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We are offering to exchange notes registered under the Securities Act of 1933, as amended, for a like principal amount of original notes that we issued in a private placement that closed on October 6, 2003.

The terms of the exchange notes are substantially identical to the terms of the original notes, except that the exchange notes will not contain transfer restrictions and will not have the registration rights that apply to the original notes 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.

JPMorgan Chase Bank is serving as the exchange agent. If you wish to tender your original notes, 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 notes at any time prior to the expiration of the exchange offer. We will exchange all original notes that are validly tendered and not withdrawn prior to the expiration of the exchange offer.

Any outstanding original notes not validly tendered will remain subject to existing transfer restrictions.

There is no existing market for the exchange notes 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 notes for exchange notes will not be taxable for United States federal income tax purposes. See “Material United States Federal Income Tax Considerations.”

The exchange notes will have the same terms and covenants as the original notes, 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 notes 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,” “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, including the status and implementation of restructuring legislation in Texas and New Mexico, our two primary jurisdictions;

	•	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 notes for exchange notes. The term “original notes” as used in this prospectus refers to our outstanding series C senior notes, 6% due 2033 that we issued on October 6, 2003 and that have not been registered under the Securities Act of 1933, as amended (the “Securities Act”). The term “exchange notes” refers to our series D senior notes, 6% due 2033 offered under this prospectus.

In this prospectus, except as otherwise indicated or as the context otherwise requires, “Southwestern Public Service Company,” “SPS,” “we,” “our,” and “us” refer to Southwestern Public Service Company, a New Mexico corporation.

Our Company

General

We are an operating utility engaged primarily in the generation, transmission, distribution and sale of electricity. We serve approximately 390,000 retail electric customers in portions of Texas, New Mexico, Oklahoma and Kansas. A major portion of our retail revenue is derived from operations in Texas. We derive a significant portion of our operating revenues from the wholesale sale of electric capacity and energy. Substantially all of this part of our business is comprised of sales of capacity and/or energy from our own generating facilities under long-term contracts.

We were incorporated in 1921 under the laws of the State of New Mexico. On August 1, 1997, we combined with Public Service Company of Colorado to form New Century Energies, Inc. (“NCE”), and we became a wholly owned subsidiary of NCE, a registered holding company under the Public Utility Holding Company Act of 1935 (“PUHCA”). On August 18, 2000, NCE merged into Northern States Power Company (“NSP”), which subsequently changed its name to Xcel Energy Inc. (“Xcel Energy”). We are now a wholly owned subsidiary of Xcel Energy. Xcel Energy is a registered holding company under PUHCA. Xcel Energy is a publicly held company and files periodic reports and other documents with the Securities and Exchange Commission (“SEC”). A majority of the members of our Board of Directors and many of our executive officers are also executive officers of Xcel Energy.

Among Xcel Energy’s other subsidiaries are Northern States Power Company, a Minnesota corporation (“NSP-Minnesota”), Public Service Company of Colorado, a Colorado corporation (“PSCo”), Northern States Power Company, a Wisconsin corporation (“NSP-Wisconsin”) and Cheyenne Light, Power and Fuel Company, a Wyoming corporation (“Cheyenne”). 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 that it had entered into an agreement with Black Hills Corp. for the sale of Cheyenne, pending regulatory approvals.

At December 31, 2003, we owned a direct subsidiary, Southwestern Public Service Capital I (“SPS Capital I”), a special purpose financing trust formed under the laws of the State of Delaware. SPS Capital I was dissolved on January 5, 2004.

Our principal executive offices are located at Tyler at Sixth Street, Amarillo, Texas 79101, and our telephone number is (303) 571-7511.

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.

The Public Utility Commission of Texas (“PUCT”) has jurisdiction over our Texas operations as an electric utility and over our retail rates and services. The municipalities in which we operate in Texas have original jurisdiction over our rates in those communities. The New Mexico Public Regulatory Commission (“NMPRC”) has jurisdiction over the issuance of securities and accounting. The NMPRC, the Oklahoma Corporation Commission (“OCC”) and the Kansas Corporation Commission (“KCC”) have jurisdiction with respect to retail rates and services in their respective states. 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 have received authorization from the FERC to make wholesale electricity sales at market-based prices.

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, of 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.


	*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.


	*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 us, 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 functions and from our “energy affiliates” (as defined by the final rule). Full compliance with the standards of conduct rules 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 Southwest Power Pool (“SPP”), the regional reliability council and power pool for the SPS system, filed in October 2003 for FERC authorization to transform its operation into a Regional Transmission Organization (“RTO”) under regulations issued by the FERC in 1999, known as FERC Order No. 2000. If we become a member of the SPP RTO, we would be required to transfer functional control of our electric transmission system to SPP. In addition, SPP made unilateral changes to the existing SPP membership agreement in a manner which increases the current costs of our membership in SPP by approximately $1.5 million per year. On October 31, 2003, we submitted a conditional notice of withdrawal from SPP in order to preserve our flexibility with regard to future RTO membership.


	*State Regulatory Matters*

Beginning in April 2003, we estimated electricity usage for approximately 9,500 customer accounts in two New Mexico cities. Estimated bills were sent to these customers for between two and five months. On September 25, 2003, the NMPRC entered an order opening an investigation into our practices regarding estimated billing. The commission ordered us to show cause why we are not in violation of the commission rule that limits the use of estimated meter readings.

As part of the September 25, 2003 order, the NMPRC also implemented temporary billing measures for customers whose bills were estimated. The temporary billing measures: (i) require us to apply the lowest fuel and purchased power cost adjustment factor that was applicable during the period when bills were being estimated, (ii) allow customers 6 months to pay bills in full without additional charges or disconnection, (iii) prohibited disconnection of service until November 1, 2003 for any customer that received an estimated bill, (iv) require us to work with the NMPRC staff on a written explanation of the fuel calculation used under the order, and (v) order us to report the amount of fuel and purchased power costs foregone as a result of the interim relief, which amount we will not be allowed to recoup from customers. The deadline for intervention has passed and no parties other than us and the NMPRC staff are parties to the investigation proceeding. The hearings examiner has not set a procedural schedule.

Summary of the Exchange Offer

On October 6, 2003, we completed the private offering of $100 million in aggregate principal amount of our series C senior notes, 6% due 2033. These original notes were not registered under the Securities Act and, therefore, they are subject to significant restrictions on resale. Accordingly, when we sold these original notes, 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 notes for exchange notes that have substantially identical terms to the original notes, except that the exchange notes will be freely transferable and will not have covenants regarding registration rights or additional interest. The exchange notes will be issued under the same indenture under which the original notes were issued and, as a holder of the exchange notes, you will be entitled to the same rights under the indenture that you had as a holder of original notes.

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


Exchange Offer		We are offering to exchange up to $100 million in aggregate principal amount of exchange notes for a like aggregate principal amount of original notes. Original notes 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 Notes		Interest on the exchange notes will accrue at the rate of 6 percent per year from the date of the last periodic payment of interest on the original notes or, if no interest has been paid, from October 6, 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;

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

		• no change in our business or financial affairs has occurred that might materially impair our ability to proceed with the exchange offer.

Procedure for Exchanging Original Notes		If the original notes 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 JPMorgan Chase Bank, as exchange agent, at the address specified on the cover page of the letter of transmittal.


		If the original notes 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 notes are registered and instruct it to tender your original notes 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 notes for exchange.

		Questions regarding the exchange of original notes 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 notes and you cannot deliver the required documents to the exchange agent by the expiration date or you cannot tender and deliver your original notes in accordance with DTC’s procedures by the expiration date, you may tender your original notes 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 notes at any time before 5:00 p.m., New York City time, on the expiration date of the exchange offer.

Acceptance of Original Notes and Delivery of Exchange Notes		We will accept for exchange any and all original notes 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 notes promptly following the expiration date.

Resale of Exchange Notes		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 notes without complying with the registration and prospectus delivery requirements of the Securities Act if:

		• you are acquiring the exchange notes in the ordinary course of your business and do not hold any original notes 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 notes 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 notes; 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 notes 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 notes for its own account in exchange for original notes 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 notes.

Consequences of Failure to Exchange		If you do not exchange your original notes for exchange notes, you will not be able to offer, sell or otherwise transfer the original notes 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 notes 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 notes 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 notes that remain outstanding after completion of the exchange offer.

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

United States Federal Income Tax Considerations		Your acceptance of the exchange offer and the exchange of your original notes for exchange notes will not be taxable for U.S. federal income tax purposes. See “Material United States Federal Income Tax Considerations” beginning on page 80.

Exchange Agent		JPMorgan Chase Bank 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 Notes

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

• the exchange notes will have been registered under the Securities Act;

• the exchange notes will not contain transfer restrictions; and

• the exchange notes will not have the registration rights that apply to the original notes 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 notes is set forth below:


Securities Offered		$100,000,000 principal amount of series D senior notes, 6% due 2033.

Maturity		October 1, 2033.

Interest Rate		6 percent per year.

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

Ranking		The exchange notes will be our unsecured and unsubordinated obligations and will rank on a parity in right of payment with all our existing and future unsecured and unsubordinated indebtedness. The indenture under which the exchange notes will be issued does not prevent us from incurring additional indebtedness, which may be secured by some or all of our assets. We currently have no outstanding secured debt and no outstanding subordinated debt obligations. As of December 31, 2003, we had approximately $826.8 million of unsecured and unsubordinated obligations outstanding, which amount includes the original notes.

Ratings		The exchange notes have been assigned a rating of “BBB” (CreditWatch positive) by Standard & Poor’s Ratings Services (“Standard & Poor’s”) and “Baa1” (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 notes 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 notes 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 Notes”) plus 20 basis points, plus in each case accrued and unpaid interest to the date fixed for redemption.

Use of Proceeds		We will not receive any proceeds from the issuance of the exchange notes. We are making the exchange offer solely to satisfy our obligations under the registration rights agreement that we

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(1)		1999		1998


	(Thousands of dollars, except ratios)
Consolidated Statement of Operations Data:
Operating revenue	$	909,402	$	770,466	$	1,025,178	$	1,385,458	$	1,079,580	$	925,937	$	951,187
Operating income	$	143,673	$	132,147	$	165,118	$	230,557	$	198,253	$	212,759	$	231,375
Interest charges and financing costs	$	39,187	$	40,292	$	53,898	$	52,917	$	70,718	$	61,435	$	58,303
Net income	$	67,112	$	59,918	$	73,882	$	130,100	$	69,492	$	102,709	$	114,987
Other Consolidated Financial Data
Ratio of earnings to fixed charges(2)		3.8		3.3		3.1		4.5		2.7		3.5		3.8


	September 30, 2003

	(Thousands of dollars)
Consolidated Balance Sheet Data:
Total assets	$	2,290,669
Long-term debt	$	725,878
Mandatorily redeemable preferred securities of subsidiary trusts(3)	$	100,000
Common stockholder’s equity	$	796,973
Total capitalization	$	1,622,851

(1) The 2000 Consolidated Statement of Operations Data has been adjusted to reflect the implementation of Statement of Financial Accounting Standard (“SFAS”) No. 145, which became effective in 2003 and requires retroactive restatement of prior periods. Interest charges and financing costs of $8.225 million related to the defeasance of our first mortgage bonds, previously disclosed in Extraordinary items, was reclassified to Interest charges and financing costs. Associated income tax benefits of $2.923 million have been reclassified from Extraordinary items to Income taxes. The reclassification had no impact on operating income or net income. The 2000 financial data were derived from financial statements audited by Arthur Andersen LLP, independent public accountants. However, due to the reclassification required by SFAS No. 145, the Consolidated Statement of Operations Data in the Summary Historical Financial Data disclosed above does not agree to the financial statements as audited by Arthur Andersen LLP with respect to Interest charges and financing costs. We have been unable to obtain the consent of Arthur Andersen LLP to the use of their report in this prospectus.

(2) 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.

(3) On October 15, 2003, we redeemed $100 million of our mandatorily redeemable preferred securities of our subsidiary trust (together with our Subordinated Debenture).

You should carefully consider the risks described below as well as other information contained in this prospectus before exchanging your original notes. 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 notes. 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 notes, and this could result in your losing all or part of your investment.

We are an operating electric 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 Energy 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 NMPRC 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 SEC 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 and taking into account the effects of the deconsolidation of NRG following its bankruptcy filing, Xcel Energy’s common equity ratio was approximately 40 percent.

Another condition of the 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 notes 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 unsecured debt has been assigned a rating of “BBB” (CreditWatch positive) by Standard & Poor’s and of “Baa1” (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 senior notes would likely reduce the value of the exchange notes offered hereby.

Historically, we have relied on bank lines of credit, the commercial paper market and capital contributions from Xcel Energy to supplement our operating cash flow in order to meet the short-term liquidity requirements of our business. If Xcel Energy’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, within certain regulatory limitations and the limitations provided by corporate law, additional or accelerated funding from us in the form of dividends.

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 $85.1 million, $93.4 million and $73.3 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. At September 30, 2003, our retained earnings were approximately $416 million.

Our Chairman, Wayne H. Brunetti, our Vice President, Richard C. Kelly, and our Vice President and General Counsel, Gary R. Johnson, have served in similar capacities at Xcel Energy. 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 Xcel Energy’s President and Chief Operating Officer, 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 similar 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 the 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 the purchase, contribution and/or retention of Xcel Energy common stock in the plans and making misleading statements and omissions in that regard. The cases have been transferred by the Judicial Panel on Multidistrict Litigation to the Minnesota federal court for purposes of coordination with the securities class actions and shareholder derivative action pending there. The defendants have filed motions to dismiss the complaints. The motions have not yet been ruled upon.

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

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 is dependent on our ability to recover costs related to providing energy and utility services to our customers. We provide retail electric service to customers in four states and we are regulated by the state public utility commissions in those four states. 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 an increased amount of 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. FERC-jurisdictional services comprised approximately 32 percent of our annual revenues as of November 30, 2003. As a result of the energy crisis in California and the alleged market abuses by certain energy companies, the FERC has issued a number of orders substantially increasing their oversight of wholesale sales and requiring further structural separation of the electric transmission function from the energy markets function. These regulatory changes could increase our costs or adversely affect our ability to recover costs. Federal, state and local agencies also have jurisdiction over many of our other activities.

Timely fuel cost recovery has been made more difficult by the volatility of the natural gas market. In Texas, fuel costs are periodically reconciled to fuel costs collected under fixed fuel cost recovery factors in proceedings that examine the prudence of fuel costs including, but not limited to, the terms of purchase, affiliate transactions and the operation and dispatch of generating units. Although we believe that our fuel costs are reasonable and prudent, there is a risk in a retroactive review that some fuel costs could be disallowed.

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 notes.

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. We also may be asked to otherwise ensure that our ratepayers are not harmed as a result of NRG’s bankruptcy.

As part of the September 25, 2003 order, the NMPRC also implemented temporary billing measures for customers whose meters were estimated. The temporary billing measures: (i) require us to apply the lowest fuel and purchased power cost adjustment factor that was applicable during the period when meters were being estimated, (ii) allow customers 6 months to pay bills in full without additional charges or disconnection, (iii) prohibit disconnection of service until November 1, 2003 for any customer that received an estimated bill, (iv) require us to work with the NMPRC’s staff on a written explanation of the fuel calculation used under the order, and (v) order us to report the amount of fuel and purchased power costs foregone as a result of the interim relief, which amount we will not be allowed to recoup from customers. The deadline for intervention has passed and no parties other than us and the NMPRC staff are parties to the investigation proceeding. The hearings examiner has not set a procedural schedule. If the investigation into our billing practices results in an adverse finding, we may be subject to additional remedial actions and civil penalties, which could have a material adverse affect on our financial position and results of operations.

