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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

     
(Mark One)
   
x
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the Fiscal Year Ended Dec. 31, 2003
or
 
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934

Commission File Number 1-3034

Xcel Energy Inc.
(Exact name of registrant as specified in its charter)
     
Minnesota
(State or Other Jurisdiction of Incorporation or Organization)

800 Nicollet Mall, Minneapolis, Minnesota
(Address of Principal Executive Offices)
  41-0448030
(I.R.S. Employer Identification No.)

55402
(Zip Code)

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

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

         
        Name of Each Exchange on
Registrant
  Title of Each Class
  Which Registered
Xcel Energy Inc.
  Common Stock, $2.50 par value per share   New York, Chicago, Pacific
Xcel Energy Inc.
  Rights to Purchase Common Stock, $2.50 par value per share Cumulative Preferred Stock, $100 par value:   New York, Chicago, Pacific
Xcel Energy Inc.
  Preferred Stock $3.60 Cumulative   New York
Xcel Energy Inc.
  Preferred Stock $4.08 Cumulative   New York
Xcel Energy Inc.
  Preferred Stock $4.10 Cumulative   New York
Xcel Energy Inc.
  Preferred Stock $4.11 Cumulative   New York
Xcel Energy Inc.
  Preferred Stock $4.16 Cumulative   New York
Xcel Energy Inc.
  Preferred Stock $4.56 Cumulative   New York

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

     The Registrant’s Definitive Proxy Statement for its 2004 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

 


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Index

         
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    139  
 Release-Based Amount Agreement
 Settlement Agreement
 Employee Matters Agreement
 Tax Matters Agreement
 Indenture
 Registration Rights Agreement
 Supplemental Trust Indenture
 Exchange and Registration Rights Agreement
 Supplemental Indenture
 Supplemental Indenture
 Credit Agreement
 Registration Rights Agreement
 Nonqualified Deferred Compensation Plan
 Northern States Power Co. Non-employee Deferred
 Power Purchase Agreement
 Statement of Computation of Ratio of Earnings
 Subsidiaries
 Consent of Independent Auditors
 Consent of Independent Accountants
 Written Consent Resolution- Power of Attorney
 Principal Executive Officer's Certification
 Principal Financial Officer's Certification
 Certification Pursuant to 18 U.S.C. Section 1350
 Statement re: Private Securities Litigation Act

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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.

         
Actual Costs as a Percent of Target Costs
  ROE
Less than or equal to 75%
    11.47 %
Over 75% and up through 85%
    11.22 %
Over 85% and up through 95%
    11.00 %
Over 95% and up through 105%
    10.86 %
Over 105% and up through 115%
    10.55 %
Over 115% and up through 125%
    10.22 %
Over 125%
    9.97 %

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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.

                                 
    System Peak Demand (in Megawatts)
Operating Company
  2001
  2002
  2003
  2004 Forecast
NSP System
    8,344       8,259       8,289       8,278  
PSCo
    5,644       5,872       6,419       6,132  
SPS
    4,080       4,018       4,338       4,497  

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.

                                         
    Coal*
  Nuclear
  Average Fuel
NSP System Generating Plants
  Cost
  Percent
  Cost
  Percent
  Cost
2003
  $ 0.99       61 %   $ 0.43       36 %   $ 0.90  
2002
  $ 0.96       59 %   $ 0.46       38 %   $ 0.81  
2001
  $ 0.96       62 %   $ 0.47       35 %   $ 0.86  

*Includes refuse-derived fuel and wood

                                         
    Coal
  Natural Gas
  Average Fuel
PSCo Generating Plants
  Cost
  Percent
  Cost
  Percent
  Cost
2003
  $ 0.92       86 %   $ 4.49       14 %   $ 1.42  
2002
  $ 0.91       79 %   $ 2.25       21 %   $ 1.19  
2001
  $ 0.86       84 %   $ 4.27       16 %   $ 1.41  

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    Coal
  Natural Gas
   
                                    Average Fuel
SPS Generating Plants
  Cost
  Percent
  Cost
  Percent
  Cost
2003**
  $ 0.93       73 %   $ 5.24       27 %   $ 2.10  
2002
  $ 1.33       74 %   $ 3.27       26 %   $ 1.84  
2001
  $ 1.40       69 %   $ 4.35       31 %   $ 2.31  

**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)

                         
    Year Ended Dec. 31,
    2003
  2002
  2001
Electric Sales (millions of Kwh)
                       
Residential
    23,428       23,302       22,113  
Commercial and Industrial
    58,274       57,815       57,755  
Public Authorities and Other
    1,169       1,143       1,103  
 
   
 
     
 
     
 
 
Total Retail
    82,871       82,260       80,971  
Sales for Resale
    21,981       23,256       26,104  
 
   
 
     
 
     
 
 
Total Energy Sold
    104,852       105,516       107,075  
 
   
 
     
 
     
 
 
Number of Customers at End of Period
                       
Residential
    2,801,550       2,756,565       2,722,832  
Commercial and Industrial
    404,046       394,620       387,579  
Public Authorities and Other
    81,158       81,341       100,819  
 
   
 
     
 
     
 
 
Total Retail
    3,286,754       3,232,526       3,211,230  
Wholesale
    211       309       305  
 
   
 
     
 
     
 
 
Total Customers
    3,286,965       3,232,835       3,211,535  
 
   
 
     
 
     
 
 
Electric Revenues (thousands of dollars)
                       
