2005, approximately $33.3 million of Weston 4 construction costs were funded through accounts payable, and accordingly, are treated as non-cash investing activities.

NOTE 3--RISK MANAGEMENT ACTIVITIES

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

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

The following table shows WPS Resources' assets and liabilities from risk management activities:

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	Assets		Liabilities
(Millions)	March 31, 2005	December 31, 2004	March 31, 2005	December 31, 2004
Utility Segment
Gas and electric purchase     contracts	$ 16.9	$ 11.0	$ -	$ -
Other	1.7	-	0.2	0.6
Nonregulated Segments
Commodity and foreign     currency contracts	578.0	396.5	538.5	366.6
Fair value hedges	0.8	3.8	8.4	2.3
Cash flow hedges
Commodity contracts	24.3	39.8	34.0	22.9
Interest rate swap	-	-	7.0	8.7
Total	$621.7	$451.1	$588.1	$401.1
Balance Sheet Presentation
Current	$513.2	$376.5	$499.7	$338.6
Long-Term	108.5	74.6	88.4	62.5
Total	$621.7	$451.1	$588.1	$401.1

Assets and liabilities from risk management activities are classified as current or long-term based upon the maturities of the underlying financial instruments.

Utility Segment

WPSC has entered into a limited number of natural gas and electric purchase contracts that are accounted for as derivatives. In the above table, "Other" includes financial instruments used to manage transmission congestion costs. The PSCW approved the recognition of a regulatory asset or liability for the fair value of derivative amounts. Thus, management believes any gains or losses resulting from the eventual expiration or settlement of these derivative instruments will be collected from or refunded to customers.

Nonregulated Segments

The derivatives in the nonregulated segments not designated as hedges are primarily commodity contracts used to manage price risk associated with natural gas purchase and sale activities, electric energy contracts, and foreign currency contracts used to manage foreign currency exposure related to our nonregulated Canadian businesses. In addition, PDI entered into a series of derivative contracts (options) covering a specified number of barrels of oil in order to manage exposure to the risk of an increase in oil prices that could reduce the amount of Section 29 tax credits that can be recognized from PDI's investment in a synthetic fuel production facility. See Note 11, "Commitments and Contingencies," for more information. Changes in the fair value of non-hedge derivatives are recognized currently in earnings.

Certain reclassifications have been made between risk management assets and risk management liabilities in the accompanying Consolidated Balance Sheets as of March 31, 2005 and December 31, 2004 to conform the presentation to the presentation of risk management assets and liabilities made in the June 30, 2005 Quarterly Report on Form 10-Q. The reclassifications relate to the balance sheet presentation of certain non-hedge derivatives, which have offsetting positions within ESI. Compared to the amounts previously reported, these reclassifications decreased both current assets and current liabilities by $82.8 million and $63.0 million at March 31, 2005 and December 31, 2004, respectively. The reclassifications decreased both noncurrent assets and noncurrent liabilities by $11.8 million and $5.8 million at March 31, 2005 and December 31, 2004, respectively. The reclassifications had no impact on previously reported shareholders' equity, results of operations or cash flows.

Our nonregulated segments also enter into derivative contracts that are designated as either fair value or cash flow hedges. Fair value hedges are used to mitigate the risk of changes in the price of natural gas

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held in storage. The changes in the fair value of these hedges are recognized currently in earnings, as are the changes in fair value of the hedged items. Fair value hedge ineffectiveness recorded in nonregulated revenue on the Consolidated Statements of Income was not significant for the three months ended March 31, 2005, and 2004. At March 31, 2005, a pre-tax mark-to-market loss of $2.2 million related to the changes in the difference between the spot and forward prices of natural gas was excluded from the assessment of hedge effectiveness. This loss was reported directly in earnings.

Cash flow hedges consist of commodity contracts associated with our energy marketing activities and an interest rate swap. The commodity contracts extend through December 2006 and are used to mitigate the risk of cash flow variability associated with the future purchases and sales of natural gas and electricity. To the extent they are effective, the changes in the values of these contracts are included in other comprehensive income, net of deferred taxes. Cash flow hedge ineffectiveness recorded in nonregulated revenue on the Consolidated Statements of Income was not significant for the three months ended March 31, 2005, and 2004. When testing for effectiveness, no portion of the derivative instruments was excluded. Amounts recorded in other comprehensive income related to these cash flow hedges will be recognized in earnings as the related contracts are settled, if the hedge becomes ineffective, or if the hedged transaction is not probable of occurring. During the three months ended March 31, 2005, we reclassified a $0.8 million net-of-tax gain from other comprehensive income into earnings as a result of the discontinuance of cash flow hedge accounting for certain hedge transactions where it was probable that the original forecasted transaction would no longer occur. The amount reclassified during the three months ended March 31, 2004, was not significant. In the next 12 months, subject to changes in market prices of natural gas and electricity, we expect that a net-of-tax loss of $4.5 million will be recognized in earnings as contracts are settled.

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 used to finance the purchase of Sunbury. Because the swap was determined to be 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 a component of interest expense as the interest becomes due. In the next 12 months, we expect to recognize $1.5 million in expense, assuming interest rates comparable to those at March 31, 2005, and assuming the hedged transaction continues after Sunbury is sold. See Note 4, "Assets Held for Sale," for more information and an update on the sale of Sunbury. We did not exclude any components of the derivative instrument's change in fair value from the assessment of hedge effectiveness.

NOTE 4--ASSETS HELD FOR SALE

On May 23, 2005, PDI sold all of Sunbury's allocated emission allowances. Prior to this sale, PDI had marketed for sale the Sunbury plant and certain other related assets (primarily inventory and unallocated emission allowances) in combination with the emission allowances. The Sunbury facility sells power on a wholesale basis and previously provided energy for a 200-megawatt around-the-clock outtake contract that expired on December 31, 2004. Following Duquesne Power, L.P.'s September 2004 termination of the previously announced sales agreement to sell Sunbury to Duquesne for approximately $120 million, PDI had continued to pursue the sale of Sunbury with the assistance of an investment banking firm, but a suitable buyer was not found.

Total sales proceeds from the sale of Sunbury's emission allowances were $109.9 million, resulting in a pre-tax gain of $85.9 million, which was recorded in the second quarter of 2005. PDI is considering other alternatives for the Sunbury plant. It is anticipated that the Sunbury plant will be operated through August 2005, at which time PDI intends to place the plant in a stand-by mode of operation, which will minimize future operating expenses while maintaining several options (including retaining the plant and operating it during favorable economic periods or a potential future sale of the plant).