We engage in wholesale sales and purchases of electric capacity and energy and coal and natural gas fuel, and, accordingly, are also subject to commodity price risk, credit risk and other risks associated with these activities.

We are exposed to market and credit risks in our generation capacity purchases and sales, electric energy purchases and sales, fuel purchases and retail distribution. The level of these risks are reduced somewhat by retail fuel and energy expenses adjustment clauses which allow certain costs to be recovered from retail customers. To minimize the risk of market price and volume fluctuations, we 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. 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 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.

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.

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.

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 security measures and cause disruptions of fuel supplies and markets, particularly with respect to gas and energy. The possibility that infrastructure facilities, such as electric generation, transmission and distribution facilities, would be direct targets of, or indirect casualties of, an act of war may affect our operations. War and the possibility of further war may have an adverse impact on the economy in general. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth. Instability in the financial markets as a result of war may also affect our ability to raise capital.

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.

Currently, there is no retail restructuring activity in our service territory. In 1999, full retail competition in Texas was mandated by the legislature to begin January 1, 2002. However, due to transmission constraints and market power concerns in the Texas Panhandle, in the 2001 legislative session, the Texas legislature delayed competition in our service territory until at least January 1, 2007. In New Mexico, restructuring proceedings have been dismissed and in 2003 the legislature repealed electric restructuring statutes. Oklahoma has also ceased electric restructuring activities and there are no restructuring activities in Kansas. Although there currently is no retail restructuring activity, as described above, from time to time the states where we operate have explored retail competition, and may in the future decide to pursue retail competition in our service territory.

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 electric utility business is a seasonal business 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

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, 2001 and December 31, 2000 and has not consented to the inclusion of their auditor’s report with respect to such financial statements in this prospectus. Events arising out of the indictment and conviction materially and adversely affect the ability of Arthur Andersen to satisfy any claims arising from the provision of auditing services to us, including claims that may arise out of Arthur Andersen’s audit of financial statements included in this prospectus. We have not had a reaudit of our financial statements as of and for the years ended December 31, 2001 and December 31, 2000.

The exchange notes will be our unsecured obligations. The indenture under which the exchange notes will be issued will not prevent us from incurring additional indebtedness, including secured debt which would have a prior claim on the assets securing that debt.

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 notes would likely reduce the value of the exchange notes offered hereby.

Although the exchange notes 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. If an active public market does not develop, the market price and liquidity of the exchange notes may be adversely affected. Furthermore, we do not intend to apply for listing of the exchange notes on any securities exchange or automated quotation system.

Even if a market for the exchange notes does develop, you may not be able to resell the exchange notes for an extended period of time, if at all. In addition, future trading prices for the exchange notes 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.


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


	•	exchanges original notes 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 notes 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 notes that exchanges its original notes in the exchange offer for the purpose of participating in a distribution of the exchange notes 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 notes.

If you do not exchange your original notes for the exchange notes offered in this exchange offer, you will continue to be subject to the restrictions on the transfer of your original notes. Those transfer restrictions are described in the indenture and in the legend contained on the original notes, and arose because we issued the original notes 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 notes 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 notes in the exchange offer, you will no longer be entitled to have those original notes registered under the Securities Act.

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

The exchange of the original notes for the exchange notes can only occur if the proper procedures, as detailed in this prospectus, are followed. The exchange notes will be issued in exchange for the original notes only after timely receipt by the exchange agent of the original notes 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 notes in exchange for exchange notes, 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 notes for exchange. Original notes 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 notes in the exchange offer in order to participate in a distribution of the exchange notes, 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 notes, they might trade at prices higher or lower than the initial offering price of the original notes. 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.

We will not receive any cash proceeds from the issuance of the exchange notes. 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 notes. In consideration for issuing the exchange notes in exchange for the original notes as described in this prospectus, we will receive, retire and cancel the original notes that are properly offered for exchange. As a result, the issuance of the exchange notes 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 notes, after deducting discounts, commissions and offering expenses, were approximately $97.8 million. We added the net proceeds from the sale of the notes to our general funds and applied them, along with cash on hand, to redeem $103,092,775 of our Subordinated Debenture.

We issued and sold the original notes on October 6, 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 notes. 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 notes (or if such day is not a business day, the next succeeding business day) relating to an offer to exchange the original notes for the exchange notes;

	•	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 notes (or if such day is not a business day, the next succeeding business day); and

	•	to keep the exchange offer open for at least 20 business days but not more than 30 business days after the date notice of the exchange offer is mailed to holders of original notes and use our best efforts to consummate the exchange offer within 210 calendar days of the issue date of the original notes (or if such day is not a business day, the next succeeding business day).

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 notes in accordance with the exchange offer on or prior to May 3, 2004, we will be required to pay additional interest to holders of original notes 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 notes 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 notes 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 notes, see “Risk Factors — Risks Related to the Exchange Notes.”

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 notes in the ordinary course of your business and do not hold any original notes 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 notes 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 notes; 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 notes 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 notes 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 notes for its own account in exchange for original notes 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 notes. This prospectus may be used by those broker-dealers to resell exchange notes 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 notes until October 4, 2004 (210 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 notes.

To the extent original notes are tendered and accepted in the exchange offer, the principal amount of original notes that will be outstanding will decrease with a resulting decrease in the liquidity in the market for the original notes. Original notes 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 notes 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 notes in exchange for each $1,000 principal amount of original notes accepted in the exchange offer. You may tender some or all of your original notes pursuant to the exchange offer. However, original notes may be tendered only in increments of $1,000.

The exchange offer is not conditioned upon any minimum aggregate principal amount of original notes being tendered for exchange. As of the date of this prospectus, an aggregate of $100 million principal amount of original notes was outstanding. This prospectus is being sent to all registered holders of original notes. There will be no fixed record date for determining registered holders of original notes entitled to participate in the exchange offer.

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 notes do not have any appraisal or dissenters’ rights under law or under our indenture under which the exchange notes will be issued,

We will be deemed to have accepted for exchange validly tendered original notes 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 notes for the purposes of receiving the exchange notes from us and delivering the exchange notes to the tendering holders.

If we do not accept for exchange any tendered original notes because of an invalid tender, the occurrence of certain other events described in this prospectus or otherwise, such unaccepted original notes 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 notes 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 notes 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 notes 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 notes; or

	•	to extend or terminate the exchange offer and to refuse to accept original notes 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 notes previously tendered will remain subject to the exchange offer. We will return any original notes 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 notes, you must complete one of the following procedures by 5:00 p.m., New York City time, on the expiration date:


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

	•	if you hold physical original notes 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


		notes you wish to exchange and all other documents required by the letter of transmittal, to JPMorgan Chase Bank, the exchange agent, at its address listed below under “— Exchange Agent”; or

	•	if you cannot tender your original notes 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 notes 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 notes through The Depository Trust Company 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 notes 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 notes and withdrawal of tendered original notes, and our determination will be final and binding. We reserve the absolute right to reject any and all original notes not properly tendered or any original notes 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 notes either before or after the expiration date. Our interpretation of the terms and conditions of the exchange offer as to any particular original notes 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 notes 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 notes 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 notes will not be deemed to have been made until all defects or irregularities have been cured or waived. Any original notes 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 notes 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 notes, 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 notes 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 notes 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 notes (other than certain specified holders) will represent to us that:


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

	•	it is not a broker-dealer tendering original notes 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 notes; 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 notes for its own account in exchange for original notes 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 notes. 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 notes 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 notes and instruct it to promptly tender your original notes for exchange on your behalf.

The exchange agent will establish an account with respect to the original notes at DTC promptly after the date of this prospectus. Your book-entry notes must be transferred into the exchange agent’s account at DTC in compliance with DTC’s transfer procedures in order for your original notes to be validly tendered for exchange. Any financial institution that is a participant in DTC’s systems may cause DTC to transfer original notes 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 notes 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 notes 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 notes shall be deemed to also refer to DTC’s book-entry delivery method.

Holders who wish to tender their original notes and (1) whose original notes are not immediately available or (2) who cannot deliver the letter of transmittal or any other required documents to the exchange agent prior to the expiration date or (3) who cannot complete the procedures for book-entry transfer on a timely basis may effect a tender if:


	•	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 notes 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 notes 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 notes tendered by the eligible institution into the exchange agent’s account at DTC in the case of book-entry original notes, or a properly completed and executed letter of transmittal and the physical original notes, in the case of original notes 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 notes according to the guaranteed delivery procedures described above.

Except as otherwise provided in this prospectus, tenders of original notes 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 notes to be withdrawn;

	•	identify the original notes to be withdrawn, including the principal amount of such original notes;

	•	state that the holder is withdrawing its election to exchange the original notes 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 notes 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 notes 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 notes so withdrawn will be deemed not to have been validly tendered for exchange for purposes of the exchange offer, and no exchange notes will be issued with respect thereto unless the original notes so withdrawn are validly re-tendered. Properly withdrawn original notes 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 notes 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 notes as soon as practicable after withdrawal, rejection of tender or termination of the exchange offer.

Despite any other term of the exchange offer, we will not be required to accept for exchange, or to issue exchange notes in exchange for, any original notes, 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; or

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

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 notes or credit any tendered original notes to the account maintained within DTC by the participant in DTC which delivered the original notes;

	•	extend the exchange offer and retain all original notes tendered before the expiration date, subject to the rights of holders to withdraw the tenders of original notes (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 notes 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 notes tendered, and we will not issue exchange notes in exchange for any of the original notes, 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.

JPMorgan Chase Bank 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 notes should be directed to the exchange agent at the address set forth below. Questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal and requests for notices of guaranteed delivery should be directed to the exchange agent addressed as follows:

Delivery to other than the above address or facsimile number 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 notes and in tendering original notes for their customers.

Holders who tender their original notes 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 notes will be amortized over the term of the exchange notes.

Holders of original notes who do not exchange their original notes for exchange notes pursuant to the exchange offer will not be able to offer, sell or otherwise transfer the original notes 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 notes 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 notes do not have any appraisal or dissenters’ rights in connection with the exchange offer.

Upon completion of the exchange offer, holders of original notes will not be entitled to any rights to have the resale of original notes 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 notes registered under a shelf registration. Except for this limited circumstance, we do not intend to register under the Securities Act the resale of any original notes that remain outstanding after completion of the exchange offer. In addition, upon completion of the exchange offer, there may be no market for the original notes, and holders of original notes who fail to exchange their original notes 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 notes for outstanding original notes. 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.


(1)	On October 15, 2003, we redeemed $100 million of our mandatorily redeemable preferred securities of our subsidiary trust (together with our Subordinated Debenture).

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.

(1)

The 2000 Consolidated Statement of Operations Data has been adjusted to reflect the implementation of SFAS No. 145, which became effective in 2003 and requires retroactive restatement of prior periods. Interest charges and financing costs of $8.225 million related to the defeasance of our first mortgage bonds, previously disclosed in Extraordinary items, was reclassified to Interest charges and financing costs. Associated income tax benefits of $2.923 million have been reclassified from Extraordinary items to Income taxes. The reclassification had no impact on operating income or net income. The 2000 financial data were derived from financial statements audited by Arthur Andersen LLP, independent public accountants. However, due to the reclassification required by SFAS No. 145, the Consolidated Statement of Operations Data in the Selected Consolidated Financial Data disclosed above does not agree to the financial statements as audited by Arthur Andersen LLP with respect to Interest charges and financing costs, Income taxes and Extraordinary items. We have been unable to obtain the consent of Arthur Andersen LLP to the use of their report in this prospectus.


(2)	This item includes in 2000 charges related to the discontinuance of SFAS No. 71 for the generation portion of our business in the second quarter of 2000, writing off generation related regulatory assets and other deferred costs recorded in anticipation of the implementation of retail competition and restructuring of electric utilities in Texas and includes in 2001 income related to the reapplication of SFAS No. 71 to our generation business when the implementation of retail competition and restructuring of electric utilities in Texas was postponed.

(3)	On October 15, 2003, we redeemed $100 million of our mandatorily redeemable preferred securities of our subsidiary trust (together with our Subordinated Debenture).

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.

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,” “may,” “objective,” “outlook,” “plan,” “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, including the status and implementation of restructuring legislation in Texas and New Mexico, our two primary jurisdictions;

	•	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 $67.1 million for the first nine months of 2003, compared with approximately $59.9 million for the first nine months of 2002. The change was primarily due to the effects of higher capacity sales and higher revenues shared through the joint operating agreement (“JOA”) with PSCo, NSP-Minnesota and NSP-Wisconsin approved by the FERC. Our net income was $73.9 million for 2002, compared with $130.1 million for 2001. The change was primarily due to decreased capacity margins, lower shared trading margins recorded through the JOA and the effects of the restoration, in 2001, of certain regulatory assets. Our net income was $130.1 million for 2001, compared with $69.5 million for 2000. The change was primarily due to increased electric revenues as a result of increased recovery of fuel and purchased power costs and favorable temperatures during 2001.

Special Charges — Regulatory Recovery Adjustment — During the first quarter of 2002, we wrote off approximately $5 million of restructuring costs relating to costs incurred to comply with legislation requiring a transition to retail competition in Texas, which was subsequently amended to delay the required transition.

Extraordinary Items — Regulatory Recovery Adjustment — In late 2001, we filed an application requesting recovery of costs incurred to comply with transition to retail competition legislation in Texas and New Mexico. During the first quarter of 2002, we entered into a settlement agreement with intervenors regarding the recovery of restructuring costs in Texas, subject to approval by the state regulatory commission. Based on the settlement agreement, we wrote off pretax restructuring costs of $5 million.

Extraordinary Items — Electric Utility Restructuring — During early 2001, legislation in both Texas and New Mexico was passed that delayed the planned implementation of restructuring within our service territory for at least five years. Accordingly, in the second quarter of 2001, we reapplied the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” for our generation business. At that time, we did not restore any regulatory assets or other costs previously written off due to the uncertainty of various regulatory issues, including transition plans to address future rate recovery of our restructuring costs.

During the fourth quarter of 2001, we completed a $500 million medium-term debt financing with the proceeds used to reduce short-term borrowings that had resulted from the 2000 defeasance of our first mortgage bonds. In our regulatory filings and communications, we have proposed to amortize our defeasance costs over the five-year life of the refinancing, consistent with historical ratemaking, and have requested incremental rate recovery of $25 million of other restructuring costs. These non-financing restructuring costs have been deferred and will be amortized in the future consistent with rate recovery. Based on these events and the corresponding reduced uncertainty surrounding the financial impacts of the delay in restructuring, we restored in 2001 certain regulatory assets totaling $17.6 million as of December 31, 2001, and reported related after-tax extraordinary income of $11.8 million. Regulatory assets previously written off in 2000 were restored only for items currently being recovered in rates and items where future rate recovery is considered probable.

For more information on our restructuring developments, including the reapplication of regulatory accounting under SFAS No. 71, see Note 10 to the audited consolidated financial statements and Note 1 to the interim consolidated financial statements.

Special Charges — Staff Consolidation — During 2001, we expensed pretax special charges of approximately $4.5 million for planned staff consolidation costs. 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.

Extraordinary Items — Our earnings for 2000 were reduced by two extraordinary items related to the discontinuation of regulatory accounting for our generation business. During the second quarter of 2000, we wrote off our generation-related regulatory assets and other deferred costs for an extraordinary charge of approximately $19 million before tax, or $13.7 million after tax. During the third quarter of 2000, we recorded an additional extraordinary charge of $8.2 million before tax, or $5.3 million after tax, related to the tender offer/ defeasance of approximately $295 million of our first mortgage bonds, of which $8.2 million has been reclassified to interest charges and financing costs and $2.9 million of related tax benefit has been reclassified as income tax for current presentation, due to the issuance of SFAS No. 145, as previously discussed.