Residential
  $ 1,812,501     $ 1,677,231     $ 1,697,390  
Commercial and Industrial
    3,104,734       2,791,550       2,979,730  
Public Authorities and Other
    108,466       98,394       91,438  
Regulatory Accrual Adjustment
          4,766       15,480  
 
   
 
     
 
     
 
 
Total Retail
    5,025,701       4,571,941       4,784,038  
Wholesale
    805,396       715,144       1,478,038  
Other Electric Revenues
    121,094       148,292       132,661  
 
   
 
     
 
     
 
 
Total Electric Revenues
  $ 5,952,191     $ 5,435,377     $ 6,394,737  
 
   
 
     
 
     
 
 
Kwh Sales per Retail Customer
    25,214       25,448       25,215  
Revenue per Retail Customer
  $ 1,529.08     $ 1,414.36     $ 1,489.78  
Residential Revenue per Kwh
    7.74 ¢     7.20 ¢     7.68 ¢
Commercial and Industrial Revenue per Kwh
    5.33 ¢     4.83 ¢     5.16 ¢
Wholesale Revenue per Kwh
    3.66 ¢     3.08 ¢     5.66 ¢

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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:

                                 
    NSP-Minnesota
  NSP-Wisconsin
  PSCo
  Cheyenne
2003
  $ 5.47     $ 6.23     $ 4.94     $ 4.65  
2002
  $ 3.98     $ 4.63     $ 3.17     $ 2.77  
2001
  $ 5.83     $ 5.11     $ 4.99     $ 5.03  

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)

                         
    Year Ended Dec. 31,
    2003
  2002
  2001
Gas Deliveries (thousands of Dth)
                       
Residential
    141,550       143,513       135,633  
Commercial and Industrial
    93,036       95,749       96,503  
 
   
 
     
 
     
 
 
Total Retail
    234,586       239,262       232,136  
Transportation and Other
    129,198       146,149       150,101  
 
   
 
     
 
     
 
 
Total Deliveries
    363,784       385,411       382,237  
 
   
 
     
 
     
 
 
Number of Customers at End of Period
                       
Residential
    1,604,466       1,565,603       1,523,391  
Commercial and Industrial
    150,183       147,952       145,850  
 
   
 
     
 
     
 
 
Total Retail
    1,754,649       1,713,555       1,669,241  
Transportation and Other
    3,304       3,199       3,054  
 
   
 
     
 
     
 
 
Total Customers
    1,757,953       1,716,754       1,672,295  
 
   
 
     
 
     
 
 
Gas Revenues (thousands of dollars)
                       
Residential
  $ 1,037,932     $ 836,729     $ 1,227,670  
Commercial and Industrial
    605,225       452,846       709,242  
 
   
 
     
 
     
 
 
Total Retail
    1,643,157       1,289,575       1,936,912  
Transportation and Other
    67,115       73,785       85,891  
 
   
 
     
 
     
 
 
Total Gas Revenues
  $ 1,710,272     $ 1,363,360     $ 2,022,803  
 
   
 
     
 
     
 
 
Dth Sales per Retail Customer
    133.69       139.63       139.07  
Revenue per Retail Customer
  $ 936.46     $ 752.57     $ 1,160.35  
Residential Revenue per Dth
  $ 7.33     $ 5.83     $ 9.05  
Commercial and Industrial Revenue per Dth
  $ 6.51     $ 4.73     $ 7.35  
Transportation and Other Revenue per Dth
  $ 0.52     $ 0.50     $ 0.57  

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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*
    2,938  
NSP-Wisconsin
    550  
PSCo
    2,579  
SPS
    1,044  
Xcel Energy Services Inc.
    2,973  
Other subsidiaries
    964  
 
   
 
 
Total
    11,048  
 
   
 
 

* 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

                     
                Summer 2003 Net
                Dependable
Station, City and Unit
      Fuel
      Installed
      Capability (Mw)
Sherburne-Becker, Minn
                   
Unit 1
  Coal     1976       705  
Unit 2
  Coal     1977       698  
Unit 3(a)
  Coal     1987       507  
Prairie Island-Welch, Minn
                   
Unit 1
  Nuclear     1973       541  
Unit 2
  Nuclear     1974       541  
Monticello-Monticello, Minn
  Nuclear     1971       583  
King-Bayport, Minn
  Coal     1968       528  
Black Dog-Burnsville, Minn
                   
2 Units
  Coal/Natural Gas     1955-1960       276  
2 Units
  Natural Gas     2002       298  
High Bridge-St. Paul, Minn
                   
2 Units
  Coal     1956-1959       267  
Riverside-Minneapolis, Minn.
                   
2 Units
  Coal     1964-1987       375  
Angus Anson-Sioux Falls, S.D.
                   
2 Units
  Natural Gas     1994       226  
Inver Hills-Inver Grove Heights, Minn
                   
6 Units
  Natural Gas     1972       350  
Blue Lake-Shakopee, Minn
                   
4 Units
  Natural Gas     1974       174  
Other
  Various   Various       324  
 
               
 
 
 
      Total       6,393  
 
               
 
 

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

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NSP — Wisconsin

                     
                Summer 2003 Net
                Dependable
Station, City and Unit
  Fuel
  Installed
  Capability (Mw)
Combustion Turbine:
                   
Flambeau Station-Park Falls, Wis 1 Unit
  Natural Gas/Oil     1969       13  
Wheaton-Eau Claire, Wis
                   
