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We are offering to exchange first mortgage bonds registered under the Securities Act of 1933, as amended, for a like principal amount of original first mortgage bonds that we issued in a private placement that closed on October 2, 2003.

The terms of the exchange first mortgage bonds are substantially identical to the terms of the original first mortgage bonds, except that the exchange first mortgage bonds will not contain transfer restrictions and will not have the registration rights that apply to the original first mortgage bonds or entitle their holders to additional interest in the event we fail to comply with these registration rights. The terms and conditions of the exchange offer are more fully described in this prospectus.

U.S. Bank National Association is serving as the exchange agent. If you wish to tender your original first mortgage bonds, you must complete, execute and deliver, among other things, a letter of transmittal to the exchange agent no later than 5:00 p.m., New York City time, on the expiration date.

You may withdraw tenders of original first mortgage bonds at any time prior to the expiration of the exchange offer. We will exchange all original first mortgage bonds that are validly tendered and not withdrawn prior to the expiration of the exchange offer.

Any outstanding original first mortgage bonds not validly tendered will remain subject to existing transfer restrictions.

There is no existing market for the exchange first mortgage bonds offered by this prospectus and we do not intend to apply for their listing on any securities exchange or any automated quotation system.

We believe that the exchange of original first mortgage bonds for exchange first mortgage bonds will not be taxable for United States federal income tax purposes. See “Material United States Federal Income Tax Considerations.”

The exchange first mortgage bonds will have the same terms and covenants as the original first mortgage bonds, and will be subject to the same business and financial risks.

You should consider carefully the “Risk Factors” beginning on page 10 of this prospectus before tendering your original first mortgage bonds for exchange.

We are not asking you for a proxy and you are requested not to send us a proxy.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

You should rely only on the information provided in this prospectus. We have not authorized anyone else to provide you with different information. This prospectus does not constitute an offer of these securities in any state where the offer is not permitted. You should not assume that the information in this prospectus is accurate as of any date other than the date on the front of this prospectus.

This prospectus contains statements that are not historical fact and constitute “forward-looking statements.” When we use words like “anticipates,” “believes,” “estimates,” “expects,” “intends,” “may,” “objective,” “outlook,” “plans,” “possible,” “potential” “projected,” or “should” or similar expressions, or when we discuss our strategy or plans, we are making forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Our future results may differ materially from those expressed in these forward-looking statements. These statements are necessarily based upon various assumptions involving judgments with respect to the future and other risks, including, among others:


	•	general economic conditions, including their impact on capital expenditures;

	•	business conditions in the retail and wholesale energy industry;

	•	competitive factors, including the extent and timing of the entry of additional competition in the markets served by us;

	•	unusual weather;

	•	changes in federal or state legislation;


	•	regulation and regulatory initiatives that affect cost and investment recovery and have an impact on rate structures;

	•	rating agency action;

	•	our ability, and that of our affiliates, to access the capital markets and obtain credit on favorable terms;

	•	costs and other effects of legal and administrative proceedings, settlements, investigations and claims, including without limitation claims brought against our parent, Xcel Energy Inc.;

	•	effects of geopolitical events, including war and acts of terrorism;

	•	changes in accounting principles; and

	•	the other risk factors discussed under “Risk Factors.”

You are cautioned not to rely unduly on any forward-looking statements. These risks and uncertainties are discussed in more detail under “Risk Factors,” “Business” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the notes to the audited consolidated financial statements and interim consolidated financial statements included in this prospectus.

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors should not be construed as exhaustive.

SUMMARY

This summary highlights some of the information contained elsewhere in this prospectus. Because this is only a summary, it does not contain all of the information that may be important to you. For a more complete understanding of this exchange offer, we encourage you to read this entire prospectus and the documents to which we refer you in deciding whether to exchange your original first mortgage bonds for exchange first mortgage bonds. The term “original first mortgage bonds” as used in this prospectus refers to our outstanding 5.25% first mortgage bonds, series A due October 1, 2018 that we issued on October 2, 2003 and that have not been registered under the Securities Act of 1933, as amended (the “Securities Act”). The term “exchange first mortgage bonds” refers to our 5.25% first mortgage bonds, series B due October 1, 2018 offered under this prospectus.

In this prospectus, except as otherwise indicated or as the context otherwise requires, “Northern States Power Company,” “NSP-W,” “we,” “our,” and “us” refer to Northern States Power Company, a Wisconsin corporation.

OUR COMPANY

General

We are an operating utility engaged in the generation, transmission and distribution of electricity to approximately 230,000 retail electric customers in northwestern Wisconsin and in the western portion of the Upper Peninsula of Michigan. We are also engaged in the distribution and sale of natural gas in the same service territory to approximately 90,000 customers.

We were incorporated in 1901 under the laws of Wisconsin as the La Crosse Gas and Electric Company. Prior to August 2000, we were a wholly-owned subsidiary of Northern States Power Company, a Minnesota corporation (“NSP”). On August 18, 2000, NSP and New Century Energies, Inc. (“NCE”) merged to form Xcel Energy Inc. (“Xcel Energy”), a Minnesota corporation and registered holding company under the Public Utility Holding Company Act of 1935 (“PUHCA”), and we became a wholly-owned subsidiary of Xcel Energy. We own three direct subsidiaries: Chippewa and Flambeau Improvement Co., which operates hydro reserves; Clearwater Investments Inc., which owns interests in affordable housing; and NSP Lands, Inc., which holds real estate.

Among Xcel Energy’s other subsidiaries are Northern States Power Company, a Minnesota corporation (“NSP-MN”), Southwestern Public Service Company, a New Mexico corporation (“SPS”), Cheyenne Light, Power and Fuel Company, a Wyoming corporation (“Cheyenne”) and Public Service Company of Colorado (“PSCo”), a Colorado corporation. Prior to December 5, 2003, Xcel Energy owned all of the common stock of NRG Energy, Inc., a Delaware corporation (“NRG”). NRG is a global energy company, primarily engaged in the ownership and operation of power generation facilities and the sale of energy, capacity and related products. On May 14, 2003, NRG filed a voluntary petition for bankruptcy under Chapter 11 of the U.S. Bankruptcy Code. On December 5, 2003, NRG emerged from bankruptcy and Xcel Energy divested its ownership interest in NRG. On January 13, 2004, Xcel Energy announced an agreement with Black Hills Corp. for the sale of Cheyenne, pending regulatory approvals.

Our principal executive offices are located at 1414 W. Hamilton Ave., Eau Claire, Wisconsin 54701, and our telephone number at that location is (715) 839-2625.

Regulatory Overview

As a subsidiary of a registered holding company under PUHCA, we are subject to the regulatory oversight of the SEC under PUHCA. As a result, we are subject to extensive regulation by the SEC with respect to issuances and sales of securities, acquisitions and sales of certain utility properties and intra-system sales of certain goods and services. In addition, PUHCA generally limits our ability to acquire additional public utility systems and to acquire and retain businesses unrelated to utility operations.

Retail rates, services and other aspects of our operation are subject to the jurisdiction of the Public Service Commission of Wisconsin (“PSCW”) and the Michigan Public Service Commission (“MPSC”). In addition, each of the state commissions certifies the need for new generating plants and electric transmission lines of designated capacities to be located within the respective states before the facilities may be sited and built. The PSCW has a biennial base rate-filing requirement. In June of each odd-numbered year, we must submit a rate filing for the two-year period beginning the following January. The filing procedure and review generally allow the PSCW sufficient time to issue an order and implement new base rates effective with the start of the test year.

We are subject to the jurisdiction of The Federal Energy Regulatory Commission (the “FERC”) with respect to our wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce.

We are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies. We are responsible for compliance with all rules and regulations issued by the various agencies.

Recent Developments


	*NRG Bankruptcy*

Commencing on May 14, 2003, NRG and certain of NRG’s affiliates filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code to restructure their debt. Neither Xcel Energy nor any of its other subsidiaries, including us, were included in the filing. NRG’s plan of reorganization filed with the U.S. Bankruptcy Court for the Southern District of New York incorporated the terms of an overall settlement among Xcel Energy, NRG and NRG’s major creditor constituencies that provided for payments by Xcel Energy to NRG, and that NRG would pay in turn to its creditors, up to $752 million. NRG’s plan of reorganization was approved by its creditors and the bankruptcy court, and on December 5, 2003, NRG completed its reorganization and emerged from bankruptcy and Xcel Energy divested its ownership interest in NRG.


	*2003 General Rate Case*

In mid-December, 2003 the PSCW informed us that they expect to complete their audit of our June 2003 rate filing in mid-January 2004, and they expect to issue an order in the first quarter of 2004. Since our filing requested authorization to maintain rates at current levels, this delay is not expected to adversely impact us.

On December 22, 2003 the PSCW issued an interim order in the rate case approving our request for alternative accounting treatment of the loss on reacquired debt associated with the refinancing of our $110 million first mortgage bonds. In November, 2003 we had filed a proposal to amortize the loss on reacquired debt over the 15-year term of the new $150 million issue, as opposed to the “revenue neutral” method specified by the PSCW order approving the refinancing. (Under the revenue neutral method, we would have been required to amortize by equal monthly charges, from the date of refunding, the deferrals associated with the refunded bonds, over a period equivalent to that in which the net savings in monthly interest and amortization charges associated with the old debt equals the amortization.) Because the alternative method approved by the PSCW results in a longer amortization period, we will realize pretax savings of $394,000 in 2003 and $1,894,000 in 2004.


	*TRANSLink*

On November 21, 2003, the TRANSLink participants, including Xcel Energy, jointly announced that formation of the proposed TRANSLink Transmission Company LLC had been suspended. On November 24, 2003 we withdrew our request for associated regulatory approvals from the PSCW.


	*FERC Rules and Orders*

The FERC has issued several recent regulatory orders or rules that will impact our future operations and costs. First, in August 2003, the FERC issued final rules requiring the standardization of generation interconnection procedures and agreement for interconnection to the transmission systems of all FERC-jurisdictional electric utilities, including us, and establishing pricing rules for interconnections and related system upgrades. In October 2003, the FERC issued final rules asserting jurisdiction over “money pool” arrangements by public utilities, including such arrangements by registered holding company systems regulated by the SEC. We entered into a money pool agreement with Xcel Energy and the other Xcel Energy operating companies in November 2003, subject to receipt of required state regulatory approvals. In November 2003, the FERC issued an order requiring amendments to the market-based wholesale tariffs of all FERC-jurisdictional electric utilities, including NSP-MN, to impose new market behavior rules, and requiring submission of compliance tariff amendments in December 2003; violations of the new tariffs could result in the disgorgement of certain wholesale sales revenues or even the loss of authority to make sales at market based rates. Finally, in December 2003, the FERC issued final standards of conduct rules affecting all FERC-jurisdictional transmission utilities, which will require greater functional separation of our electric transmission functions from our wholesale energy markets function and from “energy affiliates” (as defined by the final rule). Full compliance is required by June 1, 2004. Management has not yet estimated the cost of compliance with the new standards of conduct rules, but the cost could be material.

In addition, the FERC has made certain rulings that will impact the net cost of our participation in the Midwest Independent Transmission System Operator, Inc. (“Midwest ISO” or “MISO”) regional transmission organization (“RTO”). Pursuant to a settlement agreement in the Xcel Energy merger, we and NSP-MN agreed to join the Midwest ISO RTO. The Midwest ISO began interim operations in February 2002. In early 2003, on remand from U.S. Court of Appeals, FERC upheld its prior 2001 orders (known as Opinion No. 453) requiring members of the Midwest ISO to pay the Midwest ISO administrative surcharge in the MISO open access transmission tariff (known as Schedule 10) for transmission uses to serve retail and wholesale native load customers. The annual cost to NSP-MN and us is approximately $9 million, with us bearing about 15 percent of the total. This decision has again been appealed. In addition, in November 2003, the FERC ruled that the Midwest ISO must remove the “regional through and out rate” (“RTOR”) surcharge from its transmission tariff. The RTOR charges were established in the Midwest ISO tariff to compensate member transmission owners (such as NSPW) for a portion of the wholesale transmission service revenues lost as a result of becoming subject to the Midwest ISO tariff. Elimination of the RTOR surcharge would reduce transmission service revenues to NSP-MN and us in the long-term, but are expected to be largely offset for the next two years by revenue from transitional rate schedules expected to be implemented in 2004.

Summary of the Exchange Offer

On October 2, 2003, we completed the private offering of $150 million in aggregate principal amount of our 5.25% first mortgage bonds, series A due October 1, 2018. These original first mortgage bonds were not registered under the Securities Act and, therefore, they are subject to significant restrictions on resale. Accordingly, when we sold these original first mortgage bonds, we entered into a registration rights agreement with the initial purchasers that requires us to deliver to you this prospectus and to permit you to exchange your original first mortgage bonds for exchange first mortgage bonds that have substantially identical terms to the original first mortgage bonds, except that the exchange first mortgage bonds will be freely transferable and will not have covenants regarding registration rights or additional interest. The exchange first mortgage bonds will be issued under the same indenture under which the original first mortgage bonds were issued and, as a holder of the exchange first mortgage bonds, you will be entitled to the same rights under the indenture that you had as a holder of original first mortgage bonds.

Set forth below is a summary description of the terms of the exchange offer.


Exchange Offer		We are offering to exchange up to $150 million in aggregate principal amount of exchange first mortgage bonds for a like aggregate principal amount of original first mortgage bonds. Original first mortgage bonds may be tendered only in increments of $1,000.

Expiration Date		The exchange offer will expire at 5:00 p.m., New York City time, on March 9, 2004, unless we extend it. We do not currently intend to extend the exchange offer.

Interest on the Exchange First Mortgage Bonds		Interest on the exchange first mortgage bonds will accrue at the rate of 5.25 percent per year from the date of the last periodic payment of interest on the original first mortgage bonds or, if no interest has been paid, from October 2, 2003.

Conditions to the Exchange Offer		The exchange offer is subject to customary conditions, including that:

		• there is no change in law, regulation or any applicable interpretation of the SEC staff that prevents us from proceeding with the exchange offer;

		• there is no action or proceeding, pending or threatened, that would impair our ability to proceed with the exchange offer;

		• no stop order has been issued by the SEC or any state securities authority suspending the effectiveness of the registration statement of which this prospectus is a part; and

		• all government approvals necessary for the consummation of the exchange offer have been obtained.

Procedure for Exchanging Original First Mortgage Bonds		If the original first mortgage bonds you wish to exchange are registered in your name:

		• you must complete, sign and date the letter of transmittal and mail or otherwise deliver it, together with any other required documentation, to U.S. Bank National Association, as exchange agent, at the address specified on the cover page of the letter of transmittal.


		If the original first mortgage bonds you wish to exchange are in book-entry form and registered in the name of a broker, dealer or other nominee:

		• you must contact the broker, dealer, commercial bank, trust company or other nominee in whose name your original first mortgage bonds are registered and instruct it to tender your original first mortgage bonds on your behalf. You must comply with the procedures of The Depository Trust Company (“DTC”) for tender and delivery of book-entry securities in order to validly tender your original first mortgage bonds for exchange.

		Questions regarding the exchange of original first mortgage bonds or the exchange offer generally should be directed to the exchange agent at the address specified under the caption “The Exchange Offer — Exchange Agent.”

Guaranteed Delivery Procedures		If you wish to exchange your original first mortgage bonds and you cannot deliver the required documents to the exchange agent by the expiration date or you cannot tender and deliver your original first mortgage bonds in accordance with DTC’s procedures by the expiration date, you may tender your original first mortgage bonds according to the guaranteed delivery procedures described under the caption “The Exchange Offer — Guaranteed Delivery Procedures.”

Withdrawal Rights		You may withdraw the tender of your original first mortgage bonds at any time before 5:00 p.m., New York City time, on the expiration date of the exchange offer.

Acceptance of Original First Mortgage Bonds and Delivery of Exchange First Mortgage Bonds		We will accept for exchange any and all original first mortgage bonds that are properly tendered in the exchange offer before 5:00 p.m., New York City time, on the expiration date, as long as all of the terms and conditions of the exchange offer are met. We will deliver the exchange first mortgage bonds promptly following the expiration date.

Resale of Exchange First Mortgage Bonds		Based on interpretations by the staff of the SEC, as detailed in a series of no-action letters issued by the SEC to third parties, we believe that you may offer for resale, resell or otherwise transfer the exchange first mortgage bonds without complying with the registration and prospectus delivery requirements of the Securities Act if:

		• you are acquiring the exchange first mortgage bonds in the ordinary course of your business and do not hold any original first mortgage bonds to be exchanged in the exchange offer that were acquired other than in the ordinary course of business;

		• you are not a broker-dealer tendering original first mortgage bonds acquired directly from us;

		• you are not participating, do not intend to participate and have no arrangements or understandings with any person to partici-


		pate in the exchange offer for the purpose of distributing the exchange first mortgage bonds; and

		• you are not our “affiliate” within the meaning of Rule 405 under the Securities Act.

		If any of these conditions is not satisfied and you transfer any exchange first mortgage bonds without delivering a proper prospectus or without qualifying for a registration exemption, you may incur liability under the Securities Act.

		Each broker or dealer that receives exchange first mortgage bonds for its own account in exchange for original first mortgage bonds that were acquired as a result of market-making or other trading activities must acknowledge that it will deliver a prospectus meeting the requirements of the Securities Act in connection with any resale of the exchange first mortgage bonds.

Consequences of Failure to Exchange		If you do not exchange your original first mortgage bonds for exchange first mortgage bonds, you will not be able to offer, sell or otherwise transfer the original first mortgage bonds except:

		• in compliance with the registration requirements of the Securities Act and any other applicable securities laws;

		• pursuant to an exemption from the securities laws; or

		• in a transaction not subject to the securities laws.

		Original first mortgage bonds that remain outstanding after completion of the exchange offer will continue to bear a legend reflecting these restrictions on transfer. In addition, upon completion of the exchange offer, you will not be entitled to any rights to have the resale of original first mortgage bonds registered under the Securities Act (subject to limited exceptions applicable only to certain qualified institutional buyers). We currently do not intend to register under the Securities Act the resale of any original first mortgage bonds that remain outstanding after completion of the exchange offer.

		Upon completion of the exchange offer, there may be no market for the original first mortgage bonds, and if you fail to exchange the original first mortgage bonds, you may have difficulty selling them.

United States Federal Income Tax Considerations		Your acceptance of the exchange offer and the exchange of your original first mortgage bonds for exchange first mortgage bonds will not be taxable for U.S. federal income tax purposes. See “Material United States Federal Income Tax Considerations” beginning on page 88.

Exchange Agent		U.S. Bank National Association is serving as exchange agent for the exchange offer.

Appraisal or Dissenter’s Rights		You will have no appraisal or dissenters’ rights in connection with the exchange offer.

Summary Description of the Exchange First Mortgage Bonds

The terms of the exchange first mortgage bonds we are issuing in the exchange offer and the original first mortgage bonds are identical in all material respects, except that:

• the exchange first mortgage bonds will have been registered under the Securities Act;

• the exchange first mortgage bonds will not contain transfer restrictions; and

• the exchange first mortgage bonds will not have the registration rights that apply to the original first mortgage bonds or entitle their holders to additional interest in the event we fail to comply with these registration rights.

A brief description of the material terms of the exchange first mortgage bonds is set forth below:


Securities Offered		$150,000,000 principal amount of 5.25% first mortgage bonds, series B due October 1, 2018.

Maturity		October 1, 2018.

Interest Rate		5.25 percent per annum.

Interest Payment Dates		April 1 and October 1 of each year, beginning on April 1, 2004.

Ranking		The exchange first mortgage bonds will be our senior secured obligations and will be secured equally and ratably with all of our other outstanding first mortgage bonds. As of December 31, 2003, $215 million of our first mortgage bonds were outstanding, which amount includes the original first mortgage bonds.

Collateral		The exchange first mortgage bonds are secured by a first mortgage lien on all of our real and fixed properties, leasehold rights, franchises and permits, subject to limited exceptions.

Ratings		The exchange first mortgage bonds have been assigned a rating of “BBB+” (CreditWatch positive) by Standard & Poor’s Ratings Services (“Standard & Poor’s”) and “A3” (under review for possible upgrade) by Moody’s Investors Services, Inc. (“Moody’s”). For a description of events affecting our credit ratings, see “Risk Factors.” Ratings from credit agencies are not recommendations to buy, sell or hold our securities and may be subject to revision or withdrawal at any time by the applicable rating agency and should be evaluated independently of any other ratings.

Optional Redemption		We may redeem the exchange first mortgage bonds at any time, in whole or in part, at a “make whole” redemption price equal to the greater of (1) the principal amount being redeemed or (2) the sum of the present values of the remaining scheduled payments of principal and interest on the exchange first mortgage bonds being redeemed, discounted to the date fixed for redemption on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Yield (as defined below under the caption “Description of the Exchange First Mortgage Bonds — Redemption Provisions”) plus 25 basis points, plus accrued interest to the redemption date.

Sinking Fund		None.

Summary Historical Financial Data

The following tables present our summary consolidated historical financial data. The data presented in these tables are from “Selected Consolidated Financial Data” included elsewhere in this prospectus. You should read that section for a further explanation of the consolidated financial data summarized here. You should also read the summary consolidated financial data presented below in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” our audited and unaudited consolidated financial statements and related notes and other financial information contained in this prospectus. The historical financial information may not be indicative of our future performance.



	Nine months ended
	September 30,				Year ended December 31,

	2003		2002		2002		2001		2000		1999		1998


	(Thousands of dollars, except ratios)
Consolidated Statement of Operations Data:
Operating revenue	$	447,909	$	416,693	$	561,641	$	574,640	$	535,170	$	494,421	$	477,342
Operating income	$	78,172	$	87,161	$	113,498	$	78,782	$	69,304	$	79,539	$	70,439
Interest charges and financing costs	$	17,085	$	17,336	$	23,117	$	22,069	$	19,255	$	18,530	$	18,679
Net income	$	36,980	$	42,865	$	54,373	$	36,392	$	30,296	$	36,366	$	32,195
Other Consolidated Financial Data
Ratio of earnings to fixed charges(1)		4.5		5.0		4.9		3.5		3.3		4.1		3.7


	September 30, 2003

	(Thousands of dollars)
Consolidated Balance Sheet Data:
Total assets	$	1,019,623
Short-term debt (including current maturities)	$	40,034
Long-term debt	$	273,173
Common stockholder’s equity	$	417,431
Total capitalization (including short-term debt)	$	730,638

(1) For purposes of computing the ratio of earnings to fixed charges, (1) earnings consist of net income plus fixed charges, federal and state income taxes, deferred income taxes and investment tax credits; and (2) fixed charges consist of interest on long-term debt, other interest charges, the interest component on leases and amortization of debt discount, premium and expense.

You should carefully consider the risks described below as well as other information contained in this prospectus before exchanging your original first mortgage bonds. The risks described in this section are those that we consider to be the most significant to your decision whether to invest in our exchange first mortgage bonds. If any of the events described below occurs, our business, financial condition or results of operations could be materially harmed. In addition, we may not be able to make payments on the exchange first mortgage bonds, and this could result in your losing all or part of your investment.

We are an operating electric and gas utility and a subsidiary of Xcel Energy. Xcel Energy has a number of other utility and non-utility subsidiaries.

Xcel Energy provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries of specified agreements or transactions. Xcel Energy’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy’s guarantees limit its exposure to a maximum amount that is stated in the guarantees. As of September 30, 2003, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $329 million of which $80 million related to Xcel Energy’s former subsidiary, NRG, and actual aggregate exposure of approximately $18 million, which amount will vary over time. Xcel Energy has provided indemnities to sureties in respect of bonds for the benefit of its subsidiaries. The total amount of bonds with these indemnities outstanding as of September 30, 2003 was approximately $33 million, of which $6 million related to NRG. As part of the consummation of NRG’s plan of reorganization, NRG provided Xcel Energy with cash collateral (which NRG may replace with letters of credit) that has the effect of eliminating Xcel Energy’s exposure under the guarantees and sureties related to NRG. If Xcel Energy were to become obligated to make payments under these guarantees and bond indemnities, it could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek, within certain regulatory limitations and the limitations provided by corporate law, additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy’s credit rating below investment grade, Xcel Energy may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy part or potentially all of these exposures. If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy’s debt securities below investment grade, it would increase Xcel Energy’s cost of capital and restrict its access to the capital markets. This would limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

We rely on Xcel Energy Services Inc. (“Xcel Services”), a subsidiary service company of Xcel Energy, for many administrative services. If Xcel Energy were to experience severe financial difficulties, it could temporarily disrupt the provision of these services or cause us to provide those services ourselves, at potentially greater cost.

PUHCA contains limitations on the ability of registered holding companies and certain of their subsidiaries to issue securities. Such registered holding companies and their subsidiaries may not issue securities unless authorized by an exemptive rule or order of the SEC. For utility subsidiaries like us, one of the exemptive rules permits utilities to issue securities to finance their business so long as the issuance has been approved by the appropriate state utility commission. In our case, this offering and our other borrowings have been authorized by the PSCW and are exempt under this rule. To the extent we wish to issue securities that are not exempt by rule under PUHCA, we will need to seek authorization from the SEC under PUHCA.

Because Xcel Energy does not qualify for any of the main exemptive rules, it sought and received financing authority from the SEC under PUHCA for various financing arrangements. Xcel Energy’s current financing authority permits it, subject to satisfaction of certain conditions, to issue through June 30, 2005 up to $2.5 billion of common stock and long-term debt and $1.5 billion of short-term debt at the holding company level. Xcel Energy has issued $2 billion of long-term debt and common stock.

One of the conditions of the financing order, which also includes authorization for intra-system loans for the Xcel Energy subsidiaries to the extent not otherwise exempt, is that Xcel Energy’s ratio of common equity to total capitalization, on a consolidated basis, be at least 30 percent.

During 2002 and 2003, Xcel Energy was required to record significant asset impairment losses from sales or divestitures of NRG assets and businesses; from NRG’s canceling or deferring the funding of certain projects under construction and from NRG’s deciding not to contribute additional funds to certain projects already operating. As a result, Xcel Energy’s common equity ratio fell below 30 percent. As of September 30, 2003 Xcel Energy’s common equity ratio was approximately 40 percent.

Another condition of the SEC financing order is that (a) if the security to be issued is rated, it is rated investment grade by at least one nationally recognized rating agency and (b) all Xcel Energy’s outstanding securities (except its preferred stock) that are rated must be rated investment grade by at least one nationally recognized rating agency. As of December 31, 2003, Xcel Energy’s senior unsecured debt was rated “BBB-” (CreditWatch positive) by Standard & Poor’s and “Baa3” (under review for possible upgrade) by Moody’s, which is investment grade.

If Xcel Energy’s common equity ratio falls below the 30 percent level or its securities are not rated investment grade, and Xcel Energy is unable to obtain additional relief from the SEC, Xcel Energy may not be able to issue securities (except that it could issue common stock even if the equity ratio is below 30 percent), which could limit its ability to contribute equity or make loans to us or may cause Xcel Energy to seek, within certain regulatory limitations and the limitations provided by corporate law, additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs. Alternative sources of funds could include the issuance of additional bonds or other debt securities. No assurance can be given that such alternatives will be available to us in required amounts or at reasonable costs.

Our senior secured debt has been assigned a rating of “BBB+” (CreditWatch positive) by Standard & Poor’s and of “A3” (under review for possible upgrade) by Moody’s.

The reductions in our credit ratings and those of Xcel Energy and the other operating utilities of Xcel Energy in 2002 occurred in the context of a severe deterioration in the credit ratings of NRG that began in 2001 and continued in 2002.

Any future downgrade of our securities will likely increase our cost of capital and reduce our access to the capital markets. This could adversely affect our financial condition and results of operations. We cannot assure you that any of our current ratings or those of our affiliates, including Xcel Energy, will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency. Any lowering of the rating of our first mortgage bonds would likely reduce the value of the exchange first mortgage bonds offered hereby. As discussed above, NRG is no longer a subsidiary of Xcel Energy or an affiliate of us as of December 5, 2003.

Historically, we have relied on bank lines of credit, borrowings from NSP-MN and capital contributions from Xcel Energy to supplement our operating cash flow in order to meet the short-term liquidity requirements of our business. We are also expecting to rely on loans we may obtain under a utility money pool primarily funded by Xcel Energy pursuant to a money pool agreement entered into among Xcel Energy, us and Xcel Energy’s other operating utilities and that has been recently approved by the SEC and, as it relates to our participation, the MPSC and that will go into effect upon PSCW approval. If Xcel Energy’s or NSP-MN’s access to the capital markets is impaired, it could limit Xcel Energy’s ability to contribute equity or make loans to us or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends and could affect NSP-MN’s ability to make loans to us and could impact the rate of such loans.

We also rely on accessing the capital markets to support our capital expenditure programs and other capital requirements to maintain and build our utility infrastructure and comply with future requirements such as installing emission control equipment. If we are unable to access the capital markets on favorable terms, our ability to fund our operations and required capital expenditures and other investments may be adversely affected.

A majority of the members of our board of directors, as well as many of our executive officers, are officers of Xcel Energy. Our board makes determinations with respect to the following:


	•	our payment of dividends;

	•	decisions on our financings and our capital raising activities;

	•	mergers or other business combinations; and

	•	our acquisition or disposition of assets.

Historically we have paid quarterly dividends to Xcel Energy. In 2001, 2002 and the first nine months of 2003, we paid $32.5 million, $47.1 million and $37.4 million of dividends to Xcel Energy, respectively. Our board of directors could decide to increase dividends, within the limitations of our financial covenants and credit rating objectives, to Xcel Energy to support its cash needs. This could adversely affect our liquidity. Under PUHCA, we can only pay dividends out of current earnings and retained earnings without the prior approval of the SEC. Under our Wisconsin regulatory commitments, our ability to pay dividends is also effectively limited due to the requirement of the PSCW that we maintain an equity ratio of between 52% and 57% of our total capitalization. At September 30, 2003, our retained earnings were approximately $262 million.

On July 31, 2002, a lawsuit purporting to be a class action on behalf of purchasers of Xcel Energy common stock between January 31, 2001 and July 26, 2002, was filed in the United States District Court in Minnesota. The complaint named Xcel Energy; Wayne H. Brunetti, our Chairman and Chairman and Chief Executive Officer of Xcel Energy and one of our directors; Edward J. McIntyre, former Vice President and Chief Financial Officer of Xcel Energy; and James J. Howard, former Chairman of Xcel Energy, as defendants. Among other things, the complaint alleged violations of Section 10(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and Rule 10b-5 thereunder related to allegedly false and misleading disclosures concerning various issues, including “round trip” energy trades, the existence of cross-default provisions in Xcel Energy’s and NRG’s credit agreements with lenders, NRG’s liquidity and credit status, the supposed risks to Xcel Energy’s credit rating and the status of Xcel Energy’s internal controls to monitor trading of its power. Thereafter, several additional lawsuits were filed with similar allegations, one of which added claims on behalf of a purported class of purchasers of two series of NRG senior notes issued by NRG in early 2001. The cases have all been consolidated and a consolidated amended complaint has been filed. The amended complaint charges false and misleading disclosures concerning “round trip” energy trades and the existence of provisions in Xcel Energy’s credit agreements with lenders for cross-defaults in the event of a default by NRG and, as to the NRG senior notes, also insufficient disclosures concerning the extent to which NRG’s “fortunes” were tied to those of Xcel Energy, especially in the event of a buy-in of NRG public shares. It adds as additional defendants on the claims relating to the NRG senior notes Gary R. Johnson, our and Xcel Energy’s Vice President and General Counsel and one of our directors, Richard C. Kelly, our Vice President and one of our directors and the President and Chief Operating Officer of Xcel Energy, two former executive officers of NRG (David H. Peterson and Leonard A. Bluhm), one current executive officer of NRG (William T. Pieper) and a former independent director of NRG (Luella G. Goldberg); and, as to the NRG senior notes, it adds claims of false and misleading disclosures under Section 11 of the Securities Act. The defendants filed motions to dismiss all the claims, and the court granted the motions in part and denied them in part on September 30, 2003. The court dismissed the claims brought by a sub-class of plaintiffs represented by Catholic Workman. This group consisted of persons who purchased NRG senior notes and alleged false and misleading statements in the registration statement or prospectus under Section 11 of the Securities Act. The court, however, denied the motion with respect to a putative class of plaintiffs consisting of owners of Xcel Energy common stock who alleged fraud in violation of Sections 10(b) and 20(a) of the Exchange Act. The defendants filed an answer on November 21, 2003, and the case is expected to proceed in the normal course as to the claims relating to common stock.

On August 15, 2002, a shareholder derivative action was filed in the United States District Court for the District of Minnesota, purportedly on behalf of Xcel Energy, against Xcel Energy’s directors and certain present and former officers, citing essentially the same circumstances as the class actions described above and asserting breach of fiduciary duty. This action has been consolidated for pre-trial purposes with the securities class actions. After the filing of this action, two additional derivative actions were filed in the state trial court for Hennepin County, Minnesota (and subsequently consolidated with each other), against essentially the same defendants, focusing on allegedly wrongful energy trading activities and asserting breach of fiduciary duty for failure to establish and maintain adequate accounting controls, abuse of control and gross mismanagement. In each of the derivative cases, the defendants have served motions to dismiss the complaint for failure to make a proper pre-suit demand (or, in the federal court case, to make any pre-suit demand at all) upon Xcel Energy’s board of directors. On October 10, 2003, oral arguments related to the defendants’ motion to dismiss in the state cases were presented to the court. On January 6, 2004 the state court granted defendants’ motion to dismiss the state shareholder derivative lawsuits.