Special Charges — Our earnings for 2000 were reduced by special charges related to the merger to form Xcel Energy. During the third and fourth quarter of 2000, we expensed pretax special charges of $24.3 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.

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel cost recovery mechanisms for retail customers in several states, most fluctuations in energy costs do not materially affect electric utility margin.

The following table details the change in electric revenue and margin. Fuel and purchased power costs are recoverable in Texas through a fixed fuel factor, which is included in rates. In New Mexico, fuel and purchased energy costs are adjusted through a fuel clause and a fixed annual factor. In all other jurisdictions, we currently recover substantially all increases and refund substantially all decreases in fuel and purchased power costs pursuant to monthly adjustment clauses. Due to these fuel clause cost recovery mechanisms for retail customers and the ability to vary wholesale prices with changing market conditions, most fluctuations in energy costs do not significantly affect electric margin. However, the fuel clause cost recovery does not allow for complete recovery of all variable production expenses and, therefore, changes in costs can affect earnings.

Nine Months Ended September 30, 2003 Comparison to Nine Months Ended September 30, 2002 — Base electric utility revenue increased by approximately $137 million, or 17.9 percent, for the first nine months of 2003, compared with the first nine months of 2002. Base electric utility margin increased by approximately $9 million, or 2.5 percent, for the first nine months of 2003, compared with the first nine months of 2002. Base electric utility revenue increased primarily due to higher fuel and purchased power costs recovered through electric rates, higher sharing of commodity trading margins with PSCo and NSP-Minnesota through the JOA, partially offset by the unfavorable effects of lower average temperatures. The increase in base electric utility margin was primarily due to the effects of higher capacity sales and higher revenues shared through the JOA, partially offset by the settlement impacts of the Texas fuel cost recovery proceeding and the unfavorable effects of lower average temperatures.

2002 Comparison to 2001 — Base electric utility revenue decreased by approximately $363 million, or 26.3 percent, in 2002. Base electric utility margin decreased by approximately $51 million, or 9.8 percent, in 2002. Base electric utility revenue decreased for 2002, compared with 2001, largely due to decreased recovery of fuel and purchased power costs driven by declining fuel costs in 2002 and decreasing wholesale revenues. Base electric utility margin declined due to an approximate $57 million decrease in capacity margins and lower shared trading margins recorded through the JOA, partially offset by growth in retail sales.

2001 Comparison to 2000 — Base electric utility revenue increased by approximately $311 million, or 29.0 percent, for 2001, compared with 2000. Base electric utility margin increased by approximately $24 million, or 4.8 percent, for 2001, compared with 2000. Base electric utility revenue increased for 2001, compared with 2000, largely due to increased recovery of fuel and purchased power costs, particularly the increased cost of natural gas generation. More favorable temperatures during 2001 increased base electric retail revenue by approximately $14 million and base electric retail margin by approximately $6 million. The increase in base electric retail revenue and margin was partially offset by approximately $9 million for 2001, due to rate reductions in Texas and New Mexico agreed to as part of the merger approval process in comparison to approximately $5 million in 2000.

Nine Months Ended September 30, 2003 Comparison to Nine Months Ended September 30, 2002 — Other operating and maintenance expense increased by approximately $9.6 million, or 8.5 percent, for the first nine months of 2003, compared with the first nine months of 2002. The increased costs are due to higher incentive and other employee benefit costs partly offset by lower outage related costs.

Taxes (other than income taxes) decreased by approximately $4.8 million, or 11.9 percent, for the first nine months of 2003, compared with the first nine months of 2002. The decrease is primarily due to a lower assessed franchise tax rate within Texas for 2003.

Interest expense decreased by approximately $1.1 million, or 2.7 percent, for the first nine months of 2003, compared with the first nine months of 2002, primarily due to an increase in the allowance for equity funds used during construction.

Income tax expense increased by approximately $5.6 million, or 15.5 percent, for the first nine months of 2003, compared with the first nine months of 2002, primarily due to an increase in pre-tax income.

As discussed in Note 2 to the interim consolidated financial statements, in late 2001 SPS filed an application requesting a rate rider to recover costs incurred to comply with transition to retail competition legislation in Texas and New Mexico. During the first quarter of 2002, SPS entered into a settlement agreement with intervenors regarding the recovery of restructuring costs in Texas, subject to approval by the state regulatory commission. Based on the settlement agreement, SPS wrote off pretax restructuring costs of approximately $5 million in 2002, which are reported as special charges.

2002 Comparison to 2001 — Other operating and maintenance expense for 2002 increased by approximately $2.5 million, or 1.6 percent, compared with 2001, largely due to increased insurance premiums.

Depreciation and amortization expense increased by approximately $5.1 million, or 6.1 percent, for 2002 compared with 2001, primarily due to capital additions to utility plant.

Taxes (other than income taxes) increased by approximately by $5.7 million, or 11.8 percent, for 2002 compared with 2001, primarily due to higher property and franchise taxes.

Special charges increased slightly in 2002. During 2001, we expensed pretax special charges of approximately $4.5 million for planned staff consolidation costs. 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. In 2002, special charges of $5.1 million were expensed due to a Texas regulatory recovery adjustment. For more information, see Note 2 to the audited consolidated financial statements.

Other income decreased by $5.8 million, or 49 percent, for 2002 compared with 2001, primarily due to us no longer receiving interest income on a note receivable that was paid off in 2001.

Interest expense increased by approximately $1.0 million, or 2.1 percent, for 2002 compared with 2001. The change is primarily due to an increase in financing costs related to debt that was refinanced in late 2001.

2001 Comparison to 2000 — Other utility operating and maintenance expense for 2001 increased by approximately $5.4 million, or 3.6 percent, compared with 2000. The change is largely due to increased bad debt reserves resulting from higher energy prices and increased generation maintenance overhauls.

Depreciation and amortization expense increased by approximately $5.4 million, or 6.9 percent, for 2001, compared with 2000, primarily due to increased capital additions to utility plant.

Interest expense decreased by approximately $9.6 million, or 17.5 percent, for 2001, compared with 2000, primarily due to lower interest expense resulting from the use of more short-term debt until the issuance of long-term debt in October 2001.

Our earnings can be significantly affected by weather. Unseasonably hot summers or cold winters increase electric 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. 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 $0.4 million;

	•	weather in 2002 increased net income by an estimated $2.5 million;

	•	weather in 2001 increased net income by an estimated $4.2 million; and

	•	weather in 2000 decreased net income by an estimated $1.1 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 the JOA. 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 sales growth was estimated to be 2.2 percent in the first nine months of 2003 compared with the first nine months of 2002, 0.8 percent in 2002 compared with 2001, and 0.6 percent in 2001 compared with 2000. We are projecting that weather-normalized sales growth in 2003 compared with 2002 will be 2.1 percent.

Utility Industry Changes — The structure of the electric utility industry has been subject to change. Merger and acquisition activity over the past few years 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 assets. All FERC-jurisdictional electric utilities are required to provide nondiscriminatory wholesale access to the use of their transmission systems.

Some states had begun to allow retail customers to choose their electricity supplier, and many other states were considering retail competition proposals. 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 most industry restructuring.

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

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 SPS 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.

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 and the regulatory commissions in the states in which we operate. The rates are generally designed to recover plant investment, operating costs and an

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 $72.2 million and regulatory liabilities of approximately $2.3 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.

Merger Rate Agreements — As part of the merger approval process, we agreed to reduce our rates in several jurisdictions. The discussion below summarizes the rate reductions in Texas and New Mexico.


	•	guarantee annual merger savings credits of approximately $4.8 million and amortize merger costs through 2005;

	•	retain the current fuel-recovery mechanism to pass along fuel cost savings to retail customers; and

	•	comply with various service quality and reliability standards, covering service installations and upgrades, light replacements, customer service call centers and electric service reliability.


	•	guarantee annual merger savings credits of approximately $780,000 and amortize merger costs through December 2004;

	•	share net nonfuel operating and maintenance savings equally among retail customers and shareholders;

	•	retain the current fuel recovery mechanism to pass along fuel cost savings to retail customers; and

	•	not pass along any negative rate impacts of the merger.

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


	•	$2.4 million in the nine months ended September 30, 2003;

	•	$1.5 million in 2002;

	•	$5.7 million in 2001; and

	•	$4.9 million in 2000.

We expect to incur approximately $1.5 million in capital expenditures for compliance with environmental regulations during the last three months of 2003 and approximately $9.2 million during the period from 2004 through 2007. Most of the costs are related to water 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. On September 30, 2003, we had a special purpose subsidiary trust with outstanding mandatorily redeemable preferred securities of $100 million consolidated in our consolidated balance sheets. These securities were redeemed on October 15, 2003.

SFAS No. 143 — We adopted SFAS No. 143 — “Accounting for Asset Retirement Obligations” 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 generation, transmission and distribution facilities of Xcel Energy’s utility subsidiaries, including us. Although SFAS No. 143 does not recognize the future accrual of removal costs as a GAAP 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, at January 1, 2003, our estimated amount of future removal costs, which are considered regulatory liabilities under SFAS No. 71 that are accrued in accumulated depreciation, was $97 million.

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

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.

Business and Operational Risk — We are exposed to commodity price risk in our fuel for generation and purchased energy. However, we recover purchased fuel and energy expenses on a dollar-for-dollar basis.

We manage commodity price risk by entering into purchase and sales commitments for electric power, long-term contracts for coal supplies and fuel oil, and derivative financial instruments. Our risk management policy allows us to manage the market price risk to the extent such exposure exists and to economically manage system costs.

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.

The impacts on our pretax income of a 100 basis point change in the benchmark rate on variable debt were $0.0 at September 30, 2003, $0.3 million at December 31, 2002 and $3.9 million at December 31, 2001.

See Note 11 to the audited consolidated financial statements and Note 6 to the interim consolidated financial statements for a discussion of our interest rate swaps.

Credit Risk — In addition to the risks discussed previously, we are exposed to credit risk in transactions. Credit risk relates to the risk of loss resulting from the non-performance by a counterparty of its contractual obligations. We maintain credit policies which define acceptable credit exposures in terms of quality and size of the counterparty. We actively monitor credit exposures and manage them to within the limits defined by our credit policies.

We conduct standard credit reviews for all wholesale counterparties. Retail customers have credit reviews completed and deposits assessed in accordance with state regulatory guidelines applicable within our service territory. Deposits are held in the form of cash, surety bonds, letters of credit and parental or third party guarantees. 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 $32.3 million, or 27.6 percent, for the first nine months of 2003, compared with the first nine months of 2002. The change was primarily due to decreases in recovery of deferred electric energy costs. Net cash provided by operating activities decreased by $125.2 million, or 47.7 percent, for the year ended December 31, 2002, compared with the year ended December 31, 2001. The change was primarily due to a decrease in net income and a decrease in the recovery of deferred energy costs. Net cash provided by operating activities increased by $175.6 million, or 201.5 percent, for the year ended December 31, 2001, compared with the year ended December 31, 2000. The change was primarily due to an increase in recovery of electric energy costs.

Net cash used in investing activities increased by $40.5 million, or 111.6 percent, 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 increased by $53.7 million for the year ended December 31, 2002, compared with the year ended December 31, 2001. The change was primarily due to the repayment of notes receivable from an affiliate in 2001, partially offset by a decrease in utility capital/ construction expenditures. Net cash used in investing activities decreased by $112.7 million, or 99.1 percent, for the year ended December 31, 2001, compared with the year ended December 31, 2000. The change was primarily due to the repayment of notes receivable from an affiliate.

Net cash used in financing activities decreased by $13.4 million, or 19.6 percent, for the first nine months of 2003, compared to the first nine months of 2002. The change was primarily due to increased funds from short-term debt partially offset by an increase in dividends paid to our parent. Net cash used in financing activities decreased by $119.5 million, or 57.7 percent for the year ended December 31, 2002, compared with the year ended December 31, 2001. The change was primarily due to a decrease in repayments of short-term debt as a use of cash in 2002, partially offset by a decrease in long-term debt as a source of cash and decreased

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 June 30, 2003:

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 $85.1 million and $93.4 million and $73.3 million, respectively. The amount of dividends that we pay is dictated to some extent by the needs of Xcel Energy but is limited by federal regulatory considerations. Under PUHCA, we can pay dividends only out of current and retained earnings. As of September 30, 2003, our retained earnings were approximately $416 million.

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. Our common equity at September 30, 2003 was 49.1 percent of our total capitalization. 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 and bank lines of credit. 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.” On February 18, 2003, we entered into a 364-day credit facility with a $100 million capacity. As of December 31, 2003, we had obligations of approximately $3.2 million outstanding under this facility, all of which obligations relate to letters of credit issued under the facility.

In November 2003, we entered into a “money pool” arrangement with Xcel Energy and the other Xcel Energy operating utilities, subject to receipt of required regulatory approvals. This agreement will allow us to borrow or loan short-term funds to the pool participants at competitive costs, rather than use other short-term funding sources. The money pool agreement was approved by the SEC, and will go into effect with respect to us upon NMPRC approval and with respect to each of Xcel Energy’s other operating utilities upon receipt by the utility subsidiary of all necessary regulatory approvals.

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.

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. 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 companies assigned the following credit ratings:

As of September 30, 2003, we had cash and cash equivalents of approximately $13.8 million.

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


	•	On October 6, 2003, we issued $100 million of the original notes to qualified institutional buyers in a private placement not registered under the Securities Act. The debt was issued to refinance existing higher coupon securities as described below.

	•	On October 15, 2003, our former trust subsidiary, SPS Capital I, redeemed $100 million of 7.85 percent Trust Originated Preferred Securities. The redemption price for each security was $25 principal amount plus accrued distributions of $0.240 per preferred security.

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, 2001 and 2002 and the first nine months of 2003, there have been no reportable events (as defined in Commission Regulation S-K Item 304(a)(1)(v)).

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

We were incorporated in 1921 under the laws of the State of New Mexico. On August 1, 1997, we combined with Public Service Company of Colorado to form NCE, and we became a wholly owned subsidiary of NCE, a registered holding company under PUHCA. On August 18, 2000, NCE merged into NSP, which subsequently changed its name to Xcel Energy Inc. We are now a wholly owned subsidiary of Xcel Energy. Xcel Energy is a registered holding company under PUHCA. Xcel Energy is a publicly held company and files periodic reports and other documents with the SEC. A majority of the members of our Board of Directors and many of our executive officers are also executive officers of Xcel Energy.

Among Xcel Energy’s other subsidiaries are NSP-Minnesota, PSCo, NSP-Wisconsin and Cheyenne. 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.

At December 31, 2003, we owned a direct subsidiary, SPS Capital I, a special purpose financing trust. SPS Capital I was dissolved on January 5, 2004.

Our principal executive offices are located at Tyler at Sixth Street, Amarillo, Texas 79101, and our telephone number is (303) 571-7511.

The PUCT has jurisdiction over our Texas operations as an electric utility and over our retail rates and services. The municipalities in which we operate in Texas have original jurisdiction over our rates in those communities. The NMPRC has jurisdiction over the issuance of securities and accounting. The NMPRC, the OCC and the KCC have jurisdiction with respect to retail rates and services in their respective states.

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. We have received authorization from the FERC to make wholesale electricity sales at market-based prices. In connection with our market-based rate authority, we have an obligation to file an updated market power analysis in the first quarter of 2004.

We are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies.

