-13-

~~nine months ended September 30, 2005, and 2004. At September 30, 2005, a pre-tax mark-to-market loss of $5.1~~$2.8 million, related to changes in the difference between the spot and forward prices of natural gas ~~was~~were excluded from the assessment of hedge effectiveness. ~~This loss was~~These losses were reported directly in earnings. ~~The amount excluded from the assessment of hedge effectiveness at December 31, 2004, was not significant.~~

Commodity contracts that are designated as cash flow hedges extend through ~~October 2007~~March 2009 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 Condensed Consolidated Statements of Income related to commodity contracts was not significant for the ~~nine~~three months ended ~~September 30, 2005,~~March 31, 2006, and ~~2004.~~2005. 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 it is probable that the hedged transaction will not occur. During the ~~nine~~three months ended ~~September 30, 2005, and September 30, 2004, we~~March 31, 2006, the amount reclassified ~~a $3.1 million and a $2.8 million net-of-tax gain, respectively,~~ from other comprehensive income into earnings as a result of the discontinuance of cash flow hedge accounting for certain hedge ~~transactions.~~transactions related to commodity contracts was not significant. During the three months ended March 31, 2005, we reclassified a $0.8 million after-tax gain from other comprehensive income into earnings as a result of the discontinuance of cash flow hedge accounting for certain hedge transactions related to commodity contracts. In the next 12 months, subject to changes in market prices of natural gas and electricity, we expect that ~~a net-of-tax loss~~an after-tax gain of ~~$27.4~~$5.9 million will be recognized in earnings as contracts are settled. We expect this amount to be substantially offset by settlement of the related nonderivative ~~contracts.~~contracts that are being hedged.

In the second quarter of 2005, a variable rate non-recourse debt instrument used to finance the purchase of Sunbury was restructured to a WPS Resources variable rate obligation. An interest rate swap used to fix the interest rate on the Sunbury non-recourse debt ~~had been~~was previously designated as a cash flow hedge. As a result of the debt restructuring, the hedged transaction ~~will~~ no longer occur. This resulted in the recognition of a $9.1 million pre-tax loss (equivalent to the mark-to-market value of the swap at the date of restructuring), which was recorded as a component of interest expense in the second quarter of 2005. This loss was previously deferred as a component of other comprehensive income pursuant to hedge accounting rules.occurred. Subsequent to the restructuring, the interest rate swap was re-designated as a cash flow hedge, along with an additional interest rate swap, to fix the interest rate on the WPS Resources obligation. The changes in the fair value of the effective portion of these swaps are included in other comprehensive income, net of deferred taxes, while the changes related to the ineffective portion are recorded in earnings. During the ~~nine~~three months ended ~~September 30, 2005,~~March 31, 2006, cash flow hedge ineffectiveness recorded in earnings related to these swaps was not significant. Amounts recorded in other comprehensive income related to these swaps will be recognized as a component of interest expense as the interest becomes due. In the next 12 months, we expect to recognize ~~$0.1~~a $0.5 million inpre-tax reduction to interest expense related to these swaps, assuming interest rates comparable to those at ~~September 30, 2005.~~March 31, 2006. We did not exclude any components of the derivative instruments' change in fair value from the assessment of hedge effectiveness.

~~NOTE 4--ASSETS HELD FOR SALE~~

In the ~~second~~first quarter of ~~2005, PDI sold all~~2006, WPS Resources entered into a forward-starting swap with a ten-year term beginning in August 2006 with a notional amount of ~~Sunbury's allocated emission allowances. Prior~~$200 million to ~~this decision, PDI had marketed for sale~~hedge a portion of the ~~Sunbury plant and certain other related assets (primarily inventory and unallocated emission allowances) in combination~~interest rate risk associated with the ~~allocated emission allowances.~~planned issuance of fixed-rate, long-term debt securities in 2006. The ~~Sunbury facility sells power on a wholesale basis~~swap protects against the risk of changes in future interest payments resulting from changes in benchmark rates between the date of hedge inception 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 termination~~the date of the ~~previously announced agreement to sell Sunbury to Duquesne~~debt issuance. This derivative instrument qualifies for ~~approximately $120 million, PDI continued to pursue~~cash flow hedge treatment and is considered highly effective in hedging the ~~sale of Sunbury with~~benchmark interest rate risk on the ~~assistance of an investment banking firm, but~~forecasted debt issuance. As a ~~suitable buyer was not found.~~

~~Total sales proceeds from~~result, changes in the ~~sale of Sunbury's emission allowances were $109.9 million, resulting in a pre-tax gain of $85.9 million. The sale~~fair value of the ~~emission allowances provides PDI with more time to consider various alternatives for~~swap are recorded through other comprehensive income, net of taxes. The swap will be terminated when the ~~Sunbury plant. All available solid fuel units at~~related debt is issued, and amounts included in accumulated other comprehensive income will be reclassified into earnings as the ~~Sunbury plant were operated through September 30, 2005 due to favorable market conditions. Should market conditions decline, PDI will consider placing~~related interest expense on the ~~plant in a stand-by mode of operation, which serves to minimize~~debt accrues.

-14-

future operating expenses while maintaining several options (including closing the plant, 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 allocated 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 Sunbury as its only 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, "Accounting for the Impairment or Disposal of Long-Lived Assets," 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 were reclassified as components of continuing operations for all periods presented.

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

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

September 30,
December 31,
(Millions)

2005
2004
Property, plant, and equipment, net
$
0.8
$ 0.8
Other assets:
Emission allowances
-
23.3
Assets held for sale
$
0.8
$ 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. 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. Sunbury's non-recourse debt was restructured to a WPS Resources obligation in the second quarter of 2005 in conjunction with the sale of Sunbury's allocated emission allowances. The restructuring of the Sunbury non-recourse 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 the restructuring), which was recorded as a component of interest expense in the second quarter of 2005. This loss was previously deferred as a component of other comprehensive income pursuant to hedge accounting rules.

NOTE ~~5--ACQUISITIONS~~4--ACQUISITIONS AND SALES OF ASSETS

~~Agreement~~Sale of Kimball Storage Field

In April 2006, ESI sold WPS ESI Gas Storage, LLC, which owns a natural gas storage field located in the Kimball Township, St. Clair County, Michigan. ESI utilized this facility primarily for structured wholesale natural gas transactions as natural gas storage spreads presented arbitrage opportunities. ESI was not actively marketing this facility for sale, but believed the price being offered was above the value it would realize from continued ownership of the facility. Proceeds received in April from the sale of the Kimball natural gas storage field, stored gas, and other related assets were $19.9 million, which is expected to result in a pre-tax gain of approximately $9 million in the second quarter of 2006. The transaction is still subject to certain working capital and other post-closing adjustments.

Sale of Guardian Pipeline

On March 30, 2006, WPS Investments, LLC, a subsidiary of WPS Resources, entered into an agreement to sell its one-third interest in Guardian Pipeline, LLC to Northern Border Partners, LP for $38.5 million The transaction closed in April 2006, resulting in the recognition of a pre-tax gain of approximately $6 million in the second quarter of 2006. WPS Investments, LLC's one-third interest in Guardian Pipeline, LLC was accounted for using the equity method at March 31, 2006.

Purchase of Aquila's Michigan and Minnesota Natural Gas Distribution Operations

On September 21, 2005, WPS Resources, through wholly owned subsidiaries, entered into two definitive agreements with Aquila, Inc. (Aquila) to acquire ~~Aquila's~~its natural gas distribution operations in Michigan and Minnesota for approximately $558 million, exclusive of direct costs of the acquisition. The purchase price ~~also excludes~~will be adjusted for certain ~~adjustments related to~~ working capital balances, including accounts receivable, unbilled revenue, inventory, and certain other current ~~assets. The purchase price~~assets, and is ~~also~~ subject to ~~certain~~ other closing and post-closing ~~adjustments, primarily net plant~~ adjustments.

~~-15-~~

~~The Minnesota natural gas assets provide~~On April 1, 2006, WPS Resources, through its wholly owned subsidiary Michigan Gas Utilities Corporation (MGUC), completed the acquisition of the natural gas distribution ~~service to about 200,000 customers throughout the state~~operations in 165 cities and communities including Grand Rapids, Pine City, Rochester, and Dakota County with 226 employees. Annual natural gas throughput is approximately 761 million therms per year, which is almost as large as WPS Resources' existing regulated natural gas operations. The assets operate under a cost-of-service environment and are currently allowed an 11.71% return on equity on a 50% equity component of the regulatory capital structure.

Michigan from Aquila. The Michigan natural gas assets provide natural gas distribution service ~~to about 161,000 customers, mainly in southern Michigan~~ in 147 cities and communities ~~including~~throughout Otsego, Grand Haven, and Monroe ~~with 182 employees. Annual natural gas throughput is approximately 360 million therms per year. Like Minnesota, the~~counties. The assets ~~also~~ operate under a ~~cost-of-service~~cost of service environment and are currently allowed an 11.4% return on equity on a 45% equity component of the regulatory capital structure.

WPS Resources ~~plans that permanent~~paid total cash consideration of $314.9 million for the Michigan natural gas distribution operations, which includes estimated closing adjustments of $45.4 million related primarily to purchased working capital. The transaction was initially funded with commercial paper borrowings supported by the revolving credit agreements entered into with J.P. Morgan Chase Bank and Bank of America Securities LLC (see Note 6 "Short-Term Debt and Lines of Credit" for more information on the revolving credit agreements). WPS Resources placed $314.9 million of cash into escrow for the acquisition at March 31, 2006. Cash held in escrow is recorded as "restricted cash for acquisition" within long-term assets on the WPS Resources Condensed Consolidated Balance Sheets. Aquila took legal possession of the escrowed funds on April 1, 2006. Permanent financing for the acquisition will be issued later this year and is expected to include a combination of common equity, long-term debt instruments, and possibly other hybrid securities. The transaction will be accounted for under the purchase method of accounting in the second quarter of 2006. The final purchase price is still subject to post-closing adjustments.

The Minnesota natural gas assets provide natural gas distribution service throughout the state in 165 cities and communities including Grand Rapids, Pine City, Rochester, and Dakota County. Like Michigan, the assets also operate under a cost of service environment and are currently allowed an 11.7% return on equity on a 50% equity component of the regulatory capital structure. The transaction remains subject to approval from the Minnesota Public Utilities Commission. Assuming this approval is obtained in a timely manner, WPS Resources anticipates closing the transaction in the summer of 2006.

-15-

WPS Resources anticipates permanent financing for both the acquisitions to be raised through the issuance of a combination of equity, long-term debt, and ~~long-term debt.~~

~~The transaction is subject to various state and~~possibly other regulatory approvals, including approval from the Michigan Public Service Commission and the Minnesota Public Utilities Commission, and is subject to compliance with the Hart-Scott-Rodino Act. Assuming all approvals are obtained in a timely manner, WPS Resources anticipates closing both transactions in the first half of 2006.

~~Kewaunee Nuclear Power Plant~~

In early July 2005, Kewaunee returned to service following an unplanned outage that began in February 2005. On July 5, 2005, WPSC completed the sale of its 59% ownership interest in Kewaunee to Dominion Energy Kewaunee, LLC, a subsidiary of Dominion Resources, Inc. At the same time, Wisconsin Power and Light Company sold its 41% ownership interest to Dominion. The major benefits of the sale for WPSC included shifting financial risk from utility customers and shareholders to Dominion, greater certainty of future costs, and the return of the nonqualified decommissioning funds to customers.

WPSC's share of the cash proceeds from the sale was $112.5 million. Dominion received the assets in WPSC's qualified decommissioning trust and assumed responsibility for the eventual decommissioning of Kewaunee. These trust assets had a pre-tax fair value of $243.6 million at closing. WPSC retained ownership of the assets contained in its nonqualified decommissioning trust. The sale of Kewaunee resulted in a loss of $12.1 million, which includes the proceeds from the sale less the net assets sold, adjusted by several additional items. The most significant of these adjustments is the fair value of an indemnity issued to cover certain costs Dominion may incur related to the recent unplanned outage. In addition, the adjustments include certain costs related to the termination of the plant operating agreement and withdrawal from WPS Resources' investment in the Nuclear Management Company ("NMC"), which served as the licensed operator of Kewaunee. WPSC has received approval from the PSCW for deferral of the loss resulting from this transaction and related costs. WPSC has proposed that proceeds of $127.1 million received from the liquidation of the nonqualified decommissioning trust assets be refunded to customers, net of the loss on the sale of the plant assets and costs related to the 2004 and 2005 Kewaunee outages. See Note 16, ~~Regulatory Environment~~~~, for more information.~~

At the closing date, WPSC's share of the carrying value of the assets and liabilities that were included within the sale agreement, or that were otherwise eliminated pursuant to the sale, were as follows:

~~-16-~~

(Millions)

July 5, 2005

Qualified decommissioning trust fund
$
243.6

Other utility plant, net
165.4

Other current assets
5.5

Total assets
$
414.5

Regulatory liabilities
$
(72.1
)
Accounts payable
2.5

Asset retirement obligations
376.4

Total liabilities
$
306.8

Upon the closing of the sale, WPSC entered into a long-term power purchase agreement with Dominion to purchase energy and capacity consistent with volumes available when WPSC owned Kewaunee. The power purchase agreement extends through 2013 when the plant's current operating license will expire. Fixed monthly payments under the power purchase agreement will approximate the expected costs of production had WPSC continued to own the plant. Therefore, management believes that the sale of Kewaunee and the related power purchase agreement provides more price certainty for WPSC's customers and reduces WPSC's risk profile. In April 2004, WPSC entered into an exclusivity agreement with Dominion. Under this agreement, if Dominion decides to extend the operating license of Kewaunee, Dominion can negotiate only with WPSC during the exclusivity period for 59% of the plant output under a new power purchase agreement that would extend beyond Kewaunee's current operating license termination date. The exclusivity period started on the closing date of the sale, July 5, 2005, and extends through December 21, 2011, after which Dominion can negotiate with other parties.

hybrid securities.

NOTE ~~6--GOODWILL~~5--GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill recorded by WPS Resources was $36.8 million at ~~September 30, 2005,~~March 31, 2006 and December 31, ~~2004.~~2005. 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.~~ESI.

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

(Millions)

September 30, 2005

Asset Class

Average Life
(Years)

Gross
Carrying Amount

Accumulated
Amortization

Net

Emission allowances

1 to 30

$
16.7

$
(13.0
)
$
3.7

Customer related

1 to 8

10.5

(5.2
)

5.3

Other

1 to 30

4.2

(1.6
)

2.6

Total

$
31.4

$
(19.8
)
$
11.6

(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

An impairment charge related to Sunbury, which was recorded in the second quarter of 2005, included the write-down of $6.6 million of unallocated emission allowances. These emission allowances were reflected in the above table at December 31, 2004 (see Note 4, ~~Assets Held for Sale~~~~, for more~~

*(Millions)*	March 31, 2006							December 31, 2005
Asset Class	Gross Carrying Amount		Accumulated Amortization			Net		Gross Carrying Amount		Accumulated Amortization			Net
Emission allowances	$	34.4	$	(11.8	)	$	22.6	$	41.2	$	(22.2	)	$	19.0
Customer related		9.2		(5.0	)		4.2		10.2		(5.6	)		4.6
Other		5.1		(0.9	)		4.2		4.2		(0.9	)		3.3
Total	$	48.7	$	(17.7	)	$	31.0	$	55.6	$	(28.7	)	$	26.9

~~-17-~~

information). Because PDI sold all of Sunbury's allocated emission allowances in the first half of 2005, emission allowances are currently purchased in the market as needed for the operation of this plant.

~~Intangible asset amortization expense, in the aggregate, for the nine months ended September 30, 2005, and September 30, 2004, was $13.1 million and $1.7 million, respectively.~~ Intangible asset amortization expense, in the aggregate, for the three months ended ~~September 30,~~March 31, 2006, and March 31, 2005, ~~and September 30, 2004,~~ was ~~$10.1~~$12.3 million and ~~$1.0~~$0.6 million, respectively.

Amortization expense for the next five fiscal years is estimated as follows:

*Estimated Future Amortization ~~Expense:~~Expense (millions***)
For ~~three~~nine months ending December 31, ~~2005~~2006	$~~1.9 million~~
~~For year ending December 31, 2006~~	~~1.6 million~~21.0
For year ending December 31, 2007	~~1.3 million~~1.5
For year ending December 31, 2008	~~1.5 million~~1.4
For year ending December 31, 2009	1.2 ~~million~~
For year ending December 31, 2010	1.0

NOTE ~~7--SHORT-TERM~~6--SHORT-TERM DEBT AND LINES OF CREDIT

WPS Resources has a syndicated $500 million five-year revolving credit facility which expires in June 2010. WPSC has a syndicated $115 million five-year revolving credit facility containing annual trigger date provisions to provide short-term borrowing flexibility and security for commercial paper outstanding.

In November 2005, WPS Resources entered into two unsecured revolving credit agreements of $557.5 million and $300 million with J.P. Morgan Chase Bank and Bank of America Securities LLC. These credit facilities are bridge facilities intended to backup commercial paper borrowings related to the purchase of the Michigan and Minnesota natural gas distribution operations from Aquila and to support purchase price adjustments related to working capital at the time of the closing of the transactions. The capacity under the bridge facilities will be reduced by the amount of proceeds from any long-term financing we complete, with the exception of proceeds received from the November 2005 equity offering. The credit agreements will be further reduced as permanent or replacement financing is secured. Under the $300 million credit agreement, loans cannot exceed the purchase price adjustments in connection with the Aquila acquisitions and no more than $200 million can be borrowed for purchase price adjustments related to the first acquisition. Under the $300 million facility, these loan commitments will be reduced by one-third 90 days after the consummation of the applicable acquisition with the remaining two-thirds due 180 days after the consummation of the applicable acquisition (or earlier if long-term financing or replacement credit agreements are executed). Both of these credit agreements mature on September 5, 2007, and have representations and covenants that are similar to those in our existing

-16-

credit facilities. On March 31, 2006, in order to meet short-term financing requirements related to the acquisition of the Michigan natural gas operations from Aquila, WPS Resources issued $269.5 million of commercial paper supported by the $557.5 million credit agreement and $45.4 million of commercial paper supported by the $300 million credit agreement. See Note 4, "Acquisitions and Sales of Assets," for more information related to the purchase of Michigan natural gas distribution operations, and the anticipated purchase of the Minnesota natural gas distribution operations from Aquila.

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


(Millions)	September 30, 2005			December 31, 2004			March 31, 2006			December 31, 2005
Commercial paper outstanding	$	138.0		$	279.7		$	635.6		$	254.8
Average discount rate on outstanding commercial paper		3.95	%		2.46	%		4.99	%		4.54	%
Short-term notes payable outstanding	$	10.0		$	12.7		$	10.0		$	10.0
Average interest rate on short-term notes payable		3.67	%		2.52	%		4.65	%		4.32	%
Available under lines of credit	$	404.5		$	161.9
Available (unused) lines of credit							$	195.4		$	249.1

The commercial paper at ~~September 30~~March 31 had varying maturity dates ranging from ~~October~~April 3 through ~~October~~April 17, ~~2005.~~2006.

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


(Millions)	September 30, 2005			December 31, 2004			March 31, 2006			December 31, 2005
Commercial paper outstanding	$	32.0		$	91.0		$	83.0		$	75.0
Average discount rate on outstanding commercial paper		3.94	%		2.44	%		4.96	%		4.54	%
Short-term notes payable outstanding	$	10.0		$	10.0		$	10.0		$	10.0
Average interest rate on short-term notes payable		3.67	%		2.26	%		4.65	%		4.32	%
Available under lines of credit	$	79.2		$	20.2
Available (unused) lines of credit							$	28.2		$	36.2

The commercial paper at March 31 had varying maturity dates ranging from ~~October 7~~April 14 through ~~October~~April 17, ~~2005.~~2006.

~~-18-~~-17-

NOTE 7--LONG-TERM DEBT

~~NOTE 8--LONG-TERM DEBT~~

(Millions)
September 30,
2005
December 31,
2004

First mortgage bonds – WPSC

Series
Year Due

6.90%
2013
$ 22.0
$ 22.0

7.125%
2023
0.1
0.1

Senior notes – WPSC

Series
Year Due

6.125%
2011
150.0
150.0

4.875%
2012
150.0
150.0

4.80%
2013
125.0
125.0

6.08%
2028
50.0
50.0

First mortgage bonds – UPPCO

Series
Year Due

9.32%
2021
15.3
15.3

Unsecured senior notes – WPS Resources

Series
Year Due

7.00%
2009
150.0
150.0

5.375%
2012
100.0
100.0

Unsecured term loan due 2010 – WPS Resources
65.6
-
Term loans – non-recourse, collateralized by nonregulated assets
17.7
82.3
Tax exempt bonds
27.0
27.0
Senior secured note
2.5
2.7
Total
875.2
874.4
Unamortized discount and premium on bonds and debt
(1.9)
                 (2.0)
Total long-term debt
873.3
872.4
Less current portion
(3.7)
             (6.7)
Total long-term debt
$869.6
$865.7

On June 17, 2005, $62.9 million of non-recourse debt at PDI collateralized by nonregulated assets was converted to a five-year WPS Resources obligation as a result of the sale of Sunbury's allocated emission allowances. In addition, $2.7 million drawn on a line of credit at PDI was rolled into the five-year WPS Resources obligation. The floating interest rate on the total five-year WPS Resources’ obligation of $65.6 million has been fixed at 4.595% through two interest rate swaps.