On September 23, 2002 and October 9, 2002, actions were filed in the United States District Court for the District of Colorado, purportedly on behalf of classes of employee participants in Xcel Energy’s (and its predecessors’) 401(k) and employee stock ownership plans from as early as September 23, 1999. The complaints in the actions, which name as defendants Xcel Energy, its directors, certain former directors, and certain of Xcel Energy’s present and former officers, allege breach of fiduciary duty in allowing or encouraging

On February 26, 2003, Fortistar Capital, Inc. and Fortistar Methane, LLC (together, “Fortistar”) filed a $1 billion lawsuit in the Federal District Court for the Northern District of New York against Xcel Energy and five present or former employees of NRG and NEO Corp., a subsidiary of NRG. In the lawsuit, Fortistar claims that the defendants violated the Racketeer Influenced and Corrupt Organizations Act (“RICO”) and committed fraud by engaging in a pattern of negotiating and executing agreements “they intended not to comply with” and “made false statements later to conceal their fraudulent promises.” The allegations against Xcel Energy are, for the most part, limited to purported activities related to the contract for NRG’s Pike Energy power facility in Mississippi and statements related to an “equity infusion” into NRG by Xcel Energy. The plaintiffs allege damages of some $350 million and also assert entitlement to a trebling of these damages under the provisions of RICO. The present and former NRG and NEO Corp. officers and employees have requested indemnity from NRG and NRG is now examining these requests. A settlement has been reached by the parties, and they are in the process of dismissing the complaint.

The defense of these lawsuits may divert the attention of our management. In addition, if any one or a combination of these cases or other similar claims result in a substantial monetary judgment against Xcel Energy or are settled on unfavorable terms, Xcel Energy’s results of operations and liquidity could be materially adversely affected and it could limit Xcel Energy’s ability to contribute equity or make loans to us or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends.

The profitability of our utility operations depends on our ability to recover costs related to providing energy and utility services in rates charged to our customers. In June 2003, we filed our required biennial rate application with the PSCW requesting no change in our Wisconsin retail electric and natural gas base rates. The PSCW may not approve our request and could instead lower our base rates. In mid-December 2003, the PSCW informed us that they expect to complete their audit of our June 2003 rate filing in mid-January and they expect to issue an order in the first quarter of 2004. Although our Wisconsin gas and Michigan electric and gas rates have fuel adjustment recovery mechanisms, Wisconsin law does not allow the use of an automatic electric fuel adjustment clause for our Wisconsin retail electric customers. Instead, the PSCW uses a procedure that compares actual monthly and anticipated annual fuel costs with the forecast of those costs that was included in our latest retail electric rate case. If the comparison results in a difference outside a prescribed range, the PSCW may hold hearings limited to fuel costs and revise retail electric rates upward or downward. Any revised rates would be effective until the next fuel filing or rate case. Any adjustment approved would be calculated on an annual basis, but applied prospectively. The PSCW is not required to approve any such adjustments and may decline to do so. Although we believe that the current regulatory environment applicable to our business would permit us to recover the costs of our utility services, it is possible that there could be changes in circumstances or in the regulatory environment in one or more of those states that would impair our ability to recover costs historically absorbed by our customers. In particular, as a result of the energy crisis in California and the financial troubles at a number of energy companies, including the financial challenges of Xcel Energy and NRG, the regulatory environments in which we operate have received increased public attention. That attention could result in changes adverse to our ability to recover our costs.

The FERC has jurisdiction over rates for electric transmission service and electric energy sold at wholesale in interstate commerce. In addition, the FERC has jurisdiction over the “Restated Agreement to Coordinate Planning and Operations and Interchange Power and Energy” between NSP-MN and us (the

We are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including making payments on the exchange first mortgage bonds.

In light of the financial troubles of Xcel Energy and NRG, we face enhanced scrutiny from our state regulators. State utility commissions generally possess broad powers to ensure that the needs of the utility customers are being met. To the extent that one or more of our state utility commissions takes the position that any of our dividends have been funded by any of our financings, the regulators may not permit us to recover the related financing costs by passing them through to our customers as costs related to providing energy. Furthermore, our state utility commissions may, in future rate cases, determine that some portion of our financing costs, the issuance of the original first mortgage bonds and the exchange first mortgage bonds may not be recoverable because such costs are deemed to have been increased due to the financial problems at Xcel Energy and NRG. We also may be asked to otherwise ensure that our ratepayers are not harmed as a result of NRG’s bankruptcy.

Our electric production and transmission system is managed on an integrated basis with the electric production and transmission system of NSP-MN. As discussed above, pursuant to the Interchange Agreement between NSP-MN and us we share, on a proportional basis, all costs related to the generation and transmission facilities of the entire integrated NSP System including capital costs. Accordingly, if the costs to operate NSP-MN’s system increase, or revenue decrease, whether as a result of state or federally mandated improvements or otherwise, our costs could also increase as our revenues could decrease, and we cannot guarantee a full recovery of such costs through our rates at the time the costs are incurred.

Our electric production and transmission system is managed on an integrated basis with the electric production and transmission system of NSP-MN through the Interchange Agreement.

NSP-MN’s two nuclear stations, Prairie Island and Monticello, subject it, and indirectly us, to the risks of nuclear generation, which include:


	•	the risks associated with storage, handling and disposal of radioactive materials and the current lack of a long-term disposal solution for radioactive materials;

	•	limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; and


	•	uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

The Nuclear Regulatory Commission (“NRC”) has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at NSP-MN’s nuclear plants. In addition, although we have no reason to anticipate a serious nuclear incident, if an incident did occur, it could have a material adverse effect on our results of operations or financial condition. Furthermore, the non-compliance of other nuclear facilities operators with applicable regulations or the occurrence of a serious nuclear incident at other facilities could result in increased regulation of the industry as a whole, which could then increase NSP-MN’s compliance costs and impact the results of operations of its facilities.

Pursuant to the Interchange Agreement, we share, on a proportional basis, all costs related to the generation and transmission facilities of the entire integrated NSP System including NSP-MN’s nuclear facilities. Accordingly, if the costs to operate NSP-MN’s nuclear facilities increase, whether as a result of outages, increased compliance costs or other events, our costs could also increase, and we cannot guarantee a full recovery of such costs through our rates at the time the costs are incurred.

Environmental investigation and remediation costs at our Ashland site could impact our profitability and liquidity.

We were named as one of three primary responsible parties for creosote and coal tar contamination at a site in Ashland, Wisconsin. The Ashland site includes property owned by us and two other properties: an adjacent city lakeshore park area and a small area of Lake Superior’s Chequemegon Bay adjoining the park.

The Wisconsin Department of Natural Resources (“WDNR”) and we have each developed several estimates of the ultimate cost to remediate the Ashland site. The estimates vary significantly, between $4 million and $93 million, because different methods of remediation and different results are assumed in each. The Environmental Protection Agency (“EPA”) and WDNR have not yet selected the method of remediation to use at the site. Until the EPA and the WDNR select a remediation strategy for all operable units at the site and determine the level of responsibility of each primary responsible party, we are not able to accurately determine our share of the ultimate cost of remediating the Ashland site.

In the interim, we have recorded a liability for an estimate of our share of the cost of remediating the portion of the Ashland site that we own, estimated using information available to date and using reasonably effective remedial methods. We have deferred, as a regulatory asset, the remediation costs accrued for the Ashland site because we expect that the PSCW will continue to allow us to recover payments for environmental remediation from our customers. The PSCW has consistently authorized recovery in our rates of all remediation costs incurred at the Ashland site, and has authorized recovery of similar remediation costs for other Wisconsin utilities.

We proposed, and the EPA and WDNR have approved, an interim action (a coal tar removal/ groundwater treatment system) for one operable unit at the site for which we have accepted responsibility. The groundwater treatment system began operating in the fall of 2000. In 2002 we installed additional monitoring wells in the deep aquifer to better characterize the extent and degree of contaminants in that aquifer while the coal tar removal system is operational. In 2002 a second interim response action was also implemented. As approved by the WDNR, this interim response action involved the removal and capping of a seep area in a city park. Surface soils in the area of the seep were contaminated with tar residues. The interim action also included the diversion and ongoing treatment of groundwater that contributed to the formation of the seep.

On September 5, 2002, the Ashland site was placed on the National Priorities List (“NPL”). The NPL is intended primarily to guide the EPA in determining which sites require further investigation. Resolution of

On August 5, 2003, EPA issued to us a general notice of liability letter for the Ashland Site. EPA further notified us that it would enter into formal negotiations for the purpose of allowing us to take over the completion of the remedial investigation/ feasibility study (“RI/FS”) being conducted at the site. On August 26, 2003, we responded to EPA’s general notice of liability and committed to complete the RI/FS subject to an Administrative Order on Consent (“AOC”) document to be negotiated among the parties. We entered into the AOC and Scope of Work (“SOW”) with EPA, effective November 14, 2003. It is expected to cost approximately $1.5 million to complete the RI/FS activities required by the AOC. We must also pay USEPA’s costs of oversight of this work.

The AOC and SOW requires us to submit monthly written progress reports concerning actions taken at the site. The first progress report was submitted to EPA in December 2003. The AOC and SOW also required that we submit a technical letter report to EPA containing a description of similarities and differences between the RI/FS work plan prepared by the WDNR and our RI/FS work plan. This technical letter report was submitted to EPA in December 2003 and was used as a basis for a Technical Scoping Meeting held among EPA, WDNR and us. The Technical Scoping Meeting was held on January 8, 2004 to resolve any major technical discrepancies between DNR’s RI/FS work plan and our RI/FS work plan. We will soon be submitting a revised RI/FS work plan to EPA incorporating discussions from the Technical Scoping Meeting. Upon USEPA approval, the field work required by the RI/FS workplan will proceed, likely in 2004. It is estimated that the Final RI/FS report setting forth proposed cleanup options will be submitted at the end of 2005. Thereafter, USEPA will select a cleanup option.

We continue to work with the WDNR to access state and federal funds to apply to the ultimate remediation cost of the entire site.

We are subject to commodity price risk, credit risk and other risks associated with energy markets.

We engage in wholesale sales and purchases of electric capacity and energy and natural gas, and, accordingly, are also subject to commodity price risk, credit risk and other risks associated with these activities either directly or through the Interchange Agreement.

We are exposed to market and credit risks in our generation and retail distribution operations. The level of these risks are reduced somewhat by retail fuel cost recovery mechanisms which allow certain costs to be recovered from retail customers. To minimize the risk of market price and volume fluctuations, we or NSP-MN on our behalf enter into physical and financial derivative instrument contracts to hedge purchase and sale commitments, fuel requirements and inventories of natural gas, distillate fuel oil, electricity and coal and emission allowances. However, physical and financial derivative instrument contracts do not completely eliminate risks, including commodity price changes, market supply shortages, credit risk and interest rate changes. The impact of these variables could result in our inability to fulfill contractual obligations, significantly higher energy or fuel costs relative to corresponding sales contracts or increased interest expense.

Credit risk includes the risk that wholesale counterparties that owe us money or energy will breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we could incur losses.

Recession, grid disturbances, acts of war or terrorism could negatively impact our business.

The consequences of a prolonged recession and adverse market conditions may include the continued uncertainty of energy prices and the capital and commodity markets. We cannot predict the impact of any continued economic slowdown or fluctuating energy prices. However, such impact could have a material adverse effect on our financial condition and results of operations.

The conflict in Iraq and any other military strikes or sustained military campaign may affect our operations in unpredictable ways and may cause changes in the insurance markets, force us to increase

Further, like other operators of major industrial facilities, our generation plants, fuel storage facilities and transmission and distribution facilities may be targets of terrorist activities that could result in disruption of our ability to produce or distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair and insure our assets, which could have a material adverse impact on our financial condition and results of operation. In addition, these facilities constitute collateral for the first mortgage bonds. See “Description of the Exchange First Mortgage Bonds” below. Damage or destruction of such facilities could adversely affect the value of the collateral.

Also, because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business due to a disruption or black-out caused by an event (severe storm, generator or transmission facility outage) on a neighboring system or the actions of a neighboring utility, similar to the August 14, 2003 black-out in portions of the eastern U.S. and Canada. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial condition and results of operation.

Increased competition resulting from restructuring efforts could have a significant financial impact on us and consequently decrease our revenue.

Retail competition and the unbundling of regulated energy and gas service could have a significant financial impact on us due to an impairment of assets, a loss of retail customers, lower profit margins and/or increased costs of capital. Any such restructuring may have a significant impact on our financial position, results of operations and cash flows. We cannot predict when we will be subject to changes in legislation or regulation, nor can we predict the impact of these changes on our financial position, results of operations or cash flows. We believe that the prices we charge for electricity and the quality and reliability of our service currently place us in a position to compete effectively in the energy market.

Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.

Our electric and gas utility businesses are seasonal businesses and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating and demand for natural gas is extremely sensitive to winter (November to March) weather effects on space heating requirements. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our service territory and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating seasons. Accordingly, our operations have historically generated less revenues and income when weather conditions are cooler in the summer and milder in the winter. We expect that unusually mild summers and winters would have an adverse effect on our financial condition and results of operations.

Electric production expenses tend to vary with the quantity of electricity sold and changes in the unit costs of fuel and purchased power. The fuel and purchased power costs recovery mechanism of the Wisconsin jurisdiction does not allow for complete recovery of all expenses and, therefore, dramatic changes in costs or periods of extreme temperatures can impact earnings.

Any lowering of the credit ratings on the exchange first mortgage bonds would likely reduce their value.

As described above under the caption “Risk Factors — Risks Related to Our Relationship to Xcel Energy,” our credit ratings were lowered in 2002 and could be further lowered in the future. Any lowering of the credit rating on the exchange first mortgage bonds would likely reduce the value of the exchange first mortgage bonds offered hereby.

The exchange first mortgage bonds have no prior public market and a public market may not develop or be sustained after the offering.

Although the exchange first mortgage bonds generally may be resold or otherwise transferred by holders who are not our affiliates without compliance with the registration requirements under the Securities Act, they will constitute a new issue of securities without an established trading market. We have been advised by the initial purchasers of the original first mortgage bonds that they currently intend to make a market in the exchange first mortgage bonds. However, such a market may not develop or, if it does develop, it may not continue. In addition, any such market-making activity may be limited during the exchange offer and during the pendency of any shelf registration that we might file. If an active public market does not develop, the market price and liquidity of the exchange first mortgage bonds may be adversely affected. Furthermore, we do not intend to apply for listing of the exchange first mortgage bonds on any securities exchange or automated quotation system.

Even if a market for the exchange first mortgage bonds does develop, you may not be able to resell the exchange first mortgage bonds for an extended period of time, if at all. In addition, future trading prices for the exchange first mortgage bonds will depend on many factors, including, among other things, prevailing interest rates, our financial condition and the market for similar securities. As a result, you may not be able to liquidate your investment quickly or to liquidate it at an attractive price.

Broker-dealers or holders of our first mortgage bonds may become subject to the registration and prospectus delivery requirements of the Securities Act.


	•	exchanges its original first mortgage bonds in the exchange offer for the purpose of participating in a distribution of the exchange first mortgage bonds; or

	•	exchanges original first mortgage bonds that were received by it for its own account in the exchange offer,

may be deemed to have received restricted securities and may be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction by that broker-dealer. Any profit on the resale of the exchange first mortgage bonds and any commission or concessions received by a broker-dealer may be deemed to be underwriting compensation under the Securities Act.

In addition to broker-dealers, any holder of first mortgage bonds that exchanges its original first mortgage bonds in the exchange offer for the purpose of participating in a distribution of the exchange first mortgage bonds may be deemed to have received restricted securities and may be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction by that holder of first mortgage bonds.

Risks Related to a Failure to Exchange Original First Mortgage Bonds for Exchange First Mortgage Bonds

You may have difficulty selling the original first mortgage bonds which you do not exchange.

If you do not exchange your original first mortgage bonds for the exchange first mortgage bonds offered in this exchange offer, you will continue to be subject to the restrictions on the transfer of your original first mortgage bonds. Those transfer restrictions are described in the indenture and in the legend contained on the original first mortgage bonds, and arose because we issued the original first mortgage bonds under exemptions from, and in transactions not subject to, the registration requirements of the Securities Act. In general, you may offer or sell your original first mortgage bonds only if they are registered under the Securities Act and applicable state securities laws, or if they are offered and sold under an exemption from those requirements. If you do not exchange your original first mortgage bonds in the exchange offer, you will no longer be entitled to have those original first mortgage bonds registered under the Securities Act.

In addition, if a large number of original first mortgage bonds are exchanged for exchange first mortgage bonds issued in the exchange offer, the principal amount of original first mortgage bonds that will be outstanding will decrease. This will reduce the liquidity of the market for the original first mortgage bonds, making it more difficult for you to sell your original first mortgage bonds.

You must tender the original first mortgage bonds in accordance with proper procedures in order to ensure the exchange will occur.

The exchange of the original first mortgage bonds for the exchange first mortgage bonds can only occur if the proper procedures, as detailed in this prospectus, are followed. The exchange first mortgage bonds will be issued in exchange for the original first mortgage bonds only after timely receipt by the exchange agent of the original first mortgage bonds or a book-entry confirmation, a properly completed and executed letter of transmittal (or an agent’s message in lieu thereof) and all other required documentation. If you want to tender your original first mortgage bonds in exchange for exchange first mortgage bonds, you should allow sufficient time to ensure timely delivery. The exchange agent is not and we are not under any duty to give you notification of defects or irregularities with respect to your tender of original first mortgage bonds for exchange. Original first mortgage bonds that are not tendered will continue to be subject to the existing transfer restrictions. In addition, if you are an affiliate of ours or you tender the original first mortgage bonds in the exchange offer in order to participate in a distribution of the exchange first mortgage bonds, you will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction. Additional information is set forth below under the captions “The Exchange Offer” and “Plan of Distribution.”

If a market develops for the exchange first mortgage bonds, the exchange first mortgage bonds might trade at prices higher or lower than the initial offering price of the original first mortgage bonds.

If a market develops for the exchange first mortgage bonds, they might trade at prices higher or lower than the initial offering price of the original first mortgage bonds. The trading price would depend on many factors, such as prevailing interest rates, the market for similar securities, general economic conditions and our financial condition, performance and prospects.

Your ability to recover from our former independent certified public accountant, Arthur Andersen LLP, is limited.

On March 27, 2002, we appointed Deloitte & Touche LLP to be our independent certified public accountant. Our former independent certified public accountant, Arthur Andersen LLP, was convicted on federal obstruction of justice charges arising from the federal government’s investigation of Enron Corp. In light of the conviction, Arthur Andersen ceased practicing before the SEC on August 31, 2002. Arthur Andersen was the auditor of our consolidated financial statements and related schedules as of December 31,

We will not receive any cash proceeds from the issuance of the exchange first mortgage bonds. The exchange offer is intended to satisfy our obligations under the registration rights agreement that we entered into in connection with the private offering of the original first mortgage bonds. In consideration for issuing the exchange first mortgage bonds in exchange for the original first mortgage bonds as described in this prospectus, we will receive, retire and cancel the original first mortgage bonds that are properly offered for exchange. As a result, the issuance of the exchange first mortgage bonds will not result in any increase or decrease in our indebtedness. We have agreed to bear the expenses of the exchange offer to the extent indicated in the registration rights agreement. No underwriter is being used in connection with the exchange offer.

The net proceeds from the issuance and sale of the original first mortgage bonds, after deducting discounts, commissions and offering expenses, were approximately $147.6 million. We added the net proceeds from the sale of the bonds to our general funds and applied them, along with cash on hand, to redeem $110 million of our 7.25% first mortgage bonds due March 1, 2023 and to repay short-term debt incurred to pay at maturity $40 million of our 5.75% first mortgage bonds due October 1, 2003.

We issued and sold the original first mortgage bonds on October 2, 2003 in a private placement. In connection with that issuance and sale, we entered into a registration rights agreement with the initial purchasers of the original first mortgage bonds. In the registration rights agreement, we agreed to:


	•	file with the SEC the registration statement of which this prospectus is a part within 120 calendar days of the issue date of the original first mortgage bonds relating to an offer to exchange the original first mortgage bonds for the exchange first mortgage bonds;

	•	use our reasonable best efforts to cause the registration statement of which this prospectus is a part to be declared effective under the Securities Act within 180 calendar days of the issue date of the original first mortgage bonds; and

	•	commence the exchange offer and to keep the exchange offer open for at least 30 days after the date of this prospectus.

The exchange offer being made by this prospectus is intended to satisfy our obligations under the registration rights agreement. If we fail to exchange all validly tendered original first mortgage bonds in accordance with the exchange offer on or prior to 45 days after the effectiveness of the registration statement of which this prospectus is a part, we will be required to pay additional interest to holders of original first mortgage bonds until we have complied with this obligation.

Once the exchange offer is complete, we will have no further obligation to register any of the original first mortgage bonds not tendered to us in the exchange offer, except to the limited extent that certain qualified institutional buyers, if any, are otherwise entitled to have their original first mortgage bonds registered under a shelf registration as described under the caption “Exchange Offer and Registration Rights.” For a description of the restrictions on transfer of the original first mortgage bonds, see “Risk Factors — Risks Related to the Exchange First Mortgage Bonds.”

Based on interpretations by the SEC staff set forth in Exxon Capital Holdings Corporation (available April 13, 1989), Morgan Stanley & Co. Incorporated (available June 5, 1991), Shearman & Sterling (available July 7, 1993) and other no-action letters issued to third parties, we believe that you may offer for


	•	you are acquiring the exchange first mortgage bonds in the ordinary course of your business and do not hold any original first mortgage bonds to be exchanged in the exchange offer that were acquired other than in the ordinary course of business;

	•	you are not a broker-dealer tendering original first mortgage bonds acquired directly from us;

	•	you are not participating, do not intend to participate and have no arrangements or understandings with any person to participate in the exchange offer for the purpose of distributing the exchange first mortgage bonds; and

	•	you are not our “affiliate” within the meaning of Rule 405 under the Securities Act.

If you are not able to meet these requirements, you are a “restricted holder.” As a restricted holder, you will not be able to participate in the exchange offer, you may not rely on the interpretations of the SEC staff set forth in the no-action letters referred to above and you may only sell your original first mortgage bonds in compliance with the registration and prospectus delivery requirements of the Securities Act or under an exemption from the registration requirements of the Securities Act or in a transaction not subject to the Securities Act.

We do not intend to seek our own no-action letter, and there can be no assurance that the staff of the SEC would make a similar determination with respect to the exchange first mortgage bonds as it has in such no-action letters to third parties.

In addition, if the tendering holder is a broker-dealer that will receive exchange first mortgage bonds for its own account in exchange for original first mortgage bonds that were acquired as a result of market-making or other trading activities, it may be deemed to be an “underwriter” within the meaning of the Securities Act. Any such holder will be required to acknowledge in the letter of transmittal that it will deliver a prospectus meeting the requirements of the Securities Act in connection with any resale of these exchange first mortgage bonds. This prospectus may be used by those broker-dealers to resell exchange first mortgage bonds they receive pursuant to the exchange offer. We have agreed that we will allow this prospectus to be used by any broker-dealer in any resale of exchange first mortgage bonds until September 5, 2004 (180 days from the completion of this exchange offer).

Except as described above, this prospectus may not be used for an offer to resell, resale or other transfer of exchange first mortgage bonds.

To the extent original first mortgage bonds are tendered and accepted in the exchange offer, the principal amount of original first mortgage bonds that will be outstanding will decrease with a resulting decrease in the liquidity in the market for the original first mortgage bonds. Original first mortgage bonds that are still outstanding following the completion of the exchange offer will continue to be subject to transfer restrictions.

Upon the terms and subject to the conditions of the exchange offer described in this prospectus and in the accompanying letter of transmittal, we will accept for exchange all original first mortgage bonds validly tendered and not withdrawn before 5:00 p.m., New York City time, on the expiration date. We will issue $1,000 principal amount of exchange first mortgage bonds in exchange for each $1,000 principal amount of original first mortgage bonds accepted in the exchange offer. You may tender some or all of your original first mortgage bonds pursuant to the exchange offer. However, original first mortgage bonds may be tendered only in increments of $1,000.

The exchange offer is not conditioned upon any minimum aggregate principal amount of original first mortgage bonds being tendered for exchange. As of the date of this prospectus, an aggregate of $150 million principal amount of original first mortgage bonds was outstanding. This prospectus is being sent to all

We intend to conduct the exchange offer in accordance with the applicable requirements of the Securities Act and the Exchange Act and the rules and regulations of the SEC. Holders of original first mortgage bonds do not have any appraisal or dissenters’ rights under law or under our Supplemental and Restated Trust Indenture dated March 1, 1991 (the “Restated Indenture”) under which the exchange first mortgage bonds will be issued, as amended and supplemented, in connection with the exchange offer. Original first mortgage bonds that are not tendered for exchange in the exchange offer will remain outstanding and continue to accrue interest and will be entitled to the rights and benefits their holders have under the Restated Indenture, as amended and supplemented.

We will be deemed to have accepted for exchange validly tendered original first mortgage bonds when we have given oral or written notice of the acceptance to the exchange agent. The exchange agent will act as agent for the tendering holders of original first mortgage bonds for the purposes of receiving the exchange first mortgage bonds from us and delivering the exchange first mortgage bonds to the tendering holders.

If we do not accept for exchange any tendered original first mortgage bonds because of an invalid tender, the occurrence of certain other events described in this prospectus or otherwise, such unaccepted original first mortgage bonds will be returned, without expense, to the holder tendering them or the appropriate book-entry will be made, in each case, as promptly as practicable after the expiration date.

We are not making, nor is our board of directors making, any recommendation to you as to whether to tender or refrain from tendering all or any portion of your original first mortgage bonds in the exchange offer. No one has been authorized to make any such recommendation. You must make your own decision whether to tender your original first mortgage bonds in the exchange offer and, if you decide to do so, you must also make your own decision as to the aggregate amount of original first mortgage bonds to tender after reading this prospectus and the letter of transmittal and consulting with your advisers, if any, based on your own financial position and requirements.

The term “expiration date” means 5:00 p.m., New York City time, on March 9, 2004, unless we, in our sole discretion, extend the exchange offer, in which case the term “expiration date” shall mean the latest date and time to which the exchange offer is extended.

If we determine to extend the exchange offer, we will notify the exchange agent of any extension by oral or written notice.


	•	to delay accepting for exchange any original first mortgage bonds; or

	•	to extend or terminate the exchange offer and to refuse to accept original first mortgage bonds not previously accepted if any of the conditions set forth below under “— Conditions to the Exchange Offer” have not been satisfied by the expiration date.

Without limiting the manner in which we may choose to make public announcements of any delay in acceptance, extension, termination or amendment of the exchange offer, we will have no obligation to publish, advertise or otherwise communicate any public announcement, other than by making a timely release to a financial news service.

During any extension of the exchange offer, all original first mortgage bonds previously tendered will remain subject to the exchange offer. We will return any original first mortgage bonds that we do not accept for exchange for any reason without expense to the tendering holder as promptly as practicable after the expiration or earlier termination of the exchange offer.

In order to exchange your original first mortgage bonds, you must complete one of the following procedures by 5:00 p.m., New York City time, on the expiration date:


	•	if your original first mortgage bonds are in book-entry form, the book-entry procedures for tendering your original first mortgage bonds must be completed as described below under “— Book-Entry Transfer”;

	•	if you hold physical original first mortgage bonds that are registered in your name (i.e., not in book-entry form), you must transmit a properly completed and duly executed letter of transmittal, certificates for the original first mortgage bonds you wish to exchange and all other documents required by the letter of transmittal, to U.S. Bank National Association, the exchange agent, at its address listed below under “— Exchange Agent”; or

	•	if you cannot tender your original first mortgage bonds by either of the above methods by the expiration date, you must comply with the guaranteed delivery procedures described below under “— Guaranteed Delivery Procedures.”

A tender of original first mortgage bonds by a holder that is not withdrawn prior to the expiration date will constitute an agreement between that holder and us in accordance with the terms and subject to the conditions set forth in this prospectus and in the letter of transmittal.

The method of delivery of original first mortgage bonds through Depository Trust Company (“DTC”) and the method of delivery of the letter of transmittal and all other required documents to the exchange agent is at the holder’s election and risk. Holders should allow sufficient time to effect the DTC procedures necessary to validly tender their original first mortgage bonds to the exchange agent before the expiration date. Holders should not send letters of transmittal or other required documents to us.

We will determine, in our sole discretion, all questions as to the validity, form, eligibility (including time of receipt), acceptance of tendered original first mortgage bonds and withdrawal of tendered original first mortgage bonds, and our determination will be final and binding. We reserve the absolute right to reject any and all original first mortgage bonds not properly tendered or any original first mortgage bonds the acceptance of which would, in our opinion or in the opinion of our counsel, be unlawful. We also reserve the absolute right to waive any defects or irregularities or conditions of the exchange offer as to any particular original first mortgage bonds either before or after the expiration date. Our interpretation of the terms and conditions of the exchange offer as to any particular original first mortgage bonds either before or after the expiration date, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of original first mortgage bonds for exchange must be cured within such time as we shall determine. Although we intend to notify holders of any defects or irregularities with respect to tenders of original first mortgage bonds for exchange, neither we nor the exchange agent nor any other person shall be under any duty to give such notification, nor shall any of them incur any liability for failure to give such notification. Tenders of original first mortgage bonds will not be deemed to have been made until all defects or irregularities have been cured or waived. Any original first mortgage bonds received by the exchange agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned by the exchange agent to the tendering holders or, in the case of original first mortgage bonds delivered by book-entry transfer within DTC, will be credited to the account maintained within DTC by the participant in DTC that delivered such original first mortgage bonds, unless otherwise provided in the letter of transmittal, as soon as practicable following the expiration date.

In addition, we reserve the right in our sole discretion (a) to purchase or make offers for any original first mortgage bonds that remain outstanding after the expiration date, (b) as set forth below under “— Conditions to the Exchange Offer,” to terminate the exchange offer and (c) to the extent permitted by applicable law, purchase original first mortgage bonds in the open market, in privately negotiated transactions or otherwise. The terms of any such purchases or offers could differ from the terms of the exchange offer.

By signing, or otherwise becoming bound by, the letter of transmittal, each tendering holder of original first mortgage bonds (other than certain specified holders) will represent to us that:


	•	it is acquiring the exchange first mortgage bonds and it acquired the original first mortgage bonds being exchanged in the ordinary course of its business;

	•	it is not a broker-dealer tendering original first mortgage bonds acquired directly from us;

	•	it is not participating, does not intend to participate and has no arrangements or understandings with any person to participate in the distribution (within the meaning of the Securities Act) of the exchange first mortgage bonds; and

	•	it is not our “affiliate,” within the meaning of Rule 405 under the Securities Act, or, if it is our affiliate, it will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable.

If the tendering holder is a broker-dealer that will receive exchange first mortgage bonds for its own account in exchange for original first mortgage bonds that were acquired as a result of market-making activities or other trading activities, it may be deemed to be an “underwriter” within the meaning of the Securities Act. Any such holder will be required to acknowledge in the letter of transmittal that it will deliver a prospectus meeting the requirements of the Securities Act in connection with any resale of these exchange first mortgage bonds. The letter of transmittal states that by so acknowledging and by delivering a prospectus, the broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

If your original first mortgage bonds are in book-entry form and are registered in the name of a broker, dealer, commercial bank, trust company or other nominee, you must contact the registered holder of your original first mortgage bonds and instruct it to promptly tender your original first mortgage bonds for exchange on your behalf.

The exchange agent will establish an account with respect to the original first mortgage bonds at DTC promptly after the date of this prospectus. Your book-entry first mortgage bonds must be transferred into the exchange agent’s account at DTC in compliance with DTC’s transfer procedures in order for your original first mortgage bonds to be validly tendered for exchange. Any financial institution that is a participant in DTC’s systems may cause DTC to transfer original first mortgage bonds to the exchange agent’s account. The DTC participant, on your behalf, must transmit its acceptance of the exchange offer to DTC. DTC will verify this acceptance, execute a book-entry transfer of the tendered original first mortgage bonds into the exchange agent’s account and then send to the exchange agent confirmation of this book-entry transfer. The confirmation of this book-entry transfer will include an “agent’s message” confirming that DTC has received an express acknowledgement from the DTC participant that the DTC participant has received and agrees to be bound by the letter of transmittal and that we may enforce the letter of transmittal against this participant. Original first mortgage bonds will be deemed to be validly tendered for exchange only if the exchange agent receives the book-entry confirmation from DTC, including the agent’s message, prior to the expiration date.

All references in this prospectus to deposit or delivery of original first mortgage bonds shall be deemed to also refer to DTC’s book-entry delivery method.