6 Units
  Natural Gas/Oil     1973       353  
French Island-La Crosse, Wis
                   
2 Units
  Oil     1974       147  
Steam:
                   
Bay Front-Ashland, Wis
                   
3 Units
  Coal/Wood/Natural Gas     1945-1960       74  
French Island-La Crosse, Wis
                   
2 Units
  Wood/RDF*     1940-1948       29  
Hydro:
                   
19 Plants
      Various       253  
 
               
 
 
 
      Total       869  
 
               
 
 

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

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    PSCo

                     
                Summer 2003
                Net Dependable
Station, City and Unit
  Fuel
  Installed
  Capability (Mw)
Steam:
                   
Arapahoe-Denver, Colo
                   
2 Units
  Coal     1950-1955       156  
Cameo-Grand Junction, Colo
                   
2 Units
  Coal     1957-1960       73  
Cherokee-Denver, Colo
                   
4 Units
  Coal     1957-1968       717  
Comanche-Pueblo, Colo
                   
2 Units
  Coal     1973-1975       660  
Craig-Craig, Colo
                   
2 Units (a)
  Coal     1979-1980       83  
Hayden-Hayden, Colo
                   
2 Units (b)
  Coal     1965-1976       237  
Pawnee-Brush, Colo
  Coal     1981       505  
Valmont-Boulder, Colo
  Coal     1964       186  
Zuni-Denver, Colo
                   
3 Units
  Natural Gas/Oil     1948-1954       107  
Combustion Turbines:
                   
Fort St. Vrain-Platteville, Colo
                   
4 Units
  Natural Gas     1972-2001       690  
Various Locations
                   
6 Units
  Natural Gas   Various       185  
Hydro:
                   
Various Locations
                   
12 Units
      Various       32  
Cabin Creek-Georgetown, Colo
        1967       210  
Pumped Storage
                   
Wind:
                   
Ponnequin-Weld County, Colo
        1999-2001        
Diesel Generators:
                   
Cherokee-Denver, Colo
                   
2 Units
        1967       6  
 
               
 
 
 
      Total       3,847  
 
               
 
 

(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

                     
                Summer 2003 Net
                Dependable
Station, City and Unit
  Fuel
  Installed
  Capability (Mw)
Steam:
                   
Harrington-Amarillo, Texas
                   
3 Units
  Coal     1976-1980       1,066  
Tolk-Muleshoe, Texas
                   
2 Units
  Coal     1982-1985       1,080  
Jones-Lubbock, Texas
                   
2 Units
  Natural Gas     1971-1974       486  
Plant X-Earth, Texas
                   
4 Units
  Natural Gas     1952-1964       442  
Nichols-Amarillo, Texas
                   
3 Units
  Natural Gas     1960-1968       457  
Cunningham-Hobbs, N.M.
                   
2 Units
  Natural Gas     1957-1965       267  
Maddox-Hobbs, N.M.
  Natural Gas     1983       118  
CZ-2-Pampa, Texas
  Purchased Steam     1979       26  
Moore County-Amarillo, Texas
  Natural Gas     1954       48  
Gas Turbine:
                   
Carlsbad-Carlsbad, N.M.
  Natural Gas     1977       13  
CZ-1-Pampa, Texas
  Hot Nitrogen     1965       13  
Maddox-Hobbs, N.M.
  Natural Gas     1983       65  
Riverview-Electric City, Texas
  Natural Gas     1973       23  
Cunningham-Hobbs, N.M.
  Natural Gas     1998       220  
Diesel:
                   
Tucumcari-N.M.
                   
6 Units
        1941-1968        
 
               
 
 
 
      Total       4,324  
 
               
 
 

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

                                         
Conductor Miles
  Cheyenne
  NSP-Minnesota
  NSP-Wisconsin
  PSCo
  SPS
500 kilovolt (kv)
          2,919                    
345 kv
          5,653       1,312       538       2,754  
230 kv
          1,442             10,428       9,224  
161 kv
          298       1,494              
138 kv
                      92        
115 kv
    113       6,278       1,528       5,033       10,828  
Less than 115 kv
    3,220       78,372       31,076       68,805       21,672  

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

                                         
    Cheyenne
  NSP-Minnesota
  NSP-Wisconsin
  PSCo
  SPS
Quantity
    5       361       206       210       493  

Gas utility mains at Dec. 31, 2003:

                                         
Miles
  Cheyenne
  NSP-Minnesota
  NSP-Wisconsin
  PSCo
  WGI
Transmission
          115             2,272       12  
Distribution
    678       8,702       1,967       18,587        

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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.

                         
2003
  High
  Low
  Dividends
First Quarter
  $ 13.40     $ 10.40     $ 0.0000  
Second Quarter
  $ 15.79     $ 12.69     $ 0.3750  
Third Quarter
  $ 15.69     $ 13.60     $ 0.0000  
Fourth Quarter
  $ 17.40     $ 15.28     $ 0.3750  
                         
2002
  High
  Low
  Dividends
First Quarter
  $ 28.49     $ 22.26     $ 0.3750  
Second Quarter
  $ 26.49     $ 13.91     $ 0.3750  
Third Quarter
  $ 17.20     $ 5.12     $ 0.1875  
Fourth Quarter
  $ 11.60     $ 7.40     $ 0.1875  