(Millions)				March 31, 2006			December 31, 2005

First mortgage bonds - WPSC
	Series		Year Due
	6.90	%	2013	$	22.0		$	22.0
	7.125	%	2023		0.1			0.1

Senior notes - WPSC
	Series		Year Due
	6.125	%	2011		150.0			150.0
	4.875	%	2012		150.0			150.0
	4.80	%	2013		125.0			125.0
	6.08	%	2028		50.0			50.0

First mortgage bonds - UPPCO
	Series		Year Due
	9.32	%	2021		14.4			14.4

Unsecured senior notes - WPS Resources
	Series		Year Due
	7.00	%	2009		150.0			150.0
	5.375	%	2012		100.0			100.0

Unsecured term loan due 2010 - WPS Resources					65.6			65.6
Term loans - non-recourse, collateralized by nonregulated assets					16.4			16.4
Tax exempt bonds					27.0			27.0
Senior secured note					2.4			2.4
Total					872.9			872.9
Unamortized discount and premium on bonds and debt					(1.7	)		(1.8	)
Total debt					871.2			871.1
Less current portion					(4.0	)		(4.0	)
Total long-term debt				$	867.2		$	867.1

NOTE ~~9--ASSET~~8--ASSET RETIREMENT OBLIGATIONS

~~Legal retirement obligations, as defined by~~Under the provisions of SFAS No. 143, "Accounting for Asset Retirement Obligations," ~~previously~~and Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations," WPS Resources has recorded liabilities for legal obligations associated with the retirement of tangible long-lived assets. The utility segments identified asset retirement obligations primarily related to asbestos abatement at certain generation facilities, office buildings, and service centers; disposal of PCB-contaminated transformers; and closure of fly-ash landfills at certain generation facilities. In accordance with SFAS No. 71, the utilities establish regulatory assets and liabilities to record the differences between ongoing expense recognition under SFAS No. 143 and Interpretation No. 47, and the rate-making practices for retirement costs authorized by the PSCW and MPSC. Asset retirement obligations identified at ~~WPSC related primarily~~ESI relate to ~~the final decommissioning of Kewaunee. As discussed in Note 5,~~ ~~Acquisitions and Sales of Assets~~~~, the sale of Kewaunee to Dominion was completed on July 5, 2005. As a result of the sale, Dominion assumed the asset retirement obligation related to Kewaunee.~~

~~PDI identified a legal retirement obligation related to the~~asbestos abatement at certain generation facilities as well as closure of an ash basin located at Sunbury. The asset retirement ~~obligation associated with Sunbury is~~obligations are recorded as ~~a liability on~~other long-term liabilities in the Condensed Consolidated Balance ~~Sheets.~~

~~-19-~~

Sheets of WPS Resources and WPSC.

The following table ~~describes~~shows 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 12.4 0.2 12.6
Asset retirement obligation transferred to Dominion (376.4 ) - (376.4 )
Asset retirement obligation at September 30, 2005 $ 0.4 $ 2.4 $ 2.8

(Millions)	WPSC		UPPCO		ESI		Total
Asset retirement obligations at December 31, 2005	$	7.7	$	0.9	$	6.3	$	14.9
Accretion expense		0.1		-		0.1		0.2
Asset retirement obligations at March 31, 2006	$	7.8	$	0.9	$	6.4	$	15.1

-18-

NOTE ~~10--INCOME~~9--INCOME TAXES

For the three ~~and nine~~ months ended ~~September 30,~~March 31, 2006, and 2005, ~~and 2004,~~ WPS Resources' and WPSC's 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~~10--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 ~~September 30, 2005.~~March 31, 2006.

ESI has unconditional purchase obligations related to energy supply contracts that total ~~$4.2~~$4.9 billion. Substantially all of these obligations end by ~~2009,~~2008, with obligations totaling ~~$16.5~~$239.0 million extending from ~~2010~~2009 through ~~2015.~~2016. The majority of the energy supply contracts are to meet ESI's obligations to deliver energy to its customers.

WPSC has obligations related to coal, purchased power, and natural gas. ~~All pertinent nuclear fuel contracts were assigned to Dominion with the July 5, 2005, sale of Kewaunee to Dominion.~~ Obligations related to coal supply and transportation extend through 2016 and total ~~$346.5~~$458.6 million. Through 2016, WPSC has obligations totaling ~~$1.5~~$1.4 billion for either capacity or energy related to purchased ~~power, including the obligation under the power purchase agreement with Dominion Kewaunee, LLC.~~power. Also, there are natural gas supply and transportation contracts with total estimated demand payments of ~~$126.6~~$117.3 million through 2017. WPSC expects to recover these costs in future customer rates. Additionally, WPSC has contracts to sell electricity and natural gas to customers.

~~PDI has entered into purchase contracts totaling $6.8 million. The majority of these contracts relate to coal purchases for the PDI coal plants.~~

UPPCO has made commitments for the purchase of commodities, mainly capacity or energy related to purchased power, which total ~~$26.4~~$45.7 million and extend through 2010.

WPS Resources also has commitments in the form of purchase orders issued to various vendors. At ~~September 30, 2005,~~March 31, 2006, these purchase orders totaled ~~$485.7~~$543.1 million and ~~$471.6~~$513.2 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.

Environmental

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

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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.

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

In response to the EPA Clean Air Act enforcement initiative, several utilities have elected to settle with the EPA, while others are in litigation. In general, those utilities that have settled have entered into consent decrees which require the companies to pay fines and penalties, undertake supplemental environmental projects, and either upgrade or replace pollution controls at existing generating units or shut down existing units and replace these units with new electric generating facilities. Several of the settlements involve multiple facilities. The fines and penalties (including the capital costs of supplemental environmental projects) associated with these settlements range between $7 million and ~~$44~~$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 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 were subsequently challenged in the District of Columbia Circuit Court of Appeals. On June 24, 2005, the District of Columbia Circuit Court of Appeals issued its opinion on the EPA's 2002 new source review reform rule. The ruling upheld most of the 2002 rule, but did strike down some provisions. The rules are not yet effective in Wisconsin. They are also not retroactive.

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~~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.~~

Pulliam Air Permit Violation Lawsuit

~~On July 12, 2005, the~~The Sierra Club and Clean Wisconsin ~~notified WPS Resources of their intent to file~~filed a ~~citizen enforcement action with~~complaint in the ~~United States District Court,~~ Eastern District of Wisconsin on October 19, 2005. The lawsuit was filed pursuant to the citizen suit provisions of the Clean Air Act. The ~~Sierra Club and Clean Wisconsin indicated that the lawsuit will seek penalties, injunctive relief, and costs of litigation. The notice referenced~~complaint references opacity exceedances reported by the Pulliam facility located in Green Bay, Wisconsin, from 1999 through the first quarter of ~~2005, and~~2005. The notice also alleges monitoring violations from 1999 through ~~2004. The notice also alleged~~2004, exceedances of the Clean Air Act operating permit in 2002, exceedances of the permit issued for eight diesel generators in 2001, and exceedances of the permit for one of the ~~combustine turbine.~~

~~On October 20, 2005,~~combustion turbines. The lawsuit seeks penalties, injunctive relief, and costs of litigation. WPSC filed an answer to the ~~Sierra Club and Clean Wisconsin filed~~complaint on March 6, 2006, asserting a ~~civil lawsuit claiming that WPSC's Pulliam facility located in Green Bay, Wisconsin violated provisions~~number of ~~its air permit with respect to particulates, nitrogen oxide, and visible emissions; however, WPSC has not been served to date.~~affirmative defenses. The Sierra Club and Clean Wisconsin have stated a willingness to discuss the alleged ~~violations. WPSC is investigating~~violations and the ~~claims.~~parties have engaged in settlement negotiations.

Weston 4 Air Permit

On November 15, 2004, the Sierra Club filed a petition with the WDNR under Section 285.61, Wis. Stats., seeking a contested case hearing on the air permit issued for the Weston 4 generation station. On December 2, 2004, the WDNR granted the petition and forwarded the matter to the Division of Hearings and Appeals. In its petition, the Sierra Club raised legal and factual issues with the permit and with the process used by WDNR to develop the air emission limits and conditions. ~~In addition, both WPSC and the Sierra Club filed motions for~~Certain issues were decided on summary judgment ~~on certain~~in favor of ~~the issues. A decision regarding summary judgment was issued. In the ruling, the Administrative Law Judge denied the motion of Sierra Club and granted summary judgment to~~ WPSC with respect to certain ~~claims of~~ Sierra Club claims consistent with the rulings rendered in Wisconsin Energy's Elm Road proceeding. The contested case hearing in the matter was held during the last week of September 2005. The hearing addressed the remaining issues, which are generally related to the emission limits specified in the permit and the pollution controls to be used to achieve these limits. ~~The~~In February 2006, the Administrative Law Judge affirmed the Weston 4 air permit with modifications to the emission limits for sulfur dioxide and nitrogen oxide from the coal-fired boiler and particulate from the cooling tower. The modifications set ~~a briefing schedule~~limits that are more stringent than those set by the WDNR. The Sierra Club and ~~indicated that a decision would be issued in January 2006. If~~WPSC filed petitions for judicial review of the Administrative Law Judge's decision ~~requires modifications~~with the circuit court, both of which are pending. WPSC's petition is limited to a review

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of the decision related to sulfur dioxide limitations. The filing of the petitions did not stay the Administrative Law Judge's decision. WPSC expects that the WDNR intends to revise the air permit ~~construction delays and/or increased construction costs could result.~~consistent with that decision unless otherwise directed by the court.

Weston 4 Discovery Complaint

On December 16, 2005, the Sierra Club filed an complaint with the PSCW alleging that WPSC failed to respond accurately and completely to a PSCW staff request for information about air pollution control technology available for the Weston 4 electric generating facility, the construction of which was authorized by the PSCW in October 2004. Following an informal investigation, the PSCW determined that, although the alleged failure to provide the information did not adversely affect the outcome of the case, WPSC may not have fully complied with the PSCW's procedural rules. Based on this determination, the PSCW referred the matter to the Wisconsin Attorney General for investigation and potential enforcement action. WPSC does not believe that it violated the PSCW's procedural rules. Moreover, both the PSCW and the WDNR have determined that any error by WPSC would not have impacted the outcome of the cases involved. Nonetheless, the referral to the Attorney General could result in enforcement action against WPSC. Any such enforcement action may result in a civil forfeiture or fine.

Weston Site ~~Operation~~Operating Permit

On April 18 and April 26, 2005, WPS Resources notified the WDNR that the existing Weston facility was not in compliance with certain provisions of the "Title V" air operating permit that was issued to the facility in October 2004. These provisions include: (1) the particulate emission limits applicable to the coal handling equipment; (2) the carbon monoxide (CO) limit for Weston combustion turbines; and (3) the limitation on the sulfur content of the fuel oil stored at the Weston facility. On July 27, 2005, WPSC received a notice of violation (NOV) from the WDNR asserting that the existing Weston facility is not in compliance with certain provisions of the permit. ~~The~~In response to the NOV, a compliance plan was submitted to the WDNR. Subsequently, stack testing was performed, which indicated continuing exceedances of the particulate limits from the coal handling equipment. On January 19, 2006, WPSC received from the WDNR a Notice of Noncompliance (NON) seeking further information about the alleged ~~noncompliance is based on information previously~~non-compliance event. WPSC provided ~~by WPSC~~a response to the WDNR and is in ~~April 2005. The~~the process of seeking to have the permit revised. On February 20, 2006, the WDNR issued an NOV ~~classifies certain~~which incorporated most of the alleged ~~violations as "high priority" under~~noncompliance events described above (the alleged exceedances of the ~~EPA's high priority violation policy.~~CO limit was not included) and added issues relating to opacity monitoring and the operation of a particulate source for three days without a functioning baghouse. Under the ~~WDNR’s~~WDNR's stepped enforcement process, an NOV is the first step in the ~~WDNR’s~~WDNR's enforcement procedure. If the WDNR decides to continue the enforcement process, the next step is a ~~“referral”~~"referral" of the matter to the Wisconsin Attorney ~~General’s~~General's Office. ~~WPS Resources~~In addition, citizen groups may seek to initiate enforcement prior to the filing of any lawsuit by the Wisconsin Attorney General's Office or may seek to intervene in the Title V operating permit revision process. WPSC is seeking to amend the applicable permit limits and is taking corrective action. At this time, we believe that our exposure to fines or penalties related to this noncompliance would not have a material impact on our financial results.

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Mercury and Interstate Air Quality Rules

On October 1, 2004, the mercury emission control rule became effective in Wisconsin. The rule requires WPSC to control annual system mercury emissions in phases. The first phase will occur in 2008 and 2009. In this phase, the annual mercury emissions are capped at the average annual system mercury emissions for the period 2002 through 2004. The next phase will run from 2010 through 2014 and requires a 40% reduction from average annual 2002 through 2004 mercury input amounts. After 2015, a 75% reduction is required with a goal of an 80% reduction by 2018. Because federal regulations were promulgated in March 2005, we believe the state of Wisconsin will revise the Wisconsin rule to be consistent with the federal rule. However, the state of Wisconsin has filed suit against the federal government along with other states in opposition to the rule. WPSC estimates capital costs of approximately $14 million to achieve the proposed 75% reductions. The capital costs are expected to be recovered in a future rate ~~case.~~cases.

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In ~~December 2003,~~March 2005, the EPA ~~proposed~~finalized the 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~~finalized the Clean Air Interstate Rule (formerly known as the Interstate Air Quality Rule), which ~~would~~will reduce sulfur dioxide and nitrogen oxide emissions from utility boilers located in 29 states, including Wisconsin, Michigan, Pennsylvania, and New York. ~~In March 2005, the EPA finalized both the mercury rule and the Clean Air Interstate Rule.~~

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

The final mercury rule also establishes a mercury cap and trade program, which requires a 21% reduction in national mercury emissions in 2010 and a 70% reduction in national mercury emissions beginning in 2018. Based on the final rule and current projections, WPSC anticipates meeting the mercury rule cap and trade requirements ~~at a cost similar~~and does not anticipate incurring costs to ~~the cost~~comply incremental to those required to comply with the Wisconsin rule.

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

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

Currently, WPSC is evaluating a number of options that include using the cap and trade program and/or installing controls. For planning purposes, it is assumed that additional sulfur dioxide and nitrogen oxide controls will be needed on existing units or the existing units will need to be converted to natural gas by 2015. The installation of any controls and/or any conversion to natural gas will need to be scheduled as part of WPSC's long-term maintenance plan for its existing units. As such, controls or conversions may need to take place before 2015. On a preliminary basis and assuming controls or conversion are required, WPSC estimates capital costs of $257 million in order to meet an assumed 2015 compliance date. This estimate is based on costs of current control technology and current information regarding the final EPA rule. The costs may change based on the requirements of the final state rules.

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~~PDI~~ESI is evaluating the compliance options for the Clean Air Interstate Rule. Additional nitrogen oxide controls on some of ~~PDI's~~ESI's facilities may be necessary, and would cost approximately ~~$41~~$40 million. The cost estimate is largely dependent upon how Sunbury will be operated going forward. ~~See Note 4,~~ ~~Assets Held for Sale~~~~, for additional information on Sunbury.~~ Additional sulfur dioxide reductions are unlikely. Also, ~~PDI~~ESI will evaluate a number of options including using the cap and trade program, fuel switching, and/or installing controls.

Clean Air Regulations

Most of the generation facilities owned by ~~PDI~~ESI are located in an ozone transport region. As a result, these generation facilities are subject to additional restrictions on emissions of nitrogen ~~oxide. Throughout 2005~~oxide and ~~in future years, PDI estimates purchasing nitrogen oxide emission allowances at market rates, as needed, to meet its requirements for the Sunbury generation facility.~~

~~PDI~~sulfur dioxide. ESI began 2005 with 17,000 sulfur dioxide emission allowances for its generation facilities that are required to participate in the sulfur dioxide emission program. However, a majority of these allowances were sold in the second quarter of 2005, requiring a higher level of purchases for the remainder of ~~the year. During the remainder of~~ 2005

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and infor 2006. In future years, ~~PDI estimates purchasing~~ESI expects to purchase sulfur dioxide and nitrogen oxide emission allowances at market rates, as needed, to meet its requirements for the Sunbury generation facility.

Spent Nuclear Fuel Disposal

The federal government is responsible for the disposal or permanent storage of spent nuclear fuel. The DOE is currently preparing an application to license a permanent spent nuclear fuel storage facility in the Yucca Mountain area of Nevada.

Spent nuclear fuel is currently being stored at the Kewaunee plant. At current production levels, the plant has sufficient storage for all fuel assemblies until 2009 with full core offload. Additional capacity will be needed by 2010 to maintain full core offload capability.

The United States government through the DOE was under contract with WPSC for the pick up and long-term storage of Kewaunee's spent nuclear fuel. Because the DOE has failed to begin scheduled pickup of the spent nuclear fuel, WPSC incurred costs for the storage of the spent nuclear fuel. WPSC is a participant in a suit filed against the federal government for breach of contract and failure to pick up and store the spent nuclear fuel. The case was filed on January 22, 2004, in the United States Court of Federal Claims. The case has been temporarily stayed until June 20, 2006.

In July 2005, WPSC sold Kewaunee to a subsidiary of Dominion Resources, Inc. Pursuant to the terms of the sale, Dominion has the right to pursue the spent nuclear fuel claim and WPSC will retain the contractual right to an equitable share of any future settlement or verdict. The total amount of damages sought is unknown at this time.

Other Environmental Issues

Groundwater testing at a former ash disposal site of UPPCO indicated elevated levels of boron and lithium. Supplemental remedial investigations were performed, and a revised remedial action plan was developed. The Michigan Department of Environmental Quality approved the plan in January 2003. UPPCO received an order from the MPSC permitting deferral and future recovery of these costs. A liability of ~~$1.4~~$1.3 million and an associated regulatory asset of ~~$1.4~~$1.3 million were recorded at March 31, 2006, for estimated future expenditures associated with remediation of the site. In addition, 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~~year will be ~~$1.6~~$1.8 million. UPPCO has recorded $0.3 million of this amount as its share of the liability as of ~~September 30, 2005.~~March 31, 2006.

There is increasing concern over the issue of climate change and the effect of greenhouse gas emissions. WPS Resources is evaluating both the technical and cost implications which may result from a future greenhouse gas regulatory program. This evaluation indicates that it is probable that any regulatory program that caps emissions or imposes a carbon tax will increase costs for WPS Resources and its customers. At this time, there is no commercially available technology for removing carbon dioxide from a pulverized coal-fired plant, but significant research is in progress. Efforts are underway within the utility industry to develop cleaner ways to burn coal. The use of alternate fuels is also being explored by the industry, but there are many costs and availability issues. Based on the complexity and uncertainty of the climate issues, a risk exists that future carbon regulation will increase the cost of electricity produced at coal-fired generation units. However, we believe the capital expenditures we are making at our generation units are appropriate under any reasonable mandatory greenhouse gas program. WPS Resources will continue to monitor and manage potential risks and opportunities associated with future greenhouse gas regulatory actions.

Manufactured Gas Plant Remediation

WPSC continues to investigate the environmental cleanup of ten manufactured gas plant sites. Cleanup of the land portion of the Oshkosh, Stevens Point, Green Bay, Manitowoc, and two Sheboygan sites in Wisconsin is completed. Groundwater treatment and monitoring at these sites will continue into the

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future. Cleanup of the land portion of four sites will be addressed in the future. River sediment remains to be addressed at sites with sediment contamination, and priorities will be determined in consultation with the EPA. ~~In late 2004, WPSC purchased the Menominee site property. Clean up of this site is expected to begin in the near future. Work~~The additional work at the ~~other~~ sites remains to be scheduled.

WPSC ~~is currently in the process of transferring~~has transferred 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 the future undiscounted investigation and cleanup costs as of ~~September 30, 2005,~~March 31, 2006, to be ~~$65.3~~$66 million. WPSC may adjust these estimates in the future, contingent upon remedial technology, regulatory requirements, remedy determinations, and the assessment of natural resource damages. WPSC has received $12.7 million to date in insurance recoveries. WPSC expects to recover actual cleanup costs, net of insurance recoveries, in future customer rates. Under current PSCW policies, WPSC will not recover carrying costs associated with the cleanup expenditures.

~~Stray Voltage Claims~~MGUC, which acquired retail natural gas operations in Michigan from Aquila in the second quarter of 2006, is responsible for the environmental impacts at 11 manufactured gas plant sites. Removal of the most contaminated soil has been completed at seven sites. Future investigations are needed at many of the sites to evaluate on-site, off-site, and sediment impacts.

~~From time~~MGUC has estimated future investigation and remediation costs of approximately $25 million. The MPSC has historically authorized recovery of these costs. An environmental liability and related regulatory asset will be recorded in the second quarter of 2006 to ~~time, WPSC has been sued by dairy farmers who allege that they have suffered loss~~reflect the expected investigation and clean-up costs relating to these sites.

As these 11 sites are integrated into the corporate gas plant site management program, cost estimates may change. We will also evaluate the feasibility of ~~milk production and other damages supposedly due to "stray voltage" from~~transferring the ~~operation of WPSC's electrical system. Past cases have been resolved without any material adverse effect on~~MGUC sites into the ~~financial statements~~

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~~of WPSC. One case,~~ ~~Allen v. WPSC, has been remanded from the court of appeals to the trial court for a determination of whether a post-verdict injunction is warranted. A second case,~~ ~~Pollack v. WPSC, was tried and ended in a defense verdict on May 5, 2005, and that case is concluded. A third case,~~ ~~Seidl v. WPSC~~, was tried to a jury in October 2004, but ended in a mistrial. On June 21, 2005, the trial judge granted WPSC's motion for a directed verdict. The Seidl plaintiffs have filed a notice of appeal of that dismissal.EPA Superfund Alternative Program.

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 the plaintiffs did not have 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.~~

~~On February 15, 2005, the Court of Appeals affirmed the jury verdict in~~ ~~Allen v. WPSC~~, which 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 for additional proceedings. The Supreme Court of Wisconsin denied WPSC's petition to review the Court of Appeals decision. The judgment has been paid to the plaintiff. The trial judge must now decide whether an injunction should be issued. The expert witnesses retained by WPSC do not believe that there is any scientific basis for concluding that electricity from the utility system is currently creating any problem on the plaintiff's land. Accordingly, WPSC does not believe there is any basis for issuing an injunction, and intends to vigorously contest the portion of the case that will be remanded for further proceedings.