Holders who wish to tender their original first mortgage bonds and (1) whose original first mortgage bonds are not immediately available or (2) who cannot deliver the letter of transmittal or any other required


	•	the tender is made through an eligible institution;

	•	before the expiration date, the exchange agent receives from the eligible institution a properly completed and duly executed notice of guaranteed delivery, by facsimile transmission, mail or hand delivery, listing the principal amount of original first mortgage bonds tendered, stating that the tender is being made thereby and guaranteeing that, within three New York Stock Exchange, Inc. trading days after the expiration date, a duly executed letter of transmittal, together with a confirmation of book-entry transfer of such original first mortgage bonds into the exchange agent’s account at DTC and any other documents required by the letter of transmittal and the instructions thereto, will be deposited by such eligible institution with the exchange agent; and

	•	within three New York Stock Exchange trading days after the expiration date, the exchange agent receives a confirmation of book-entry transfer of all original first mortgage bonds tendered by the eligible institution into the exchange agent’s account at DTC in the case of book-entry original first mortgage bonds, or a properly completed and executed letter of transmittal and the physical original first mortgage bonds, in the case of original first mortgage bonds in certificated form, and all other documents required by the letter of transmittal.

Upon request to the exchange agent, a notice of guaranteed delivery will be sent to holders who wish to tender their original first mortgage bonds according to the guaranteed delivery procedures described above.

Except as otherwise provided in this prospectus, tenders of original first mortgage bonds may be withdrawn at any time prior to 5:00 p.m., New York City time, on the expiration date.

For a withdrawal to be effective, the exchange agent must receive a written or facsimile transmission notice of withdrawal at the address set forth below under “— Exchange Agent.” Any notice of withdrawal must:


	•	specify the name of the person who tendered the original first mortgage bonds to be withdrawn;

	•	identify the original first mortgage bonds to be withdrawn, including the principal amount of such original first mortgage bonds;

	•	state that the holder is withdrawing its election to exchange the original first mortgage bonds to be withdrawn;

	•	be signed by the holder in the same manner as the original signature on the letter of transmittal by which the original first mortgage bonds were tendered and include any required signature guarantees; and

	•	specify the name and number of the account at DTC to be credited with the withdrawn original first mortgage bonds and otherwise comply with the procedures of DTC.

We will determine, in our sole discretion, all questions as to the validity, form and eligibility (including time of receipt) of any notice of withdrawal, and our determination shall be final and binding on all parties. Any original first mortgage bonds so withdrawn will be deemed not to have been validly tendered for exchange for purposes of the exchange offer, and no exchange first mortgage bonds will be issued with respect thereto unless the original first mortgage bonds so withdrawn are validly re-tendered. Properly withdrawn original first mortgage bonds may be re-tendered by following one of the procedures described above under “— Procedures for Tendering” at any time prior to the expiration date.

Any original first mortgage bonds that are tendered for exchange through the facilities of DTC but that are not exchanged for any reason will be credited to an account maintained with DTC for the original first

Despite any other term of the exchange offer, we will not be required to accept for exchange, or to issue exchange first mortgage bonds in exchange for, any original first mortgage bonds, and we may terminate the exchange offer as provided in this prospectus prior to the expiration date, if:


	•	we are not permitted to effect the exchange offer according to the registration rights agreement because of any change in law, regulation or any applicable interpretation of the SEC staff;

	•	a pending or threatened action or proceeding would impair our ability to proceed with the exchange offer;

	•	a stop order has been issued by the SEC or any state securities authority suspending the effectiveness of the registration statement; or

	•	not all governmental approvals necessary for the consummation of the exchange offer have been obtained.

These conditions are for our sole benefit and may be asserted by us regardless of the circumstances giving rise to any of these conditions or may be waived by us, in whole or in part, at any time and from time to time in our reasonable discretion. Our failure at any time to exercise any of the foregoing rights shall not be deemed a waiver of the right and each right shall be deemed an ongoing right which may be asserted at any time and from time to time.

If we determine in our reasonable judgment that any of the conditions are not satisfied, we may:


	•	refuse to accept and return to the tendering holder any original first mortgage bonds or credit any tendered original first mortgage bonds to the account maintained within DTC by the participant in DTC which delivered the original first mortgage bonds;

	•	extend the exchange offer and retain all original first mortgage bonds tendered before the expiration date, subject to the rights of holders to withdraw the tenders of original first mortgage bonds (see “— Withdrawal of Tenders” above); or

	•	waive the unsatisfied conditions with respect to the exchange offer prior to the expiration date and accept all properly tendered original first mortgage bonds that have not been withdrawn or otherwise amend the terms of the exchange offer in any respect as provided under “— Expiration Date; Extensions; Amendments.”

In addition, we will not accept for exchange any original first mortgage bonds tendered, and we will not issue exchange first mortgage bonds in exchange for any of the original first mortgage bonds, if at that time any stop order is threatened or in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the indenture under the Trust Indenture Act of 1939, as amended.

U.S. Bank National Association has been appointed as the exchange agent for the exchange offer. All signed letters of transmittal and other documents required for a valid tender of your original first mortgage bonds should be directed to the exchange agent at the address set forth below. Questions and requests for

Delivery to other than the above address or facsimile number or delivery by e-mail will not constitute a valid delivery.

We will bear the expenses of soliciting tenders for the exchange offer. These expenses include fees and expenses of the exchange agent and the trustee, the registration fee, accounting and legal fees, printing costs and related fees and expenses. We will principally solicit tenders for the exchange offer by mail or overnight courier, although our officers and regular employees may additionally solicit in person or by telephone or facsimile.

We have not retained any dealer-manager in connection with the exchange offer and will not pay any brokers, dealers or others soliciting acceptance of the exchange offer. We, however, will pay the exchange agent reasonable and customary fees for its services and its reasonable out-of-pocket expenses. We may also pay brokerage houses and other custodians, nominees and fiduciaries their reasonable out-of-pocket expenses for sending copies of this prospectus, letters of transmittal and related documents to holders of the original first mortgage bonds and in tendering original first mortgage bonds for their customers.

Holders who tender their original first mortgage bonds for exchange will not be obligated to pay any transfer taxes in connection with the exchange offer.

We will recognize no gain or loss, for accounting purposes, as a result of the exchange offer. The expenses of the exchange offer and the unamortized expenses relating to the issuance of the original first mortgage bonds will be amortized over the term of the exchange first mortgage bonds.

Holders of original first mortgage bonds who do not exchange their original first mortgage bonds for exchange first mortgage bonds pursuant to the exchange offer will not be able to offer, sell or otherwise transfer the original first mortgage bonds except in compliance with the registration requirements of the Securities Act and other applicable securities laws, pursuant to an exemption from the securities laws or in a transaction not subject to the securities laws. Original first mortgage bonds not exchanged pursuant to the exchange offer will otherwise remain outstanding in accordance with their respective terms and will continue to bear a legend reflecting these restrictions on transfer. Holders of original first mortgage bonds do not have any appraisal or dissenters’ rights in connection with the exchange offer.

Upon completion of the exchange offer, holders of original first mortgage bonds will not be entitled to any rights to have the resale of original first mortgage bonds registered under the Securities Act except to the limited extent that certain qualified institutional buyers, if any, are otherwise entitled under the registration rights agreement to have their original first mortgage bonds registered under a shelf registration. Except for

In addition, upon completion of the exchange offer, there may be no market for the original first mortgage bonds, and if you fail to exchange the original first mortgage bonds, you may have difficulty selling them.

The following table sets forth our consolidated capitalization as of September 30, 2003. We will not receive any proceeds from the exchange of the exchange first mortgage bonds for outstanding original first mortgage bonds. You should read the information in this table together with the detailed information and financial statements appearing in this prospectus and with “Selected Consolidated Financial Data” included elsewhere in this prospectus.

The following selected consolidated financial data as of and for the years ended December 31, 2002, 2001, 2000, 1999 and 1998 have been derived from our audited consolidated financial statements and the related notes. The consolidated financial data as of September 30, 2003 and 2002 have been derived from our unaudited interim consolidated financial statements. The information set forth below should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” our audited and unaudited consolidated financial statements and related notes and other financial information contained in this prospectus. The historical financial information may not be indicative of our future performance.

The following discussion and analysis should be read in conjunction with “Summary — Summary Historical Financial Data,” “Selected Consolidated Financial Data” and our financial statements and related notes appearing elsewhere in this prospectus. This discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. See “Special Note Regarding Forward-Looking Statements.” The actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors including, but not limited to, those set forth under “Special Note Regarding Forward-Looking Statements” and “Risk Factors” in this prospectus.

We were incorporated in 1901 under the laws of Wisconsin as the La Crosse Gas and Electric Company. Prior to August 2000, we were a wholly-owned subsidiary of Northern States Power Company, a Minnesota corporation (“NSP”). On August 18, 2000, NSP and New Century Energies, Inc. merged to form Xcel Energy Inc. (“Xcel Energy”), a Minnesota corporation and registered holding company under the Public Utility Holding Company Act of 1935 (“PUHCA”), and we became a wholly-owned subsidiary of Xcel Energy. We own three direct subsidiaries: Chippewa and Flambeau Improvement Co., which operates hydro reserves; Clearwater Investments Inc., which owns interests in affordable housing; and NSP Lands, Inc., which holds real estate. We are now a wholly owned subsidiary of Xcel Energy. NSP-MN is a Minnesota corporation formed in 2000 that was assigned the electric and natural gas utility assets and obligations of NSP effective on the merger date, including obligations under the Interchange Agreement.

The following discussion and analysis by management focuses on those factors that had a material effect on our financial condition and results of operations during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying audited and interim consolidated financial statements and notes included in this prospectus.

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. The forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan,” “may,” “objective,” “outlook,” “possible,” “potential,” “projected,” “should” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to:


	•	general economic conditions, including their impact on capital expenditures;

	•	business conditions in the retail and wholesale energy industry;

	•	competitive factors, including the extent and timing of the entry of additional competition in the markets served by us;

	•	unusual weather;

	•	changes in federal or state legislation;

	•	regulation and regulatory initiatives that affect cost and investment recovery and have an impact on rate structures;

	•	rating agency action;

	•	our ability, and that of our affiliates, to access the capital markets and obtain credit on favorable terms;

	•	costs and other effects of legal and administrative proceedings, settlements, investigations and claims, including without limitation claims brought against our parent, Xcel Energy;

	•	effects of geopolitical events, including war and acts of terrorism;


	•	changes in accounting principles; and

	•	the other risk factors discussed under “Risk Factors.”

Our net income was approximately $37.0 million for the first nine months of 2003, compared with approximately $42.9 million for the first nine months of 2002. The change was primarily due to a lower gross margin in 2003, partially offset by an increase in other nonoperating income. Our net income was $54.4 million for 2002, compared with $36.4 million for 2001. The change was primarily due to a higher gross margin in 2002. Our net income was $36.4 million for 2001, compared with $30.3 million for 2000. The change was primarily due to a higher gross margin in 2001, partially offset by a decrease in other nonoperating income.

Significant Factors that Impacted Results for the Nine Months Ended September 30, 2002

Special Charges — During the nine months ended September 30, 2002, we expensed pretax special charges of approximately $0.5 million. The charges related to our allocated share of severance costs for utility operations resulting from restaffing plans of several operating and corporate support areas of Xcel Energy.

Special Charges — During 2002, we expensed pretax special charges of approximately $0.7 million. The charges related to our allocated share of severance costs for utility operations resulting from restaffing plans of several operating and corporate support areas of Xcel Energy. All accrued staff terminations occurred in 2002 and all related severance payments had been made by September 30, 2003.

Special Charges — During 2001, we expensed pretax special charges of approximately $2.5 million for planned staff consolidation costs. The charges related to our allocated share of severance costs for utility operations resulting from restaffing plans of several operating and corporate support areas of Xcel Energy. We accrued for our allocated share of staff terminations for all of Xcel Energy that were expected to occur in the first quarter of 2002.

Special Charges — During 2000, we expensed pretax special charges totaling approximately $12.8 million. The pretax charges included expenses related to one-time transaction-related costs incurred in connection with the merger of NSP and NCE and pretax charges pertaining to incremental costs of transition and integration activities associated with the merger.

The following table details the change in electric revenue and gross margin. The fuel and purchased power cost recovery mechanism of the Wisconsin jurisdiction does not allow for complete recovery of all expenses and, therefore, dramatic changes in costs or periods of extreme temperatures can impact earnings.

Nine Months Ended September 30, 2003 Comparison to Nine Months Ended September 30, 2002 — Electric utility revenue increased by approximately $9.1 million or 2.6 percent for the first nine months of 2003 due to sales growth and higher billings to NSP-MN for cost allocations under the Interchange Agreement. (For more information on the Interchange Agreement, see our discussion elsewhere in this prospectus and Note 17 to the audited financial statements.) Electric utility margin decreased by approximately $6 million, or 3.2 percent, in the first nine months of 2003, compared with the first nine months of 2002, primarily due to lower fuel cost recovery through rates and higher unit costs of fuel and purchased power in 2003. Sales growth and higher billings to NSP-MN for cost allocations partially offset the margin decreases.

2002 Comparison to 2001 — Electric revenue increased by approximately $8 million, or 1.7 percent, in 2002 primarily due to higher fuel cost recoveries through rates, sales growth, and more favorable weather conditions. Partially offsetting the revenue increases were lower Interchange Agreement billings to NSP-MN for energy delivered and cost allocations. Electric margin increased by approximately $29 million, or 13.4 percent, in 2002 due largely to higher fuel cost recoveries through rates, lower fuel and purchased power cost, sales growth, and more favorable weather conditions.

2001 Comparison to 2000 — Electric revenue increased by approximately $27 million, or 6.4 percent, in 2001. Electric margin increased by approximately $4 million, or 1.9 percent, in 2001 as compared to 2000. Revenue increased primarily because of rate and cost-sharing mechanisms that passed through some of the effects of higher electricity production costs to our customers. The primary causes of the increase in fuel and purchased power expenses were higher generating plant fuel cost and greater and more expensive purchases of power from other parties.

The following table details the change in gas revenue and gross margin. The cost of gas tends to vary with changing sales requirements and unit cost of wholesale gas purchases. However, due to purchase gas cost recovery mechanisms for retail customers in Wisconsin and Michigan, fluctuations in the cost of gas have little effect on gas margin.

Nine Months Ended September 30, 2003 Comparison to Nine Months Ended September 30, 2002 — Natural gas revenue for the first nine months of 2003 increased by approximately $23 million, or 33.7 percent, compared with the first nine months of 2002, primarily due to significant increases in the wholesale cost of natural gas, which are largely recovered through various purchased natural gas cost recovery mechanisms. Natural gas margin increased by approximately $2 million, or 11.8 percent, in the first nine months of 2003 due to a higher-revenue mix of sales volumes and more favorable weather conditions in 2003.

2002 Comparison to 2001 — Gas revenue decreased by approximately $21 million, or 17.0 percent, in 2002 compared with 2001, mostly due to decreases in the wholesale cost of natural gas, which are largely passed through to customers through various purchased gas cost recovery mechanisms. Gas margin increased by $3 million, or 11.1 percent, in 2002 primarily due to sales growth and more favorable weather conditions.

2001 Comparison to 2000 — Gas revenue increased by approximately $13 million, or 11.8 percent, in 2001 compared with 2000, mostly due to recovery of the higher wholesale natural gas costs in 2001. Gas margin decreased mainly due to unfavorable weather conditions experienced in the fourth quarter of 2001, which decreased gas sales.

Nine Months Ended September 30, 2003 Comparison to Nine Months Ended September 30, 2002 — Other operating and maintenance expense for the first nine months of 2003 increased by approximately $3.0 million, or 3.9 percent, compared with the first nine months of 2002, primarily due to higher incentive and other benefit costs partially offset by lower transmission Interchange Agreement charges from NSP-MN.

Depreciation and amortization expense increased by approximately $1.8 million, or 5.3 percent, in the first nine months of 2003, compared with the first nine months of 2002, primarily due to capital additions to utility plant.

As discussed in Note 2 to the interim financial statements, in the first quarter of 2002, pretax special charges of $0.5 million were expensed for our share of the costs of staff consolidations. The charges related to severance costs for utility operations resulting from restaffing plans of several operating and corporate support areas of Xcel Energy.

2002 Comparison to 2001 — Other operating and maintenance expense for 2002 decreased by approximately $4.5 million or 4.2 percent, compared with 2001, largely due to reduced benefit costs and Interchange Agreement expense from NSP-MN. See further discussion of the Interchange Agreement at Note 17 to the audited financial statements.

Depreciation and amortization expense increased by approximately $2.8 million, or 6.8 percent, for 2002 compared with 2001, primarily due to capital additions to utility plant and remaining life changes to production plant and data processing equipment.

Special charges decreased by $1.8 million in 2002. During 2001, we expensed pretax special charges of approximately $2.5 million for planned staff consolidation costs. In the first quarter of 2002, the identification of affected employees was completed and additional pretax charges of $0.7 million were expensed for the final costs of staff consolidations. The charges related to our allocation of severance costs for utility operations resulting from restaffing plans of several operating and corporate support areas of Xcel Energy. For more information, see Note 2 to the audited financial statements.

Interest expense increased by approximately $1.0 million, or 4.7 percent, for 2002 compared with 2001, largely due to regulatory amortization of an interest refund in 2001 that did not recur in 2002 and lower allowance for funds used during construction (related to lower construction expenditures).

2001 Comparison to 2000 — Other operating and maintenance expense for 2001 increased by $1.8 million, or one percent, compared with 2000, reflecting fairly stable costs.

Depreciation and amortization expense was $1.1 million, or 2.8 percent, higher in 2001 than in 2000, primarily because more utility plant was being depreciated.

Interest expense increased by approximately $2.8 million, or 14.6 percent, for 2001 compared with 2000. Approximately $4.6 million of the increase relates to a full year’s interest and a partial year’s interest paid on debt issued in October 2000. This increase was partially offset by lower short-term debt balances and lower interest rates.

Our earnings can be significantly affected by weather. Unseasonably hot summers or cold winters increase electric and natural gas sales, but also can increase expenses, which may not be fully recoverable. Unseasonably mild weather reduces electric sales, but may not reduce expenses, which affects overall results. Unseasonably mild weather can significantly reduce natural gas sales, which affects overall results. The following summarizes the estimated impact on our earnings due to temperature variations from historical averages:


	•	weather in the first nine months of 2003 increased net income by an estimated $0.7 million;

	•	weather in 2002 decreased net income by an estimated $0.3 million;

	•	weather in 2001 decreased net income by an estimated $1.1 million; and

	•	weather in 2000 decreased net income by an estimated $0.7 million.

Our utility revenues depend on customer usage, which varies with weather conditions, general business conditions and the cost of energy services. Regulatory agencies approve the prices for electric and natural gas service within their respective jurisdictions. The historical and future trends of our operating results have been, and are expected to be, affected by the following factors:

General Economic Conditions — Economic conditions in the United States, and to a lesser extent in foreign countries, may have a material impact on our operating results. Although the United States economy is showing recent signs of recovery as measured by gross domestic product growth, general economic conditions over the past year contributed to a decline in the price for power and decreased energy commodity-trading margins with respect to our affiliates. In addition, certain operating costs, such as insurance and security, have increased due to the dual threats of terrorist activity and war. We could experience a material adverse impact to our results of operations, future growth or ability to raise capital should the current economic recovery stall or further military engagements or terrorist incidents occur. Management cannot predict the impact of a continued economic slowdown, fluctuating energy prices, terrorism, war or the threat of war.

Sales Growth — In addition to weather impacts, customer sales levels can vary with economic conditions, customer usage patterns and other factors. Weather-normalized electric retail sales growth was estimated to be 1.7 percent in the first nine months of 2003 compared with the first nine months of 2002, 2.9 percent in 2002 compared with 2001 and (0.4) percent in 2001 compared with 2000. We are projecting that weather-normalized sales growth in 2003 compared with 2002 will be 2.0 percent. Weather-normalized gas firm sales growth was estimated to be 7.1 percent in the first nine months of 2003 compared with the first nine months of 2002, 6.6 percent in 2002 compared with 2001, and (2.8) percent in 2001 compared with 2000. We are projecting that weather-normalized sales growth in 2003 compared with 2002 will be 4.1 percent.

Utility Industry Changes — The structure of the electric utility industry has been subject to change. Merger and acquisition activity has been significant as utilities combine to capture economies of scale or establish a strategic niche in preparing for the future. Some regulated utilities are divesting generation or transmission assets. All FERC jurisdictional electric utilities, including NSPW, are required to provide nondiscriminatory access to the use of their transmission systems. Effective February 1, 2002, access to the integrated NSP System is available through the Midwest ISO open access transmission tariff.

Some states had begun to allow retail customers to choose their electricity supplier, and many other states were considering retail competition proposals. Since January 1, 2002, we have been providing our Michigan electric customers with the opportunity to select an alternative electric energy provider. This action was required by Michigan’s “Customer Choice and Electricity Reliability Act,” which became law in June 2002. However, the experience of the State of California in instituting competition, as well as the bankruptcy of Enron Corporation in 2001, have caused indefinite delays in retail restructuring in Wisconsin.

We cannot predict the outcome of restructuring proceedings in the electric utility jurisdictions we serve at this time. The resolution of these matters may have a significant impact on our financial position, results of operations and cash flows.

Critical Accounting Policies — Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles (“GAAP”) requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. This application necessarily involves judgments regarding future events, including legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may have a significant effect, not only on the operation of the business, but also on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies have not changed. Listed below are accounting policies that are most significant to the portrayal of our financial condition and results and that require management’s most difficult, subjective or complex judgments. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or when using different assumptions.

Pension Plan Costs and Assumptions — Xcel Energy’s pension costs are based on an actuarial calculation that includes a number of key assumptions, most notably the annual return level that pension investment assets will earn in the future, and the interest rate used to discount future pension benefit payments to a present value obligation for financial reporting. In addition, the actuarial calculation uses an asset smoothing methodology to reduce volatility of varying investment performance over time.

Pension costs have been increasing in recent years, and are expected to increase further over the next several years, due to lower than expected investment returns and decreases in interest rates used to discount benefit obligations. Investment returns in 2000 and 2001 were below the assumed level of 9.5 percent, and interest rates have declined from the 7.5 percent to 8 percent levels used in 1999 and 2000 cost determinations to 7.25 percent used in 2002. Xcel Energy continually reviews its pension assumptions, and for 2003 has changed its investment return assumption to 9.25 percent and the discount rate assumption to 6.75 percent.

Xcel Energy bases its investment return assumption on expected long-term performance for each of the investment types included in its pension asset portfolio. These include equity investments, such as corporate common stocks; fixed-income investments, such as corporate bonds; and U.S. Treasury securities and non-traditional investments, such as timber or real estate partnerships. In reaching a return assumption, Xcel Energy considers the actual historical returns achieved by its asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts in the marketplace. The historical weighted average annual return for the past 20 years for Xcel Energy’s portfolio of pension investments is 12.6 percent, in excess of the current assumption level. The pension cost determinations assume the continued current mix of investment types over the long-term. Xcel Energy’s portfolio is heavily weighted toward equity securities, and includes non-traditional investments that can provide a higher than average return. However, as is the experience in recent years, a higher weighting in equity investments can increase the volatility in the return levels actually achieved by pension assets in any year. Xcel Energy lowered the 2003 pension investment return assumptions to reflect changing expectations of investment experts in the marketplace.

The investment gains or losses resulting from the difference between the expected pension returns assumed on smoothed or “market-related” asset levels and actual returns earned is deferred in the year the difference arises and recognized over the subsequent five-year period. This gain or loss recognition occurs by using a five-year moving-average value of pension assets to measure expected asset returns in the cost determination process, and by amortizing deferred investment gains or losses over the subsequent five-year period. Based on the use of average market-related asset values, and considering the expected recognition of past investment gains and losses over the next five years, achieving the assumed rate of asset return of 9.25 percent in each future year and holding other assumptions constant, Xcel Energy currently projects that the pension costs recognized by it for financial reporting purposes will increase from a credit, or negative expense, of $84 million in 2002 to a credit of $45 million in 2003, a credit of $20 million in 2004, and a net expense of $20 million in 2005. Pension costs are currently a credit due to the recognized investment asset returns exceeding the other pension cost components, such as benefits earned for current service and interest costs for the effects of the passage of time on discounted obligations.

Xcel Energy bases its discount rate assumption on benchmark interest rates quoted by an established credit rating agency, Moody’s, and has consistently benchmarked the interest rate used to derive the discount rate to the movements in long-term corporate bond indices for bonds rated AAA through BAA by Moody’s, which have a period to maturity comparable to Xcel Energy’s projected benefit obligations. At December 31, 2002, the annualized Moody’s Aa index rate, roughly in the middle of the AAA and BAA range, was 6.63 percent, which when rounded to the nearest quarter-percent rate, as is Xcel Energy’s policy, resulted in a 6.75 percent pension discount rate at year-end 2002. This rate was used to value the actuarial benefit obligations at that date, and will be used in 2003 pension cost determinations.

If Xcel Energy were to use alternative assumptions for pension cost determinations, a 1 percent change would result in the following impacts on the estimated pension costs recognized by Xcel Energy for financial reporting purposes:


	•	a 1 percent higher rate of return, 10.25 percent, would decrease 2003 pension costs by $22 million;

	•	a 1 percent lower rate of return, 8.25 percent, would increase 2003 pension costs by $22 million;

	•	a 1 percent higher discount rate, 7.75 percent, would decrease 2003 pension costs by $8 million; and

	•	a 1 percent lower discount rate, 5.75 percent, would increase 2003 pension costs by $12 million.

Alternative assumptions would also change the expected future cash funding requirements for the pension plans. Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other pertinent calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding in recent years for Xcel Energy’s pension plans, and do not require funding in 2003. Assuming future asset return levels equal the actuarial assumption of 9.25 percent for the years 2003-2005, then under current funding regulations Xcel Energy projects that no cash funding would be required for 2004, $35 million in funding would be required for 2005, and $54 million in funding would be required for 2006. Actual performance can affect these funding requirements significantly; projected 2003 investment performance is expected to eliminate pension funding requirements for NSPW for 2004 and with assumed return levels in 2004 and 2005, could eliminate funding for 2005 and 2006, as well. Current funding regulations are under legislative review, and if not retained in their current form, could change these funding requirements materially.

In April 2003, Xcel Energy amended certain of its retirement plans to provide the same level of benefits to all non-bargaining employees of its utility and service company operations. While this change did not have a material impact on 2003 costs for the affected pension and retiree health plans, the increased obligations resulting from the plan amendment did create a minimum pension liability which was recorded in the second quarter of 2003.

Regulation — We are subject to extensive regulation by the SEC under PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain properties and intra-system sales of certain goods and services.

The rates charged to customers are approved by the FERC, the PSCW and the MPSC. The rates are generally designed to recover plant investment, operating costs and an allowed return on investment. We request changes in rates for utility services through filings with the governing commissions. Because comprehensive rate changes are requested infrequently at FERC and the MPSC, and only biennially at the PSCW, changes in operating costs can affect our financial results. Wisconsin law does not allow the use of an automatic electric fuel adjustment clause for our Wisconsin retail electric customers. Instead, the PSCW uses a procedure that compares actual monthly and anticipated annual fuel costs with the forecast of those costs that was included in our latest retail electric rate case. If the comparison results in a difference outside a prescribed range, the PSCW may hold hearings limited to fuel costs and revise retail electric rates upward or downward on a prospective basis. In addition to changes in operating costs, including changes in costs allocated under the Interchange Agreement, other factors affecting rate filings are sales growth, conservation and demand-side management efforts and the cost of capital.

Regulated public utilities are allowed to record as regulatory assets certain costs that are expected to be recovered from customers in future periods and to record as regulatory liabilities certain income items that are expected to be refunded to customers in future periods. In contrast, nonregulated enterprises would expense these costs and recognize the income in the current period. If restructuring or other changes in the regulatory environment occur, we may no longer be eligible to apply this accounting treatment, and may be required to eliminate such regulatory assets and liabilities from our balance sheet. Such changes could have a material adverse effect on our results of operations in the period the write-off is recorded.

At September 30, 2003, we reported on our balance sheet regulatory assets of approximately $47 million and regulatory liabilities of approximately $12 million that would be recognized in the statement of operations in the absence of regulation. In addition to a potential write-off of regulatory assets and liabilities, restructuring and competition may require recognition of certain stranded costs not recoverable under market pricing. We currently do not expect to write off any stranded costs unless market price levels change or cost levels increase above market price levels. See Notes 1 and 10 to the audited consolidated financial statements for further discussion of regulatory deferrals.

Environmental Matters — Capital expenditures on environmental improvements at our facilities were approximately:


	•	$1.9 million in 2003;

	•	$6.1 million in 2002;

	•	$29.0 million in 2001; and

	•	$0.0 million in 2000.

We expect to incur approximately $14.5 million during the period from 2004 through 2007. Most of the costs are related to air pollution control.

Inflation — Inflation at its current level is not expected to materially affect our prices or returns to our shareholder.

SFAS No. 150 — In May 2003, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 150 — “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS No. 150 establishes standards for classifying and measuring as liabilities certain financial instruments that embody obligations of the issuer and have characteristics of both liabilities and equity, including:


	•	instruments that represent, or are indexed to, an obligation to buy back the issuer’s shares, regardless whether the instrument is settled on a net-cash or gross physical basis;

	•	mandatorily redeemable equity instruments;

	•	written options that give the counterparty the right to require the issuer to buy back shares; and

	•	forward contracts that require the issuer to purchase shares.

In November 2003, the FASB posted a staff position, which delayed the implementation of SFAS No. 150 indefinitely.

SFAS No. 143 — We adopted Statement of Financial Accounting Standard (SFAS) No. 143 — “Accounting for Asset Retirement Obligations” (SFAS No. 143) effective January 1, 2003. As required by SFAS No. 143, future plant decommissioning obligations were recorded as a liability at fair value as of January 1, 2003, with a corresponding increase to the carrying values of the related long-lived assets. This liability will be increased over time by applying the interest method of accretion to the liability, and the capitalized costs will be depreciated over the useful life of the related long-lived assets. The adoption of the statement had no income statement impact, as the cumulative effect adjustments required under SFAS No. 143 have been deferred through the establishment of a regulatory asset pursuant to SFAS No. 71 — “Accounting for the Effects of Certain Types of Regulation.”

The adoption of SFAS No. 143 in 2003 affects accrued plant removal costs for our generation, transmission and distribution facilities. Although SFAS No. 143 does not recognize the future accrual of removal costs as a Generally Accepted Accounting Principles liability, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying

SFAS No. 145 — In April 2002, the FASB issued SFAS No. 145 — “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections,” which supersedes previous guidance for the reporting of gains and losses from extinguishment of debt and accounting for leases, among other things. We adopted SFAS No. 145 in July 2003. The impacts of SFAS No. 145 are not material to us.

SFAS No. 146 — In June 2002, the FASB issued SFAS No. 146 — “Accounting for Exit or Disposal Activities,” addressing recognition, measurement and reporting of costs associated with exit and disposal activities, including restructuring activities. The impacts of SFAS No. 146 are not expected to be material to us.

SFAS No. 149 — In April 2003, the FASB issued SFAS No. 149 — “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” which amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133. SFAS No. 149 clarifies the discussion around initial net investment, clarifies when a derivative contains a financing component and amends the definition of underlying to conform it to language used in FASB Interpretation No. 45. In addition, SFAS No. 149 also incorporates certain implementation issues of a derivative implementation group. The provisions of SFAS No. 149 are effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003.

FASB Interpretation No. 45 (FIN No. 45) — In November 2002, the FASB issued FIN No. 45 — “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” The initial recognition and measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year-end. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. The interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. The interpretation also clarifies the requirements related to the recognition of a liability by a guarantor at the inception of the guarantee for the obligations the guarantor has undertaken in issuing the guarantee.

SFAS No. 133 Implementation Issue No. C20 — In June 2003, for purposes of determining the applicability of the normal purchases and normal sales scope exception, the FASB issued SFAS No. 133 Implementation Issue No. C20 as supplemental guidance to SFAS No. 133 Implementation Issue No. C11. The effective date of the implementation guidance of Issue No. C20 for us is during the fourth quarter of 2003. We are currently in the process of reviewing and interpreting this guidance and do not anticipate any material adverse financial impact due to the implementation of Issue No. C20 guidance as a result of our ability to recover prudently-incurred purchased capacity costs from customers.

FASB Interpretation No. 46 (FIN No. 46) — In January 2003, the FASB issued FIN No. 46, requiring an enterprise’s consolidated financial statements to include subsidiaries in which the enterprise has a controlling financial interest. Historically, consolidation has been required for only subsidiaries in which an enterprise has a majority voting interest. Under FIN No. 46, an enterprise’s consolidated financial statements will include the consolidation of variable interest entities, which are entities that the enterprise has a controlling financial interest. As a result, we expect that we will be required to consolidate our affordable housing investments, which currently are accounted for under the equity method. We plan to adopt FIN No. 46 when required in the first quarter of 2004. The impact of consolidating these entities is not expected to have a material impact on net income.

Business and Operational Risk — We have limited exposure to market price risk for the purchase and sale of electric energy. Most electric generation and transmission costs for the NSP System are incurred by NSP-MN and a portion (approximately 15 percent) is allocated to NSP-W through the Interchange Agreement. Wisconsin law does not allow for the use of an automatic electric fuel adjustment clause for our Wisconsin retail electric customers. Instead, Wisconsin retail rates include a fixed price forecast of future electric fuel and purchased energy costs. Between general rate cases, the PSCW uses a procedure that compares actual monthly and anticipated annual fuel and purchased energy costs with the forecast of those costs that was included in the most recent retail electric rate case. If the comparison results in a difference outside a prescribed range, the PSCW may hold hearings limited to fuel costs and revise retail electric rates upward or downward. Any revised rates would be effective until the next fuel filing or rate case. Any adjustment approved would be calculated on an annual basis, but applied prospectively. The PSCW is not required to approve any such adjustments and may decline to do so.