Texas — Fuel and purchased power costs are recoverable in Texas through a fixed fuel factor, which is part of our rates. If it appears that we will materially over-recover or under-recover these costs, the factor may be revised upon application by us or action by the PUCT. The regulations require refunding and surcharging over/under-recovery amounts, including interest, when they exceed 4 percent of our annual fuel and purchased power costs, as allowed by the PUCT, if this condition is expected to continue. PUCT regulations require periodic examination of our fuel and purchased power costs, the efficiency of the use of such fuel and purchased power, fuel acquisition and management policies and purchase power commitments. Under the PUCT’s regulations, we are required to file an application for the PUCT to retrospectively review at least every three years the operations of our electric generation and fuel management activities.

In June 2002, we filed an application for the PUCT to retrospectively review the operations of our electric generation and fuel management activities. In this application, we filed our reconciliation for electric generation and fuel management activities, totaling approximately $608 million, from January 2000 through December 2001. In May 2003, a stipulation was approved by the PUCT. The stipulation resolves all issues regarding our fuel costs and wholesale trading activities through December 2001. We will withdraw, without prejudice, our request to share in 10 percent of margins from certain wholesale non-firm sales. We will recover $1.1 million from Texas customers for the proposed sharing of wholesale non-firm sales margins. The parties agreed that we would reduce our December 2001 fuel under-recovery balances by $5.8 million. Including the withdrawal of proposed margin sharing of wholesale non-firm sales, the net impact to our deferred fuel expense, before tax, is a reduction of $4.7 million.

In May 2003, we proposed to increase our voltage-level fuel factors to reflect increased fuel costs since the time our current fuel factors were approved in March 2002. The proposed fuel factors are expected to increase Texas annual retail revenues by approximately $60.2 million.

We also reported to the PUCT that we have under-collected our fuel costs under the current Texas retail fixed fuel factors. In the same May 2003 application, we proposed to surcharge $13.2 million and related interest for fuel cost under-recoveries incurred through March 2003. In June 2003, the administrative law judge approved the increased fuel factors on an interim basis subject to hearings and completion of the case. The increased fuel factors became effective in July 2003. In July 2003, a unanimous settlement was reached adopting the surcharge and providing for the implementation of an expedited procedure for revising the fixed fuel factors on a semi-annual basis. The surcharge will be collected from customers over an eight-month period. In August 2003, the PUCT approved the settlement and the new proposed fuel cost recovery process and the surcharge became effective in September 2003. The Texas retail fuel factors will change each November and May based on the projected cost of natural gas. Revenues will continue to be reconciled to fuel costs in accordance with Texas law.

In July 2003, we filed a second fuel cost surcharge factor application in Texas to recover an additional $26 million of fuel cost under-recoveries accrued during April through June 2003. In August 2003, the parties to the case filed a stipulation resolving various issues. The stipulation provided approval of our modified request to surcharge $15.7 for the months April 2003 and May 2003 over twelve months, beginning with the November 2003 billing cycle. The stipulation was approved by the PUCT in October 2003.

New Mexico — The NMPRC regulations provide for a fuel and purchased power cost adjustment clause for our New Mexico retail jurisdiction. We file monthly and annual reports of our fuel and purchased power costs with the NMPRC.

On December 17, 2001, we filed an application with the NMPRC seeking approval of continued use of our fuel and purchased power cost adjustment using a monthly adjustment factor, authorization to implement the proposed monthly factor on an interim basis and approval of the reconciliation of our fuel and purchase power adjustment clause collections for the period October 1999 through September 2001. In January 2002, the NMPRC authorized us to implement a monthly adjustment factor on an interim basis beginning with the February 2002 billing cycle. On August 19, 2003, the NMPRC gave final approval authorizing a monthly adjustment factor.

On May 27, 2003, a hearing examiner for the NMPRC issued a recommended decision on our fuel proceeding approving our utilizing a monthly fuel factor. We had been utilizing an annual fuel factor, which had allowed significant under-collections. The decision denied the intervenors’ request that all margins from off-system sales be credited to ratepayers. On August 19, 2003, the NMPRC approved the hearing examiner’s recommended decision. In accordance with NMPRC regulations, we must file our next New Mexico fuel factor continuation case no later than August 2005.

Texas Excess Earnings Proceeding — Prior to June 2001, we operated under an earnings test in Texas, which required excess earnings to be returned to our customers. In May 2000, we filed our 1999 earnings report with the PUCT, indicating no excess earnings. In September 2000, the PUCT staff and the Office of Public Utility Counsel filed with the PUCT a notice of disagreement, indicating adjustments to our calculations, which would result in excess earnings. During 2000, we recorded an estimated obligation of approximately $11.4 million for 1999 and 2000. In February 2001, the PUCT ruled on the disputed issues in the 1999 earnings report and found that we had excess earnings of $11.7 million. We appealed this decision to the District Court. On December 11, 2001, we entered into an overall settlement of all earnings issues for 1999 through 2001, which reduced the excess earnings for 1999 to $7.3 million and found that there were no excess earnings for 2000 or through June 2001. The settlement also provided that the remaining excess earnings for 1999 could be used to offset approved transition costs that we were seeking to recover. The PUCT approved the overall settlement on January 10, 2002.

Golden Spread Electric Cooperative, Inc. — In October 2001, Golden Spread Electric Cooperative, Inc. (“Golden Spread”) filed a complaint and request for investigation against us before the FERC. Golden Spread alleged we had violated provisions of a Commitment and Dispatch Service Agreement (the “Commitment Agreement”) pursuant to which we conduct joint dispatch of our and Golden Spread’s resources. We filed a counter complaint against Golden Spread in which we alleged that Golden Spread failed to adhere to certain requirements of the Commitment Agreement. In May 2003, we and Golden Spread reached a settlement that was approved by the FERC in July 2003. The $5 million accrued costs for payments under the settlement have been deferred by us as they are for economic purchased energy and are recoverable from our customers through the respective jurisdictional fuel and purchased power cost recovery mechanisms.

Texas Transition to Competition Cost Recovery Application — In December 2001, we filed an application with the PUCT to recover $20.3 million in costs from Texas retail customers associated with the transition to competition. These costs were incurred to position us for retail competition, which was eventually delayed. The filing was amended in March 2002 to reduce the recoverable costs by $7.3 million, which was associated with over-earnings recognized for the 1999 annual report. The PUCT approved our use of the 1999 annual report over-earnings to offset the claims for reimbursement of transition to competition costs. This reduced the requested net collection in Texas to $13.0 million. In April 2002, a unanimous settlement agreement was reached. Final approval by the PUCT was received in May 2002. The stipulation provides for the recovery of $5.9 million through an incremental cost recovery rider and the capitalization of $1.9 million for metering equipment. Based on the settlement agreement, we wrote off pretax restructuring costs of approximately $5 million in the first quarter of 2002. Recovery of the $5.9 million began in July 2002.

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. We, NSP-Minnesota, and PSCo previously received FERC authorization to make wholesale sales at market-based rates, and have been engaged in such sales subject to a tariff on file at the FERC. 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, the FERC issued a final order requiring amendments to the market-based wholesale tariffs of all FERC-jurisdictional electric utilities, including us, 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 our market-based rate authority, we have an obligation to file an updated market power analysis in the first quarter of 2004.

FERC Money Pool Final Rules — 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. 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.

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. The 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 SPP regional tariff, which will govern most generation interconnections to the SPS 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 our wholesale energy markets functions and from our “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.

Southwest Power Pool Restructuring — In October 2003, SPP, the regional reliability council and power pool for the SPS system, filed for FERC authorization to transform its operation into an RTO under FERC Order No. 2000. The FERC rejected a prior similar SPP proposal in 2001. If we become a member of the SPP RTO, we would be required to transfer functional control of our electric transmission system to SPP and take all transmission services, including services required to serve retail native loads, under the SPP regional tariff. In addition, SPP made unilateral changes to the existing SPP membership agreement in order to fund the start of RTO operations in a manner which increases the current costs of our membership in SPP by approximately $1.5 million per year. On October 31, 2003, we submitted a conditional notice of withdrawal from SPP in order to preserve our flexibility with regard to future RTO membership.

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.

Texas Fuel Reconciliation, Fuel Factor and Fuel Surcharge Application — In November 2003, we submitted a third fuel cost surcharge factor application in Texas to recover an additional $25 million of fuel cost under recoveries accrued during June through September 2003. If approved, the proposed surcharge will go into effect after the first surcharge is completed and will continue for 12 months beginning in May 2004. This case is pending review and approval by the PUCT.

Merger Agreement — As a part of the NCE and NSP merger approval process in Texas, we agreed to:


	•	guarantee annual merger savings credits of approximately $4.8 million and amortize merger costs through 2005;

	•	retain the current fuel recovery mechanism to pass along fuel cost savings to retail customers; and

	•	comply with various service quality and reliability standards, covering service installations and upgrades, light replacements, customer service call centers and electric service reliability.


	•	guarantee annual merger savings credits of approximately $780,000 and amortize merger costs through December 2004;

	•	share net non-fuel operating and maintenance savings equally among retail customers and shareholders;

	•	retain the current fuel recovery mechanism to pass along fuel cost savings to retail customers; and

	•	not pass along any negative rate impacts of the merger.

New Mexico Renewable Energy Requirements — In December 2002, the NMPRC adopted new regulations requiring investor-owned utilities operating in New Mexico to promote the use of renewable energy technologies by procuring at least ten percent of their New Mexico retail energy requirements from renewable resources by no later than 2011.

NMPRC Billing Practices Investigation — Beginning in April 2003, we estimated electricity usage for approximately 9,500 customer accounts in two New Mexico cities. Estimated bills were sent to these customers for between two and five months. On September 25, 2003, the NMPRC entered an order opening an investigation into our practices regarding estimated billing. The commission ordered us to show cause why we are not in violation of the commission rule that limits the use of estimated meter readings.

Lamb County Electric Cooperative — On July 24, 1995, Lamb County Electric Cooperative, Inc. (“LCEC”) petitioned the PUCT for a cease and desist order against us. LCEC alleged that we had been unlawfully providing service to oil field customers and their facilities in LCEC’s singly certificated area. A trial on the merits was held in October 2002, and on May 23, 2003, the PUCT issued an order denying LCEC’s petition for a cease and desist order against us. The basis of the decision was the determination that we were granted a certificate of convenience and necessity in 1976 to serve the disputed customers. LCEC has filed an appeal of the decision with the District Court in Travis County, Texas. The appeal is expected to include a substantial evidence review of the record evidence introduced at the PUCT proceeding. The Texas Attorney General has responded to the appeal on behalf of the PUCT and we, Texaco Exploration and Production Inc. and Apache Corporation have intervened in the proceeding in support of the PUCT’s decision. A hearing on the appeal is currently scheduled for April 9, 2004.

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 costs of capital. The restructuring may have a significant financial 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 impacts of such 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.

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.

Utility Industry Changes and Restructuring — The structure of the electric utility industry has been subject to change. Merger and acquisition activity over the past few years 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 assets. All utilities are required to provide nondiscriminatory access to the use of their transmission systems.

Some states had begun to allow retail customers to choose their electricity supplier, and many other states were considering retail access proposals. However, the experience of the State of California in instituting competition, as well as the bankruptcy filing of Enron Corp. in 2001, have caused indefinite delays in most industry restructuring.

We cannot predict the outcome of restructuring 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.

For more information on the delay of restructuring in Texas and New Mexico, see below and Note 10 to the audited consolidated financial statements and Note 2 to the interim consolidated financial statements.

TRANSLink Transmission Company LLC — In September 2001, Xcel Energy’s operating companies, including us, 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 RTO. Initially, the applicants proposed that our high voltage transmission system be under the functional control of TRANSLink under an operating agreement between us and TRANSLink. Our electric

In April 2002, the FERC gave 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 2002, we filed for PUCT and NMPRC approval to transfer functional control of our electric transmission system to TRANSLink within the merged SPP/MISO RTO, of which we would be a participant. In March 2003, the SPP and MISO cancelled their planned merger to form a large mid-continent RTO. This development materially impacted our applications in Texas and New Mexico. We requested the cases be dismissed without prejudice while we evaluated possible RTO arrangements for the SPS system. In June 2003, the Minnesota Public Utilities Commission (“MPUC”) held a hearing on the NSP-Minnesota TRANSLink application, filed in December 2002. At the hearing, the MPUC deferred any decision. Instead, the MPUC 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. Similar state regulatory filings by NSP-Minnesota in North Dakota and by NSP-Wisconsin in Wisconsin were not contested, but were not approved.

On November 21, 2003, the TRANSLink participants, including Xcel Energy, jointly announced that the formation of TRANSLink had been suspended due to continued regulatory and market uncertainty.

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. At this time it is unclear when or if the final SMD rules may be implemented. The SPP application for approval as an RTO proposes a phased-in implementation of a market based on SMD principles from 2004 through 2006.

New Mexico Restructuring — In March 2001, the State of New Mexico enacted legislation that delayed customer choice until 2007 and amended the Electric Utility Restructuring Act of 1999. Restructuring laws were repealed in 2003. We have requested recovery of our costs incurred to prepare for customer choice in New Mexico of approximately $5.1 million. The NMPRC is allowing utilities, including us, to retain transition costs as regulatory assets on their books pending recovery, which is scheduled to be completed by January 1, 2010.

Texas Restructuring — In June 2001, the Governor of Texas signed legislation postponing the implementation of retail competition and restructuring of us until at least 2007. This legislation amended the 1999 legislation, Senate Bill No. 7 (“SB-7”), which provided for retail electric competition beginning in January 2002. Under the legislation, prior PUCT orders issued in connection with the restructuring of the SPS system will be considered null and void. Our restructuring and rate unbundling proceedings in Texas have been terminated. In addition, under the new legislation, we are entitled to recover all reasonable and necessary expenditures made or incurred before September 1, 2001 to comply with SB-7. We filed an application with the PUCT requesting a rate rider to recover these costs incurred preparing for customer choice of approximately $20.3 million. These costs were incurred to position us for retail competition, which was eventually delayed. The filing was amended in March 2002 to reduce the recoverable costs by $7.3 million, which were associated with over-earnings for the calendar year 1999. The PUCT approved our use of the 1999 over-earnings to offset the claims for reimbursement of transition to competition costs. This reduced the requested net collection in Texas to $13.0 million. In April 2002, a unanimous settlement agreement was reached. Final approval by the PUCT was received in May 2002. The stipulation provides for the recovery of $5.9 million through an incremental cost recovery rider and the capitalization of $1.9 million for metering equipment. Based on the settlement agreement, we wrote off pretax restructuring costs of approximately $5 million in the first quarter of 2002. Recovery of the $5.9 million began in July 2002.

For more information on restructuring in Texas and New Mexico, see Note 10 to the audited consolidated financial statements and Note 2 to the interim consolidated financial statements.

Kansas Restructuring — During the 2001 legislative session, several restructuring-related bills were introduced for consideration by the state legislature but, to date, there has been no restructuring mandate in Kansas.

Oklahoma Restructuring — The Electric Restructuring Act of 1997 was enacted in Oklahoma during 1997. This legislation directed a series of studies to define the orderly transition to consumer choice of electric energy supplier by July 1, 2002. In 2001, Senate Bill 440 was signed into law to formally delay electric restructuring until restructuring issues could be studied further and new enabling legislation could be enacted. Senate Bill 440 established the Electric Restructuring Advisory Committee and directed the committee to complete an interim report on the state’s transmission infrastructure needs by December 31, 2001. The Advisory Committee submitted this report to the Governor and Legislature on December 31, 2001. During 2002 and the first nine months of 2003, there was no action taken by the Legislature as a result of this report. Oklahoma continues to delay retail competition.

See also the matters discussed under “Utility Regulation — Pending Regulatory Matters.”

