UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

Commission File Number 1-3034

Registrant’s Telephone Number, including Area Code (612) 330-5500

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of Act:      None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes o No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). x Yes o No

As of June 28, 2003, the aggregate market value of the voting common stock held by non-affiliates of the Registrant was $5,991,223,342 and there were 398,731,917 shares of common stock outstanding.

As of March 5, 2004, there were 398,146,597 shares of common stock outstanding, $2.50 par value.

DOCUMENTS INCORPORATED BY REFERENCE

TABLE OF CONTENTS

Index

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Item 1. Business

COMPANY OVERVIEW

Xcel Energy Inc. (Xcel Energy), a Minnesota corporation, is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). In 2003, Xcel Energy directly owned five utility subsidiaries that serve electric and natural gas customers in 11 states. These utility subsidiaries are Northern States Power Co., a Minnesota corporation (NSP-Minnesota); Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado (PSCo); Southwestern Public Service Co. (SPS); and Cheyenne Light, Fuel and Power Co. (Cheyenne). These utilities serve customers in portions of Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas, Wisconsin and Wyoming. Along with WestGas InterState Inc. (WGI), an interstate natural gas pipeline, these companies comprise our continuing regulated utility operations. In January 2003, Xcel Energy sold Viking Gas Transmission Co. (Viking), an interstate natural gas pipeline company. In October 2003, Xcel Energy sold Black Mountain Gas Co. (BMG), a regulated natural gas and propane distribution company. Both Viking and BMG are reported as a component of discontinued operations. In January 2004, Xcel Energy reached an agreement to sell Cheyenne, pending regulatory approval.

Xcel Energy’s nonregulated subsidiaries in continuing operations include Utility Engineering Corp. (engineering, construction and design); Seren Innovations, Inc. (broadband telecommunications services); Planergy International, Inc. (energy management solutions); and Eloigne Co. (investments in rental housing projects that qualify for low-income housing tax credits). During 2003, the board of directors of Xcel Energy approved management’s plan to exit certain businesses conducted by the nonregulated subsidiaries Xcel Energy International Inc. (an international independent power producer, primarily in Argentina) and e prime inc. (a natural gas marketing and trading company). Both of these businesses are presented as a component of discontinued operations. Also during 2003, Planergy closed and sold a majority of its business operations and final dissolution is expected in 2004.

During 2003, Xcel Energy also divested its ownership interest in NRG Energy, Inc. (NRG), an independent power producer. On May 14, 2003, NRG and certain of its affiliates filed voluntary petitions in the U. S. Bankruptcy Court for the Southern District of New York for reorganization under Chapter 11 of the U.S. Bankruptcy Code to restructure their debt. On Dec. 5, 2003, NRG completed its reorganization and emerged from bankruptcy. As a result of the reorganization, Xcel Energy relinquished its ownership interest in NRG. At Dec. 31, 2003, Xcel Energy reports NRG’s financial activity as a component of discontinued operations. Xcel Energy is obligated to make payments of up to $752 million to NRG in early 2004 and expects to fund these payments with cash on hand, borrowings against Xcel Energy’s revolving credit facilities and proceeds from a tax refund associated with the write-off of its investment in NRG.

Xcel Energy was incorporated under the laws of Minnesota in 1909. Its executive offices are located at 800 Nicollet Mall, Minneapolis, Minn. 55402.

For information on the nonregulated subsidiaries of Xcel Energy, see Nonregulated Subsidiaries under Item 1. For information regarding Xcel Energy’s segments, see Note 20 to the Consolidated Financial Statements.

Xcel Energy’s web site address is www.xcelenergy.com. Xcel Energy makes available, free of charge through its web site, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (SEC).

Regulated Subsidiaries

NSP-Minnesota

NSP-Minnesota was incorporated in 2000 under the laws of Minnesota. NSP-Minnesota is an operating utility engaged in the generation, purchase, transmission, distribution and sale of electricity in Minnesota, North Dakota and South Dakota. NSP-Minnesota also purchases, distributes and sells natural gas to retail customers and transports customer-owned natural gas in Minnesota and North Dakota. NSP-Minnesota provides electric utility service to approximately 1.3 million customers and gas utility service to approximately 440,000 customers.

NSP-Minnesota owns the following direct subsidiaries: United Power and Land Co., which holds real estate; and NSP Nuclear Corp., which holds NSP-Minnesota’s interest in the Nuclear Management Co. NSP-Minnesota owned NSP Financing I, a special purpose financing trust, for which a certificate of cancellation was filed for dissolution on Sept. 15, 2003.

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NSP-Wisconsin

NSP-Wisconsin was incorporated in 1901 under the laws of Wisconsin. NSP-Wisconsin is an operating utility engaged in the generation, transmission and distribution of electricity to approximately 235,000 customers in northwestern Wisconsin and in the western portion of the Upper Peninsula of Michigan. NSP-Wisconsin is also engaged in the distribution, sale and transport of customer-owned natural gas in the same service territory to approximately 95,000 customers.

NSP-Wisconsin owns the following direct subsidiaries: Chippewa and Flambeau Improvement Co., which operates hydro reservoirs; Clearwater Investments Inc., which owns interests in affordable housing; and NSP Lands, Inc., which holds real estate.

PSCo

PSCo was incorporated in 1924 under the laws of Colorado. PSCo is an operating utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity and the purchase, transportation, distribution and sale of natural gas. PSCo serves approximately 1.3 million electric customers and approximately 1.2 million natural gas customers in Colorado.

PSCo owns the following direct subsidiaries: 1480 Welton, Inc., which owns certain real estate interests for PSCo; P.S.R. Investments, Inc., which owns and manages permanent life insurance policies on certain employees; and Green and Clear Lakes Company, which owns water rights. PSCo also holds a controlling interest in several other relatively small ditch and water companies whose capital requirements are not significant. PS Colorado Credit Corp., a finance company that was owned by PSCo and financed certain of PSCo’s current assets, was dissolved in 2002. PSCo owned PSCo Capital Trust I, a special purpose financing trust, for which a certificate of cancellation was filed for dissolution on Dec. 29, 2003.

SPS

SPS was incorporated in 1921 under the laws of New Mexico. SPS is an operating utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity. SPS serves approximately 395,000 electric customers in portions of Texas, New Mexico, Oklahoma and Kansas. The wholesale customers served by SPS comprise approximately 38 percent of the total kilowatt-hour sales. A major portion of SPS’ retail electric operating revenues is derived from operations in Texas.

At Dec. 31, 2003, SPS owned a direct subsidiary, Southwestern Public Service Capital I (SPS Capital I), a special purpose financing trust, for which a certificate of cancellation was filed for dissolution on Jan. 5, 2004.

Other Regulated Subsidiaries

Cheyenne was incorporated in 1900 under the laws of Wyoming. Cheyenne is an operating utility engaged in the purchase, transmission, distribution and sale of electricity and natural gas, primarily serving approximately 38,000 electric customers and 31,000 natural gas customers in and around Cheyenne, Wyo. In January 2004, Xcel Energy reached an agreement to sell Cheyenne, pending regulatory approval.

BMG is a natural gas and propane distribution company located in Cave Creek, Ariz. In October 2003, Xcel Energy sold BMG.

Viking is an interstate natural gas pipeline serving portions of Minnesota, Wisconsin and North Dakota. In January 2003, Xcel Energy sold Viking, including its ownership interest in Guardian Pipeline, LLC, another interstate natural gas pipeline.

WGI was incorporated in 1990 under the laws of Colorado. WGI is a small interstate natural gas pipeline company engaged in transporting natural gas from the PSCo system near Chalk Bluffs, Colo., to the Cheyenne system near Cheyenne, Wyo.

UTILITY REGULATION

Ratemaking Principles

Xcel Energy is subject to the regulatory oversight of the SEC under PUHCA. The rules and regulations under PUHCA impose a number of restrictions on the operations of registered holding company systems. These restrictions include, subject to certain exceptions, a requirement

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that the SEC approve securities issuances, payments of dividends out of capital or unearned surplus, sales and acquisitions of utility assets or of securities of utility companies and acquisitions of other businesses. PUHCA also generally limits the operations of a registered holding company to a single integrated public utility system, plus additional energy-related businesses. PUHCA rules require that transactions between affiliated companies in a registered holding company system be performed at cost, with limited exceptions. See additional discussion of PUHCA requirements under Factors Affecting Results of Operations and Liquidity and Capital Resources in Management’s Discussion and Analysis under Item 7.

The Federal Energy Regulatory Commission (FERC) has jurisdiction over rates for electric transmission service in interstate commerce and electric energy sold at wholesale, hydro facility licensing, accounting practices and certain other activities of Xcel Energy’s utility subsidiaries. Federal, state and local agencies also have jurisdiction over many of Xcel Energy’s other activities, including regulation of retail rates and environmental matters.

NSP-Minnesota

Retail rates, services and other aspects of NSP-Minnesota’s operations are subject to the jurisdiction of the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC) and the South Dakota Public Utilities Commission (SDPUC) within their respective states. The MPUC has regulatory authority over aspects of NSP-Minnesota’s financial activities, including security issuances, certain property transfers, mergers with other utilities and transactions between NSP-Minnesota and its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s electric resource plans and gas supply plans for meeting customers’ future energy needs. The MPUC also certifies the need for generating plants greater than 50 megawatts and transmission lines greater than 100 kilovolts. NSP-Minnesota is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce. NSP-Minnesota has received authorization from the FERC to make wholesale electric sales at market-based prices.

The Minnesota Environmental Quality Board (MEQB) is empowered to select and designate sites for new power plants with a capacity of 50 megawatts or more and wind energy conversion plants with a capacity of five megawatts or more. It also designates routes for electric transmission lines with a capacity of 100 kilovolts or more. No power plant or transmission line may be constructed in Minnesota except on a site or route designated by the MEQB. The NDPSC has regulatory authority over the need for certain generating and transmission facilities, and the siting and routing of certain new generation and transmission facilities in North Dakota.

NSP-Wisconsin

NSP-Wisconsin is subject to regulation by the Public Service Commission of Wisconsin (PSCW) and the Michigan Public Service Commission (MPSC). In addition, each of the state commissions certifies the need for new generating plants and electric and retail gas transmission lines of designated capacities to be located within the respective states before the facilities may be sited and built. NSP-Wisconsin is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce. NSP-Wisconsin has received authorization from the FERC to make wholesale electric sales at market-based prices.

The PSCW has a biennial base-rate filing requirement. By June of each odd-numbered year, NSP-Wisconsin must submit a rate filing for the two-year test year period beginning the following January. The filing procedure and review generally allow the PSCW sufficient time to issue an order and implement new base rates effective with the start of the test year.

PSCo

PSCo is subject to the jurisdiction of the Colorado Public Utilities Commission (CPUC) with respect to its facilities, rates, accounts, services and issuance of securities. PSCo is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce. PSCo has received authorization from the FERC to make wholesale electricity sales at market-based prices. Also, PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction under the federal Natural Gas Act.

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SPS

The Public Utility Commission of Texas (PUCT) has jurisdiction over SPS’ Texas operations as an electric utility and over its retail rates and services. The municipalities in which SPS operates in Texas have original jurisdiction over SPS’ rates in those communities. The New Mexico Public Regulation Commission (NMPRC) has jurisdiction over the issuance of securities. The NMPRC, the Oklahoma Corporation Commission and the Kansas Corporation Commission have jurisdiction with respect to retail rates and services and construction of transmission or generation in their respective states. SPS is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce. SPS has received authorization from the FERC to make wholesale electricity sales at market-based prices.

Cheyenne

Cheyenne is subject to the jurisdiction of the Wyoming Public Service Commission (WPSC) with respect to its facilities, rates, accounts, services and issuance of securities. Cheyenne is subject to the jurisdiction of the FERC with respect to its accounting practices and the transmission of electricity in interstate commerce.

Other

WGI is subject to FERC jurisdiction with respect to its accounting practices and holds a FERC certificate, which allows it to transport natural gas in interstate commerce pursuant to the provisions of the Natural Gas Act.

Fuel, Purchased Gas and Resource Adjustment Clauses

NSP-Minnesota

NSP-Minnesota’s retail electric rate schedules in Minnesota, North Dakota and South Dakota jurisdictions provide for monthly adjustments to billings and revenues for changes in prudently incurred cost of fuel and purchased energy. NSP-Minnesota is permitted to recover these costs through fuel clause mechanisms individually approved by the regulators in each jurisdiction. The fuel clause mechanisms allow NSP-Minnesota to bill customers for the cost of fuel used to generate electricity at its plants and energy purchased from other suppliers. In general, capacity costs are not recovered through the fuel clause adjustment. NSP-Minnesota’s electric wholesale customers do not have a fuel clause provision in their contracts. Instead, the contracts have an annual price escalation factor subject to a rate cap.

The MPUC has opened an investigation to consider the continuing usefulness of fuel clause adjustments for electric utilities in Minnesota. No action has been proposed. The MPUC has the authority to disallow recovery of certain costs if it finds the utility was not prudent in its procurement activities.

NSP-Minnesota’s retail gas rate schedules for Minnesota and North Dakota include a purchased gas adjustment (PGA) clause that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased gas. The annual difference between the gas costs collected through PGA rates and the actual gas costs are collected or refunded over the subsequent 12-month period. The MPUC has the authority to disallow recovery of certain costs if it finds the utility was not prudent in its procurement activities.

NSP-Minnesota is required by Minnesota law to spend a minimum of 2 percent of Minnesota electric revenue and 0.5 percent of Minnesota gas revenue on conservation improvement programs. These costs are recovered through an annual cost recovery mechanism for electric and gas conservation and energy management program expenditures. NSP-Minnesota is required to request a new cost recovery level annually.

NSP-Wisconsin

NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail customers. Instead, it has a procedure that compares actual monthly and anticipated annual fuel costs with those costs that were included in the latest retail electric rates. If the comparison results in a difference outside a prescribed range, the PSCW may hold hearings limited to fuel costs and revise rates upward or downward. Any revised rates would remain in effect until the next rate change. The adjustment approved is calculated on an annual basis, but applied prospectively. Most of NSP-Wisconsin’s wholesale electric rate schedules provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy.