On August 2, 2005, a judgment was entered dismissing the Seidls’ stray voltage case and awarding WPSC its costs, which were approximately $63,000. On September 14, 2005, the Seidls filed a notice of appeal from that judgment. The appeal asserts that the trial court did not have jurisdiction to grant the motion to dismiss because of the passage of time, and that there was sufficient evidence in the record that WPSC was negligent in distributing electricity to the Seidls to require a jury to resolve that issue. It typically takes about a year to resolve appeals. WPSC believes it has meritorious arguments which support the judgment and plans to vigorously contest the appeal.

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

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~~channel. This caused the release of Silver Lake far beyond the

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intended design of the fuse plug. The fuse plug for the Silver Lake reservoir was designed by an outside engineering firm.

UPPCO has worked with federal and state agencies in their investigations. UPPCO is still in the process of investigating the incident. WPS Resources maintains a comprehensive insurance program that includes UPPCO and which provides both property insurance for its facilities and liability insurance for liability to third parties. WPS Resources is insured in amounts that it believes are sufficient to cover its responsibilities in connection with this event. Deductibles and self-insured retentions on these policies are not material to WPS Resources.

As of May 13, 2005, several lawsuits were filed by the claimants and putative defendants relating to this incident. The suits that have been filed against UPPCO, WPS Resources, and WPSC include the following claimants: ~~WE Energies,~~Wisconsin Electric Power Company, Cleveland Cliffs, Inc., Board of Light and Power

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of the City of Marquette, the City of Marquette, the County of Marquette, Dead River Campers, Inc., Marquette County Road Commission, SBC, and various land and ~~homeowners~~home owners along the Silver Lake reservoir and Dead River system. WPS Resources is defending these lawsuits and is seeking resolution of all claims and litigation where possible. UPPCO filed a suit against the engineering company that designed the fuse plug (MWH Americas, Inc.) and the contractor who built it (Moyle Construction, Inc.). UPPCO has reached a confidential settlement with Wisconsin Electric Power Company resolving Wisconsin Electric Power Company's claims. The settlement payment has been reimbursed by WPS Resource's insurer and, therefore, did not have a material impact on the Condensed Consolidated Financial Statements. WPS Resources has also settled several small claims with various landowners that are also covered by insurance. WPS Resources is defending the remaining lawsuits filed against it and is seeking resolution of all claims and litigations where possible. A trial date in September 2007 has been set for the remaining cases.

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 has announced its decision to restore Silver Lake as a reservoir for power generation pending approval of aan economically feasible design by the FERC. The FERC has required that a board of consultants evaluate and oversee the ~~new construction. The board of consultants~~design approval process. UPPCO is developing a timeline for the project, but early estimates call for work to begin in 2006 and be completed in 2008, provided the FERC approves an economically feasible design. Once work is done, Silver Lake is expected to ~~review~~take approximately two years to refill, based upon natural precipitation.

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 ~~design options~~operation of WPSC's electrical system. Past cases have been resolved without any material adverse effect on the financial statements of WPSC. One case, Allen v. WPSC, was remanded from the court of appeals to the trial court for a determination of whether a post-verdict injunction is warranted. A second case, Pollack v. WPSC, was tried and ended in a defense verdict on May 5, 2005, and that case is concluded. A third case, Seidl v. WPSC, was dismissed on June 21, 2005, when the trial judge granted WPSC's motion for a directed verdict. The Seidl plaintiffs have filed a notice of appeal of that dismissal. WPSC believes it has meritorious arguments supporting the dismissal and WPSC plans to vigorously contest the appeal.

On February 15, 2005, the Court of Appeals affirmed the jury verdict in Allen v. WPSC, which awarded the plaintiff $0.8 million for economic damages and $1 million for nuisance. All appeals have been exhausted and the judgment has been paid to the plaintiff, but the plaintiff is still seeking an injunction. The injunction issues are scheduled to be tried in September 2006. The expert witnesses retained by WPSC do not believe that there is any scientific basis for concluding that electricity from the utility system is currently creating any problem on the plaintiff's land. Accordingly, WPSC does not believe there is any basis for issuing an injunction, and intends to contest the plaintiff's claim.

Three cases, Theuerkauf v. WPSC, Wojciehowski Brothers Farms v. WPSC, and Schmoker v. WPSC were filed in the ~~fall~~fourth quarter of ~~2005, prior~~2005. The Theuerkauf case was brought by Michigan farmers and was in federal court in Green Bay, but has recently settled for an amount within the self-insured retention. The Wojciehowski case was brought in Wisconsin state court in Marinette County. The Schmoker case was brought in Wisconsin state court in Winnebago County. While these two cases are still in the early stages and it is too early to ~~construction, with construction expected~~accurately predict their likely outcomes, based on currently available information, WPSC believes it has meritorious defenses to the plaintiff's claims and intends to vigorously defend them.

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even though the utility had complied with the PSCW's established level of concern. Thus, despite the fact that WPSC believes it abides by the applicable PSCW requirements, it is not immune from the tort suits such as these under Wisconsin law.

Wausau, Wisconsin, to Duluth, Minnesota, Transmission Line

Construction of the 220-mile, 345-kilovolt Wausau, Wisconsin, to Duluth, Minnesota, transmission line began in the first quarter of 2004 with the Minnesota portion completed in early 2005. Construction in Wisconsin began on August 8, 2005.

ATC has assumed primary responsibility for the overall management of the project and will own and operate the completed line. WPSC received approval from the PSCW and the FERC ~~to transfer~~and subsequently transferred ownership of the project to ATC. WPSC will continue to manage obtaining the private property rights, design, and construction of the Wisconsin portion of the project.

~~In December 2003, the PSCW issued an amended~~The Certificate of Public Convenience and Necessity ~~per ATC's request~~and other permits needed for ~~relief. This decision was appealed to the Dane County Circuit Court by certain landowners. The court affirmed the PSCW's decision,~~construction have been received and no appeal has been filed during the allowed time allotted for appeals. On July 25, 2005, the Administrative Law Judge issued the WDNR permit and water quality certification, subject to certain conditions. The conditions were acceptable to ATC and WPSC. Project opponents did not file an appeal of the Administrative Law Judge’s decision within the specified time, and it too isare final. In addition, on August 5, 2005, the new law allowing condemnation of county land for transmission lines approved by the PSCW became effective. In light of this legislation, Douglas County negotiated an easement agreement with ATC that allows the project to be constructed across county land on the route originally selected by the PSCW. On September 15, 2005, the Douglas County Board approved that agreement. Accordingly, the lawsuit against Douglas County to force it to provide easements for the project ~~is being~~has been dismissed as moot, and ATC has asked the PSCW to close the docket, which was opened to examine alternative routes in Douglas County.

WPS Resources committed to fund 50% of total project costs incurred up to $198 million and will receive additional equity in ~~the~~ ATC in exchange for the project funding. Under its agreement, ~~to fund approximately half of the Wausau to Duluth transmission line,~~ WPS Resources invested ~~$35.4~~$16.1 million in ATC during the ~~ATC for the nine~~three months ended ~~September 30, 2005,~~March 31, 2006, bringing WPS ~~Resources’~~Resources' investment in ~~the~~

~~-26-~~

ATC related to the project to ~~$63.0~~$102.8 million since the inception of the project. WPS Resources may terminate funding if the project extends beyond January 1, 2010. On December 19, 2003, WPSC and ATC received approval from the PSCW to continue the project at a revised cost estimate of $420.3 million to reflect additional costs for the project resulting from time delays, added regulatory requirements, changes and additions to the project, and ATC overhead costs. WPS Resources has the right, but not the obligation, to provide additional funding in excess of $198 million for up to 50% of the revised cost estimate. ~~The final portion of the line is expected to be placed in service in 2008.~~ Allete ~~Inc.~~ has anexercised its option to fund a portion of ~~this commitment~~the Wausau to Duluth transmission line. WPSC and ~~intends~~Allete agreed that Allete will fund up to ~~fund~~ $60 million byof the ~~end of 2006. This would ultimately decrease~~future capital calls for the ~~amount of additional equity WPS Resources has in the ATC. For~~line. Considering this, for the period ~~October 2005~~January 2006 through ~~November~~the anticipated completion of the line in 2008, WPS Resources expects to fund up to approximately ~~$141~~$61 million for its portion of the Wausau to Duluth transmission ~~line assuming Allete, Inc. does not exercise its option, and approximately $81 million if Allete, Inc. does exercise this option.~~line.

Beaver Falls

~~PDI's~~ESI's Beaver Falls generation facility in New York has been out of service since late June 2005. An unplanned outage was caused by the failure of the first stage turbine blades. ~~At this time, inclusive~~Inclusive of estimated insurance recoveries, ~~PDI~~ESI estimates at this time that it will cost between $3 million and $5 million to repair the turbine and replace the damaged blades. Depending on the amount of insurance recovery, ESI could incur significantly higher net out-of-pocket costs than originally estimated to repair the damage. Resolution of the insurance claim is expected to occur in the second quarter of 2006. In addition, ESI continues to attempt to renegotiate an existing steam off-take agreement with a counterparty, the outcome of which will significantly impact its ability to recover costs. If ~~the estimated repair costs are subsequently revised upward or if the~~significant repair costs are not ~~fully~~ recoverable through insurance or ESI is not able to renegotiate the terms of the steam off-take agreement, then a possibility exists that ESI would not repair the ~~repairs either will not be made or will cause the~~plant, in which case undiscounted cash flows related to future operations tomay be insufficient to recover the carrying value of the plant, resulting in an impairment. The carrying value of the Beaver Falls generation facility at ~~September 30, 2005,~~March 31, 2006, is ~~$18.6~~$17.8 million.

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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 2929/45K of the Internal Revenue Code for the production and sale of solid synthetic fuel produced from coal. These tax credits are scheduled to expire at the end of 2007 and are provided as an incentive for taxpayers to produce ~~fuels~~fuel from alternate sources and reduce domestic dependence on imported oil. This incentive is not deemed necessary if the price of oil increases sufficiently to provide a natural market for ~~these fuels.~~the fuel. Therefore, the tax ~~credit~~credits in a given year isare subject to ~~phase out~~phase-out if the annual average reference price of oil within that year exceeds a minimum threshold price set by the Internal Revenue Service (IRS) and isare eliminated entirely if the average annual reference price increases beyond a ~~phase-out price.~~maximum threshold price set by the IRS. The reference price of a barrel of oil is an estimate of the annual average wellhead price per barrel for domestic crude oil, which have in recent history been approximately $6 below the NYMEX price of a barrel of oil. The threshold price at which the credit begins to ~~phase out~~phase-out was set in 1980 and is adjusted annually for ~~inflation. For 2004,~~inflation; the ~~reference price was $36.75,~~IRS releases the ~~threshold price was $51.35, and~~final numbers for a given year in the ~~credits would have been eliminated had~~first part of the ~~reference price exceeded $64.47. For 2005, the estimated threshold price is $52.57, and the credits will be eliminated if the reference price exceeds $65.99.~~following year.

Numerous events have ~~recently~~ increased domestic crude oil prices, including concerns about terrorism and foreign relations, storm-related supply disruptions, and worldwide demand. 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~~mitigate exposure to the risk of an increase in oil prices that could reduce the amount of ~~2005, 2006, and 2007~~ Section 2929/45K federal tax credits that could be recognized, ~~PDI~~ESI entered into a series of derivative (option) contracts, beginning in the first quarter of 2005, covering a specified number of barrels of oil. ~~These derivatives~~If no phase-out were to occur in 2006 and 2007, we would expect to recognize approximately $26 million of Section 29/45K federal tax credits in each of these years. Based upon 2006 actual year-to-date and forward oil prices, we are anticipating significant phase-outs of 2006 and 2007 Section 29/45K federal tax credits. However, we cannot predict with certainty the future price of a barrel of oil and, therefore, have no way of knowing what portion of our 2006 and 2007 tax credits will ultimately be phased out, or if any phase-out will occur. ESI estimates that 2006 Section 29/45K federal tax credits will begin phasing out if the annual average NYMEX price of a barrel of oil reaches approximately $60, with a total phase-out if the annual average NYMEX price of a barrel of oil reaches approximately $74. At March 31, 2006, based upon estimated annual average oil prices, we anticipated that approximately 51% of the 2006 tax credits that otherwise would be available from the production and sale of synthetic fuel would be phased-out. Based on the amount of the anticipated Section 29/45K phase-out at March 31, 2006, our 2006 annual production assumption is that it is more likely than not that WPS Resources (in order to save on production costs) would also begin curtailing our share of production sometime late in the third quarter of 2006. However, our hedged position may offer a number of alternatives to improve expected results that do not involve production curtailment. For the year ending December 31, 2006, including the projected production curtailment and tax credit phase-out, we expect to recognize the benefit of Section 29/45K federal tax credits totaling approximately $10 million. However, the actual amount of tax credits recognized in 2006 could differ substantially from our March 31, 2006, estimate based upon actual average annual oil prices.

There is proposed federal legislation that would establish the 2006 reference price used to determine the phase-out for 2006 based upon the previous calendar year. If the proposed legislation becomes law, we do not anticipate that any phase-out of 2006 Section 29/45K federal tax credits would occur. However, ESI cannot predict what impact, if any, this proposed legislation would have on the value of the tax credits in 2007, but it could provide an opportunity for ESI to utilize its 2006 derivative (option) contracts to mitigate ~~approximately 100%, 95%,~~the risk of 2007 tax credit phase-outs. However, we cannot provide any certainty that the proposed federal legislation will be enacted into law, and; therefore, we have not relied on the proposed legislation in determining the amount of Section 29/45K federal tax credits to recognize in first quarter of 2006.

ESI has derivative (option) contracts that mitigate substantially all of the Section 29/45K tax credit exposure in 2006 and 40% of the ~~Section 29 tax credit~~ exposure in ~~2005, 2006, and 2007, respectively.~~2007. The derivative contracts involve purchased and written call options that provide for net cash settlement at expiration based on the annual average NYMEX trading price of oil in relation to the strike price of each option. Net premiums paid to date for options to mitigate exposure to Section 29/45K federal tax credit phase-outs in 2006 and 2007 totaled $15.7 million, including $1.3 million of net option premiums paid in April 2006 ($12.4 million for 2006

Our ability to fully utilize the Section 29 tax credits available to us in connection with our remaining interest in a synthetic fuel production facility will depend on whether the amount of our federal income tax liability is sufficient to permit the use of such credits. 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. In 2005, we recognized $24.1 million in Section 29 tax credits. At September 30, 2005, we determined that it was not necessary to record a reserve against any portion of the deferred tax asset related to these

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~~credits. We have~~options and $3.3 million for 2007 options), all of which are recorded as risk management assets and liabilities on the ~~tax benefit~~balance sheet. Essentially, ESI paid $12.4 million for options ($7.4 million after-tax) to protect the value of approximately ~~$133.3~~$26 million of Section 29 tax credits as reductions to income tax expense from the project's inception in June 1998 through September 30, 2005. As a result of alternative minimum tax rules, approximately $71.6 million of this tax benefit has been carried forward as a deferred tax asset as of September 30, 2005. These alternative minimum tax credits can be carried forward indefinitely. The tax benefit recorded with respect to WPS Resources' share of tax credits in 2006 and $3.3 million for options ($2.0 million after-tax) to protect the value of approximately $10 million of tax credits in 2007. ESI has not hedged an estimated $16 million of 2007 tax credits. ESI does not expect to mitigate exposure on the remaining 2007 tax credits until the above referenced federal legislation is settled. The derivative contracts have not been designated as hedging instruments and, as a result, changes in the fair value of the options are recorded currently as a component of nonregulated revenue. This results in mark-to-market gains being recognized in earnings in different periods, compared to any offsetting tax credit phase-outs. For example, from the ~~facility is based~~inception of ESI's Section 29/45K hedging strategy in the first quarter of 2005 through March 31, 2006, total pre-tax mark-to-market and realized gains recognized on ~~our expected consolidated~~2006 oil options were $11.9 million, while total pre-tax mark-to-market gains recognized on 2007 oil options were $6.8 million. These pre-tax gains compared to an estimated $4.9 million tax ~~liability for all open~~credit phase-out that was recognized in the first quarter of 2006 (no tax ~~years including the current year, and all future years~~credit phase-outs were recognized in ~~which we expect~~2005).

In addition to ~~utilize deferred~~exposure from federal tax credits, ESI has also historically received royalties tied to ~~offset our future~~the amount of synthetic fuel produced as well as variable payments from a counterparty related to its 30% sell-down of ECO Coal Pelletization #12 in 2002. Royalties and variable payments received in 2006 and 2007 could decrease if a phase-out occurs, or if synthetic fuel production is reduced. While variable payments are received by ESI quarterly, royalties are a function of annual synthetic fuel production and are generally not received until later in the year.

The following table shows the impact that ESI's investment in the synthetic fuel production facility, including derivative (option) contract activity, had on the Condensed Consolidated Statements of Income for the quarters ended March 31. An explanation for the change in tax ~~liability. Reductions~~credits is discussed in ~~our expected consolidated tax liability~~more detail within "Results of Operations - WPS Resources." Amounts recorded as a component of miscellaneous income did not change significantly between periods.

Amounts are pre-tax, except tax credits (millions)	Income (loss)

	2006			2005
Provision for income taxes:
Section 29/45K federal tax credits recognized	$	4.5		$	12.8

Nonregulated revenue:
Mark-to-market gains on 2005 oil options		-			2.1
Mark-to-market gains on 2006 oil options		6.0			0.4
Net realized gains on 2006 oil options		2.0			-
Mark-to-market gains on 2007 oil options		2.4			0.3

Miscellaneous income:
Operating losses - synthetic fuel facility		(4.7	)		(4.2	)
Variable payments received		0.9			0.9
Royalty income recognized		-			-
Deferred gain recognized		0.6			0.6
Interest received on fixed note receivable		0.3			0.4

Minority interest		1.2			1.1

NOTE 11--GUARANTEES

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

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

At March 31, 2006, and December 31, 2005, outstanding guarantees totaled $1,295.1 million, and $1,310.6 million, respectively, as follows:

WPS Resources' Outstanding Guarantees (Millions)	March 31, 2006		December 31, 2005
Guarantees of subsidiary debt	$	27.2	$	27.2
Guarantees supporting commodity transactions of subsidiaries		1,104.6		1,154.7
Standby letters of credit		149.0		114.3
Surety bonds		0.8		0.8
Other guarantees		13.5		13.6
Total guarantees	$	1,295.1	$	1,310.6


WPS Resources' Outstanding Guarantees (Millions) Commitments Expiring	Total Amounts Committed At March 31, 2006		Less Than 1 Year		1 to 3 Years		4 to 5 Years		Over 5 Years
Guarantees of subsidiary debt	$	27.2	$	-	$	-	$	-	$	27.2
Guarantees supporting commodity transactions of subsidiaries		1,104.6		993.9		27.7		23.6		59.4
Standby letters of credit		149.0		148.3		0.7		-		-
Surety bonds		0.8		0.8		-		-		-
Other guarantees		13.5		-		-		13.5		-
Total guarantees	$	1,295.1	$	1,143.0	$	28.4	$	37.1	$	86.6

At March 31, 2006, WPS Resources had outstanding $27.2 million in corporate guarantees supporting indebtedness. Of that total, $27.0 million supports outstanding debt at one of ESI's subsidiaries. The underlying debt related to these ~~years could result~~guarantees is reflected on WPS Resources' Condensed Consolidated Balance Sheet.

WPS Resources' Board of Directors has authorized management to issue corporate guarantees in ~~disallowance~~the aggregate amount of ~~previously recorded credits, and/or a change~~up to $1.5 billion to support the business operations of ESI. WPS Resources primarily issues the guarantees to counterparties in the wholesale electric and natural gas marketplace to provide them assurance that ESI will perform on its obligations and permit ESI to operate within these markets. At March 31, 2006, WPS Resources provided parental guarantees in the amount of $1,101.7 million, reflected in the ~~tax~~above table, for ESI's indemnification obligations for business operations, including $8.1 million of guarantees that received specific authorization from WPS Resources' Board of Directors and are not included in the $1.5 billion general authorized amount. Of the parental guarantees provided by WPS Resources, the outstanding balance at March 31, 2006, which WPS Resources would be obligated to support, is approximately $324 million.

Another $2.9 million of corporate guarantees support energy and transmission supply at UPPCO and are not reflected on WPS Resources' Condensed Consolidated Balance Sheet. In February 2005, WPS Resources' Board of Directors authorized management to issue corporate guarantees in the aggregate amount of up to $15.0 million to support the business operations of UPPCO. Corporate

-29-

guarantees issued in the future under the Board authorized limit may or may not be reflected on WPS Resources' Condensed Consolidated Balance Sheet, depending on the nature of the guarantee.

At WPS Resources' request, financial institutions have issued $149.0 million in standby letters of credit for the benefit ~~deferred~~of third parties that have extended credit to ~~future periods.~~certain subsidiaries. Of this amount, $143.9 million has been issued to support ESI's operations. Included in the $143.9 million is $2.5 million that has specific authorization from WPS Resources Board of Directors and is not included in the $1.5 billion guarantee limit. The remaining $141.4 million counts against the $1.5 billion guarantee limit authorized for ESI. If a subsidiary does not pay amounts when due under a covered contract, the counterparty may present its claim for payment to the financial institution, which will request payment from WPS Resources. Any amounts owed by our subsidiaries are reflected in WPS Resources' Condensed Consolidated Balance Sheet.

At March 31, 2006, WPS Resources furnished $0.8 million of surety bonds for various reasons including worker compensation coverage and obtaining various licenses, permits, and rights-of-way. Of the $0.8 million of surety bonds, $0.3 million supports ESI and is included in the $1.5 billion guarantee limit authorized for ESI. Liabilities incurred as a result of activities covered by surety bonds are included in the WPS Resources' Condensed Consolidated Balance Sheet.

A ~~portion~~guarantee of ~~future payments~~$4.6 million listed in the above table under ~~one~~other guarantees was issued by WPSC to indemnify a third party for exposures related to the construction of utility assets. This amount is not reflected on WPS Resources' Condensed Consolidated Balance Sheet, as this agreement was entered into prior to the ~~agreements covering~~effective date of FASB Interpretation No. 45.