Interest Rate Risk — We are exposed to fluctuations in interest rates where we enter into variable rate debt obligations to fund certain power projects being developed or purchased. Exposure to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. Our risk management policy allows us to reduce interest rate exposure from variable rate debt obligations.

However, with the exception of short-term borrowings, we do not have variable interest rates; therefore our interest rate risk is limited.

Credit Risk — In addition to the risks discussed previously, we are exposed to credit risk in our risk management activities. Credit risk relates to the risk of loss resulting from the non-performance by a counterparty of its contractual obligations. We maintain credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.

We conduct standard credit reviews for all wholesale counterparties. Xcel Energy employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. The credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

For a further discussion of derivatives, risk management and market risks, see Note 12 to the audited consolidated financial statements.

Net cash provided by operating activities decreased by $29.5 million, or 26.2%, for the first nine months of 2003, compared with the first nine months of 2002. The change was primarily due to lower net income and a decrease in working capital as a source of cash in the first nine months of 2003. Net cash provided by operating activities increased by $61.2 million, or 128.3%, for the year ended December 31, 2002, compared with the year ended December 31, 2001. The change was largely due to higher net income and a decrease in working capital as a use of cash in 2002 compared with 2001. Net cash provided by operating activities decreased by $23.4 million, or 32.9%, for the year ended December 31, 2001, compared with the year ended December 31,

Net cash used in investing activities increased by $8.5 million, or 27.6%, for the first nine months of 2003, compared with the first nine months of 2002. The change was primarily due to an increase in utility capital/construction expenditures. Net cash used in investing activities decreased by $22.4 million, or 37.3%, for the year ended December 31, 2002, compared with the year ended December 31, 2001. The change was primarily due to a decrease in utility capital/construction expenditures. Net cash used in investing activities decreased by $28.6 million, or 32.3%, for the year ended December 31, 2001, compared with the year ended December 31, 2000. The change was primarily due to a decrease in utility capital/construction expenditures.

Net cash used in financing activities decreased by $23.0 million, or 34.6%, for the first nine months of 2003, compared to the first nine months of 2002. The decrease was primarily due to lower repayments of short-term borrowings, partially offset by a larger dividend payment to our parent in 2003. We used $71.3 million of cash in financing activities in the year ended December 31, 2002, compared with cash of $12.2 million provided by financing activities in the year ended December 31, 2001, a change of 683.1%. The change was largely due to repayments of short-term borrowings and increased dividends paid to our parent in 2002. Net cash provided in financing activities decreased by $5.2 million, or 30.0%, for the year ended December 31, 2001, compared with the year ended December 31, 2000. The change was primarily due to larger dividend payments to our parent in 2001.

See the discussion of trends, commitments and uncertainties with the potential for future impact on cash flow and liquidity under Capital Sources.

Capital Expenditures — The estimated cost as of September 30, 2003 of our capital expenditure programs and other capital requirements for the years 2003, 2004 and 2005 are shown in the table below.

Our capital expenditure programs are subject to continuing review and modification. Actual utility construction expenditures may vary from the estimates due to changes in electric projected load growth, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting long-term energy needs. In addition, our need to comply with future requirements to install emission-control equipment may impact actual capital requirements.

Contractual Obligations and Other Commitments — We have a variety of contractual obligations and other commercial commitments that represent prospective requirements in addition to our capital expenditure programs. The following is a summarized table of contractual obligations as of September 30, 2003.

The amounts reflected in this table do not include our obligations under the Interchange Agreement with NSP-MN pursuant to which we share, on a proportional basis, all costs related to generation and transmission for the integrated electric system of the two companies. The Interchange Agreement costs of NSP-MN allocated to us in 2002 were $220.7 million and $80.2 million of our costs were allocated to NSP-MN for the same period. Costs allocated to us under the Interchange Agreement are used, among other things, to establish our retail rates in biennial rate proceedings before the PSCW. The Interchange Agreement can be terminated upon five years’ notice or upon mutual agreement.

Dividend Policy — Historically we have paid quarterly dividends to Xcel Energy. In 2001, 2002 and the first nine months of 2003, we have paid dividends to Xcel Energy of $32.5 million, $47.1 million and $37.4 million, respectively. The amount of dividends that we pay is dictated to some extent by the needs of Xcel Energy but is limited by restrictions imposed by state regulatory commissions, our debt agreements and the SEC under PUHCA. These restrictions include, but may not be limited to, maintenance of a minimum equity ratio of 30 percent, payment of dividends only from retained earnings and debt covenant restrictions under our credit agreement for debt and interest coverage ratios. Under our Wisconsin regulatory commitments, our ability to pay dividends is also effectively limited due to the requirement that we maintain an equity ration of between 52 percent and 57 percent of our total capitalization. As of September 30, 2003, our retained earnings were approximately $262 million and our common equity was approximately 57 percent of our total capitalization.

We expect to meet future financing requirements by periodically issuing long-term debt, short-term debt and common equity to maintain desired capitalization ratios. As a result of being a subsidiary of a registered holding company under PUHCA, we are required to maintain a common equity ratio of 30 percent or higher in our consolidated capital structure. To the extent Xcel Energy experiences constraints on available capital sources, it may limit its equity contributions to us.

Short-Term Funding Sources — We use a number of sources to fulfill short-term funding needs. Primary among these is operating cash flow, but also included are short-term borrowing arrangements such as notes payable to NSP-MN. The amount and timing of short-term funding needs depend in large part on financing needs for utility construction expenditures as discussed previously under “Capital Requirements.” We currently have regulatory authority to have $50 million of short-term borrowings outstanding, at any one time.

Operating cash flow as a source of short-term funding is reasonably likely to be affected by such operating factors as weather; regulatory requirements including rate recovery of costs, environmental regulation compliance and industry restructuring; changes in the trends for energy prices and supply; as well as operational uncertainties that are difficult to predict.

In November 2003, we entered into a “money pool” agreement with Xcel Energy and the other Xcel Energy operating utilities, subject to receipt of required regulatory approvals. The money pool agreement is more specifically described below under “Certain Relationships and Related Transactions — Money Pool Agreement.” This agreement will allow us to borrow or loan short-term funds to the pool participants at

We also have an intercompany borrowing arrangement with NSP-MN, where interest is charged at NSP-MN’s short-term borrowing rates. At September 30, 2003 and December 31, 2002 we had $0.0 and $6.9 million, respectively, in short-term borrowings outstanding. Our weighted average interest rate was 0% at September 30, 2003 and 4.4% at December 31, 2002.

Short-term borrowing as a source of short-term funding is affected by access to the capital markets on reasonable terms. Our access varies based on financial performance and existing debt levels. If current debt levels are perceived to be at or higher than standard industry levels or those levels that can be sustained by current operating performance, access to reasonable short-term borrowings could be limited. These factors are evaluated by credit rating agencies that review Xcel Energy and its subsidiary operations on an ongoing basis.

Our cost of capital and access to capital markets for both long-term and short-term funding are dependent in part on credit rating agency reviews, and with respect to our short-term borrowing arrangements with NSP-MN, are dependent on NSP-MN credit ratings and cost of capital. As discussed above under the caption “Risk Factors — Risks Related to Our Relationship to Xcel Energy,” our credit ratings were lowered in 2002, and could be further lowered in the future, reflecting pressure on our credit profile resulting from NRG’s financial position. As of September 30, 2003, the rating agencies assigned the following credit ratings:

As of September 30, 2003, we had cash and cash equivalents of approximately $0.1 million.

Financing Activities — We engaged in the following financing activities in 2003:


	•	On October 2, 2003, we issued $150 million of the original first mortgage bonds to qualified institutional buyers in a private placement not registered under the Securities Act. The debt was issued to redeem $110 million of our 7.25% first mortgage bonds due March 1, 2023 at a redemption price of 102.84 percent of the principal amount, and to repay short-term debt incurred to pay at maturity $40 million of our 5.75% first mortgage bonds due October 1, 2003.

Financing Plans — We currently plan no additional debt issuances during 2004.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

During 2000, 2001 and 2002 and the first nine months of 2003, there were no disagreements with our independent public accountants on accounting principles or practices, financial statement disclosures, or auditing scope or procedures.

On March 27, 2002, the Audit Committee of Xcel Energy’s Board of Directors recommended, and our Board of Directors approved, the decision to engage Deloitte & Touche LLP, subject to completion of their customary acceptance procedures, as our new principal independent accountants for 2002. Accordingly, on March 27, 2002, our management informed Arthur Andersen LLP that the firm would no longer be engaged as our principal independent accountants. The reports of Arthur Andersen LLP on our financial statements for the year ended December 31, 2001 or 2000 did not contain an adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope or accounting principles. Further, during 2000,

Arthur Andersen LLP furnished us with a letter addressed to the SEC stating that it agreed with the above statements.

We were incorporated in 1901 under the laws of Wisconsin as the La Crosse Gas and Electric Company. Prior to August 2000, we were a wholly-owned subsidiary of NSP. On August 18, 2000, NSP and NCE merged to form Xcel Energy, a registered holding company under PUHCA, and we became a wholly-owned subsidiary of Xcel Energy. We own three direct subsidiaries: Chippewa and Flambeau Improvement Co., which operates hydro reserves; Clearwater Investments Inc., which owns interests in affordable housing; and NSP Lands, Inc., which holds real estate. NSP-MN is a Minnesota corporation formed in 2000 that was assigned the electric and natural gas utility assets and obligations of NSP effective on the merger date, including obligations under the Interchange Agreement.

Among Xcel Energy’s other subsidiaries are NSP-MN, SPS, Cheyenne and PSCo. Prior to December 5, 2003, Xcel Energy owned all of the common stock of NRG. NRG is a global energy company, primarily engaged in the ownership and operation of power generation facilities and the sale of energy, capacity and related products. On May 14, 2003, NRG filed a voluntary petition for bankruptcy under Chapter 11 of the U.S. Bankruptcy Code. On December 5, 2003, NRG emerged from bankruptcy and Xcel Energy divested its ownership interest in NRG. On January 13, 2004, Xcel Energy announced that it had entered into an agreement with Black Hills Corp. for the sale of Cheyenne, pending regulatory approvals.

Our principal executive offices are located at 1414 W. Hamilton Ave., Eau Claire, Wisconsin 54701, and our telephone number is (715) 839-2625.

As a subsidiary of a registered holding company, we are subject to the regulatory oversight of the SEC under PUHCA. As a result, we are subject to extensive regulation by the SEC with respect to issuances and sales of securities, acquisitions and sales of certain utility properties and intra-system sales of certain goods and services. In addition, PUHCA generally limits the ability to acquire additional public utility systems and to acquire and retain businesses unrelated to utility operations.

Retail rates, services and other aspects of our operation are subject to the jurisdiction of the PSCW and the MPSC. In addition, each of the state commissions certifies the need for new generating plants and electric transmission lines of designated capacities to be located within the respective states before the facilities may be sited and built. The PSCW has a biennial base rate-filing requirement. June of each odd-numbered year, we must submit a rate filing for the two-year period beginning the following January. The filing procedure and review generally allow the PSCW sufficient time to issue an order and implement new base rates effective with the start of the test year.

We are subject to the jurisdiction of the FERC with respect to our wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce, and the Interchange Agreement.

Wisconsin law does not allow for the use of an automatic electric fuel adjustment clause for Wisconsin retail customers. Instead, the PSCW has a procedure that compares actual monthly and anticipated annual fuel costs with the forecast of those costs that was included in the latest retail electric rates. If the comparison

We have a retail material gas cost recovery mechanism in Wisconsin to recover changes in the actual cost of wholesale natural gas and transportation and storage services.

Our natural gas and retail electric rate schedules for Michigan customers include gas cost recovery factors and power supply cost recovery factors, respectively, which are based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers over the subsequent 12-month period.

FERC Order Modifying Market Based Sales Tariffs — In November 2001, the FERC issued an order under Section 206 of the Federal Power Act initiating a “generic” investigation proceeding against all jurisdictional electric suppliers making sales in interstate commerce at market-based rates. NSP-MN previously received FERC authorization to make wholesale sales at market-based rates, and has been engaged in such sales subject to a tariff on file at the FERC, with certain revenues shared through the Interchange Agreement. The order proposed that all wholesale electric sales at market-based rates conducted starting 60 days after publication of the FERC order in the Federal Register would be subject to refund conditioned on factors determined by the FERC. In December 2001, the FERC issued a supplemental order delaying the effective date of the subject to refund condition, but subject to further investigation and proceedings.

In November 2003, FERC issued a final order requiring amendments to the market-based wholesale tariffs of all FERC-jurisdictional electric utilities, including NSP-MN, to impose new market behavior rules, and requiring submission of compliance tariff amendments in December 2003. Violations of the new tariffs could result in the disgorgement of certain wholesale sales revenues or the loss of authority to make sales at market based rates. In connection with its market based rate authority, NSP-MN has an obligation to file an updated market power analysis in the first quarter of 2004.

FERC Money Pool Final Rules — In October 2003, FERC issued final rules asserting jurisdiction over “money pool” arrangements by public utilities, including such arrangements by registered holding company systems regulated by the SEC. As described elsewhere in this prospectus, we entered into a money pool agreement with Xcel Energy and the other Xcel Energy operating companies in November 2003, subject to receipt of required state regulatory approvals. The Xcel Energy money pool arrangements were filed with FERC in December 2003, as required by the final rule.

2003 General Rate Case — On June 1, 2003, we filed our required biennial rate application with the PSCW requesting no change in Wisconsin retail electric and natural gas base rates. We requested the PSCW approve its application without hearing, pending completion of the Staff’s audit. An order is expected in the beginning of 2004. In mid-December, 2003 the PSCW informed us they expect to complete their audit in mid-January, and they expect to issue an order in the first quarter of 2004. Since we did not request a rate change, this delay is will not adversely impact us.

Midwest ISO Electric Market Initiative — Pursuant to a settlement agreement in the Xcel Energy merger, we and NSP-MN agreed to join the Midwest ISO RTO. The Midwest ISO began interim operations in February 2002. On July 25, 2003, MISO filed proposed changes to its regional FERC open access transmission tariff to implement a new transmission and energy markets tariff that would establish certain wholesale energy and transmission service markets based on locational marginal cost pricing effective in 2004. After numerous protests were filed by both customers and state regulatory agencies, MISO filed to withdraw the proposed tariff change in October 2003, and the FERC approved the withdrawal. However, MISO

Generation Interconnection Rules — In August 2003, the FERC issued final rules requiring the standardization of generation interconnection procedures and agreement for interconnection of generators of 20 MW or more to the transmission systems of all FERC-jurisdictional electric utilities, including us, and establishing pricing rules for interconnections and related system upgrades. FERC required all jurisdictional utilities to submit compliance filings by January 20, 2004. Submission of the mandated changes to the Xcel Energy operating companies tariff and the Midwest ISO regional tariff, which will govern most generation interconnections to our transmission system, are pending.

FERC Standards of Conduct Rules — In December 2003, the FERC issued final standards of conduct rules affecting all FERC-jurisdictional transmission utilities, including us, which will require us to maintain greater functional separation of our electric transmission functions from the NSP-MN wholesale energy markets function and from “energy affiliates” (as defined by the final rule). Full compliance is required by June 1, 2004. Xcel Energy and other parties have requested the FERC to grant clarification or rehearing of the rules. Management has yet not estimated the cost of compliance with the new standards of conduct rules, but the cost could be material.

MISO Administrative Costs — In October 2001, the FERC issued an order (known as Opinion No. 453) in the separate proceeding to establish the initial MISO regional transmission tariff rates, ruling that all transmission services (with limited exceptions) in the MISO region must be subject to the MISO regional tariff and administrative charges (known as Schedule 10) to prevent discrimination between wholesale transmission service users. In early 2003, after the 2001 orders were remanded from the U.S. Court of Appeals for the District of Columbia, the FERC upheld its prior 2001 orders requiring members of the Midwest ISO to pay the Midwest ISO administrative charge. The annual cost to NSP-MN and us is approximately $9 million, with us bearing about 15 percent of the total through the Interchange Agreement. This FERC decision has again been appealed to a federal appeals court.

MISO Transmission Revenue Reductions — In addition, in November 2003, FERC ruled that the Midwest ISO must remove the RTOR surcharge from its transmission tariff. The RTOR charges were established in the Midwest ISO tariff to compensate member transmission owners (such as us) for a portion of the wholesale transmission service revenues lost as a result of becoming subject to the Midwest ISO tariff. Elimination of the RTOR surcharge would reduce transmission service revenues to NSP-MN and us in the long-term, but are expected to be largely offset for the next two years by revenue from partially offset by transitional rate schedules expected to be implemented in 2004.

FERC Transmission Inquiry — In 2002, the FERC began a formal, non-public inquiry relating to the treatment by public utility companies of affiliates in generator interconnection and other transmission matters. In connection with the inquiry, the FERC asked the Xcel Energy operating companies for certain information and documents. Xcel Energy and its subsidiaries, including us, are complying with the request. Approximately ten other public utilities were made the subject of similar inquiries, with the utilities, apparently, selected at random.

MISO/ PJM Interconnection “Seams” Agreement — On December 31, 2003, the Midwest ISO and the PJM Interconnection, LLC, a neighboring RTO serving portions of the eastern United States, filed a “joint operating agreement” which will govern the operational interactions at the numerous borders (or “seams”) between the two RTOs starting in 2004. Xcel Energy is studying the agreement to determine any impact on the NSP System.

Retail competition and the unbundling of regulated energy service could have a significant financial impact on us due to an impairment of assets, a loss of retail customers, lower profit margins and/or increased

Retail Business Competition — The retail electric business faces increasing competition as industrial and large commercial customers have some ability to own or operate facilities to generate their own electric energy. In addition, customers may have the option of substituting other fuels, such as natural gas for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost environment. While we face these challenges, we believe our rates are competitive with currently available alternatives. We are taking actions to lower operating costs and are working with our customers to analyze energy efficiency and load management programs in order to better position us to more effectively operate in a competitive environment.

Wholesale Business Competition — The wholesale electric business faces increasing competition in the supply of bulk power, due to federal and state initiatives to provide open access to utility transmission systems. Under current FERC rules, utilities are required to provide wholesale open-access transmission services and to unbundle wholesale merchant and transmission operations. We are operating under a joint tariff in compliance with these rules. To date, these provisions have not had a material impact on our operations.

Retail Competition and Restructuring — The structure of the electric utility industry has been subject to change. Merger and acquisition activity has been significant as utilities combine to capture economies of scale or establish a strategic niche in preparing for the future. Some regulated utilities are divesting generation or transmission assets. All FERC-jurisdictional utilities are required to provide nondiscriminatory access to the use of their transmission systems. Access to the NSP System is provided through the Midwest ISO tariff.

Some states had begun to allow retail customers to choose their electricity supplier, and many other states were considering retail competition proposals. Since January 1, 2002, we have been providing our Michigan electric customers with the opportunity to select an alternative electric energy provider. This action was required by Michigan’s “Customer Choice and Electricity Reliability Act,” which became law in June 2002. We developed and successfully implemented internal procedures, and obtained MPSC approval for these procedures to meet the January 1, 2002 deadline. Key elements of internal procedures include the development of retail open access tariffs and unbundled billing, environmental and fuel disclosure information, and a code of conduct compliance plan. At this time, however, there are no retail customers taking service from an alternative supplier.

However, the experience of the State of California in instituting competition, as well as the bankruptcy of Enron Corp. in 2001, have caused indefinite delays in retail competition in Wisconsin.

We cannot predict the outcome of retail competition proceedings in the jurisdictions we serve at this time. The resolution of these matters may have a significant impact on our financial position, results of operations and cash flows.

Start of MISO Operations — In compliance with a condition in the January 2000 FERC order approving the Merger, we and NSP-MN entered into agreements to join the MISO in August 2000. In December 2000, the FERC approved the MISO as the first approved regional transmission organization (“RTO”) in the U.S., pursuant to FERC Order 2000. On February 1, 2002, the MISO began interim operations, including regional transmission tariff administration services for the NSP System. We and NSP-MN have received all required regulatory approvals to transfer functional control of our high voltage (100 kV and above) transmission systems to the MISO when the MISO is fully operational. The MISO will then control the operations of these facilities and the facilities of neighboring electric utilities.

TRANSLink Transmission Company LLC — In September 2001, Xcel Energy’s operating companies joined a proposal with several other electric utilities in the U.S. mid-continent region to form TRANSLink Transmission Company LLC (“TRANSLink”), an independent transmission company (“ITC”) which would own and/or operate electric high voltage transmission facilities within a FERC-approved regional

In April 2002, the FERC gave conditional approval for the applicants to transfer ownership or operations of their transmission systems to TRANSLink and to form TRANSLink as an ITC operating under the umbrella RTO organization of MISO, subject to several conditions.

Several state approvals also would be required to implement the proposal, and the proposal would require SEC approval. State applications were made in late 2002 and early 2003. In November 2002, we filed for PSCW approval to transfer functional control of our electric transmission system to TRANSLink, but the application was never approved. In June 2003, the Minnesota Public Utilities Commission (“MPUC”) held a hearing on the NSP-MN TRANSLink application, filed in December 2002. At the hearing, the MPUC deferred any decision. Instead, the MPUC indicated NSP-MN could submit a supplemental or revised application to explain certain recent changes to the proposal and to respond to a number of issues and questions posed by the MPUC advisory staff and other parties. A similar filing in North Dakota was not contested, but was also not approved.

On November 21, 2003, the TRANSLink participants including Xcel Energy announced the formation of TRANSLink had been suspended. On November 24, 2003, we withdrew our request for associated regulatory approvals from the PSCW. As of September 30, 2003, Xcel Energy had incurred and deferred approximately $5 million of TRANSLink-related costs based on anticipated allocation to and recovery from participating operating utilities in future rates. None of these costs had been allocated to us or other regulatory jurisdictions at that date, pending resolution of TRANSLink operating uncertainties. Consequently, it is not determinable at this time how much, if any, costs will ultimately be allocated to us or recovered from our ratepayers.

Standard Market Design Rulemaking — In July 2002, the FERC issued a Notice of Proposed Rulemaking on Standard Market Design (“SMD”) rulemaking for regulated utilities. If implemented as proposed, the rulemaking will substantially change how wholesale markets operate throughout the United States. The proposal expands the FERC’s intent to unbundle transmission operations from integrated utilities and ensure robust competition in wholesale markets. The rule contemplates that all wholesale and retail customers will be on a single network transmission service tariff. The rule also contemplates the implementation of a bid-based system for buying and selling energy in wholesale markets. The market will be administered by RTOs or Independent Transmission Providers. RTOs will also be responsible for putting together regional plans that identify opportunities to construct new transmission, generation or demand side programs to reduce transmission constraints and meet regional energy requirements. Finally, the rule envisions the development of Regional Market Monitors responsible for ensuring that individual participants do not exercise unlawful market power. Comments to the rules were filed in the fourth quarter of 2002, and replies and further comment were filed in the first quarter of 2003. In April 2003, the FERC issued a “whitepaper” describing proposed changes to the proposed SMD rules based on public comments. Pending legislation in Congress would forbid the FERC from implementing the SMD rules for several years, but that legislation has not been adopted. However, for the NSP System, the MISO RTO separately proposed in July 2003 to implement a market design similar to the one proposed by the FERC rules. As noted above, the July 2003 MISO filing was withdrawn, but MISO intends to file a new energy markets tariff in first quarter 2004 to be effective in late 2004.

Wisconsin Restructuring — The State of Wisconsin continued its incremental approach to industry restructuring by passing legislation in 2001 that reduced the wholesale gross receipts tax on the sale of electricity by 50 percent starting in 2003. This legislation eliminates the double taxation on wholesale sales from non-utility generators, and should encourage the development of merchant plants by making sales from independent power producers more competitive. Additional legislation was passed that enables regulated utilities to enter into leased generation contracts with unregulated generation affiliates. The new legislation provides utilities a new financing mechanism and option to meet their customers’ energy needs. In 2002, the PSCW approved the first power plant proposal utilizing the new leased generation contract arrangement.

Michigan Restructuring — As indicated above, since January 1, 2002, we have been providing our Michigan electric customers with the opportunity to select an alternative electric energy provider. However, no retail customers are purchasing electric supply services from an alternative supplier.

Our electric production and transmission system and the electric production and transmission system of NSP-MN are managed as an integrated system (referred to as the NSP System). The system peak demand for each of the last three years and the forecast for 2004, assuming normal weather during the remainder of 2004, for our system peak demand and the net dependable system capacity are projected below:

The NSP-System peak demand typically occurs in the summer. During 2003, the peak demand for the NSP-System was 7,760 megawatts which occurred on June 24, 2003. The 2002 NSP-System peak demand occurred on July 30, 2002.

We expect to use the following resources to meet our net dependable system capacity requirements:


	•	NSP System generating stations;

	•	NSP-MN purchases from other utilities, independent power producers and power marketers and delivered to us under the Interchange Agreement;

	•	demand-side management options; and

	•	phased expansion of existing generation at select NSP System power plants.

We do not directly purchase power, but rather share in power purchased by NSP-MN pursuant to the Interchange Agreement.

NSP-MN has contractual arrangements to purchase power from other utilities and nonregulated energy suppliers. Capacity, typically measured in kilowatts or megawatts, is the measure of the rate at which a particular generating source produces electricity. Energy, typically measured in kilowatt-hours or megawatt-hours, is a measure of the amount of electricity produced from a particular generating source over a period of time. Purchase power contracts typically require a periodic payment to secure the capacity from a particular generating source and a charge for the associated energy actually purchased from that generating source.

NSP-MN also makes short-term and non-firm purchases to replace generation from company NSP System units that are unavailable due to maintenance and unplanned outages, to provide our reserve obligation, to obtain energy at a lower cost than that which could be produced by other resource options, including NSP System generation and/or long-term purchase power contracts, and for various other operating requirements.

Our electric production and transmission system is managed on an integrated basis with the electric production and transmission system of NSP-MN under the Interchange Agreement. Pursuant to the

In December 2002, NSP-MN filed its Resource Plan with the MPUC for 2003 to 2017. The plan describes how we intend to meet the energy needs of the NSP System. The plan contains conservation programs to reduce the NSP System’s peak demand and conserve overall electricity use, an approximate schedule of power purchase solicitations to meet increasing demand, and programs and plans to maintain the reliable operations of existing resources. Critical to NSP-MN’s Resource Plan is the role nuclear power at the NSP-MN Prairie Island and Monticello plants will play in future years. Last spring, the MPUC suspended the Resource Plan proceeding while the issue of spent nuclear fuel storage and continued operation of NSP-MN’s nuclear plants was taken up by the Minnesota Legislature. In May 2003, the Minnesota Legislature and Governor authorized additional spent fuel storage so that the Prairie Island plant can operate until its federal licenses expire in 2013 and 2014. The act also provides a process in which the MPUC can determine if it is in the state’s interest to allow the plants to operate beyond their current licensed life. On September 10, 2003, NSP-MN provided the MPUC with a Resource Plan update and requested permission to refile a new plan in the fall of 2004 due to the legislative changes and the passage of time. The request is pending.

NSP-MN has contractual arrangements with regional transmission service providers to deliver power and energy to our native load customers (retail and wholesale load obligations with terms of more than one year). Point-to-point transmission services typically include a charge for the specific amount of transmission capacity being reserved, although some agreements may base charges on the amount of metered energy delivered. Network transmission services include a charge for the metered demand at the delivery point at the time of the provider’s monthly transmission system peak, usually calculated as a 12-month rolling average.

The following tables present the delivered cost per million British thermal units (“MMBtu”) of each significant category of fuel consumed for electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels during such years for the NSP System. Fuel costs are allocated between NSP-MN and us through the Interchange Agreement:

NSP-MN normally maintains between 30 and 45 days of coal inventory at each plant site. Estimated coal requirements at NSP-MN’s major coal-fired generating plants are approximately 12 million tons per year. NSP-MN has long-term contracts providing for the delivery of up to 100 percent of 2003 coal requirements and up to 95 percent of their 2004 requirements. Coal delivery may be subject to short-term interruptions or reductions due to transportation problems, weather and availability of equipment. (As shown below in the description of Properties, our only generating unit with coal burning capability is Bayfront, which also burns other fuels.)

All of the coal we and NSP-MN burn has a sulfur content of less than 1 percent. NSP-MN has contracts for a minimum of 31.0 million tons of low-sulfur coal for the next four years. The contracts are with a Montana coal supplier and three Wyoming suppliers with expiration dates ranging between 2004 and 2007. If

We and NSP-MN use both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Our and NSP-MN’s current fuel oil inventory is adequate to meet anticipated requirements for 2004, and NSP-MN also has access to the spot market to buy more oil as needed. Natural gas supplies and interstate pipeline transportation services for power plants are procured under short- and intermediate-term contracts to provide an adequate supply of fuel.

To operate its nuclear generating plants, NSP-MN secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication. The contract strategy involves a portfolio of spot purchases and medium- and long-term contracts for uranium, conversion and enrichment. Current contracts are flexible and cover 100 percent of uranium, conversion and enrichment requirements through the year 2005. These contracts expire at varying times between 2004 and 2006. The overlapping nature of contract commitments will allow NSP-MN to maintain 50 percent to 100 percent coverage beyond 2003. NSP-MN expects sufficient uranium, conversion and enrichment to be available for the total fuel requirements of its nuclear generating plants. Fuel fabrication is 100 percent committed through 2004 and 30 percent committed through 2010.

NSP-MN owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. Monticello began operation in 1971 and is licensed to operate until 2010. Prairie Island units 1 and 2 began operation in 1973 and 1974 and are licensed to operate until 2013 and 2014, respectively. Nuclear power plant operation produces gaseous, liquid and solid radioactive wastes. The discharge and handling of such wastes are controlled by federal regulation. High-level radioactive waste includes used nuclear fuel. Low-level radioactive waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in the plant.

Federal law places responsibility on each state for disposal of its low-level radioactive waste. Low-level radioactive waste from NSP-MN’s Monticello and Prairie Island nuclear plants is currently disposed of at the Barnwell facility, located in South Carolina (all classes of low-level waste), and the Clive facility, located in Utah (class A low-level waste only). Chem Nuclear is the owner and operator of the Barnwell facility, which has been given authorization by South Carolina to accept low-level radioactive waste from out of state. Envirocare, Inc. operates the Clive facility. NSP-MN and Barnwell currently operate under an annual contract, while NSP-MN uses the Envirocare facility through various low-level waste processors. NSP-MN has low-level storage capacity available on-site at Prairie Island and Monticello that would allow both plants to continue to operate until the end of their licensed lives if off-site low-level disposal facilities were not available to NSP-MN.

The federal government has the responsibility to dispose of, or permanently store, domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the United States Department of Energy (“DOE”) to implement a program for nuclear waste management. This includes the siting, licensing, construction and operation of a repository for domestically produced spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent storage or disposal facility by 1998. None of NSP-MN’s spent nuclear fuel has yet been accepted by the DOE for disposal. See “— Legal Proceedings” and Note 19 to the audited consolidated financial statements for further discussion of this matter.

NSP-MN has on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear plants. The Prairie Island plant is licensed by the federal NRC to store up to 48 casks of spent fuel at the plant. In 1994, the Minnesota Legislature adopted a limit on dry cask storage of 17 casks for the entire state. The 17 casks, which stand outside the Prairie Island plant, are now full, and under the current configuration the storage pool within the plant would be full by 2007.

As discussed above, in May 2003, the Minnesota Legislature enacted legislation which will enable NSP-MN to store at least 12 more casks of spent fuel outside the Prairie Island plant, allowing spent-fuel storage there until our licenses with the NRC expire in 2013 and 2014. The legislation transfers from the Minnesota Legislature to the MPUC the primary authority concerning future spent-fuel storage issues and allows for the extension of the NRC licenses of the Prairie Island and the Monticello nuclear generating plants without an affirmative vote from the Minnesota Legislature. The legislation requires NSP-MN to add at least 300 megawatts of additional wind power by 2010 with an option to own 100 megawatts of this power.

The legislation also requires specified levels of payments to various third parties during the remaining operating life of the Prairie Island plant. These payments include: $2.25 million per year to the Prairie Island Tribal Community beginning in 2004; 5 percent of NSP-MN’s conservation program expenditures (estimated at $2 million per year) to the University of Minnesota for renewable energy research; and an increase in funding commitments to the previously-established Renewable Development Fund from $500,000 per installed cask per year to a total of $16 million per year beginning in 2003. The legislation also designated $10 million in one-time grants to the University of Minnesota for additional renewable energy research, which is to be funded from commitments already made to the Renewable Development Fund. Funding commitments to the Renewable Development Fund would terminate after the Prairie Island plant discontinues operation unless the MPUC determines that NSP-MN failed to make a good faith effort to move the waste, in which case NSP-MN would have to make payments in the amount of $7.5 million per year.

Nearly all of the cost increases to NSP-MN from these required payments and funding commitments are expected to be recoverable in customer rates, mainly through cost recovery mechanisms. NSP-MN currently has petitions pending with the MPUC requesting that payments to the Prairie Island Tribal Community and all Renewable Development Fund research and development projects and projects required to be located in Minnesota be recovered solely from State of Minnesota electric retail customers. These petitions also request that costs associated with Renewable Development Fund projects resulting in the generation of electricity with no requirement to be located in Minnesota continue to be shared with us through the Interchange Agreement.