Prior to the decision to sell the emission allowances separately, the Sunbury plant, allocated emission allowances, and other related assets had been classified as held for sale as a combined asset disposal group, and Sunbury's results of operations and related cash flows had been reported as discontinued operations. However, because PDI is no longer committed to the sale of the Sunbury plant as its only

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option, generally accepted accounting principles require those assets and liabilities previously classified as held for sale that no longer meet the held for sale criteria outlined in SFAS No. 144, to be reclassified to the appropriate held and used categories for all periods presented. As a result, the allocated emission allowances that were sold in May 2005 remain classified as held for sale for all applicable periods presented, but the Sunbury plant, unallocated emission allowances, and other related assets and liabilities were reclassified as held and used. Furthermore, Sunbury's results of operations have been reclassified as components of continuing operations for all periods presented.

All long-lived assets reclassified as held and used were required to be recorded individually at the lower of their carrying value before they were classified as assets held for sale (adjusted for any depreciation expense that would have been recognized had they been continuously classified as held and used) or fair value at the date the held for sale criteria were no longer met. In the second quarter of 2005, upon reclassification of the Sunbury plant and related assets as held and used, PDI recorded a non-cash, pre-tax impairment charge of $80.6 million. The impairment charge substantially offsets the gain on the sale of the emission allowances.

The major classes of assets held for sale are as follows:

(Millions)	March 31, 2005	December 31, 2004
Property, plant, and equipment, net	$ 0.8	$ 0.8
Other assets (includes emission allowances)	23.2	23.3
Assets held for sale	$24.0	$24.1

PDI financed Sunbury with equity from WPS Resources and debt financing, including non-recourse debt and a related interest rate swap. The interest rate swap was designated as a cash flow hedge and, as a result, the mark-to-market loss of $7.0 million before tax was recorded as a component of other comprehensive income at March 31, 2005. WPS Resources is required to recognize the amount accumulated within other comprehensive income currently in earnings if management determines that the hedged transactions (i.e., future interest payments on the debt) will not continue after the sale. No such determination had been made at March 31, 2005, however, the debt was converted to a WPS Resources obligation in the second quarter of 2005 as a result of the sale of Sunbury's emission allowances. The conversion of the Sunbury debt to a WPS Resources' obligation triggered a $9.1 million pre-tax loss (the mark-to-market value of the swap at the date of conversion), which was recorded as a component of interest expense in the second quarter of 2005. This loss was previously deferred as a component of other comprehensive income pursuant to hedge accounting rules.

NOTE 5--ACQUISITIONS AND SALES OF ASSETS

Kewaunee Nuclear Power Plant

In 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 Kewaunee, Wisconsin Power and Light Company, also agreed to sell its 41% ownership interest in Kewaunee to Dominion. All of the major regulatory approvals related to this transaction have been obtained, including a written approval that was received from the PSCW in April 2005. We do not expect to close on the sale of Kewaunee until it returns to service following the unplanned outage that began in February 2005. See the Wisconsin section of Note 16, "Regulatory Environment," for additional information related to the Kewaunee outage.

WPSC estimates that its share of the cash proceeds from the sale will approximate $130 million, subject to various closing adjustments, including any potential adjustments related to the current outage. 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 pre-tax fair value of the non-qualified decommissioning trust's assets at March 31, 2005, was approximately $128 million. Dominion will assume responsibility for the eventual decommissioning of Kewaunee and will receive WPSC's qualified decommissioning trust assets that had a pre-tax fair value of approximately $243 million at March 31, 2005. WPSC has received approval from the PSCW for deferral

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of the gain or loss resulting from this transaction and related costs. 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 or recovered from customers under future rate orders.

As of March 31, 2005, WPSC's share of the carrying value of the assets and liabilities included within the sale agreement was as follows:

(Millions)	March 31, 2005
Property, plant, and equipment, net	$170.7
Qualified decommissioning trust fund	243.0
Other current assets	5.5
Total assets	$419.2
Regulatory liabilities	$ (63.1)
Asset retirement obligations	369.2
Total liabilities	$306.1

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 SFAS No. 144, because Kewaunee is not available for immediate sale in its present condition due to the unplanned outage.

Assuming the closing of the sale, WPSC will enter into a long-term power purchase agreement with Dominion to purchase energy and capacity virtually equivalent to the amounts that would have been received had current ownership in Kewaunee continued. The power purchase agreement 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 WPSC 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 WPSC's customers and reduce our risk profile. In April 2004, WPSC entered into an exclusivity agreement with Dominion. Under this agreement, if Dominion decides to extend the operating license of Kewaunee, Dominion agreed to negotiate only with WPSC for its share of the plant output for a new power purchase agreement that would extend beyond Kewaunee's current operating license termination date. This agreement allows for the same exclusivity rights for Wisconsin Power and Light and its share of output of the plant. The exclusivity period will start on the closing date of the sale and extend through December 21, 2011.

NOTE 6--GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill recorded by WPS Resources was $36.8 million at March 31, 2005, and December 31, 2004. Of this amount, $36.4 million is recorded in WPSC's natural gas segment relating to its merger with Wisconsin Fuel and Light. The remaining $0.4 million of goodwill relates to PDI.

Goodwill and purchased intangible assets are included in other assets on the Consolidated Balance Sheets. Emission credits are recorded at the lower of cost or market. Information in the tables below relates to total purchased identifiable intangible assets for the years indicated.

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(Millions)	March 31, 2005
Asset Class	Average Life (Years)	Gross Carrying Amount	Accumulated Amortization	Net
Emission allowances	1 to 30	$15.1	$(1.0)	$14.1
Customer related	1 to 8	11.2	(5.1)	6.1
Other	1 to 30	4.2	(1.6)	2.6
Total		$30.5	$(7.7)	$22.8
(Millions)	December 31, 2004
Asset Class	Average Life (Years)	Gross Carrying Amount	Accumulated Amortization	Net
Emission allowances	1 to 30	$15.8	$(0.9)	$14.9
Customer related	1 to 8	11.2	(4.6)	6.6
Other	1 to 30	4.2	(1.6)	2.6
Total		$31.2	$(7.1)	$24.1

Intangible asset amortization expense, in the aggregate, for the three months ended March 31, 2005, and March 31, 2004, was $0.6 million and $0.3 million, respectively. Amortization expense for the next five fiscal years is estimated as follows:

Estimated Future Amortization Expense:
For year ending December 31, 2005	$3.2 million
For year ending December 31, 2006	2.4 million
For year ending December 31, 2007	2.3 million
For year ending December 31, 2008	2.5 million
For year ending December 31, 2009	2.2 million

NOTE 7--SHORT-TERM DEBT AND LINES OF CREDIT

WPS Resources has a syndicated $225 million 364-day revolving credit facility and a $175 million 364-day bi-lateral loan agreement. WPSC has syndicated a $115 million 364-day revolving credit facility to provide short-term borrowing flexibility and security for commercial paper outstanding.