In conjunction with the sale of Kewaunee, WPSC and Wisconsin Power and Light agreed to indemnify Dominion for 70% of any and all reasonable costs resulting from or arising from the resolution of any design bases documentation issues that are incurred prior to completion of Kewaunee's scheduled maintenance period for 2009 up to a ~~portion~~maximum combined exposure of ~~our interest in~~$15 million for WPSC and Wisconsin Power and Light. WPSC believes that it will expend its share of costs related to this indemnification and, as a result, recorded the ~~facility is contingent~~fair value of the liability, or $8.9 million, as a component of the loss on the ~~facility's continued production~~sale of ~~synthetic fuel. In the event of a~~

Section 29 tax credit phase-out in 2006 and 2007, a possibility exists that the level of synthetic fuel production at the facility would be reduced. If the facility reduces production, PDI may see an adjustment in the $7 million annual pre-tax gains expected to be realized through 2007 from the sell-down.Kewaunee.

~~Dairyland Power Cooperative~~WPSC also agreed to indemnify Dominion for losses resulting from potential breaches of WPSC's representations and warranties under the sale agreement. The indemnification is limited to approximately $18 million and expires in July 2006. WPSC believes the likelihood of having to make any material cash payments under the sale agreement as a result of breaches of representations and warranties is remote.

~~Dairyland Power Cooperative has confirmed~~In April 2006, ESI entered into a $150 million credit agreement to finance its ~~intent~~margin requirements related to ~~purchase a 30% interest in Weston 4~~natural gas and electric contracts traded on the NYMEX and the Intercontinental Exchange. Future borrowings under this agreement will be guaranteed by ~~signing a joint plant agreement in November 2004,~~WPS Resources and subject to ~~a number~~the aggregate $1.5 billion guarantee limit authorized for ESI by WPS Resources' Board 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. WPS Resources anticipates closing on the agreement with Dairyland Power Cooperative by the end of 2005, at which time Dairyland Power Cooperative will remit payment to WPSC in an amount equal to 30% of total costs already incurred by WPSC related to Weston 4 and thereafter will fund 30% of future costs.Directors.

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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 ~~September 30:~~

WPS Resources
Pension Benefits

Other Benefits

(Millions)

2005
2004
2005
2004
Net periodic benefit cost

Service cost
$
6.0
$ 5.2
$
2.0
$ 1.8
Interest cost
10.0
10.0
4.1
4.1
Expected return on plan assets
(10.9
)
(11.5 )
(3.1
)
(2.9 )
Amortization of transition obligation
-
-
0.1
0.1
Amortization of prior-service cost (credit)
1.3
1.4
(0.6
)
(0.5 )
Amortization of net loss
2.2
1.2
1.4
0.7
Net periodic benefit cost
$
8.6
$ 6.3
$
3.9
$ 3.3
March 31:

WPS Resources	Pension Benefits						Other Benefits
(Millions)	2006			2005			2006			2005
Net periodic benefit cost
Service cost	$	5.9		$	6.2		$	1.8		$	2.0
Interest cost		10.0			10.1			3.9			4.2
Expected return on plan assets		(10.5	)		(10.9	)		(3.1	)		(3.1	)
Amortization of transition obligation		-			-			0.1			0.1
Amortization of prior-service cost (credit)		1.3			1.4			(0.5	)		(0.6	)
Amortization of net loss		2.1			2.0			1.0			1.1
Net periodic benefit cost	$	8.8		$	8.8		$	3.2		$	3.7

WPSC's share of net periodic benefit cost for the three months ended ~~September 30~~March 31 is included in the table below:

WPSC
Pension Benefits

Other Benefits

(Millions)

2005
2004
2005
2004
Net periodic benefit cost

Service cost
$
4.8
$ 4.2
$
1.9
$ 1.6
Interest cost
8.4
8.3
3.7
3.7
Expected return on plan assets
(9.6
)
(10.2 )
(3.0
)
(2.8 )
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
1.5
0.5
1.2
0.6
Net periodic benefit cost
$
6.3
$ 4.1
$
3.4
$ 2.7

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~~The following table provides the components of net periodic benefit cost for WPS Resources' benefit plans for the nine months ended September 30:~~

WPS Resources
Pension Benefits

Other Benefits

(Millions)

2005
2004
2005
2004
Net periodic benefit cost

Service cost
$
17.9
$ 15.4
$
6.0
$ 5.7
Interest cost
30.2
29.9
12.4
12.8
Expected return on plan assets
(32.7
)
(34.4 )
(9.4
)
(8.7 )
Amortization of transition obligation
0.1
0.1
0.3
0.3
Amortization of prior-service cost (credit)
4.0
4.3
(1.6
)
(1.7 )
Amortization of net loss
6.5
3.3
4.1
3.4
Net periodic benefit cost
$
26.0
$ 18.6
$
11.8
$ 11.8

~~WPSC's share of net periodic benefit cost for the nine months ended September 30 is included in the table below:~~


WPSC	Pension Benefits						Other Benefits						Pension Benefits						Other Benefits
(Millions)	2005			2004			2005			2004			2006			2005			2006			2005
Net periodic benefit cost
Service cost	$	14.5		$	12.5		$	5.6		$	5.2		$	4.5		$	4.9		$	1.7		$	1.8
Interest cost		25.1			24.9			11.3			11.5			8.3			8.4			3.5			3.8
Expected return on plan assets		(28.7	)		(30.6	)		(9.1	)		(8.5	)		(9.1	)		(9.6	)		(3.0	)		(3.0	)
Amortization of transition obligation		0.1			0.1			0.3			0.3			-			-			0.1			0.1
Amortization of prior-service cost (credit)		3.6			3.8			(1.4	)		(1.4	)		1.2			1.2			(0.5	)		(0.5	)
Amortization of net loss		4.3			1.6			3.5			2.6			1.4			1.4			0.9			0.9
Net periodic benefit cost	$	18.9		$	12.3		$	10.2		$	9.7		$	6.3		$	6.3		$	2.7		$	3.1

Contributions to the plans are made in accordance with legal and tax requirements and do not necessarily occur evenly throughout the year. For the ~~nine~~three months ended ~~September 30, 2005, $8.2 million of~~March 31, 2006, no contributions were made to the pension benefit plan ~~and no contributions were made to the~~or other postretirement benefit plans. WPS Resources expects to contribute ~~an additional $20.4~~$25.3 million to its pension plan and $19.7 million to its other postretirement benefit plans in ~~2005.~~the remainder of 2006.

NOTE 13--STOCK-BASED COMPENSATION

WPS Resources has four stock-based compensation plans: the 2005 Omnibus Incentive Compensation Plan ("2005 Omnibus Plan"), the 2001 Omnibus Incentive Compensation Plan ("2001 Omnibus Plan"), the 1999 Stock Option Plan ("Employee Plan"), and the 1999 Non-Employee Directors Stock Option Plan ("Director Plan"). Under the provisions of the 2005 Omnibus Plan, the number of shares of stock that may be issued in satisfaction of plan awards may not exceed 1,600,000. No additional ~~stock-based compensation~~awards will be issued under the 2001 Omnibus Plan or the Employee Plan, although the plans will continue to exist for purposes of the existing outstanding stock-based compensation. The number of shares issuable under each of the aforementioned stock-based compensation plans, each outstanding award, and stock option exercise prices are subject to adjustment in the event of any stock split, stock dividend, or other similar transaction. At January 1, 2006, only stock options and performance stock rights were outstanding under the aforementioned plans.

Prior to January 1, 2006, WPS Resources ~~accounts~~accounted for ~~these~~the plans under the recognition and measurement ~~principles~~provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to ~~Employees,~~Employees." Accordingly, WPS Resources provided pro forma disclosure amounts in accordance with SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and ~~related interpretations. Upon grant~~Disclosure," as if the fair value method defined by SFAS No. 123, "Accounting for Stock-Based Compensation," had been applied.

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Effective January 1, 2006, WPS Resources adopted the fair value recognition provisions of ~~stock options, no stock-based employee~~SFAS No. 123R, "Share-Based Payment," using the modified prospective transition method. Under this transition method, prior periods' results are not restated. Stock-based compensation cost ~~is reflected~~for the first quarter of 2006 includes compensation cost for all stock-based compensation awards granted prior to, but not yet fully vested as of January 1, 2006, based on the grant date fair value estimated in ~~net income, as~~accordance with the original provisions of SFAS No. 123, adjusted for estimated future forfeitures. There was no material cumulative effect of a change in accounting principle recorded upon adoption of SFAS No 123R. Stock-based compensation cost for all ~~options~~awards granted ~~under these plans~~after January 1, 2006, will be recognized based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123R. The implementation of SFAS No. 123R had an ~~exercise price equal to the market value of the underlying common stock~~immaterial impact on ~~the date of grant.~~ cash flows from operations and cash flows from financing activities.

The following table illustrates the effect on income available for common shareholders and earnings per share iffor the ~~company~~first quarter of 2005, had WPS Resources applied the fair value recognition provisions of SFAS No. ~~123, "Accounting~~123:

(Millions, except per share amounts)	Three Months Ended March 31, 2005

Income available for common shareholders
As reported	$	65.9
Add: Stock-based compensation expense using the intrinsic value method - net of tax		0.4
Deduct: Stock-based compensation expense using the fair value method - net of tax		(0.4	)
Pro forma	$	65.9

Basic earnings per common share
As reported	$	1.74
Pro forma		1.74

Diluted earnings per common share
As reported	$	1.73
Pro forma		1.73

Stock Options

Under the provisions of the 2005 Omnibus Plan, no single employee who is the chief executive officer of WPS Resources or any of the other four highest compensated officers of WPS Resources and its subsidiaries can be granted options for ~~Stock-Based~~more than 250,000 shares during any calendar year. Stock options are granted by the Compensation" Committee of the Board of Directors and may be granted at any time. No stock options will have a term longer than ten years. The exercise price of each stock option is equal to ~~stock-based employee compensation:~~the fair market value of the stock on the date the stock option is granted. Under the 2005 and 2001 Omnibus Plans and the Employee Plan, one-fourth of the stock options granted vest and become exercisable each year on the anniversary of the grant date.

The number of stock options granted under the Director Plan may not exceed 100,000, and the shares to be delivered will consist solely of treasury shares. Stock options are granted at the discretion of the Board of Directors. No options may be granted under this plan after December 31, 2008. All options have a ten-year term, but they may not be exercised until one year after the date of grant. Options granted under this plan are immediately vested. The exercise price of each option is equal to the fair market value of the stock on the date the stock options were granted.

The fair values of stock option awards outstanding at January 1, 2006, were estimated using the Black-Scholes option-pricing model. Stock options granted after the implementation of SFAS No. 123R will be valued using a binomial lattice model. No stock options were granted during the quarter ended March 31, 2006, and no modifications were made to previously issued awards. Total pre-tax

~~-29-~~-32-

compensation expense recognized during the first quarter of 2006 for stock options was $0.2 million, of which $0.1 relates to WPSC. The total compensation cost capitalized for the same period was immaterial.

As of March 31, 2006, $1.4 million of total pre-tax compensation cost related to unvested and outstanding stock options is expected to be recognized over a weighted-average period of 2.7 years.

Cash received from option exercises during the three months ended March 31, 2006, totaled $0.5 million. The tax benefit realized from these option exercises totaled $0.1 million.

A summary of stock option activity for the first quarter of 2006 is presented below:

	Stock Options	Weighted-Average Exercise Price Per Share	Weighted Average Remaining Contractual Life (in Years)	Aggregate Intrinsic Value (Millions)
Outstanding at December 31, 2005
2001 Omnibus Plan	1,194,441	$41.72
2005 Omnibus Plan	325,347	54.85
Employee Plan	156,973	33.99
Director Plan	12,000	25.50
Exercised during the quarter
2001 Omnibus Plan	13,014	38.61		$0.2
Outstanding at March 31, 2006
2001 Omnibus Plan	1,181,427	41.75	7.29	8.8
2005 Omnibus Plan	325,347	54.85	9.69	-
Employee Plan	156,973	33.99	4.48	2.4
Director Plan	12,000	25.50	3.74	0.3
Options exercisable at March 31, 2006
2001 Omnibus Plan	697,797	39.31	6.78	6.9
Employee Plan	156,973	33.99	4.48	2.4
Director Plan	12,000	25.50	3.74	0.3

No options expired or were forfeited during the first quarter of 2006.

The aggregate intrinsic value for outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they all exercised their options at March 31, 2006. This is calculated as the difference between WPS Resources' closing stock price on March 31, 2006, and the option exercise price, multiplied by the number of in-the-money stock options.

Other Stock-Based Compensation Awards

A portion of the long-term incentive is awarded in the form of performance stock rights. No more than 400,000 of the shares authorized for issuance under the provisions of the 2005 Omnibus Plan can be granted as performance shares. In addition, no single employee who is the chief executive officer of WPS Resources or any of the other four highest compensated officers of WPS Resources and its subsidiaries can receive a payout in excess of 50,000 performance shares during any calendar year. Performance stock rights vest over a three-year performance period and are paid out in shares of WPS Resources' common stock. The number of shares paid out is calculated by multiplying a performance percentage by the number of outstanding stock rights at the completion of the vesting period. The performance multiplier is based on the total shareholder return of WPS Resources' common stock relative to the total shareholder return of a peer group of companies. The payout may range from 0% to 200% of target.

Three Months Ended
September 30,

Nine Months Ended
September 30,

(Millions, except per share amounts)

2005
2004
2005
2004

Income available for common shareholders

As reported
$
48.2
$ 34.8
$
138.0
$ 82.0
Add: Stock-based compensation expense
using the intrinsic value method - net of tax

0.3
0.2
1.6
0.7
Deduct: Stock-based compensation expense
using the fair value method - net of tax

(0.4
)
(0.3 )
(1.1
)
(0.9 )
Pro forma
$
48.1
$ 34.7
$
138.5
$ 81.8

Basic earnings per common share

As reported
$
1.26
$ 0.93
$
3.63
$ 2.20
Pro forma
1.26
0.93
3.64
2.20

Diluted earnings per common share

As reported
$
1.25
$ 0.93
$
3.60
$ 2.19
Pro forma
1.25
0.92
3.62
2.18

-33-

The fair values of performance stock right awards outstanding at January 1, 2006, were estimated using WPS Resources' common stock price on the date of grant, less the present value of expected dividends over the three-year vesting period, assuming a payout of 100% of target. Performance stock rights granted after the implementation of SFAS No. 123R will be valued using the Monte Carlo valuation model. No performance stock rights were granted during the quarter ended March 31, 2006, and no modifications were made to previously issued awards. Pre-tax compensation expense recorded for performance stock rights was $0.7 million for the first quarter of 2006, of which $0.4 relates to WPSC. The total compensation cost capitalized was immaterial.

The total intrinsic value of performance shares distributed during the quarter (related to the December 2002 grant) was $2.4 million. The tax benefit realized due to the distribution of performance shares totaled $1.0 million.

As of March 31, 2006, $3.9 million of total pre-tax compensation cost related to unvested and outstanding performance stock rights is expected to be recognized over a weighted-average period of 2.5 years.

A summary of the activity of the performance stock rights plan for the first quarter of 2006 is presented below:

	Performance Stock Rights	Weighted-Average Grant Date Fair Value
Outstanding at December 31, 2005	211,421	$41.93
Distributed during the quarter	37,600	$31.60
Outstanding at March 31, 2006	173,821	$44.16

Performance stock rights vested at December 31, 2005, were paid out during the first quarter of 2006. The actual number of shares of WPS Resources' common stock distributed totaled 45,121 based on a payout of 120% of target. None of the stock rights outstanding at March 31, 2006, were exercisable at March 31, 2006. No stock rights expired or were forfeited during the quarter.

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
September 30,

(Millions)

2005
2004
Income available for common shareholders
$
48.2
$ 34.8
Cash flow hedges, net of tax of $(13.5) and $(1.0)
(21.3
)
(1.7 )
Foreign currency translation
0.4
-
Unrealized gain on available-for-sale securities, net of tax
0.5
-
Total comprehensive income
$
27.8
$ 33.1


	Nine Months Ended September 30,					Three Months Ended March 31,
(Millions)	2005			2004		2006		2005
Income available for common shareholders	$	138.0		$	82.0	$	60.1	$	65.9
Cash flow hedges, net of tax of $(20.5) and $5.2		(32.0	)		7.6
Cash flow hedges, net of tax of $12.0 and $(8.7)							18.6		(13.6	)
Foreign currency translation		0.1			-		-		(0.7	)
Unrealized gain on available-for-sale securities, net of tax		0.6			-
Unrealized gain on available-for-sale securities, net of tax of $0.1 for both periods							0.2		0.2
Total comprehensive income	$	106.7		$	89.6	$	78.9	$	51.8

The following table shows the changes to ~~Accumulated Other Comprehensive~~accumulated other comprehensive Income from December 31, ~~2004,~~2005, to ~~September 30, 2005.~~March 31, 2006.

(Millions)
December 31, 2004 balance	$	(16.1	)
December 31, 2005 balance				$	(10.4	)
Cash flow hedges		(32.0	)		18.6
Foreign currency translation adjustment		0.1
Unrealized gain on available-for-sale securities		0.6			0.2
September 30, 2005 balance	$	(47.4	)
March 31, 2006 balance				$	8.4

~~-30-~~-34-

NOTE 15--EARNINGS PER SHARE

WPS Resources' common stock shares, $1 par value

September 30,
2005

December 31,
2004

Common stock outstanding, $1 par value, 200,000,000 shares authorized
38,091,465

37,500,791

Treasury shares
12,000
12,000
Average cost of treasury shares
$
25.19
$ 25.19
Shares in deferred compensation rabbi trust
267,794
229,238
Average cost of deferred compensation rabbi trust shares
$
40.13
$ 36.84

WPS Resources' common stock shares, $1 par value	March 31, 2006	December 31, 2005
Common stock outstanding, $1 par value, 200,000,000 shares authorized	40,266,630	40,089,898
Treasury shares	12,000	12,000
Average cost of treasury shares	$25.19	$25.19
Shares in deferred compensation rabbi trust	271,165	270,491
Average cost of deferred compensation rabbi trust shares	$41.09	$40.29

~~Earnings~~Basic earnings per share isare 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.~~grants, and shares related to the forward equity transaction. The calculation of diluted earnings per share for the ~~years~~periods 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 September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
(Millions, except per share amounts)	2005		2004		2005		2004		2006		2005
Income available to common shareholders	$	48.2	$	34.8	$	138.0	$	82.0	$	60.1	$	65.9
Basic weighted average shares		38.2		37.4		38.0		37.2		40.3		37.8
Incremental issuable shares		0.4		0.2		0.3		0.3		0.3		0.3
Diluted weighted average shares		38.6		37.6		38.3		37.5		40.6		38.1
Basic earnings per common share	$	1.26	$	0.93	$	3.63	$	2.20	$	1.49	$	1.74
Diluted earnings per common share	$	1.25	$	0.93	$	3.60	$	2.19	$	1.48	$	1.73

NOTE 16--REGULATORY ENVIRONMENT

Wisconsin

On ~~November 5, 2004,~~April 25, 2006, WPSC filed ~~an application~~ with the PSCW a stipulation agreement with various interveners to ~~defer all incremental costs, including carrying costs, resulting from unexpected problems encountered in~~refund a portion of the 2004 refueling outage at Kewaunee. During the refueling outage, an unexpected problem was encountered with equipment used for lifting the reactor vessel internal components to perform a required 10-year inspection. These equipment problems caused the outage to be extended by approximately three weeks. On November 11, 2004, the PSCW authorized WPSC to defer the replacementdifference between 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 problemsthat 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. The PSCW is reviewing the costs associated with this outage and WPSC expects these costs to be addressedprojected in the 2006 Wisconsin retail rate case ~~which should~~and actual Wisconsin retail fuel costs incurred from January through March 2006 as well as the projected savings in April through June 2006. This refund will be ~~settled in December 2005.~~a credit to customers' bills over the months of May 2006 to August 2006. A current liability of $9.4 million has been recorded at March 31, 2006, for a portion of the savings realized through March 31. Rates remain subject to refund under the agreement through the end of the year.

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 was made to resolve the issue and the unit went back into service at 100% power on July 4, 2005.March 31, 2006, WPSC filed a request with the PSCW ~~on March 11,~~to increase retail electric and natural gas rates 14.4% ($125.1 million) and 3.9% ($22.6 million), respectively for 2007. The proposed retail electric rate increase is required because of increased costs associated with electric transmission, (including the recovery of 2007 MISO costs, and deferred MISO costs from 2005 and 2006), higher fuel and purchased power costs (including the recovery of deferred costs for ~~deferral of replacement power~~reduced coal deliveries in 2005 and ~~operating and maintenance expenses incurred to address the design weakness and engineering issues identified. On March 17, 2005, the PSCW authorized WPSC to defer replacement fuel~~2006), costs related to the ~~outage. On April 8, 2005,~~construction of Weston 4 and the ~~PSCW approved deferral~~additional personnel to maintain and operate the plant, and costs to maintain the Weston 3 generation unit and the De Pere Energy Center. The proposed retail natural gas rate increase is driven by infrastructure improvements necessary to ensure the reliability of the ~~operating~~natural gas distribution system and ~~maintenance costs, including carrying costs at the most~~remediation of former manufactured gas sites. This filing included an 11.0% return on common equity and a common equity ratio of 60.35% in its regulatory capital structure.