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

                                         
(Millions of dollars, except share and per-share data)
  2003
  2002
  2001
  2000
  1999
Operating revenues (a)
  $ 7,938     $ 7,035     $ 8,724     $ 7,298     $ 6,754  
Operating expenses (a)
  $ 6,852     $ 5,894     $ 7,505     $ 7,005     $ 5,713  
Income (loss) from continuing operations (a)
  $ 510     $ 528     $ 579     $ 312     $ 454  
Net income (loss)
  $ 622     $ (2,218 )   $ 795     $ 527     $ 571  
Earnings available for common stock
  $ 618     $ (2,222 )   $ 791     $ 523     $ 566  
Average number of common shares outstanding (000’s)
    398,765       382,051       342,952       337,832       331,943  
Average number of common and potentially dilutive shares outstanding (000’s) (f)
    418,912       384,646       343,742       338,111       332,054  
Earnings per share from continuing operations (a)
  $ 1.27     $ 1.37     $ 1.69     $ 0.91     $ 1.35  
Earnings per share-basic
  $ 1.55     $ (5.82 )   $ 2.31     $ 1.54     $ 1.70  
Earnings per share-diluted (f)
  $ 1.50     $ (5.77 )   $ 2.30     $ 1.54     $ 1.70  
Dividends declared per share (b)
  $ 0.75     $ 1.13     $ 1.50     $ 1.45     $ 1.47  
Total assets (d)
  $ 20,205     $ 29,436     $ 28,754     $ 21,769     $ 18,070  
Long-term debt (e)
  $ 6,519     $ 5,319     $ 4,230     $ 3,884     $ 3,839  
Book value per share
  $ 12.95     $ 11.70     $ 17.91     $ 16.32     $ 15.78  
Return on average common equity
    12.6 %     (41.0 )%     13.5 %     9.6 %     10.9 %
Ratio of earnings to fixed charges (c)
  2.2   2.5   2.8   2.1   2.5

(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.

                         
    Contribution to earnings
(Millions of dollars)
  2003
  2002
  2001
GAAP income (loss) by segment
                       
Regulated electric utility segment income — continuing operations
  $ 462.5     $ 486.8     $ 556.0  
Regulated natural gas utility segment income — continuing operations
    94.9       89.0       63.1  
Other utility results (a)
    6.6       20.4       18.4  
 
   
 
     
 
     
 
 
Total utility segment income — continuing operations
    564.0       596.2       637.5  
Other nonregulated results and holding company costs (a)
    (54.0 )     (68.5 )     (58.3 )
 
   
 
     
 
     
 
 
Total income — continuing operations
    510.0       527.7       579.2  
Regulated utility income — discontinued operations
    24.3       10.4       6.0  
NRG income (loss) — discontinued operations
    (251.4 )     (3,444.1 )     195.1  
Other nonregulated income — discontinued operations (b)
    339.5       688.0       2.8  
 
   
 
     
 
     
 
 
Total income (loss) — discontinued operations
    112.4       (2,745.7 )     203.9  
Extraordinary item — net of tax
                11.8  
 
   
 
     
 
     
 
 
Total GAAP income (loss)
  $ 622.4     $ (2,218.0 )   $ 794.9  
 
   
 
     
 
     
 
 
                         
    Contribution to earnings per share
    2003
  2002
  2001
GAAP earnings per share contribution by segment
                       
Regulated electric utility segment — continuing operations
  $ 1.10     $ 1.27     $ 1.62  
Regulated natural gas utility segment — continuing operations
    0.23       0.23       0.19  
Other utility results (a)
    0.02       0.05       0.05  
 
   
 
     
 
     
 
 
Total utility segment earnings per share — continuing operations
    1.35       1.55       1.86  
Other nonregulated results and holding company costs (a)
    (0.12 )     (0.18 )     (0.18 )
 
   
 
     
 
     
 
 
Total earnings per share — continuing operations
    1.23       1.37       1.68  
Regulated utility earnings — discontinued operations
    0.06       0.03       0.02  
NRG earnings (loss) — discontinued operations
    (0.60 )     (8.95 )     0.56  
Other nonregulated earnings — discontinued operations (b)
    0.81       1.78       0.01  
 
   
 
     
 
     
 
 
Total earnings (loss) per share — discontinued operations
    0.27       (7.14 )     0.59  
Extraordinary item
                0.03  
 
   
 
     
 
     
 
 
Total GAAP earnings (loss) per share — diluted
  $ 1.50     $ (5.77 )   $ 2.30  
 
   
 
     
 
     
 
 

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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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    Base           Electric    
    Electric   Short-Term   Commodity   Consolidated
(Millions of dollars)
  Utility
  Wholesale
  Trading
  Totals
2003
                               
Electric utility revenue
  $ 5,773     $ 179     $     $ 5,952  
Electric fuel and purchased power-utility
    (2,592 )     (118 )           (2,710 )
Electric trading revenue-gross
                333       333  
Electric trading costs
                (316 )     (316 )
 
   
 
     
 
     
 
     
 
 
Gross margin before operating expenses
  $ 3,181     $ 61     $ 17     $ 3,259  
 
   
 
     
 
     
 
     
 
 
Margin as a percentage of revenue
    55.1 %     34.1 %     5.1 %     51.9 %
2002
                               
Electric utility revenue
  $ 5,232     $ 203     $     $ 5,435  
Electric fuel and purchased power-utility
    (2,029 )     (170 )           (2,199 )
Electric trading revenue-gross
                1,529       1,529  
Electric trading costs
                (1,527 )     (1,527 )
 
   
 
     
 
     
 
     
 
 
Gross margin before operating expenses
  $ 3,203     $ 33     $ 2     $ 3,238  
 
   
 