The information in the table below relates to WPS Resources' short-term debt and lines of credit as of the time periods indicated.

(Millions)	March 31, 2005	December 31, 2004
Commercial paper outstanding	$202.9	$279.7
Average discount rate on outstanding commercial paper	2.90%	2.46%
Short-term notes payable outstanding	$12.7	$12.7
Average interest rate on short-term notes payable	2.95%	2.52%
Available under lines of credit	$232.0	$161.9

The commercial paper had varying maturity dates ranging from April 4 through 15, 2005.

The information in the table below relates to WPSC's short-term debt and lines of credit as of the time periods indicated.

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(Millions)	March 31, 2005	December 31, 2004
Commercial paper outstanding	$91.0	$91.0
Average discount rate on outstanding commercial paper	2.89%	2.44%
Short-term notes payable outstanding	$10.0	$10.0
Average interest rate on short-term notes payable	2.67%	2.26%
Available under lines of credit	$20.2	$20.2

The commercial paper had varying maturity dates ranging from April 8 through 15, 2005.

NOTE 8--LONG-TERM DEBT

(Millions)			March 31, 2005	December 31, 2004
First mortgage bonds - WPSC
	Series 6.90% 7.125%	Year Due 2013 2023	$ 22.0 0.1	$ 22.0 0.1
Senior notes - WPSC
	Series 6.125% 4.875% 4.80% 6.08%	Year Due 2011 2012 2013 2028	150.0 150.0 125.0 50.0	150.0 150.0 125.0 50.0
First mortgage bonds - UPPCO
	Series 9.32%	Year Due 2021	15.3	15.3
Unsecured senior notes - WPS Resources
	Series 7.00% 5.375%	Year Due 2009 2012	150.0 100.0	150.0 100.0
Term loans - nonrecourse, collateralized by nonregulated assets			81.5	82.3
Tax exempt bonds			27.0	27.0
Senior secured note			2.7	2.7
Total			873.6	874.4
Unamortized discount and premium on bonds and debt			(2.0)	(2.0)
Total long-term debt			871.6	872.4
Less current portion			(6.7)	(6.7)
Total long-term debt			$864.9	$865.7

NOTE 9--ASSET RETIREMENT OBLIGATIONS

Legal retirement obligations, as defined by the provisions of SFAS No. 143, "Accounting for Asset Retirement Obligations," identified at WPSC relate primarily to the final decommissioning of Kewaunee. WPSC has a legal obligation to decommission the irradiated portions of Kewaunee in accordance with the Nuclear Regulatory Commission's minimum decommissioning requirements. The liability, calculated under the provisions of SFAS No. 143, is based on several 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 PSCW to calculate the nuclear decommissioning liability for funding purposes. In accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," WPSC established a regulatory liability to record the differences between ongoing expense recognition under SFAS No. 143 and the ratemaking practices for retirement costs authorized by the PSCW. As of March 31, 2005, the net-of-tax market

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value of external nuclear decommissioning trusts established for future retirement costs, authorized by the PSCW, was approximately $345 million. See Note 5, "Acquisitions and Sales of Assets," for information on the pending sale of Kewaunee.

PDI has identified a legal retirement obligation related to the closure of an ash basin located at Sunbury.

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

(Millions)	WPSC	PDI	Total
Asset retirement obligation at December 31, 2004	$364.4	$2.2	$366.6
Accretion expense	5.2	0.1	5.3
Asset retirement obligation at March 31, 2005	$369.6	$2.3	$371.9

NOTE 10--INCOME TAXES

For the quarters ended March 31, 2005, and 2004, WPS Resources' provision for income taxes was calculated in accordance with APB Opinion No. 28, "Interim Financial Reporting." Accordingly, our interim effective tax rate reflects our projected annual effective tax rate. The effective tax rate differs from the federal tax rate of 35%, primarily due to the effects of tax credits and state income taxes.

NOTE 11--COMMITMENTS AND CONTINGENCIES

Commodity and Purchase Order Commitments

WPS Resources routinely enters into long-term purchase and sale commitments that have various quantity requirements and durations. The commitments described below are as of March 31, 2005.

ESI has unconditional purchase obligations related to energy supply contracts that total $2.8 billion. Substantially all of these obligations end by 2009, with obligations totaling $9.3 million extending from 2010 through 2012. The majority of the energy supply contracts are to meet ESI's obligations to deliver energy to its customers.

WPSC has obligations related to nuclear fuel, coal, purchased power, and natural gas. Nuclear fuel contracts total $37.1 million and extend through 2014. Assuming Kewaunee is sold (see Note 5, "Acquisitions and Sales of Assets," for a discussion of the pending sale), these nuclear fuel contracts would be assigned to Dominion. Obligations related to coal supply and transportation extend through 2016 and total $370.3 million. Through 2016, WPSC has obligations totaling $619.1 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 $133.8 million through 2010. WPSC expects to recover these costs in future customer rates. Additionally, WPSC has contracts to sell electricity and natural gas to customers.

PDI has entered into purchase contracts totaling $10.4 million. The majority of these contracts relate to coal purchases for Sunbury and expire in 2008. See Note 4, "Assets Held for Sale," for more information on Sunbury.

UPPCO has made commitments for the purchase of commodities, mainly capacity or energy related to purchased power, which total $33.5 million and extend through 2010.

WPS Resources also has commitments in the form of purchase orders issued to various vendors. At March 31, 2005, these purchase orders totaled $566.6 million and $558.2 million for WPS Resources and WPSC, respectively. The majority of these commitments relate to large construction projects, including construction of the 500-megawatt Weston 4 coal-fired generation facility near Wausau, Wisconsin.

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Nuclear Plant Operation

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 WPSC 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 relate to WPSC's 59% ownership in Kewaunee.