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NSP-Wisconsin has a retail gas cost recovery mechanism for Wisconsin operations to recover changes in the actual cost of natural gas and transportation and storage services. The PSCW has the authority to disallow certain costs if it finds the utility was not prudent in its procurement activities.

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

PSCo

PSCo has several retail adjustment clauses that recover fuel, purchased energy and resource costs:

	•		Incentive Cost Adjustment (ICA) and Interim Adjustment Clause (IAC) — The ICA allowed for an equal sharing between retail electric customers and shareholders of certain fuel and purchased energy costs and expired Dec. 31, 2003. The collection of prudently incurred 2002 ICA costs is being amortized over the period June 1, 2002 through March 31, 2005. During 2003, the IAC provided for the recovery of prudently incurred fuel and energy costs not included in electric base rates.
	•		Electric Commodity Adjustment (ECA) — The ECA, effective Jan. 1, 2004, is an incentive adjustment mechanism that compares actual fuel and purchased energy expense in a calendar year to a benchmark formula. The ECA then provides for an $11.25 million cap on any cost sharing over or under an allowed ECA formula rate.
	•		Gas Cost Adjustment (GCA) — The GCA allows PSCo to recover its actual costs of purchased gas. The GCA rate is revised at least annually to coincide with changes in purchased gas costs. In 2002, PSCo requested to modify the GCA to allow for monthly changes in gas rates. A final decision in this proceeding is expected in 2004.
	•		Steam Cost Adjustment (SCA) — The SCA allows PSCo to recover the difference between its actual cost of fuel and the amount of these costs recovered under its base steam service rates. The SCA rate is revised annually to coincide with changes in fuel costs.
	•		Air-Quality Improvement Rider (AQIR) — The AQIR recovers, over a 15-year period, the incremental cost (including fuel and purchased energy) incurred by PSCo as a result of a voluntary plan to reduce emissions and improve air quality in the Denver metro area.
	•		Demand-Side Management Cost Adjustment (DSMCA) — The DSMCA clause currently permits PSCo to recover DSM costs over five years while non-labor incremental expenses and carrying costs associated with deferred DSM costs are recovered on an annual basis. PSCo also has a low-income energy assistance program. The costs of this energy conservation and weatherization program for low-income customers are recovered through the DSMCA.

PSCo recovers fuel and purchased energy costs from its wholesale customers through a fuel cost adjustment clause accepted for filing by the FERC. In February 2004, the FERC approved a revised wholesale fuel adjustment clause for PSCo, which PSCo submitted as part of a settlement agreement with certain of its wholesale customers contesting past charges under PSCo's prior fuel adjustment clause.

SPS

Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor, which is part of SPS’ retail electric rates. In July 2003, a unanimous settlement was reached providing for the implementation of an expedited procedure for revising the fixed fuel factors on a semi-annual basis. The Texas retail fuel factors will change each November and May based on the projected cost of natural gas.

If it appears that SPS will materially over-recover or under-recover these costs, the factor may be revised upon application by SPS or action by the PUCT. The regulations require refunding or surcharging over- or under-recovery amounts, including interest, when they exceed 4 percent of the utility’s annual fuel and purchased energy costs, as allowed by the PUCT, if this condition is expected to continue. In 2003, SPS has received approval and implemented two fuel surcharge applications in Texas to recover additional fuel cost under-recoveries totaling approximately $28.9 million.

PUCT regulations require periodic examination of SPS fuel and purchased energy costs, the efficiency of the use of such fuel and purchased energy, fuel acquisition and management policies and purchase energy commitments. Under the PUCT’s regulations, SPS is required to file an application for the PUCT to retrospectively review at least every three years the operations of SPS’ electric generation and fuel management activities. In May 2003, a stipulation was approved by the PUCT, resolving all issues regarding SPS’ fuel costs and wholesale trading activities

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from January 2000 through December 2001. The parties agreed that SPS would reduce its December 2001 fuel under-recovery balances by $5.8 million. The net impact to SPS’ income, before tax, was a reduction of $4.7 million recorded in 2003. SPS has agreed to file its next reconciliation for electric generation and fuel management activities for the period from January 2002 through December 2003 by June 2004.

The NMPRC regulations provide for a fuel and purchased power cost adjustment clause for SPS’ New Mexico retail jurisdiction. SPS files monthly and annual reports of its fuel and purchased power costs with the NMPRC. The NMPRC authorized SPS to implement a monthly adjustment factor beginning with the February 2002 billing cycle. In accordance with the NMPRC regulations, SPS must file its next New Mexico fuel factor continuation case no later than August 2005.

SPS recovers fuel and purchased energy costs from its wholesale customers through a fuel cost adjustment clause accepted for filing by the FERC.

Cheyenne

All electric demand and purchased power costs are recoverable through an energy adjustment clause. All purchased gas costs are recoverable through a gas cost adjustment clause. Differences in costs incurred from costs recovered in rates, including interest, are deferred and recovered through prospective adjustments to rates. Rate changes for cost recovery require WPSC approval before going into effect.

Other Regulatory Mechanisms and Requirements

General

See discussion of PUHCA regulation at Management’s Discussion and Analysis — Liquidity and Capital Resources.

See discussions of regional transmission organizations (RTO) at Electric Utility Operations below.

NSP-Minnesota

“PLUS” Performance-Based Regulation — In December 2000, the NDPSC approved NSP-Minnesota’s “PLUS” performance-based regulation proposal, effective January 2001, for its electric operations in North Dakota. The plan established operating and service performance standards in the areas of system reliability, customer satisfaction, price and worker safety. NSP-Minnesota’s performance determines the range of allowed return on equity for its North Dakota electric operations. The plan will generate refunds or surcharges when earnings fall outside of the allowed return on equity range. The PLUS plan will remain in effect through 2005. In late 2003, NSP-Minnesota proposed certain changes to the performance indices for the 2004 and 2005 plan years, but it is unknown if the NDPSC will approve the changes.

Minnesota Emissions Reduction Project (MERP) — On Dec. 18, 2003, the MPUC approved NSP-Minnesota’s proposal to convert two coal-fueled electric generating plants to natural gas, and to install advanced pollution control equipment at a third coal-fired plant. All three plants are in the Minneapolis – St. Paul metropolitan area. These improvements are expected to significantly reduce air emissions from these facilities, while increasing the capacity at system peak by 300 megawatts. The projects are expected to come on line between 2007 and 2009, at a cumulative investment of approximately $1 billion. The MPUC also approved NSP-Minnesota’s proposal to recover prudent costs of the projects through a rate adjustment provision applicable to retail electric rates beginning Jan. 1, 2006, including a rate of return on the construction work in progress. The MPUC approval has a sliding return on equity (ROE) scale based on actual construction cost compared with a target level of construction costs (based on an equity ratio of 48.5 percent and debt of 51.5 percent) to incentivize NSP-Minnesota to control construction costs.

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PSCo

The CPUC established an electric performance-based regulatory plan (PBRP) under which PSCo operates. The PBRP includes an annual electric earnings test, an electric quality of service plan and a natural gas quality of service plan. See further discussion under Item 7, Management’s Discussion and Analysis.

SPS

Prior to June 2001, SPS operated under an earnings test in Texas, which required all excess earnings to be refunded to retail customers. SPS did not operate under an earnings test in Texas in 2003, 2002 or the remainder of 2001.

Pending Regulatory Matters

General

Section 206 Investigation Against All Wholesale Electric Sellers — In November 2001, the FERC issued an order under Section 206 of the Federal Power Act initiating a “generic” investigation proceeding against all jurisdictional electric suppliers making sales in interstate commerce at market-based rates. NSP-Minnesota, NSP-Wisconsin, PSCo and SPS 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, to impose new market behavior rules, and requiring submission of compliance tariff amendments in December 2003. NSP-Minnesota, NSP-Wisconsin, PSCo, and SPS each made a timely compliance filing. Violations of the new tariffs could result in the loss of certain wholesale sales revenues or the loss of authority to makes sales at market-based rates.

Additionally, in connection with their market-based rate authority, NSP-Minnesota, NSP-Wisconsin, PSCo, and SPS have an obligation to file, on a periodic basis, an updated market power analysis based on a supply margin assessment (SMA). Xcel Energy, on behalf of itself and the Xcel Energy operating companies with market-based rate authority, filed such an updated market power analysis on January 6, 2004. The analysis shows that the Xcel Energy operating companies with market-based rate authority do not have undue market power, based on application of the FERC market power assessment screen (the SMA screen). However, FERC is presently evaluating on a generic basis continued use of the SMA screen. The Xcel Energy analysis showed that if the screen is modified to take into account load obligations, the Xcel Energy companies do not possess market power. Depending on what market screen it ultimately adopts, FERC may deny the Xcel Energy operating companies continued market-based rate authority, or, more likely, make continued authorization subject to certain mitigation in certain geographic markets.

Commodity Futures Trading Commission Investigation — In 2002 and 2003, the Commodity Futures Trading Commission (CFTC) issued broad subpoenas to Xcel Energy on behalf of its affiliates calling for production, among other things, of “documents related to natural gas and electricity trading,” as well as documents concerning the reporting of energy transactions to industry publications. The CFTC also requested testimony from current and former employees and executives concerning the reporting of energy transactions. Xcel Energy produced documents and other materials, including documents identifying instances where Xcel Energy’s e prime subsidiary reported natural gas transactions to an industry publication in a manner inconsistent with the publication’s instructions. Xcel Energy determined that several e prime employees reported inaccurate trading information to one industry publication and may have reported inaccurate trading information to other industry publications. e prime ceased reporting to publications in 2002.

In January 2004, Xcel Energy and e prime reached a settlement agreement with the CFTC with respect to allegations that e prime submitted inaccurate information to industry publications. Without admitting or denying the CFTC’s findings, e prime agreed to pay $16 million to settle the matter. The CFTC order resolving the matter recognized Xcel Energy’s cooperation in the CFTCs investigation. Xcel Energy officials pledged to continue cooperating with the CFTC.

Prior to the CFTC investigation, e prime had 32 employees. As a result of the investigation and Xcel Energy’s decision to exit the natural gas merchant business, e prime has severed all but four of its employees.

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SEC Trading Investigation — Pursuant to a formal order of investigation, on June 26, 2002, the SEC issued a subpoena to Xcel Energy requesting all documents concerning any so-called “round trip trades” with Reliant Resources, Inc. Pursuant to another formal order of investigation, on Oct. 3, 2002, the SEC issued a subpoena to Xcel Energy calling for additional information concerning certain energy trades between Xcel Energy on the one hand and Duke Energy Corporation and Mirant Corporation on the other, involving the same product, quantity and price executed on the same day. Xcel Energy has produced documents and has cooperated in these investigations, but cannot predict the outcome of any investigation.

FERC Transmission Inquiry — In October 2002, the FERC Office of Market Oversight and Investigations began a formal, non-public standard industry inquiry relating to the treatment by certain public utility companies of affiliates in generator interconnection and other transmission matters. In connection with the inquiry, the FERC asked Xcel Energy and its utility subsidiaries for certain information and documents. Xcel Energy and its utility subsidiaries have responded to the requests. This standard audit process is pending.

NSP-Minnesota

Minnesota Service Quality Investigation — In 2002, the MPUC directed the Office of the Attorney General and the Minnesota Department of Commerce (state agencies) to investigate the accuracy of NSP-Minnesota’s electric reliability records, which are summarized and reported to the MPUC on a monthly basis with an annual true-up.

On Sept. 24, 2003, NSP-Minnesota and the state agencies announced that they had reached a settlement agreement that would be submitted to the MPUC for its approval. Among the provisions are:

	•		$1 million in refunds to Minnesota customers who have experienced the longest duration of outages, which have been accrued at Sept. 30, 2003;
	•		additional actions to improve system reliability in an effort to reduce outage frequency and duration. These actions, including tree trimming and cable replacement, will target the primary outage causes. At least an additional $15 million, above amounts being currently recovered in rates, is to be spent in Minnesota on these outage prevention improvements by Jan. 1, 2005; and
	•		development of a revised service quality plan containing a standard for service outage documentation, new performance measures, new thresholds for current performance measures and a new structure for consequences that will result from failure to meet these performance measures.

On Nov. 14, 2003, NSP-Minnesota submitted a proposed service quality plan and an update regarding certain service quality settlement agreement provisions already implemented by NSP-Minnesota. On Jan. 22, 2004, the MPUC voted to modify the settlement to include an annual independent audit of NSP-Minnesota’s service outage records and under-performance payments for any future finding of inaccurate data by an independent auditor. Both state agencies and NSP-Minnesota have the option to void the settlement if they choose not to accept the MPUC’s modification. On March 10, 2004, the MPUC issued its order formally approving the settlement as modified. All parties to the proceeding have twenty days from the date of the order to seek clarification or hearing.

South Dakota Service Quality — In 2002, the SDPUC investigated NSP-Minnesota’s electric service quality. In particular, the investigation focused on NSP-Minnesota operations in the Sioux Falls area. NSP-Minnesota committed to a number of actions to improve reliability, which were implemented; and in December 2003 provided the SDPUC with an updated 10-year capacity plan. NSP-Minnesota has completed the commitments made in December 2002 relating to service quality in the Sioux Falls area. In 2003, NSP-Minnesota also worked with the SDPUC to provide information and to answer inquiries regarding service quality. No docket was opened and the matter is now resolved.

Renewable Transmission Cost Recovery — In 2002, NSP-Minnesota filed for MPUC approval to establish a Renewable Cost Recovery (RCR) adjustment mechanism to recover the costs of transmission investments incurred to deliver renewable energy resources. The MPUC approved the RCR adjustment mechanism and the two-phase filing mechanism in April 2003. In February 2004, the MPUC conditionally approved the initial Phase 1 facility eligibility determination filing. NSP-Minnesota then filed for approval to recover $6 million of annual additional transmission costs from May 2004 to December 2004. The request is pending MPUC approval. The RCR adjustment mechanism provides for annual filings to set the RCR adjustment rates using updated transmission cost information.