     
 
     
 
     
 
 
Margin as a percentage of revenue
    61.2 %     16.3 %     0.1 %     46.5 %
2001
                               
Electric utility revenue
  $ 5,607     $ 788     $     $ 6,395  
Electric fuel and purchased power-utility
    (2,559 )     (613 )           (3,172 )
Electric trading revenue-gross
                1,337       1,337  
Electric trading costs
                (1,268 )     (1,268 )
 
   
 
     
 
     
 
     
 
 
Gross margin before operating expenses
  $ 3,048     $ 175     $ 69     $ 3,292  
 
   
 
     
 
     
 
     
 
 
Margin as a percentage of revenue
    54.4 %     22.2 %     5.2 %     42.6 %

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

                 
(Millions of dollars)
  2003 vs. 2002
  2002 vs. 2001
Sales growth (excluding weather impact)
  $ 59     $ 80  
Estimated impact of weather
    (29 )     20  
Conservation incentive recovery
          (34 )
Fuel and purchased power cost recovery
    435       (414 )
Air quality improvement recovery (AQIR)
    36        
Capacity sales
    12       (54 )
Rate reductions and customer refunds
    (29 )     28  
Renewable development fund recovery
    12        
Other
    45       (1 )
 
   
 
     
 
 
Total base electric utility revenue increase (decrease)
  $ 541     $ (375 )
 
   
 
     
 
 

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

                 
(Millions of dollars)
  2003 vs. 2002
  2002 vs. 2001
Sales growth (excluding weather impact)
  $ 48     $ 64  
Estimated impact of weather
    (23 )     15  
Conservation incentive recovery
          (34 )
Purchased capacity costs
    (50 )     (32 )
Fuel and purchased power cost recovery
    (41 )     133  
AQIR
    28        
Capacity sales
    12       (54 )
Rate reductions and customer refunds
    (29 )     28  
Renewable development fund recovery
    12        
Other
    21       35  
 
   
 
     
 
 
Total base electric utility margin increase (decrease)
  $ (22 )   $ 155  
 
   
 
     
 
 

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

2003 Comparison to 2002 Short-term wholesale and electric commodity trading margins increased approximately $43 million in 2003 compared with 2002. The increase reflects more favorable market conditions in the northern regions.

2002 Comparison to 2001 Short-term wholesale and electric commodity trading sales margins decreased an aggregate of approximately $209 million in 2002, compared with 2001. The decrease in short-term wholesale and electric commodity trading margin reflects less favorable market conditions in the western regions.

Natural Gas Utility Margins

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

                         
(Millions of dollars)
  2003
  2002
  2001
Natural gas utility revenue
  $ 1,710     $ 1,363     $ 2,023  
Cost of natural gas purchased and transported
    (1,208 )     (853 )     (1,521 )
 
   
 
     
 
     
 
 
Natural gas utility margin
  $ 502     $ 510     $ 502  
 
   
 
     
 
     
 
 

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The following summarizes the components of the changes in natural gas revenue and margin for the years ended Dec. 31:

Natural Gas Revenue

                 
(Millions of dollars)
  2003 vs. 2002
  2002 vs. 2001
Sales growth (excluding weather impact)
  $ 15     $  
Estimated impact of weather on firm sales volume
          22  
Purchased natural gas adjustment clause recovery
    348       (675 )
Rate changes — Colorado
    (14 )      
Transportation and other
    (2 )     (7 )
 
   
 
     
 
 
Total natural gas revenue increase (decrease)
  $ 347     $ (660 )
 
   
 
     
 
 

2003 Comparison to 2002 Natural gas revenue increased mainly due to higher natural gas costs in 2003, which are passed through to customers.

2002 Comparison to 2001 Natural gas revenue decreased mainly due to lower natural gas costs in 2002, which are passed through to customers.

Natural Gas Margin

                 
(Millions of dollars)
  2003 vs. 2002
  2002 vs. 2001
Sales growth (excluding weather impact)
  $ 5     $  
Estimated impact of weather on firm sales volume
    (4 )     18  
Rate changes — Colorado
    (14 )      
Transportation and other
    5       (10 )
 
   
 
     
 
 
Total natural gas margin increase (decrease)
  $ (8 )   $ 8  
 
   
 
     
 
 

2003 Comparison to 2002 Natural gas margin decreased due to base rate decreases agreed to in the settlement of the PSCo 2002 general rate case and the impact of warmer winter temperatures in 2003 compared with 2002. The rate case settlement agreement is discussed further under Factors Affecting Results of Continuing Operations. Partially offsetting the rate decrease was weather-normalized sales growth of 1.6 percent.

2002 Comparison to 2001 Natural gas margin increased due mainly to the impact of colder winter temperatures in 2002 compared with 2001.

Weather — Xcel Energy’s earnings can be significantly affected by weather. Unseasonably hot summers or cold winters increase electric and natural gas sales, but also can increase expenses. Unseasonably mild weather reduces electric and natural gas sales, but may not reduce expenses, which affects overall results. The impact of weather on earnings is based on the number of customers, temperature variances and the amount of gas or electricity the average customer historically has used per degree of temperature.

The following summarizes the estimated impact on the earnings of the utility subsidiaries of Xcel Energy due to temperature variations from historical averages:

  weather in 2003 had minimal impact on earnings per share;
 
  weather in 2002 increased earnings by an estimated 6 cents per share; and
 
  weather in 2001 had minimal impact on earnings per share.