Clean Air Regulations

Most of the generation facilities of PDI are located in an ozone transport region. As a result, these generation facilities are subject to additional restrictions on emissions of nitrogen oxide. During 2005, no additional nitrogen oxide emission allowances have been purchased and no additional allowance purchases are anticipated for 2005. PDI began 2005 with 17,000 sulfur dioxide emission allowances for its generation facilities that are required to participate in the sulfur dioxide emission program. During 2005, PDI estimates purchasing approximately 10,000 sulfur dioxide allowances in total, at market rates, to meet its 2005 requirements for its Sunbury generation facility.

EPA Section 114 Request

In November 1999, the EPA 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 utilities. In these enforcement proceedings, the EPA claims that the utilities made modifications to the coal-fired boilers and related equipment at the utilities' electric generation stations without first obtaining appropriate permits under the EPA's pre-construction permit program and without installing appropriate air pollution control equipment. In addition, the EPA 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, WPSC received from the EPA a request for information under Section 114 of the Clean Air Act. The EPA sought information and documents relating to work performed on the coal-fired boilers located at WPSC's Pulliam and Weston electric generation stations. WPSC filed a response with the EPA in early 2001.

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

In 2000 and 2002, Wisconsin Power and Light Company received a similar series of EPA information requests relating to work performed on certain coal-fired boilers and related equipment at the Columbia generation station (a facility located in Portage, Wisconsin, jointly owned by Wisconsin Power and Light Company, Madison Gas and Electric Company, and WPSC). Wisconsin Power and Light Company is the operator of the plant and is responsible for responding to governmental inquiries relating to the operation of the facility. Wisconsin Power and Light Company filed its most recent response for the Columbia facility on July 12, 2002.

Depending upon the results of the EPA's review of the information, the EPA may issue "notices of violation" or "findings of violation" asserting that a violation of the Clean Air Act occurred and/or seek additional information from WPSC and/or third parties who have information relating to the boilers or close out the investigation. To date, the EPA has not responded to the filings made by WPSC and Wisconsin Power and Light. In addition, under the federal Clean Air Act, citizen groups may pursue a claim. WPSC has received no notice of a claim from a citizen suit.

In response to the EPA Clean Air Act enforcement initiative, several utilities have elected to settle with the EPA, while others are in litigation. In general, those utilities that have settled have entered into consent

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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 $44 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 WPSC and if it were determined by a court that historic projects at WPSC's Pulliam and Weston plants required either a state or federal Clean Air Act permit, WPSC may, under the applicable statutes, be required to:

• shut down any unit found to be operating in non-compliance,
• install additional pollution control equipment,
• pay a fine, and/or
• pay a fine and conduct a supplemental environmental project in order to resolve any such claim.

At the end of December 2002 and October 2003, the EPA issued new rules governing the federal new source review program. These rules are currently being challenged in the District of Columbia Circuit Court of Appeals, and a final decision is not anticipated before May of 2005. 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 Wisconsin rules are not anticipated to be finalized before 2006, after the District of Columbia Circuit Court of Appeals' decision is rendered.

Mercury and Interstate Quality Rules

On October 1, 2004, the mercury emission control rule became effective in Wisconsin. The rule requires WPSC to control annual system mercury emissions in phases. The first phase will occur in 2008 and 2009. In this phase, the annual mercury emissions are capped at the average annual system mercury emissions for the period 2002 through 2004. The next phase will run from 2010 through 2014 and requires a 40% reduction from average annual 2002 through 2004 mercury input amounts. After 2015, a 75% reduction is required with a goal of an 80% reduction by 2018. Because federal regulations were promulgated in March 2005, we believe the state of Wisconsin will revise the Wisconsin rule to be consistent with the federal rule. However, the state of Wisconsin has filed suit against the federal government along with other states in opposition to the rule. WPSC estimates capital costs of approximately $101 million to achieve the proposed 75% reductions. The capital costs are expected to be recovered in a future rate case.

In December 2003, the EPA proposed mercury "maximum achievable control technology" standards and an alternative mercury "cap and trade" program substantially modeled on the Clear Skies legislation initiative. The EPA also proposed the Clean Air Interstate Rule (formerly known as the Interstate Air Quality Rule), which would reduce sulfur dioxide and nitrogen oxide emissions from utility boilers located in 29 states, including Wisconsin, Michigan, Pennsylvania, and New York. In March 2005, the EPA finalized both the mercury rule and the Clean Air Interstate Rule.

The final mercury rule establishes New Source Performance Standards for new units based upon the type of coal burned. Weston 4 will install and operate mercury control technology with the aim of achieving a mercury emission rate less than that in the final EPA mercury rule.

The final mercury rule also establishes a mercury cap and trade program. The mercury cap and trade program requires a 21% reduction in national mercury emissions in 2010 and a 70% reduction in national

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mercury emissions beginning in 2018. Based on the final rule and current projections, WPSC anticipates meeting the mercury rule cap and trade requirements at a cost similar to the cost to comply with the Wisconsin rule.

PDI's current analysis indicates that additional emission control equipment on its existing units may be required. Excluding Sunbury, PDI estimates the capital cost for the remaining units to be approximately $1 million to achieve a 70% reduction. Including Sunbury, the total PDI mercury control costs could approximate $33 million in total, depending upon how this facility is operated. See Note 4, "Assets Held for Sale," for more information on Sunbury.

The final Clean Air Interstate Rule requires reduction of sulfur dioxide and nitrogen oxide emissions in two phases. The first phase requires about a 50% reduction beginning in 2009 for nitrogen oxide, and 2010 for sulfur dioxide. The second phase begins in 2015 for both pollutants and requires about a 65% reduction in emissions. The rule allows the affected states (including Wisconsin, Michigan, Pennsylvania, and New York) to either require utilities located in the state to participate in the EPA's interstate cap and trade program or meet the state's emission budget for sulfur dioxide and nitrogen oxide through measures to be determined by the state. The states have not adopted a preference as to which option they would select, but the states are investigating the cap and trade program, as well as alternatives or additional requirements. Consequently, the effect of the rule on WPSC's and PDI's facilities is uncertain, since it depends upon how the states choose to implement the final Clean Air Interstate Rule.