~~-31-~~-35-

~~recently authorized pre-tax weighted average cost~~On December 22, 2005, the PSCW issued a final written order authorizing a retail electric rate increase of ~~capital. WPSC~~$79.9 million (10.1%) and a retail natural gas rate increase of $7.2 million (1.1%), effective January 1, 2006. The 2006 rates reflect an 11.0% return on common equity. The PSCW also ~~filed~~approved a common equity ratio of 59.7% in its regulatory capital structure. The retail electric rate increase was required primarily because of higher fuel and purchased power costs (including costs associated with ~~FERC~~the Fox Energy Center power purchase agreement), and also for ~~approval~~costs related to ~~defer these costs in~~ the ~~wholesale jurisdiction. FERC is in the process~~construction of ~~investigating the justness~~Weston 4, higher transmission expenses, and ~~reasonableness~~recovery of ~~the recovery~~a portion of the costs and will subsequently rule on the filing. For our Michigan retail customers, fuel costs are recovered through a pass through fuel adjustment clause and no deferral request is needed. Through July 4, 2005, WPSC had deferred $46.2 million of replacement power costs and $11.6 million of operating and maintenance expenses related to ~~this~~the 2005 Kewaunee outage. ~~WPSC believes recovery~~Partially offsetting the items discussed above, retail electric rates were lowered to reflect a refund to customers in 2006 of ~~these costs in future rates is probable and anticipates the PSCW will address recovery~~a portion of the ~~deferred costs in~~proceeds received from the ~~2006 rate case. On July 5, 2005, WPSC sold its 59% share of Kewaunee to Dominion. See Note 5,~~ ~~Acquisitions and Sales of Assets~~~~, for further information on the sale of Kewaunee.~~

~~As part of the Kewaunee sale, the PSCW approved the refund of the value~~liquidation of the nonqualified decommissioning trust fund ~~to customers. The details~~as a result of the ~~distribution~~sale of Kewaunee. The retail natural gas rate increase was driven by infrastructure improvements necessary to ensure the reliability of the refund will be addressed in the 2006 rate case. A proposal to refund the nonqualified decommissioning trust fund to customers was also approved by the FERC with no specification of the details for distribution. Subsequently, onnatural gas distribution system.

On June 7, 2005, WPSC filed with the PSCW, the MPSC, and the FERC a request for establishment of a cooperative joint proceeding for approval of the Kewaunee wind-up plan. The wind-up plan ~~provides~~proposed that the refunds due to both retail and wholesale customers ofrelated to proceeds received from the ~~value~~liquidation of the nonqualified decommissioning trust fund be offset by the net loss on the sale of the plant and also by certain costs related to the 2004 and 2005 Kewaunee ~~related deferred costs applicable to each customer class.~~outages. The wind-up plan ~~also seeks~~proposed to begin the amortization of the net regulatory liability as a credit to customer rates as of the effective date of the ~~PSCW’s~~PSCW's order ~~(expected~~(January 1, 2006). The FERC subsequently denied the request for joint proceeding with the PSCW. The wind-up plan was addressed by the PSCW in WPSC's 2006 rate case (discussed above). The PSCW ruled in the 2006 rate case that the deferred assets and liabilities related to the Kewaunee matters should be treated separately and not netted as WPSC initially proposed in its wind-up plan. In the 2006 rate case, the PSCW determined that Wisconsin retail customers were entitled to be refunded approximately 85% of the proceeds received from the liquidation of the nonqualified decommissioning trust fund based on a historical allocation methodology, or approximately $108 million of the total $127.1 million of proceeds received, over a two-year period beginning on January 1, ~~2006)~~2006 (in addition to the refund of carrying costs on the unamortized balance at the authorized pre-tax weighted average cost of capital). In 2005, the MPSC ruled that WPSC's Michigan customers were entitled to be refunded approximately 2% of the proceeds received from the liquidation of the nonqualified decommissioning fund and refunding to Michigan customers began in the third quarter of 2005. At March 31, 2006, WPSC had recorded a $113.1 million regulatory liability representing the amount of proceeds received from the liquidation of the nonqualified decommissioning trust fund remaining to be refunded to both retail and wholesale customers. On August 8, 2005, the FERC accepted the proposed refund plan for filing and ~~set it for hearing~~implemented the plan effective January 1, 2006, subject to refund upon final resolution. Settlement discussions between WPSC and settlement procedures; however, FERC denied the request for joint proceeding with the PSCW. The PSCW plans to address these issues as part of the 2006 rate case. FERC is holding a settlement discussion with WPSCwholesale parties contesting WPSC's refund plan were held both in the fourth quarter of ~~2005.~~

2005 and in the first quarter of 2006, and final resolution was reached between WPSC and one party on this matter, pending FERC approval. On April ~~1, 2005, WPSC filed an application~~25, 2006, formal settlement discussions were terminated 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~~remaining parties. The issues will be ~~effective January 1, 2006. Factors driving~~litigated at 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. These electric amounts do not include adjustments for the nonqualified decommissioning trust fund, the loss on the sale of Kewaunee, or the Kewaunee outages, all of which are discussed above.

On October 6, 2005, WPSC updated the previously filed 2006 rate case application with the PSCW for an additional 5.7% increase ($44.6 million increase in revenues) to the electric generation fuel cost. The update to the rate case is due to the drastic increase in natural gas prices, including the effect of production and supply disruptions in the Gulf of Mexico as a result of Hurricanes Katrina and Rita. WPSC initially used 2006 natural gas futures prices from Fall 2004 to predict the 2006 cost of fuel for its natural gas-fired electric generation facilities.

The amount of fuel and purchased power costs WPSC is authorized to recover in rates is established in its PSCW 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, on April 14, 2005, the PSCW reopened WPSC's 2005 rate case for potential refund of fuel and purchased power costs. Therefore, revenues collected after that date were subject to refund pending a review of projected fuel costs for 2005. Rates would be adjusted downward for the balance of the year if projected costs were deemed to be more than 2% less than the amount allowed in the 2005 rate case. At June 30, 2005, WPSC had recorded a refund liability of $2.1 million to reflect the potential fuel refund due to customers. Subsequently, due to the drastic increase in natural gas prices, projected fuel costs for 2005 are expected to be more than 2% higher than the currently approved level, and the $2.1 million refund liability recorded in June was reversed during the third quarter of 2005.

~~-32-~~

WPSC primarily receives coal for all of its coal-fired plants from the Power River Basin (PRB) region in Wyoming. Delivery of coal from the PRB region has been disrupted by train derailments and other operational problems purportedly caused by deteriorated rail track beds of approximately 100 miles in length in Wyoming. Repair and reconstruction of the rail line, jointly owned by BNSF Railway Co. and Union Pacific Railroad, is expected to extend until December 1, 2005 with remaining repairs completed in the Spring of 2006. Coal shipments and rail operations are expected to return to normal levels when construction activity is halted in December; however, deliveries may be delayed again in the Spring of 2006 as construction activity resumes. Reduced shipments of coal from Wyoming mines in the PRB will reduce PRB coal available for WPSC generating facilities. WPSC implemented a mitigation plan to conserve existing coal supplies and to obtain additional coal supplies from sources other than the PRB. The mitigation plan is resulting in increased incremental fuel and purchased power costs for WPSC. Therefore, on September 9, 2005, WPSC requested authorization to defer all incremental fuel and purchased power costs incurred, including carrying costs at WPSC’s most recent authorized pre-tax weighted cost of capital, as a result of the railroads’ reduction in coal deliveries and the actions taken by WPSC to manage coal supplies in this emergency situation. On September 23, 2005, the PSCW approved WPSC’s request for deferred treatment of the incremental fuel costs. As of September 30, 2005, $4.1 million was deferred.

~~On September 21, 2005, WPSC announced the acquisition of the Michigan and Minnesota natural gas distribution operations of Aquila, Inc. (Aquila). See Note 5,~~ ~~Acquisitions and Sales of Assets~~, for further information on the acquisition of these assets. In relation to the acquisition, WPS Michigan Utilities, Inc. and Aquila jointly filed with the MPSC on October 10, 2005, for approval of the termination of Aquila’s duty to provide natural gas service in Michigan and for WPS Michigan Utilities to provide natural gas service in the Michigan service territory of Aquila pursuant to the rates, terms, and conditions in Aquila’s current tariff book. Also in relation to the acquisition, on October 17, 2005, WPS Minnesota Utilities, Inc. and Aquila jointly filed with the Minnesota Public Utilities Commission to approve the sale of the Minnesota assets of Aquila’s two divisions, Aquila Networks-PNG and Aquila Networks-NMU, to WPS Minnesota Utilities pursuant to the Asset Purchase Agreement dated September 21, 2005. The MPSC and the Minnesota Public Utilities Commission have not yet ruled on the filings.FERC.

Michigan

On ~~December 8, 2004,~~January 3, 2006, UPPCO ~~submitted~~filed a request to the MPSC to approve UPPCO's proposed treatment of the pre-tax gains from certain sales of undeveloped and partially developed land located in the Upper Peninsula of Michigan as appropriate for ratemaking purposes. On February 4, 2005, UPPCO submitted an application to the MPSC for a 7.6% increase inits retail electric rates ~~($5.7~~by $6.6 million (8.1%), with an 11.5% return on equity, and a common equity ratio of 55% in ~~revenues).~~its regulatory capital structure. It is anticipated that, unless settled earlier, the MPSC will act on this request by the fourth quarter of 2006. UPPCO ~~also~~ requested interim ~~rate recovery of 6.0% ($4.5 million~~rates effective in ~~revenues)~~the second quarter, subject to ~~allow UPPCO to recover costs during the time~~refund, while the MPSC reviews the entire request. A hearing with the MPSC on the interim request took place on April 17, 2006, and an order is ~~reviewing~~expected to be effective in the ~~full case.~~second quarter of 2006. The retail electric rate increase ~~was~~is required ~~due~~in order to ~~costs associated with improving~~improve service quality and reliability, upgrade technology, ~~upgrades,~~ and ~~managing~~manage rising employee and retiree benefit costs. 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 and UPPCO withdrew theUPPCO's last retail electric rate increase request. 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. UPPCO intends to file a 2006 rate case with the MPSC.was in December 2002.

-36-

Federal

Through a series of orders issued by the FERC, Regional Through and Out Rates for transmission service between the MISO and the PJM Interconnection were eliminated effective December 1, 2004. To compensate transmission owners for the revenue they will no longer receive due to this rate elimination, the FERC ordered a transitional pricing mechanism called the Seams Elimination Charge Adjustment (SECA) to be put into ~~place, which will be~~place. Load-serving entities paid ~~by load serving entities. On February 10, 2005, FERC issued an order requesting compliance filings~~these SECA charges during a 16-month transition period from ~~transmission providers implementing the SECA effective~~ December 1, 2004, ~~subject~~through March 31, 2006. Total exposure for the 16-month transitional period, is $19.2 million for ESI, of which approximately $17 million relates to ~~refund~~its Michigan retail electric business and ~~surcharge, as appropriate. Public hearings will be held~~$2 million relates to its Ohio retail electric business. During the 16 months ended March 31, 2006, ESI has received billings of $19.2 million for these charges, of which $14.7 million has been expensed.

~~-33-~~

~~regarding the compliance filings.~~ The application and legality of the SECA is being challenged by many load-serving entities, including ESI. ~~On February 28, 2005,~~ ESI filed a motion for a Partial Stay of the February 10, 2005, FERC order, proposing that SECA charges on its Michigan load be postponed until a FERC order approves a decision or settlement in the formal hearing proceeding. FERC denied this motion on May 4, 2005. On June 3, 2005, ESI filed with FERC a request for rehearing of the order denying stay. ESI also participated in a joint petition to the District of Columbia Circuit Court in an attempt to obtain a final order from the FERC on rehearing of the initial SECA order. ESI will continuecontinues to pursue all avenues to appeal and/or reduce the SECA obligations. ~~In the interim, the~~It is probable that ESI's total exposure will be ~~managed through customer~~reduced by at least $4.5 million because of inconsistencies between the FERC's SECA order and the transmission owners' compliance filings (representing the difference between the amount ESI has paid for SECA charges and ~~other available avenues, where feasible.~~the amount that has been expensed as of March 31, 2006, as discussed above). ESI anticipates settling a significant portion of its SECA matters through vendor negotiations in the first half of 2006 and reached a $1 million settlement agreement with one of its vendors in January 2006. Resolution of issues to be raised in ~~the~~an upcoming SECA hearing offer the possibility of further reductions in ESI's exposure, but the extent is unknown at present. Through existing contracts, ESI has the ability to pass a portion of the SECA charges on to customers and has ~~begun to do~~been doing so. Since SECA is a transition charge ~~ending~~that ended on March 31, 2006, it does not directly impact ESI's long-term competitiveness.

The SECA is also an issue for WPSC and UPPCO, who have intervened and protested a number of proposals in this docket because they believe those proposals could result in unjust, unreasonable, and discriminatory charges for customers. It is anticipated that most of the SECA rate charges incurred by WPSC and UPPCO and any refunds will be passed on to customers through rates. WPSC and UPPCO have reached a settlement in principle with American Electric Power and Commonwealth Edison, which has been filed with the settlement judge. If this settlement is certified by the settlement judge and approved by the FERC, which is anticipated, American Electric Power and Commonwealth Edison will refund almost $1 million of the approximately $4 million paid by WPSC in the transition period.

Other

On September 21, 2005, WPS Resources announced that it had entered into agreements to acquire the Michigan and Minnesota natural gas distribution operations of Aquila. See Note 4, "Acquisitions and Sales of Assets," for further information on the acquisition of these assets. In relation to the acquisition, WPS Michigan Utilities, Inc. (which subsequently changed its name to Michigan Gas Utilities Corporation) and Aquila jointly filed with the MPSC on October 10, 2005, for approval of the termination of Aquila's duty to provide natural gas service in Michigan and for WPS Michigan Utilities to provide natural gas service in the Michigan service territory of Aquila pursuant to the rates, terms, and conditions in Aquila's current tariff book. On November 10, 2005, approval was obtained from the MPSC for the Michigan transaction. WPS Resources closed on the Michigan acquisition on April 1, 2006. On October 17, 2005, WPS Minnesota Utilities, Inc. (which subsequently changed its name to Minnesota Energy Resources Corporation) and Aquila jointly filed with the Minnesota Public Utilities Commission to approve the sale of the Minnesota assets of Aquila's two divisions, Aquila Networks-PNG and Aquila Networks-NMU, to WPS Minnesota Utilities pursuant to the Asset Purchase Agreement dated September 21, 2005. We anticipate that the Minnesota Public Utilities Commission will rule on this matter in the second quarter of 2006, and that the transaction will close this summer.

-37-

NOTE 17--SEGMENTS OF BUSINESS

We manage our reportable segments separately due to their different operating and regulatory environments. Prior to the fourth quarter of 2005, WPS Resources reported two nonregulated segments, ESI and PDI. In the fourth quarter of 2005, WPS Resources' Chief Executive Officer and its Board of Directors decided to view ESI and PDI as one business; therefore, corresponding changes were made to the segment information reported to them. Effective in the fourth quarter of 2005, WPS Resources began reporting to the Chief Executive Officer and Board of Directors one nonregulated segment, ESI. Segment information related to prior periods has been reclassified to reflect this change.

Our ~~utility business~~two regulated segments ~~are~~include the regulated electric utility operations of WPSC and UPPCO, and the regulated natural gas utility operations of ~~WPSC. Our other reportable segments include two nonregulated companies, ESI~~WPSC and ~~PDI.~~certain transition costs related to the acquisition of retail natural gas distribution operations in Michigan and the anticipated acquisition of retail natural gas distribution operations in Minnesota from Aquila. As discussed above, ESI is ~~a diversified~~our primary nonregulated segment offering natural gas, electric, and alternate fuel supplies as well as energy ~~supply~~management and consulting services ~~company. PDI is an electric~~to retail and wholesale customers, and marketing power from its generation ~~company.~~plants that are not under contract to third parties. The Other segment, another nonregulated 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⁽¹⁾

Reconciling
Eliminations

WPS Resources
Consolidated

Three Months Ended
September 30, 2005

External revenues
$
289.6

$
71.6

$
361.2

$
1,328.8

$
67.3

$
-

$
-

$
1,757.3

Intersegment revenues
9.0

0.2

9.2

12.1

10.5

0.3

(32.1
)

-

Income available for common shareholders
28.0

(3.5
)

24.5

8.9

13.2

1.6

-

48.2

Three Months Ended
September 30, 2004

External revenues $ 233.5 $ 45.5 $ 279.0 $ 782.4 $ 30.5 $ - $ - $ 1,091.9
Intersegment revenues 5.5 0.1 5.6 (2.9 ) 8.4 0.3 (11.4 ) -
Income available for common shareholders 32.1 (3.3 ) 28.8 2.5 4.2 (0.7 ) - 34.8

Nine Months Ended
September 30, 2005

External revenues
$
757.9

$
335.7

$
1,093.6

$
3,338.7

$
139.4

$
-

$
-

$
4,571.7

Intersegment revenues
25.0

0.5

25.5

18.4

27.8

0.9

(72.6
)

-

Income available for common shareholders
72.4

8.6

81.0

25.3

28.7

3.0

-

138.0

Nine Months Ended
September 30, 2004

External revenues $ 657.1 $ 284.5 $ 941.6 $ 2,518.0 $ 78.8 $ - $ - $ 3,538.4
Intersegment revenues 15.6 4.3 19.9 4.3 19.7 0.9 (44.8 ) -
Income available for common shareholders 60.2 9.9 70.1 16.7 (5.0 ) 0.2 - 82.0

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

	Regulated Utilities						Nonutility and Nonregulated Operations
Segments of Business *(Millions)*	Electric Utility⁽¹⁾		Gas Utility⁽¹⁾		Total Utility⁽¹⁾		ESI		Other⁽¹⁾		Reconciling Eliminations			WPS Resources Consolidated

Three Months Ended March 31, 2006
External revenues	$	246.2	$	193.0	$	439.2	$	1,598.8	$	-	$	-		$	2,038.0
Intersegment revenues		10.2		-		10.2		1.3		0.3		(11.8	)		-
Income available for common shareholders		15.5		6.7		22.2		37.1		0.8		-			60.1

Three Months Ended March 31, 2005
External revenues	$	236.3	$	174.6	$	410.9	$	1,076.0	$	-	$	-		$	1,486.9
Intersegment revenues		7.7		-		7.7		1.1		0.3		(9.1	)		-
Income available for common shareholders		23.5		14.0		37.5		28.2		0.2		-			65.9

~~-34-~~

~~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
September 30, 2005

External revenues
$
266.7

$
71.8

$
338.5

$
0.4

$
(0.4
)
$
338.5

Earnings on common stock
26.7

(3.5
)

23.2

2.6

(0.1
)

25.7

Three Months Ended
September 30, 2004

External revenues $ 214.6 $ 45.6 $ 260.2 $ 0.4 $ (0.4 ) $ 260.2
Earnings on common stock 31.5 (3.3 ) 28.2 2.3 - 30.5

Nine Months Ended
September 30, 2005

External revenues
$
705.8

$
336.2

$
1,042.0

$
-

$
-

$
1,042.0

Earnings on common stock
69.7

8.6

78.3

6.3

-

84.6

Nine Months Ended
September 30, 2004

External revenues $ 603.2 $ 288.8 $ 892.0 $ 1.1 $ (1.1 ) $ 892.0
Earnings on common stock 58.1 9.9 68.0 6.9 - 74.9

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

WPSC's principal business segments are the regulated electric utility operations and the regulated natural 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, 2006
External revenues	$	229.4	$	193.0	$	422.4	$	0.4	$	(0.4	)	$	422.4
Earnings on common stock		14.1		10.7		24.8		1.4		-			26.2

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

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

-38-

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 companies to measure the cost of share-based awards at the grant date fair value. That cost is recognized over the period during which an employee is required to provide service in exchange for the award. SFAS No. 123R 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 inApril 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 Staff Position No. FIN 46(R)-6, "Determining the Variability to Be Considered in Applying FASB Interpretation No. ~~47,~~46(R)." This Staff Position clarifies that a qualitative analysis of the design of an entity should be used to determine the variability to be considered in applying Interpretation No. 46(R), "Consolidation of Variable Interest Entities." In particular, the following steps should be used as the basis for that determination: (1) analyze the nature of the risks in the entity, and (2) determine the purpose(s) for which the entity was created and determine the variability (created by the risks identified in step (1)) the entity is designed to create and pass along to its interest holders. The guidance is to be applied prospectively beginning the first day of the first reporting period beginning after June 15, 2006. WPS Resources does not expect this guidance to have a significant impact on its financial statements.

In September 2005, the FASB ratified the consensus reached by the EITF on Issue 04-13, "Accounting for ~~Conditional Asset Retirement Obligations.~~Purchases and Sales of Inventory with the Same Counterparty." ~~Interpretation~~This guidance addresses the following issues: (1) whether two or more exchange transactions involving inventory with the same counterparty are entered into in contemplation of one another and should be viewed as a single exchange transaction within the scope of Accounting Principles Board Opinion No. ~~47 clarifies that the term Conditional Asset Retirement Obligation as used in FASB Statement No. 143,~~29, "Accounting for ~~Asset Retirement Obligations~~,Non-monetary Transactions," ~~refers to a legal obligation to perform an asset retirement activity~~and (2) whether non-monetary exchanges of inventory in ~~which~~ the ~~timing and/~~same line of business should be recognized at fair value. This consensus is effective for all arrangements entered into in reporting periods beginning after March 15, 2006, and for modifications or ~~method~~renewals of ~~settlement are conditional on a future event~~existing arrangements after 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.date. WPS Resources is ~~required to adopt the provisions of Interpretation No. 47 as of December 31, 2005. WPS Resources has not yet determined~~currently analyzing the impact ~~that the adoption~~ of ~~Interpretation No. 47 will have~~this guidance on its financial position or results of operations. If expenses under Interpretation No. 47 for WPSC and UPPCO differ from expenses recovered currently in rates, management will assess the probability of recovering this difference in future rates. To the extent future recovery is probable, a regulatory asset would be recognized in accordance with the provisions of SFAS No. 71.statements.

~~-35-~~-39-

Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION - WPS RESOURCES

WPS Resources is a diversified holding company operating through subsidiaries that ~~is exempt from the Public Utility Holding Company Act of 1935.~~provide energy and related services. Our wholly owned subsidiaries include two regulated utilities, WPSC ~~(which is an operating entity~~and UPPCO, as well as ~~a holding company exempt~~certain transition costs related to the acquisition of retail natural gas distribution operations in Michigan and the anticipated acquisition of retail natural gas distribution operations in Minnesota from ~~the Public Utility Holding Company Act of 1935) and UPPCO.~~Aquila, Inc. (Aquila). Another wholly owned subsidiary, WPS Resources Capital Corporation, is a holding company for our nonregulated ~~businesses, including~~ ESI ~~and PDI.~~subsidiary.