Time-of-Use Pilot Project — As required by MPUC Orders, NSP-Minnesota has been working to develop a time-of-use pilot project that would attempt to measure customer response and conservation potential of such a program. This pilot project explores providing customers with pricing signals and information that could better inform customers about their use of electricity and its costs. NSP-Minnesota has petitioned the MPUC for recovery of program costs. The 2002 program costs were approximately $2 million. The DOC has supported deferred

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accounting to provide for recovery of prudent, otherwise unrecovered and appropriate costs, subject to a normal prudence review process. The Office of the Attorney General has argued that cost recovery should be denied for several reasons. A MPUC hearing was held in January 2004 and requested NSP-Minnesota to further substantiate the prudence and appropriateness of the costs incurred. A final decision by the MPUC is expected in the second half of 2004.

NSP-Wisconsin

2004 General Rate Case — On June 1, 2003, NSP-Wisconsin filed its required biennial rate application with the PSCW requesting no change in Wisconsin retail electric and natural gas base rates. NSP-Wisconsin requested the PSCW approve its application without hearing, pending completion of the Staff’s audit.

On Dec. 22, 2003, the PSCW issued an interim order in the rate case approving NSP-Wisconsin’s request for alternative accounting treatment of the loss on reacquired debt associated with the refinancing of $110 million first mortgage bonds. In November 2003, NSP-Wisconsin had filed a proposal to amortize the loss on reacquired debt over the 15-year term of the new $150 million issue, as opposed to the “revenue neutral” method, which was specified in the PSCW order approving the refinancing and resulted in a shorter amortization period. Because the alternative method approved by the PSCW results in a longer amortization period, NSP-Wisconsin lowered financing costs by $394,000 in 2003 and expects to lower financing costs by $1,894,000 in 2004.

On Feb. 19, 2004, the PSCW verbally approved NSP-Wisconsin’s request for no change in retail electric and natural gas rates and determined to forego a public rate hearing based on the results of the PSCW’s staff audit. A final written order was issued on Feb. 23, 2004. In approving NSP-Wisconsin’s request, the current 11.9 percent return on common equity was retained and the existing fuel credit factor will be rolled into base rates, effective March 15, 2004. The PSCW also allowed NSP-Wisconsin the option of filing updated fuel costs in the fall of 2004 for the purpose of resetting the fuel component of rates in 2005.

PSCo

Incentive Cost Adjustment and Interim Adjustment Clause — PSCo’s ICA mechanism was in place for periods prior to 2003. The CPUC conducted a proceeding to review and approve the incurred and recoverable 2001 costs under the ICA. On July 10, 2003, a stipulation and settlement agreement was filed with the CPUC, which resolved all issues. The stipulation and settlement agreement also provides for a prospective revenue adjustment related to the maximum allowable natural gas hedging costs that will be a part of the electric commodity adjustment for 2004 and is expected to reduce 2004 rates by an estimated $4.6 million. The stipulation and settlement agreement was approved by the CPUC in August 2003. An evaluation of the 2002 recoverable ICA costs is pending before the CPUC with a decision expected no later than September 2004. In 2003, PSCo’s prudently incurred fuel and purchased energy costs are fully recoverable under the IAC and are not subject to sharing; however, they will still be subject to a future review by the CPUC.

Wholesale Electric Rate Case — On June 19, 2003, PSCo filed a wholesale electric rate case with the FERC, proposing to increase the annual electric sales rates charged to wholesale customers, other than Cheyenne. On Aug. 1, 2003, PSCo submitted a revised filing correcting an error in the calculation of income taxes. The revised filing requested an approximately $2 million annual increase with new rates effective in January 2004, subject to refund. In August 2003, PSCo reached a settlement in principle in this case. In December 2003, PSCo filed the offer of settlement for FERC approval, which was accepted by the FERC in February 2004.

Electric Commodity Trading Investigation — In the comprehensive settlement agreement that concluded the PSCo 2002 general retail rate case, PSCo agreed to file an application with the CPUC in January 2004 for a review of the Colorado regulatory treatment of its wholesale electric commodity trading operations. In the filing, PSCo offered to replace the margin sharing between shareholders and retail customers that resulted from the rate case settlement with a defined trading benefit that would reduce retail electric rates by $2.02 million in 2005 and by $1.3 million in 2006. In return for this defined benefit, PSCo proposed to retain for shareholders all margins earned from electric commodity trading in 2005 and 2006 and to bear all risk of loss associated with electric commodity trading. PSCo’s proposal is pending before the CPUC. A decision is expected in October 2004.

PSCo Wholesale Fuel Adjustment Clause Proceedings — Certain wholesale electric sales customers of PSCo filed complaints with the FERC in 2002 alleging PSCo has been improperly collecting certain fuel and purchased energy costs through the wholesale fuel cost adjustment clause included in their rates related to the periods 1996 through 2002. The FERC consolidated these complaints and set them for hearing. Claims were estimated at approximately $30 million. In August 2003, PSCo reached agreements in principle with all of the complainants under which such claims, as well as issues those customers had raised in response to PSCo’s proposal to change the base demand and energy rates applicable to wholesale requirements sales, were compromised and settled. Under the proposed settlement agreements, PSCo accrued a liability of $1.1 million in 2003 and made either cash payments or billing credits to respective customers in January 2004. The settlements also provide for

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revisions to the base demand and energy rates filed in the PSCo wholesale electric rate case that is currently pending before the FERC in a separate docket, as discussed above. As a part of the settlement, the customers agreed to withdraw their fuel clause investigation complaints. In January 2004, the customers filed motions to conditionally withdraw their complaints pending approval of the base rate settlement proposals. The settlement proposal is pending FERC acceptance.

Electric Department Earnings Test Proceedings — PSCo has filed with the CPUC its annual electric department earnings test report for 2002. PSCo did not earn above its allowed authorized return on equity and, accordingly, has not recorded any refund obligations. The CPUC has opened a docket to consider whether PSCo’s cost of debt has been adversely affected by the financial difficulties at NRG and, if so, whether any adjustments to PSCo’s cost of capital should be made. The 2002 proceeding has been set for hearing in September 2004.

Capacity Cost Adjustment — In October 2003, PSCo filed with the CPUC an application to recover approximately $31.5 million of incremental capacity costs through a purchased capacity cost adjustment (PCCA) rider beginning March 1, 2004. The purpose of the PCCA is to recover purchased capacity payments to third party power suppliers that will not be recovered in PSCo’s current base electric rates or other recovery mechanisms. In addition, PSCo has proposed to return to its retail customers 100 percent of any electric earnings in excess of its authorized rate of return on equity allowed in the last rate case, currently 10.75 percent. In February 2004, PSCo updated its filing which will reduce the recovery amount from the original filing, and proposed that the PCCA rider become effective in the later part of 2004; a decision by the CPUC is pending.

Home Builders Association of Metropolitan Denver — In February 2001, Home Builders Association of Metropolitan Denver (HBA) filed a complaint with the CPUC seeking a reparations award of $13.6 million for PSCo’s failure to update its gas extension policy construction allowances from 1996 to 2002 under its tariff. On Sept. 24, 2003, the CPUC issued its decision, directing PSCo to pay a portion of the claimed reparations to HBA members, including interest, based on a revised construction allowance for the period Feb. 24, 1999, through May 31, 2002. In March 2004, PSCo filed a settlement which, if approved by the CPUC, would provide payment of approximately $700,000 to HBA.

California Refund Proceeding — A number of parties purchasing energy in markets operated by the California Independent System Operator (California ISO) or the California Power Exchange (PX) have asserted prices paid for such energy were unjust and unreasonable and that refunds should be made in connection with sales in those markets for the period Oct. 2, 2000 through June 20, 2001. PSCo supplied energy to these markets during this period and has been an active participant in the proceedings. The FERC ordered an investigation into the California ISO and PX spot markets and concluded that the electric market structure and market rules for wholesale sales of energy in California were flawed and have caused unjust and unreasonable rates for short-term energy under certain conditions. The FERC ordered modifications to the market structure and rules in California and established an administrative law judge (ALJ) to make findings with respect to, among other things, the amount of refunds owed by each supplier based on the difference between what was charged and what would have been charged in a more functional market, i.e., the “market clearing price,” which is based on the unit providing energy in an hour with the highest incremental cost. The initial proceeding related to California’s demand for $8.9 billion in refunds from power sellers. The ALJ subsequently stated that after assessing a refund of $1.8 billion for power prices, power suppliers were owed $1.2 billion because the State was holding funds owed to suppliers. Because of the low volume of sales that PSCo had into California after this date, PSCo’s exposure is estimated at approximately $1.2 million, which is offset by amounts owed by the California ISO to PSCo in excess of that amount.

Certain California parties have sought rehearing of this decision. Among other things, they have asserted that the refund effective date should be set at an earlier date. They have based this request in part on the argument that the use by sellers of certain trading strategies in the California market resulted in unjust and unreasonable rates, thereby justifying an earlier refund effective date. The FERC subsequently allowed the purchasing parties to request from sellers, including PSCo, additional information regarding the market participants’ use of certain strategies and the effect those strategies may have had on the market. Based on the additional information they obtained, these purchasing entities argued to the FERC that use of these strategies did justify an earlier refund effective date. PSCo has estimated that the requested earlier effective date could increase PSCo’s refund exposure to approximately $15 million.

In an order issued on October 16, 2003, the FERC determined that the refund effective date should not be reset to an earlier date, and gave clarification how refunds should be determined for the previously set refund period. The proceeding is still pending at the FERC to address the refund level issue. Certain California parties have filed appeals of the FERC’s decision not to establish an earlier refund effective date.

FERC Investigation Against Wholesale Electric Sellers — On June 25, 2003, the FERC issued two show cause orders addressing alleged improper market behavior in the California electricity markets. In the first show cause order, the FERC found that 24 entities may have worked in concert through partnerships, alliances or other arrangements to engage in activities that constitute gaming and/or anomalous market

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behavior. The FERC initiated proceedings against these 24 entities requiring that they show cause why their behavior did not constitute gaming and/or anomalous market behavior. PSCo was not named in this order. In a second show cause order, the FERC indicated that various California parties, including the California ISO, have alleged that 43 entities individually engaged in one or more of seven specific types of practices that the FERC has identified as constituting gaming or anomalous market behavior within the meaning of the California ISO and California Power Exchange tariffs. PSCo was listed in an attachment to that show cause order as having been alleged to have engaged in one of the seven identified practices, namely circular scheduling. Subsequent to the show cause order, PSCo provided information to the FERC staff showing PSCo did not engage in circular scheduling. Subsequently, certain California parties requested that FERC make PSCo subject to the show cause proceeding addressing partnerships and expand the scope of the show cause order addressing gaming and/or anomalous to have PSCo address an allegation that it engaged in another of the specified activities, namely “load shift.”

On Aug. 29, 2003, the FERC trial staff filed a motion to dismiss PSCo from the show cause proceeding. On Jan. 22, 2004, the FERC granted its Trial Staff’s motions to dismiss certain parties, including PSCo, of the show cause proceedings addressing the use of gaming or anomalous market behavior. The FERC also rejected requests to expand the scope of the show cause proceedings. On February 23, 2004, certain California parties sought rehearing of the FERC’s orders.

Pacific Northwest FERC Refund Proceeding — In July 2001, the FERC ordered a preliminary hearing to determine whether there may have been unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for the period Dec. 25, 2000 through June 20, 2001. PSCo supplied energy to the Pacific Northwest markets during this period and has been an active participant in the hearings. In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered. Subsequent to the ruling the FERC has allowed the parties to request additional evidence regarding the use of certain strategies and how they may have impacted the markets in the Pacific Northwest markets. For the referenced period, parties have claimed the total amount of transactions with PSCo subject to refund are $34 million.

On June 25, 2003, the FERC issued an order terminating the proceeding without ordering further proceedings. On Nov. 10, 2003, in response to requests for rehearing, FERC reaffirmed this ruling to terminate the proceeding without refunds. Certain purchasers have filed appeals of the FERC’s orders in this proceeding.

CPUC Reliability Inquiry — In January 2004, the CPUC staff issued an initial report regarding its informal inquiry of PSCo’s electric distribution system reliability (Initial Report). The Initial Report makes several recommendations for improving reliability and noted that PSCo had already taken steps toward improvement. In February 2004, PSCo provided the CPUC with its written and oral responses to the Initial Report describing its action plan to improve electric distribution system reliability. PSCo identified $24.9 million in expenditures directed at this effort that it would make during 2004.

The Initial Report recommended audits of PSCo’s electric distribution system operations and maintenance practices and its IT systems supporting electric distribution reliability. PSCo believes the audits are unnecessary in light of its action plan to address the reliability concerns raised in the Initial Report. The CPUC has taken the Initial Report and PSCo’s response under advisement.

SPS

Texas Fuel Surcharge Application — In November 2003, SPS submitted a fuel cost surcharge factor application in Texas to recover an additional $25 million of fuel cost under recoveries accrued during June through September 2003. In February 2004, the parties in the proceeding submitted a unanimous settlement for SPS to collect net under-recoveries experienced through December 2003 of $22 million. The surcharge will go into effect May 2004 and will continue for 12 months. The settlement is pending review and approval by the PUCT.

Lamb County Electric Cooperative — On July 24, 1995, Lamb County Electric Cooperative, Inc. (LCEC) petitioned the PUCT for a cease and desist order against SPS. LCEC alleged that SPS had been unlawfully providing service to oil field customers and their facilities in LCEC’s singly-certificated area. The PUCT denied LCEC’s petition. See further discussion under Item 3 — Legal Proceedings.

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Cheyenne

As previously noted, in January 2004, Xcel Energy reached an agreement to sell Cheyenne to Black Hills Corporation. The sale is subject to regulatory approval by the Wyoming Public Service Commission, the FERC and the SEC. Xcel Energy expects to complete the sale in 2004.