Currently, WPSC is evaluating a number of options that include using the cap and trade program and/or installing controls. For planning purposes, it is assumed that additional sulfur dioxide and nitrogen oxide controls will be needed on existing units or the existing units will need to be converted to natural gas by 2010. The installation of any controls and/or any conversion to natural gas will need to be scheduled as part of WPSC's long-term maintenance plan for its existing units. As such, controls or conversions may need to take place before 2010. On a preliminary basis and assuming controls or conversion are required, WPSC estimates capital costs of $246 million in order to meet an assumed 2010 compliance date. This estimate is based on costs of current control technology and current information regarding the final EPA rule. The costs may change based on the requirements of the final state rules.

PDI is evaluating the compliance options for the Clean Air Interstate Rule. Additional nitrogen oxide controls on some of PDI's facilities may be necessary. The estimated capital costs for additional nitrogen oxide controls are $2.9 million, excluding Sunbury. Additional sulfur dioxide reductions are unlikely. Including Sunbury, the additional nitrogen oxide control costs could increase to about $41 million in total, but are largely dependent upon how the facility will be operated going forward. Also, PDI will evaluate a number of options using the cap and trade program, fuel switching, and/or installing controls. See Note 4, "Assets Held for Sale," for more information on Sunbury.

Other Environmental Issues

Groundwater testing at a former ash disposal site of UPPCO indicated elevated levels of boron and lithium. Supplemental remedial investigations were performed, and a revised remedial action plan was developed. The Michigan Department of Environmental Quality approved the plan in January 2003. UPPCO received an order from the MPSC permitting deferral and future recovery of these costs. A liability of $1.4 million and an associated regulatory asset of $1.4 million were recorded for estimated future expenditures associated with remediation of the site. UPPCO has an informal agreement, with the owner of another landfill, under which UPPCO has agreed to pay 17% of the investigation and remedial costs. It is estimated that the cost of addressing the site over the next 3 years is $1.6 million. UPPCO has recorded $0.3 million of this amount as its share of the liability as of March 31, 2005.

Manufactured Gas Plant Remediation

WPSC 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, Manitowoc, and two Sheboygan sites was substantially complete. Groundwater treatment and monitoring at these sites will continue into the future. Cleanup of the land portion of four sites will be addressed in the future. River

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sediment remains to be addressed at six sites with sediment contamination. Remedial investigation work is expected to begin on the sediment portion of the Sheboygan site in 2005. Work at the other sites remains to be scheduled.

WPSC is currently in the process of transferring sites with sediment contamination formally under WDNR jurisdiction to the EPA Superfund Alternatives Program. Under the EPA's program, the remedy decision will be based on risk-based criteria typically used at Superfund sites. WPSC estimated future undiscounted investigation and cleanup costs as of March 31, 2005, to be $66.4 million. WPSC may adjust these estimates in the future contingent upon remedial technology, regulatory requirements, remedy determinations, and the assessment of natural resource damages. WPSC has received $12.7 million to date in insurance recoveries. WPSC expects to recover actual cleanup costs, net of insurance recoveries, in future customer rates. Under current PSCW policies, WPSC will not recover carrying costs associated with the cleanup expenditures.

Stray Voltage Claims

From time to time, WPSC has been sued by dairy farmers who allege that they have suffered loss of milk production and other damages supposedly due to "stray voltage" from the operation of WPSC's electrical system. Past cases have been resolved without any material adverse effect on the financial statements of WPSC. Currently, there are three such cases pending in state court in Wisconsin. Of the remaining three cases, one is in trial, one was tried in September 2004 but ended in a mistrial, and one is on appeal following a trial. A fourth case was settled within WPSC's self-insured retention.

The PSCW has established certain requirements regarding stray voltage for all utilities subject to its jurisdiction. The PSCW has defined what constitutes "stray voltage," established a level of concern at which some utility corrective action is required, and set forth test protocols to be employed in evaluating whether a stray voltage problem exists. Based upon the information available to it to date, WPSC believes that it was in compliance with the PSCW's orders, and that none of the plaintiffs had a stray voltage problem as defined by the PSCW for which WPSC is responsible. Nonetheless, in 2003, the Supreme Court of Wisconsin ruled in the case Hoffmann v. WEPCO that a utility could be liable in tort to a farmer for damage from stray voltage even though the utility had complied with the PSCW's established level of concern.

One of the three pending cases, Russell Allen v. WPSC, was appealed to the Wisconsin Court of Appeals. On February 15, 2005, the Court of Appeals affirmed the jury verdict that awarded the plaintiff approximately $0.8 million for economic damages and $1 million for nuisance. The Court of Appeals also remanded to the trial court the issue of whether an injunction should be issued. WPSC has filed a Petition for Review with the Supreme Court of Wisconsin asking it to accept the case and reverse the damages awarded to the plaintiff. One of the other cases, Seidl v. WPSC, was tried to a jury in September 2004. In October 2004, the jury returned a verdict which was not in accordance with the law, resulting in a mistrial. WPSC has renewed its motion to dismiss the case for lack of proof of negligence, and that motion is pending before the trial judge. If the judge denies the motion, the Seidl case will be retried in October 2005. The other pending case, Pollack v. WPSC, began trial in April 2005. In these cases, the expert witnesses retained by WPSC do not believe that there is a scientific basis for concluding that electricity has harmed or damaged the plaintiffs or their cows. Accordingly, WPSC is vigorously defending and contesting these actions.

WPSC has insurance coverage for these claims, but the policies have customary self-insured retentions per occurrence. Based upon the information known at this time and the availability of insurance, WPSC believes that the total cost to it of resolving the remaining three actions will not be material.

The Pollack case includes a claim for common law punitive damages, as well as a claim for treble damages under a Wisconsin statute, sec. 196.94. In the Seidl case, the judge dismissed those claims as a matter of law for lack of supporting evidence. In the Allen case, the trial judge dismissed the statutory treble damages claim, and this dismissal has been affirmed by the Court of Appeals. In light of the information it now has, WPSC does not believe there is any basis for the award of punitive or treble damages in the remaining case. However, if a jury awarded such damages, and if the total of defense

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costs and all damages exceeded the self-insured retention, WPSC believes its insurance policies would cover such a verdict, including any punitive or treble damages.

Flood Damage

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

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

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

UPPCO has worked with federal and state agencies in their investigations. UPPCO is still in the process of investigating the incident. WPS Resources maintains a comprehensive insurance program that includes UPPCO and which provides both property insurance for its facilities and liability insurance for liability to third parties. WPS Resources is insured in amounts that it believes are sufficient to cover its responsibilities in connection with this event. Deductibles and self-insured retentions on these policies are not material to WPS Resources. To date no lawsuits have been commenced.