Strategic Overview

The focal point of WPS Resources' business plan is the creation of long-term value for our shareholders ~~(through~~and our customers through growth, operational excellence, ~~and~~ asset ~~management)~~management, risk management, and the continued emphasis on reliable, competitively priced, and environmentally sound energy ~~services for our customers.~~and energy related services. We are seeking growth of our ~~utility~~regulated and nonregulated portfolio ~~but we are~~and placing an emphasis on regulated growth. A discussion of the essential components of our business plan is set forth below:

Maintain and Grow a Strong Regulated Utility Base - We are focusing on growth in our ~~utility~~regulated operations. A strong regulated utility base is important in order to maintain a strong balance sheet, predictable cash flows, a desired risk profile, attractive dividends, and quality credit ratings, which are critical to our success. WPS Resources believes the following recent ~~events~~developments have helped, or will help maintain and grow its ~~strong~~regulated utility base:

·	In 2004, WPSC signed power sales contracts with Consolidated Water Power through December 31, 2017, and Wisconsin Public Power Inc. through April 30, 2021, in order to bolster growth beyond the normal utility growth rate.

WPSC is ~~also~~ expanding its regulated generation fleet in order to meet growing electric demand and ensure ~~the~~ continued ~~reliability~~reliability. Construction of ~~energy services. Construction is underway on~~ the 500-megawatt coal-fired Weston 4 base-load power plant located near Wausau, ~~Wisconsin.~~Wisconsin, is underway, in partnership with DPC. In addition, WPSC ~~also continues to pursue~~is pursuing plans to construct other electric ~~generating~~generation facilities ~~but details relating~~in the future, in particular to ~~fuel type~~meet new energy efficiency and ~~in-service dates have yet to be determined.~~renewables standards enacted in Wisconsin.

In September 2005, WPS Resources entered into a definitive ~~agreement~~agreements with Aquila ~~Inc.~~ to acquire ~~Aquila's~~its natural gas distribution operations in Michigan and ~~Minnesota. Subject to various regulatory approvals, these transactions are~~Minnesota and completed the acquisition of the Michigan operations on April 1, 2006. The purchase of the operations in Minnesota is expected to close in the ~~first half~~summer of 2006, ~~and will more than double~~after approval is received from the ~~size~~Minnesota Public Utilities Commission. The addition of these regulated assets in close proximity to WPS ~~Resource's current utility~~Resources' existing regulated electric and natural gas ~~business.~~

·	~~WPS Resources currently owns approximately 28% of ATC, which is a utility operation that owns, builds, maintains, and operates high voltage electric transmission lines primarily~~operations in Wisconsin and ~~Upper Michigan.~~ Michigan will transition WPS Resources to a larger and stronger regional energy company.
·	We continue to ~~increase our ownership interest~~invest in ~~the~~ ATC ~~through~~and receive additional equity interest ~~received~~ as consideration for funding a portion of the Duluth, Minnesota, to Wausau, Wisconsin, transmission ~~line.~~line and currently expect this interest to contribute between 10% and 15% of earnings, on average.
·	WPSC continues to invest in environmental projects to improve air quality and meet the requirements set by environmental regulators. Capital projects to construct and upgrade equipment to meet or exceed required environmental standards are planned each year.

Integrate Resources to Provide Operational Excellence - WPS Resources is committed to integrating ~~the~~ resources of its regulated business units ~~(in accordance with~~and also its nonregulated business units, while maintaining any and all applicable regulatory ~~restrictions)~~and legal restrictions. This will provide the best value to all customers by leveraging ~~their~~the individual capabilities and expertise ~~across the company.~~of each unit and assist in lowering costs for certain activities.

This strategy is evident at our nonregulated subsidiaries, where we have restructured the management of our two primary nonregulated subsidiaries (ESI and PDI). Currently, we have one executive management team overseeing the operations of all of our nonregulated businesses. ESI also continues to optimize the value of PDI's merchant generation fleet and reduce the market price risk while extracting additional value from these plants, through the use of various financial and physical instruments (such as forwards, futures, options, and swaps), which has provided more predictable revenues and margin.

~~-36-~~-40-

~~Combining~~We have integrated resources at our nonregulated subsidiaries by restructuring the management teams of ESI and PDI and taking measures to reduce merchant generation market risk.

This strategy will also be demonstrated in our regulated business by optimally sourcing work and combining resources to achieve best practices ofat WPSC, UPPCO, and the ~~Aquila~~ natural gas distribution ~~businesses~~operations in Michigan and Minnesota, ~~(expected to be acquired in 2006) is expected to enhance operations of our overall natural gas distribution businesses.~~operational excellence, and sustainable value for customers and shareholders.

Strategically Grow Nonregulated Businesses - ESI ~~looks to~~will grow its electric and natural gas business ~~targeting growth in the northeastern United States and adjacent portions of Canada~~ (through strategic acquisitions, market penetration ofin existing ~~businesses,~~markets, and new product offerings)~~, which is~~ by targeting growth in areas where it has market expertise and through "strategic hiring" in other areas. ESI ~~has the most market expertise. PDI~~also focuses on optimizing the operational efficiency of its existing portfolio of assets and pursues compatible ~~power~~ development projects ~~and the acquisition of generation assets~~ that strategically fit with ~~ESI's~~its customer base and market expertise. ~~The acquisition of Advantage Energy in July 2004 provided ESI with enhanced opportunities to compete in the New York market and had a positive impact on ESI's margin in the first half of 2005.~~

·	ESI began offering retail electric products primarily to large commercial and industrial customers in Illinois and New Hampshire and plans on marketing these products in the second quarter of 2006 in Rhode Island. Previously, in 2005, ESI was only offering natural gas products and energy management services to customers in Illinois and did not offer retail electric products in New Hampshire and Rhode Island.
·	ESI began developing a product offering in the Texas retail electric market in 2005. Entry into Texas, with its thriving market structure, provides ESI with an opportunity to leverage the infrastructure and capability ESI developed to provide products and services that it believes customers will value. ESI plans on serving customers in the Texas market starting in the third quarter of 2006.
·	ESI began marketing electric products to customers in Massachusetts in 2005 and has had initial success in signing up commercial and industrial customers.

Place Strong Emphasis on Asset and Risk Management -Our asset management strategy calls for the ~~continuing disposition~~continuous assessment of our existing assets and ~~acquisition of assets in a manner that enhances our earnings capability. The acquisition portion of this strategy calls for~~ the acquisition of assets that complement our existing ~~businesses~~business and strategy. This strategy such as the pending acquisitions of Aquila's natural gas distribution operations in Michigan and Minnesota, which are expected to be accretive to earnings (excluding one-time transition costs) over the first 12 months following the close of the acquisition, as well as ESI's 2004 acquisition of Advantage Energy. The utilities are the backbone of our earnings, and we expect ESI and PDI to continue to provide between 15 and 25 percent of our earnings in the future.

~~Another portion of the strategy~~also calls for the disposition of assets, including plants and entire business units, which are either no longer ~~required for operations. The sale~~strategic to ongoing operations, are not performing as needed, or would reduce our risk profile. We maintain a portfolio approach to risk and earnings and expect ESI to provide between 20 and 30 percent of ~~Sunbury's allocated emission allowances was completed~~our earnings in ~~May 2005 for $109.9 million. The proceeds received from~~ the sale enabled Sunbury to eliminate its non-recourse debt obligation, which provided greater flexibility as PDI evaluates its options related to Sunbury. These options range from closing the plant, operating the plant only during favorable economic periods, to a future sale. We also sold WPSC's Kewaunee plant in July 2005. The major benefits of the Kewaunee sale include transferring financial risk from WPSC's electric customers and WPS Resources' shareholders to Dominion, greater certainty of future energy costs through a purchase power agreement, and being able to return the non-qualified decommissioning funds to our customers.future.

·	The acquisition of the Michigan natural gas distribution operations from Aquila in April 2006, and the anticipated acquisition of the Minnesota natural gas distribution operations from Aquila will transition WPS Resources into a larger and stronger regional energy company.
·	On March 30, 2006, a subsidiary of WPS Resources entered into an agreement to sell its one-third interest in Guardian Pipeline, LLC to Northern Border Partners, LP for $38.5 million. The transaction closed in April 2006, resulting in a pre-tax gain of approximately $6 million in the second quarter of 2006. We believe it will provide a good opportunity to redeploy the proceeds into other investment opportunities providing value to our shareholders.
·	In April 2006, ESI sold WPS ESI Gas Storage, LLC, which owns a natural gas storage field in Kimball Township, St. Clair County, Michigan. ESI utilized this facility primarily for structured wholesale natural gas transactions as natural gas storage spreads presented arbitrage opportunities. ESI was not actively marketing this facility for sale, but believed the price being offered was above the value it would realize from continued ownership of the facility. Proceeds received in April from the sale of the Kimball natural gas storage field, stored gas, and other related assets were $19.9 million, which is expected to result in a pre-tax gain of approximately $9 million in the second quarter of 2006.
·	We ~~also~~ continue to evaluate alternatives for the sale of our identified real estate holdings no longer needed for operation.

The risk management strategy, in addition to ~~evaluate alternatives for~~asset risk management, includes the ~~sale~~management of market, credit and operational risk through the ~~balance~~normal course of our identified real estate holdings no longer needed for operation. A significant portion of our expected land sales are at UPPCO and will benefit our customers as well as our shareholders. UPPCO withdrew a rate increase request that it filed in February 2005 after the MPSC approved its requested regulatory treatment of these land sales by sharing gains between customers and shareholders.business.

-41-

·	Forward purchases and sales of electric capacity, energy, natural gas, and other commodities allow for opportunities to secure prices in a volatile price market.
·	An initiative we call "Competitive Excellence" is being deployed across our entire company. Competitive Excellence strives to eliminate work that does not provide value for our customers. This will create more efficient processes, improve the effectiveness of employees, and reduce costs.

Business Operations

Our regulated and nonregulated businesses have distinct competencies and business ~~strategies,~~strategies. They offer differing energy and energy related products and services, and experience a wide array of risks and ~~challenges and are viewed uniquely by management.~~challenges. The "Management's Discussion and Analysis of Financial Condition and Results of Operations - Introduction - WPS Resources," appearing in ~~the 2004~~our 2005 Form 10-K included a discussion of these topics. There have not been significant changes to the content of the matters discussed in the above referenced ~~section~~Section of ~~the 2004~~our 2005 Form 10-K; however, certain tables have been updated and included below to reflect current information. These tables should be read in conjunction with the discussion appearing in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Introduction - WPS Resources," appearing in ~~the 2004~~our 2005 Form 10-K.

The table below discloses future natural gas and electric sales volumes under contract at ESI as of ~~September 30, 2005.~~March 31, 2006. Contracts are generally one to three years in duration. ESI expects that its ultimate sales volumes in ~~2005~~2006 and beyond will exceed the volumes shown in the table below as it continues to seek growth opportunities and existing customers who do not have long-term contracts continue to buy their short-term requirements from ESI.

~~-37-~~


Forward Contracted Volumes at ~~September 30, 2005~~3/31/2006 ⁽¹⁾	~~October 1, 2005~~ ~~through~~ ~~September 30, 2006~~4/01/06 to 3/31/07		~~October 1, 2006~~04/01/07 to 03/31/08		~~through~~ ~~September 30,~~After March 31, 2008

Wholesale sales volumes - billion cubic feet		~~115.8~~137.0		~~12.3~~14.8		5.8
Retail sales volumes - billion cubic feet		~~151.1~~184.0		~~47.0~~41.0		37.4
Total natural gas sales volumes		~~266.9~~321.0		~~59.3~~55.8		43.2

Wholesale sales volumes - million kilowatt-hours		~~10,951~~16,131		~~4,803~~7,027		4,346
Retail sales volumes - million kilowatt-hours		~~2,374~~1,868		~~751~~430		140
Total electric sales volumes		~~13,325~~17,999		~~5,554~~7,457		4,486

⁽¹⁾ This table represents physical sales contracts for natural gas and electric power for delivery or settlement in future periods; however, there is a possibility that some of the contracted volumes reflected in the above table could be net settled. Management has no reason to believe that gross margins that will be generated by the contracts included above will vary significantly from those experienced historically.

For comparative purposes, the future natural gas and electric sales volumes under contract at ~~September 30, 2004,~~March 31, 2005, are shown below. ~~Actual~~The actual electric and natural gas sales volumes for the ~~nine~~three months ended ~~September 30,~~March 31, 2006, and 2005 ~~and 2004~~ are disclosed within Results of Operations - WPS Resources, ESI Segment Operations below.

Forward Contracted Volumes at September 30, 2004 ⁽¹⁾

October 1, 2004
through
September 30, 2005

October 1, 2005
through
September 30, 2007

Wholesale sales volumes - billion cubic feet 91.3 13.6
Retail sales volumes - billion cubic feet 162.9 48.9
Total natural gas sales volumes 254.2 62.5

Wholesale sales volumes - million kilowatt-hours 5,523 1,032
Retail sales volumes - million kilowatt-hours 3,730 1,832
Total electric sales volumes 9,253 2,864

-42-

Forward Contracted Volumes at 3/31/2005 ⁽¹⁾	04/01/05 to 03/31/06	04/01/06 to 03/31/07	After March 31, 2007

Wholesale sales volumes - billion cubic feet	111.7	6.7	1.7
Retail sales volumes - billion cubic feet	155.6	30.7	12.6
Total natural gas sales volumes	267.3	37.4	14.3

Wholesale sales volumes - million kilowatt-hours	8,032	1,753	1,584
Retail sales volumes - million kilowatt-hours	3,863	1,575	285
Total electric sales volumes	11,895	3,328	1,869

⁽¹⁾ This table represents physical sales contracts for natural gas and electric power for delivery or settlement in future periods; however, there is a possibility that some of the contracted volumes reflected in the above table could be net settled. ~~Management has no reason to believe that gross margins that will be generated by these contracts will vary significantly from those experienced historically.~~

Both retail and wholesale natural gas volumes under contract have increased as of March 31, 2006, compared to March 31, 2005. The increase in retail natural gas volumes under contract was driven by continued customer growth in Canada. Also, ESI has been able to lock in contracts with retail natural gas customers in other markets due to a decline in natural gas prices compared to the latter half of 2005. In the first quarter of 2006, customers were more inclined to lock in prices related to their natural gas purchases, compared to the first quarter of 2005. Increased volatility in natural gas prices and high natural gas storage spreads (future natural gas sales prices were higher than the near term price of natural gas) increased the profitability of natural gas transactions, driving the increase in wholesale natural gas sales volumes under contract at March 31, 2006, compared to March 31, 2005. Wholesale electric volumes under contract increased significantly at March 31, 2006. ESI continues to expand its wholesale origination capabilities with a focus on physical, customer-based purchase and sale agreements in areas where it has market expertise. The emphasis ESI is placing on its originated wholesale customer electric business is producing encouraging results and, as a result, ESI has recently locked in numerous contracts to provide electricity to customers in the future. Retail electric sales volumes under contract have decreased at March 31, 2006. ESI has experienced significant customer attrition in Michigan as a result of tariff changes granted to Michigan utilities and high wholesale energy prices. ESI's retail electric aggregation sales in Ohio ended on December 31, 2005, with the expiration of ESI's contracts with its Ohio aggregation customers.

In order to mitigate its exposure to credit risk, ESI employs credit policies. As a result of these credit policies, ESI has not experienced significant write-offs from its large wholesale counterparties to date. The table below summarizes ESI's wholesale counterparty credit exposure, categorized by maturity date, as of ~~September 30, 2005.~~March 31, 2006. At ~~September 30, 2005,~~March 31, 2006, ESI had net exposure with ~~one non-rated counterparty~~two investment grade counterparties that ~~was~~were more than 10% of total ~~exposure, including collateral. Total~~exposure. Net exposure with ~~this counterparty~~these counterparties was ~~$41.2~~$47.9 million and is included in the table below.

~~-38-~~-43-

Counterparty Rating *(Millions)* ⁽¹⁾	Exposure ⁽²⁾		Exposure Less Than 1 Year		Exposure 1 to 3 Years		Exposure 4 to 5 years

Investment grade - regulated utility	$	32.0	$	22.4	$	7.2	$	2.4
Investment grade - other		125.4		72.8		48.3		4.3

Non-investment grade - regulated utility		6.9		6.9		-		-

Non-rated - regulated utility ⁽³⁾		14.1		4.6		7.8		1.7
Non-rated - other ⁽³⁾		64.8		52.8		10.0		2.0

Exposure	$	243.2	$	159.5	$	73.3	$	10.4

Counterparty Rating (Millions) ⁽¹⁾

Exposure ⁽²⁾

Exposure Less
Than 1 Year

Exposure 1
to 3 Years

Exposure 4
to 5 years

Investment grade - regulated utility $ 13.7 $ 13.7 $ - $ -
Investment grade - other 305.0 223.8 76.0 5.2

Non-investment grade - regulated utility 32.2 32.2 - -
Non-investment grade - other 4.9 4.9 - -

Non-rated - regulated utility ⁽³⁾
- - - -
Non-rated - other ⁽³⁾
97.1 85.4 10.3 1.4

Total Exposure $ 452.9 $ 360.0 $ 86.3 $ 6.6

⁽¹⁾The investment and non-investment grade categories are determined by publicly available credit ratings of the counterparty or the rating of any guarantor, whichever is higher. Investment grade counterparties are those with a senior unsecured Moody's rating of Baa3 or above or a Standard & Poor's rating of BBB- or above.

⁽²⁾

Exposure considers netting of accounts receivable and accounts payable where netting agreements are in place as well as netting mark-to-market exposure. Exposure is before consideration of collateral from counterparties. Collateral, in the form of cash and letters of credit, received from counterparties totaled $68.4 million at September 30, 2005, $63.0 million from investment grade counterparties, and $5.4⁽²⁾Exposure considers netting of accounts receivable and accounts payable where netting agreements are in place as well as netting mark-to-market exposure. Exposure is before consideration of collateral from counterparties. Collateral, in the form of cash and letters of credit, received from counterparties totaled $63.0 million at March 31, 2006, $39.1 million from investment grade counterparties, and $23.9 million from non-rated counterparties.

⁽³⁾ Non-rated counterparties include stand-alone companies, as well as unrated subsidiaries of rated companies without parental credit support. These counterparties are subject to an internal credit review process.

RESULTS OF OPERATIONS - WPS RESOURCES

~~Third~~First Quarter ~~2005~~2006 Compared with ~~Third~~First Quarter ~~2004~~2005

WPS Resources Overview

WPS Resources' results of operations for the ~~three months~~quarters ended ~~September 30~~March 31 are shown in the following table:


WPS Resources' Results (Millions, except share amounts)	2005		2004		Change			2006		2005		Change

Consolidated operating revenues	$	1,757.3	$	1,091.9		60.9	%
Income available for common shareholders	$	48.2	$	34.8		38.5	%	$	60.1	$	65.9		(8.8	%)
Basic earnings per share	$	1.26	$	0.93		35.5	%	$	1.49	$	1.74		(14.4	%)
Diluted earnings per share	$	1.25	$	0.93		34.4	%	$	1.48	$	1.73		(14.5	%)

The $665.4 million increase in consolidated operating revenues for the quarter ended September 30, 2005, compared to the same quarter in 2004, was driven by a $561.4 million (72.0%) increase in revenue at ESI, an $85.8 million (30.1%) increase in utility revenue, and a $38.9 million (100.0%) increase in PDI revenue. Higher revenue at ESI was driven by an increase in natural gas prices, continued expansion of the Canadian natural gas business, and higher volumes related to an increase in structured wholesale natural gas transactions. Electric utility revenue increased $59.6 million, primarily due to higher electric sales volumes related to warmer summer weather conditions and new power sales agreements with wholesale customers, and an approved retail electric rate increase. Gas utility revenue increased $26.2 million due to an increase in the per-unit cost of natural gas, higher natural gas throughput volumes, and an approved rate increase. The increase in revenue at PDI was driven by higher revenue at Sunbury due to increased opportunities to sell power into the market due to the expiration of a fixed price outtake contract and mark-to-market gains on derivatives utilized to protect the value of a portion of PDI's Section 29 federal tax credits. Revenue changes by reportable segment are discussed in more detail below.

~~-39-~~

Income available for common shareholders was ~~$48.2~~$60.1 million ($~~1.26~~1.49 basic earnings per share) for the quarter ended ~~September 30, 2005,~~March 31, 2006, compared to ~~$34.8~~$65.9 million ($~~0.93~~1.74 basic earnings per share) for the same quarter in ~~2004.~~2005. Significant factors impacting the change in earnings and earnings per share are as follows (and are discussed in more detail below).

PDI's earnings increased $9.0 million during the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004. The increase in PDI's earnings can be attributed to mark-to-market and realized gains on derivative instruments utilized to protect a portion of PDI's Section 29 federal tax credits and significant improvements in Sunbury's margin, partially offset by a decrease in Section 29 federal tax credits recognized during the quarter.

~~ESI's~~Electric utility earnings ~~increased $6.4~~decreased $8.0 million, ~~driven by a $22.1~~from $23.5 million ~~improvement in its natural gas margin during~~for the quarter ended ~~September 30,~~March 31, 2005, to $15.5 million for the quarter ended March 31, 2006. The decrease in electric utility earnings was driven by residential customer conservation efforts and the negative impact warmer weather conditions had on the electric utility margin in the first quarter of 2006, compared to the same quarter in 2005. The Kewaunee power purchase agreement and the ~~prior year. ESI's electric margin~~refund of a portion of the proceeds received from the liquidation of the Kewaunee nonqualified nuclear decommissioning fund had little impact on earnings as these items were offset with revenues and operating expenses.