ELECTRIC UTILITY OPERATIONS

Competition and Industry Restructuring

Retail competition and the unbundling of regulated energy service could have a significant financial impact on Xcel Energy and its utility subsidiaries, due to an impairment of assets, a loss of retail customers, lower profit margins and increased costs of capital. During the past several years, there have been several restructuring initiatives initiated in the various states Xcel Energy and its utility subsidiaries operate, as well as the Federal level. However, we believe such risk has been mitigated, to a certain degree, as a result of less focus recently on such initiatives. The total impacts of restructuring may have a significant financial impact on the financial position, results of operation and cash flows of Xcel Energy and its utility subsidiaries. Xcel Energy and its utility subsidiaries cannot predict when they will be subject to changes in legislation or regulation, nor can they predict the impacts of such changes on their financial position, results of operation or cash flows. Xcel Energy believes that the prices its utility subsidiaries charge for electricity and the quality and reliability of their service currently place them in a position to compete effectively in the energy market.

Retail Business Competition — The retail electric business faces some competition as industrial and large commercial customers have some ability to own or operate facilities to generate their own electricity. In addition, customers may have the option of substituting other fuels, such as natural gas or steam/chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region. While each of Xcel Energy’s utility subsidiaries face these challenges, these subsidiaries believe their rates are competitive with currently available alternatives. Xcel Energy’s utility subsidiaries are taking actions to manage their operating costs and are working with their customers to analyze energy efficiency and load management in order to better position Xcel Energy’s utility subsidiaries to more effectively operate in a competitive environment.

Wholesale Business Competition — The wholesale electric business faces 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, investor-owned utilities are required to provide wholesale open access transmission services and to unbundle wholesale merchant and transmission operations. Xcel Energy’s utility subsidiaries are operating under a joint tariff in compliance with these rules. To date, these provisions have not had a material impact on the operations of Xcel Energy’s utility subsidiaries.

Utility Industry Changes — The structure of the electric and natural gas utility industry has been subject to change. Merger and acquisition activity in the past had been significant as utilities combined to capture economies of scale or establish a strategic niche in preparing for the future, although such activity slowed substantially after 2001. All investor-owned utilities were required to provide nondiscriminatory access to the use of their transmission systems in 1996. The FERC continues to pursue the expansion of competitive wholesale electricity markets through regional transmission organizations and standard market design rules. In addition, the FERC issued a series of regulatory orders in 2003. These orders, among other things, standardized the methods and pricing of power generation interconnections, establish new standards of conduct rules for transmission providers and new market behavioral rules for utilities with wholesale market-based sales rate authority. Xcel Energy has not yet estimated the full impact of the new FERC regulatory orders, but it could be material.

Some states had begun to allow retail customers to choose their electricity supplier, while other states have delayed or canceled industry restructuring. There were no significant retail electric or natural gas restructuring efforts in the states served by Xcel Energy in 2003. In 1999, the state of Texas implemented retail restructuring legislation and major portions of the state have restructured and are providing retail competition. In Xcel Energy’s Texas service area, which is outside the Electric Reliability Council of Texas, retail electric competition has been delayed until at least 2007. The State of New Mexico repealed its Electric Industry Restructuring Act of 1999.

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

Midwest ISO Operations — In August 2000, NSP-Minnesota and NSP-Wisconsin joined the Midwest Independent Transmission System Operator, Inc. (MISO). In December 2001, the FERC approved the MISO as the first regional transmission organization (RTO) in the United States under FERC Order No. 2000. On Feb. 1, 2002, the MISO began interim operations, including regional transmission tariff administration

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services for the NSP-Minnesota and NSP-Wisconsin electric transmission systems. In 2002, NSP-Minnesota and NSP-Wisconsin received all required regulatory approvals to transfer functional control of their high voltage (100 kilovolts and above) transmission systems to the MISO. The MISO membership grants MISO functional control over the operations of these facilities and the facilities of neighboring electric utilities.

In October 2001, the FERC issued an order in a separate proceeding to establish the initial MISO regional transmission tariff rates, ruling that all transmission services, with limited exceptions, in the MISO region must be subject to the MISO regional tariff and administrative surcharges to prevent discrimination between wholesale transmission service users. The FERC order unilaterally modified the agreement with the MISO signed in August 2000. The FERC order increased wholesale transmission costs to NSP-Minnesota and NSP-Wisconsin by approximately $9 million per year.

On July 25, 2003, MISO filed proposed changes to its regional open access transmission tariff to implement a new Transmission and Energy Markets Tariff (TEMT) that would establish certain wholesale energy and transmission service rates based on locational marginal cost pricing effective in 2004. NSP-Minnesota and NSP-Wisconsin presently receive transmission services from MISO for service to their retail loads and would be subject to the new tariff, if approved by the FERC. On Oct. 17, 2003, MISO filed to withdraw the TEMT, after numerous parties filed protests to the proposal. The FERC issued an order approving the withdrawal and provided guidance on MISO’s proposals on Oct. 29, 2003. MISO is now conducting a stakeholder consultation process to prepare and submit a revised TEMT in March 2004 to be effective Dec. 1, 2004. Management believes any new tariff, if approved by the FERC, could have a material effect on wholesale power supply or transmission service costs to NSP-Minnesota and NSP-Wisconsin.

Southwest Power Pool (SPP) Restructuring — SPS is a member of the SPP regional reliability council, and SPP acts as tariff administrator for the SPS system. In October 2003, SPP filed for FERC authorization to transform its operation into an RTO under FERC Order No. 2000. In addition, SPP made unilateral changes to the existing SPP membership agreement, which increases the current costs of SPS membership in SPP by approximately $1.5 million per year, in order to fund the start of RTO operations. On Oct. 31, 2003, SPS submitted a conditional notice of withdrawal from SPP in order to preserve flexibility with regard to future RTO membership. On Feb. 10, 2004, the FERC conditionally approved SPP’s proposed formation as an RTO, subject to SPP meeting certain requirements. The order also provides that SPS may only terminate its current membership in SPP with FERC approval. If SPS elects to be a member of the SPP RTO, SPS will be required to transfer functional control of its electric transmission system to SPP and take all transmission services, including services required to serve retail native loads, under the SPP regional tariff.

TRANSLink Transmission Co., LLC (TRANSLink) — In September 2001, Xcel Energy and several other mid-continent electric utilities applied to the FERC to integrate operations of their electric transmission systems into a single system through the formation of TRANSLink, a for-profit, independent transmission-only company. The utilities were to participate in TRANSLink through a combination of divestiture, leases and operating agreements. TRANSLink was intended to be a cost-effective option to manage transmission and to comply with the Order No. 2000 regulations issued by the FERC that required investor-owned electric utilities to transfer operational control of their transmission system to an independent RTO.

Under the proposal, TRANSLink would have been responsible for planning, managing and operating both local and regional transmission assets. TRANSLink would also have constructed and owned new transmission system additions. In November 2003, however, the formation activity for TRANSLink was suspended due to continued market and regulatory uncertainty.

Generation Interconnection Rules — In August 2003, the FERC issued final rules requiring the standardization of generation interconnection procedures and agreements for interconnection of new electric generators of 20 megawatts or more to the transmission systems of all FERC-jurisdictional electric utilities, including Xcel Energy’s utility subsidiaries. The FERC also established pricing rules for interconnections and related transmission system upgrades. As required by the FERC, Xcel Energy’s utility subsidiaries submitted a compliance filing on Jan. 20, 2004. The FERC approval of the compliance changes to the Xcel Energy utility subsidiaries’ tariff, the MISO regional tariff, and the SPP regional tariff, which will govern most generation interconnections to the Xcel Energy utility subsidiaries’ transmission system, are pending. On March 5, 2004, the FERC issued an order on rehearing adopting certain changes to the pricing provisions of the final rules.

Standards of Conduct Rulemaking — In November 2003, the FERC issued final standards of conduct rules affecting all FERC jurisdictional transmission utilities, which will require a greater functional separation of electric transmission functions from the wholesale energy marketing and sales functions and from “energy affiliates”. Xcel Energy’s utility subsidiaries filed their initial compliance plan on Feb. 9, 2004. Full compliance is required by June 1, 2004. Xcel Energy and other parties have requested the FERC to grant clarification or rehearing of certain aspects of the final rules. Management has estimated the cost of compliance with the new standards of conduct rules at approximately $1 million in 2004.

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Standard Market Design Rulemaking — In July 2002, the FERC issued a notice of proposed rulemaking on wholesale standard market design (SMD) for regulated utilities. If implemented as proposed, the rulemaking would substantially change how wholesale electric supply markets operate throughout the United States. The proposed rulemaking 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 electric markets using location marginal pricing. RTOs or independent transmission providers will administer the market. RTOs will also be responsible for 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. The FERC later extended the comment period, but the final rules could be in place in 2004 and the contemplated market changes in 2004 or 2005. Recent MISO actions indicate that the MISO plans to establish a market design similar to SMD by December 2004, which would impact wholesale markets on the NSP-Minnesota and NSP-Wisconsin systems. The SPP RTO proposal approved by the FERC in February 2004 anticipates establishing a wholesale electric market applying certain aspects of SMD beginning in 2005, which would impact wholesale markets on the SPS system.

NSP-Minnesota

Minnesota Restructuring — In 2001, the Minnesota Legislature passed an energy security bill that included provisions intended to streamline the siting process of new generation and transmission facilities. It also included voluntary benchmarks for achieving renewable energy as a portion of the utility’s supply portfolio; however, the benchmarks are mandatory for NSP-Minnesota (subject to certain conditions). In 2003, the Minnesota Legislature revised the 2001 statute to require Minnesota utilities to develop and submit analyses to the MPUC of the transmission upgrades required to deliver the benchmark quantities of renewable energy as part of biennial transmission planning process established by the 2001 energy security bill. There was no other action on restructuring in 2002 or 2003.

North Dakota Restructuring — In 1997, the North Dakota Legislature established, by statute, an Electric Utility Competition Committee (EUC). While its legislated scope is quite broad, the committee focused much of its initial efforts on the study of the state’s current tax treatment of the electric utility industry. In 2003, the legislature expanded the membership of the committee and extended its life to 2007.

NSP-Wisconsin

Wisconsin Restructuring — The State of Wisconsin passed legislation in 2001 that reduced the wholesale gross receipts tax on the sale of electricity by 50 percent starting in 2003. This legislation eliminates the double taxation on wholesale sales from non-utility generators. Additional legislation was passed that enables regulated utilities to enter into leased generation contracts with unregulated generation affiliates. The new legislation provides utilities a new financing mechanism and option to meet their customers’ energy needs. In 2002, the PSCW approved the first power plant proposal utilizing the new leased generation contract arrangement. While industry-restructuring changes continue in Wisconsin, the movement towards retail customer choice has virtually ceased.

Michigan Restructuring — Since Jan. 1, 2002, NSP-Wisconsin has been providing its Michigan electric customers with the opportunity to select an alternative electric energy provider. This action was required by Michigan’s Customer Choice Electricity Reliability Act, which became law in June 2000. NSP-Wisconsin developed and successfully implemented internal procedures, and obtained MPSC approval for these procedures to meet the Jan. 1, 2002 deadline. Key elements of internal procedures included the development of retail open access tariffs and unbundled billing, environmental and fuel disclosure information, and a code of conduct compliance plan. To date, no NSP-Wisconsin retail electric customers have converted to a competing supplier.

PSCo

Colorado Restructuring — There was no legislative action with respect to restructuring in Colorado during the 2001, 2002 or 2003 legislative sessions. None is expected in 2004.

SPS

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. In April 2003, the State of New Mexico repealed the Electric Utility Restructuring Act of 1999. The repeal legislation provided utilities the opportunity to recover their transition costs incurred to comply with the Restructuring Act of 1999. Utilities may retain these transition costs as a regulatory asset on their books pending recovery, which shall be completed by Jan. 1, 2010. At Dec. 31, 2003, SPS had deferred $5.1 million of New Mexico restructuring costs.

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Texas Restructuring — In June 2001, the Governor of Texas signed legislation postponing retail competition and restructuring of SPS until at least 2007. This legislation amended the 1999 legislation, Senate Bill No. 7 (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. SPS’ restructuring and rate unbundling proceedings in Texas have been terminated. 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.

For more information on restructuring in Texas and New Mexico, see Note 14 to the Consolidated Financial Statements.

Kansas Restructuring — During the 2001 legislative session, several restructuring related bills were introduced for consideration by the state legislature. To date, however, there is no restructuring mandate in Kansas.

Oklahoma Restructuring — In 2001, Senate Bill 440 (SB-440) was signed into law to formally delay electric restructuring until restructuring issues could be studied further and new enabling legislation could be enacted. SB-440 established the Electric Restructuring Advisory Committee. The Advisory Committee submitted a report to the Governor and Legislature on Dec. 31, 2001. During 2002 and 2003, there was no action taken by the Legislature as a result of this report. Oklahoma continues to delay retail competition.

Capacity and Demand

Assuming normal weather during 2004, system peak demand and the net dependable system capacity for Xcel Energy’s electric utility subsidiaries are projected below. The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin are managed as an integrated system (referred to as the NSP System). The system peak demand for each of the last three years and the forecast for 2004 are listed below.

The peak demand for all systems typically occurs in the summer. The 2003 system peak demand for the NSP System occurred on Aug. 20, 2003. The 2003 system peak demand for PSCo occurred on July 24, 2003. The 2003 system peak demand for SPS occurred on Aug. 5, 2003.

Energy Sources

Xcel Energy’s utility subsidiaries expect to use the following resources to meet their net dependable system capacity requirements: 1) Xcel Energy utility subsidiary electric generating stations, 2) purchases from other utilities, independent power producers and power marketers, 3) demand-side management options, and 4) phased expansion of existing generation at select power plants.

Purchased Power

Xcel Energy’s electric utility subsidiaries 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 such generating source.

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The utility subsidiaries of Xcel Energy 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 each utility’s 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.