NSP-MN is part of a consortium of private parties working to establish a private facility for interim storage of spent nuclear fuel. In 1997, Private Fuel Storage, LLC (“PFS”) filed a license application with the NRC for a temporary storage site for spent nuclear fuel on the Skull Valley Indian Reservation in Utah. The NRC license review process includes formal evidentiary hearings before an Atomic Safety and Licensing Board (the “ASLB”) and opportunities for public input. Evidentiary hearings were held in 2000 and 2002, Most of the issues raised by opponents of the project have been favorably resolved or dismissed. On March 10, 2003, the ASLB ruled that the likelihood of certain aircraft crashes into the proposed facility was sufficiently credible that it would have to be addressed before the facility could be licensed and set forth a potential process for addressing this concern. PFS is currently evaluating this decision and awaiting ASLB decisions on the remaining five major issues expected in a few weeks. Due to uncertainty regarding NRC and other regulatory and governmental approvals, it is possible that this interim storage may be delayed or not available at all.

In February 2001, NSP-MN signed a contract with Steam Generating Team Ltd. to perform engineering and construction services for the installation of replacement steam generators at the Prairie Island nuclear power plant. NSP-MN is evaluating the economics of replacing two steam generators on unit 1 at the plant. NSP-MN is taking steps to preserve the replacement option for as early as 2004. The total cost of replacing the steam generators is estimated to be approximately $132 million.

The NRC is engaged in various ongoing studies and rulemaking activities that may impose additional requirements upon commercial nuclear power plants. Management is unable to predict any new requirements or their impact on NSP-MN’s facilities and on our and NSP-MN’s operations. As discussed above, a portion of all costs associated with NSP-MN nuclear generation are allocated to us through the Interchange Agreement.

In the early 1990’s, the FERC issued Order No. 636, which mandated the unbundling of interstate natural gas pipeline services — sales, transportation, storage and ancillary services. The implementation of Order No. 636 has resulted in additional competitive pressure on all local distribution companies (“LDC”) to keep gas supply and transmission prices for their large customers competitive. Customers have greater ability to buy gas directly from suppliers and arrange their own pipeline and LDC transportation service. Changes in regulatory policies and market forces have shifted the industry from traditional bundled gas sales service to an unbundled transportation and market based commodity service.

The natural gas delivery or transportation business has remained competitive as industrial and large commercial customers have the ability to bypass the local gas utility through the construction of interconnec-

As an LDC, we provide unbundled transportation service to large customers. Transportation service does not have an adverse effect on earnings because the sales and transportation rates have been designed to make them economically indifferent to whether gas has been sold and transported or merely transported. However, some transportation customers may have greater opportunities or incentives to physically bypass the LDCs distribution system.

We categorize our gas supply requirements as firm or interruptible (customers with an alternate energy supply). The maximum daily sendout (firm and interruptible) for our distribution system was 121,227 MMBtu for 2002, which occurred on March 3, 2002, and 134,109 MMBtu for 2003, which occurred on January 22, 2003.

We purchase natural gas for our LDC system from independent suppliers. The gas is delivered under gas transportation agreements with interstate pipelines regulated by FERC. These agreements provide for firm deliverable pipeline capacity of approximately 114,000 MMBtu/day. In addition, we have contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 19 percent of winter season and 31 percent of our peak daily firm retail customer requirements.

We also own and operate one liquefied natural gas (“LNG”) plant with a storage capacity of 0.27 Billion cubic feet (“Bcf”) equivalent and one propane-air plant with a storage capacity of 0.13 Bcf equivalent to help meet our peak retail customer requirements. These peak-shaving facilities have production capacity equivalent to 18,408 MMBtu of natural gas per day, or approximately 14 percent of peak day firm requirements. The LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the “needle peaks” caused by firm space heating demand on extremely cold winter days and can be used to minimize daily imbalance fees on interstate pipelines.

We are required to file for PSCW approval of our gas supply and transportation contract levels to meet peak demand, to redistribute demand costs among classes, or exchange one form of demand for another. Our winter 2002-2003 supply plan was approved by the PSCW in October 2002. Our winter 2003-2004 supply plan is pending PSCW approval.

We actively seek gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk, and economical rates. This diversification involves numerous domestic and Canadian supply sources, with varied contract lengths.

The following table summarizes the average cost per MMBtu of gas purchased for resale by our regulated retail gas distribution business:

The cost of natural gas supply, pipeline transportation service and storage service is recovered through various cost recovery adjustment mechanisms in Wisconsin and Michigan.

We have firm gas transportation contracts with several interstate pipelines, which expire at various times through 2014. Approximately 55 percent of our retail gas customers are served from the Northern Natural Gas pipeline system, and 40 percent are served from the Viking Gas Transmission Company system. In 2003, we entered into a capacity release agreement whereby NSP-MN assigned 3,107 MMBtu/day of firm transportation capacity on the Viking Gas system, purchased to serve an NSP-MN generating plant in the Twin Cities,

We have certain gas supply and transportation agreements that include obligations for the purchase and/or delivery of specified volumes of gas or to make payments in lieu of delivery. At September 30, 2003, we were committed to approximately $93 million in such obligations under these contracts, which expire at various times from the remainder of 2003 through 2013.

We purchase firm gas supply utilizing long-term and short-term agreements from approximately 30 domestic and Canadian suppliers under contracts. This diversity of suppliers and contract lengths allows us to maintain competition from suppliers and minimize supply costs.

Certain of our facilities are regulated by federal and state environmental agencies. These agencies have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances.

Ashland MGP Site — we were named as one of three primary responsible parties for creosote and coal tar contamination at a site in Ashland, Wisconsin. The Ashland site includes property owned by us and two other properties: an adjacent city lakeshore park area and a small area of Lake Superior’s Chequemegon Bay adjoining the park.

The Wisconsin Department of Natural Resources (WDNR) and we have each developed several estimates of the ultimate cost to remediate the Ashland site. The estimates vary significantly, between $4 million and $93 million, because different methods of remediation and different results are assumed in each. The Environmental Protection Agency (EPA) and WDNR have not yet selected the method of remediation to use at the site. Until the EPA and the WDNR select a remediation strategy for all operable units at the site and determine the level of responsibility of each primary responsible party, we are not able to accurately determine our share of the ultimate cost of remediating the Ashland site.

In the interim, we have recorded a liability for an estimate of our share of the cost of remediating the portion of the Ashland site that we own, estimated using information available to date and using reasonably effective remedial methods. We have deferred, as a regulatory asset, the remediation costs accrued for the Ashland site because we expect that the (PSCW) will continue to allow us to recover payments for environmental remediation from our customers. The PSCW has consistently authorized recovery in our rates of all remediation costs incurred at the Ashland site, and has authorized recovery of similar remediation costs for other Wisconsin utilities.

On September 5, 2002, the Ashland site was placed on the National Priorities List (NPL). The NPL is intended primarily to guide the EPA in determining which sites require further investigation. Resolution of Ashland remediation issues is not expected until 2004 or 2005.

On August 5, 2003, EPA issued to us a general notice of liability letter for the Ashland Site. EPA further notified us that it would enter into formal negotiations for the purpose of allowing us to take over the completion of the remedial investigation/feasibility study (“RI/ FS”) being conducted at the site. On August 26, 2003, we responded to EPA’s general notice of liability and committed to complete the RI/ FS subject to an Administrative Order on Consent (“AOC”) document to be negotiated among the parties. We entered into the AOC and Scope of Work (“SOW”) with EPA, effective November 14, 2003. It is expected to cost approximately $1.5 million to complete the RI/ FS activities required by the AOC. We must also pay USEPA’s costs of oversight of this work.

We continue to work with the WDNR to access state and federal funds to apply to the ultimate remediation cost of the entire site.

We strive to comply with all environmental regulations applicable to our operations. However, it is not possible at this time to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or, generally, what effect future laws or regulations may have upon our operations. For more information on environmental contingencies, see Note 13 to the audited consolidated financial statements, Note 4 to the interim consolidated financial statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Factors Affecting Results of Operations — Environmental Matters.”

For a discussion of expected capital expenditures and funding sources, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Listed below are our interests in electricity utility generating stations as of December 31, 2002:

Listed below are electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at December 31, 2003:

We had 205 electric utility transmission and distribution substations at December 31, 2002 and 206 electric utility transmission and distribution substations at December 31, 2003.

We had 1,929 miles of gas utility distribution at December 31, 2002 and 1,967 miles at December 31, 2003.

We had 588 employees at December 31, 2003. Of those employees, 459, or 78.06 percent, are covered under collective bargaining agreements. In addition, employees of Xcel Energy’s subsidiary service company, Xcel Services, provide services to us.

In the normal course of business, various lawsuits and claims have arisen against us. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters.

On November 13, 2001, Ralph Schmidt, Karline Schmidt, August C. Heeg Jr., and Joanne Heeg filed a complaint in Clark County, Wisconsin against Xcel Services. We were subsequently substituted for Xcel Services as the proper party defendant. In late 2003, pursuant to court order, plaintiffs filed amended complaints separating the claims of the Heegs and the Schmidts into two separate lawsuits. Both complaints allege that electricity supply by us harmed plaintiffs’ dairy herds resulting in decreased milk production, lost profits and income, and property damage. The complaints sound in negligence, strict products liability and nuisance. The Heeg plaintiffs allege compensatory damages of $1.9 million and pre-verdict interest of $6.1 million, for total damages of $8 million. The Schmidt plaintiffs allege compensatory damages of $1 million and pre-verdict interest of $1.2 million, for total damages of $2.2 million. In addition, plaintiffs allege entitlement to treble and punitive damages. A final pretrial in Heeg has been scheduled for December 17, 2004, at which time a trial date will be selected. A final pretrial in Schmidt has been scheduled for April 1, 2005, at which time a trial date will be selected.

On March 1, 2002, we were served with a lawsuit commenced by James and Grace Gumz and Michael and Susan Gumz in Marathon County Circuit Court, Wisconsin, alleging that electricity supplied by us harmed their dairy herd and caused them personal injury. The Gumz’s complaint alleges negligence, strict liability, nuisance, trespass, and statutory violations. Plaintiffs allege compensatory damages of $1.7 million and pre-verdict interest of $1.8 million for total damages of $3.5 million. In addition, plaintiffs allege entitlement to treble and punitive damages. Trial has been adjourned to September 7-21, 2004.

On July 28, 2003, James and Elaine Nigon, defendants in a real estate misrepresentation suit commenced in Clark County Circuit Court by Dennis and Kathy Weber, served us with a third-party summons and complaint. The Webers purchased a dairy farm from the Nigons in June 2000, and allege that the Nigons misrepresented the existence of stray voltage problems at the farm. The Nigons have joined us as a third-party defendant, alleging that if they are liable to plaintiffs, it is as a result of their reliance on our representations

On January 16, 2003, we were served with a lawsuit commenced by George and Diane Grosjean in the Circuit Court for Ashland County, Wisconsin. Mr. Grosjean alleges that in connection with his employment for the City of Ashland he was exposed to toxic wastes generated by us and that such exposure resulted in personal injury. The complaint is based on nuisance and negligence and seeks an unspecified amount of damages. Trial is set for October 18-29, 2004 in Ashland, Wisconsin.

French Island — Our French Island plant generates electricity by burning a mixture of wood waste and refuse derived fuel. The fuel is derived from municipal solid waste furnished under a contract with La Crosse County, Wisconsin. In October 2000, the EPA reversed a prior decision and found that the plant was subject to the federal large combustor regulations. Those regulations became effective on December 19, 2000. We did not have adequate time to install the emission controls necessary to come into compliance with the large combustor regulations by the compliance date. As a result, on March 29, 2001, the EPA issued a finding of violation to NSP-Wisconsin. On April 2, 2001, a conservation group sent us a notice of intent to sue under the citizen suit provisions of the Clean Air Act. On October 20, 2003, the U.S. District Court entered a consent decree settling the EPA’s claims against us related to the French Island plant. Pursuant to the terms of that consent decree, the company paid a penalty of $500,000. Under the consent decree, the court retains jurisdiction over the plant for several years to monitor compliance with the emission limits and other requirements contained in the decree.

On August 15, 2001, we received a Certificate of Authority to install control equipment necessary to bring the French Island plant into compliance with the large combustor regulations. We began construction of the new air quality equipment on October 1, 2001. We have reached an agreement with La Crosse County through which La Crosse County will pay for the extra emissions equipment required to comply with the EPA regulation. Installation of the control equipment has been completed and source tests confirm that the plant is now in compliance with the state and federal dioxin standards.

On July 27, 2001, the State of Wisconsin filed a lawsuit against us in the Wisconsin Circuit Court for La Crosse County, contending that we exceeded dioxin emission limits on numerous occasions between July 1995 and December 2000 at French Island. On September 3, 2002, the Wisconsin Circuit Court approved a settlement between us and the state of Wisconsin. Under terms of that settlement, we paid a penalty of approximately $168,000 and agreed to contribute $300,000 in installments through 2005 to help fund a household hazardous waste project in the LaCrosse area.

For a discussion of other legal claims and environmental proceedings, see Note 13 to the audited consolidated financial statements and Note 4 to the interim consolidated financial statements. For a discussion of proceedings involving utility rates, see “Business — Pending Regulatory Matters.”

A majority of the members of our Board of Directors and many of our executive officers are also executive officers of Xcel Energy. The following table sets forth certain information about our directors and executive officers as of January 19, 2004.


†	Mr. Ripka resigned as Vice President and Controller of NSP-W effective January 19, 2004.


††	Ms. Madden was appointed as Vice President and Controller of NSP-W effective January 19, 2004.

Michael L. Swenson is President, Chief Executive Officer and a Director of NSP-W. He has served as President, Chief Executive Officer and Director of NSP-W since February, 2002. Previously, Mr. Swenson served as Vice President, North and South Dakota from May 2000 until January 2002. From 1995 through May 2000, Mr. Swenson was a manager of Xcel Energy’s gas operations. Mr. Swenson also serves as a director of NSP-W’s subsidiaries, Chippewa Flambeau Improvement Company, where he also serves as President; Clearwater Investments, Inc., where he also serves as President; and NSP Lands. Mr. Swenson has been a director on each of the before mentioned boards since 2002.

Wayne H. Brunetti has been Chairman of NSP-W since August 2000. Mr. Brunetti also serves as Chairman and Chief Executive Officer of Xcel Energy. He has served as Chairman of Xcel Energy since August 18, 2001 and as Chief Executive Officer of Xcel Energy from the completion of its merger that formed Xcel Energy (the “Merger”) on August 18, 2000. From the completion of the Merger until October 2003, Mr. Brunetti also served as President of Xcel Energy. Mr. Brunetti has been a Director of Xcel Energy since 2000. From March 1, 2000 until the completion of the Merger, he served as Chairman, President and Chief Executive Officer of NCE and as a director and officer of several of NCE’s subsidiaries. From August 1997 until March 1, 2000, Mr. Brunetti was Vice Chairman, President and Chief Operating Officer of NCE. Before the merger of PSCo and SPS to form NCE, Mr. Brunetti was President and CEO of PSCo. He joined PSCo in July 1994 as President and Chief Operating Officer. In January 1996, he added the title of CEO. Mr. Brunetti is the former President and CEO of Management Systems International, a Florida management consulting firm that he founded in 1991. Prior to that, he was Executive Vice President of Florida Power & Light Company. Mr. Brunetti has been active in various professional and civic groups. He currently serves as a Chairman of Edison Electric Institute and serves on its board, executive committee, policy committee on energy services and policy committee on energy supply. He serves on the boards of Medic Alert Foundation, Capital City Partnership and the Minnesota Orchestra. He is past Chairman of the 2000 Mile High United

Way campaign, past Chairman of the board of the Colorado Association of Commerce and Industry and served on the Colorado Association of Commerce and Industry and served on the Colorado Renewable Energy Task Force, an appointment made by Governor Roy Romer. He is the author of Achieving Total Quality in Integrated Business Strategy & Customer Needs. Mr. Brunetti holds a bachelor of science degree in business administration from the University of Florida. He is a graduate of the Harvard Business School’s Program for Management Development. Mr. Brunetti is also Chairman of NSP-MN, SPS and PSCo. Mr. Brunetti was also the Chairman and Chief Executive Officer of NRG from June 6, 2002 until May 14, 2003 and a Director of NRG from June 2000 until May 14, 2003. In May 2003, NRG and certain of NRG’s affiliates filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code to restructure their debt. NRG emerged from bankruptcy on December 5, 2003.

Gary R. Johnson has been a Vice President and General Counsel of NSP-W since August 2000 and a Director of NSP-W since August 2002. Mr. Johnson has also served as Vice President and General Counsel of Xcel Energy since August 2000. Previously, Mr. Johnson served as Vice President and General Counsel of NSP from 1991. Mr. Johnson is also a Director of NSP-MN, SPS and PSCo. Mr. Johnson was a Director of NRG from 1993 until May 14, 2003. In May 2003, NRG and certain of NRG’s affiliates filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code to restructure their debt. NRG emerged from bankruptcy on December 5, 2003.

Benjamin G.S. Fowke, III has been Chief Financial Officer of NSP-W since October 2003 and Vice President and Treasurer of NSP-W since November 2002. Mr. Fowke has also served as Chief Financial Officer of Xcel Energy since October 2003 and Vice President and Treasurer of Xcel Energy since November 2002. Previously, Mr. Fowke served as Vice President and Chief Financial Officer of Xcel Energy’s commodity trading and marketing business unit from 2000. He was Vice President of Retail Services and Energy Markets at NCE from January 1999 to July 2000 and Vice President-Finance/ Accounting at e prime, Inc., a subsidiary of Xcel Energy, from May 1997 to December 1998.

David E. Ripka has been Vice President and Controller of NSP-W from August 2000 through January 19, 2004. Mr. Ripka has also served as Vice President and Controller of Xcel Energy from August 2000 through January 19, 2004. Previously, Mr. Ripka served as Vice President and Controller of NRG from June 1999 to August 2000, Controller of NRG from March 1997 to June 1999 and Assistant Controller for NSP from June 1992 to March 1997.

Teresa S. Madden has been named Vice President and Controller of NSP-W and Xcel Energy effective as of January 19, 2004. Previously, Ms. Madden served as Vice President Finance — Customer and Field Operations of Xcel Energy since August 2003. Prior thereto, Ms. Madden served as Interim Chief Financial Officer of Rogue Wave Software, Inc. from February 2003 through July 2003 and prior thereto as Corporate Controller from October 2000 through February 2003. Prior to her employment with Rogue Wave Software, Inc., Ms. Madden served as Corporate Controller and as Corporate Secretary of NCE from 1997 through September 2000 and May 1998, respectively.

Richard C. Kelly has been a Director of NSP-W since August 2000 and a Vice President since August 2002. Mr. Kelly has also served as President and Chief Operating Officer of Xcel Energy since October 2003. Previously, Mr. Kelly was Vice President and Chief Financial Officer of Xcel Energy from August 2002 to October 2003 and President — Enterprises of Xcel Energy from August 2000 to August 2002. Mr. Kelly also served as Executive Vice President and Chief Financial Officer for NCE from 1997 to August 2000 and Senior Vice President of PSCo from 1990 to 1997. Mr. Kelly is also a Director of NSP-MN, SPS and PSCo. Mr. Kelly was also the President and Chief Operating Officer of NRG from June 6, 2002 until May 14, 2003 and a Director of NRG from June 2000 until May 14, 2003. In May 2003, NRG and certain of NRG’s affiliates filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code to restructure their debt. NRG emerged from bankruptcy on December 5, 2003.

Cathy J. Hart has been Vice President and Corporate Secretary of NSP-W and of Xcel Energy since August 2000. Previously, Ms. Hart served as Secretary of NCE from 1998 and as Manager of Corporate Communications of PSCo from 1993 to 1996. For family reasons, Ms. Hart resigned as Manager of Corporate

Paul J. Bonavia has been a Vice President of NSP-W since August 2000 and has been President — Commercial Enterprises of Xcel Energy since December 2003. Previously, Mr. Bonavia served as President — Energy Markets of Xcel Energy from August 2000 to December 2003 and as Senior Vice President and General Counsel of NCE from 1997.

Cynthia L. Lesher has been a Vice President of NSP-W since May 2001 and the Chief Administrative Officer of Xcel Energy since August 2000. She has also been Chief Human Resources Officer of Xcel Energy since July 2001. Previously, Ms. Lesher served as President of NSP-Gas from July 1997 and previously Vice President — Human Resources of NSP.

Raymond E. Gogel has been Vice President of NSP-W since April 2002 and a Vice President and Chief Information Officer of Xcel Energy since April 2002. Previously, Mr. Gogel was Vice President and Senior Client Services Principal for IBM Global Services since June 2001 and Senior Project Executive for IBM’s Global Services since January 1998.

Patricia K. Vincent has been a Vice President of NSP-W since December 2000 and the President — Energy Customer and Field Operations of Xcel Energy since July 2003. Previously, Ms. Vincent served as President — Retail Services of Xcel Energy from March 2001 to July 2003, Vice President of Marketing and Sales of Xcel Energy from August 2000 to March 2001, Vice President of Marketing & Sales of NCE from January 1999 to August 2000 and Manager, Director and Vice President of Marketing and Sales at Arizona Public Service Company from 1992 to January 1999.

David M. Wilks has been a Vice President of NSP-W since August 2000 and the President — Energy Supply of Xcel Energy since August 2000. Previously, Mr. Wilks served as Executive Vice President and Director of PSCo from 1997 to August 2000, President of Delivery and Director of New Century Services from 1997 to August 2000 and President, Chief Operating Officer and Director of SPS from 1995 to August 2000.

The Board had no Committees during 2003. During 2003 the Board met one time on June 12, 2003 at the annual shareholder and board meeting. Three directors attended the annual shareholder and board meeting and one director was absent.

Each of our directors is employed by Xcel Services or us. None of our directors receive any compensation for his Board activities.

All of our outstanding common stock is owned by Xcel Energy. The following table sets forth information concerning beneficial ownership of Xcel Energy common stock as of December 31, 2003 for: (a) each director of NSP-W; (b) the Named Executive Officers set forth in the Summary Compensation Table; and (c) the directors and executive officers of NSP-W as a group. Unless otherwise indicated, each person has sole investment and voting power (or shares such powers with his or her spouse) with respect to the shares set forth in the following table. None of the individuals listed in the Beneficial Ownership Table below own more than 0.21 percent of Xcel Energy common stock. None of these individuals owns any shares of Xcel Energy preferred stock.


(1)	Mr. Brunetti is also Chairman of the Board and Chief Executive Officer of Xcel Energy.

(2)	Mr. Kelly is also President and Chief Operating Officer of Xcel Energy. Mr. Kelly was elected President and Chief Operating Officer of Xcel Energy effective October 22, 2003.

(3)	Mr. Johnson is also Vice President and General Counsel of Xcel Energy.

(4)	Mr. Bonavia is also President, Commercial Enterprises, of Xcel Energy.

(5)	Mr. Petillo resigned as Vice President of NSP-W effective August 8, 2003 and as Vice President of Xcel Services and as President, Delivery of Xcel Energy effective August 31, 2003.

The following tables set forth cash and non-cash compensation for each of the last three fiscal years ended December 31, 2003 for the Chief Executive Officer of NSP-W, each of the four next most highly compensated executive officers serving as officers of NSP-W at December 31, 2003 and one former officer of NSP-W who would have been among such four next most highly compensated executive officers but for the fact that he was not serving as an officer at December 31, 2003 (collectively, the “Named Executive Officers”). As set forth in the footnotes, the data presented in this table and the tables that follow include amounts paid to the Named Executive Officers in 2003 by Xcel Energy or any of its subsidiaries, in all capacities in which they served Xcel Energy or its subsidiaries during such periods.


(1)	The amounts in this column for 2003 awards are not yet available. The amounts in this column for 2002 represent awards earned under the Xcel Energy Executive Annual Incentive Award program. For Mr. Brunetti, Mr. Kelly and Mr. Petillo, the amounts for 2001 include the value of 25,068, 4,449, 10,536 and 5,682 shares, respectively, of restricted common stock they received in lieu of a portion of the cash payments to which they were otherwise entitled under the Xcel Energy Executive Annual Incentive Award program. For Mr. Bonavia, the amount for 2001 includes the pre-tax value of 3,023 shares of common stock he received in lieu of a portion of the cash payment to which he was otherwise entitled under the Xcel Energy Executive Annual Incentive Award program.

(2)	The amounts shown include reimbursements for taxes on certain personal benefits, including perquisites received by the named executives.

(3)	As of December 31, 2003, Messrs. Swenson, Brunetti and Kelly held shares of restricted stock. As of December 31, 2003, Mr. Brunetti held 25,245.99, Mr. Kelly held 3,312.22 and Mr. Swenson held 79.38 shares of restricted stock with an aggregate value of approximately $431,959, $56,672 and $1,358, respectively. Restricted stock vests in three equal annual installments and the holders are entitled to receive dividends at the same rate as paid on all other shares of common stock. The dividends are reinvested in additional shares of stock which is also restricted for the same periods as the underlying restricted stock on which the dividends are paid.


(4)	The amounts shown for 2001 include cash payments made under the Xcel Energy Long-term Inventive Program. No awards were paid in 2002 or 2003. No performance amounts under the NCE Value Creation Plan for Messrs. Swenson, Brunetti, Kelly, Bonavia or Petillo were paid during the periods presented.

(5)	The amounts represented in the “All Other Compensation” column for the year 2003 for the Named Executive Officers include the following:


(a)	The amounts for 2003 are not yet available.

(b)	This amount represents payments related to non-competition provisions in the severance agreement with Mr. Petillo entered into in connection with the termination of his employment on August 31, 2003. Approximately $2 million related to non-competition provisions in the severance agreement. Additional payments include a $87,749 lump sum related to Xcel Energy’s qualified pension plan, a $10,833 lump sum payment related to Xcel Energy’s non-qualified pension plan and a $708,307 lump sum related to Xcel Energy’s Senior Executive Retirement Plan.

Aggregated Option/ SAR Exercises in Last Fiscal Year and FY-End Option/ SAR Values

The following table indicates for each of the Named Executives Officers the number and value of exercisable and unexercisable options and SARs of Xcel Energy as of December 31, 2003.

The following table shows information on awards granted during 2003 under Xcel Energy’s Omnibus Incentive Plan for each person in the Summary Compensation Table.


(1)	Each unit represents the value of one share of Xcel Energy common stock.

(2)	Represents performance share component. If the threshold for the performance share component of the 35th percentile is achieved, the payout could range between 25 percent and 200 percent. The amounts are based on a stock price of $11.10, which was the average high/low price on January 2, 2003.

(3)	Represents the restricted stock unit component. On March 28, 2003, the Governance, Compensation and Nominating Committee of Xcel Energy’s board of directors granted restricted stock units and performance shares under the Xcel Energy Omnibus Incentive Plan approved by the shareholders in 2000. No stock options have been granted in 2003. Restrictions on the restricted stock units will lapse, but not before one year from the date of grant, after the achievement of a 27 percent total shareholder return (“TSR”) for 10 consecutive business days and other criteria relating to Xcel Energy’s common equity ratio. If the TSR target and other criteria relating to Xcel Energy’s common equity ratio is not met within four years, the grant will be forfeited. TSR is measured using the market price per share of Xcel Energy common stock, which at the grant date was $12.93, plus common dividends declared after grant date. Additional units are credited during the restricted period at the same rate as dividends paid on shares of outstanding Xcel Energy common stock. The dividend equivalents are subject to all terms of the original grant. As of December 31, 2003, the following dividend equivalents have been credited:

The following table shows estimated combined pension benefits payable to a covered participant from the qualified and non-qualified defined benefit plans maintained by Xcel Energy and its subsidiaries and the Xcel

The benefits listed in the Pension Plan Table are not subject to any deduction or offset. The compensation used to calculate the SERP benefits is base salary as of December 31 plus annual incentive. The Salary and Bonus columns of the Summary Compensation Table for 2003 reflect the covered compensation used to calculate SERP benefits.

The SERP benefit accrues ratably over 20 years and, when fully accrued, is equal to (a) 55 percent of the highest three years covered compensation of the five years preceding retirement or termination minus (b) any other qualified and non-qualified benefits. The SERP benefit is payable as an annuity for 20 years, or as a single lump-sum amount equal to the actuarial equivalent present value of the 20-year annuity. Benefits are payable at age 62, or as early as age 55, but would be reduced 5 percent for each year that the benefit

Notwithstanding any special provisions related to pension benefits described below under “— Employment Agreements and Severance Arrangements,” Xcel Energy has granted additional credited years of service to Mr. Brunetti for purposes of SERP accrual. The additional credited years of service (approximately seven) are included in the table above. Additionally, Xcel Energy has agreed to grant full accrual of SERP benefits to Mr. Brunetti at age 62 and Mr. Bonavia at age 57 and 8 months, if they continue to be employed by Xcel Energy until such age.

Wayne H. Brunetti Employment Agreement — At the time of their merger agreement, NCE and NSP-MN also entered into a new employment agreement with Mr. Brunetti, which replaced his existing employment agreement with NCE when the Merger was completed. The initial term of the new agreement is four years, with automatic one-year extensions beginning at the end of the second year and continuing each year thereafter unless notice is given by either party that the agreement will not be extended. Under the terms of the agreement, Mr. Brunetti served as Chief Executive Officer and President of Xcel Energy and a member of Xcel Energy’s board of directors for one year following the Merger, and commencing August 18, 2001 (one year after the Merger) began serving as Chief Executive Officer, President and Chairman of Xcel Energy’s Board of Directors. Mr. Brunetti is required to perform the majority of his duties at Xcel Energy’s headquarters in Minneapolis, Minnesota, and was required to relocate the residence at which he spends the majority of his time to the Twin Cities area. His agreement also provides that if Mr. Brunetti becomes entitled to receive severance benefits, he will be forbidden from competing with Xcel Energy and its affiliates for two years following the termination of his employment, and from disclosing confidential information of Xcel Energy and its affiliates.

Under his employment agreement, Mr. Brunetti will receive the following compensation and benefits:


	•	a base salary not less than his base salary immediately before the Merger;

	•	the opportunity to earn annual and long-term incentive compensation amounts not less than he was able to earn immediately before the Merger;

	•	life insurance coverage and participation in a supplemental executive retirement plan; and

	•	the same fringe benefits as he received under his NCE employment agreement, or, if greater, as those of Xcel Energy’s next highest executive officer.

If Mr. Brunetti’s employment were to be terminated by Xcel Energy without cause or if he were to terminate his employment for good reason, he would be entitled to receive the compensation and benefits described above as if he had remained employed for the employment period remaining under his employment agreement and then retired, at which time he would be eligible for all retiree benefits provided to Xcel Energy’s retired senior executives. In determining the level of his compensation following termination of employment, the amount of incentive compensation he would receive would be based upon the target level of incentive compensation he would have received in the year in which his termination occurred, and he would receive cash equal to the value of stock options, restricted stock and other stock-based awards he would have

Mr. Brunetti also had a change-of-control employment agreement with NCE. The Merger did not cause a “change of control” under this agreement, so it did not become effective as a result of the Merger. However, in case this agreement becomes effective because of a later change of control, Mr. Brunetti has waived his right to receive any severance benefits under the change-of-control employment agreement to the extent they would duplicate severance benefits under his employment agreement.

Paul J. Bonavia Employment Agreement — In connection with and effective upon completion of the Merger, Xcel Energy and Paul J. Bonavia entered into an amendment to an employment agreement between Mr. Bonavia and NCE. Except as discussed below, the original agreement expired December 14, 2000. In connection with the Merger, Mr. Bonavia’s position changed from Senior Vice President, General Counsel and President of NCE’s International Business Unit to President of Xcel Energy’s Energy Markets Business Unit. In the amendment, Mr. Bonavia agreed not to assert before January 6, 2003 that his duties and responsibilities had been diminished, and thus he has waived the right to claim certain benefits under the Xcel Energy Senior Executive Severance Policy, which terminated on August 18, 2003, relating to this change in his status prior to that date. If certain conditions were met on January 6, 2003 or within seven business days thereafter, which conditions include the termination of Mr. Bonavia’s employment, Mr. Bonavia would have been entitled to severance benefits comparable to those provided to the other senior executives under the Xcel Energy Senior Executive Severance Policy. Mr. Bonavia and Xcel Energy have entered into another amendment to this agreement. As part of this amendment, Mr. Bonavia agreed to continue his employment through August 31, 2003. Mr. Bonavia also agreed not to assert that his duties and responsibilities have been diminished. In return, Xcel Energy agreed that if it terminates Mr. Bonavia’s employment for any reason other than cause, or if Mr. Bonavia terminates his employment for any reason after August 31, 2003, then he will be entitled to severance benefits comparable to those that were provided under the Xcel Energy Senior Executive Severance Policy prior to its expiration.

NSP and NCE each adopted a 1999 senior executive severance policy in March 1999. These policies were combined into a single Xcel Energy Senior Executive Severance Policy, which terminated on August 18, 2003 on its scheduled termination date. All of our executive officers other than Mr. Brunetti participated in the policy until its termination.

Under the 1999 policy, a participant whose employment was terminated at any time before August 18, 2003, the third anniversary of the Merger, received severance benefits unless:


	•	the employer terminated the participant for cause;

	•	the termination was because of the participant’s death, disability or retirement;

	•	the participant’s division or subsidiary was sold and the buyer agreed to continue the participant’s employment with specified protections for the participant; or

	•	the participant terminated voluntarily without good reason.