-44-

·	Natural gas utility earnings decreased ~~$6.9~~$7.3 million, ~~driven by lower margin~~ from ~~portfolio optimization strategies and lower margin from retail electric operations in Michigan. Partially offsetting~~$14.0 million for the ~~overall margin improvement was a $5.7~~quarter ended March 31, 2005, to $6.7 million for the quarter ended March 31, 2006, primarily due to an $8.8 million increase in ~~ESI's~~ operating and maintenance expenses (driven by $4.1 million of transition costs associated with the acquisition of retail natural gas distribution operations in Michigan and the anticipated acquisition of retail natural gas distribution operations in Minnesota from Aquila), and a $1.5 million decrease in the natural gas margin, driven by warmer weather conditions and customer conservation efforts.
·	ESI's earnings increased $8.9 million, from $28.2 million for the quarter ended March 31, 2005, to $37.1 million for the quarter ended March 31, 2006. Higher earnings were driven by a $34.1 million increase in margin, partially offset by an $8.3 million decrease in tax credits recognized and a $3.9 million increase in operating expenses.
·	Earnings at the Holding Company and other segment increased $0.6 million, from $0.2 million for the quarter ended March 31, 2005, to $0.8 million for the quarter ended March 31, 2006. The increase was primarily related to ~~continued business expansion.~~a $3.7 million increase in pre-tax earnings from ATC, substantially offset by a $2.7 million increase in operating expenses.

~~Utility~~The change in basic earnings ~~decreased $4.3~~per share was impacted by the items discussed above as well as an increase of 2.5 million ~~(14.9%), largely due~~shares in the weighted average number of outstanding shares of WPS Resources' common stock for the quarter ended March 31, 2006, compared to the ~~negative impact that increasing natural gas prices had on third~~same quarter ~~margin at~~in 2005. WPS Resources' issuance of 1.9 million additional shares of common stock through a public offering in November 2005 was the electric utility. Earnings were also negatively impacted because certain costs incurred in the third quarter of 2005 related to plant outages, carrying costs on capital additions, and other costs (which are recovered in rates relatively evenly throughout the year) were partially recovered in revenue during the first six months of the year, leading to higher earnings in those periods.

~~A $2.6 million pre-tax increase (approximately $1.6 million after taxes) in equity earnings from our investment in the ATC also contributed~~primary contributor to the increase in ~~income available for common shareholders.~~the weighted average number of shares outstanding. Additional shares were also issued in 2005 and in the first quarter of 2006 under the Stock Investment Plan and certain stock-based employee benefit plans.

Overview of Utility Operations

Utility operations include (1) the electric utility segment, consisting of the electric operations of WPSC and UPPCO, and (2) the gas utility segment, consisting of the natural gas operations of ~~WPSC.~~WPSC as well as certain transition costs related to the acquisition of retail natural gas distribution operations in Michigan and the anticipated acquisition of retail natural gas distribution operations in Minnesota from Aquila. Income available for common shareholders attributable to the electric utility segment was ~~$28.0~~$15.5 million for the quarter ended ~~September 30, 2005,~~March 31, 2006, compared to ~~$32.1~~$23.5 million for the same quarter ~~ended September 30, 2004. The net loss~~in 2005. Income available for common shareholders attributable to the gas utility segment was ~~$3.5~~$6.7 million for the quarter ended ~~September 30, 2005,~~March 31, 2006, compared to ~~a net loss of $3.3~~$14.0 million for the same quarter ~~ended September 30, 2004.~~in 2005.

Electric Utility Segment Operations


WPS Resources' Electric Utility	Three Months Ended September 30,							Three Months Ended March 31,
Segment Results (Millions)	2005		2004		Change			2006		2005		Change

Revenue	$	298.6	$	239.0		24.9	%
Revenues								$	256.4	$	244.0		5.1	%
Fuel and purchased power costs		150.0		74.7		100.8	%		125.7		80.7		55.8	%
Margin	$	148.6	$	164.3		(9.6	%)
Margins								$	130.7	$	163.3		(20.0	%)

Sales in kilowatt-hours		4,207.4		3,730.0		12.8	%		3,827.9		3,680.4		4.0	%

Electric utility revenue increased ~~$59.6~~$12.4 million ~~(24.9%~~(5.1%) for the quarter ended ~~September 30, 2005,~~March 31, 2006, compared to the same quarter ~~ended September 30, 2004. Electric utility revenue increased~~in 2005, largely due to an ~~increase in electric sales volumes and an~~ approved annual electric rate increase for WPSC's Wisconsin retail ~~customers. Electric~~customers and a 4.0% increase in electric sales ~~volumes increased 12.8%, primarily due to significantly warmer weather in the third quarter of~~volumes. In December 2005, ~~compared to the third quarter of 2004, and new power sales agreements that were~~

~~-40-~~

~~entered into with wholesale customers. As a result of the warm weather, WPSC set all-time records for peak electric demand in the third quarter of 2005. On December 21, 2004,~~ the PSCW approved a retail electric rate increase of ~~$60.7~~$79.9 million ~~(8.6%~~(10.1%), effective January 1, ~~2005.~~2006. The retail electric rate increase was required primarily ~~to recover increased costs related to~~because of higher fuel and purchased power costs (including costs associated with the Fox Energy Center power purchase agreement), and also for costs related to the construction of ~~the~~ Weston 4, ~~base-load generation facility,~~higher transmission expenses, and ~~benefit costs.~~recovery of a portion of the costs related to the 2005 Kewaunee outage. Partially offsetting the items discussed above, rates were lowered to reflect a refund to customers in 2006 of a portion of the proceeds received from the liquidation of the nonqualified decommissioning trust fund as a result of the sale of Kewaunee. The increase in electric

-45-

sales volumes was largely due to a 15% increase in wholesale sales volumes, driven by higher demand from existing WPSC wholesale customers. The increase in electric sales volumes to the wholesale customers was largely offset by a decrease in electric sales volumes to higher margin residential customers, resulting from residential customer conservation efforts and warmer weather during the heating season in the first quarter of 2006, compared to the same period in 2005. Residential customers are taking measures to conserve energy as a result of recent rate increases.

The electric utility margin decreased ~~$15.7~~$32.6 million ~~(9.6%~~(20.0%) for the quarter ended ~~September 30, 2005,~~March 31, 2006, compared to the quarter ended ~~September 30, 2004.~~March 31, 2005. The decrease ~~can be attributed to~~in electric margin was driven by a ~~$16.6~~$33.5 million ~~(10.9%~~(22.2%) decrease in WPSC's electric margin, ~~which was largely driven by~~primarily related to the sale of Kewaunee on July 5, 2005, and the related power purchase agreement. Prior to the sale of Kewaunee, only nuclear fuel expense was reported as a component of fuel, natural gas, and purchased ~~power costs.~~power. Subsequent to the sale, all payments to Dominion Energy Kewaunee, LLC (Dominion) for power purchased from Kewaunee are reported as ~~components~~a component of utility cost of fuel, natural gas, and purchased ~~power costs.~~power. These include both variable payments for energy delivered and fixed payments. As a result of the sale, WPSC no longer incurs operating and maintenance ~~expense,~~expenses, depreciation and decommissioning expense, or interest expense ~~for~~related to Kewaunee.

Excluding the ~~$21.0~~$24.0 million of fixed ~~payment~~payments made to Dominion ~~Energy Kewaunee, LLC~~ in the ~~third~~first quarter of ~~2005,~~2006, WPSC's electric utility margin decreased $9.5 million, which was driven by a $13.8 million decrease in rates related to the refund of a portion of the Kewaunee nonqualified decommissioning fund to customers. Pursuant to regulatory accounting, the decrease in margin related to this refund was offset by a corresponding decrease in operating and maintenance expenses as explained below and, therefore, did not have a significant impact on earnings. Adjusting for the decrease in revenues related to the refund, the electric utility margin increased ~~$5.3~~$4.3 million. The retail electric rate increase and an increase in margin related to higher sales volumes to wholesale customers drove the remaining net increase in the electric utility margin. However, the increase in margin provided by the rate increase and the increase in wholesale electric sales volumes, was largely offset by a decrease in electric sales volumes to WPSC's higher margin residential electric customers. Residential customer conservation efforts and weather that was approximately 11% warmer during the heating season drove the decrease in residential sales volumes.

Gas Utility Segment Operations

WPS Resources'	Three Months Ended March 31,
Gas Utility Segment Results (Millions)	2006		2005		Change

Revenues	$	193.0	$	174.6		10.5	%
Purchased gas costs		148.2		128.3		15.5	%
Margins	$	44.8	$	46.3		(3.2	%)

Throughput in therms		266.9		308.7		(13.5	%)

Natural gas utility revenue increased $18.4 million (10.5%) for the quarter ended March 31, 2006, compared to the same quarter in ~~the prior year. This increase was driven by the increase in electric sales volumes and the rate increase discussed above, but was largely offset by higher per-unit fuel and purchased power costs.~~

The quantity of power purchased by WPSC during the quarter ended September 30, 2005, increased approximately 168% compared to the same quarter in 2004, and fuel and purchased power costs were approximately 68% higher on a per-unit basis. The increase in the quantity of power purchased was largely due to power purchased from Dominion Energy Kewaunee, LLC as previously discussed, warm weather conditions, WPSC's need to conserve coal because of coal supply issues (see ~~Other Future Considerations~~~~), and a planned outage at WPSC's Weston 3 generation plant that began in the third quarter of~~ 2005. The increase in the per-unit cost of fuel and purchased power was driven by the sale of Kewaunee (primarily related to $21.0 million of fixed payments being recorded as a component of fuel and purchased power costs), congestion charges and line loss charges that were not fully offset by credits from MISO, increased coal costs related to procurement of coal from alternate sources, and the need to supply more energy from higher cost peaking units due to warm weather conditions, coal conservation efforts, and a planned outage at WPSC's Weston 3 generation plant that began in the third quarter of 2005. The PSCW approved the deferral of increased fuel and purchased power costs related to the MISO and coal supply matters discussed above and WPSC deferred $15.9 million of costs related to these issues in the third quarter of 2005. Excluding deferred costs, fuel and purchased power costs at WPSC increased $68.7 million. As discussed above, approximately $21.0 million of the increase in purchased power costs related to the Kewaunee fixed payments. Excluding these fixed payments, fuel and purchased power costs at WPSC increased $47.7 million and total fuel and purchased power costs incurred during the quarter exceeded the amount recovered from ratepayers (as approved in the 2005 rate case), therefore, having a negative impact on margin.

The PSCW allows WPSC to adjust prospectively the amount billed to Wisconsin retail customers for fuel and purchased power if costs are above or below approved levels by more than 2% on an annualized basis. At June 30, 2005, WPSC was experiencing fuel and purchased power costs that were more than 2% lower than the approved level. However, primarily because of the high cost of naturalNatural gas resulting from the impact hurricanes had on natural gas supply in combination with the need to run the natural gas fired peaker units more in the third quarter, at September 30, 2005, WPSC projects that actual fuel and purchased power costs for 2005 could be significantly higher than what was allowed in the 2005 rate case.

Electric utility earnings decreased $4.1 million (12.8%) for the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004, largely driven by the higher fuel and purchased power costs discussed above. Earnings were also negatively impacted because certain costs incurred in the third quarter of 2005 related to plant outages, carrying costs on capital additions, and other costs (which are recovered in rates relatively evenly throughout the year) were partially recovered in revenue during the first six months of the year, leading to higher earnings in those periods.

~~-41-~~

~~Gas Utility Segment Operations~~

WPS Resources' Three Months Ended September 30,
Gas Utility Segment Results (Millions)

2005
2004 Change

Revenue
$
71.8
$ 45.6 57.5 %
Purchased natural gas costs
52.6
28.8 82.6 %
Margin
$
19.2
$ 16.8 14.3 %

Throughput in therms
128.6
104.1 23.5 %

~~Gas utility revenue increased $26.2 million (57.5%) for the quarter ended September 30, 2005, compared to the quarter ended September 30, 2004. Gas~~ utility revenue increased primarily as a result of an increase in the per-unit ~~cost~~price of natural gas ~~higher natural gas throughput volumes,~~ and a rate increase. Natural gas costs ~~increased 15.6%~~were 36.9% higher (on a per-unit basis) ~~for~~during the quarter ended ~~September 30, 2005,~~March 31, 2006, compared to the same quarter ~~ended September 30, 2004.~~in 2005. Following regulatory practice, WPSC passes changes in the total cost of natural gas on to customers through a purchased gas adjustment clause, as allowed by the PSCW and the MPSC. ~~Natural gas throughput volumes increased 23.5%, primarily related to an increase in interdepartmental sales from~~In December 2005, the ~~natural gas utility to the electric utility as a result of increased electric generation from natural gas fired combustion turbines. The~~ PSCW issued a final order authorizing aan annual natural gas rate increase of ~~$5.6~~$7.2 million (1.1%), effective January 1, ~~2005.~~2006. The rate increase was required as a result of infrastructure improvements necessary to ensure the reliability of the natural gas distribution system. The increase in natural gas utility revenue was partially offset by a 13.5% decrease in natural gas throughput volumes, primarily ~~driven by higher benefit costs and~~related to weather that was 11% warmer during the ~~cost~~heating season in the first quarter of ~~distribution system improvements.~~2006. Customers are also taking measures to conserve energy as a result of the high natural gas prices.

-46-

Commission File Number	Registrants; State of Incorporation; Address; and Telephone Number	IRS Employer Identification No.

1-11337	WPS RESOURCES CORPORATION (A Wisconsin Corporation) 700 North Adams Street P. O. Box 19001 Green Bay, WI 54307-9001 920-433-4901	39-1775292

1-3016	WISCONSIN PUBLIC SERVICE CORPORATION (A Wisconsin Corporation) 700 North Adams Street P. O. Box 19001 Green Bay, WI 54307-9001 800-450-7260	39-0715160

WPS Resources Corporation	Yes [x] No [ ]
Wisconsin Public Service Corporation	Yes [x] No [ ]

WPS Resources Corporation
~~Yes [x] No~~ Large Accelerated filer [X]	Accelerated filer [ ]	Non-accelerated filer [ ]
Wisconsin Public Service Corporation
~~Yes~~ Large Accelerated filer [ ] ~~No [x~~	Accelerated filer [ ]	Non-accelerated filer [X]

WPS Resources Corporation	Yes [ ] No [x ]
Wisconsin Public Service Corporation	Yes [ ] No [x ]

WPS RESOURCES CORPORATION	Common stock, $1 par value, ~~38,094,761~~40,306,482 shares outstanding at ~~October 31, 2005~~April 30, 2006

WISCONSIN PUBLIC SERVICE CORPORATION	Common stock, $4 par value, 23,896,962 shares outstanding at ~~October 31, 2005~~April 30, 2006

WPS RESOURCES CORPORATION AND WISCONSIN PUBLIC SERVICE CORPORATION FORM 10-Q FOR THE QUARTER ENDED ~~SEPTEMBER 30, 2005~~MARCH 31, 2006 CONTENTS
		Page

	FORWARD-LOOKING STATEMENTS	4

PART I.	FINANCIAL INFORMATION

Item 1.	FINANCIAL STATEMENTS
	WPS RESOURCES CORPORATION
	Condensed Consolidated Statements of Income	5
	Condensed Consolidated Balance Sheets	6
	Condensed Consolidated Statements of Cash Flows	7

	WISCONSIN PUBLIC SERVICE CORPORATION
	Condensed Consolidated Statements of Income	8
	Condensed Consolidated Balance Sheets	9
	Condensed Consolidated Statements of Capitalization	10
	Condensed Consolidated Statements of Cash Flows	11

	CONDENSED NOTES TO FINANCIAL STATEMENTS OF	12-39
	WPS Resources Corporation and Subsidiaries Wisconsin Public Service Corporation and Subsidiaries	~~12-35~~

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations for
	WPS Resources Corporation	~~36-70~~40-64
	Wisconsin Public Service Corporation	~~71-80~~65-70

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	8171

Item 4.	Controls and Procedures	8272

PART II.	OTHER INFORMATION	8373

Item 1.	Legal Proceedings	8373

Item 5.1A.	~~Other Information~~Risk Factors	8373

Item 6.	Exhibits	8474

Signatures		~~85-86~~75-76

	CONTENTS (continue)	Page

EXHIBIT INDEX		8777

12.1	WPS Resources Corporation Ratio of Earnings to Fixed Charges

12.2	Wisconsin Public Service Corporation Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed Charges and Preferred Dividends

31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for WPS Resources Corporation

31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for WPS Resources Corporation

31.3	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for Wisconsin Public Service Corporation

31.4	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934 for Wisconsin Public Service Corporation

32.1	Written Statement of the Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350 for WPS Resources Corporation

32.2	Written Statement of the Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350 for Wisconsin Public Service Corporation

Commonly Used Acronyms

ATC	American Transmission Company LLC
DOE	United States Department of Energy
DPC	Dairyland Power Cooperative
EPA	United States Environmental Protection Agency
ESI	WPS Energy Services, Inc.
ESOP	Employee Stock Ownership Plan
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
MISO	Midwest Independent Transmission System Operator
MPSC	Michigan Public Service Commission
PDI	WPS Power Development, LLC
PSCW	Public Service Commission of Wisconsin
SEC	Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
UPPCO	Upper Peninsula Power Company
WDNR	Wisconsin Department of Natural Resources
WPSC	Wisconsin Public Service Corporation


PART 1. FINANCIAL INFORMATION	PART 1. FINANCIAL INFORMATION													PART 1. FINANCIAL INFORMATION

Item 1. Financial Statements

WPS RESOURCES CORPORATION	WPS RESOURCES CORPORATION													WPS RESOURCES CORPORATION


CONDENSED CONSOLIDATED STATEMENTS OF INCOME		Three Months Ended						Nine Months Ended
(Unaudited)		September 30						September 30
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)															Three Months Ended
															March 31
(Millions, except per share amounts)		2005			2004			2005			2004				2006			2005

Nonregulated revenue		$	1,396.0		$	812.8		$	3,478.1		$	2,596.8			$	1,598.9		$	1,076.0
Utility revenue			361.3			279.1			1,093.6			941.6				439.1			410.9
Total revenues			1,757.3			1,091.9			4,571.7			3,538.4				2,038.0			1,486.9

Nonregulated cost of fuel, gas, and purchased power			1,335.2			784.5			3,324.2			2,499.9
Utility cost of fuel, gas, and purchased power			190.5			97.3			526.8			404.9
Nonregulated cost of fuel, natural gas, and purchased power																1,502.6			1,017.9
Utility cost of fuel, natural gas, and purchased power																269.1			201.6
Operating and maintenance expense			124.0			123.9			399.4			394.1				131.2			133.3
Depreciation and decommissioning expense			23.8			26.1			119.6			78.4				24.1			29.2
Gain on sale of emission allowances			-			-			(86.8	)		-
Impairment loss			-			-			80.6			-
Taxes other than income			11.8			11.5			35.7			34.8				13.3			12.0
Operating income			72.0			48.6			172.2			126.3				97.7			92.9

Miscellaneous income			9.6			9.9			62.8			20.8				8.5			7.7
Interest expense			(15.6	)		(14.9	)		(56.2	)		(44.2	)			(18.2	)		(16.2	)
Minority interest			1.2			1.2			3.4			2.3				1.2			1.0
Other income (expense)			(4.8	)		(3.8	)		10.0			(21.1	)
Other expense																(8.5	)		(7.5	)

Income before taxes			67.2			44.8			182.2			105.2				89.2			85.4
Provision for income taxes			18.3			9.3			41.9			20.9				28.3			18.7
Net income before preferred stock dividends of subsidiary			48.9			35.5			140.3			84.3				60.9			66.7

Preferred stock dividends of subsidiary			0.7			0.7			2.3			2.3				0.8			0.8
Income available for common shareholders		$	48.2		$	34.8		$	138.0		$	82.0			$	60.1		$	65.9


Average shares of common stock
Basic			38.2			37.4			38.0			37.2				40.3			37.8
Diluted			38.6			37.6			38.3			37.5				40.6			38.1

Earnings per common share
Basic		$	1.26		$	0.93		$	3.63		$	2.20			$	1.49		$	1.74
Diluted		$	1.25		$	0.93		$	3.60		$	2.19			$	1.48		$	1.73

Dividends per common share declared		$	0.565		$	0.555		$	1.675		$	1.645			$	0.565		$	0.555

The accompanying condensed notes are an integral part of these statements.	The accompanying condensed notes are an integral part of these statements.

WISCONSIN PUBLIC SERVICE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	Nine Months Ended
	September 30
(Millions)	2005			2004

Operating Activities
Net income	$	86.9		$	77.2
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and decommissioning		107.0			66.7
Amortization		30.1			29.4
Deferred income taxes		(20.8	)		12.8
Investment tax credit restored		(1.0	)		(1.0	)
Allowance for funds used during construction		(1.7	)		(1.5	)
Realized gain on investments		(15.7	)		(3.3	)
Equity income		(8.4	)		(10.7	)
Pension and post retirement expense		29.0			22.0
Pension and post retirement funding		(8.2	)		-
Deferral of Kewaunee outage expenses		(57.8	)		-
Other		(21.6	)		(6.0	)
Changes in -
Customer and other receivables		(22.0	)		15.3
Accrued utility revenues		33.0			24.6
Fossil fuel inventory		(5.4	)		(0.8	)
Gas in storage		(17.8	)		(16.4	)
Miscellaneous assets		15.5			(3.7	)
Accounts payable		6.8			(2.2	)
Accrued taxes and interest		4.3			(0.3	)
Miscellaneous current and accrued liabilities		3.8			3.6
Net cash provided by operating activities		136.0			205.7

Investing Activities
Capital expenditures		(283.9	)		(185.4	)
Proceeds from the sale of Kewaunee power plant		112.5			-
Proceeds from the liquidation of non-qualified decommissioning trust		127.1			-
Other		(0.3	)		16.4
Net cash used for investing activities		(44.6	)		(169.0	)

Financing Activities
Short-term debt - net		(59.0	)		31.0
Payments of long-term debt		(0.3	)		(50.2	)
Net equity contributions from parent		30.0			40.0
Dividends to parent		(60.8	)		(56.3	)
Preferred stock dividends		(2.3	)		(2.3	)
Other		1.5			1.7
Net cash used for financing activities		(90.9	)		(36.1	)
Change in cash and cash equivalents		0.5			0.6
Cash and cash equivalents at beginning of period		3.5			4.7
Cash and cash equivalents at end of period	$	4.0		$	5.3


The accompanying condensed notes are an integral part of these statements.