Nonregulated Operating Margins

The following table details the changes in nonregulated revenue and margin included in continuing operations:

                         
(Millions of dollars)
  2003
  2002
  2001
Nonregulated and other revenue
  $ 258     $ 235     $ 237  
Nonregulated cost of goods sold
    (157 )     (133 )     (128 )
 
   
 
     
 
     
 
 
Nonregulated margin
  $ 101     $ 102     $ 109  
 
   
 
     
 
     
 
 

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2003 Comparison to 2002 Nonregulated revenue increased in 2003, due mainly to increasing customer levels in Seren’s communication business. Nonregulated margin decreased in 2003, due to higher cost of goods sold at a subsidiary of Utility Engineering offsetting the revenue increases at Seren.

2002 Comparison to 2001 Nonregulated margin decreased in 2002 compared to 2001, due to higher cost of goods sold at a subsidiary of Utility Engineering.

Non-Fuel Operating Expense and Other Items

Other Utility Operating and Maintenance Expense Other utility operating and maintenance expense for 2003 increased by approximately $91 million, or 6.1 percent, compared with 2002. The increase is due primarily to higher employee related costs, including higher performance-based compensation of $36 million, restricted stock unit grants of $29 million, lower pension credits of $19 million and higher medical and health care costs of $9 million. In 2002 there were no restricted stock unit grants and only a partial award of performance-based compensation. In addition, other utility operating and maintenance expense for 2003 reflects inventory write-downs of $8 million, higher uncollectible accounts receivable of $3 million, higher reliability expenses of $6 million and a software project write-off of $2 million. The increase was partially offset by lower information technology costs resulting from centralization.

Other utility operating and maintenance expense for 2002 decreased by approximately $3 million, or 0.2 percent, compared with 2001. The decreased costs reflect lower incentive compensation and other employee benefit costs of $20 million, as well as lower staffing levels in the corporate areas of approximately $11 million due to completion of the corporate merger synergy plans in late 2001. These decreases were substantially offset by higher costs associated with plant outages of $11 million due to planned outages at multiple plants and higher property insurance costs of $9 million due to unfavorable market conditions in 2002, in addition to inflationary factors such as market wage increases and general market inflation.

Other Nonregulated Operating and Maintenance Expense Other nonregulated operating and maintenance expenses decreased $8 million, or 7.7 percent, in 2003 compared with 2002. Other nonregulated operating and maintenance expenses in 2002 increased $20 million, or 22.8 percent, compared with 2001. The 2002 expenses included employee severance costs at the holding company. These expenses are included in the results for each nonregulated subsidiary, as discussed later.

Depreciation and Amortization Expense Depreciation and amortization expense decreased by approximately $15 million, or 2.0 percent, for 2003, compared with 2002. This decrease reflects the impacts of nuclear plant life extensions at Prairie Island and certain depreciation rate changes in Colorado, partially offset by increasing depreciation related to plant additions. The increase in depreciation and amortization in 2002 compared with 2001 is also due to the impacts of plant additions.

In December 2003, the Minnesota Public Utilities Commission (MPUC) extended the authorized useful lives of the two NSP-Minnesota generating units at the Prairie Island nuclear plant until 2013 and 2014, respectively. The recovery was effective Jan. 1, 2003, and the net effect on depreciation and amortization, partially offset by revisions to nuclear decommissioning accrual, was a $22 million decrease in depreciation expense. In addition, effective July 1, 2003, the Colorado Public Utilities Commission (CPUC) lengthened the depreciable lives of certain electric utility plant at PSCo as a part of the general Colorado rate case, which will reduce annual depreciation expense by $20 million and reduced 2003 depreciation expense by approximately $10 million.

Special Charges Special charges reported in 2003 relate to the TRANSLink project and NRG restructuring costs. Special charges for 2002 include NRG restructuring costs, as discussed later, but are largely related to regulated utility costs as discussed in the following paragraph. All 2001 special charges relate to utility costs. See Note 2 to the Consolidated Financial Statements for further discussion of these items.

Regulated utility earnings from continuing operations were reduced by approximately 2 cents per share in 2002 due to a $5 million regulatory recovery adjustment for SPS and $9 million in employee separation costs associated with a restaffing initiative for utility and service company operations. Regulated utility earnings from continuing operations in 2001 were lower by 4 cents per share due to a Colorado Supreme Court decision that resulted in a pretax write-off of $23 million of a regulatory asset related to deferred post-employment benefit costs at PSCo. Also, regulated utility earnings from continuing operations were reduced by approximately 7 cents per share in 2001 due to $39 million of employee separation costs associated with a restaffing initiative late in the year for utility and service company operations.

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Interest and Other Income, Net of Nonoperating Expenses Interest and other income, net of nonoperating expenses decreased $9 million in 2003 compared with 2002. Interest income decreased $13 million in 2003 compared with 2002 primarily due to interest received on tax refunds in 2002. Other income decreased $11 million primarily due to a gain on the sale of contracts at Planergy in 2002. Partially offsetting these decreases was an increase in allowance for funds used during construction resulting from lower levels of short-term debt used to finance utility construction.

Interest and other income, net of nonoperating expenses increased $14 million from 2002 compared with 2001. Interest income increased by $8 million primarily due to interest received on tax refunds in 2002. Other income increased by $13 million, primarily due to a gain on the sale of contracts at Planergy in 2002. Partially offsetting these increases was a decrease in the gain on disposal of assets of $5 million due to a gain recorded in 2001 by PSCo.