To receive the severance benefits, the participant must have also signed an agreement releasing all claims against the employer and its affiliates, and agreeing not to compete with the employer and its affiliates and not to solicit their employees and customers.

The severance benefits for executive officers under the 1999 policy included the following:


	•	a cash payment equal to 2.5 times the participant’s annual base salary, annual bonus and annualized long-term incentive compensation, prorated incentive compensation for the year of termination and perquisite allowance;

	•	a cash payment equal to the additional amounts that would have been credited to the executive under pension and retirement savings plans, if the participant had remained employed for another 2.5 years;

	•	continued welfare benefits for 2.5 years;

	•	financial planning benefit for two years, and outplacement services costing not more than $30,000; and

	•	an additional cash payment to make the participant whole for any excise tax on excess severance payments that he or she may incur, with certain limitations specified in the policies.

Our former Vice President and Xcel Energy’s former President — Energy Delivery, James T. Petillo, resigned as Vice President of NSP-W effective August 8, 2003 and as President — Energy Delivery of Xcel Energy effective August 31, 2003. In connection with the termination of his employment, Mr. Petillo entered into an agreement with Xcel Energy and its affiliates and subsidiaries under which he waived claims to certain benefits he would have received under the 1999 severance policy had he terminated his employment prior to the expiration of the policy. Mr. Petillo received a cash payment of $2 million, continued welfare benefits for 2.5 years, financial planning benefits for two years and outplacement services costing no more than $30,000. The agreement with Mr. Petillo also contains non-competition, non-solicitation and non-disparagement clauses.

In October of 2003, Xcel Energy adopted the Xcel Energy Senior Executive Severance and Change-in-Control Policy. The 2003 policy was intended to replace the 1999 policy and, in many ways, operates similarly to the 1999 policy. Each of our executive officers, other than Mr. Swenson, Mr. Brunetti and Mr. Bonavia, are participants in the 2003 policy. Additional participants may be named by Xcel Energy’s Board or the Governance, Compensation and Nominating Committee from time to time.

Under the 2003 policy, a participant whose employment is terminated will receive severance benefits unless:


	•	the employer terminated the participant for cause (as defined in the 2003 policy);

	•	termination was because of the participant’s death, disability or retirement;

	•	the participant’s division, subsidiary or business unit was sold and the buyer agreed to continue the participant’s employment with specified protections for the participant; or

	•	the participant terminated voluntarily.

The severance benefits for executive officers under the 2003 policy include the following:


	•	a cash payment equal to two times the participant’s annual base salary and target annual incentive award;

	•	prorated target annual incentive compensation for the year of termination;

	•	financial planning benefit for two years and outplacement services costing not more than $30,000;

	•	a cash payment equal to value of the additional amounts that would have been credited to or paid on behalf of the participant under pension and retirement savings plans, if the participant had remained employed for another two years;

	•	continued medical, dental and life insurance benefits for two years; and

If the participant is terminated, including a voluntary termination following a diminution in salary, benefits or responsibilities, within two years following a change in control (as defined in the 2003 policy), the participant will receive benefits under the 2003 policy similar to the severance benefits above, except that for certain of our executive officers, including those of our named executive officers who are participants, the cash payment will be equal to three times the participant’s annual base salary and target annual incentive award, the cash payment for the value of additional retirement savings and pension credits will be for three years instead of two and medical, dental and life insurance, financial planning and perquisite allowance benefits will be continued for three years instead of two. In addition, each of the participants entitled to increased severance benefits upon a change in control will be entitled to receive an additional cash payment to make the participant whole for any excise tax on excess parachute payments that he or she may incur, with certain limitations specified in the 2003 policy.

To receive the benefits under the 2003 policy, the participant must also sign an agreement releasing all claims against the employer and its affiliates, and agreeing not to compete with the employer and its affiliates and not to solicit their employees and customers.

A portion of the costs of these various executive and Board of Directors compensation and other programs are allocated to us pursuant to the utility services agreement between us and Xcel Services discussed below.

The summaries of the agreements described below are not complete. You should read the agreements in their entirety, copies of which are available upon request from us. See “Where You Can Find More Information.”

Our electric production system is managed on an integrated basis with the electric production system of NSP-MN. Pursuant to the Interchange Agreement between NSP-MN and us we share, on a proportional basis, all costs related to the generation and transmission facilities of the entire integrated NSP-System including capital costs. Under the Interchange Agreement we recorded $29 million of revenue and $12 million of expense for the nine months ended September 30, 2003 and $37 million and $16 million respectively, for the year ended 2002. For more information on the Interchange Agreement see our discussions elsewhere in this prospectus and in Note 17 to the consolidated audited financial statements.

The Joint Operating Agreement dated as of July 23, 1999 (the “Joint Operating Agreement”) integrates the generating resources of the NSP System, PSCo and SPS (individually, an “Operating Company” and collectively, the “Operating Companies”). More specifically, the Joint Operating Agreement sets out the framework for the coordinated planning, operations, and maintenance of generation resources (both owned and purchased), coordinated wholesale marketing activities and the sales of capacity and energy among the Operating Companies. In this connection, the Joint Operating Agreement also provides for the allocation of associated costs and benefits. For many purposes under the Joint Operating Agreement, we and NSP-MN are treated as one system due to our contractual relationship under the Interchange Agreement. We receive no revenue under the Joint Operating Agreement.

We and NSP-MN also coordinate the planning, construction, operations and maintenance of their electric supply facilities on an integrated basis and operate as a single coordinate electric system pursuant to Interchange Agreement. For this reason, we and NSP-MN are treated as a single Operating Company under the Joint Operating Agreement for virtually all purposes. The Joint Operating Agreement is intended to be in addition to, and not in lieu of, the Interchange Agreement. The FERC has jurisdiction over the actual power transactions set out in the Joint Operating Agreement. The costs for various administrative and general

Xcel Services is the service company for the Xcel Energy system. Xcel Services provides a variety of administrative, management and support services, including services relating to support of electric and gas plant operations, customer bills and related matters, materials management, facilities, real estate, human resources, finance, accounting, internal auditing, information systems, corporate planning and research, public affairs, corporate communications, legal, environmental matters and executive services to Xcel Energy’s non-utility and utility companies, including us pursuant to individual service agreements. Xcel Services also administers the money pool pursuant to the Money Pool Agreement. PUHCA generally requires that Xcel Services provides services to us at cost. Under the services agreement, we were billed $25 million for the nine months ended September 30, 2003, and $36 million for the year ended 2002.

In November 2003, Xcel Energy, Xcel Services and each of the operating utility subsidiaries of Xcel Energy (the “Pool Participants”), including us, executed a money pool agreement, which provides a mechanism for intrasystem financing of the Pool Participants, thus reducing total capitalization needs and potentially reducing costs. The agreement will become effective as to each Pool Participant upon the Pool Participant’s receipt of all requisite regulatory approvals and will continue until terminated by the parties thereto.

Pool Participants are not required to borrow through this arrangement if the Pool Participant has the ability and authority to borrow at a lower cost from a bank or other external source. In addition, a Pool Participant will lend surplus funds to the money pool only when the return on such investment is equal to or greater than returns that the Pool Participant could receive elsewhere. Pool Participants will use the money pool when it is most efficient — e.g., a lower cost of borrowing, a better return on investment or more flexible terms as to amount of borrowing, term of borrowing, notice requirements, etc.

On April 5, 2001, we and the other operating utility subsidiaries of Xcel Energy, i.e., NSP-MN, SPS, PSCo and Cheyenne, entered into an agreement that provides that, to the extent available and mutually beneficial, each of the operating utilities will, at its option, provide and assign certain of its employees and provide, at its cost, certain incidental services and goods to any or all of the other operating utilities. The services that may be provided under the agreement include delivery services such as electric and/or natural gas transmission and/or distribution crews for construction, maintenance, or service restoration; generating plant maintenance, construction and/or operation, and other similar services. The goods that may be provided under the agreement include utility equipment; computers and software; railcars and other transportation services; coal and other fuels; and other goods owned, leased or contracted for by any of the operating utilities. Expenses billed to us under the administration services agreement for the nine months ended September 30, 2003 and the year ended 2002 were immaterial.

As of December 31, 2003, in addition to the original first mortgage bonds, we had other first mortgage bonds in the amount of $65 million outstanding that rank pari passu with the original first mortgage bonds and will rank pari passu with the exchange first mortgage bonds, when issued. We have no outstanding subordinated debt obligations. We also had $80 million of unsecured Senior Notes, $18.6 million in pollution control bonds and $0.9 million of other long term debt outstanding.

The description below contains summaries of selected provision of the Indenture (as defined below) under which the exchange first mortgage bonds will be issued. In the summary below, we have included references to section numbers of the Indenture so that you can easily locate those provisions. The following description of provisions of the exchange notes is not complete and is subject to, and qualified in its entirety by reference to, the exchange first mortgage bonds and the Indenture.

We will issue the exchange first mortgage bonds as a series of securities under the Indenture dated April 1, 1947 (the “1947 Indenture”), as previously supplemented by several supplemental trust indentures, a Supplemental and Restated Trust Indenture dated March 1, 1991 (the “Restated Indenture”) and a new supplemental indenture for the first mortgage bonds (the “New Supplemental Indenture”), all from us to U.S. Bank National Association, as successor trustee (the “Trustee”). The 1947 Indenture, as supplemented by the supplemental indentures, the Restated Indenture and the New Supplemental Indenture are referred to in this prospectus as the “Indenture”. As of December 31, 2003, there were two series of first mortgage bonds in an aggregate principal amount of $215 million outstanding under the Indenture.

The Restated Indenture amends and restates the 1947 Indenture and the supplemental indentures. The Restated Indenture became effective and operative on October 1, 1993.

The holders of the outstanding first mortgage bonds do not, and the holders of any exchange first mortgage bonds offered by this prospectus will not, have the right to require us to repurchase the first mortgage bonds if we become involved in a highly leveraged or change in control transaction. The Indenture does not have any provision that is designed specifically in response to highly leveraged or change in control transactions. However, holders of exchange first mortgage bonds would have the security afforded by the first mortgage lien on substantially all our property as described below under the caption “— Security for the First Mortgage Bonds.” In addition, any change in control transaction and any incurrence of substantial additional indebtedness, as first mortgage bonds, debt securities or otherwise, by us in a transaction of that nature would require approval of state utility regulatory authorities and, possibly, of federal utility regulatory authorities. Management believes that these approvals would be unlikely in any transaction that would result in us, or our successor, having a highly leveraged capital structure.

The exchange first mortgage bonds will bear interest from the date of the last periodic payment of interest on the original first mortgage bonds, or, no interest has been paid, from October 2, 2003, at the rate of 5.25% per year and will mature on October 1, 2018.

We will issue the exchange first mortgage bonds in fully registered form, without coupons, in denominations of $1,000 principal amount and whole multiples of $1,000. The exchange first mortgage bonds will be represented by one or more global securities registered in the name of The Depository Trust Company (“DTC”) or its nominee, as Depository (the “Depository”), and will be available only in book-entry form. See “— Book-Entry System”. We will pay principal and interest in immediately available funds to the registered holder, which will be DTC or its nominee.

The entire principal amount of the exchange first mortgage bonds will mature and become due and payable, together with any accrued and unpaid interest, on October 1, 2018. Each exchange first mortgage bond will bear interest from the date of the last periodic payment of interest on the original first mortgage bonds, or, if no interest has been paid, from October 2, 2003, at the rate of 5.25% per year. The interest will be payable semi-annually on April 1 and October 1 of each year, commencing April 1, 2004. The interest will be paid to the person in whose name the first mortgage bond is registered at the close of business on the March 15

Principal, interest and premium, if any, on the first mortgage bonds will be paid in the manner described below under “— Book-Entry System.”

All monies paid by us to a paying agent for the payment of principal, interest or premium, if any, on any first mortgage bonds which remain unclaimed at the end of two years after that principal, interest or premium has become due and payable will be repaid to us and the holder of that first mortgage bond will thereafter look only to us for payment of that principal, interest or premium.

We may redeem the exchange first mortgage bonds at any time, in whole or in part, at a “make whole” redemption price equal to the greater of (1) the principal amount being redeemed or (2) the sum of the present values of the remaining scheduled payments of principal and interest on the exchange first mortgage bonds being redeemed, discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Yield plus 25 basis points, plus accrued interest to the redemption date.

“Treasury Yield” means, for any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for the redemption date.

“Comparable Treasury Issue” means the United States Treasury security selected by an Independent Investment Banker as having a maturity comparable to the remaining term of the first mortgage bonds that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of the exchange first mortgage bonds.

“Comparable Treasury Price” means, for any redemption date, (1) the average of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) on the third business day preceding the redemption date, as set forth in the daily statistical release (or any successor release) published by the Federal Reserve Bank of New York and designated “Composite 3:30 p.m. Quotations for U.S. Government Securities” or (2) if that release (or any successor release) is not published or does not contain those prices on that business day, (A) the average of the Reference Treasury Dealer Quotations for the redemption date, after excluding the highest and lowest Reference Treasury Dealer Quotations for the redemption date, or (B) if the Trustee obtains fewer than four Reference Treasury Dealer Quotations, the average of all of the quotations.

“Independent Investment Banker” means BNY Capital Markets, Inc., Goldman, Sachs & Co. or their successors or, if such firms or their successors are unwilling or unable to select the Comparable Treasury Issue, one of the remaining Reference Treasury Dealers appointed by the Trustee after consultation with us.

“Reference Treasury Dealer” means (1) each of BNY Capital Markets, Inc. and Goldman, Sachs & Co., and any other primary U.S. Government Securities dealer in the United States (a “Primary Treasury Dealer”) designated by, and not affiliated with, BNY Capital Markets, Inc. and Goldman, Sachs & Co., and their respective successors, provided, however, that if any of the foregoing or any of their designees ceases to be a Primary Treasury Dealer, we will appoint another Primary Treasury Dealer as a substitute and (2) any other Primary Treasury Dealer selected by us.

“Reference Treasury Dealer Quotations” means, for each Reference Treasury Dealer and any redemption date, the average, as determined by the Independent Investment Banker, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Independent Investment Banker by the Reference Treasury Dealer at 5:00 p.m. on the third business day preceding the redemption date.

Notice of redemption will be given by mail not less than 30 days prior to the date fixed for redemption to the holders of the exchange first mortgage bonds to be redeemed. If we elect to redeem less than all the exchange first mortgage bonds and the exchange first mortgage bonds are at the time represented by one or more global bonds, then the Depository will select by lot the particular interest to be redeemed. If we elect to redeem less than all of the exchange first mortgage bonds, and the exchange first mortgage bonds are not represented by a global bond, then the Trustee will select the particular exchange first mortgage bonds to be redeemed by lot.

In the opinion of our counsel, the exchange first mortgage bonds being issued pursuant to this prospectus will be secured equally and ratably with all of our other outstanding first mortgage bonds, subject to the provisions relating to any sinking fund for any particular series, by a valid and direct first mortgage lien on all of the real and fixed properties, leasehold rights, franchises and permits then owned by us subject only to permitted encumbrances (as discussed below). The lien of the Indenture does not cover securities, cash, contracts, receivables, motor vehicles, merchandise, equipment and supplies and specified non-utility property.

The Indenture subjects to the lien of the Indenture all property, rights and franchises, except as otherwise expressly provided, we acquired after the date of the 1947 Indenture. These provisions might not be effective as to property acquired within 90 days prior and subsequent to the filing of a case by us under the United States Bankruptcy Code. The opinion of counsel does not cover titles to easements for water flowage purposes or rights-of-way for electric and gas transmission and distribution facilities. However, we have the power of eminent domain in the states in which we operate.

The Indenture provides that no prior liens, other than permitted encumbrances, may be created or permitted to exist upon the mortgaged and pledged property whether now owned or acquired in the future. (Section 8.04 of Article VIII of the Restated Indenture.)


	•	permitted liens (liens for taxes not yet delinquent or being contested in good faith, mechanics’, workers’ and other similar liens and easements and rights of way which do not materially impair the use of the property in our business);

	•	rights of parties to agreements with us relating to property owned or used jointly with that party, provided that the rights:


	•	do not materially impair the use of the property in the normal course of our business;

	•	do not materially affect the security provided by the Indenture; and

	•	are not inconsistent with the remedies of the Mortgage Trustee upon a completed default;


	•	leases existing on the effective date of the Restated Indenture affecting property owned by us on the effective date;

	•	leases which do not interfere in any material respect with the use by us of the property for its intended purpose and which will not have a material adverse impact on the security provided by the Indenture;

	•	other leases relating to 5% or less of the sum of our depreciable property and land; and


	•	any mortgage, lien, charge or other encumbrance prior or equal to the lien of the Indenture, other than a prepaid lien, existing on the date we acquire the property, provided that on the acquisition date:


	•	no default has occurred and is continuing;

	•	the principal amount secured by that mortgage, lien, charge or encumbrance does not exceed 66 2/3% of the lesser of the cost or fair value of the property; and

	•	the mortgage will apply only to the property originally subject to that mortgage, we will close the mortgage and we will not issue additional indebtedness under that mortgage.

The holders of 66 2/3% of the principal amount of exchange first mortgage bonds outstanding may (1) consent to the creation or existence of a prior lien with respect to up to 50% of the sum of our depreciable property and land, after giving effect to the prior lien, or (2) terminate the lien of the Indenture with respect to up to 50% of the sum of our depreciable property and land. (Section 19.02(e) of the Restated Indenture.)

We have agreed to pay the Mortgage Trustee, as an annual sinking fund, on April 1 of each year an amount sufficient to redeem, on the following June 1, for sinking fund purposes, 1% of the highest amount at any time outstanding of our first mortgage bonds of the series due March 1, 2023. We may offset the sinking fund payments by applying amounts of established permanent additions equal to 150% of the principal amount of the bonds that would otherwise be required to be retired by the sinking fund or by retiring or delivering to the Trustee bonds of the series for which the sinking fund is applicable. The exchange first mortgage bonds offered hereby will not be subject to a sinking fund.

As a maintenance fund for the exchange first mortgage bonds, we have agreed to pay to the Mortgage Trustee on each May 1 an amount equal to 2.50% of our completed depreciable property as of the end of the preceding calendar year, after deducting credits at our option for the following:


	•	maintenance;

	•	property retirements offset by permanent additions;

	•	retirements or redemptions of exchange first mortgage bonds; and

	•	amounts of established permanent additions.

The Restated Indenture further provides that to the extent that maintenance fund credits exceed 2.50% of completed depreciable property for any year after 1990, such excess credits may be applied in future years (1) to offset any maintenance fund deficiency or (2) to increase the amount of established permanent additions available for use under the Indenture in an aggregate amount equal to the lesser of such excess credits or the amount of permanent additions used after 1990 for the maintenance fund. (Section 9.05 of the Restated Indenture.)

We have agreed to maintain our properties in adequate repair, working order and condition. (Section 8.06 of the Restated Indenture.)

The maximum principal amount of first mortgage bonds that we may issue under the Indenture is not limited, except as described below. We may issue additional first mortgage bonds in amounts equal to (1) 66 2/3% of the cost or fair value, whichever is less, of permanent additions after deducting retirements

The original first mortgage bonds were and the exchange first mortgage bonds issued pursuant to this prospectus will be issued under clause (1) above. At August 31, 2003, the amount of net permanent additions available for the issuance of first mortgage bonds exceeded $750 million, of which $225 million were used to authenticate $150 million principal amount of the original first mortgage bonds. As of August 31, 2003, approximately $16 million of retired first mortgage bonds were available to authenticate up to $16 million of original first mortgage bonds.

We may not issue any additional first mortgage bonds on the basis of clause (1), clause (2) under specified conditions or clause (3), unless the earnings applicable to bond interest for a specified twelve-month period are equal to twice the annual interest requirements on the first mortgage bonds, including those about to be issued, any permitted indebtedness and any obligations secured by prior liens (Sections 1.03, 5.03, 6.02 and 7.01 of the Restated Indenture.) The calculation of earnings applicable to bond interest will include all of our nonutility revenues. (Section 1.03 of the Restated Indenture.)


	•	our electric and steam generating, transmission and distribution properties;

	•	our gas storage and distribution properties;

	•	construction work-in-progress;

	•	our fractional and undivided property interests;

	•	property used for providing telephone or other communication services; and

	•	engineering, financial, economic, environmental, geological and legal or other studies, surveys or reports associated with the acquisition or construction of any depreciable property. (Section 1.03 of the Restated Indenture.)

Assuming that the interest cost on variable rate first mortgage bonds is at the maximum allowable rate, earnings applicable to bond interest for the twelve months ended June 30, 2003, would be 3.83 times the annual interest requirements on our first mortgage bonds, including the first mortgage bonds issued pursuant to this offering circular. Additional first mortgage bonds may vary as to maturity, interest rate, redemption prices and sinking fund, among other things. (Article II of the Restated Indenture.)

The Indenture does not restrict our ability to pay dividends on our common stock.

The Indenture permits the release from its lien of any property upon depositing or pledging cash or certain other property of comparable fair value. The Indenture also permits the following, in each case without any release or consent by the Trustee or accountability to the Trustee:


	•	the sale or other disposal of securities not pledged under the Indenture, contracts, accounts, motor cars and certain equipment and supplies;

	•	the cancellation, change or alteration of leases, rights-of-way and easements; and

	•	the surrender and modification of any franchise or governmental consent subject to certain restrictions.


	•	we may sell or otherwise dispose of, free of the lien of the Indenture, all motor vehicles, vessels and marine equipment, railroad cars, engines and related equipment, airplanes, office furniture and leasehold interests in property owned by third parties; and

	•	we may enter into leases relating to the property subject to the lien of the Indenture which do not interfere in any material respect with the use of the property for the purpose for which it is held by us and will not have a material adverse impact on the security afforded by the Indenture. (Section 11.02(b) of the Restated Indenture.)

Any of the mortgaged and pledged property may be released from the lien of the Indenture if, after the release, the fair value of the remaining mortgaged and pledged property equals or exceeds a sum equal to 150% of the aggregate principal amount of first mortgage bonds outstanding. (Section 11.03(k) of the Restated Indenture.) When effective and upon satisfaction of the requirements set forth in the Indenture, this provision would permit us to spin-off or otherwise dispose of a substantial amount of assets or a line of business, including all or a portion of our electric generation, transmission or distribution assets, or our gas storage and distributions assets, without depositing cash or property with the Trustee or obtaining the consent of the bondholders.

With our consent, the provisions of the Indenture may be changed by the affirmative vote of the holders of 66 2/3% in principal amount of the first mortgage bonds outstanding except that, among other things, the following may not be done without the consent of the holder of each first mortgage bond so affected:


	•	the maturity of a first mortgage bond may not be changed;

	•	the interest rate may not be reduced;

	•	the terms of payment of principal or interest may not be changed;

	•	no lien ranking prior to or on a parity with the lien of the Indenture with respect to any of the property mortgaged or pledged under the Indenture may be created;

	•	the security of the lien upon the mortgaged and pledged property for the security of such holder’s bond may not be deprived; and

	•	the required percentage of the holders of first mortgage bonds relating to actions that require their consent may not be changed.

The following is a summary of events defined in the Indenture as completed defaults:


	•	default in payment of principal of any first mortgage bond;

	•	default continued for 30 days in payment of interest on any first mortgage bond;

	•	default continued for 60 days in any sinking fund payment;

	•	default in the covenant contained in Section 8.11 of the Restated Indenture regarding bankruptcy, insolvency, assignment or receivership; and

	•	default continued for 60 days after notice in the performance of any other covenant, agreement or condition.

Notice of Default. The Trustee is required to give notice to bondholders within 90 days after the occurrence of a default, unless the default has been cured before giving its notice. However, except in the case of a default resulting from the failure to make any payment of principal or interest on any first mortgage bonds or to make any sinking fund payment, the Trustee may withhold the notice if its board of directors, executive committee or a trust committee of directors or responsible officers determines in good faith that withholding the notice is in the interest of the bondholders. (Section 17.02 of the Restated Indenture.)

Acceleration of Maturity. In case of a completed default, either the Trustee or the holders of 25% in principal amount of the first mortgage bonds outstanding may declare the first mortgage bonds due and payable, subject to the right of the holders of a majority of the first mortgage bonds then outstanding to rescind or annul such action. Further, the Trustee is obligated to take the actions provided in the Indenture to enforce payment of the first mortgage bonds and the lien of the Indenture upon being requested to do so by the holders of a majority in principal amount of the first mortgage bonds. However, the holders of a majority in principal amount of the first mortgage bonds may direct the taking of any of these actions or the refraining from these actions as is not in violation of the law or the Indenture. Before taking these actions, the Trustee may require adequate indemnity against the costs, expenses and liabilities to be incurred in connection with these actions. (Article XIV of the Restated Indenture.)

Compliance Certificate. We are required to file with the Trustee information, documents and reports regarding our compliance with the conditions and covenants of the Indenture as may be required by the rules and regulations of the SEC, including a certificate, furnished at least annually, as to our compliance with all of the conditions and covenants under the Indenture. (Section 8.18 of the Restated Indenture.)

Whenever all indebtedness secured by the Indenture has been paid, or adequate provision for payment has been made, the Trustee will cancel and discharge the Indenture. (Article XVIII of the Restated Indenture.) We may deposit with the Trustee any combination of cash or government obligations in order to provide for the payment of any series or all of the first mortgage bonds outstanding. Such a deposit could constitute a taxable event as to holders of such first mortgage bonds, creating possible adverse tax consequences. The Indenture also provides that we must furnish to the Trustee officers’ certificates, certificates of an engineer, appraiser or other expert and, in some cases, accountants’ certificates in connection with the authentication of first mortgage bonds, the release or release and substitution of property and some other matters, and opinions of counsel as to the lien of the Indenture and some other matters. (Articles IV, V, VI, VII, XI and XVIII and Section 21.08 of the Restated Indenture.)

U.S. Bank National Association, is the Trustee. We maintain banking relationships with the Trustee in the ordinary course of business. The Trustee also acts as trustee for certain unsecured debt securities we may issue from time to time under an indenture dated as of September 1, 2000.

The Indenture and the exchange first mortgage bonds are governed by, and construed in accordance with, the laws of the State of Wisconsin.

Except as set forth below, the exchange first mortgage bonds will initially be issued in the form of one or more global bonds (each, a “new global bonds”). Each new global bond will be deposited on the date of the closing of the exchange of the original first mortgage bonds for the exchange first mortgage bonds with, or on behalf of, DTC and will be registered in the name of DTC or its nominee. Investors may hold their beneficial interests in a new global bond directly through DTC or indirectly through organizations which are participants in the DTC system.

Unless and until they are exchanged in whole or in part for certificated bonds, the new global bonds may not be transferred except as a whole by DTC or its nominee.

DTC has advised us as follows: DTC is a limited-purpose trust company organized under the laws of the State of New York, a “banking organization” within the meaning of New York banking law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code, and a “clearing agency” registered pursuant to the provisions of Section 17A of the Exchange Act. DTC holds and provides asset servicing for over 2 million issues of U.S. and non-U.S. equity issues, corporate and municipal debt issues, and money market instruments from over 85 countries that DTC’s participants (“Direct Participants”) deposit with DTC. DTC also facilitates the post-trade settlement among Direct Participants of sales and other securities transactions in deposited securities, through electronic computerized book-entry transfers and pledges between Direct Participants’ accounts. This eliminates the need for physical movement of securities certificates. Direct Participants include both U.S. and non-U.S. securities brokers and dealers, banks, trust companies, clearing corporations, and certain other organizations. DTC is a wholly owned subsidiary of The Depository Trust & Clearing Corporation (“DTCC”). DTCC, in turn, is owned by a number of Direct Participants of DTC and Members of the National Securities Clearing Corporation, Government Securities Clearing Corporation, MBS Clearing Corporation, and Emerging Markets Clearing Corporation, as well as by the New York Stock Exchange, Inc., the American Stock Exchange LLC, and the National Association of Securities Dealers, Inc. Access to the DTC system is also available to others such as both U.S. and non-U.S. securities brokers and dealers, banks, trust companies, and clearing corporations that clear through or maintain a custodial relationship with a Direct Participant, either directly or indirectly. DTC has Standard & Poor’s highest rating: AAA. The DTC Rules applicable to its Participants are on file with the SEC. More information about DTC can be found at www.dtcc.com.

Upon the issuance of the new global bonds, DTC or its custodian will credit, on its internal system, the respective principal amounts of the exchange first mortgage bonds represented by the new global bonds to the accounts of persons who have accounts with DTC. Ownership of beneficial interests in the new global bonds will be limited to persons who have accounts with DTC or persons who hold interests through the persons who have accounts with DTC. Persons who have accounts with DTC are referred to as “participants.” Ownership of beneficial interests in the new global bonds will be shown on, and the transfer of that ownership will be effected only through, records maintained by DTC or its nominee, with respect to interests of participants, and the records of participants, with respect to interests of persons other than participants.

As long as DTC or its nominee is the registered owner or holder of the new global bonds, DTC or the nominee, as the case may be, will be considered the sole record owner or holder of the exchange first mortgage bonds represented by the new global bonds for all purposes under the Indenture and the exchange first mortgage bonds. No beneficial owners of an interest in the new global bonds will be able to transfer that interest except according to DTC’s applicable procedures, in addition to those provided for under the Indenture. Owners of beneficial interests in the new global bonds will not:


	•	be entitled to have the exchange first mortgage bonds represented by the new global bonds registered in their names, receive or be entitled to receive physical delivery of certificated bonds in definitive form; and

	•	be considered to be the owners or holders of any exchange first mortgage bonds under the new global bonds.

Accordingly, each person owning a beneficial interest in new global bonds must rely on the procedures of DTC and, if a person is not a participant, on the procedures of the participant through which that person owns its interests, to exercise any right of a holder of exchange first mortgage bonds under the new global bonds. We understand that under existing industry practice, if an owner of a beneficial interest in the new global bonds desires to take any action that DTC, as the holder of the new global bonds, is entitled to take, DTC would authorize the participants to take that action, and that the participants would authorize beneficial owners owning through the participants to take that action or would otherwise act upon the instructions of beneficial owners owning through them.

Payments of the principal of, premium, if any, and interest on the exchange first mortgage bonds represented by the new global bonds will be made by us to the Trustee and from the Trustee to DTC or its nominee, as the case may be, as the registered owner of the new global bonds. Neither we, the Trustee, nor any paying agent will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial ownership interests in the new global bonds or for maintaining, supervising or reviewing any records relating to the beneficial ownership interests.

We expect that DTC or its nominee, upon receipt of any payment of principal of, premium, if any, or interest on the new global bonds will credit participants’ accounts with payments in amounts proportionate to their respective beneficial ownership interests in the principal amount of the new global bonds, as shown on the records of DTC or its nominee. We also expect that payments by participants to owners of beneficial interests in the new global bonds held through these participants will be governed by standing instructions and customary practices, as is now the case with securities held for the accounts of customers registered in the names of nominees for these customers. These payments will be the responsibility of these participants.

Transfer between participants in DTC will be effected in the ordinary way in accordance with DTC rules. If a holder requires physical delivery of notes in certificated form for any reason, including to sell notes to persons in states which require the delivery of the notes or to pledge the notes, a holder must transfer its interest in the new global bonds in accordance with the normal procedures of DTC and the procedures set forth in the Indenture.

Unless and until they are exchanged in whole or in part for certificated exchange first mortgage bonds in definitive form, the new global bonds may not be transferred except as a whole by DTC to a nominee of DTC or by a nominee of DTC to DTC or another nominee of DTC.

DTC has advised us that DTC will take any action permitted to be taken by a holder of first mortgage bonds, including the presentation of first mortgage bonds for exchange as described below, only at the direction of one or more participants to whose account the DTC interests in the new global bonds are credited. Further, DTC will take any action permitted to be taken by a holder of first mortgage bonds only in respect of that portion of the aggregate principal amount of first mortgage bonds as to which the participant or participants has or have given that direction.

Although DTC has agreed to these procedures in order to facilitate transfers of interests in the new global bonds among participants of DTC, it is under no obligation to perform these procedures, and may discontinue them at any time. Neither we nor the trustee will have any responsibility for the performance by DTC or its participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

Subject to specified conditions, any person having a beneficial interest in the new global bonds may, upon request to the trustee, exchange the beneficial interest for exchange first mortgage bonds in the form of certificated first mortgage bonds. Upon any issuance of certificated first mortgage bonds, the trustee is required to register the certificated first mortgage bonds in the name of, and cause the same to be delivered to, the person or persons, or the nominee of these persons. In addition, if DTC is at any time unwilling or unable to continue as a depositary for the new global bonds, and a successor depositary is not appointed by us within 120 days, we will issue certificated first mortgage bonds in exchange for the new global bonds.

As part of the sale of the original first mortgage bonds, under a registration rights agreement, dated as of October 2, 2003 (the “Registration Rights Agreement”), we agreed with the initial purchasers in the offering of the original first mortgage bonds, for the benefit of the holders of the original first mortgage bonds, to file with the SEC an exchange offer registration statement (an “Exchange Offer Registration Statement”) for the purpose of offering exchange first mortgage bonds in exchange for original first mortgage bonds (a “Registered Exchange Offer”) or, if applicable, a shelf registration statement (as defined below).