The system peak demand for each of the last three years and the forecast for 2004, assuming normal weather during 2004, are projected below:

Our peak demand typically occurs in the summer. During 2003, our peak demand occurred on August 5, 2003. The 2002 system peak demand occurred on August 1, 2002.

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


	•	our electric generating stations;

	•	purchases from other utilities, independent power producers and power marketers;

	•	demand-side management options; and

	•	phased expansion of existing generation at select power plants, if required or necessary.

We have 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.

We also make short-term and non-firm purchases to replace generation from company-owned 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 company-owned generation and/or long-term purchase power contracts, and for various other operating requirements.

We have 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 at our generating plants 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:


*	The lower 2003 coal costs reflect a prior period fuel credit adjustment. The normalized costs per MMBtu was approximately $1.15. This reduced coal cost was due to renegotiated coal transportation contracts.

We purchase all of our coal requirements for Harrington and Tolk electric generating stations from TUCO Inc. (“TUCO”), in the form of crushed, ready-to-burn coal delivered to our plant bunkers. For the Harrington station, the coal supply contract expires in 2016 and the coal-handling agreement expires in 2004. For the Tolk station, the coal supply contract expires in 2017 and the coal-handling agreement expires in 2005. At September 30, 2003, coal inventories at the Harrington and Tolk sites were approximately 37 days supply and 36 days supply, respectively. TUCO has a long-term coal supply agreement to supply approximately

We have a number of short and intermediate-term contracts with natural gas suppliers operating in gas fields with long life expectancies in or near our service area. We also utilize firm and interruptible transportation to minimize fuel costs during volatile market conditions and to provide reliability of supply. We maintain sufficient gas supplies under short and intermediate-term contracts to meet all power plant requirements; however, due to flexible contract terms, approximately 60 percent of our gas requirements during 2003 were purchased under spot agreements.


(1)	Other electric revenues is negative in 2000 primarily due to increased provision for rate refunds.

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. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. We have received all necessary authorizations for the construction and continued operation of our generation, transmission and distribution systems. Company facilities have been designed and constructed to operate in compliance with applicable environmental standards.

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 September 30, 2003:

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

We had 492 electric utility transmission and distribution substations at December 31, 2002 and December 31, 2003.

We had 988 employees at December 31, 2003. Of those employees, 685, or 69.3 percent, are covered under collective bargaining agreements. In addition, employees of Xcel Energy 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.

Lamb County Electric Cooperative — On July 24, 1995, LCEC petitioned the PUCT for a cease and desist order against us. LCEC alleged that we had been unlawfully providing service to oil field customers and their facilities in LCEC’s singly certificated area. A trial on the merits was held in October 2002, and on May 23, 2003, the PUCT issued an order denying LCEC’s petition for a cease and desist order against us. The basis of the decision was the determination that we were granted a certificate of convenience and necessity in 1976 to serve the disputed customers. LCEC has filed an appeal of the decision with the District Court in Travis County, Texas. The appeal is expected to include a substantial evidence review of the record evidence introduced at the PUCT proceeding. The Texas Attorney General has responded to the appeal on behalf of the PUCT and we, Texaco Exploration and Production Inc. and Apache Corporation have intervened in the proceeding in support of the PUCT’s decision. A hearing on the appeal is currently scheduled for April 9, 2004.

On October 18, 1996, LCEC filed a suit for damages against us in the District Court in Lamb County, Texas, based the same facts as alleged in its petition for a cease and desist order at the PUCT. This suit has been dormant since it was filed, awaiting a final determination at the PUCT of the legality of us providing electric service to the disputed customers. The PUCT order of May 23, 2003 found that we were legally serving the disputed customers thus collaterally determining the issue of liability contrary to LCEC’s position in the suit. An adverse ruling on the appeal of the May 23, 2003 PUCT order could mean that this issue of liability may not be collaterally determined.

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 governmental proceedings, 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 SPS effective January 19, 2004.

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

Gary L. Gibson is President, Chief Executive Officer and a Director of SPS. He has served as President since December 2000 and Chief Executive Officer since August 2001. Prior to the merger that formed Xcel Energy on August 18, 2000 (the “Merger”), Mr. Gibson was Vice President of Sales of NCE from May 1997. Previous to that, Mr. Gibson held a variety of positions in marketing, consumer services, industrial services and engineering at SPS. In 2004, Mr. Gibson plans to serve as Co-Chair for the 2004 Amarillo/Canyon United Way and the 2004 Friends of Scouting Campaign Council Chairman.

Wayne H. Brunetti has been Chairman of SPS since August 2001. 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 the Merger. 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-Minnesota, NSP-Wisconsin and PSCo. Mr. Brunetti was also the Chairman and Chief Executive

Richard C. Kelly has been Vice President and a Director of SPS since August 2001. 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-Minnesota, NSP-Wisconsin 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.

Gary R. Johnson has been Vice President and General Counsel of SPS since August 2001 and a Director of SPS 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-Minnesota, NSP-Wisconsin 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 SPS since October 2003 and Vice President and Treasurer of SPS 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 SPS from August 2001 through January 19, 2004. Mr Ripka has also served as Vice President and Controller of Xcel Energy since August 2000. 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 SPS 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.

Cathy J. Hart has been Vice President and Secretary since August 2001. She has also served as Vice President and Corporate Secretary 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 Communications at PSCo in June 1996 to move to Australia. From June 1996 to June 1998, Ms. Hart was not employed. She was re-employed by NCE as Corporate Secretary in June 1998.

Paul J. Bonavia has been Vice President of SPS since August 2001. He has also served as President — Commercial Enterprises of Xcel Energy since December 2003. Previously, Mr. Bonavia served as Senior Vice President and General Counsel of NCE from 1997 and President — Energy Markets of Xcel Energy from August 2000 to December 2003.

Raymond E. Gogel has been Vice President of SPS since April 2002. He has also served as 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 Vice President of SPS since August 2001. She has also served as 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 Vice President of SPS since August 2001. He has also served as 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.

Our Board currently consists of four directors. The Board had no committees during 2003. During 2003, the Board did not meet but approved nine resolutions by unanimous written consent, as permitted by our Amended and Restated Articles of Incorporation and Bylaws.

Each of our directors is employed by Xcel Energy 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 SPS; (b) the Named Executive Officers set forth in the Summary Compensation Table; and (c) the directors and executive officers of SPS 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 SPS effective August 8, 2003. He resigned as President, Energy 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 SPS, each of the four next most highly compensated executive officers serving as officers of SPS at December 31, 2003 and one former officer of SPS 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. A portion of the cost is allocated to SPS pursuant to SEC requirements.

(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. Gibson, Brunetti and Kelly held shares of restricted stock. As of December 31, 2003, Mr. Gibson held 1,719.47, Mr. Brunetti held 25,245.99 and Mr. Kelly held 3,312.22 shares of restricted stock with an aggregate value of approximately $29,421, $431,959 and $56,672, 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 Incentive Program. No awards were paid in 2002 or 2003. No performance cash awards under the NCE Value Creation Plan for Messrs. Gibson, 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:

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 performance share or restricted stock 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. 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 Energy Supplemental Executive Retirement Plan (the “SERP”). The Named Executive Officers are all participants in the SERP and the qualified and non-qualified defined benefit plans sponsored by Xcel Energy.

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 to Mr. Bonavia at age 57 and 8 months, if they continue to be employed by Xcel Energy until such age. A portion of the costs of the SERP arrangements is allocated to SPS by Xcel Energy Services.

At the time of their merger agreement, NCE and NSP-Minnesota 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.

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 SPS 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. Gibson, 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 enhanced 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 Director compensation and other programs are allocated to us pursuant to the utility services agreement between us and Xcel Energy 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.”

The Joint Operating Agreement dated as of July 23, 1999 (the “Joint Operating Agreement”) integrates the generating resources of NSP-Minnesota, NSP-Wisconsin, 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), and coordinated wholesale marketing activities of the Operating Companies. It also provides for the allocation of associated costs and benefits.

The Joint Operating Agreement provides for the joint planning and coordinated operation of each of the Operating Companies’ resources. While preserving the pre-merger dispatch priorities applicable to each company’s resources to allay any possible state regulatory concern regarding cost-shifts among the Operating Companies, the agreement further provides that “the Control Areas will be dispatched on a coordinated basis in real time to minimize total generation costs for the Operating Companies, subject to the availability of Firm Transmission Entitlements or other transmission arrangements linking the Operating Companies’ Control Areas or other transmission services.” Thus, the Operating Companies are obligated to exchange power when economic subject to the foregoing conditions.

The Joint Operating Agreement also contains service schedules providing for actual power transactions among the Operating Companies or by the Operating Companies acting jointly with non-affiliated third parties.

The FERC has jurisdiction over the actual power transactions set out in the Joint Operating Agreement. The costs for various non-power transaction activities (e.g., for joint planning) are incurred by Xcel Energy Services and allocated to the Operating Companies in accordance with SEC-jurisdictional service agreements.

We received revenue through the Joint Operating Agreement of $613,000 for 2002 and $1,985,000 for the nine months ended September 30, 2003.

Xcel Energy Services is the service company for the Xcel Energy system. Xcel Energy 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 Energy Services also administers the money pool pursuant to the Money Pool Agreement described below. PUHCA generally requires that Xcel Energy Services provides services to us at cost. We received charges through the agreement of $67.1 million for 2002 and $47.5 million for the nine months ended September 30, 2003.

In September 1997, we entered into an affiliated transactions agreement with Utility Engineering (the “UE Agreement”). Pursuant to the agreement, we provide specified services to Utility Engineering, including:


	•	substation construction, material and operations;

	•	substation engineering and support;

	•	provision of power plant facilities, equipment, tools and personnel;

	•	plant engineering and support; and

	•	use of facilities and real property.

Utility Engineering also performs on behalf of us engineering, development, design, construction and other related services. Pursuant to the UE Agreement, at the discretion of the loaning party, either party may loan employees and equipment to the other party for the purposes of providing services under the agreement in order to meet its needs and obligations. The UE Agreement will continue until terminated by either party on not less than one year’s prior written notice. Utility Engineering earned $13 million of revenue from us in 2002.

In November 2003, Xcel Energy, Xcel Energy Services and each of the operating utility subsidiaries of Xcel Energy (the “Pool Participants”) executed a money pool agreement (the “Money Pool Agreement”), which provides a mechanism for intra-system 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-Minnesota, NSP-Wisconsin, 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

As of December 31, 2003, in addition to the original notes, we had other unsecured and unsubordinated indebtedness in the amount of approximately $726.8 million outstanding that rank pari passu with the original notes and will rank pari passu with the exchange notes, when issued. We currently have no outstanding secured debt and no outstanding subordinated debt obligations.

The description below contains summaries of selected provisions of the Indenture (as defined below) under which the exchange notes 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 notes and the Indenture.

We will issue the exchange notes as a series of securities under the Indenture dated February 1, 1999 between us and JPMorgan Chase Bank, successor in interest to The Chase Manhattan Bank, as trustee (the “Trustee”). We refer to this indenture, as supplemented and to be supplemented by various supplemental indentures, including one or more supplemental indentures relating to the exchange notes being offered by this prospectus, as the “Indenture.” The exchange notes will be unsecured obligations and will rank on a parity with our other existing and future unsecured and unsubordinated indebtedness. We refer to the debt securities issued under the Indenture, whether previously issued or to be issued in the future, including the exchange notes being offered by this prospectus, as the “debt securities.” The amount of debt securities that we may issue under the Indenture is not limited. As of December 31, 2003, there were three series of debt securities, including the original notes, in an aggregate principle amount of $700 million outstanding under the Indenture.

The exchange notes will bear interest from the date of the last periodic payment of interest on the original notes, or, if no interest has been paid, from October 6, 2003, at a rate of 6 percent per year and will mature on October 1, 2033.

The Indenture does not require that future issues of indebtedness be issued under the Indenture. We may use other indentures or documentation, which may contain provisions different from those included in the Indenture, in connection with future issues of other indebtedness.

We will issue the exchange notes in fully registered form, without coupons, in denominations of $1,000 principal amount and whole multiples of $1,000. The exchange notes will be represented by one or more global securities registered in the name of DTC, as Depository (the “Depository”), or its nominee 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 exchange notes will be our unsecured and unsubordinated obligations. The exchange notes will rank on a parity in right of payment with all of our existing and future unsecured and unsubordinated indebtedness. However, the exchange notes will be subordinated to any secured indebtedness that we may issue, as to the assets securing that indebtedness. As of December 31, 2003, we had no secured indebtedness and no

The entire principal amount of the exchange notes will mature and become due and payable, together with any accrued and unpaid interest, on October 1, 2033. Each exchange note will bear interest from the date of the last periodic payment of interest on the original notes, or, if no interest has been paid, from October 6, 2003, at the rate of 6 percent 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 exchange note is registered at the close of business on the March 15 or September 15 immediately preceding the April 1 or October 1. We will compute the interest on the basis of a 360-day year comprised of twelve 30-day months.

Principal, interest and premium, if any, on the exchange notes will be paid in the manner described 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 exchange notes 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 exchange note will thereafter look only to us for payment of that principal, interest or premium.

There are no provisions in the Indenture or the exchange notes that require us to redeem, or permit the holders to cause a redemption of, the exchange notes or that otherwise protect the holders in the event that we incur substantial additional indebtedness, whether or not in connection with a change in control of our company. However, any change in control transaction that involves the incurrence of substantial additional long-term indebtedness by us in such a transaction could require approval of state regulatory authorities and, possibly, of federal utility regulatory authorities. Management believes that such approvals would be unlikely in any transaction that would result in our company, or a successor to our company, having a highly leveraged capital structure.

We may redeem the exchange notes at any time, in whole or in part, at a 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 notes 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 plus 20 basis points, plus in each case accrued interest to the date fixed for redemption.

“Treasury Yield” means, for any date fixed for redemption, the rate per year 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 date fixed for redemption.

“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 exchange notes 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 notes.

“Independent Investment Banker” means Citigroup Global Markets, Inc. or its successor or, if such firm or its successor is unwilling or unable to select the Comparable Treasury Issue, one of the remaining Reference Treasury Dealers appointed by the Trustee after consultation with us.

“Comparable Treasury Price” means, for any date fixed for redemption, (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 date fixed for redemption, 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

“Reference Treasury Dealer Quotations” means, for each Reference Treasury Dealer and any date fixed for redemption, 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 date fixed for redemption.

“Reference Treasury Dealer” means (1) each of Citigroup Global Markets Inc. and Credit Suisse First Boston LLC, and any other primary U.S. Government Securities dealer in the United States (a “Primary Treasury Dealer”) designated by, and not affiliated with, Citigroup Global Markets Inc. and Credit Suisse First Boston LLC, 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.

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 notes to be redeemed. If we elect to redeem less than all the exchange notes, and the exchange notes are represented a global note, then the Trustee will select the particular exchange notes to be redeemed in a manner it deems appropriate and fair.

We will not consolidate with or merge into, or transfer all or substantially all of our assets to, any person, unless:


	•	the person is organized under the laws of the United States or a state of the United States;

	•	the person assumes by supplemental indenture all of our obligations under the Indenture, the debt securities and any coupons;

	•	all required approvals of any regulatory body having jurisdiction over the transaction have been obtained;

	•	immediately after the transaction no default (as described below) exists; and

	•	we deliver to the Trustee an officer’s certificate and an opinion of counsel stating that the transaction and the supplemental indenture comply with the Indenture.