NSP System Resource Plan

In December 2002, NSP-Minnesota filed its resource plan with the MPUC for 2003 to 2017. The plan describes how Xcel Energy intends to meet the energy needs of the NSP System. The plan presented conservation programs to reduce NSP System’s peak demand and conserve electricity, an approximate schedule of power purchase solicitations to meet increasing demand and programs and plans to maintain the reliable operations of existing resources. In summary, the plan includes the following elements:

	•		1.7 percent annual growth in the NSP System’s energy and peak demand requirements;
	•		NSP System’s demand-side management and conservation program requirements;
	•		various pending legislative and regulatory proceedings affecting over half of the generating capacity necessary to meet the demand for electricity;
	•		additional power purchase solicitation proposals to meet growing demand for electricity; and
	•		updated the status of spent nuclear fuel at the Prairie Island and Monticello plants and describes the alternatives to replace nuclear generation if the two plants must be replaced as the result of spent nuclear fuel storage limitations.

In May 2003, the Minnesota Legislature approved additional dry cask storage for the NSP-Minnesota nuclear power plants. See Nuclear Power Operations and Waste Disposal-High-Level Radioactive Waste Disposal below. In February 2004, the MPUC approved a request by NSP-Minnesota to close the 2002 resource plan docket and address issues in the upcoming 2004 resource plan filing, to be filed in October 2004.

NSP-Minnesota Power Purchase Agreement

NSP-Minnesota has a 500-megawatt participation power purchase commitment with the Manitoba Hydro Electric Board, which expires in April 2015. The cost, through April 2005, is based on 80 percent of the costs of owning and operating NSP-Minnesota’s Sherco 3 generating unit, adjusted to 1993 dollars. The cost for the period May 2005 through April 2015 is based on a base price and will be escalated by the change in the United States Gross National Product to reflect the current year. In addition, NSP-Minnesota and Manitoba Hydro have seasonal diversity exchange agreements, and there are no capacity payments for the diversity exchanges. These commitments represent about 17 percent of Manitoba Hydro’s system capacity and account for approximately 6 percent of NSP-Minnesota’s 2003 electric system capability. The risk of loss from nonperformance by Manitoba Hydro is not considered significant, and the risk of loss from market price changes is mitigated through cost-of-energy rate adjustments.

NSP-Minnesota Combustion Turbine Proposal

In November 2003, NSP-Minnesota proposed investing approximately $164 million in generating capacity in Minnesota and South Dakota to ensure adequate electric capacity for its Upper Midwest customers. NSP-Minnesota is requesting authorization for a $100-million project to add two combustion turbines at its Blue Lake peaking plant in Shakopee, Minn., and for a $64-million project to add one turbine at its Angus Anson peaking plant in Sioux Falls, S.D.

Each of the three new turbines would be fired by natural gas and would have a summer capacity of approximately 160 megawatts. Currently, the Blue Lake plant has four units fired by oil and a net dependable capacity of 174 megawatts; the Angus Anson plant has two units that can be fired by either natural gas or oil and a net dependable capacity of 226 megawatts.

The Blue Lake proposal requires a certificate of need from the MPUC, a site permit from the MEQB, and air quality permits from the Minnesota Pollution Control Agency. The Angus Anson expansion requires an amended facility permit from the South Dakota Public Utilities Commission and air quality permits from the South Dakota Department of Environment and Natural Resources. The projects also require approval by MISO with regards to interconnection and transmission service requests. Final approval is not certain, but decisions on the respective projects are expected in 2004.

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NSP-Minnesota Transmission Certificates of Need

In December 2001, NSP-Minnesota proposed construction of various transmission system upgrades to provide transmission outlet capacity for up to 825 MW of renewable energy generation (wind and biomass) being constructed in southwest and western Minnesota. In March 2003, the MPUC granted three certificates of need to NSP-Minnesota, thereby approving construction, subject to certain conditions. The initial projected cost of the transmission upgrades was approximately $160 million. The first of the transmission facilities is now pending MEQB approval as to siting and routing; additional MEQB siting/routing applications are expected to be filed in 2004. The actual in-service dates could be affected by regulatory delays or the need to amend the certificates to reflect increased demand for generation interconnection services. In 2003, the MPUC also approved a Renewable Cost Recovery adjustment that will allow NSP-Minnesota to recover the revenue requirements associated with certain transmission investments associated with delivery of renewable energy resources through an automatic adjustment mechanism starting in 2004.

PSCo Resource Plan

PSCo estimates it will purchase approximately 37 percent of its total electric system energy input for 2004. Approximately 48 percent of the total system capacity for the summer 2004 system peak demand for PSCo will be provided by purchased power.

To meet the demand and energy needs of the rapidly growing economy in Colorado, PSCo added approximately 1,800 megawatts of resources to its system between 2002 and beginning of 2004.

In April 2004, PSCo plans to file a least cost resource plan to serve the growing needs for future years. This resource plan is expected to include a proposal to build a 750-megawatt coal plant at the existing site of the Comanche generating station in Pueblo, Colo. The project would cost approximately $1.3 billion and could begin producing electricity by late 2009. Several public power entities have the option to participate in the ownership of the facility. Such ownership would reduce PSCo’s supply from the plant and its capital investment. Various regulatory approvals are required before any construction could begin.

Purchased Transmission Services

Xcel Energy’s electric utility subsidiaries have contractual arrangements with regional transmission service providers to deliver power and energy to the subsidiaries’ native load customers, which are 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.

Fuel Supply and Costs

The following tables show the delivered cost per million British thermal units (MMBtu) of each significant category of fuel consumed for electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels during such years.

*Includes refuse-derived fuel and wood

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**The lower 2003 SPS coal costs reflect a prior period fuel credit adjustment. The normalized cost per MMBtu was approximately $1.14. These reduced coal costs were due to renegotiated coal transportation contracts.

NSP-Minnesota and NSP-Wisconsin

NSP-Minnesota and NSP-Wisconsin normally maintain between 30 and 45 days of coal inventory at each plant site. Estimated coal requirements at NSP-Minnesota’s major coal-fired generating plants are approximately 12.5 million tons per year. NSP-Minnesota and NSP-Wisconsin have long-term contracts providing for the delivery of up to 100 percent of 2004 coal requirements and up to 92 percent of their 2005 requirements. Coal delivery may be subject to short-term interruptions or reductions due to transportation problems, weather, and availability of equipment.

NSP-Minnesota and NSP-Wisconsin expect that all of the coal they burn in 2004 will have an average sulfur content of less than 0.6 percent. NSP-Minnesota and NSP-Wisconsin have contracts for a maximum of 34.7 million tons of low-sulfur coal for the next four years. The contracts are with one Montana coal supplier, three Wyoming suppliers and one Minnesota oil refinery, with expiration dates ranging between 2005 and 2007. NSP-Minnesota and NSP-Wisconsin could purchase approximately 9 percent of coal requirements in the spot market in 2005 if spot prices are more favorable than contracted prices.

NSP-Minnesota and NSP-Wisconsin’s current fuel oil inventory is adequate to meet anticipated 2004 requirements, and they also have access to the spot market to buy more oil, if needed. NSP-Minnesota and NSP-Wisconsin use both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas supplies for power plants are procured under short- and intermediate-term contracts to provide an adequate supply of fuel.

To operate NSP-Minnesota’s nuclear generating plants, NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication. The contract strategy involves a portfolio of spot purchases and medium- and long-term contracts for uranium, conversion and enrichment. Current nuclear fuel supply contracts cover 71 percent of uranium requirements through 2007 with no coverage of requirements for 2008 and beyond. Current contracts for conversion services requirements cover 68 percent of the requirements through 2008 with no coverage of requirements for 2009 and beyond. Current enrichment services contracts cover 79 percent of the requirements through 2006 with no coverage of requirements for 2007 and beyond. These current contracts expire at varying times between 2004 and 2008. NSP-Minnesota expects sufficient uranium, conversion and enrichment to be available for the total fuel requirements of its nuclear generating plants. Contracts for additional uranium and enrichment services are currently being negotiated that would provide additional supply requirements through 2007 for uranium and 2010 for enrichment services. Fuel fabrication is 100 percent committed for Prairie Island Unit 1 through 2007 and through 2006 for Prairie Island Unit 2. Both Prairie Island Units are not contracted for fuel fabrication beyond those dates. NSP-Minnesota is currently in negotiations with various vendors to pursue fuel fabrication for Prairie Island plant needs beyond the current fuel contracts. Fuel fabrication for Monticello is covered through 2010.

PSCo

PSCo’s generation stations use low-sulfur western coal purchased primarily under long-term contracts with suppliers operating in Colorado and Wyoming. During 2003, PSCo’s coal requirements for existing plants were approximately 10.2 million tons, a substantial portion of which was supplied pursuant to long-term supply contracts. Coal supply inventories at Dec. 31, 2003 were approximately 39 days usage, based on the average burn rate for all of PSCo’s coal-fired plants.

PSCo operates the Hayden station, and has partial ownership in the Craig station in Colorado. All of Hayden station’s coal requirements are supplied under a long-term agreement. Approximately 75 percent of PSCo’s Craig station coal requirements are supplied by two long-term agreements. Any remaining Craig station requirements for PSCo are supplied via spot coal purchases.

PSCo has contracted for coal supplies to supply approximately 100 percent of the Cherokee, Cameo and Valmont stations’ projected requirements in 2004.

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PSCo has long-term coal supply agreements for the Pawnee and Comanche stations’ projected requirements. Under the long-term agreements, the supplier has dedicated specific coal reserves at the contractually defined mines to meet the contract quantity obligations. In addition, PSCo has a coal supply agreement to supply approximately 65 percent of Arapahoe station’s projected requirements for 2004. Any remaining Arapahoe station requirements will be procured via spot market purchases.

PSCo uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas supplies for PSCo’s power plants are procured under short- and intermediate-term contracts to provide an adequate supply of fuel.

SPS

SPS purchases all of its coal requirements for Harrington and Tolk electric generating stations from TUCO, Inc. in the form of crushed, ready-to-burn coal delivered to the plant bunkers. TUCO, in turn, arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing, and delivery of coal to the plant bunkers to meet SPS’s requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters, and handlers. For the Harrington station, the coal supply contract with TUCO expires Dec. 31, 2016. For the Tolk station, the coal supply contract with TUCO expires Dec. 31, 2017. TUCO’s current coal handling contract for Harrington station expires on July 31, 2004; however, amendments that will extend that agreement, and TUCO’s coal handling contract for Tolk station, are being negotiated by the parties. At Dec. 31, 2003, coal supplies at the Harrington and Tolk sites were approximately 37 and 35 days supply, respectively. TUCO has coal supply agreements to supply 100 percent of the projected 2004 requirements for Harrington and Tolk stations. TUCO has long-term contracts for supply of coal in sufficient quantities to meet the primary needs of the Harrington and Tolk stations.

SPS uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas suppliers for SPS’ power plants are procured under short- and intermediate-term contracts to provide an adequate supply of fuel.

Trading Operations

Xcel Energy and its utility subsidiaries conduct various trading operations, including the purchase and sale of electric capacity and energy. Participation in short-term wholesale energy markets provides market intelligence and information that supports the energy management of each utility subsidiary. Xcel Energy and its utility subsidiaries reduce commodity price and credit risks by using physical and financial instruments to minimize commodity price and credit risk and hedge supplies and purchases. Optimizing the utility subsidiaries’ physical assets by engaging in short-term sales and purchase commitments results in lowering the cost of supply for the customers and the capturing of additional margins from non-traditional customers. Xcel Energy and its utility subsidiaries also use these trading operations to capture arbitrage opportunities created by regional pricing differentials, supply and demand imbalances and changes in fuel prices. See Pending Regulatory Matters under Item 1 for a discussion of investigations of trading activities.

Nuclear Power Operations and Waste Disposal

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. See additional discussion regarding the nuclear generating plants at Note 18 to the Consolidated Financial Statements.

Nuclear power plant operation produces gaseous, liquid and solid radioactive substances. The discharge and handling of such substances are controlled by federal regulation. High-level radioactive substance includes used nuclear fuel. Low-level radioactive substance consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in the plant.

Low-Level Radioactive Waste Disposal — Federal law places responsibility on each state for disposal of its low-level radioactive substance. Low-level radioactive substance from NSP-Minnesota’s Monticello and Prairie Island nuclear plants is currently disposed of at the Barnwell facility located in South Carolina (all classes of low-level substance), and the Clive facility located in Utah (class A low-level substance only). Chem Nuclear is the owner and operator of the Barnwell facility, which has been given authorization by South Carolina to accept low-level radioactive substance from out of state. Envirocare, Inc. operates the Clive facility. NSP-Minnesota has an annual contract with Barnwell,

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while NSP-Minnesota uses the Envirocare facility through various low-level substance processors. NSP-Minnesota has low-level storage capacity available on-site at Prairie Island and Monticello that would allow both plants to continue to operate until the end of their licensed lives, if off-site low-level disposal facilities were not available to NSP-Minnesota.

High-Level Radioactive Waste Disposal — The federal government has the responsibility to dispose of, or permanently store, domestic spent nuclear fuel and other high-level radioactive substances. The Nuclear Waste Policy Act requires the Department of Energy (DOE) to implement a program for nuclear substance management. This includes the siting, licensing, construction and operation of a repository for domestically produced spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive substances at a permanent storage or disposal facility. The DOE has accepted none of NSP-Minnesota’s spent nuclear fuel. See Item 3 — Legal Proceedings and Note 18 to the Consolidated Financial Statements for further discussion of this matter.

NSP-Minnesota has on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear plants. The Prairie Island plant is licensed by the federal Nuclear Regulatory Commission (NRC) to store up to 48 casks of spent fuel at the plant. In 1994, the Minnesota Legislature adopted a limit on dry cask storage of 17 casks for the entire state. The 17 casks, which stand outside the Prairie Island plant, are now full. On May 29, 2003, the Minnesota Legislature enacted legislation that allows NSP-Minnesota to continue to operate the facility and store spent fuel there until its licenses with NRC expire in 2013 and 2014. This will enable NSP-Minnesota to store at least 12 more casks of spent fuel outside the Prairie Island nuclear generating plant. The legislation transfers the primary authority concerning future spent-fuel storage issues from the state Legislature to the MPUC. It also allows for additional storage without the requirement of an affirmative vote from the state Legislature, if the NRC extends the licenses of the Prairie Island and Monticello plants and the MPUC grants a certificate of need for such additional storage. See Note 18 in the Consolidated Financial Statements for further discussion of the matter.