Interest and Financing Costs Interest and financing costs increased approximately $30 million, or 7.1 percent, for 2003 compared with 2002. This increase was due to the full-year impact of the issuance of long-term debt in the latter part of 2002 intended to reduce dependence on short-term debt. In addition, during the fourth quarter of 2002, Xcel Energy incurred approximately $15 million to redeem temporary holding company debt. During 2003, Xcel Energy issued approximately $1.7 billion of long-term debt to refinance higher coupon debt. These actions are expected to reduce 2004 interest costs by approximately $15 million compared with 2003 levels.

Interest and financing costs increased $56 million, or 15.3 percent, in 2002 compared with 2001. During 2002, certain long-term debt was refinanced at higher interest rates. Additionally, certain redemption costs were incurred, as noted previously.

Income Tax Expense Income tax expense decreased by approximately $77 million in 2003, compared with a decrease of $69 million in 2002. The effective tax rate for 2003 was 23.7 percent, compared with 30.9 percent in 2002. The decrease in the effective rate in 2003 was due largely to approximately $36 million of tax adjustments recorded mainly in the fourth quarter of 2003 to reflect the successful resolution of various outstanding tax issues related to prior years. The tax issues resolved during 2003 included the tax deductibility of certain merger costs associated with the merger to form Xcel Energy and NCE and the deductibility, for state purposes, of certain tax benefit transfer lease benefits. Tax expense also decreased in 2003 due to lower income levels in 2003. The decrease in 2002 was primarily due to increased tax credits and lower pretax income in 2002. See Note 10 to the Consolidated Financial Statements.

Other Nonregulated Subsidiaries and Holding Company Results

The following tables summarize the net income and earnings per share contributions of the continuing operations of Xcel Energy’s nonregulated businesses and holding company results:

                         
    Contribution to Xcel Energy’s
(Millions of dollars)
  earnings
    2003
  2002
  2001
Eloigne Company
  $ 7.7     $ 8.0     $ 8.7  
Seren Innovations
    (18.4 )     (27.0 )     (26.8 )
Planergy
    (7.7 )     (1.7 )     (12.0 )
Financing costs — holding company
    (44.1 )     (47.4 )     (34.0 )
Special charges — holding company
    (11.2 )     (2.9 )      
Other nonregulated and holding company results
    19.7       2.5       5.8  
 
   
 
     
 
     
 
 
Total nonregulated/holding company earnings (loss) — continuing operations
  $ (54.0 )   $ (68.5 )   $ (58.3 )
 
   
 
     
 
     
 
 
                         
    Contribution to Xcel Energy’s
    earnings per share
    2003
  2002
  2001
Eloigne Company
  $ 0.02     $ 0.02     $ 0.03  
Seren Innovations
    (0.04 )     (0.07 )     (0.08 )
Planergy
    (0.02 )           (0.04 )
Financing costs and preferred dividends — holding company
    (0.09 )     (0.13 )     (0.11 )
Special charges — holding company
    (0.03 )     (0.01 )      
Other nonregulated and holding company results
    0.04       0.01       0.02  
 
   
 
     
 
     
 
 
Total nonregulated/holding company earnings (loss) per share — continuing operations
  $ (0.12 )   $ (0.18 )   $ (0.18 )
 
   
 
     
 
     
 
 

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Eloigne Company — Eloigne invests in affordable housing that qualifies for Internal Revenue Service tax credits. Eloigne’s earnings contribution declined slightly in 2003 and 2002 as tax credits on mature affordable housing projects began to decline.

Seren Innovations — Seren operates a combination cable television, telephone and high-speed Internet access system in St. Cloud, Minn., and Contra Costa County, Calif. 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.

Planergy Planergy provides energy management services. Planergy’s losses were lower in 2002 largely due to pretax gains of approximately $8 million from the sale of a portfolio of energy management contracts, which reduced losses by approximately 2 cents per share.

Financing Costs and Preferred Dividends — Nonregulated results include interest expense and the earnings-per-share impact of preferred dividends, which are incurred at the Xcel Energy and intermediate holding company levels, and are not directly assigned to individual subsidiaries.

In November 2002, the Xcel Energy holding company issued temporary financing, which included detachable options for the purchase of Xcel Energy notes, which are convertible to Xcel Energy common stock. This temporary financing was replaced with long-term holding company financing in late November 2002. Costs incurred to redeem the temporary financing included a redemption premium of $7.4 million, $5.2 million of debt discount associated with the detachable option, and other issuance costs, which increased financing costs and reduced 2002 earnings by 2 cents per share.

Financing costs and preferred dividends per share for 2003 included above reflect the impact of dilutive securities, as discussed further in Note 11 to the Consolidated Financial Statements. The impact of the dilutive securities, if converted, is a reduction of interest expense of approximately $11 million, or 3 cents per share.

Holding Company Special Charges — During 2002, NRG experienced credit-rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity. These events ultimately led to the restructuring of NRG in late 2002 and its bankruptcy filing in May 2003. See Note 4 to the Consolidated Financial Statements. Certain costs related to NRG’s restructuring were incurred at the holding company level and included in continuing operations and reported as Special Charges. Approximately $12 million of these costs were incurred in 2003 and $5 million were incurred in 2002, which reduced after-tax earnings by approximately 2 cents per share and 1 cent per share, respectively. Costs in 2003 included approximately $32 million of financial advisor fees, legal costs and consulting costs related to the NRG bankruptcy transaction. These charges were partially offset by a $20 million pension curtailment gain related to the termination of NRG employees from Xcel Energy’s pension plan. In 2003, Xcel Energy also recorded a $7 million charge in connection with the suspension of the formation of the independent transmission company TRANSLink Transmission Co., LLC (TRANSLink). See Note 2 to the Consolidated Financial Statements for further discussion of these special charges.