If these conditions are satisfied, then the successor will be substituted for us, and thereafter all our obligations under the Indenture, the debt securities and any coupons will terminate. (Section 5.01)

The following are events of default with respect to each series of debt securities currently outstanding under the Indenture and with respect to the exchange notes offered pursuant to this prospectus:


	•	default in any payment of interest on any debt securities of that series when due and payable and the default continues for a period of 60 days;

	•	default in the payment of the principal of any debt securities of that series when due and payable at maturity or upon redemption, acceleration or otherwise;

	•	default in the payment or satisfaction of any sinking fund obligation with respect to any debt securities of that series as required by the resolution establishing such series and the default continues for a period of 60 days;


	•	default in the performance of any of our other agreements applicable to the debt securities of that series and the default continues for 90 days after the notice specified below; or

	•	specified events of bankruptcy, insolvency or reorganization of our company.

A default of the type described in the third bullet point above is not an event of default under the Indenture until the Trustee or the holders of at least 25 percent in principal amount of the outstanding exchange notes offered by this prospectus notify us of the default and we do not cure the default within the time specified after receipt of the notice. If the holders notify us of a default, they must notify the Trustee at the same time. (Section 6.01)

Acceleration of Maturity. If an event of default occurs and is continuing on a series, either the Trustee or the holders of at least 25 percent in principal amount of outstanding debt securities of that series may declare the principal of and accrued interest on all debt securities of the series to be due and payable immediately. The holders of a majority in principal amount of the outstanding debt securities of that series may rescind an acceleration and its consequences if the rescission would not conflict with any judgment or decree and if all existing events of default on the series have been cured or waived except the nonpayment of amounts due solely because of the acceleration. (Section 6.02)

Indemnification of Trustee. The Trustee generally will be under no obligation to exercise any of its rights or powers under the Indenture unless the Trustee, upon a reasonable belief that exercising such rights or powers would expose it to any loss, liability or expense, receives indemnity satisfactory to it against such loss, liability or expense. (Section 7.01)

Right to Direct Proceedings. The holders of a majority in principal amount of a series generally will have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee, or of exercising any trust or power conferred on the Trustee, relating to that series. However, the Trustee may refuse to follow any direction that conflicts with law or the Indenture or would expose the Trustee to personal liability or be unduly prejudicial to holders not joining in such proceeding. (Section 6.05)

Limitation on Rights to Institute Proceedings. No holder of the debt securities of a series will have any right to pursue a remedy under the Indenture, unless:


	•	the holder has previously given the Trustee written notice of a continuing event of default on the series;

	•	the holders of at least 25 percent in principal amount of the outstanding debt securities of that series have made written request, and the holder or holders have offered indemnity satisfactory to the Trustee to pursue the remedy;

	•	the Trustee has failed to comply with the request within 60 days after the request and offer; and

	•	during such 60-day period the holders of a majority in principal amount of the outstanding debt securities of that series do not give the Trustee any inconsistent directions. (Section 6.06)

No Impairment of Right to Receive Payment. Notwithstanding any other provision of the Indenture, the holder of any debt security will have the absolute and unconditional right to receive payment of the principal, premium, if any, and interest on that debt security when due, and to institute suit for enforcement of that payment. This right may not be impaired without the consent of the holder. (Section 10.02)

Notice of Default. The Trustee is required to give the holders notice of the occurrence of a default within 90 days of the default. Except in the case of a non-payment on the debt securities, the Trustee may withhold the notice if its committee of officers determines in good faith that it is in the interest of holders to do so. (Section 7.04) We are required to deliver to the Trustee each year a certificate as to whether or not we are in compliance with the conditions and covenants under the Indenture. (Section 4.05)

Waiver. The holders of not less than a majority in aggregate principal amount of a series may waive any default on the series, except a default in the payment of the principal, premium, if any, or interest on the series

The Indenture does not have a cross-default provision. Thus, a default by us on any other debt (including any other series of securities issued under the Indenture) would not constitute an event of default.

The exchange notes may be exchanged for other exchange notes of the same series of any authorized denominations and of a like aggregate principal amount and kind.

The exchange notes may be presented for registration of transfer (duly endorsed or accompanied by a duly executed written instrument of transfer), at the office of the Trustee maintained for such purpose with respect to the exchange notes, without service charge and upon payment of any taxes and other governmental charges as described in the Indenture. Such transfer or exchange will be effected upon being satisfied with the documents of title and indemnity of the person making the request.

In the event of any redemption of the exchange notes, the Trustee will not be required to exchange or register a transfer of any exchange note selected, called or being called for redemption except, in the case of any exchange note to be redeemed in part, the portion thereof not to be so redeemed.

We and the Trustee may modify and amend the Indenture from time to time as described below. Depending upon the type of amendment, we may not need the consent or approval of any of the holders of the debt securities, including the exchange notes offered by this prospectus, or we may need either the consent or approval of the holders of a majority in principal amount of all outstanding debt securities affected by the proposed amendment or the consent or approval of each holder affected by the proposed amendment.

We will not need the consent of any holder for the following types of amendments:


	•	to cure any ambiguity, omission, defect or inconsistency;

	•	to provide for assumption of our obligations under the Indenture and the debt securities in the event of a merger or consolidation requiring such assumption;

	•	to provide that specific provisions of the Indenture not apply to a series of debt securities not previously issued;

	•	to create a series and establish its terms;

	•	to provide for a separate trustee for one or more series; or

	•	to make any change that does not materially adversely affect the rights of any holder of debt securities. (Section 10.01)

We will need the consent of the holders of each outstanding debt security affected, if the proposed amendment would do any of the following:


	•	reduce the amount of debt securities whose holders must consent to an amendment or waiver;

	•	reduce the interest rate or change the time for payment of interest on any debt security;

	•	change the fixed maturity of any debt security;

	•	reduce the principal of any non-discounted debt security or reduce the amount of principal of any discounted debt security that would be due on acceleration;

	•	change the currency in which principal or interest is payable;

	•	make any change that materially adversely affects the right to convert any debt security;

	•	waive any default in payment of interest or principal; or

	•	make any change in the Indenture provisions governing waiver of past defaults or the Indenture provisions described in the preceding seven bullet points, except to (a) increase the amount of holders


		whose consent is required for an amendment or waiver or (b) provide that the amendment or waiver of other Indenture provisions requires the consent of each holder affected.

Amendments other than those described in the above paragraphs will require the approval of the holders of a majority in principal amount of the debt securities affected voting as one class. (Section 10.02)

At any time we may terminate as to a series of debt securities issued under the Indenture (including the exchange notes offered by this prospectus) all of our obligations (except for specified obligations regarding the defeasance trust and obligations to register the transfer or exchange of a debt security, to replace destroyed, lost or stolen debt securities and coupons and to maintain paying and other agencies for the debt securities) with respect to the debt securities of that series and any related coupons and the Indenture (“legal defeasance”).

At any time we may terminate as to a series of debt securities issued under the Indenture (including the exchange notes offered by this prospectus) our obligations under any restrictive covenants which may be applicable to that particular series (“covenant defeasance”). We may exercise our legal defeasance option notwithstanding our prior exercise of our covenant defeasance option. If we exercise our legal defeasance option, the debt securities of that particular series may not be accelerated because of an event of default. If we exercise our covenant defeasance option, the debt securities of that particular series may not be accelerated by reference to any restrictive covenant which may be applicable to the debt securities so defeased under their terms.

To exercise either defeasance option as to a series of debt securities issued under the Indenture (including the exchange notes offered by this prospectus), we must deposit in trust (the “defeasance trust”) with the Trustee money or direct obligations of the United States of America which have the full faith and credit of the United States of America pledged for payment and which are not callable at the issuer’s option, or certificates representing an ownership interest in those obligations for the payment of principal, premium, if any, and interest on the debt securities to redemption or maturity and must comply with specified other conditions. In particular, we must obtain an opinion of tax counsel that the defeasance will not result in recognition of any gain or loss to holders for federal income tax purposes. (Article 8)

The Trustee may resign at any time by notifying us; however, the resignation will not take effect until a successor trustee has accepted its appointment as trustee. (Section 7.07)

The holders of a majority in principal amount of the outstanding debt securities may remove the Trustee at any time. (Section 7.07) We may remove the Trustee if the Trustee fails to comply with specific provisions of the Trust Indenture Act of 1939, as amended, or fails to comply with the Indenture’s capital and surplus requirements. We may also remove the Trustee if one of the following occurs:


	•	the Trustee is adjudged a bankrupt or an insolvent;

	•	a custodian or other public officer takes charge of the Trustee or its property;

	•	the Trustee becomes incapable of acting;

	•	or specified events of bankruptcy, insolvency or reorganization with respect to the Trustee occur.

JPMorgan Chase Bank, successor in interest to The Chase Manhattan Bank, is the Trustee. We maintain banking relationships with the Trustee in the ordinary course of business. The Trustee also acts as trustee for some of our other securities as well as securities of some of our affiliates.

The Indenture and the exchange notes are governed by, and construed in accordance with, the laws of the State of New York.

Except as set forth below, the exchange notes will initially be issued in the form of one or more global notes (each, a “new global note”). Each new global note will be deposited on the date of the closing of the exchange of the original notes for the exchange notes with, or on behalf of, The Depository Trust Company and will be registered in the name of DTC or its nominee. Investors may hold their beneficial interests in a new global note 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 notes, the new global notes 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 notes, DTC or its custodian will credit, on its internal system, the respective principal amounts of the exchange notes represented by the new global notes to the accounts of persons who have accounts with DTC. Ownership of beneficial interests in the new global notes 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 notes 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 notes, DTC or the nominee, as the case may be, will be considered the sole record owner or holder of the exchange notes represented by the new global notes for all purposes under the Indenture and the exchange notes. No beneficial owners of an interest in the new global notes 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 notes will not:


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

	•	be considered to be the owners or holders of any exchange notes under the new global notes.

Accordingly, each person owning a beneficial interest in new global notes 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 notes under the new global notes. We understand

Payments of the principal of, premium, if any, and interest on the exchange notes represented by the new global notes 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 notes. 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 notes 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 notes will credit participants’ accounts with payments in amounts proportionate to their respective beneficial ownership interests in the principal amount of the new global notes, 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 notes 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 notes 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 notes in definitive form, the new global notes 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 notes, including the presentation of notes for exchange as described below, only at the direction of one or more participants to whose account the DTC interests in the new global notes are credited. Further, DTC will take any action permitted to be taken by a holder of notes only in respect of that portion of the aggregate principal amount of notes 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 notes 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 notes may, upon request to the trustee, exchange the beneficial interest for exchange notes in the form of certificated notes. Upon any issuance of certificated notes, the trustee is required to register the certificated notes 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 notes, and a successor depositary is not appointed by us within 120 days, we will issue certificated notes in exchange for the new global notes.

As part of the sale of the original notes, under a registration rights agreement, dated as of October 6, 2003, we agreed with the initial purchasers in the offering of the original notes, for the benefit of the holders of the original notes, to file with the SEC an exchange offer registration statement (an “Exchange Offer Registration Statement”) for the purpose of offering exchange notes in exchange for original notes (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 note is not eligible to participate in the Registered Exchange Offer;

	•	for any other reason the Registered Exchange Offer is not consummated within 210 days after the date of issue of the original notes;

	•	an initial purchaser so requests with respect to original notes not eligible to be exchanged for exchange notes in the Registered Exchange Officer; or

	•	any initial purchaser who participates in the Registered Exchange Offer does not receive freely tradeable exchange notes in the Registered Exchange Offer;


	•	as promptly as practicable, but in no event more than 120 days after becoming required to do so, file a registration statement under the Securities Act covering continuous resales of the original notes or the exchange notes, 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 notes covered by the Shelf Registration Statement can be sold pursuant to Rule 144 under the Securities Act without any limitations thereunder and (b) two years from the issuance of the original notes.

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 notes or the exchange notes, as the case may be. A holder that sells original notes 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).


	(1) 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;

	(2) 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 original notes or exchange notes, as the case may be, as provided in and during the periods specified in the registration rights agreement (each such event referred to in clauses (1) and (2), 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 notes or exchange notes.

We will pay liquidated damages to the holders of global notes by wire transfer of immediately available funds or by federal funds check and to holders of certificated notes 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.

The following is a discussion of the material U.S. federal income tax consequences of the exchange of original notes for exchange notes. 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 notes upon their original issuance and that hold the original notes, and will hold the exchange notes, 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 notes 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 notes for exchange notes will not be taxable for U.S. federal income tax purposes because the exchange notes will not be considered to differ materially in kind or extent from the original notes. Rather, the exchange notes you receive will be treated as a continuation of your investment in the original notes. Accordingly, you will not recognize gain or loss upon the exchange of original notes for exchange notes pursuant to the exchange offer, your tax basis in the exchange notes will be the same as your adjusted tax basis in the original notes immediately before the exchange, and your holding period for the exchange notes will include the holding period for the original notes exchanged therefor. There will be no U.S. federal income tax consequences to holders that do not exchange their original notes 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 notes issued in the exchange offer if:


	•	you acquire the exchange notes 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 notes.

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


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

	•	a broker-dealer that acquired original notes directly from us; or

	•	a broker-dealer that acquired original notes 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 notes for exchange notes 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 notes for its own account under the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. Broker-dealers may use this prospectus, as it may be amended or supplemented from time to time, for resales of exchange notes received in exchange for original notes where the original notes 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 210 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 notes by broker-dealers. Broker-dealers may sell exchange notes 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 notes; 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 notes. Any broker-dealer that receives exchange notes for its own account under the exchange offer and any broker or dealer that participates in a distribution of such exchange notes may be deemed to be an “underwriter” within the meaning of the Securities Act. Any profit on any such resale of exchange notes and any commission or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver, and by delivering, a prospectus, a broker-dealer will not admit that it is an “underwriter” within the meaning of the Securities Act.

Furthermore, any broker-dealer that acquired any of its original notes 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 noteholder 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 notes (including any broker-dealers) against some liabilities, including liabilities under the Securities Act.

Legal opinions relating to the exchange notes will be rendered by our counsel, Jones Day, Chicago, Illinois, and Hinkle, Hensley, Shanor & Martin, L.L.P., Austin, Texas. Hinkle, Hensley, Shanor & Martin, L.L.P. will pass upon matters pertaining to the laws of the State of New Mexico. Jones Day will pass only upon matters pertaining to New York and federal law.

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 Southwestern Public Service Company 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. Southwestern Public Service Company has been unable to obtain, after reasonable efforts, the written 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 Southwestern Public Service Company, including claims that may arise out of Arthur Andersen LLP’s audit of financial statements included in this prospectus. Southwestern Public Service Company 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:

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

The consolidated financial statements of Southwestern Public Service Company for the years ended December 31, 2001 and 2000 were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion and included an explanatory paragraph related to the Company’s adoption of Statement of Financial Accounting Standards No. 133 — “Accounting for Derivative Instruments and Hedging Activity” 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 consolidated 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 referred to above present fairly, in all material respects, the financial position of Southwestern Public Service Company and 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 Southwestern Public Service Company (a New Mexico corporation) as of December 31, 2001 and 2000, and the related consolidated statements of income, stockholder’s equity and cash flows for each of the three 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 Southwestern Public Service Company as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States.

As discussed in Note 12 to the consolidated financial statements, effective January 1, 2001 Southwestern Public Service Company adopted Statement of Financial Accounting Standard No. 133, “Accounting for Derivative Instruments and Hedging Activity,” which changed its method of accounting for certain commodity contracts and other derivatives.

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 there in relation to the basic financial statements taken as a whole.

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 — SPS is a wholly-owned subsidiary of Xcel Energy and is engaged principally in the generation, purchase, transmission, distribution and sale of electricity. SPS is subject to the regulatory provisions of the PUHCA. SPS is subject to regulation by the FERC and state utility commissions. SPS’ 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 — SPS has a subsidiary, which has been consolidated. In the consolidation process, we eliminate all significant intercompany transactions and balances.