In November 2003, UPPCO received approval from the MPSC and the FERC for deferral of costs that are not reimbursable through insurance or recoverable through the power supply cost recovery mechanism. Recovery of costs deferred will be addressed in future rate proceedings.

In January 2005, UPPCO announced its decision to restore Silver Lake as a reservoir for power generation, pending approval of a design by FERC. Provided that FERC approves a design in the spring of 2005, work is expected to begin in 2005 and be completed in 2006.

Wausau, Wisconsin, to Duluth, Minnesota, Transmission Line

Construction of the 220-mile, 345-kilovolt Wausau, Wisconsin, to Duluth, Minnesota, transmission line began in the first quarter of 2004 with the Minnesota portion completed in early 2005. Construction in Wisconsin is scheduled to begin in August 2005.

ATC has assumed primary responsibility for the overall management of the project and will own and operate the completed line. WPSC received approval from the PSCW and the FERC to transfer ownership of the project to ATC. WPSC will continue to manage construction of the project and be responsible for obtaining private property rights in Wisconsin necessary for the construction of the project.

In December 2003, the PSCW issued an amended Certificate of Public Convenience and Necessity per ATC's request for relief. This decision was appealed to the Dane County Circuit Court by certain landowners. The court affirmed the PSCW's decision, and no appeal has been filed during the allowed time allotted for appeals. In addition, Douglas County in Wisconsin continues to oppose the line and refuses to engage in negotiations relating to easement access to county owned land for the project. As a result of this opposition, the PSCW reopened the docket and ordered the applicants to submit an amended application identifying alternative routes and other options for the project in Douglas County. In addition, various WDNR permit-related decisions are currently the subject of a contested case hearing in Wisconsin. A decision on the contested case is expected in the third quarter of 2005.

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WPS Resources committed to fund 50% of total project costs incurred up to $198 million. WPS Resources will receive additional equity in ATC in exchange for a portion of the project funding. During the quarter ended March 31, 2005, WPS Resources invested $8.8 million in ATC, 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, WPSC and ATC received approval from the PSCW to continue the project at a revised 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 equity portion of revised cost estimate. For the period of April 2005 through December 2008, we expect to fund up to approximately $170 million for our portion of the Wausau to Duluth transmission line. Our commitment to fund this transmission line could decrease up to 50% if another entity exercises its option to fund a portion of the project.

Synthetic Fuel Production Facility

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. Other future tax legislation and Internal Revenue Service review may also affect the value of the tax credits and the value of our share of the facility.

The Internal Revenue Code provides Section 29 tax credits as an incentive for taxpayers to produce fuels from alternate sources and reduce domestic dependence on imported oil. This incentive is not deemed necessary if the price of oil increases sufficiently to provide a natural market for these fuels. Therefore, the Section 29 tax credits are subject to phase out if domestic crude oil prices reach specified levels. Although we do not expect the amount of our 2005 Section 29 tax credits to be adversely affected by oil prices given the current forward price curve for crude oil, we cannot predict with any certainty the future price of a barrel of oil. Therefore, in order to manage exposure to the risk that an increase in oil prices could reduce the recognizable amount of 2005, 2006, and 2007 Section 29 tax credits, PDI entered into a series of derivative contracts (options) covering a specified number of barrels of oil. These derivatives were entered into in March and April 2005 and mitigate approximately 95%, 60%, and 40% of the Section 29 tax credit exposure related to rising oil prices in 2005, 2006, and 2007, respectively.

We have recorded the tax benefit of approximately $126.2 million of Section 29 tax credits as reductions to income tax expense from the project's inception in June 1998 through March 31, 2005. As a result of alternative minimum tax rules, approximately $71.7 million of this tax benefit has been carried forward as a deferred tax asset as of March 31, 2005. 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 our 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 is 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.

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Dairyland Power Cooperative

Dairyland Power Cooperative has confirmed its intent to purchase a 30% interest in Weston 4 by signing a joint plant agreement in November 2004, subject to a number of conditions. The agreement with Dairyland Power Cooperative is part of our continuing plan to provide least-cost, reliable energy for the increasing electric demand of our customers.

NOTE 12--EMPLOYEE BENEFIT PLANS

The following table provides the components of net periodic benefit cost for WPS Resources' benefit plans for the three months ended March 31:

WPS Resources	Pension Benefits		Other Benefits
(Millions)	2005	2004	2005	2004
Net periodic benefit cost
Service cost	$ 6.2	$ 5.1	$2.0	$2.0
Interest cost	10.1	9.7	4.2	4.3
Expected return on plan assets	(10.9)	(10.6)	(3.1)	(2.8)
Amortization of transition obligation	-	-	0.1	0.1
Amortization of prior-service cost (credit)	1.4	1.4	(0.6)	(0.6)
Amortization of net loss	2.0	1.0	1.1	1.5
Net periodic benefit cost	$ 8.8	$ 6.6	$3.7	$4.5

WPSC's share of net periodic benefit cost for the three months ended March 31 is included in the table below:

WPSC	Pension Benefits		Other Benefits
(Millions)	2005	2004	2005	2004
Net periodic benefit cost
Service cost	$4.9	$4.1	$1.8	$1.8
Interest cost	8.4	8.1	3.8	3.9
Expected return on plan assets	(9.6)	(9.4)	(3.0)	(2.7)
Amortization of transition obligation	-	-	0.1	0.1
Amortization of prior-service cost (credit)	1.2	1.3	(0.5)	(0.5)
Amortization of net loss	1.4	0.4	0.9	1.2
Net periodic benefit cost	$6.3	$4.5	$3.1	$3.8

Contributions to the plans are made in accordance with legal and tax requirements, and contributions do not necessarily occur evenly throughout the year. For the three months ended March 31, 2005, $3.0 million of contributions were made to the pension benefit plan and no contributions were made to the other postretirement benefit plans. WPS Resources expects to contribute an additional $5.3 million to its pension plans and $21.9 million to its other postretirement benefit plans in 2005.

NOTE 13--STOCK-BASED COMPENSATION

WPS Resources has three main stock-based compensation plans: the 2001 Omnibus Incentive Compensation Plan ("Omnibus Plan"), the 1999 Stock Option Plan ("Employee Plan"), and the 1999 Non-Employee Directors Stock Option Plan ("Director Plan"). No additional stock options will be issued under the Employee Plan, although the plan will continue to exist for purposes of the existing outstanding options.