(Millions)	Nine Months Ended September 30				Three Months Ended March 31
WPS Resources	2005		2004		2006		2005
Cash paid for interest	$	38.9	$	34.1	$	9.8	$	8.7
Cash paid for income taxes		47.4		26.7	$	5.5	$	0.5

WPSC
Cash paid for interest	$	21.1	$	19.9	$	6.6	$	6.2
Cash paid for income taxes		39.5		25.3
Cash paid (received) for income taxes					$	1.4	$	(3.0	)

	Assets				Liabilities
(Millions)	March 31, 2006		December 31, 2005		March 31, 2006		December 31, 2005
Utility Segments
Commodity contracts	$	9.6	$	22.0	$	3.7	$	-
Financial transmission rights		4.2		14.5		0.4		1.8
Nonregulated Segments
Commodity and foreign currency contracts		864.4		1,058.6		747.4		971.7
Fair value hedges - commodity contracts		7.6		4.2		1.9		12.9
Cash flow hedges
Commodity contracts		53.0		33.6		35.6		50.1
Interest rate swaps		4.4		-		3.4		4.7
Total	$	943.2	$	1,132.9	$	792.4	$	1,041.2
Balance Sheet Presentation
Current	$	728.0	$	906.4	$	622.9	$	852.8
Long-term		215.2		226.5		169.5		188.4
Total	$	943.2	$	1,132.9	$	792.4	$	1,041.2


	September 30,		December 31,
(Millions)	2005		2004
Property, plant, and equipment, net	$	0.8	$	0.8
Other assets:
Emission allowances		-		23.3
Assets held for sale	$	0.8	$	24.1


(Millions)	July 5, 2005

Qualified decommissioning trust fund	$	243.6
Other utility plant, net		165.4
Other current assets		5.5
Total assets	$	414.5

Regulatory liabilities	$	(72.1	)
Accounts payable		2.5
Asset retirement obligations		376.4
Total liabilities	$	306.8


*(Millions)*	September 30, 2005
Asset Class	Average Life (Years)		Gross Carrying Amount		Accumulated Amortization			Net
Emission allowances		1 to 30	$	16.7	$	(13.0	)	$	3.7
Customer related		1 to 8		10.5		(5.2	)		5.3
Other		1 to 30		4.2		(1.6	)		2.6
Total			$	31.4	$	(19.8	)	$	11.6


(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

(Millions)			September 30, 2005	December 31, 2004

First mortgage bonds – WPSC
	Series	Year Due
	6.90%	2013	$ 22.0	$ 22.0
	7.125%	2023	0.1	0.1

Senior notes – WPSC
	Series	Year Due
	6.125%	2011	150.0	150.0
	4.875%	2012	150.0	150.0
	4.80%	2013	125.0	125.0
	6.08%	2028	50.0	50.0

First mortgage bonds – UPPCO
	Series	Year Due
	9.32%	2021	15.3	15.3

Unsecured senior notes – WPS Resources
	Series	Year Due
	7.00%	2009	150.0	150.0
	5.375%	2012	100.0	100.0

Unsecured term loan due 2010 – WPS Resources			65.6	-
Term loans – non-recourse, collateralized by nonregulated assets			17.7	82.3
Tax exempt bonds			27.0	27.0
Senior secured note			2.5	2.7
Total			875.2	874.4
Unamortized discount and premium on bonds and debt			(1.9)	(2.0)
Total long-term debt			873.3	872.4
Less current portion			(3.7)	(6.7)
Total long-term debt			$869.6	$865.7


Forward Contracted Volumes at September 30, 2004 ⁽¹⁾	October 1, 2004 through September 30, 2005		October 1, 2005 through September 30, 2007

Wholesale sales volumes - billion cubic feet		91.3		13.6
Retail sales volumes - billion cubic feet		162.9		48.9
Total natural gas sales volumes		254.2		62.5

Wholesale sales volumes - million kilowatt-hours		5,523		1,032
Retail sales volumes - million kilowatt-hours		3,730		1,832
Total electric sales volumes		9,253		2,864

	Three Months Ended March 31,
(Millions except natural gas sales volumes)	2006		2005		Change

Nonregulated revenues	$	1,600.1	$	1,077.1		48.6	%
Nonregulated cost of fuel, natural gas, and purchased power		1,509.4		1,020.5		47.9	%
Margins	$	90.7	$	56.6		60.2	%
Margin Detail
Electric and other margins	$	52.4	$	36.4		44.0	%
Natural gas margins	$	38.3	$	20.2		89.6	%

Gross volumes (includes volumes both physically delivered and net settled)
Wholesale electric sales volumes in kilowatt-hours		14,308.7		8,570.3		67.0	%
Retail electric sales volumes in kilowatt-hours		1,209.4		2,047.0		(40.9	%)
Wholesale natural gas sales volumes in billion cubic feet		79.8		61.2		30.4	%
Retail natural gas sales volumes in billion cubic feet		100.4		90.5		10.9	%

Physical volumes (includes only transactions settled physically for the periods shown)
Wholesale electric sales volumes in kilowatt-hours		781.3		990.3		(21.1	%)
Retail electric sales volumes in kilowatt-hours		1,001.9		1,754.5		(42.9	%)
Wholesale natural gas sales volumes in billion cubic feet		74.2		57.9		28.2	%
Retail natural gas sales volumes in billion cubic feet		96.1		77.9		23.4	%


ESI's Natural Gas Results	Three Months Ended September 30,
(Millions, except sales volumes)	2005		2004			Change

Nonregulated natural gas revenue	$	1,153.4	$	645.2			78.8	%
Nonregulated natural gas cost of sales		1,133.1		647.0			75.1	%
Margin	$	20.3	$	(1.8	)		-

Wholesale sales in billion cubic feet ⁽¹⁾		78.4		47.3			65.8	%
Retail sales in billion cubic feet ⁽¹⁾		59.2		77.7			(23.8	%)


ESI's Electric Results	Three Months Ended September 30,
(Millions)	2005		2004		Change

Nonregulated electric revenue	$	186.9	$	133.9		39.6	%
Nonregulated electric cost of sales		175.5		115.6		51.8	%
Margin	$	11.4	$	18.3		(37.7	%)

Wholesale sales volumes in kilowatt-hours ⁽¹⁾		334.2		579.2		(42.3	%)
Retail sales volumes in kilowatt-hours ⁽¹⁾		1,746.5		2,027.2		(13.8	%)

(Millions)	Increase (Decrease) in Margin for the Quarter Ended March 31, 2006 Compared to Quarter Ended March 31, 2005

Electric and other margins
Realized and unrealized gains on structured origination contracts	$	5.3
ESI generation		(2.3	)
Retail electric operations (primarily Michigan and Ohio)		(10.2	)
Other wholesale electric operations		15.8

Other significant items:
Oil option activity, net		7.6
Unrealized gains on non-qualifying hedges		2.0
Increased costs related to the liquidation of an electric supply contract in 2005		(2.2	)

Net increase in electric and other margins	$	16.0

Natural gas margins
Realized natural gas margins (primarily wholesale as well as Canada and Michigan retail)	$	5.7

Other significant items:
Spot to forward differential		3.1
Unrealized loss on Ohio mass market options		(3.2	)
Other mark-to-market activity		12.5

Net increase in natural gas margins	$	18.1

Total increase in ESI's margin	$	34.1

·	Realized and unrealized gains on structured origination contracts - ESI's electric and other margin increased $5.3 million in the first quarter of 2006, compared to the same quarter in 2005, due to realized and unrealized gains from origination contracts involving the sale of energy through structured transactions to wholesale customers (primarily several municipalities in the northeastern United States). These origination contracts were not in place in the first quarter of 2005. ESI continues to expand its wholesale origination capabilities with a focus on physical, customer-based purchase and sale agreements in areas where it has market expertise.
·	ESI generation - The margin from ESI's electric generation facilities decreased $2.3 million (11.4%), from $20.2 million for the quarter ended March 31, 2005, to $17.9 million for the quarter ended March 31, 2006. The decrease was driven by a $2.9 million (22.5%) decrease in margin at ESI's Sunbury generation facility. While sales volumes at Sunbury did not change significantly from the first quarter of the prior year, the cost of fuel and emission allowances was significantly higher than in the prior year, a trend that is expected to continue for the remainder of the year. The decrease in margin at Sunbury was partially offset by an increase in margin at ESI's Canada and New England hydroelectric generation facilities, which was driven by increased sales volumes related to higher water flows.
·	Retail electric operations (primarily Michigan and Ohio) - The margin from retail electric operations decreased $10.2 million. The margin from retail electric operations in Michigan decreased $5.9 million and the margin from retail electric operations in Ohio decreased $1.8 million. ESI has

	experienced significant customer attrition in Michigan as a result of tariff changes granted to Michigan utilities and high wholesale energy prices (See "Other Future Considerations" for more information on ESI's retail electric operations in Michigan). ESI's retail electric aggregation sales in Ohio ended on December 31, 2005, with the expiration of ESI's contracts with Ohio aggregation customers. ESI remains prepared to offer future retail electric service in Ohio and increase future retail electric service in Michigan as the regulatory climate and market conditions allow.
·	Other wholesale electric operations - A $15.8 million increase in margin from other wholesale electric operations was driven by an increase in net realized and unrealized gains related to trading activities utilized to optimize the value of ESI's merchant generation fleet and customer supply portfolios. As part of its trading activities, ESI seeks to generate profits from the volatility of the price of electricity, by purchasing or selling contracts in established wholesale markets (primarily in the northeastern portion of the United States where ESI has market expertise) under risk management policies set by management and approved by WPS Resources' Board of Directors. ESI also seeks to maximize the value of its generation and customer supply portfolios to reduce market price risk and extract additional value from these assets through the use of various financial and physical instruments (such as forward contracts and options). Period-by-period variability in the margin contributed by ESI's optimization strategies and trading activities is expected due to constantly changing market conditions. ESI continues to produce strong results from its optimization and trading activities and believes it maintains a relatively low risk profile. A diverse mix of products and markets, combined with disciplined execution and exit strategies have allowed ESI to consistently generate economic value and earnings while staying within WPS Resources' Board of Directors' authorized value-at-risk (VaR) limits. For more information on VaR, see "Item 3, Quantitative and Qualitative Disclosures about Market Risk."
·	Oil option activity, net - An increase in mark-to-market and realized gains on derivative instruments utilized to protect the value of a portion of ESI's Section 29/45K federal tax credits in 2006 and 2007 contributed $7.6 million to the increase in its electric and other margin. The derivative instruments have not been designated as hedging instruments and, as a result, changes in the fair value are recorded currently in earnings. The benefit from Section 29/45K federal tax credits during a period is primarily based upon estimated annual synthetic fuel production levels, annual earnings projections, and any impact projected annual oil prices may have on the realization of the Section 29/45K federal tax credits. This results in mark-to-market gains or losses being recognized in different periods, compared to any tax credit phase-outs that may be recognized. For more information on Section 29/45K federal tax credits, see Note 10 to the Condensed Notes to Financial Statements, "Commitments and Contingencies."
·	Unrealized gains on non-qualifying hedges - ESI mitigates market price risk fluctuations associated with its merchant generation fleet using derivative instruments; including basis swaps, futures, forwards, and options, in addition to other instruments. Derivative instruments used to mitigate the market price risk associated with ESI's Niagara generation facility do not qualify for hedge accounting under generally accepted accounting principles. As a result, these derivative instruments were required to be marked-to-market, resulting in the recognition of a $2.0 million unrealized gain in the first quarter of 2006. For the remainder of 2006, the derivative instruments will continue to be marked-to-market, without a corresponding offset related to the power expected to be generated from Niagara. Generation plants are not considered derivative instruments, therefore, no gain or loss is recognized on power that can be produced from ESI's Niagara generation facility until it is sold into the market.
·	Increased costs related to the liquidation of an electric supply contract in 2005 - In the fourth quarter of 2005, an electricity supplier exiting the wholesale market in Maine requested that ESI liquidate a firm contract to buy power in 2006 and 2007. At that time, ESI recognized an $8.2 million gain related to the liquidation of the contract and entered into a new contract with another supplier for firm power in 2006 and 2007 to supply its customers in Maine. The cost to purchase power under the new contract was more than the cost under the liquidated contract. As a result of the termination of this contract, purchased power costs to serve customers in Maine will be $6.4 million higher for the year ended December 31, 2006, and slightly higher than the original contracted amount in 2007. The liquidation of this contract had a $2.2 million negative impact on the electric and other margin in the first quarter of 2006, resulting from higher purchased power costs recorded under the new contracts.


PDI's Operating Results	Three Months Ended September 30,
(Millions)	2005		2004		Change

Nonregulated other revenues	$	77.8	$	38.9		100.0	%
Nonregulated other cost of sales		46.2		26.9		71.7	%
Margins	$	31.6	$	12.0		163.3	%

·	Realized natural gas margins (primarily wholesale as well as Canada and Michigan retail) - Realized natural gas margins increased $5.7 million in the first quarter of 2006, compared to the same period in the prior year. The majority of this increase was due to an increase in structured wholesale natural gas transactions related to an increase in the volatility of the price of natural gas and high natural gas storage spreads during the first quarter of 2006. The remaining increase in the realized natural gas margin was driven by retail natural gas operations in Canada and Michigan due to customer growth.
·	Spot to forward differential- The natural gas storage cycle contributed $3.1 million to ESI's margin. For the three months ended March 31, 2006, the natural gas storage cycle had a $0.9 million positive impact on ESI's natural gas margin, compared to a $2.2 million negative impact on margin for the same period of 2005. At March 31, 2006, there was a $4.9 million difference between the market value of natural gas in storage and the market value of future sales contracts (net unrealized loss), related to the 2006/2007 natural gas storage cycle. This $4.9 million difference between the market value of natural gas in storage and the market value of future sales contracts (net unrealized loss) related to the 2006/2007 storage cycle is expected to vary with market conditions, but will reverse entirely and have a positive impact on earnings when all of the natural gas is withdrawn from storage.
·	Unrealized loss on Ohio mass market options- A $3.2 million mark-to-market loss on options utilized to manage supply costs for Ohio mass market customers, which were purchased in the latter half of 2005 and expire in varying months through September 2006, had a negative impact on ESI's natural gas margin in the first quarter of 2006. These contracts are utilized to reduce the risk of price movements and changes in consumer consumption patterns. Earnings volatility results from the application of derivative accounting rules to the options (requiring that these derivative instruments be marked-to-market), without a corresponding mark-to-market offset related to the customer contracts. Full requirements natural gas contracts with ESI's customers are not considered derivatives and, therefore, no gain or loss is recognized on these contracts until settlement.
·	Other mark-to-market activity - Mark-to-market gains on derivatives not previously discussed totaling $8.9 million were recognized in the first quarter of 2006, compared to the recognition of $3.6 million of mark-to-market losses on other derivative instruments in the first quarter of 2005. A significant portion of the difference relates to changes in the fair market value of basis swaps utilized to mitigate market price risk associated with natural gas transportation contracts and certain natural gas sales contracts. Earnings volatility results from the application of derivative accounting rules to the basis swaps (requiring that these derivative instruments be marked-to-market), without a corresponding mark-to-market offset related to the physical natural gas transportation contracts or the natural gas sales contracts (as these contracts are not considered derivative instruments). Therefore, no gain or loss is recognized on the transportation contracts or customer sales contracts until settlement.


	Three Months Ended September 30,							Three Months Ended March 31,
WPS Resources' Operating Expenses (Millions)	2005		2004		Change			2006		2005		Change

Operating and maintenance expense	$	124.0	$	123.9		-	%	$	131.2	$	133.3		(1.6	%)
Depreciation and decommissioning expense		23.8		26.1		(8.8	%)		24.1		29.2		(17.5	%)
Taxes other than income		11.8		11.5		2.6	%		13.3		12.0		10.8	%

·	WPSC refunded $13.8 million of the proceeds received from the liquidation of the Kewaunee nonqualified decommissioning fund to ratepayers in the first quarter of 2006. This reduction in revenue was offset by a related decrease in operating expenses, due to the partial amortization of the regulatory liability recorded for the refund of this fund.
·	Operating and maintenance expenses related to the Kewaunee nuclear plant decreased approximately $12 million due to the sale of this facility in July 2005. The decrease in operating and maintenance expenses related to Kewaunee did not have a significant impact on net income as WPSC is still purchasing power from this facility in the same amount as its original ownership interest. The cost of the power is included as a component of utility cost of purchased power.
·	Write-offs of uncollectible customer accounts increased $2.1 million in the first quarter of 2006, compared to the same period in 2005, due primarily to higher energy costs.
·	Excluding Kewaunee, maintenance expenses at WPSC increased $1.9 million in the first quarter of 2006, compared to the first quarter of 2005. Planned maintenance was required on certain combustion turbines in the first quarter of 2006, and maintenance expenses related to electric distribution assets also increased.
·	In the first quarter of 2006, WPSC began amortizing costs that were deferred related to the 2005 Kewaunee outage. In the first quarter of 2006, $0.4 million of costs were amortized, compared to the deferral of $1.1 million of costs related to the outage in the first quarter of 2005, resulting in a $1.5 million increase in operating and maintenance expense.
·	Customer account expenses increased $1.2 million, driven by an increase in consulting fees related to the implementation of a new software system.
·	Transmission-related expenses increased $1.0 million.


	Three Months Ended September 30,									Three Months Ended March 31,
WPS Resources' Other Income (Expense) (Millions)	2005			2004			Change			2006			2005			Change

Miscellaneous income	$	9.6		$	9.9			(3.0	%)	$	8.5		$	7.7			10.4	%
Interest expense		(15.6	)		(14.9	)		4.7	%		(18.2	)		(16.2	)		12.3	%
Minority interest		1.2			1.2			-	%		1.2			1.0			20.0	%
Other income (expense)	$	(4.8	)	$	(3.8	)		26.3	%
Other expense										$	(8.5	)	$	(7.5	)		13.3	%


WPS Resources' Electric Utility	Nine Months Ended September 30,
Segment Results (Millions)	2005		2004		Change

Revenue	$	782.9	$	672.7		16.4	%
Fuel and purchased power costs		309.9		216.9		42.9	%
Margin	$	473.0	$	455.8		3.8	%

Sales in kilowatt-hours		11,691.1		10,792.0		8.3	%


Credit Ratings	Standard & Poor's	Moody's
WPS Resources Senior unsecured debt Commercial paper Credit facility	A A-1 -	A1 P-1 A1
WPSC Senior secured debt Preferred stock Commercial paper Credit facility	A+ A- A-1 -	Aa2 A2 P-1 Aa3


			Payments Due By Period										Payments Due By Period
Contractual Obligations As of September 30, 2005 (Millions)	Total Amounts Committed		Less Than 1 Year		1 to 3 Years		3 to 5 Years		Over 5 Years
Contractual Obligations As of March 31, 2006 (Millions)											Total Amounts Committed		Less Than 1 Year		1 to 3 Years		3 to 5 Years		Over 5 Years

Long-term debt principal and interest payments	$	1,276.2	$	28.1	$	111.0	$	262.0	$	875.1	$	1,248.2	$	55.4	$	111.7	$	312.4	$	768.7
Operating leases		23.9		1.4		7.5		5.8		9.2		21.4		3.4		7.2		4.8		6.0
Commodity purchase obligations		6,188.3		1,601.8		3,091.7		577.7		917.1		6,928.9		3,220.2		2,264.3		722.3		722.1
Purchase orders		485.7		270.4		184.4		30.9		-		543.1		421.8		120.5		0.8		-
Capital contributions to equity method investment		168.7		27.6		134.1		7.0		-		62.9		23.8		39.1		-		-
Other		419.0		30.6		89.6		49.7		249.1		383.8		45.0		72.4		38.9		227.5
Total contractual cash obligations	$	8,561.8	$	1,959.9	$	3,618.3	$	933.1	$	2,050.5	$	9,188.3	$	3,769.6	$	2,615.2	$	1,079.2	$	1,724.3


WPS Resources' Outstanding Guarantees (Millions)	September 30, 2005		December 31, 2004
Guarantees of subsidiary debt	$	27.2	$	27.2
Guarantees supporting commodity transactions of subsidiaries		1,073.9		863.9
Standby letters of credit		76.0		80.9
Surety bonds		0.7		0.6
Other guarantee		4.9		5.3
Total guarantees	$	1,182.7	$	977.9


WPS Resources' Outstanding Guarantees (Millions) Commitments Expiring	Total Amounts Committed At September 30, 2005		Less Than 1 Year		1 to 3 Years		4 to 5 Years		Over 5 Years
Guarantees of subsidiary debt	$	27.2	$	-	$	-	$	-	$	27.2
Guarantees supporting commodity transactions of subsidiaries		1,073.9		896.5		118.2		15.2		44.0
Standby letters of credit		76.0		60.4		15.6		-		-
Surety bonds		0.7		0.7		.		-		-
Other guarantee		4.9		-		-		4.9		-
Total guarantees	$	1,182.7	$	957.6	$	133.8	$	20.1	$	71.2


ESI Mark-to-Market Roll Forward (Millions)	Natural Gas			Electric			Total

Fair value of contracts at December 31, 2004	$	31.6		$	13.7		$	45.3
Less - contracts realized or settled during period		9.5			(4.8	)		4.7
Plus - changes in fair value of contracts in existence at September 30, 2005		(73.3	)		(6.4	)		(79.7	)
Fair value of contracts at September 30, 2005	$	(51.2	)	$	12.1		$	(39.1	)

ESI Mark-to-Market Roll Forward (Millions)	Oil Options		Natural Gas			Electric		Total

Fair value of contracts at December 31, 2005	$	23.6	$	8.2		$	29.8	$	61.6
Less - contracts realized or settled during period		1.1		(11.4	)		3.3		(7.0	)
Plus - changes in fair value of contracts in existence at March 31, 2006		8.7		33.0			29.7		71.4
Fair value of contracts at March 31, 2006	$	31.2	$	52.6		$	56.2	$	140.0