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.

SPS has various rate adjustment mechanisms in place that currently provide for the recovery of certain fuel and purchased power 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.

SPS’ rates in Texas have fixed fuel factor and periodic fuel filing, reconciling and reporting requirements, which provide cost recovery. In New Mexico, SPS has recently reinstituted a monthly fuel and purchased power cost recovery factor.

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.

SPS determines the depreciation of their plant by using the straight-line method, which spreads the original cost equally over the plant’s useful life. Depreciation expense for SPS 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 SPS’ rate base for establishing utility service rates. Interest capitalized as AFDC for SPS 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 SPS, 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. SPS defers 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 — SPS utilizes 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.

On Jan. 1, 2001, SPS adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activity,” as amended by SFAS No. 137 and SFAS No. 138 (collectively referred to as SFAS No. 133). For more information on the impact of SFAS No. 133, see Notes 11 and 12 to the Consolidated Financial Statements.

Use of Estimates — In recording transactions and balances resulting from business operations, SPS 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 — SPS 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 — SPS 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, SPS 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.

SPS 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. SPS’ deferred financing costs, net of amortization at Dec. 31, are listed in the following table:

2002 — Regulatory Recovery Adjustment — In late 2001, SPS filed an application requesting recovery of costs incurred to comply with transition to retail competition legislation in Texas and New Mexico. During the first quarter of 2002, SPS entered into a settlement agreement with intervenors regarding the recovery of restructuring costs in Texas, subject to approval by the state regulatory commission. Based on the settlement agreement, SPS wrote off pretax restructuring costs of approximately $5 million.

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 SPS, 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.

Of the total pretax special charges recorded by Xcel Energy that related to its regulated operations, $159 million was recorded during the third quarter of 2000 and $40 million was recorded during the fourth quarter of 2000. See Note 18 to the Consolidated Financial Statements for the quarterly impacts on Xcel Energy’s utility subsidiaries.

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:

Notes Payable and Commercial Paper — Information regarding notes payable and commercial paper for the years ended Dec. 31, 2002 and 2001 is:

Bank Lines of Credit — At Dec. 31, 2002, SPS had credit facilities with several banks. SPS paid for these lines of credit with fee payments.

The SPS $250 million facility expired on Feb. 18, 2003 and was replaced on that date with a $100 million unsecured, 364-day credit agreement. The facility provides short-term financing in the form of bank loans and letters of credit.

Certain SPS payments under its pollution control obligations are pledged to secure obligations of the Red River Authority of Texas.

SPS Capital I, a wholly owned, special-purpose subsidiary trust of SPS, has $100 million of 7.85 percent trust preferred securities issued and outstanding that mature in 2036. Distributions paid by the subsidiary trust on the preferred securities are financed through interest payments on debentures issued by SPS and held by the subsidiary trust, which are eliminated in consolidation. The securities are redeemable at the option of SPS, at 100 percent of the principal amount plus accrued interest. Distributions and redemption payments are guaranteed by SPS.

Distributions paid to preferred security holders are reflected as a financing cost in the accompanying Consolidated Statements of Income along with interest expense.

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. SPS had 757 union employees covered under a collective bargaining agreement, which expires in October 2005.

Pension Benefits — Xcel Energy has several noncontributory, defined benefit pension plans that cover almost all utility employees. 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:

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 $1.9 million for SPS.

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.

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:

In the second quarter of 2000, SPS discontinued regulatory accounting under SFAS No. 71 for the generation portion of its business due to the issuance of a written order by the PUCT in May 2000, addressing the implementation of electric utility restructuring. SPS’ transmission and distribution business continued to meet the requirements of SFAS No. 71, as that business was expected to remain regulated. During the second quarter of 2000, SPS wrote off its generation related regulatory assets and other deferred costs totaling approximately $19.3 million. This resulted in an after-tax extraordinary charge of approximately $13.7 million. During the third quarter of 2000, SPS recorded an extraordinary charge of $8.2 million before tax, or $5.3 million after tax, related to the tender offer and defeasance of first mortgage bonds. The first mortgage bonds were defeased to facilitate the legal separation of generation, transmission and distribution assets, which was expected to eventually occur in 2001 under restructuring requirements in effect in 2000.

In March 2001, the state of New Mexico enacted legislation that amended its Electric Utility Restructuring Act of 1999 and delayed customer choice until 2007. SPS has requested recovery of its costs incurred to prepare for customer choice in New Mexico. A decision on this and other matters is pending before the NMPRC. SPS expects to receive future regulatory recovery of these costs.

In June 2001, the Governor of Texas signed legislation postponing the deregulation and restructuring of SPS until at least 2007. This legislation amended the 1999 legislation, SB-7, which provided for retail electric competition beginning January 2002. Under the amended legislation, prior PUCT orders issued in connection with the restructuring of SPS are considered null and void. In addition, under the new legislation, SPS is entitled to recover all reasonable and necessary expenditures made or incurred before Sept. 1, 2001, to comply with SB-7.

As a result of these legislative developments, SPS reapplied the provisions of SFAS No. 71 for its generation business during the second quarter of 2001. More than 95 percent of SPS’ retail electric revenues are from operations in Texas and New Mexico. Because of the delays to electric restructuring passed by Texas and New Mexico, SPS’ previous plans to implement restructuring, including the divestiture of generation assets, have been abandoned. Accordingly, SPS will continue to be subject to rate regulation under traditional cost-of-service regulation, consistent with its past accounting and ratemaking practices for the foreseeable future (at least until 2007).

During the fourth quarter of 2001, SPS completed a $500 million medium-term debt financing with the proceeds used to reduce short-term borrowings that had resulted from the 2000 defeasance. In its regulatory filings and communications, SPS proposed to amortize its defeasance costs over the five-year life of the refinancing, consistent with historical ratemaking, and requested incremental rate recovery of $25 million of other restructuring costs in Texas and New Mexico. These nonfinancing restructuring costs have been deferred and are being amortized consistent with rate recovery. Management believes it will be allowed full recovery of its prudently incurred costs. Based on these 2001 events and the corresponding reduced uncertainty surrounding the financial impacts of the delay in restructuring, SPS restored certain regulatory assets totaling $17.6 million as of Dec. 31, 2001, and reported related after-tax extraordinary income of $11.8 million. Regulatory assets previously written off in 2000 were restored only for items being recovered in current rates and for items where future rate recovery is considered probable.

See Note 2 for discussion of special charges related to SPS restructuring in 2002.

The estimated December 31 fair values of Xcel Energy’s utility subsidiaries’, including SPS, 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 values of SPS’ long-term investments are estimated based on quoted market prices for those or similar investments. The fair value of SPS’ long-term debt and the mandatorily redeemable preferred securities are 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.

The discussion below briefly describes the derivatives of SPS and discloses the respective fair values at Dec. 31, 2002. For more detailed information regarding derivative financial instruments and the related risks, see Note 12 to the Consolidated Financial Statements.

Interest Rate Swaps — On both Dec. 31, 2002 and 2001, SPS had an interest rate swap, converting variable-rate debt to fixed-rate debt, with a notional amount of $25 million. The fair value of the swap on both Dec. 31, 2002 and 2001 was a liability of approximately $7 million.

SPS uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. The following table details the letters of credit outstanding for SPS at Dec. 31, 2002. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined by the market.

Business and Operational Risk — SPS is exposed to commodity price risk in their generation and retail distribution operations. SPS recovers purchased energy expenses on a dollar-for-dollar basis.

SPS manages commodity price risk by entering into purchase and sales commitments for electric power, long-term contracts for coal supplies and fuel oil, and derivative financial instruments. Xcel Energy’s risk management policy allows SPS to manage the market price risk within each rate regulated operation to the extent such exposure exists. Management is limited under the policy to enter into only transactions that reduce market price risk where the rate regulation jurisdiction does not already provide for dollar-for-dollar recovery.

Interest Rate Risk — SPS is exposed to fluctuations in interest rates where they 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. Xcel Energy’s risk management policy allows the utility subsidiaries to reduce interest rate exposure from variable rate debt obligations.

See Note 11 to the Consolidated Financial Statements for a discussion of SPS’ interest rate swaps.

2001 Accounting Change — On Jan. 1, 2001, Xcel Energy and SPS adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” 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 income statement, 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.

A fair value hedge requires that the effective portion of the change in the fair value of a derivative instrument be offset against the change in the fair value of the underlying asset, liability, or firm commitment being hedged. That is, fair value hedge accounting allows the gain or loss on the hedged item to offset the gain or loss on the derivative instrument in the same period. A cash flow hedge requires that the effective portion of the change in the fair value of a derivative instrument be recognized in Other Comprehensive Income, and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. The ineffective portion of a derivative instrument’s change in fair value is recognized currently in earnings.

SPS formally documents hedge relationships, including, among other things, the identification of the hedging instrument and the hedged transaction, as well as the risk management objectives and strategies for undertaking the hedged transaction. Derivatives are recorded in the balance sheet at fair value. SPS also formally assesses, both at inception and at least quarterly thereafter, whether the derivative instruments being used are highly effective in offsetting changes in either the fair value or cash flows of the hedged items.

The components of SFAS No. 133 impacts on Other Comprehensive Income for 2002 and 2001, included in Stockholder’s Equity, are detailed in the following table (Millions of dollars).

SPS did not realize any material impact to earnings related to ineffective hedges during 2002 and 2001.

SPS records the fair value of derivative instruments in the Consolidated Balance Sheets as separate line items noted as “Derivative Instruments Valuation” for assets and liabilities, as well as current and non-current.

and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. SPS reclassified into earnings during 2002 net after-tax gains from Other Comprehensive Income of approximately $0.5 million.

Normal Purchases or Normal Sales — SPS enters into fixed price contracts for the purchase and sale of various commodities for use in its 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 as normal and exempted from the accounting and reporting requirements of SFAS No. 133.

SPS evaluates all of its contracts when such contracts are entered into to determine if they are derivatives and if so, if they qualify and meet the normal designation requirements under SFAS No. 133. None of the contracts entered into within the trading operations are considered normal.

Normal purchases and normal sales contracts are accounted for as executory contracts as required under other generally accepted accounting principles.

Leases — SPS leases a variety of equipment and facilities used in the normal course of business.

The remainder of the 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 SPS are listed in the following table:

Fuel Contracts — SPS has contracts providing for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2003 and 2025. In addition, SPS is required to pay additional amounts depending on actual quantities shipped under these agreements. The potential risk of loss for SPS, 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.

Purchased Power Agreements — SPS has entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. SPS has various pay-for-performance contracts with expiration dates through the year 2050. In general, these contracts provide for capacity payments, subject to meeting certain contract obligations and energy payments based on actual power taken under the contracts. Most of the capacity and energy costs are recovered through base rates and other cost recovery mechanisms.

At Dec. 31, 2002, the estimated future payments for capacity that SPS is obligated to purchase, subject to availability, are as follows (Thousands of dollars):

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.

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.

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

An electric cooperative in Lamb County, Texas filed a complaint with the PUCT regarding SPS’ alleged unlawful provision of service to oil-field customers and the cooperative’s facilities in the cooperative’s certified service area. SPS is awaiting a decision on this matter from a state administrative law judge. In addition, pending a final administrative determination on the lawfulness of SPS’ service, the cooperative has also commenced related litigation against SPS for damages. Damages resulting from decisions on these legal matters that are adverse to SPS could be material. However, SPS does not consider an adverse outcome probable at this time and consequently no costs have been accrued for this matter.

In 2001, Golden Spread filed a complaint against SPS and a request for investigation before the FERC. Golden Spread alleges SPS has violated provisions of an agreement pursuant to which SPS conducts joint dispatch of SPS and Golden Spread resources. Golden Spread seeks damages in excess of $10 million. SPS

denies all of Golden Spread’s allegations, and has filed a counter-complaint against Golden Spread in which it has alleged that Golden Spread has failed to adhere to certain requirements of the agreement. Both complaints are presently pending before the FERC and settlement procedures have been ordered by the Commission. Settlement discussions are ongoing. Even if SPS is required to pay more to Golden Spread for power purchased under this agreement, we believe that the amounts are likely to be recoverable from customers under SPS’ various fuel clause mechanisms.

In the normal course of business, SPS made a filing to facilitate the PUCT’s review of electric generation and fuel management activities, totaling approximately $608 million, for the period from January 2000 through December 2001. This proceeding is ongoing, and intervenor and PUCT staff testimony is being reviewed. Intervenors have proposed that revenues from certain wholesale transactions be credited to Texas retail customers. SPS is opposing this proposed revenue treatment, and believes all deferred costs under review are recoverable in future rates.

SPS prepares its 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 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 of SPS are:


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

	This table excludes deferred energy charges expected to be recovered within the next 12 months of $16 million for 2002, and energy cost recovery expected to be returned to customers within the next 12 months of $40 million for 2001.

The adoption of SFAS No. 143 in 2003 will also affect SPS’ 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:

SPS has only one reportable segment. SPS operates in the regulated electric utility industry providing wholesale and retail electric service in the states of Texas, New Mexico, Kansas and Oklahoma. Revenues from external customers were $1,025.2 million, $1,385.5 million and $1,079.6 million for the years ended Dec. 31, 2002, 2001 and 2000, respectively.

SPS receives various administrative, management, environmental and other support services from Xcel Energy Services Inc., which began operations in August 2000. Prior to this, New Century Services provided these support services to SPS before the merger to form Xcel Energy.

SPS receives construction services from Utility Engineering. In addition, SPS pays interest expense on any short-term borrowings from Xcel Energy.

In 2000, SPS received interest income from Xcel Energy’s Wholesale Energy Group Inc. subsidiary on the note receivable related to the sale of Utility Engineering and its affiliate, Quixx, as part of the PSCo/SPS Merger.

The table below contains significant affiliate transactions among the companies and related parties for the years ended Dec. 31:


*	Operating expense includes $68,045, $72,259, and $210,174 paid to Xcel Energy Services Inc. in 2002, 2001 and 2000.


(a)	2002 results include special charges as discussed in Note 2 to the Financial Statements. First quarter results were decreased by $5 million for a pretax special charge related to restructuring costs.

(b)	2001 results include special charges as discussed in Note 2 to the Financial Statements. Fourth quarter results were decreased by $5 million for a pretax special charge related to employee restaffing costs.

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly the financial position of SPS 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 SPS’ electric sales, interim results are not necessarily an appropriate base from which to project annual results.

The accounting policies of SPS are set forth in Note 1 to its consolidated financial statements for the year ended Dec. 31, 2002 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 this 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.

SPS 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 also affects accrued plant removal costs for other generation, transmission and distribution facilities for SPS. 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, SPS 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:

Regulatory Recovery Adjustment (2002) — During the first quarter of 2002, SPS wrote off approximately $5 million of restructuring costs relating to costs incurred to comply with legislation requiring a transition to retail competition in Texas, which was subsequently amended to delay the required transition.

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 SPS. All 564 of accrued staff terminations occurred in 2002 and as of Sept. 30, 2003, all severance payments have been made.