WPS Resources accounts for these plans under the recognition and measurement principles of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. Upon grant of stock options, no stock-based employee compensation cost is reflected in net income, as all options granted under these plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on income available for common shareholders and earnings per share if the company had applied the fair value

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recognition provisions of SFAS No. 123, "Accounting for Stock-Based Compensation," to stock-based employee compensation:

	Three Months Ended March 31,
(Millions, except per share amounts)	2005	2004
Income available for common shareholders
As reported	$65.9	$42.6
Add: Stock-based compensation expense using the intrinsic   value method - net of tax	0.4	0.4
Deduct: Stock-based compensation expense using the fair   value method - net of tax	(0.4)	(0.3)
Pro forma	$65.9	$42.7
Basic earnings per common share
As reported	$1.74	$1.15
Pro forma	1.74	1.15
Diluted earnings per common share
As reported	$1.73	$1.14
Pro forma	1.73	1.14

NOTE 14--COMPREHENSIVE INCOME

SFAS No. 130, "Reporting Comprehensive Income," requires the reporting of other comprehensive income in addition to income available for common shareholders. Total comprehensive income includes all changes in equity during a period except those resulting from investments by shareholders and distributions to shareholders. WPS Resources' total comprehensive income is:

	Three Months Ended March 31,
(Millions)	2005	2004
Income available for common shareholders	$65.9	$42.6
Cash flow hedges, net of tax of $(8.7) and $2.9	(13.6)	4.2
Foreign currency translation	(0.7)	-
Unrealized gain on available-for-sale securities,   net of tax of $0.1	0.2	-
Total comprehensive income	$51.8	$46.8

The following table shows the changes to Accumulated Other Comprehensive Income from December 31, 2004, to March 31, 2005.

(Millions)
December 31, 2004 balance	$(16.1)
Cash flow hedges	(13.6)
Foreign currency translation adjustment	(0.7)
Unrealized gain on available-for-sale securities	0.2
March 31, 2005 balance	$(30.2)

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NOTE 15--EARNINGS PER SHARE

WPS Resources' common stock shares, $1 par value	March 31, 2005	December 31, 2004
Common stock outstanding, $1 par value, 200,000,000 shares authorized	37,815,206	37,500,791
Treasury shares	12,000	12,000
Average cost of treasury shares	$25.19	$25.19
Shares in deferred compensation rabbi trust	262,658	229,238
Average cost of deferred compensation rabbi trust shares	$39.79	$36.84

Earnings per share is computed by dividing income available for common shareholders by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share is computed by dividing income available for common shareholders by the weighted average number of shares of common stock outstanding during the period adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive items include in-the-money stock options, restricted shares, and performance share grants. The calculation of diluted earnings per share for the years shown excludes some stock option plan shares that had an anti-dilutive effect. The shares having an anti-dilutive effect are not significant for any of the periods shown. The following table reconciles the computation of basic and diluted earnings per share:

Reconciliation of Earnings Per Share	Three Months Ended March 31,
(Millions, except per share amounts)	2005	2004
Income available to common shareholders	$65.9	$42.6
Basic weighted average shares	37.8	37.1
Incremental issuable shares	0.3	0.2
Diluted weighted average shares	38.1	37.3
Basic earnings per common share	$1.74	$1.15
Diluted earnings per common share	$1.73	$1.14

NOTE 16--REGULATORY ENVIRONMENT

Wisconsin

On November 5, 2004, WPSC filed an application with the PSCW to defer all incremental costs, including carrying costs, resulting from unexpected problems encountered in the 2004 refueling outage at Kewaunee. During the refueling outage, an unexpected problem was encountered with equipment used for lifting internal vessel components to perform a required 10-year inspection. These equipment problems caused the outage to be extended by approximately three weeks. On November 11, 2004, the PSCW authorized WPSC to defer the replacement fuel costs related to the extended outage. On November 23, 2004, the PSCW authorized WPSC to defer purchased power costs ($5.6 million) and operating and maintenance expenses ($1.6 million) related to the extended outage, effective from when the problems were discovered, including carrying costs at WPSC's authorized weighted average cost of capital. Kewaunee returned to service on December 4, 2004. On February 18, 2005, WPSC filed for PSCW approval to recover these costs, and the PSCW determined that costs associated with this outage will be addressed in the 2006 rate case.

On February 20, 2005, Kewaunee was temporarily removed from service after a potential design weakness was identified in its auxiliary feedwater system. Plant engineering staff identified the concern and the unit was shut down 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 the end of May 2005. WPSC filed a request with the PSCW on March 11, 2005, for deferral of replacement power and operating and maintenance expenses incurred to address the design weakness and engineering issues identified. On April 8, 2005, the PSCW approved deferral of these costs, including carrying costs at the most recently authorized pre-tax weighted average cost of capital. Under the formula rate mechanism, recovery of costs for our wholesale market-based rate customers generally follows the Wisconsin retail

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methodology. For our Michigan retail customers, fuel costs are recovered through a pass through fuel adjustment clause and no deferral request is anticipated. As of March 31, 2005, WPSC deferred $14.7 million of replacement power costs and $1.1 million of operating and maintenance expenses. WPSC anticipates the PSCW will address recovery of the deferred costs in the 2006 rate case. WPSC and Dominion remain committed to the sale of Kewaunee.

On April 1, 2005, WPSC filed an application with the PSCW for an 11.4% increase in retail electric rates ($89.7 million in revenues) and a 2.09% increase in natural gas rates ($10.0 million in revenues), both to be effective January 1, 2006. Factors impacting the requested 2006 retail electric rate increase include costs of transmission, costs for the construction of Weston 4, and increased purchased power costs. The natural gas rate increase is primarily related to increases in environmental monitoring costs and the cost of distribution system improvements. The PSCW's approval of the Kewaunee plant sale could reduce these requested rate increases.

The amount of fuel and purchased power costs WPSC is authorized to recover in rates is established in its general rate filings. If the actual fuel and purchased power costs vary from the authorized level by more than 2% on an annualized basis, WPSC is allowed, or may be required, to file an application adjusting rates for the remainder of the year to reflect revised annualized cost estimates. At March 31, 2005, excluding the impact of the Kewaunee outage (which was deferred), WPSC was experiencing actual fuel and purchased power costs that were more than 2% lower than the currently approved level. As a result, the PSCW reopened WPSC's 2005 rate case for recovery of these costs on April 14, 2005. Therefore, revenues collected after that date are subject to refund pending a review of projected fuel costs for 2005. Rates will be adjusted downward for the balance of the year if projected costs are deemed to be more than 2% less than the amount allowed in the 2005 rate case.