Visual Inspections — Required visual inspections have been performed of the Prairie Island Unit 2 upper and lower reactor vessel heads, and the Unit 1 upper head. Reactor vessel heads for both units were found to be in compliance with all NRC requirements. Xcel Energy has placed orders and plans to replace the reactor vessel upper heads of Prairie Island Unit 2 during the 2005 refueling outage and Unit 1 during the 2006 refueling outage.

Private Fuel Storage — NSP-Minnesota is part of a consortium of private parties working to establish a private facility for interim storage of spent nuclear fuel. In 1997, Private Fuel Storage, LLC (PFS) filed a license application with the NRC for a temporary storage site for spent nuclear fuel on the Skull Valley Indian Reservation in Utah. The NRC license review process includes formal evidentiary hearings before an Atomic Safety and Licensing Board (ASLB) and opportunities for public input. Evidentiary hearings were held in 2000 and 2002. Most of the issues raised by opponents of the project have been favorably resolved or dismissed. On March 10, 2003, the ASLB ruled that the likelihood of certain aircraft crashes into the proposed facility was sufficiently credible that it would have to be addressed before the facility could be licensed and set forth a potential process for addressing this concern. PFS has submitted responses to all NRC concerns. Public hearings with the ASLB are expected to begin in early 2004. Due to uncertainty regarding NRC and other regulatory and governmental approvals, it is possible that this interim storage may be delayed or not available at all.

Prairie Island Steam Generator Replacement — In February 2001, NSP-Minnesota signed a contract with Steam Generating Team, Ltd. to perform engineering and construction services for the installation of replacement steam generators at the Prairie Island nuclear power plant. NSP-Minnesota plans to replace both steam generators in Prairie Island Unit 1 in the fall 2004 refueling outage. The total cost of replacing the steam generators is estimated to be approximately $132 million.

Nuclear Management Co. (NMC)

During 1999, NSP-Minnesota, Wisconsin Electric Power Co., Wisconsin Public Service Corp. (WPS) and Alliant Energy Corp. established NMC. The objective in creating NMC was to enhance operational excellence in nuclear plant operations by consolidating resources, combining talent and gaining efficiencies. The Consumers Power subsidiary of CMS Energy Corp. joined NMC during 2000, and transferred operating authority for the Palisades nuclear plant to NMC in 2001. The five affiliated companies own eight nuclear units on six sites, with total generation capacity exceeding 4,500 megawatts. WPS is selling its Kewaunee Nuclear Power Plant to a subsidiary of Dominion Resources, Inc., and may not continue to participate in NMC.

The NRC has approved requests by NMC’s affiliated utilities to transfer operating authority for their nuclear plants to NMC, formally establishing NMC as an operating company. NMC manages the operations and maintenance at the plants, and is responsible for physical security. NMC’s responsibilities also include oversight of on-site dry storage facilities for used nuclear fuel at the Prairie Island nuclear plant. Utility plant owners, including NSP-Minnesota, continue to own the plants, control all energy produced by the plants, and retain responsibility for nuclear liability insurance and decommissioning costs. Existing personnel continue to provide day-to-day plant operations, with the additional benefit of implementing best practices from all NMC-operated plants for improved safety, reliability and operational performance.

For further discussion of nuclear issues, see Notes 17 and 18 to the Consolidated Financial Statements.

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Electric Operating Statistics (Xcel Energy)

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NATURAL GAS UTILITY OPERATIONS

Competition and Industry Restructuring

Changes in regulatory policies and market forces have shifted the industry from traditional bundled natural gas sales service to an unbundled transportation and market-based commodity service at the wholesale level and for larger commercial and industrial customers. These customers have greater ability to buy natural gas directly from suppliers and arrange their own pipeline and retail local distribution company (LDC) transportation service.

The natural gas delivery/transportation business has remained competitive as industrial and large commercial customers have the ability to bypass the local natural gas utility through the construction of interconnections directly with, and the purchase of natural gas from, interstate pipelines, thereby avoiding the delivery charges added by the local natural gas utility.

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

Capability and Demand

NSP-Minnesota and NSP-Wisconsin

Xcel Energy categorizes its natural gas supply requirements as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for the combined system of NSP-Minnesota and NSP-Wisconsin was 727,354 million British thermal units (MMBtu) for 2003, which occurred on Jan. 20, 2003.

NSP-Minnesota and NSP-Wisconsin purchase natural gas from independent suppliers. The natural gas is delivered under natural gas transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 610,000 MMBtu/day. In addition, NSP-Minnesota and NSP-Wisconsin have contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 17 percent of winter natural gas requirements and 22 percent of peak day, firm requirements of NSP-Minnesota and NSP-Wisconsin.

NSP-Minnesota and NSP-Wisconsin also own and operate two liquefied natural gas (LNG) plants with a storage capacity of 2.5 Billion cubic feet (Bcf) equivalent and four propane-air plants with a storage capacity of 1.4 Bcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 242,708 MMBtu of natural gas per day, or approximately 30 percent of peak day firm requirements. LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days.

NSP-Minnesota and NSP-Wisconsin are required to file for a change in natural gas supply contract levels to meet peak demand, to redistribute demand costs among classes or to exchange one form of demand for another. NSP-Minnesota’s 2002-2003 entitlement levels were approved on Feb. 27, 2003, which allow NSP-Minnesota to recover the demand entitlement costs associated with the increase in transportation, supply, and storage levels in its monthly PGA. The 2003-2004 entitlement levels are pending MPUC action. NSP-Wisconsin’s winter 2003-2004 supply plan was approved by the PSCW in October 2003.

PSCo and Cheyenne

PSCo and Cheyenne project peak day natural gas supply requirements for firm sales and backup transportation, which include transportation customers contracting for firm supply backup, to be approximately 1,769,706 MMBtu and 44,380 MMBtu, respectively. In addition, firm transportation customers hold 438,560 MMBtu for PSCo and 139 MMBtu for Cheyenne, of capacity without supply backup. Total firm delivery obligation for PSCo is 2,208,266 MMBtu and for Cheyenne is 44,519 MMBtu, per day. The maximum daily deliveries for both companies in 2003 for firm and interruptible services were 1,588,833 MMBtu for PSCo and 65,738 MMBtu for Cheyenne on Feb. 24, 2003.

PSCo and Cheyenne purchase natural gas from independent suppliers. The natural gas supplies are delivered to the respective delivery systems through a combination of transportation agreements with interstate pipelines and deliveries by suppliers directly to each company. These

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agreements provide for firm deliverable pipeline capacity of approximately 1,842,891 MMBtu/day, which includes 816,866 MMBtu of supplies held under third-party underground storage agreements. In addition, PSCo operates three company-owned underground storage facilities, which provide about 45,000 MMBtu of natural gas supplies on a peak day. The balance of the quantities required to meet firm peak day sales obligations are primarily purchased at the companies’ city gate meter stations and a small amount is received directly from wellhead sources.

PSCo has received approval and is in the process of closing the Leyden Storage Field. The field’s 110,000 MMBtu peak day capacity was replaced with additional third-party storage and transportation capacity. See further discussion at Note 17 to the Consolidated Financial Statements.

PSCo is required by CPUC regulations to file a natural gas purchase plan by June of each year projecting and describing the quantities of natural gas supplies, upstream services and the costs of those supplies and services for the period beginning July 1 through June 30 of the following year. PSCo is also required to file a natural gas purchase report by October of each year reporting actual quantities and costs incurred for natural gas supplies and upstream services for the 12-month period ending the previous June 30.

Natural Gas Supply and Costs

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

The following table summarizes the average cost per MMBtu of natural gas purchased for resale by Xcel Energy’s regulated retail natural gas distribution business:

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

NSP-Minnesota and NSP-Wisconsin

NSP-Minnesota and NSP-Wisconsin have firm natural gas transportation contracts with several pipelines, which expire in various years from 2004 through 2014.

NSP-Minnesota and NSP-Wisconsin have certain natural gas supply and transportation agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2003, NSP-Minnesota and NSP-Wisconsin were committed to approximately $622.3 million in such obligations under these contracts.

NSP-Minnesota and NSP-Wisconsin purchase firm natural gas supply utilizing long-term and short-term agreements from approximately 20 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Minnesota and NSP-Wisconsin to maintain competition from suppliers and minimize supply costs.

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PSCo and Cheyenne

PSCo and Cheyenne have certain natural gas supply and transportation agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2003, PSCo and Cheyenne were committed to approximately $940.9 million and $4.4 million, respectively, in such obligations under these contracts, which expire in various years from 2004 through 2030. Any contracts entered into by PSCo to serve Cheyenne will be transferred in conjunction with the sale of Cheyenne.

PSCo and Cheyenne purchase natural gas by optimizing a balance of long-term and short-term natural gas purchases, firm transportation and natural gas storage contracts. PSCo and Cheyenne also utilize a mixture of fixed-price purchases and index-related purchases to provide a less volatile, yet market-sensitive, price to its customers. During 2003, PSCo and Cheyenne purchased natural gas from approximately 40 suppliers.

Viking

In January 2003, Xcel Energy sold Viking, including its partial interest in Guardian Pipeline, LLC, to Border Viking Co., whose ultimate parent is Northern Border Partners L. P. Xcel Energy received net proceeds of $124 million.

BMG

On Oct. 20, 2003, Xcel Energy completed the sale of BMG to Southwest Gas Corp. Xcel Energy received net proceeds of $24 million.

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Gas Operating Statistics (Xcel Energy)

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NONREGULATED SUBSIDIARIES

Through its non-utility subsidiaries, Xcel Energy invests in and operates several nonregulated businesses in a variety of industries. The following is an overview of the significant nonregulated businesses.

NRG Energy, Inc.

NRG is an energy company primarily engaged in the ownership and operation of power generation facilities and the sale of energy, capacity and related products in the United States and internationally.

During 2003, Xcel Energy relinquished its ownership interest in NRG. On May 14, 2003, NRG and certain of its affiliates filed voluntary petitions in the U. S. Bankruptcy Court for the Southern District of New York for reorganization under Chapter 11 of the U.S. Bankruptcy Code to restructure their debt. On Dec. 5, 2003, NRG completed its reorganization and emerged from bankruptcy. As a result of the reorganization, Xcel Energy relinquished its ownership interest in NRG. At Dec. 31, 2003, Xcel Energy reports NRG’s financial activity as a component of discontinued operations. Xcel Energy is obligated to make payments of up to $752 million to NRG in 2004 and expects to fund these payments with cash on hand, borrowings against Xcel Energy's revolving credit facilities and proceeds from a tax refund associated with the write-off of its investment in NRG.

Since the early 1990’s, NRG has pursued a strategy of rapid growth through acquisitions. Starting in 2000, NRG added new construction to this strategy. This strategy required significant capital, much of which was satisfied primarily with debt. Due to a number of factors, including the overall downturn in the energy industry, NRG’s financial condition deteriorated significantly and resulted in the bankruptcy filing. Prior to its emergence from bankruptcy and Xcel Energy’s divestiture of ownership, NRG sold a significant amount of its assets. See Notes 3 and 4 to the Consolidated Financial Statements.

e prime, inc.

e prime was incorporated in 1995 under the laws of Colorado. e prime provided energy related products and services, which included natural gas marketing and trading and energy consulting. In 1996, e prime received authorization from the FERC to act as a power marketer.

e prime’s gas trading operations acquired assets and commodities and subsequently traded around those assets or commodity positions. e prime captured trading opportunities through price volatility driven by factors such as asset utilization, locational price differentials, weather, available supplies, credit and customer actions. Trading margins were captured through the utilization of transmission, transportation and storage assets, capture of regional price differences and other factors. Xcel Energy’s board of directors made a decision in December 2003 to discontinue operations of e prime. Consequently, e prime is in the process of shutting down operations. As part of Xcel Energy’s decision to exit the natural gas merchant business, e prime has severed all but four of its employees. At Dec. 31, 2003, Xcel Energy reported e prime’s financial activity as a component of discontinued operations.

Other Subsidiaries

Although not individually reportable segments, Xcel Energy also has a number of nonregulated subsidiaries in various lines of business. The most significant are discussed below.

Xcel Energy International

Xcel Energy International was formed in 1997 to manage the international operations of Xcel Energy.

Xcel Energy and American Electric Power Co. each held a 50-percent interest in Yorkshire, a UK retail electricity and gas supplier and electric distributor, before selling 95 percent of Yorkshire to Innogy Holdings plc in April 2001. In August 2002, Xcel International sold the remaining 5-percent interest in Yorkshire Power for $33 million to CE Electric UK. Xcel Energy International’s primary operations are conducted through Xcel Energy Argentina. Xcel Energy Argentina’s primary investment consists of the ownership and operation of three independent power production facilities in Argentina.

In December 2003, the board of directors of Xcel Energy approved management’s plan to exit the businesses conducted by Xcel Energy International. Xcel Energy is in the process of marketing the remaining assets and operations of these businesses to prospective buyers and expects to exit the businesses during 2004. At Dec. 31, 2003, Xcel Energy reported Xcel Energy International’s financial activity as a component of discontinued operations.

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Results of discontinued nonregulated operations in 2003 include an after-tax loss expected on the disposal of all Xcel Energy International assets of $59 million based on the estimated fair value of such assets. The fair value represented a market bid or appraisal received that is believed to best reflect the assets fair value at Dec. 31, 2003. Xcel Energy’s remaining investment in Xcel Energy International at Dec. 31, 2003, was approximately $39 million.

Utility Engineering Corp. (UE)

UE was incorporated in 1985 under the laws of Texas. UE is engaged in engineering, design, construction management and other miscellaneous services. UE currently has five wholly owned subsidiaries, including Universal Utility Services LLC, Precision Resource Co., Quixx Corp., Proto-Power Corp. and Applied Power Associates Inc.

Planergy International Inc.

Planergy provides energy management, consulting, on-site generation, load curtailment, demand-side management, energy conservation and optimization, distributed generation and power quality services, as well as information management solutions to industrial, commercial and utility customers. During 2003, Planergy closed the majority of its business operations. Planergy sold its remaining operating units in December 2003 and January 2004, and final dissolution is expected in 2004.