SPS Texas Fuel Reconciliation, Fuel Factor and Fuel Surcharge Applications — In June 2002, SPS filed an application for the Public Utility Commission of Texas (PUCT) to retrospectively review the operations of the utility’s electric generation and fuel management activities. In this application, SPS filed its reconciliation for electric generation and fuel management activities, totaling approximately $608 million, from January 2000 through December 2001. In May 2003, a stipulation was approved by the PUCT. The stipulation resolves all issues regarding SPS’ fuel costs and wholesale trading activities through December 2001. SPS will withdraw, without prejudice, its request to share in 10 percent of margins from certain wholesale non-firm sales. SPS will recover $1.1 million from Texas customers for the proposed sharing of wholesale non-firm sales margins. The parties agreed that SPS would reduce its December 2001 fuel under-recovery balances by $5.8 million. Including the withdrawal of proposed margin sharing of wholesale non-firm sales, the net impact to SPS’ deferred fuel expense, before tax, is a reduction of $4.7 million.

In May 2003, SPS proposed to increase its voltage-level fuel factors to reflect increased fuel costs since the time SPS’ current fuel factors were approved in March 2002. The proposed fuel factors are expected to increase Texas annual retail revenues by approximately $60.2 million. SPS also reported to the PUCT that it has undercollected its fuel costs under the current Texas retail fixed fuel factors. In the same May 2003 application, SPS proposed to surcharge $13.2 million and related interest for fuel cost underrecoveries incurred through March 2003. In June 2003, the administrative law judge approved the increased fuel factors on an interim basis subject to hearings and completion of the case. The increased fuel factors became effective in July 2003. In July 2003, a unanimous settlement was reached adopting the surcharge and providing for the implementation of an expedited procedure for revising the fixed fuel factors on a semiannual basis. The surcharge will be collected from customers over an eight-month period. In August 2003, the PUCT approved the settlement and the new proposed fuel cost recovery process and the surcharge became effective in September 2003. The Texas retail fuel factors will change each November and May based on the projected cost of natural gas. Revenues will continue to be reconciled to fuel costs in accordance with Texas law.

In July 2003, SPS filed a second fuel cost surcharge factor application in Texas to recover an additional $26 million of fuel cost underrecoveries accrued during April through June 2003. In August 2003, the parties to the case filed a stipulation resolving various issues. The stipulation provided approval of SPS’ modified request to surcharge $15.7 million for the months April 2003 and May 2003 over 12 months beginning with the November 2003 billing cycle. The stipulation was approved by the PUCT in October 2003.

In November 2003, SPS submitted a third fuel cost surcharge factor application in Texas to recover an additional $25 million of fuel cost underrecoveries accrued during June through September 2003. If approved, the proposed surcharge will go into effect after the first surcharge is completed and will continue for 12 months beginning in May 2004. This case is pending review and approval by the PUCT.

SPS New Mexico Fuel Reconciliation and Fuel Factor Applications — On May 27, 2003, a hearing examiner for the New Mexico Public Regulatory Commission (NMPRC) issued a recommended decision on SPS’s fuel proceeding approving SPS utilizing a monthly fuel factor. SPS had been utilizing an annual fuel factor, which had allowed significant undercollections. The decision denied the intervernors’ request that all margins from off-system sales be credited to ratepayers. On Aug. 19, 2003, the NMPRC approved the hearing examiner’s recommended decision. In accordance with NMPRC regulations, SPS must file its next New Mexico fuel factor continuation case no later than August 2005.

SPS New Mexico Billing Practice Investigation — On Sept. 25, 2003, the NMPRC entered an order opening an investigation into estimated billing practices used to send estimated bills to approximately 9,500 customers for between two and five months. As part of the Sept. 25, 2003, order, the NMPRC also implemented temporary billing measures for customers whose bills were estimated. The temporary billing

measures: (i) require SPS to apply the lowest fuel and purchased power cost adjustment factor that was applicable during the period when meters were being estimated, (ii) allow customers six months to pay bills in full without additional charges or disconnection, (iii) prohibit disconnection of service until Nov. 1, 2003, for any customer that received an estimated bill, (iv) require a written explanation of the fuel calculation used under the order and (v) order a report of the amount of fuel and purchased power costs foregone as a result of the interim relief, which amount will not be allowed to be recovered from customers. The proceeding has been referred to a hearing examiner.

TRANSLink Transmission Co., LLC (TRANSLink) — In 2002, SPS filed for PUCT and NMPRC approval to transfer functional control of its electric transmission system to TRANSLink, of which SPS would be a participant. In March 2003, the Southwest Power Pool (SPP) and the MISO cancelled their planned merger to form a large mid-continent regional transmission organization (RTO). This development materially impacted SPS’ applications in Texas and New Mexico. SPS requested the cases be dismissed without prejudice while it evaluates possible RTO arrangements for the SPS system.

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 SPS’ financial position and results of operations.

Other Environmental Contingencies — SPS has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, SPS is pursuing, or intends to pursue, insurance claims and believes they will recover some portion of these costs through such claims. Additionally, where applicable, SPS 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, SPS would be required to recognize an expense for such unrecoverable amounts in its consolidated financial statements.

Golden Spread Electric Cooperative, Inc. — In October 2001, Golden Spread Electric Cooperative, Inc. (Golden Spread) filed a complaint and request for investigation against SPS at the FERC. Golden Spread alleged SPS has violated provisions of a commitment and dispatch service agreement pursuant to which SPS conducts joint dispatch of SPS and Golden Spread electric generating resources. SPS filed a complaint against Golden Spread in which it has alleged that Golden Spread has failed to adhere to certain requirements of the commitment and dispatch service agreement. In May 2003, SPS and Golden Spread reached a settlement that was approved by the FERC in July 2003. The $5-million accrued costs for payments under the settlement have been deferred by SPS as they are for economic purchased energy and are recoverable from SPS customers through the respective jurisdictional fuel and purchased power cost recovery mechanisms.

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. 6, 2003, SPS issued $100 million of 6-percent, Series C Senior Notes due 2033 in a private placement to qualified institutional buyers. On Oct. 15, 2003, the proceeds were used to redeem $100 million, 7.85-percent Trust Originated Preferred Securities of its trust subsidiary, Southwestern Public Service Capital I.

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


	•	maintenance of a minimum equity ratio of 30 percent;

	•	payment of dividends only from retained earnings; and

	•	debt covenant restrictions under the credit agreement for debt and interest coverage ratios.

SFAS No. 150 — In May 2003, the FASB issued SFAS No. 150 — “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (SFAS No. 150). 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 of 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 150, indefinitely. SPS had a special purpose subsidiary trust with outstanding mandatorily redeemable preferred securities of $100 million consolidated in SPS’ Consolidated Balance Sheets. This security was redeemed on Oct. 15, 2003.

SPS 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.

SPS 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, SPS has 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, SPS 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.

SPS enters into interest rate swap instruments that effectively fix the interest payments on certain floating rate debt obligations. 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. SPS expects to reclassify into earnings during the next 12 months net losses from Other Comprehensive Income of approximately $2.1 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. SPS is allowed to recover in electric rates the costs of certain financial instruments purchased to reduce commodity cost volatility.

SPS 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.

SPS evaluates all of their 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. None of the contracts entered into within the trading operations qualify for a normal designation.

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 SPS. SPS 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.

SPS operates in the regulated electric utility industry, providing wholesale and retail electric service in the states of Texas, New Mexico, Kansas and Oklahoma. Revenues from external customers were $380.5 million and $291.9 million for the three months ended Sept. 30, 2003 and 2002, respectively. Revenues from external customers were $909.4 million and $770.5 million for the nine months ended Sept. 30, 2003 and 2002, respectively.

The accumulated comprehensive income in Stockholder’s Equity at Sept. 30, 2003 and 2002, relates to valuation adjustments on SPS’ derivative financial instruments and hedging activities and unrealized losses related to its minimum pension liability.

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. The additional pension obligation recorded by SPS increased noncurrent liabilities by approximately $21 million and reduced Accumulated Other Comprehensive Income, a component of shareholder’s equity, by approximately $25 million (net of related deferred tax effects of $14 million) during the quarter. The minimum pension liability adjustment also increased SPS’ noncurrent intangible assets by approximately $40 million due to the recording of unamortized prior service costs, and reduced its previously recorded prepaid pension assets accordingly.

UNTIL OCTOBER 4, 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
SUMMARY
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 NOTES
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



				December 31,
		September 30,
		2003		2002		2001		2000		1999		1998


		(Thousands of dollars)
Consolidated Balance Sheet Data:
Current assets		$	248,675	$	226,997	$	237,327	$	296,037	$	156,690	$	117,537
Net property, plant and equipment			1,816,251		1,803,538		1,836,394		1,800,754		1,773,815		1,729,339
Other assets			225,743		234,809		227,059		295,845		291,656		282,988

	Total assets	$	2,290,669	$	2,265,344	$	2,300,780	$	2,392,636	$	2,222,161	$	2,129,864

Current liabilities		$	233,606		175,987		209,270		928,071		348,668		361,151
Deferred credits and other liabilities			434,212		434,985		420,115		386,430		406,235		399,875
Long-term debt			725,878		725,662		725,375		226,506		605,875		530,618
Mandatorily redeemable preferred securities of subsidiary trust(3)			100,000		100,000		100,000		100,000		100,000		100,000
Common stockholder’s equity			796,973		828,710		846,020		751,629		761,383		738,220

	Total liabilities and equity	$	2,290,669	$	2,265,344	$	2,300,780	$	2,392,636	$	2,222,161	$	2,129,864


	Base
	Electric			Short-Term			Consolidated
	Utility			Wholesale			Totals


	(Millions of dollars)
Nine months ended September 30, 2003
Electric utility revenue	$	904		$	5		$	909
Electric fuel and purchased power		(539	)		(4	)		(543	)

Gross margin before operating expenses	$	365		$	1		$	366

Margin as a percentage of revenue		40.4	%		20.0	%		40.3	%
Nine months ended September 30, 2002
Electric utility revenue	$	767		$	4		$	771
Electric fuel and purchased power		(411	)		(4	)		(415	)

Gross margin before operating expenses	$	356		$	—		$	356

Margin as a percentage of revenue		46.4	%		—	%		46.2	%


	Base
	Electric			Short-Term			Consolidated
	Utility			Wholesale			Totals


	(Millions of dollars)
Year ended December 31, 2002
Electric utility revenue	$	1,019		$	6		$	1,025
Electric fuel and purchased power		(550	)		(5	)		(555	)

Gross margin before operating expenses	$	469		$	1		$	470

Margin as a percentage of revenue		46.0	%		16.7	%		45.9	%
Year ended December 31, 2001
Electric utility revenue	$	1,382		$	3		$	1,385
Electric fuel and purchased power		(862	)		(2	)		(864	)

Gross margin before operating expenses	$	520		$	1		$	521

Margin as a percentage of revenue		37.6	%		33.3	%		37.6	%
Year ended December 31, 2000
Electric utility revenue	$	1,071		$	9		$	1,080
Electric fuel and purchased power		(575	)		(7	)		(582	)

Gross margin before operating expenses	$	496		$	2		$	498

Margin as a percentage of revenue		46.3	%		22.2	%		46.1	%


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
		• Interest rates used in valuing benefit obligation
		• Actuarial period selected to recognize deferred investment gains and losses


	Page

Special Note Regarding Forward-Looking Statements		i
Summary		1
Risk Factors		10
Use of Proceeds		19
The Exchange Offer		19
Capitalization		27
Selected Consolidated Financial Data		28
Management’s Discussion and Analysis of Financial Condition and Results of Operations		30
Business		45
Management		58
Certain Relationships and Related Transactions		68
Description of Other Indebtedness		70
Description of the Exchange Notes		70
Book-Entry System		76
Exchange Offer and Registration Rights		78
Material United States Federal Income Tax Considerations		80
Plan of Distribution		81
Legal Opinions		82
Experts		82
Where You Can Find More Information		83
Index to Financial Statements		F-1


	•	the exchange notes will have been registered under the Securities Act;

	•	the exchange notes will not contain transfer restrictions; and

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


		entered into in connection with the private offering of the original notes.

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 notes for exchange notes.


(1)	The 2000 Consolidated Statement of Operations Data has been adjusted to reflect the implementation of Statement of Financial Accounting Standard (“SFAS”) No. 145, which became effective in 2003 and requires retroactive restatement of prior periods. Interest charges and financing costs of $8.225 million related to the defeasance of our first mortgage bonds, previously disclosed in Extraordinary items, was reclassified to Interest charges and financing costs. Associated income tax benefits of $2.923 million have been reclassified from Extraordinary items to Income taxes. The reclassification had no impact on operating income or net income. The 2000 financial data were derived from financial statements audited by Arthur Andersen LLP, independent public accountants. However, due to the reclassification required by SFAS No. 145, the Consolidated Statement of Operations Data in the Summary Historical Financial Data disclosed above does not agree to the financial statements as audited by Arthur Andersen LLP with respect to Interest charges and financing costs. We have been unable to obtain the consent of Arthur Andersen LLP to the use of their report in this prospectus.

(2)	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.

(3)	On October 15, 2003, we redeemed $100 million of our mandatorily redeemable preferred securities of our subsidiary trust (together with our Subordinated Debenture).


	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 notes 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 are currently the subject of an investigation by the NMPRC regarding estimated billing practices and we may face remedial or punitive action.*


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


	*Recession, regional black-outs or acts of war or terrorism could negatively impact our business.*


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


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


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


	*The exchange notes would have a claim that is junior with respect to the assets securing any secured debt that we may issue.*


	*Any lowering of the credit ratings on the exchange notes would likely reduce their value.*


	*The exchange notes have no prior public market and a public market may not develop or be sustained after the offering.*


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


	*You may have difficulty selling the original notes which you do not exchange.*


	*You must tender the original notes in accordance with proper procedures in order to ensure the exchange will occur.*


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


By Registered, Certified or by Hand or Overnight Delivery: JPMorgan Chase Bank Institutional Trust Services 2001 Bryan Street 9th Floor Dallas, Texas 75221 Attention: Frank Ivins		By Facsimile: Attention: Frank Ivins (214) 468-6494



		As of September 30, 2003
		(unaudited)

		(Thousands of dollars)		(% of Capitalization)

Long-term debt		$	725,878		44.7	%
Mandatorily redeemable preferred securities of subsidiary trust(1)			100,000		6.2	%
Common stockholder’s equity			796,973		49.1	%

	Total capitalization	$	1,622,851		100.0	%



		Nine months ended
		September 30				Year Ended December 31,

		2003		2002		2002		2001		2000(1)			1999		1998


		(Thousands of dollars)
Consolidated Statement of Operations Data:
Operating revenue		$	909,402	$	770,466	$	1,025,178	$	1,385,458	$	1,079,580		$	925,937	$	951,187
Operating expense			765,729		638,319		860,060		1,154,901		881,327			713,178		719,812

	Operating income		143,673		132,147		165,118		230,557		198,253			212,759		231,375
Other income, net			4,319		4,174		6,025		11,814		11,468			10,784		7,611
Interest charges and financing costs			39,187		40,292		53,898		52,917		70,718			61,435		58,303
Income taxes			41,693		36,111		43,363		71,175		55,853			59,399		65,696
Extraordinary items(2)			—		—		—		11,821		(13,658	)		—		—

	Net income	$	67,112	$	59,918	$	73,882	$	130,100	$	69,492		$	102,709	$	114,987


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


	2003		2004		2005


	(Thousands of dollars)
Total capital expenditures	$	92,445	$	104,684	$	80,847
Sinking funds and debt maturities		—		—		—

Total capital requirements	$	92,445	$	104,684	$	80,847



			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	$	726,800	$	—	$	—	$	500,000	$	226,800
Operating leases		12,819		2,144		4,310		4,250		2,115
Unconditional purchase obligations		1,844,164		183,936		339,454		264,953		1,055,821
Other long-term obligations		100,000		—		—		—		100,000
Short-term debt		—		—		—		—		—

Total contractual cash obligations	$	2,683,783	$	186,080	$	343,764	$	769,203	$	1,384,736