Michigan

On December 8, 2004, UPPCO submitted a request to the MPSC to approve UPPCO's proposed treatment of the pre-tax gains from certain sales of undeveloped and partially developed land located in the Upper Peninsula of Michigan as appropriate for ratemaking purposes. On April 28, 2005, the MPSC issued an order authorizing UPPCO to retain 100% of the pre-tax gains on certain lands owned up to $18.5 million and 73% of any pre-tax gains over that amount. In addition, UPPCO will voluntarily forego filing for retail electric service base rate increases until January 1, 2006, except UPPCO may file for MPSC consideration of deferred accounting of any governmental mandates during the moratorium and for any unusual and extraordinary events that would cause serious financial harm to UPPCO. Further, UPPCO's Power Supply Cost Recovery Clause is not subject to the filing moratorium.

On February 4, 2005, UPPCO submitted an application to the MPSC for a 7.6% increase in retail electric rates ($5.7 million in revenues). UPPCO also requested interim rate recovery of 6.0% ($4.5 million in revenues) to allow UPPCO to recover costs during the time the MPSC is reviewing the full case. The retail electric rate increase was required due to costs associated with improving service quality and reliability, technology upgrades, and managing rising employee and retiree benefit costs. Barring any appeals of the order issued by the MPSC on April 28, 2005, UPPCO will withdraw this rate case and not re-file before January 1, 2006.

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Federal

On February 10, 2005, the FERC issued an order accepting compliance filings implementing the Seams Elimination Charge Adjustment (SECA) effective December 1, 2004, subject to refund and surcharge, as appropriate, and setting the case in its entirety for a formal hearing. The purpose of the SECA is to compensate transmission owners (during the 16-month transition period) for revenues they would no longer receive due to the elimination of the Regional Through and Out Rates. Because ESI is a load serving entity, it is subject to the SECA charges. 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 hearing. ESI has actively participated in the SECA case since its beginning and believes its position has strong merits. On February 28, 2005, ESI filed a motion for Partial Stay of FERC's February 10, 2005, order, proposing that SECA charges on its Michigan load be postponed until a FERC order approves a decision or settlement in the formal hearing proceeding. The FERC has not yet ruled on this motion.

The SECA is also an issue for WPSC and UPPCO, who have intervened in this docket since some of the current proposals could result in unjustifiable higher rates for customers. It is anticipated that most of the SECA charges incurred by WPSC and UPPCO will be recoverable in customer rates.

NOTE 17--SEGMENTS OF BUSINESS

We manage our reportable segments separately due to their different operating and regulatory environments. Our utility business segments are the regulated electric utility operations of WPSC and UPPCO and the regulated gas utility operations of WPSC. Our other reportable segments include two nonregulated companies, ESI and PDI. ESI is a diversified energy supply and services company. PDI is an electric generation company. The Other segment includes the operations of WPS Resources and WPS Resources Capital Corporation as holding companies, along with the nonutility activities at WPSC and UPPCO.

	Regulated Utilities			Nonutility and Nonregulated Operations
Segments of Business (Millions)	Electric Utility(1)	Gas Utility(1)	Total Utility(1)	ESI	PDI	Other	Reconciling Eliminations	WPS Resources Consolidated
Three Months Ended March 31, 2005
External revenues	$236.4	$174.5	$410.9	$1,032.9	$43.1	$ -	$ -	$1,486.9
Intersegment revenues	7.6	0.1	7.7	1.5	9.3	0.3	(18.8)	-
Income available for  common shareholders	23.5	14.0	37.5	11.7	16.5	0.2	-	65.9
Three Months Ended March 31, 2004
External revenues	$217.2	$169.5	$386.7	$973.7	$26.6	$ -	$ -	$1,387.0
Intersegment revenues	5.7	4.1	9.8	2.4	5.8	0.3	(18.3)	-
Income available for  common shareholders	18.2	13.6	31.8	12.1	(1.0)	(0.3)	-	42.6

(1) Includes only utility operations. Nonutility operations are included in the Other column.

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WPSC's principal business segments are the regulated electric utility operations and the regulated gas utility operations.

	Regulated Utilities
Segments of Business (Millions)	Electric Utility(1)	Gas Utility(1)	Total Utility	Other	Reconciling Eliminations	WPSC  Consolidated
Three Months Ended March 31, 2005
External revenues	$219.8	$174.6	$394.4	$0.4	$(0.4)	$394.4
Earnings on common stock	22.4	14.0	36.4	1.2	-	37.6
Three Months Ended March 31, 2004
External revenues	$198.4	$173.6	$372.0	$0.4	$(0.4)	$372.0
Earnings on common stock	16.6	13.6	30.2	2.3	-	32.5

(1) Includes only utility operations.Nonutility operations are included in the Other column.

NOTE 18--NEW ACCOUNTING PRONOUNCEMENTS

In December 2004, the FASB issued SFAS No. 123R, "Share-Based Payment," which addresses the accounting for share-based payment transactions. SFAS No. 123R eliminates the ability to account for share-based compensation transactions using APB Opinion No. 25, "Accounting for Stock Issued to Employees," and requires a company to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions). That cost is recognized over the period during which an employee is required to provide service in exchange for the award. SFAS No. 123R will be effective for WPS Resources on January 1, 2006. SFAS No. 123R offers companies alternative methods of adopting this standard. The impact on WPS Resources' financial position and results of operations will be dependent upon a number of factors, including share-based payments made in 2006. Because we do not know the amount of share-based payments to be made in 2006, we cannot yet estimate the effect of this standard on our financial position and results of operations.

In March 2005, the FASB issued FASB Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations." Interpretation No. 47 clarifies that the term Conditional Asset Retirement Obligation as used in FASB Statement No. 143, "Accounting for Asset Retirement Obligation," refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Accordingly, an entity is required to recognize a liability for the fair value of a Conditional Asset Retirement Obligation if the fair value of the liability can be reasonably estimated. WPS Resources is required to adopt the provisions of Interpretation No. 47 on December 31, 2005. WPS Resources has not yet determined the impact that the adoption of Interpretation No. 47 will have on its financial position or results of operations.

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