Seren Innovations, Inc.

Seren operates a combination cable television, telephone and high-speed Internet access system in St. Cloud, Minn., and Contra Costa County, California. Operation of its broadband communications network has resulted in losses. Seren has completed its build-out phase and has been experiencing improvement in its operating results. Neutral cash flow is expected in 2004 and positive cash flow is projected for 2005. A positive earnings contribution is anticipated in 2007, assuming customer addition goals are met. As of Dec. 31, 2003, Xcel Energy’s investment in Seren was approximately $265 million. Seren had capitalized $331 million for plant in service and had incurred another $10 million for construction work in progress for these systems at Dec. 31, 2003.

Eloigne Company

Eloigne was established in 1993 and its principal business is the acquisition of rental housing projects that qualify for low-income housing tax credits under current federal tax law. As of Dec. 31, 2003, approximately $84 million had been invested in Eloigne projects, including approximately $22 million in wholly owned properties and approximately $62 million in equity interests in jointly owned projects. Completed Eloigne projects as of Dec. 31, 2003, are expected to generate tax credits of $39 million over the time period of 2004 through 2012.

ENVIRONMENTAL MATTERS

Certain of Xcel Energy’s subsidiary 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. Xcel Energy has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Company facilities have been designed and constructed to operate in compliance with applicable environmental standards.

Xcel Energy and its subsidiaries strive to comply with all environmental regulations applicable to its 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 Xcel Energy’s operations. For more information on environmental contingencies, see Notes 17 and 18 to the Consolidated Financial Statements and environmental matters in Management’s Discussion and Analysis under Item 7.

CAPITAL SPENDING AND FINANCING

For a discussion of expected capital expenditures and funding sources, see Management’s Discussion and Analysis under Item 7.

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EMPLOYEES

The number of Xcel Energy employees at Dec. 31, 2003, is presented in the table below. Of the employees listed below, 5,655, or 51 percent, are covered under collective bargaining agreements.

* NSP-Minnesota employees include 341 employees loaned to the NMC. In addition, the NMC has 817 employees of its own.

EXECUTIVE OFFICERS

Wayne H. Brunetti, 61, Chairman of the Board, August 2001 to present, Chief Executive Officer, August 2000 to present. Previously, President, Xcel Energy, August 2000 to October 2003, Vice Chairman, President, Chief Operating Officer and Director of NCE since 1997 and President and Director of PSCo since 1994.

Paul J. Bonavia, 52, President — Commercial Enterprises, December 2003 to present and President — Energy Markets, Xcel Energy, August 2000 to present. Previously, Senior Vice President and General Counsel of NCE since 1997.

Benjamin G.S. Fowke III, 45, Chief Financial Officer, Xcel Energy, October 2003 to present, Vice President and Treasurer, Xcel Energy, November 2002 to present. Previously, Vice President and Chief Financial Officer — Energy Markets, Xcel Energy from August 2000 to November 2002, Vice President — Retail Services and Energy Markets, NCE from January 1999 to July 2000 and Vice President — Finance/Accounting, e prime from May 1997 to December 1998.

Raymond E. Gogel, 53, Vice President and Chief Information Officer, Xcel Energy, April 2002 to present. Previously, Vice President and Senior Client Services Principal for IBM Global Services since June 2001 and Senior Project Executive for IBM Global Services since January 1998.

Cathy J. Hart, 54, Vice President and Corporate Secretary, Xcel Energy, August 2000 to present. Previously, Secretary of NCE since 1998.

Gary R. Johnson, 57, Vice President and General Counsel, Xcel Energy, August 2000 to present. Previously, Vice President and General Counsel of NSP since 1991.

Richard C. Kelly, 57, President and Chief Operating Officer, Xcel Energy, October 2003 to present. Previously, Vice President and Chief Financial Officer, Xcel Energy, August 2002 to October 2003, President — Enterprises, Xcel Energy, August 2000 to August 2002, Executive Vice President and Chief Financial Officer for NCE from 1997 to August 2000 and Senior Vice President of PSCo from 1990 to 1997.

Cynthia L. Lesher, 55, Chief Administrative Officer, Xcel Energy, August 2000 to present and Chief Human Resources Officer, Xcel Energy, July 2001 to present. Previously, President of NSP-Gas since July 1997 and prior was Vice President-Human Resources of NSP.

Teresa S. Madden, 47, Vice President and Controller, Xcel Energy, January 2004 to present. Previously, Vice President of Finance for Xcel Energy Customer and Field Operations from August 2003 to January 2004, Interim CFO for Rogue Wave Software, Inc. from February 2003 to July 2003, Corporate Controller for Rogue Wave Software, Inc. from October 2000 to February 2003, Controller for NCE, 1997 to August 2000.

David E. Ripka, 54, Vice President and Controller, Xcel Energy, August 2000 to January 2004. Previously, Vice President and Controller of NRG from June 1999 to August 2000, Controller of NRG from March 1997 to June 1999 and prior was Assistant Controller for NSP from June 1992 to March 1997.

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Patricia K. Vincent, 45, President — Customer and Field Operations, Xcel Energy, July 2003 to present. Previously, President — Retail, Xcel Energy, March 2001 to July 2003, Vice President of Marketing and Sales of Xcel Energy from August 2000 to March 2001, Vice President of Marketing and 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, 57, President — Energy Supply, Xcel Energy, August 2000 to present. Previously, Executive Vice President and Director of PSCo and New Century Services from 1997 to August 2000 and President, Chief Operating Officer and Director of SPS from 1995 to August 2000.

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Item 2. Properties

Virtually all of the utility plant of NSP-Minnesota, NSP-Wisconsin and PSCo is subject to the lien of their first mortgage bond indentures.

Electric utility generating stations:

NSP — Minnesota

(a) Based on NSP-Minnesota’s ownership interest of 59 percent.

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NSP — Wisconsin

* RDF is refuse-derived fuel, made from municipal solid waste.

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PSCo

(a) Based on PSCo’s ownership interest of 9.72 percent.

(b) Based on PSCo’s ownership interest of 75.5 percent of unit 1 and 37.4 percent of unit 2.

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SPS

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2003:

Electric utility transmission and distribution substations at Dec. 31, 2003:

Gas utility mains at Dec. 31, 2003:

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Item 3. Legal Proceedings

In the normal course of business, various lawsuits and claims have arisen against Xcel Energy in addition to the regulatory matters discussed in Item 1. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters.

Legal Contingencies

Department of Energy (DOE) Complaint — On June 8, 1998, NSP-Minnesota filed a complaint in the Court of Federal Claims against the DOE requesting damages in excess of $1 billion for the DOE’s partial breach of the Standard Contract. NSP-Minnesota requested damages consisting of the costs of storage of spent nuclear fuel at the Prairie Island nuclear generating plant, anticipated costs related to the Private Fuel Storage, LLC and costs relating to the 1994 state legislation limiting the number of casks that can be used to store spent nuclear fuel at Prairie Island. On April 6, 1999, the Court of Federal Claims dismissed NSP-Minnesota’s complaint. On May 20, 1999, NSP-Minnesota appealed to the Court of Appeals for the Federal Circuit. On Aug. 31, 2000, the Court of Appeals for the Federal Circuit reversed and remanded to the Court of Federal Claims. On Dec. 26, 2000, NSP-Minnesota filed a motion with the Court of Federal Claims to amend its complaint and renew its motion for summary judgment on the DOE’s liability. On July 31, 2001, the Court of Federal Claims granted NSP-Minnesota’s motion for summary judgment on liability. On Nov. 28, 2001, the DOE brought motions for partial summary judgment on the schedule for acceptance of spent nuclear fuel and the DOE’s obligation to accept greater than Class C waste. These motions are pending. Limited discovery with respect to the schedule issues has been conducted. A trial in NSP-Minnesota’s suit against the DOE is not likely to occur before the second quarter of 2004.

Lamb County Electric Cooperative — On July 24, 1995, Lamb County Electric Cooperative, Inc. (LCEC) petitioned the PUCT for a cease and desist order against SPS. LCEC alleged that SPS 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 SPS. The basis of the decision was the determination that SPS was 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 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 SPS, Texaco Exploration and Production Inc. and Apache Corporation have intervened in the proceeding and filed briefs 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 SPS in the District Court in Lamb County, Texas, based on 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 SPS providing electric service to the disputed customers. The PUCT order of May 23, 2003, found that SPS was 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 result in a re-determination of the legality of SPS’ service to the disputed customers.

St. Cloud Gas Explosion — Twenty-five lawsuits have been filed as a result of a Dec. 11, 1998, gas explosion in St. Cloud, Minn. that killed four persons (including two employees of NSP-Minnesota), injured several others and damaged numerous buildings. Most of the lawsuits name as defendants NSP-Minnesota, Xcel Energy’s Seren subsidiary, Cable Constructors, Inc. (CCI) (the contractor hired by Seren that struck the marked gas line), and Sirti, an architectural/engineering firm hired by Seren for its St. Cloud cable installation project. The court granted the plaintiffs’ request to amend the complaint to seek punitive damages against Seren and CCI. The plaintiffs brought a similar motion against NSP-Minnesota, which was subsequently denied by the court. On Nov. 11, 2003, court-ordered mediation was conducted. As a result of this mediation NSP-Minnesota reached a confidential settlement with a group of plaintiffs representing the most significant claims asserted against NSP-Minnesota. In November and December of 2003, similar mediations were conducted that resulted in confidential settlements with various plaintiffs representing the most significant claims asserted against Seren. The settlements will be paid primarily by NSP-Minnesota and Seren’s insurance carriers. Remaining settlement payments by NSP-Minnesota are not material. A trial date has not been set for the remaining lawsuits although Seren’s insurance carriers have initiated mediation efforts with these plaintiffs.

Fortistar Litigation — On Feb. 26, 2003, Fortistar Capital, Inc. and Fortistar Methane, LLC filed a $1-billion lawsuit in the Federal District Court for the Northern District of New York against Xcel Energy Inc. and five former employees of NRG or NEO Corp., a subsidiary of NRG. In the lawsuit, Fortistar claims that the defendants violated the Racketeer Influenced and Corrupt Organizations Act (RICO) and committed fraud by engaging in a pattern of negotiating and executing agreements “they intended not to comply with” and “made false statements later to conceal their fraudulent promises.” The allegations against Xcel Energy are, for the most part, limited to purported activities related to the

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contract for the Pike Energy power facility in Mississippi and statements related to an “equity infusion” into NRG by Xcel Energy. The plaintiffs allege damages of some $350 million and also assert entitlement to a trebling of these damages under the provisions of the RICO. A settlement has been reached between plaintiffs and defendants resulting in the dismissal of this lawsuit.

Stone & Webster, Inc. vs. Xcel Energy Inc. — On Oct. 17, 2002, Stone & Webster, Inc. and Shaw Constructors, Inc. filed an action in the U.S. District Court for the Southern District of Mississippi against Xcel Energy; Wayne H. Brunetti, Chairman, and Chief Executive Officer; Richard C. Kelly, Vice President and Chief Operating Officer, and NRG and certain NRG subsidiaries. The plaintiffs alleged they had a contract with a single purpose NRG subsidiary for the construction of a power generation facility, which was abandoned before completion but after substantial sums had been spent by plaintiffs. They alleged breach of contract, breach of an NRG guarantee, breach of fiduciary duty, tortious interference with contract, detrimental reliance, misrepresentation, conspiracy and aiding and abetting, and sought to impose alter ego liability on defendants other than the contracting NRG subsidiary through piercing the corporate veil. The complaint sought compensatory damages of at least $130 million plus demobilization and cancellation costs and punitive damages at least treble the compensatory damages. On Dec. 23, 2002, the defendants filed motions to dismiss the complaint, which the court denied. In September 2003, the parties reached a settlement that resulted in the dismissal of the lawsuit.

Xcel Energy Inc. Shareholder Derivative Action; Essmacher vs. Brunetti; McLain vs. Brunetti — On Aug. 15, 2002, a shareholder derivative action was filed in the U.S. District Court for the District of Minnesota, purportedly on behalf of Xcel Energy, against the directors and certain present and former officers, citing allegedly false and misleading disclosures concerning various issues and asserting breach of fiduciary duty. This action has been consolidated for pre-trial purposes with other securities class actions, described in Note 17 to the Consolidated Financial Statements, and an amended complaint was filed. After the filing of this action, two additional derivative actions were filed in the state trial court for Hennepin County, Minn., against essentially the same defendants, focusing on allegedly wrongful energy trading activities and asserting breach of fiduciary duty for failure to establish adequate accounting controls, abuse of control and gross mismanagement. Considered collectively, the complaints seek compensatory damages, a return of compensation received, and awards of fees and expenses. In each of the cases, the defendants filed motions to dismiss the complaint or amended 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. The motions in federal court have not been ruled upon. In an order dated Jan. 6, 2004, the Minnesota district court judge granted the defendants’ motion to dismiss both of the state court actions. On March 3, 2004, plaintiffs filed notices of appeal related to this decision. Discovery is proceeding in conjunction with the securities litigation, previously described.

Newcome vs. Xcel Energy Inc.; Barday vs. Xcel Energy Inc. — On Sept. 23, 2002, and Oct. 9, 2002, two essentially identical actions were filed in the U.S. District Court for the District of Colorado, purportedly on behalf of classes of employee participants in Xcel Energy’s and its predecessors’ 401(k) or ESOP plans, from as early as Sept. 23, 1999, forward. The complaints in the actions name as defendants Xcel Energy, its directors, certain former directors, James J. Howard and Giannantonio Ferrari, and certain present and former officers, Edward J. McIntyre and David E. Ripka. The complaints allege violations of the ERISA in the form of breach of fiduciary duty in allowing or encouraging purchase, contribution and/or retention of Xcel Energy’s common stock in the plans and making misleading statements and omissions in that regard. The complaints seek injunctive relief, restitution, disgorgement and other remedial relief, interest and an award of fees and expenses. The defendants filed motions to dismiss the complaints. On March 10, 2004, defendants’ motions were granted in part and denied in part. The plaintiffs have made certain voluntary disclosure of information, and discovery is proceeding in conjunction with the securities litigation previously described. Upon motion of defendants, the cases have been transferred to the District of Minnesota for purposes of coordination with the securities class actions and shareholders derivative action pending there.