	•	a change in law or in applicable interpretations of the staff of the SEC do not permit us to effect such a Registered Exchange Offer;

	•	any holder of an original first mortgage bonds is not eligible to participate in the Registered Exchange Offer; or

	•	for any other reason the Registered Exchange Offer is not consummated within 225 days after the date of issue of the original first mortgage bonds;


	•	as promptly as practicable, but in no event more than 90 days after becoming required to do so, file a registration statement under the Securities Act covering continuous resales of the original first mortgage bonds or the exchange first mortgage bonds, as the case may be (“Shelf Registration Statement”);

	•	use our best efforts to cause the Shelf Registration Statement to be declared effective under the Securities Act; and

	•	use our best efforts to keep the Shelf Registration Statement effective until the earlier of (a) the time when the original first mortgage bonds covered by the Shelf Registration Statement are freely tradable under the Securities Act and (b) two years from the issuance of the original first mortgage bonds.

We will, in the event a Shelf Registration Statement is filed, among other things, provide to each holder for whom the Shelf Registration Statement was filed copies of the prospectus which is a part of the Shelf Registration Statement, notify each such holder when the Shelf Registration Statement has become effective and take other actions as are required to permit unrestricted resales of the original first mortgage bonds or the exchange first mortgage bonds, as the case may be. A holder that sells original first mortgage bonds issued pursuant to the Shelf Registration Statement generally will be required to be named as a selling security holder in the related prospectus and to deliver a prospectus to purchasers, will be subject to applicable civil liability provisions under the Securities Act in connection with sales of that kind and will be bound by the provisions of the registration rights agreement that are applicable to that holder (including certain indemnification obligations).


	•	the Exchange Offer Registration Statement or the Shelf Registration Statement is not filed with the SEC on or prior to the applicable filing deadline specified in the Registration Rights Agreement;

	•	the Exchange Offer Registration Statement or the Shelf Registration Statement is not declared effective by the SEC on or prior to the applicable effectiveness deadline specified in the Registration Rights Agreement;

	•	the Registered Exchange Offer is not consummated on or prior to the applicable consummation deadline specified in the Registration Rights Agreement; or


	•	after either the Exchange Offer Registration Statement or the Shelf Registration Statement is declared effective, such registration statement thereafter ceases to be effective or usable (subject to certain exceptions) in connection with resales of first mortgage bonds or exchange first mortgage bonds as provided in and during the periods specified in the Registration Rights Agreement (each such event referred to in clauses (1) through (4), a “Registration Default”).

Liquidated damages will be incurred from and including the date on which any such Registration Default shall occur to and including the first week in which all Registration Defaults have been cured in an amount equal to $0.10 per week per $1,000 principal amount of original first mortgage bonds or exchange first mortgage bonds.

We will pay liquidated damages to the holders of global bonds by wire transfer of immediately available funds or by federal funds check and to holders of certificated bonds by wire transfer to the accounts specified by them or by mailing checks to their registered address if no such accounts have been specified. No liquidated damages will be paid for any week beginning after all Registration Defaults have been cured.

If we effect the Registered Exchange Offer, we will be required to use our reasonable best efforts to close the Registered Exchange Offer no later than 225 days after the issuance of the first mortgage bonds.

The following is a discussion of the material U.S. federal income tax consequences of the exchange of original first mortgage bonds for exchange first mortgage bonds. This summary is based on the Internal Revenue Code of 1986, as amended, Treasury regulations, administrative pronouncements and judicial decisions, all as in effect on the date of this prospectus and all subject to change or differing interpretations, possibly with retroactive effect. This discussion is limited to holders that purchased the original first mortgage bonds upon their original issuance and that hold the original first mortgage bonds, and will hold the exchange first mortgage bonds, as capital assets within the meaning of Section 1221 of the Internal Revenue Code. This discussion does not address all of the tax consequences that may be relevant to a holder in light of the holder’s particular circumstances or to holders subject to special rules, such as financial institutions, tax-exempt entities, holders whose functional currency is not the U.S. dollar, insurance companies, dealers in securities or foreign currencies, persons holding bonds as part of a hedge, straddle or other integrated transaction, or persons who have ceased to be United States citizens or to be taxed as resident aliens. You should consult with your own tax advisor about the application of the U.S. federal income tax laws to your particular situation as well as any consequences of the exchange under the tax laws of any state, local or foreign jurisdiction.

Your acceptance of the exchange offer and your exchange of original first mortgage bonds for exchange first mortgage bonds will not be taxable for U.S. federal income tax purposes because the exchange first mortgage bonds will not be considered to differ materially in kind or extent from the original first mortgage bonds. Rather, the exchange first mortgage bonds you receive will be treated as a continuation of your investment in the original first mortgage bonds. Accordingly, you will not recognize gain or loss upon the exchange of original first mortgage bonds for exchange first mortgage bonds pursuant to the exchange offer, your tax basis in the exchange first mortgage bonds will be the same as your adjusted tax basis in the original first mortgage bonds immediately before the exchange, and your holding period for the exchange first mortgage bonds will include the holding period for the original first mortgage bonds exchanged therefor. There will be no U.S. federal income tax consequences to holders that do not exchange their original first mortgage bonds pursuant to the exchange offer.

Based on interpretations by the staff of the SEC in no-action letters issued to third parties, we believe that you may freely transfer exchange first mortgage bonds issued in the exchange offer if:


	•	you acquire the exchange first mortgage bonds in the ordinary course of your business; and

	•	you are not engaged in, and do not intend to engage in, and have no arrangement or understanding with any person to participate in, a distribution of exchange first mortgage bonds.

We believe that you may not transfer exchange first mortgage bonds issued in the exchange offer in exchange for the original first mortgage bonds if you are:


	•	our “affiliate,” within the meaning of Rule 405 under the Securities Act;

	•	a broker-dealer that acquired original first mortgage bonds directly from us; or

	•	a broker-dealer that acquired original first mortgage bonds as a result of market-making activities or other trading activities without compliance with the registration and prospectus delivery provisions of the Securities Act.

If you wish to exchange your original first mortgage bonds for exchange first mortgage bonds in the exchange offer, you will be required to make representations to us as described under the caption “The Exchange Offer — Procedures for Tendering” and in the letter of transmittal.

Each broker-dealer that receives exchange first mortgage bonds for its own account under the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such exchange first mortgage bonds. Broker-dealers may use this prospectus, as it may be amended or supplemented from time to time, for resales of exchange first mortgage bonds received in exchange for original first mortgage bonds where the original first mortgage bonds were acquired as a result of market-making activities or other trading activities. We have agreed that, starting on the date of completion of the exchange offer and ending on the close of business 180 days after such date, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale.

We will not receive any proceeds from any sale of exchange first mortgage bonds by broker-dealers. Broker-dealers may sell exchange first mortgage bonds received for their own account under the exchange offer in one or more transactions:


	•	in the over-the-counter market;

	•	in negotiated transactions;

	•	through the writing of options on the exchange first mortgage bonds; or

	•	a combination of such methods of resale.


	•	at market prices prevailing at the time of resale;

	•	at prices related to such prevailing market prices; or

	•	at negotiated prices.

Broker-dealers may make any such resale directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer and/or the purchasers of any such exchange first mortgage bonds. Any broker-dealer that receives exchange first mortgage bonds for its own account under the exchange offer and any broker or dealer that participates in a distribution of such exchange first mortgage bonds may be deemed to be an “underwriter” within the meaning of the Securities Act. Any profit on any such resale of exchange first mortgage bonds and any commission or concessions received by any such persons may be deemed to be underwriting compensation under the

Furthermore, any broker-dealer that acquired any of its original first mortgage bonds directly from us:


	•	may not rely on the applicable interpretation of the staff of the SEC’s position contained in Exxon Capital Holdings Corp., SEC no-action letter (available April 13, 1988), Morgan, Stanley & Co. Inc., SEC no-action letter (available June 5, 1991) and Shearman & Sterling, SEC no-action letter (available July 2, 1983); and

	•	must also be named as a selling bondholder in connection with the registration and prospectus delivery requirements of the Securities Act relating to any resale transaction.

For a period of 210 days from the date of completion of this exchange offer, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal. We have agreed to pay all expenses incident to the exchange offer other than commissions or concessions of any broker-dealers and will indemnify the holders of the original first mortgage bonds (including any broker-dealers) against some liabilities, including liabilities under the Securities Act.

Legal opinions relating to the exchange first mortgage bonds will be rendered by Michael C. Connelly, 800 Nicollet Mall, Minneapolis, Minnesota, Vice President and Deputy General Counsel of Xcel Energy.

The consolidated financial statements and related financial statement schedule as of and for the year ended December 31, 2002 included in this prospectus have been audited by Deloitte & Touche LLP, independent auditors, as stated in their report appearing herein, and are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The consolidated financial statements and schedule of Northern States Power Company, a Wisconsin corporation, as of and for the years ended December 31, 2001 and December 31, 2000 have been audited by Arthur Andersen LLP, independent auditors for those periods, as stated in their report with respect thereto. Arthur Andersen LLP was convicted on federal obstruction of justice charges arising from the federal government’s investigation of Enron Corp. In light of the conviction, Arthur Andersen ceased practicing before the SEC on August 31, 2002. NSP-W has been unable to obtain the consent of Arthur Andersen LLP to the use of their report in this prospectus. Events arising out of the indictment and conviction materially and adversely affect the ability of Arthur Andersen LLP to satisfy any claims arising from the provision of auditing services to NSP-W, including claims that may arise out of Arthur Andersen LLP’s audit of financial statements included in this prospectus. NSP-W has not had a reaudit of its financial statements as of and for the years ended December 31, 2001 and December 31, 2000.

We have filed with the Securities and Exchange Commission, 450 Fifth Street, N.W., Washington, D.C. 20549, a Registration Statement on Form S-4 under the Securities Act relating to the offering. As permitted by the rules and regulations of the SEC, this prospectus does not contain all the information contained in the registration statement. For further information about us and the offering, you can read the registration statement and the exhibits and financial schedules filed with the registration statement. The statements contained in this prospectus about the contents of any contract or other document are not necessarily complete. You can read a copy of each contract or other document filed as an exhibit to the registration statement.

We file annual, quarterly and special reports and other information with the SEC. Our SEC filings are available free of charge to the public over the Internet at the SEC’s web site at http://www.sec.gov. You may also read and copy any document we file at the SEC’s public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.

You may request a copy of these filings at no cost, by writing or telephoning us at the following address:


	Corporate Secretary Northern States Power Company (Wisconsin) c/o Xcel Energy Inc. 800 Nicollet Mall Minneapolis, Minnesota 55401 (612) 330-5500

We have audited the accompanying consolidated balance sheet and consolidated statement of capitalization of Northern States Power Company-Wisconsin (a Wisconsin corporation) and subsidiaries (the Company) as of December 31, 2002, and the related consolidated statements of income, stockholder’s equity and cash flows for the year then ended. Our audit also included the financial statement schedule listed in the Index at Item 21. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

The consolidated financial statements of Northern States Power Company-Wisconsin for the years ended December 31, 2001 and 2000 were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those consolidated financial statements and the financial statement schedules in their report dated February 21, 2002.

We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Northern States Power Company-Wisconsin and its subsidiaries as of December 31, 2002, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

THE FOLLOWING REPORT IS A COPY OF A PREVIOUSLY ISSUED REPORT OF ARTHUR ANDERSEN LLP AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.

We have audited the accompanying consolidated balance sheets and statements of capitalization of Northern States Power Company-Wisconsin (a Wisconsin corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, stockholder’s equity and cash flows for each of the two years in the period ended December 31, 2001. These financial statements and the schedule referred to below are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Northern States Power Company-Wisconsin and its subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States.

Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the index of the consolidated financial statements is presented for purposes of complying with the Securities and Exchange Commission’s rules and is not a required part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in our audits of the basic financial statements and, in our opinion, fairly states, in all material respects, the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.

See disclosures regarding NSP-Wisconsin in the Notes to Consolidated Financial Statements

See disclosures regarding NSP-Wisconsin in the Notes to Consolidated Financial Statements.

See disclosures regarding NSP-Wisconsin in the Notes to Consolidated Financial Statements

Merger and Basis of Presentation — On Aug. 18, 2000, Northern States Power Co. (NSP) and New Century Energy, Inc. (NCE) merged and formed Xcel Energy Inc. Each share of NCE common stock was exchanged for 1.55 shares of Xcel Energy common stock. NSP shares became Xcel Energy shares on a one-for-one basis. Cash was paid in lieu of any fractional shares of Xcel Energy common stock. The merger was structured as a tax-free, stock-for-stock exchange for shareholders of both companies (except for fractional shares) and accounted for as a pooling-of-interests. At the time of the merger, Xcel Energy registered as a holding company under the PUHCA.

Pursuant to the merger agreement, NCE was merged with and into NSP. NSP, as the surviving legal corporation, changed its name to Xcel Energy. Also, as part of the merger, NSP transferred its existing utility operations that were being conducted directly by NSP at the parent company level to a newly formed wholly owned subsidiary of Xcel Energy, which was renamed NSP-Minnesota.

Consistent with pooling accounting requirements, results and disclosures for all periods prior to the merger have been restated for consistent reporting with post-merger organization and operations.

Business and System of Accounts — NSP-Wisconsin is a wholly owned subsidiary of Xcel Energy and is engaged principally in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. NSP-Wisconsin is subject to the regulatory provisions of the PUHCA. NSP-Wisconsin is subject to regulation by the FERC and state utility commissions. Its accounting records conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material aspects.

Principles of Consolidation — NSP-Wisconsin has subsidiaries, which have been consolidated. In the consolidation process, we eliminate all significant intercompany transactions and balances.

NSP-Wisconsin has subsidiaries for which it uses the equity method of accounting for its investments and records its portion of earnings from such investments after subtracting income taxes.

Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based of the reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated.

NSP-Wisconsin has various rate adjustment mechanisms in place that currently provide for the recovery of certain purchased natural gas and electric energy costs. These cost adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically, as prescribed by the appropriate regulatory agencies, for any difference between the total amount collected under the clauses and the recoverable costs incurred.

NSP-Wisconsin’s rates include a cost-of-energy adjustment clause for purchased natural gas, but not for purchased electricity or electric fuel. NSP-Wisconsin can request recovery of those electric costs prospectively through the rate review process, which normally occurs every two years, and an interim fuel-cost hearing process.

Property, Plant, Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and applicable interest expense. The cost of plant retired, plus net removal cost is charged to accumulated depreciation and amortization. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance are charged to expense as incurred. Maintenance and replacement of items determined to be less than units of property are charged to operating expenses.

NSP-Wisconsin determines the depreciation of its plant by using the straight-line method, which spreads the original cost equally over the plant’s useful life. Depreciation expense, expressed as a percentage of average depreciable property, for the years ended December 31, is listed in the following table:

Allowance for Funds Used During Construction (AFDC) and Capitalized Interest — AFDC, a noncash item, represents the cost of capital used to finance utility construction activity. AFDC is computed by applying a composite pretax rate to qualified construction work in progress. The amount of AFDC capitalized as a utility construction cost is credited to other income and deductions (for equity capital) and interest charges (for debt capital). AFDC amounts capitalized are included in rate base for establishing utility service rates. Interest capitalized as AFDC is listed in the following table:

Environmental Costs — We record environmental costs when it is probable we are liable for the costs and we can reasonably estimate the liability. We may defer costs as a regulatory asset based on our expectation that we will recover these costs from customers in future rates. Otherwise, we expense the costs. If an environmental expense is related to facilities we currently use, such as pollution-control equipment, we capitalize and depreciate the costs over the life of the plant, assuming the costs are recoverable in future rates or future cash flow.

We record estimated remediation costs, excluding inflationary increases and possible reductions for insurance coverage and rate recovery. The estimates are based on our experience, our assessment of the current situation and the technology currently available for use in the remediation. We regularly adjust the recorded costs as we revise estimates and as remediation proceeds. If we are one of several designated responsible parties, we estimate and record only our share of the cost. We treat any future costs of restoring sites where operation may extend indefinitely as a capitalized cost of plant retirement. The depreciation expense levels we can recover in rates include a provision for these estimated removal costs.

Income Taxes — Xcel Energy and its utility subsidiaries, including NSP-Wisconsin, file consolidated federal and combined and separate state income tax returns. Income taxes for consolidated or combined subsidiaries are allocated to the subsidiaries based on separate company computations of taxable income or loss. In accordance with the PUHCA requirements, the holding company also allocates its own net income tax benefits to its direct subsidiaries based on the positive taxable income of each company in the consolidated federal or combined state returns. Xcel Energy’s utility subsidiaries defer income taxes for all temporary

differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. We use the tax rates that are scheduled to be in effect when the temporary differences are expected to turn around, or reverse.

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded, we account for the reversal of some temporary differences as current income tax expense. We defer investment tax credits and spread their benefits over the estimated lives of the related property. Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which we summarize in Note 15 to the Consolidated Financial Statements. For more information on income taxes, see Note 8 to the Consolidated Financial Statements.

Derivative Financial Instruments — NSP-Wisconsin may utilize a variety of derivatives, including interest rate swaps and locks, to reduce exposure to interest rate risk and energy contracts to reduce exposure to commodity price risk. The energy contracts are both financial- and commodity-based in the energy trading and energy nontrading operations. These contracts consist mainly of commodity futures and options, index or fixed price swaps and basis swaps.

Use of Estimates — In recording transactions and balances resulting from business operations, NSP-Wisconsin uses estimates based on the best information available. We use estimates for such items as plant depreciable lives, tax provisions, uncollectible amounts, environmental costs, unbilled revenues and actuarially determined benefit costs. We revise the recorded estimates when we get better information or when we can determine actual amounts. Those revisions can affect operating results. Each year we also review the depreciable lives of certain plant assets and revise them, if appropriate.

Cash Items — NSP-Wisconsin considers investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. Those instruments are primarily commercial paper and money market funds.

Regulatory Accounting — NSP-Wisconsin accounts for certain income and expense items using SFAS No. 71. Under SFAS No. 71:


	•	we defer certain costs, which would otherwise be charged to expense, as regulatory assets based on our expected ability to recover them in future rates; and

	•	we defer certain credits, which would otherwise be reflected as income, as regulatory liabilities based on our expectation they will be returned to customers in future rates.

We base our estimates of recovering deferred costs and returning deferred credits on specific ratemaking decisions or precedent for each item. We amortize regulatory assets and liabilities consistent with the period of expected regulatory treatment.

Intangible Assets and Deferred Financing Costs — Effective Jan. 1, 2002, NSP-Wisconsin implemented SFAS No. 142, “Goodwill and Other Intangible Assets,” which requires different accounting for intangible assets as compared to goodwill. Intangible assets are amortized over their economic useful life and reviewed for impairment in accordance with SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of.” Goodwill is no longer amortized after adoption of SFAS No. 142. Non-amortized intangible assets and goodwill are tested for impairment annually and on an interim basis if an event or circumstance occurs between annual tests that might reduce the fair value of that asset.

NSP-Wisconsin, has immaterial amounts of unamortized intangible assets and no amounts of goodwill as of Dec. 31, 2002 and 2001.

Other assets include deferred financing costs, which we are amortizing over the remaining maturity periods of the related debt. NSP-Wisconsin’s deferred financing costs, net of amortization at Dec. 31, are listed in the following table:

2002 and 2001 — Restaffing — During the fourth quarter of 2001, Xcel Energy expensed pretax special charges of $39 million for expected staff consolidation costs for an estimated 500 employees in several utility operating and corporate support areas of Xcel Energy. Approximately $36 million of these restaffing costs were allocated to Xcel Energy’s utility subsidiaries, including NSP-Wisconsin, consistent with service company cost allocation methodologies utilized under the requirements of the PUHCA. In the first quarter of 2002, the identification of affected employees was completed and additional pretax special charges of $9 million were expensed for the final costs of staff consolidations. Approximately $6 million of these restaffing costs were allocated to Xcel Energy’s utility subsidiaries. All 564 of accrued staff terminations have occurred. See the summary of costs below.

2000 — Merger Costs — Upon consummation of the merger in 2000, Xcel Energy expensed pretax special charges related to its regulated operations totaling $199 million. During 2000, an allocation of approximately $188 million of merger costs was made to Xcel Energy’s utility subsidiaries consistent with prior regulatory filings, in proportion to expected merger savings by the Company and consistent with service company cost allocation methodologies utilized under the requirements of the PUHCA. These costs are reported on the accompanying consolidated financial statements as special charges.

The total pretax charges included $52 million related to one-time transaction related costs incurred in connection with the merger of NSP and NCE. These transaction costs included investment banker fees, legal and regulatory approval costs, and expenses for support of and assistance with planning and completing the merger transaction.

Also included in the total were $147 million of pretax charges pertaining to incremental costs of transition and integration activities associated with merging operations. These transition costs included approximately $77 million for severance and related expenses associated with staff reductions. All 721 of accrued staff terminations have occurred. The staff reductions were non-bargaining positions mainly in corporate and operations support areas. Other transition and integration costs included amounts incurred for facility consolidation, systems integration, regulatory transition, merger communications and operations integration assistance.

Accrued Special Charges — The following table summarizes activity related to accrued special charges in 2002 and 2001:

NSP-Wisconsin has an intercompany borrowing arrangement with NSP-Minnesota, with interest charged at NSP-Minnesota’s short-term borrowing rate. At Dec. 31, 2002 and 2001, NSP-Wisconsin had $6.9 million and $34.3 million, respectively, in short-term borrowings. The weighted average interest rate for NSP-Wisconsin was 4.40 percent at Dec. 31, 2002 and 2.16 percent at Dec. 31, 2001.

All property of NSP-Wisconsin is subject to the lien of its first mortgage indenture, which is a contract between the companies and the bondholders.

The first mortgage bond indenture provides for the ability to have sinking fund requirements. These annual sinking fund requirements are 1 percent of the highest principal amount of the series of first mortgage bond at any time outstanding. Sinking fund requirements at NSP-Wisconsin are $1 million and are for one series of first mortgage bonds. Such sinking fund obligations may be satisfied with property additions or cash.

Maturities and sinking fund requirements for long-term debt are listed in the following table:

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The reasons for the difference are:

Income taxes comprise the following expense (benefit) items (Thousands of dollars):

The components of net deferred tax liability (current and noncurrent portions) at Dec. 31 were:

Xcel Energy offers various benefit plans to its benefit employees. Approximately 51 percent of benefit employees are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2002, NSP-Wisconsin had 419 union employees covered under a collective bargaining agreement, which expires at the end of 2004.

Pension Benefits — Xcel Energy has several noncontributory, defined benefit pension plans that cover almost all utility employees, including those of NSP-Wisconsin. Benefits are based on a combination of years of service, the employee’s average pay and Social Security benefits.

Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws. Plan assets principally consist of the common stock of public companies, corporate bonds and U.S. government securities.

A comparison of the actuarially computed pension benefit obligation and plan assets for Xcel Energy plans which benefit utility subsidiary employees, on a combined basis, is presented in the following table:

During 2002, one of Xcel Energy’s pension plans which provides benefits to employees of a subsidiary other than NSP-Wisconsin became underfunded, with projected benefit obligations of $590 million exceeding plan assets of $452 million on Dec. 31, 2002. All other Xcel Energy plans, which provide benefits to employees of the utility subsidiaries, in the aggregate had plan assets of $2,188 million and projected benefit obligations of $1,916 million on Dec. 31, 2002.

The components of net periodic pension cost (credit) for Xcel Energy plans which benefit employees of its utility subsidiaries are:

Xcel Energy also maintains noncontributory defined benefit supplemental retirement income plans for certain qualifying executive personnel. Benefits for these unfunded plans are paid out of Xcel Energy’s operating cash flows.

Defined Contribution Plans — Xcel Energy maintains 401(k) and other defined contribution plans that cover substantially all employees. Total contributions to these plans, which benefit employees of the utility subsidiaries, were approximately $19 million in 2002, $23 million in 2001, and $24 million in 2000. The contribution for 2002 included $0.7 million for NSP-Wisconsin.

Until May 6, 2002 Xcel Energy had a leveraged employee stock ownership plan (ESOP) that covered substantially all employees of NSP-Minnesota and NSP-Wisconsin. Xcel Energy made contributions to this noncontributory, defined contribution plan to the extent it realized tax savings from dividends paid on certain ESOP shares. ESOP contributions had no material effect on Xcel Energy earnings because the contributions were essentially offset by the tax savings provided by the dividends paid on ESOP shares. Xcel Energy allocated leveraged ESOP shares to participants when it repaid ESOP loans with dividends on stock held by the ESOP.

In May 2002 the ESOP was merged into the Xcel Retirement Savings 401(k) Plan. Starting with the 2003 plan year, the ESOP component of the 401(k) will no longer be leveraged.

Xcel Energy’s leveraged ESOP held no shares of Xcel Energy common stock at the end of 2002, 10.7 million shares of Xcel Energy common stock at May 6, 2002, 10.5 million shares of Xcel Energy common

stock at the end of 2001, and 12.0 million shares of Xcel Energy common stock at the end of 2000. Xcel Energy excluded the following average number of uncommitted leveraged ESOP shares from earnings per share calculations: 0.7 million in 2002, 0.9 million in 2001, and 0.7 million in 2000. On Nov. 19, 2002, Xcel Energy paid off all of the ESOP loans. All uncommitted ESOP shares were released and will be used by Xcel Energy for its employer matching contribution to its 401(k) plan.

Postretirement Health Care Benefits — Xcel Energy has contributory health and welfare benefit plans that provide health care and death benefits to most Xcel Energy retirees. The former NSP discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees of NSP-Minnesota and NSP-Wisconsin who retired after 1999. However, employees of the former NCE who retired in 2002 continue to receive employer subsidized health care benefits. Employees of the former NSP who retired after 1998 are eligible to participate in the Xcel Energy health care program with no employer subsidy.

In conjunction with the 1993 adoption of SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pension,” Xcel Energy elected to amortize the unrecognized accumulated postretirement benefit obligation (APBO) on a straight-line basis over 20 years.

Certain state agencies, which regulate Xcel Energy’s utility subsidiaries, have also issued guidelines related to the funding of SFAS No. 106 costs. Wisconsin retail regulators required external funding of accrued SFAS No. 106 costs to the extent such funding is tax advantaged. Plan assets held in external funding trusts principally consist of investments in equity mutual funds, fixed-income securities and cash equivalents.

A comparison of the actuarially computed benefit obligation and plan assets for Xcel Energy postretirement health care plans that benefit employees of its utility subsidiaries is presented in the following table:

The assumed health care cost trend rate for 2002 is approximately 8 percent, decreasing gradually to 5.5 percent in 2007 and remaining level thereafter. A 1 percent change in the assumed health care cost trend rate would have the following effects:

The components of net periodic postretirement benefit cost of Xcel Energy’s plans are:

The estimated December 31 fair values of recorded financial instruments were as follows:

The carrying amount of cash, cash equivalents, short-term investments and other financial instruments approximates fair value because of the short maturity of those instruments. The fair value of long-term debt is estimated based on the quoted market prices for the same or similar issues, or the current rates for debt of the same remaining maturities and credit quality.

The fair value estimates presented are based on information available to management as of Dec. 31, 2002 and 2001. These fair value estimates have not been comprehensively revalued for purposes of these financial statements since that date and current estimates of fair values may differ significantly from the amounts presented herein.

Business and Operational Risk — NSP-Wisconsin is exposed to commodity price risk in its generation, retail distribution. NSP-Wisconsin has limited exposure to market price risk for the purchase and sale of

electric energy. Electric energy expenses are recovered based on fixed price limits or under established sharing mechanisms.

Interest Rate Risk — NSP-Wisconsin is exposed to fluctuations in interest rates where it enters into variable rate debt obligations to fund certain power projects being developed or purchased. Exposure to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. Xcel Energy’s risk management policy allows NSP-Wisconsin to reduce interest rate exposure from variable rate debt obligations.

With the exception of short-term borrowings, NSP-Wisconsin does not have variable interest rates; therefore there is limited interest rate risk.

NSP-Wisconsin leases, primarily leases of coal-hauling railcars, trucks, cars and power-operated equipment are accounted for as operating leases. The amounts paid under operating leases during 2002 for NSP-Wisconsin are listed in the following table:

Fuel Contracts — The utility subsidiaries of Xcel Energy have contracts providing for the purchase and delivery of a significant portion of their current coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2003 and 2025. In addition, the utility subsidiaries of Xcel Energy are required to pay additional amounts depending on actual quantities shipped under these agreements. The potential risk of loss for the utility subsidiaries of Xcel Energy, in the form of increased costs, from market price changes in fuel is mitigated through the cost-of-energy adjustment provision of the ratemaking process, which provides for recovery of most fuel costs.

We are subject to regulations covering air and water quality, the storage of natural gas and the storage and disposal of hazardous or toxic wastes. We continuously assess our compliance. Regulations, interpretations and enforcement policies can change, which may impact the cost of building and operating our facilities.

Site Remediation — We must pay all or a portion of the cost to remediate sites where past activities of our subsidiaries and some other parties have caused environmental contamination. At Dec. 31, 2002 there were three categories of sites:


	•	third party sites, such as landfills, to which we are alleged to be a potentially responsible party (PRP) that sent hazardous materials and wastes,

	•	the site of a former federal uranium enrichment facility, and

	•	sites of former manufactured gas plants (MGP’s) operated by our subsidiaries or predecessors.

We record a liability when we have enough information to develop an estimate of the cost of remediating a site and revise the estimate as information is received. The estimated remediation cost may vary materially.

To estimate the cost to remediate these sites, we may have to make assumptions where facts are not fully known. For instance, we might make assumptions about the nature and extent of site contamination, the extent of required cleanup efforts, costs of alternative cleanup methods and pollution control technologies, the period over which remediation will be performed and paid for, changes in environmental remediation and pollution control requirements, the potential effect of technological improvements, the number and financial strength of other PRPs and the identification of new environmental cleanup sites.

We revise our estimates as facts become known, but at Dec. 31, 2002 our estimated liability for the cost of remediating sites was:


	•	insurance coverage;

	•	other parties that have contributed to the contamination; and

	•	customers.

Neither the total remediation cost nor the final method of cost allocation among all PRPs of the unremediated sites has been determined. We have recorded estimates of our share of future costs for these sites. We are not aware of any other parties’ inability to pay, nor do we know if responsibility for any of the sites is in dispute.

Asbestos Removal — Some of our facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated. Since we intend to operate most of these facilities indefinitely, we cannot estimate the amount or timing of payments for its final removal. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of

removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Ashland MGP Site — NSP-Wisconsin was named as one of three PRPs for creosote and coal tar contamination at a site in Ashland, Wis. The Ashland site includes property owned by NSP-Wisconsin and two other properties: an adjacent city lakeshore park area and a small area of Lake Superior’s Chequemegon Bay adjoining the park.

The Wisconsin Department of Natural Resources (WDNR) and NSP-Wisconsin have each developed several estimates of the ultimate cost to remediate the Ashland site. The estimates vary significantly, between $4 million and $93 million, because different methods of remediation and different results are assumed in each. The Environmental Protection Agency (EPA) and WDNR have not yet selected the method of remediation to use at the site. Until the EPA and the WDNR select a remediation strategy for all operable units at the site and determine the level of responsibility of each PRP, we are not able to accurately determine our share of the ultimate cost of remediating the Ashland site.

In the interim, NSP-Wisconsin has recorded a liability for an estimate of its share of the cost of remediating the portion of the Ashland site that it owns, estimated using information available to date and using reasonably effective remedial methods. NSP-Wisconsin has deferred, as a regulatory asset, the remediation costs accrued for the Ashland site because we expect that the Public Service Commission of Wisconsin (PSCW) will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized recovery in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site, and has authorized recovery of similar remediation costs for other Wisconsin utilities.

We proposed, and the EPA and WDNR have approved, an interim action (a coal tar removal/ groundwater treatment system) for one operable unit at the site for which NSP-Wisconsin has accepted responsibility. The groundwater treatment system began operating in the fall of 2000. In 2002 NSP-Wisconsin installed additional monitoring wells in the deep aquifer to better characterize the extent and degree of contaminants in that aquifer while the coal tar removal system is operational. In 2002 a second interim response action was also implemented. As approved by the WDNR, this interim response action involved the removal and capping of a seep area in a city park. Surface soils in the area of the seep were contaminated with tar residues. The interim action also included the diversion and ongoing treatment of groundwater that contributed to the formation of the seep.

On Sept. 5, 2002, the Ashland site was placed on the National Priorities List (NPL). The NPL is intended primarily to guide the EPA in determining which sites require further investigation. Resolution of Ashland remediation issues is not expected until 2004 or 2005.

NSP-Wisconsin continues to work with the WDNR to access state and federal funds to apply to the ultimate remediation cost of the entire site.

Plant Emissions — NSP-Wisconsin’s French Island plant generates electricity by burning a mixture of wood waste and refuse derived fuel. The fuel is derived from municipal solid waste furnished under a contract with La Crosse County, Wisconsin. In late 2000, the EPA reversed a prior decision and found that the plant was subject to the federal large combustor regulations. Those regulations became effective on Dec. 19, 2000. NSP-Wisconsin did not have adequate time to install the emission controls necessary to come into compliance with the large combustor regulations by the compliance date. As a result, in early 2001, the EPA issued a finding of violation to NSP-Wisconsin. NSP-Wisconsin is engaged in ongoing settlement discussions with the EPA regarding the finding of violation. In April 2001, a conservation group sent NSP-Wisconsin a notice of intent to sue under the citizen suit provisions of the Clean Air Act. NSP-Wisconsin could be fined up to $27,500 per day for each violation.