Additional Information

For more discussion of legal claims and environmental proceedings, see Note 17 to the Consolidated Financial Statements under Item 8, incorporated by reference. For a discussion of proceedings involving utility rates and other regulatory matters, see Pending Regulatory Matters under Item 1, and Management’s Discussion and Analysis under Item 7, incorporated by reference.

Item 4. Submission of Matters to a Vote of Security Holders

No issues were submitted for a vote during the fourth quarter of 2003.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Quarterly Stock Data

Xcel Energy’s common stock is listed on the New York Stock Exchange (NYSE), the Chicago Stock Exchange and the Pacific Stock Exchange. The trading symbol is XEL. The following are the reported high and low sales prices based on the NYSE Composite Transactions for the quarters of 2003 and 2002 and the dividends declared per share during those quarters.

Book value per share at Dec. 31, 2003, was $12.95. The number of common shareholders of record as of Dec. 31, 2003 was 121,900.

Xcel Energy’s Restated Articles of Incorporation provide for certain restrictions on the payment of cash dividends on common stock. At Dec. 31, 2003 and 2002, the payment of cash dividends on common stock was not restricted except as described below.

Under PUHCA, unless there is an order from the SEC, a holding company or any subsidiary may only declare and pay dividends out of retained earnings. Due to 2002 losses incurred by NRG, retained earnings of Xcel Energy were a deficit of $101 million at Dec. 31, 2002 and, accordingly, dividends could not be declared until earnings in 2003 were sufficient to eliminate this deficit or Xcel Energy was granted relief under the PUHCA. See Common Stock Dividends under Item 7 for a discussion of factors affecting Xcel Energy’s payment of dividends during 2003.

See Item 12 for information concerning securities authorized for issuance under equity compensation plans.

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Item 6. Selected Financial Data

(a)		Operating revenues and expenses for 1999 through 2002 include reclassifications to conform to the 2003 presentation. These reclassifications related to reporting electric and natural gas trading revenues and costs on a net basis, and to presenting the results of discontinued operations separately. These reclassifications had no effect on net income.
(b)		Amounts include pro forma adjustments to restate periods before the merger to create Xcel Energy, for historically consistent reporting. Dividends in 2000 reflect dividends paid by predecessor companies before, and Xcel Energy after, the Xcel Energy merger in August 2000.
(c)		Excludes undistributed equity income and includes allowance for funds used during construction.
(d)		Total assets for 2003 and 2002 reflect the classification of accrued future plant removal costs as a component of regulatory liabilities. For periods prior to 2001, they are reflected as a component of accumulated depreciation. Accrued future removal costs were $862 million and $810 million in 2003 and 2002, respectively.
(e)		Long term debt for 1999 through 2003 includes only debt of continuing operations.
(f)		The 2002 average number of common and potentially dilutive shares has been restated to include the effect of dilutive securities which were excluded in 2002 due to Xcel Energy’s loss from continuing operations. Including these securities would have been antidilutive, or would have reduced the reported loss per share. In 2002, the loss from continuing operations that was caused by NRG made some securities “antidilutive” or would have reduced the reported loss per share. In 2003, NRG’s results were reclassified to discontinued operations.

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Item 7. Management’s Discussion and Analysis

BUSINESS SEGMENTS AND ORGANIZATIONAL OVERVIEW

Xcel Energy Inc. (Xcel Energy), a Minnesota corporation, is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). In 2003, Xcel Energy directly owned five utility subsidiaries that serve electric and natural gas customers in 11 states. These utility subsidiaries are Northern States Power Co., a Minnesota corporation (NSP-Minnesota); Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado (PSCo); Southwestern Public Service Co. (SPS) and Cheyenne Light, Fuel and Power Co. (Cheyenne). These utilities serve customers in portions of Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas, Wisconsin and Wyoming. Along with WestGas InterState Inc. (WGI), an interstate natural gas pipeline, these companies comprise our continuing regulated utility operations. In January 2003, Xcel Energy sold Viking Gas Transmission Co. (Viking), an interstate natural gas pipeline company, including Viking’s interest in Guardian Pipeline, LLC. In October 2003, Xcel Energy sold Black Mountain Gas Co. (BMG), a regulated natural gas and propane distribution company. Both Viking and BMG are reported as a component of discontinued operations. In January 2004, Xcel Energy reached an agreement to sell Cheyenne, pending regulatory approval.

Xcel Energy’s nonregulated subsidiaries in continuing operations include Utility Engineering Corp. (engineering, construction and design), Seren Innovations, Inc. (broadband telecommunications services), Planergy International, Inc. (energy management solutions) and Eloigne Co. (investments in rental housing projects that qualify for low-income housing tax credits). During 2003, the board of directors of Xcel Energy approved management’s plan to exit businesses conducted by the nonregulated subsidiaries Xcel Energy International Inc. (an international independent power producer, operating primarily in Argentina) and e prime inc. (a natural gas marketing and trading company). Both of these businesses are presented as a component of discontinued operations.

During 2003, Xcel Energy also divested its ownership interest in NRG Energy, Inc. (NRG), an independent power producer. On May 14, 2003, NRG and certain of its affiliates filed voluntary petitions in the U.S. Bankruptcy Court for the Southern District of New York for reorganization under Chapter 11 of the U.S. Bankruptcy Code to restructure their debt. On Dec. 5, 2003, NRG completed its reorganization and emerged from bankruptcy. As a result of the reorganization, Xcel Energy relinquished its ownership interest in NRG. At Dec. 31, 2003, Xcel Energy reports NRG’s financial activity as a component of discontinued operations. Xcel Energy is obligated to make payments of up to $752 million to NRG in 2004 and expects to fund these payments with cash on hand and proceeds from a tax refund associated with the write-off of its investment in NRG.

See Note 3 to the Consolidated Financial Statements for further discussion of discontinued operations.

FORWARD-LOOKING STATEMENTS

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. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “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 the availability of credit and its impact on capital expenditures and the ability of Xcel Energy and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by Xcel Energy and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership; structures that affect the speed and degree to which competition enters the electric and natural gas markets; the higher risk associated with Xcel Energy’s nonregulated businesses compared with its regulated businesses; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; risks associated with the California power market; the items described under Factors Affecting Results of Operations; and the other risk factors listed from time to time by Xcel Energy in reports filed with the Securities and Exchange Commission (SEC), including Exhibit 99.01 to Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2003.

FINANCIAL REVIEW

The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy’s financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying Consolidated Financial Statements and Notes. All note references refer to the Notes to Consolidated Financial Statements.

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RESULTS OF OPERATIONS

Summary of Financial Results

The following table summarizes the earnings contributions of Xcel Energy’s business segments on the basis of generally accepted accounting principles (GAAP). Continuing operations consist of the following:

	•		regulated utility subsidiaries, operating in the electric and natural gas segments; and
	•		several nonregulated subsidiaries and the holding company, where corporate financing activity occurs.

Discontinued operations consist of the following:

	•		the regulated natural gas businesses Viking and BMG, which were sold in 2003;
	•		NRG, which emerged from bankruptcy in late 2003, at which time Xcel Energy divested its ownership interest in NRG; and
	•		the nonregulated subsidiaries Xcel Energy International and e prime, which were classified as held for sale in late 2003 based on the decision to divest them.

Prior-year financial statements have been restated to conform to the current year presentation and classification of certain operations as discontinued. See Note 3 to the Consolidated Financial Statements for a further discussion of discontinued operations.

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(a) Not a reportable segment. Included in All Other segment results in Note 20 to the Consolidated Financial Statements.

(b) Includes tax benefit related to NRG. See Note 3 to the Consolidated Financial Statements.

The regulated utility segment contribution to income from continuing operations was lower in 2003 primarily due to higher operating costs and weather impacts, as well as share dilution. The increase in income from discontinued operations in 2003 is largely due to lower NRG-related losses compared with 2002. NRG recorded more than $3 billion of asset impairment and other charges in 2002 as it commenced its financial restructuring. Results from discontinued operations include NRG-related tax benefits in both 2003 and 2002, as discussed in the Discontinued Operations section later.

Common Stock Dilution — Dilution, primarily from common stock and convertible securities issued in 2002, reduced the utility segment earnings from continuing operations by 12 cents per share for 2003, compared with average common stock and equivalent levels in 2002. Total earnings from continuing operations were reduced by 11 cents per share for 2003, compared with 2002 share levels. In 2003 and 2002, approximately 418.9 million and 384.6 million average common shares and equivalents, respectively, were used in the calculation of diluted earnings per share.

Because the divestiture of NRG has required its reclassification to discontinued operations in 2003, as discussed later, Xcel Energy is now reporting income from continuing operations in 2003 and 2002. Under accounting requirements, the calculation of diluted earnings per share must be changed for prior periods that reported losses, in which equivalents were previously considered antidilutive. Accordingly, the average common shares assumed in the diluted earnings per share amounts for the third and fourth quarters of 2002, the year 2002 and the first three quarters of 2003 have been recalculated to assume more share dilution and are different from amounts previously reported for those periods. See Note 11 to the Consolidated Financial Statements for further discussion of the calculation of average shares and earnings per share.

Statement of Operations Analysis — Continuing Operations

The following discussion summarizes the items that affected the individual revenue and expense items reported in the Statement of Operations.

Electric Utility and Commodity Trading Margins

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 retail fuel clause cost recovery mechanism in Colorado changed in 2003. For 2002 and 2001, electric utility margins in Colorado reflect the impact of sharing energy costs and savings between customers and shareholders relative to a target cost per delivered kilowatt-hour under the retail incentive cost adjustment (ICA) ratemaking mechanism. For 2003, PSCo is authorized to fully recover its retail electric fuel and purchased energy expense through the interim adjustment clause (IAC). In addition to the IAC, PSCo has other adjustment clauses that allow certain costs to be recovered from retail customers.

Xcel Energy has two distinct forms of electric wholesale sales: short-term wholesale and electric commodity trading. Short-term wholesale refers to electric sales for resale, which are associated with energy produced from Xcel Energy’s generation assets or energy and capacity purchased to serve native load. Electric commodity trading refers to the sales for resale activity of purchasing and reselling electric energy to the wholesale market. Short-term wholesale and electric trading activities are considered part of the electric utility segment.

Xcel Energy’s electric commodity trading operations are conducted by NSP-Minnesota and PSCo. Margins from electric trading activity are partially redistributed to other operating utilities of Xcel Energy, pursuant to a joint operating agreement (JOA) approved by the Federal Energy Regulatory Commission (FERC). PSCo’s short-term wholesale and electric trading margins reflect the impact of regulatory sharing, if applicable, of certain margins with Colorado retail customers. Trading revenues, as discussed in Note 1 to the Consolidated Financial Statements, are reported net (i.e., on a margin basis) in the Consolidated Statements of Operations. Trading revenue and costs associated with NRG’s operations are included in discontinued operations. Xcel Energy has participated in natural gas commodity trading through e prime, which is now considered a discontinued operation for all periods presented. Consequently, neither NRG nor e prime trading activity is reflected in the following table. The following table details the revenue and margin for base electric utility, short-term wholesale and electric commodity trading activities:

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The following summarizes the components of the changes in base electric utility revenue and base electric utility margin for the years ended Dec. 31:

Base Electric Utility Revenue

2003 Comparison with 2002 — Base electric utility revenues increased due to weather-normalized retail sales growth of approximately 1.5 percent, higher fuel and purchased power costs, which are largely passed through to customers, and higher capacity sales in Texas. In addition, the AQIR was implemented in Colorado in January 2003 for the recovery of investments and related costs to improve air quality. Partially offsetting the higher revenues was the impact of warmer temperatures during the summer of 2002 compared with the summer of 2003, as well as 2003 rate reductions related to lower property taxes in Minnesota and estimated customer refunds related to service quality requirements in Colorado.

2002 Comparison with 2001 — Base electric utility revenues decreased due mainly to lower fuel and purchased power costs, which are largely passed through to customers, and lower capacity sales in Texas. In addition, 2002 revenues were lower due to the 2001 allowed recovery of 1998 incentives associated with state-mandated programs for energy conservation. The amounts were previously recorded as liabilities potentially due to Minnesota customers. Partially offsetting the decreases in revenue was weather-normalized retail sales growth of approximately 1.8 percent, the impact of warmer temperatures during the summer of 2002 compared with 2001 and lower 2002 estimated customer refunds related to both service quality requirements in Colorado and property tax refunds in Minnesota.

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Base Electric Utility Margin

2003 Comparison to 2002 — Base electric utility margin decreased due mainly to higher purchased capacity costs associated with new contracts to support growth, the allowed recovery of fuel and purchased power costs in excess of actual costs in 2002 under the sharing provisions of the incentive cost adjustment mechanism in Colorado, compared with passing through costs with no sharing provisions under the IAC in 2003 and the impact of weather. Also decreasing margin were 2003 rate reductions related to lower property taxes in Minnesota and estimated refunds to customers related to service quality requirements in Colorado. The decreases were partially offset by weather-normalized sales growth, the implementation of the AQIR and higher capacity sales, as previously discussed.

2002 Comparison to 2001 — Base electric utility margin increased due to weather-normalized retail sales growth, the impact of weather and lower 2002 estimated customer refunds related to both service quality requirements in Colorado and property tax refunds in Minnesota. In addition, the higher base electric margins in 2002 reflect lower unrecovered costs, due in part to resetting the base-energy-cost recovery at PSCo in January 2002. In 2001, PSCo’s allowed recovery was approximately $78 million less than its actual costs, while in 2002, its allowed recovery was approximately $29 million more than its actual costs. Partially offsetting the increased margin was the 2001 conservation incentive recovery discussed previously and higher purchased capacity costs due to new contracts to support growth and lower capacity sales in Texas.

Short-Term Wholesale and Electric Commodity Trading Margin