In July 2001, the state of Wisconsin filed a lawsuit against NSP-Wisconsin in the Wisconsin Circuit Court for La Crosse County, contending that NSP-Wisconsin exceeded dioxin emission limits on numerous

occasions between July 1995 and December 2000 at French Island. In September 2002, the Court approved a settlement in the case requiring NSP-Wisconsin to pay penalties of $167,579 and contribute $300,000 in installments through 2005 to help fund a household hazardous waste project in the La Crosse area.

In August 2001, NSP-Wisconsin received a Certificate of Authority to install control equipment necessary to bring the French Island plant into compliance with both the federal large combustor regulations and state dioxin standard. NSP-Wisconsin began construction of the new air quality equipment in late 2001 and completed construction in 2002. NSP-Wisconsin has reached an agreement with La Crosse County through which La Crosse County will pay for the extra emissions equipment required to comply with the regulations.

In the normal course of business, NSP-Wisconsin is party to routine claims and litigation arising from prior and current operations. NSP-Wisconsin is actively defending these matters and have recorded an estimate of the probable cost of settlement or other disposition.

NSP-Wisconsin is the defendant in suits claiming electricity and/or stray voltage from NSP-Wisconsin’s system has harmed plaintiffs’ dairy herds and caused other damage and injuries. Total damages claimed in these proceedings are approximately $17.5 million. The ultimate outcome of these claims is not determinable at this time, and NSP-Wisconsin has recorded an estimate of costs necessary to settle or otherwise resolve these matters.

NSP-Wisconsin prepares financial statements in accordance with the provisions of SFAS No. 71, as discussed in Note 1 to the Consolidated Financial Statements. Under SFAS No. 71, regulatory assets and liabilities can be created for amounts that regulators allow us to collect from, or require us to pay back to, customers in future electric and natural gas rates.

Any portion of our business that is not rate regulated cannot use SFAS No. 71 accounting. Efforts to restructure and deregulate the utility industry may further reduce or end our ability to apply SFAS No. 71 in the future. Write-offs and material changes to our balance sheet, income and cash flows may result in such circumstances.

The components of unamortized regulatory assets and liabilities on the balance sheet is:


(d)	Earns a return on investment in the ratemaking process. These amounts are amortized consistent with recovery in rates.

The adoption of SFAS No. 143 in 2003 will also affect Xcel Energy’s accrued plant removal costs for other generation, transmission and distribution facilities for its utility subsidiaries. Although SFAS No. 143 does not recognize the future accrual of removal costs as a Generally Accepted Accounting Principles liability, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long periods over which the amounts were accrued and the changing of rates through time, we have estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accordingly, the estimated amounts of future removal costs, which are considered regulatory liabilities under SFAS No. 143 that are accrued in accumulated depreciation, are as follows at Dec. 31, 2002:


	•	NSP-Wisconsin’s Electric Utility generates, transmits and distributes electricity in Wisconsin and Michigan. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States.

	•	NSP-Wisconsin’s Gas Utility transmits, transports, stores and distributes natural gas and propane primarily in portions of Wisconsin and Michigan.

Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the All Other category.

To report net income for electric and natural gas utility segments, NSP-Wisconsin must assign or allocate all costs and certain other income. In general, costs are:


	•	directly assigned wherever applicable;

	•	allocated based on cost causation allocators wherever applicable; or

	•	allocated based on a general allocator for all other costs not assigned by the above two methods.

The accounting policies of the segments are the same as those described in Note 1 to the Consolidated Financial Statements. NSP-Wisconsin evaluates performance by each legal entity based on profit or loss.

NSP-Wisconsin receives various administrative, management, environmental and other support services from Xcel Energy Services Inc., which began operations in August 2000. Prior to this, all of these support services resided in former NSP for NSP-Minnesota and NSP-Wisconsin and were allocated to the former NSP subsidiaries, as appropriate.

Viking Gas Transmission Co. (Viking), a subsidiary of Xcel Energy through 2002, transports gas purchased by NSP-Wisconsin from various suppliers. NSP Wisconsin purchased $1.6 million of transportation service from Viking during 2002.

The electric production and transmission costs of the entire NSP system are shared by NSP-Minnesota and NSP-Wisconsin. A FERC approved agreement (Interchange Agreement) between the two companies provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs. Billings under the Interchange Agreement, which are included in the Consolidated Statements of Income, are as follows:


*	Other operations expense includes $272,825, $289,339, and $543,013 paid to Xcel Energy Services Inc. in 2002, 2001 and 2000.


*	Other operations expense includes $36,695, $28,816, and $42,509 paid to Xcel Energy Services Inc. in 2002, 2001 and 2000.

NSP-Wisconsin obtains short-term borrowings from NSP-Minnesota at NSP-Minnesota’s average daily interest rate, including the cost of NSP-Minnesota’s compensating balance requirements. Corresponding interest charges on NSP-Wisconsin’s statement of income and other income on NSP-Minnesota’s statement of income include $0.2 million, $0.4 million, and $3.4 million for 2002, 2001, and 2000.

NSP-Minnesota’s receivables from affiliates include amounts receivable from NSP-Wisconsin for the Interchange Agreement and short-term borrowings. NSP-Minnesota’s payable to affiliates primarily repre-

sents amounts payable to Xcel Energy Services Inc. for NSP-Minnesota’s allocation of support services from Xcel Energy Services Inc.

NSP-Wisconsin’s receivable from affiliates primarily represents amounts receivable from NSP-Minnesota for the Interchange Agreement. NSP-Wisconsin’s notes payable to affiliates represents amounts payable to NSP-Minnesota.


(a)	2001 results include special charges as discussed in Note 2 to the Financial Statements. Fourth quarter results were decreased by $2 million for a pretax special charge related to employee restaffing costs.

See disclosures regarding NSP-Wisconsin in the Notes to Consolidated Financial Statements

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly the financial position of NSP-Wisconsin as of Sept. 30, 2003, and Dec. 31, 2002; the results of their operations for the three and nine months ended Sept. 30, 2003 and 2002; and their cash flows for the nine months ended Sept. 30, 2003 and 2002. Due to the seasonality of electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

The accounting policies of NSP-Wisconsin are set forth in Note 1 to its consolidated financial statements beginning on page F-4 of this prospectus. The following notes should be read in conjunction with such policies and other disclosures contained elsewhere in the prospectus.

Certain items in the 2002 statement of operations, statement of cash flows and balance sheet have been reclassified to conform to the 2003 presentation. These reclassifications had no effect on Stockholder’s Equity or Net Income as previously reported.

NSP-Wisconsin adopted Statement of Financial Accounting Standard (SFAS) No. 143 — “Accounting for Asset Retirement Obligations” (SFAS No. 143) effective Jan. 1, 2003. As required by SFAS No. 143, future plant decommissioning obligations were recorded as a liability at fair value as of Jan. 1, 2003, with a corresponding increase to the carrying values of the related long-lived assets. This liability will be increased over time by applying the interest method of accretion to the liability, and the capitalized costs will be depreciated over the useful life of the related long-lived assets. The adoption of the statement had no income statement impact, as the cumulative effect adjustments required under SFAS No. 143 have been deferred through the establishment of a regulatory asset pursuant to SFAS No. 71 — “Accounting for the Effects of Certain Types of Regulation.”

The adoption of SFAS No. 143 in 2003 affects accrued plant removal costs for other generation, transmission and distribution facilities for NSP-Wisconsin. Although SFAS No. 143 does not recognize the future accrual of removal costs as a Generally Accepted Accounting Principles liability, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long periods over which the amounts were accrued and the changing of rates through time, NSP-Wisconsin has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accordingly, the estimated amounts of future removal costs, which are considered regulatory liabilities under SFAS No. 71 that are accrued in accumulated depreciation, are as follows at Jan. 1, 2003:

Utility Restaffing (2002) — During the fourth quarter of 2001, Xcel Energy recorded an estimated liability for expected staff consolidation costs for an estimated 500 employees in several utility operating and corporate support areas of Xcel Energy. In the first quarter of 2002, the identification of affected employees was completed and additional pretax special charges of $9 million were expensed for the final costs of the utility-related staff consolidations. Approximately $6 million of these restaffing costs were allocated to the utility subsidiaries, including NSP-Wisconsin. All 564 of accrued staff terminations occurred in 2002 and as of Sept. 30, 2003, all severance payments have been made.

Midwest Independent Transmission System Operator, Inc. (MISO) Electric Market Initiative — On July 25, 2003, MISO filed proposed changes to its regional open access transmission tariff to implement a new Transmission and Energy Markets Tariff (TEMT) that would establish certain wholesale energy and transmission service rates based on locational marginal cost pricing (LMP) to be effective in 2004. NSP-Minnesota and NSP-Wisconsin presently receive transmission services from MISO for service to their retail loads and would be subject to the new tariff, if approved by the FERC. After numerous parties, including several states, filed protests to the proposal, MISO filed on Oct. 17, 2003, to withdraw the TEMT without prejudice to refiling. The FERC issued an order approving the withdrawal and provided guidance on MISO’s proposals on Oct. 29, 2003. MISO is now starting the stakeholder consultation process to prepare and submit a revised TEMT in 2004. Management believes any new tariff, if approved by the FERC, could have a material effect on wholesale power supply or transmission service costs to NSP-Minnesota and NSP-Wisconsin.

NSP-Wisconsin General Rate Case — On June 1, 2003, NSP-Wisconsin filed its required biennial rate application with the Public Service Commission of Wisconsin (PSCW) requesting no change in Wisconsin retail electric and natural gas base rates. NSP-Wisconsin requested the PSCW approve its application without hearing, pending completion of the Staff’s audit. An order is expected in late 2003 or early 2004.

TRANSLink Transmission Co., LLC (TRANSLink) — In 2002, NSP-Minnesota filed for MPUC approval to transfer functional control of its transmission system to TRANSLink, a proposed independent transmission company. In June 2003, the MPUC held a hearing on the TRANSLink application. At the hearing, the MPUC deferred any decision and indicated NSP-Minnesota could submit a supplemental or revised application to explain certain recent changes to the proposal and to respond to a number of issues and questions posed by the MPUC advisory staff and other parties. On Nov. 3, 2003, NSP-Minnesota submitted a status report to the MPUC indicating the participants are evaluating the TRANSLink proposal in light of recent events and would provide a further report within 30 days. Similar filings in North Dakota and Wisconsin are not contested, but have not been approved.

Xcel Energy is considering these developments, as well as the proceedings in process in other jurisdictions, to evaluate the future role of TRANSLink in providing transmission operations services for the Xcel Energy system. As of Sept. 30, 2003, Xcel Energy’s subsidiaries had deferred approximately $5 million of TRANSLink-related costs based on anticipated recovery in future rates.

Lawsuits and claims arise in the normal course of business. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition of them. The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution of these matters could have a material adverse effect on NSP-Wisconsin’s financial position and results of operations.

French Island (NSP-Wisconsin) — On Oct. 20, 2003, the U.S. District Court in Madison, Wisconsin entered a consent decree settling the EPA’s claims against NSP-Wisconsin related to the French Island generating plant, but denying any liability. The consent decree is now enforceable. On or before Nov. 19, 2003, NSP-Wisconsin will pay a civil penalty of $500,000. At Sept. 30, 2003, NSP-Wisconsin has accrued all costs related to this matter.

Other Environmental Contingencies — NSP-Wisconsin has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, NSP-Wisconsin is pursuing, or intends to pursue, insurance claims and believes it will recover some portion of these costs through such claims. Additionally, where applicable, NSP-Wisconsin is pursuing, or intends to pursue, recovery from other potentially responsible parties and through the rate regulatory process. To the extent any costs are not recovered through the options listed above, NSP-Wisconsin would be required to recognize an expense for such unrecoverable amounts in its consolidated financial statements.

Other — The circumstances set forth in Notes 13 and 14 to the consolidated financial statements for the year ended Dec. 31, 2002 contained elsewhere in this prospectus, appropriately represent, in all material respects, the current status of commitments and contingent liabilities and are incorporated herein by reference.

Financing Activity — On Oct. 2, 2003, NSP-Wisconsin issued $150 million of 5.25-percent first mortgage bonds due Oct. 1, 2018, in a private placement to qualified institutional buyers. The proceeds were used to repay short-term borrowings incurred to pay at maturity $40 million of 5.75 percent first mortgage bonds due Oct. 1, 2003, and to redeem $110 million of 7.25 percent first mortgage bonds. On Oct. 15, 2003, NSP-Wisconsin redeemed the $110 million of 7.25-percent first mortgage bonds, due March 1, 2023.

Dividend Restrictions — NSP-Wisconsin has dividend restrictions imposed by state regulatory commissions, debt agreements and the SEC under the PUHCA limiting the amount of dividends NSP-Wisconsin can pay to Xcel Energy. These restrictions include, but may not be limited to:


	•	maintenance of an equity ratio of 52 percent to 57 percent; and

	•	payment of dividends only from retained earnings.

NSP-Wisconsin analyzes derivative financial instruments in accordance with SFAS No. 133 — “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). This statement requires that all derivative instruments as defined by SFAS No. 133 be recorded on the balance sheet at fair value unless exempted. Changes in a derivative instrument’s fair value must be recognized currently in earnings unless the derivative has been designated in a qualifying hedging relationship. The application of hedge accounting allows a derivative instrument’s gains and losses to offset related results of the hedged item in the statement of operations, to the extent effective. SFAS No. 133 requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.

The impact of the components of SFAS No. 133 on Other Comprehensive Income, included in Stockholder’s Equity, are detailed in the following tables:


*	In accordance with SFAS No. 71 — “Accounting for the Effects of Certain Types of Regulation,” certain costs/ benefits have been deferred as they are expected to be recovered in future periods from customers.

NSP-Wisconsin enters into derivative instruments to manage variability of future cash flows from changes in commodity prices. These derivative instruments are designated as cash flow hedges for accounting purposes, and the changes in the fair value of these instruments are recorded as a component of Other Comprehensive Income. At Sept. 30, 2003, NSP-Wisconsin had various commodity-related contracts deemed as cash flow hedges extending through 2009. Amounts deferred in Other Comprehensive Income are recorded in earnings as the hedged purchase or sales transaction is settled. This could include the physical purchase or sale of electric energy, the use of natural gas to generate electric energy or gas purchased for resale. As of Sept. 30, 2003, NSP-Wisconsin had no gains or losses accumulated in Other Comprehensive Income that are expected to be recognized in earnings during the next 12 months as the hedged transactions settle. However, due to the volatility of commodities markets, the value in Other Comprehensive Income will likely change prior to its recognition in earnings.

NSP-Wisconsin enters into interest rate lock agreements that effectively fix the yield or price on a specified treasury security for a specific period. These derivative instruments are designated as cash flow hedges for accounting purposes, and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. NSP-Wisconsin expects to reclassify into earnings during the next 12 months net losses from other Comprehensive Income of approximately $0.1 million.

Hedge effectiveness is recorded based on the nature of the item being hedged. Hedging transactions for the sales of electric energy are recorded as a component of revenue, hedging transactions for fuel used in energy generation are recorded as a component of fuel costs, hedging transactions for gas purchased for resale are recorded as a component of gas costs and hedging transactions for interest rate swaps and interest rate lock agreements are recorded as a component of interest expense. Certain Xcel Energy Utility Subsidiaries are allowed to recover in electric or gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.

NSP-Wisconsin enters into contracts for the purchase and sale of various commodities for use in their business operations. SFAS No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that literally meet the definition of a derivative may be exempted from SFAS No. 133 as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that meet the requirements of normal are documented and exempted from the accounting and reporting requirements of SFAS No. 133.

NSP-Wisconsin evaluates all of its contracts when such contracts are entered to determine if they are derivatives and, if so, if they qualify and meet the normal designation requirements under SFAS No. 133.

Normal purchases and normal sales contracts are accounted for as executory contracts as required under other generally accepted accounting principles.

SFAS No. 149 — In April 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 149 — “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS No. 149), which amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133. SFAS No. 149 clarifies the discussion around initial net investment, clarifies when a derivative contains a financing component and amends the definition of an underlying to conform it to language used in FASB Interpretation No. 45. In addition, SFAS No. 149 also incorporates certain implementation issues of a derivative

implementation group. The provisions of SFAS No. 149 have been applied to contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003.

SFAS No. 133 Implementation Issue No. C20 — In June 2003, for purposes of determining the applicability of the normal purchases and normal sales scope exception, the FASB issued SFAS No. 133 Implementation Issue No. C20 as supplemental guidance to SFAS No. 133 Implementation Issue No. C11. The effective date of the Implementation guidance of Issue No. C20 is the during fourth quarter of 2003 for Xcel Energy’s Utility Subsidiaries. NSP-Wisconsin is currently in the process of reviewing and interpreting this guidance and do not currently anticipate any material adverse financial impact due to the implementation of Issue No. C20 guidance as a result of the ability to recover prudently-incurred purchased capacity costs from customers.

NSP-Wisconsin has two reportable segments, Electric Utility and Natural Gas Utility. All Other represents activity of unregulated subsidiaries and other operations of NSP-Wisconsin.

In 2003, the process to allocate common costs of the Electric and Natural Gas Utility segments was revised. Segment results for 2002 have been restated to reflect the revised cost allocation process.

The accumulated comprehensive income in stockholder’s equity at Sept. 30, 2003 and 2002, relates to valuation adjustments on NSP-Wisconsin’s derivative financial instruments and hedging activities, the related regulatory deferral and the mark-to-market components of NSP-Wisconsin’s marketable securities.

UNTIL SEPTEMBER 5, 2004, ALL DEALERS THAT EFFECT TRANSACTIONS IN THESE SECURITIES, WHETHER OR NOT PARTICIPATING IN THIS OFFERING, MAY BE REQUIRED TO DELIVER A PROSPECTUS. THIS IS IN ADDITION TO THE DEALERS’ OBLIGATION TO DELIVER A PROSPECTUS WHEN ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR UNUSED ALLOTMENTS OR SUBSCRIPTIONS.


SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
OUR COMPANY
RISK FACTORS
USE OF PROCEEDS
THE EXCHANGE OFFER
CAPITALIZATION
SELECTED CONSOLIDATED FINANCIAL DATA
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
BUSINESS
MANAGEMENT
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
DESCRIPTION OF OTHER INDEBTEDNESS
DESCRIPTION OF THE EXCHANGE FIRST MORTGAGE BONDS
BOOK-ENTRY SYSTEM
EXCHANGE OFFER AND REGISTRATION RIGHTS
MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
PLAN OF DISTRIBUTION
LEGAL OPINIONS
EXPERTS
WHERE YOU CAN FIND MORE INFORMATION


Use of Proceeds		We will not receive any proceeds from the issuance of the exchange first mortgage bonds. We are making the exchange offer solely to satisfy our obligations under the registration rights agreement that we entered into in connection with the private offering of the original first mortgage bonds.

Risk Factors		See “Risk Factors” and the other information in this prospectus for a discussion of factors you should carefully consider before deciding to exchange your original first mortgage bonds for exchange first mortgage bonds.



				December 31,
		September 30,
		2003		2002		2001		2000		1999		1998


		(Thousands of dollars)
Consolidated Balance Sheet Data:
Current assets		$	89,683	$	101,201	$	87,658	$	113,122	$	86,748	$	88,297
Net property, plant and equipment			820,982		815,619		821,717		802,036		752,771		709,784
Other assets			108,958		104,063		82,883		70,917		67,584		65,630

	Total assets	$	1,019,623	$	1,020,883	$	992,258	$	986,075	$	907,103	$	863,711

Current portion of long-term debt		$	40,034	$	40,034	$	34	$	34	$	0	$	0
Other current liabilities			56,665		69,736		82,285		99,034		137,539		104,619

	Total current liabilities		96,699		109,770		82,319		99,068		137,539		104,619
Deferred credits and other liabilities			232,320		219,267		187,339		183,738		180,614		179,598
Long-term debt			273,173		273,108		313,054		313,000		231,950		231,863
Common stockholder’s equity			417,431		418,738		409,546		390,269		357,000		347,631

	Total liabilities and equity	$	1,019,623	$	1,020,883	$	992,258	$	986,075	$	907,103	$	863,711


	Nine months			Nine months
	ended			ended			Year ended			Year ended			Year ended
	September 30,			September 30,			December 31,			December 31,			December 31,
	2003			2002			2002			2001			2000


	(Millions of dollars)
Electric utility revenue	$	358		$	349		$	459		$	451		$	424
Electric fuel and purchased power		(175	)		(160	)		(212	)		(233	)		(210	)

Gross margin before operating expenses	$	183		$	189		$	247		$	218		$	214

Margin as percentage of revenue		51.1	%		54.2	%		53.8	%		48.3	%		50.5	%


	Nine months			Nine months
	ended			ended			Year ended			Year ended			Year ended
	September 30,			September 30,			December 31,			December 31,			December 31,
	2003			2002			2002			2001			2000


	(Millions of dollars)
Gas utility revenue	$	90		$	67		$	102		$	123		$	110
Cost of gas sold and transported		(68	)		(47	)		(72	)		(96	)		(82	)

Gas utility margin	$	22		$	20		$	30		$	27		$	28


	Page

Special Note Regarding Forward-Looking Statements		i
Summary		1
Risk Factors		10
Use of Proceeds		22
The Exchange Offer		22
Capitalization		31
Selected Consolidated Financial Data		32
Management’s Discussion and Analysis of Financial Condition and Results of Operations		33
Business		48
Management		64
Certain Relationships and Related Transactions		75
Description of Other Indebtedness		76
Description of the Exchange First Mortgage Bonds		77
Book-Entry System		84
Exchange Offer and Registration Rights		86
Material United States Federal Income Tax Considerations		88
Plan of Distribution		89
Legal Opinions		90
Experts		90
Where You Can Find More Information		90
Index to Financial Statements		F-1


	•	the exchange first mortgage bonds will have been registered under the Securities Act;

	•	the exchange first mortgage bonds will not contain transfer restrictions; and

	•	the exchange first mortgage bonds will not have the registration rights that apply to the original first mortgage bonds or entitle their holders to additional interest in the event we fail to comply with these registration rights.


(1)	For purposes of computing the ratio of earnings to fixed charges, (1) earnings consist of net income plus fixed charges, federal and state income taxes, deferred income taxes and investment tax credits; and (2) fixed charges consist of interest on long-term debt, other interest charges, the interest component on leases and amortization of debt discount, premium and expense.


	Xcel Energy is subject to regulatory restrictions on accessing capital. If Xcel Energy fails to meet financing conditions imposed on it by the SEC under PUHCA, Xcel Energy would be prevented from raising capital by issuing securities, forcing us to seek alternate sources of funds to meet our cash needs.


	In 2002, our credit ratings were lowered and could be further lowered as a consequence of changes in the credit ratings of our affiliates or otherwise. If this were to occur, the value of the exchange first mortgage bonds could be reduced.


	*Any reduced access to sources of liquidity may increase our cost of capital and our dependence on bank lenders and external capital markets.*


	We are a wholly owned subsidiary of Xcel Energy. Xcel Energy can, within certain regulatory limitations and the limitations provided by corporate law, exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.


	*Recent and ongoing lawsuits relating to Xcel Energy’s former ownership of NRG could impair Xcel Energy’s profitability and liquidity and could divert the attention of our management.*


	Our profitability depends on our ability to recover costs from our customers and there may be changes in circumstances or in the regulatory environment that impair our ability to recover costs from our customers.


	*We are facing increased scrutiny from our state regulators as a result of the financial situation at Xcel Energy and NRG.*


	We share in the electric production and transmission costs of the NSP-MN system, which is integrated with our system. Accordingly, our costs may be increased due to increased costs associated with NSP-MN’s system.


	Although we do not own any nuclear generating facilities, because our production and transmission system is operated on an integrated basis with NSP-MN’s production and transmission system, we may be subject to the risks associated with NSP-MN’s nuclear generation.



By Registered, Certified or by Hand or Overnight Delivery: U.S. Bank National Association Corporation Trust Services EP-MN-WS3C 60 Livingston Avenue St. Paul, MN 55107		By Facsimile: Attention: Frank P. Leslie, III (651) 495-8097



		As of September 30, 2003
		(unaudited)

		(Thousands of dollars)		(% of Capitalization)

Short-term debt (including current maturities)		$	40,034		5.5	%
Long-term debt			273,173		37.4	%
Common stockholder’s equity			417,431		57.1	%

	Total capitalization	$	730,638		100.0	%


Accounting Policy		Judgments/ Uncertainties Affecting Application

Regulatory Mechanisms and Cost Recovery		• External regulatory decisions, requirements and regulatory environment
		• Anticipated future regulatory decisions and their impact
		• Impact of deregulation and competition on ratemaking process and ability to recover costs
Environmental Issues		• Approved methods for cleanup
		• Responsible party determination
		• Governmental regulations and standards
		• Results of ongoing research and development regarding environmental impacts
Benefit Plan Accounting		• Future rate of return on pension and other plan assets, including impacts of changes to investment portfolio composition


Accounting Policy		Judgments/ Uncertainties Affecting Application

		• Interest rates used in valuing benefit obligation
		• Actuarial period selected to recognize deferred investment gains and losses


	2003		2004		2005


	(Thousands of dollars)
Total capital expenditures	$	52,972	$	51,241	$	47,930
Sinking funds and debt maturities		41,134		1,134		1,134

Total capital requirements	$	94,106	$	52,375	$	49,064



	Payments Due by Period

			Less than
Contractual Obligations	Total		1 Year		1-3 Years		4-5 Years		After 5 Years


	(Thousands of dollars)
Long-term debt	$	314,529	$	41,134	$	2,268	$	2,268	$	268,859
Operating leases		207,998		34,605		70,646		71,510		31,237
Unconditional purchase obligations		91,885		46,837		29,652		10,576		4,820
Other long-term obligations		—		—		—		—		—
Short-term debt		—		—		—		—		—

Total contractual cash obligations	$	614,412	$	122,576	$	102,566	$	84,354	$	304,916


Company	Credit Type	Moody’s*		Standard & Poor’s**

NSP-W	Senior Unsecured Debt		Baa1		BBB
NSP-W	Senior Secured Debt		A3		BBB+
NSP-MN	Senior Unsecured Debt		Baa1		BBB-
NSP-MN	Senior Secured Debt		A3		BBB+
NSP-MN	Commercial Paper		P2		A2



	Coal*					Nuclear
											Average
NSP-System generating plants:	Cost		Percent			Cost		Percent			Fuel Cost

First Nine Months of 2003.	$	0.99		62	%	$	0.44		36	%	$	0.95
2002	$	0.96		59	%	$	0.46		38	%	$	0.81
2001	$	0.96		62	%	$	0.47		35	%	$	0.86
2000	$	1.11		60	%	$	0.45		36	%	$	0.91


				Summer 2002
				Net Dependable
Station and Unit		Fuel	Installed	Capability (Mw)

Combustion Turbine:
Flambeau Station — Park Falls, Wisconsin		Natural Gas/Oil	1969		12
Wheaton — Eau Claire, Wisconsin
	6 Units	Natural Gas/Oil	1973		345
French Island — La Crosse, Wisconsin
	2 Units	Oil	1974		142
Steam:
Bay Front — Ashland, Wisconsin
	3 Units	Coal/Wood/ Natural Gas	1945-1960		76
French Island — La Crosse, Wisconsin
	2 Units	Wood/RDF*	1940-1948		27
Hydro:
	19 Plants		Various		249

			Total		851


*	RDF is refuse derived fuel, made from municipal solid waste.



Structure Miles

500 kilovolt (kv)			—
345 kv			1,312
230 kv			—
161 kv			1,494
138 kv			—
115 kv			1,528
Less than 115 kv			31,076


Name	Age		Position

Michael L. Swenson		53	President, Chief Executive Officer and Director
Wayne H. Brunetti		61	Chairman of the Board*
Gary R. Johnson		57	Vice President, General Counsel and Director
Benjamin G.S. Fowke III		45	Vice President, Chief Financial Officer and Treasurer*
David E. Ripka		54	Vice President and Controller*,†
Teresa S. Madden		47	Vice President and Controller*,††
Richard C. Kelly		57	Vice President and Director*
Cathy J. Hart		54	Vice President and Secretary*
Paul Bonavia		52	Vice President*
Raymond E. Gogel		53	Vice President*
Cynthia L. Lesher		55	Vice President*
David M. Wilks		57	Vice President*


							Options
Name and Principal Position of		Common			Stock		Exercisable		Restricted
Beneficial Owner		Stock			Equivalents		Within 60 Days		Stock		Total

Michael L. Swenson			4,045.00			0		13,295		79.38	17,419.38
	President, Chief Executive Officer and Director
Wayne H. Brunetti			109,377.88			13,175.18		692,850		25,245.99	840,649.05
	Chairman of the Board(1)
Richard C. Kelly			34,201.83	*		3,533.02		224,750		3,312.22	265,797.07
	Vice President and Director(2)
Gary R. Johnson			20,407.33			0		109,505		0	129,912.33
	Vice President, General Counsel and Director(3)
Paul J. Bonavia			5,662.74			1,440.07		186,000		0	193,102.81
	Vice President(4)
J. T. Petillo			17,650.83			1,304.59		112,530		0	131,485.42
	Former Vice President (5)
Directors and Executive Officers as a group (13 persons)			281,846.56			26,735.71		1,698,917		33,613.21	2,041,112.48


	*	Mr. Kelly disclaims beneficial ownership of 4,904.84 shares



				Annual Compensation						Long-Term Compensation


										Awards				Payouts

(a)		(b)		(c)		(d)		(e)		(f)		(g)		(h)		(i)

												Number of
										Restricted		Securities
								Other Annual		Stock		Underlying		LTIP		All Other
								Compensation		Awards		Options and		Payouts		Compensation
Name and Principal Position		Year		Salary($)		Bonus($)(1)		($)(2)		($)(3)		SAR’s(#)		($)(4)		($)(5)


Michael L. Swenson			2003		180,000		—		—		—		—		—		4,012
	President and Chief Executive		2002		177,879		—		—		—		—		—		5,711
	Officer		2001		140,000		77,719		—		—		—		40,778		465
Wayne H. Brunetti			2003		1,065,000		—		3,288		—		—		—		5,337
	Chairman of the Board		2002		1,065,000		—		9,836		—		—		—		95,832
			2001		895,000		953,873		9,267		—		—		902,271		81,360
Richard C. Kelly			2003		532,361		—		2,127		—		—		—		2,550
	Vice President		2002		510,000		—		3,817		—		—		—		45,917
			2001		425,417		338,588		1,208		—		—		269,633		39,077
Gary R. Johnson			2003		390,000		—		1,091		—		—		—		2,142
	Vice President and General		2002		390,000		—		1,329		—		—		—		26,656
	Counsel		2001		340,000		236,656		3,934		—		—		175,206		27,640
Paul J. Bonavia			2003		385,000		—		11,198		—		—		—		1,324
	Vice President		2002		385,000		—		3,956		—		—		—		9,278
			2001		350,000		262,920		15,416		—		—		180,338		16,503
James T. Petillo*			2003		230,000		—		4,063		—		—		—		2,807,841
	Vice President		2002		345,000		—		1,617		—		—		—		15,157
			2001		316,250		200,463		12,978		—		—		149,408		15,562



					Number of Securities				Value of Unexercised
					Underlying Unexercised				In-the-Money
	Shares				Options/SARs at				Options/SARs at
	Acquired on		Value		FY-End(#)				FY-End($)
	Exercise		Realized
Name	(#)		($)		Exercisable		Unexercisable		Exercisable		Unexercisable

Michael L. Swenson		—		—		13,295		36,000		—		—
Wayne H. Brunetti		—		—		692,850		756,000		—		—
Richard C. Kelly		—		—		224,750		228,000		—		—
Gary R. Johnson		—		—		109,505		147,000		—		—
Paul J. Bonavia		—		—		186,000		153,000		—		—
James T. Petillo		—		—		112,530		126,000		—		—



	Number of					Estimated Future Payouts Under
	Shares, Units			Performance or		Non-Stock Price-Based Plans
	or Other			Other Period Until
Name	Rights(#)(1)			Maturation or Payout		Threshold($)(2)		Target($)(#)			Maximum($)

Michael L. Swenson		8,514	(2)		1/1/03-12/31/05	$	23,625	$	94,500		$	189,000
		7,309	(3)		3/28/03-3/28/07		—		7,309	#		7,309	#
Wayne H. Brunetti		218,277	(2)		1/1/03-12/31/05	$	605,719	$	2,422,875		$	4,845,750
		187,384	(3)		3/28/03-3/28/07		—		187,384	#		187,384	#
Richard C. Kelly		67,770	(2)		1/1/03-12/31/05	$	188,063	$	752,250		$	1,504,500
		58,179	(3)		3/28/03-3/28/07		—		58,179	#		58,179	#
Gary R. Johnson		39,527	(2)		1/1/03-12/31/05	$	109,688	$	438,750		$	877,500
		33,933	(3)		3/28/03-3/28/07		—		33,933	#		33,933	#
Paul J. Bonavia		39,020	(2)		1/1/03-12/31/05	$	108,281	$	433,125		$	866,250
		33,498	(3)		3/28/03-3/28/07		—		33,498	#		33,498	#
James T. Petillo		34,966	(2)		1/1/03-12/31/05	$	97,031	$	388,125		$	766,250
		30,017	(3)		3/28/03-3/28/07		—		30,017	#		30,017	#


Mr. Swenson			270
Mr. Brunetti			6,931
Mr. Kelly			2,152
Mr. Johnson			1,255
Mr. Bonavia			1,239
Mr. Petillo			1,110