Other Nonregulated In 2003, Utility Engineering sold water rights, resulting in a pretax gain (reported as nonoperating income) of $15 million. The gain increased after-tax income by approximately 2 cents per share.

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Statement of Operations Analysis — Discontinued Operations

A summary of the various components of discontinued operations is as follows for the years ended Dec. 31:

                         
Income (loss) in millions
  2003
  2002
  2001
Viking Gas Transmission Co.
  $ 21.9     $ 9.4     $ 5.0  
Black Mountain Gas
    2.4       1.0       1.0  
 
   
 
     
 
     
 
 
Regulated natural gas utility segment — income
    24.3       10.4       6.0  
 
NRG segment — income (loss)
    (251.4 )     (3,444.1 )     195.1  
 
Xcel Energy International
    (45.5 )     (17.1 )     (2.9 )
e prime
    (17.8 )     1.5       8.0  
Other
    (1.6 )     (2.4 )     (2.3 )
NRG-related tax benefits
    404.4       706.0        
 
   
 
     
 
     
 
 
Nonregulated/other — income
    339.5       688.0       2.8  
 
   
 
     
 
     
 
 
Total income (loss) from discontinued operations.
  $ 112.4     $ (2,745.7 )   $ 203.9  
 
   
 
     
 
     
 
 
Earnings (loss) per share
                       
Viking Gas Transmission Co.
  $ 0.05     $ 0.03     $ 0.02  
Black Mountain Gas
    0.01              
 
   
 
     
 
     
 
 
Regulated natural gas utility segment - income per share
    0.06       0.03       0.02  
 
NRG segment — income (loss) per share
    (0.60 )     (8.95 )     0.56  
 
Xcel Energy International
    (0.11 )     (0.05 )     (0.01 )
e prime
    (0.04 )           0.02  
NRG-related tax benefits
    0.96       1.83        
 
   
 
     
 
     
 
 
Nonregulated/other — income per share
    0.81       1.78       0.01  
 
   
 
     
 
     
 
 
Total income (loss) per share from discontinued operations
  $ 0.27     $ (7.14 )   $ 0.59  
 
   
 
     
 
     
 
 

Regulated Natural Gas Utility Results — Discontinued Operations

During 2003, Xcel Energy completed the sale of two subsidiaries in its regulated natural gas utility segment: Viking, including its interest in Guardian Pipeline, LLC, and BMG. After-tax disposal gains of $23.3 million, or 6 cents per share, were recorded for the natural gas utility segment, primarily related to the sale of Viking.

Viking had minimal income in 2003, as it was sold in January of that year. Income from Viking was higher in 2002 compared with 2001 primarily due to increased revenues.

NRG Results — Discontinued Operations

Due to NRG’s emergence from bankruptcy in December 2003 and Xcel Energy’s corresponding divestiture of its ownership interest in NRG, Xcel Energy’s share of NRG results for current and prior periods is now shown as a component of discontinued operations.

2003 NRG Results Compared with 2002 As a result of NRG’s bankruptcy filing in May 2003, Xcel Energy ceased the consolidation of NRG and began accounting for its investment in NRG using the equity method in accordance with Accounting Principles Board Opinion No. 18 — “The Equity Method of Accounting for Investments in Common Stock.” After changing to the equity method, Xcel Energy was limited in the amount of NRG’s losses subsequent to the bankruptcy date that it was required to record. In accordance with these limitations under the equity method, Xcel Energy stopped recognizing equity in the losses of NRG subsequent to the quarter ended June 30, 2003. These limitations provided for loss recognition by Xcel Energy until its investment in NRG was written off to zero, with further loss recognition to continue if its financial commitments to NRG exist beyond amounts already invested. Xcel Energy initially recorded more losses than the limitations allow as of June 30, 2003, but upon Xcel Energy’s divestiture of its interest in NRG, the NRG losses recorded in excess of Xcel Energy’s investment in and financial commitment to NRG were reversed in the fourth quarter of 2003. This resulted in a noncash gain of $111 million, or 26 cents per share, for the quarter and an adjustment of the total NRG losses recorded for the year 2003 to $251 million, or 60 cents per share.

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NRG’s results included in Xcel Energy’s earnings for 2003 were as follows:

         
    Six months ended
(Millions of dollars)
  June 30, 2003
Total NRG loss
  $ (621 )
Losses not recorded by Xcel Energy under the equity method*
    370  
 
   
 
 
Equity in losses of NRG included in Xcel Energy results for 2003
  $ (251 )
 
   
 
 

*   These represent NRG losses incurred in the first and second quarters of 2003 that were in excess of the amounts recordable by Xcel Energy under the equity method of accounting limitations discussed previously.

Following its credit downgrade in July 2002, NRG experienced credit and liquidity constraints and commenced a financial and business restructuring, including a voluntary petition for bankruptcy protection. This restructuring created significant incremental costs and resulted in numerous asset impairments as the strategic and economic value of assets under development and in operation changed.

NRG’s asset impairments and related charges in 2003 include approximately $40 million in first-quarter charges related to NRG’s NEO landfill gas projects and equity investments, and approximately $500 million was recorded in the second quarter. The impairment and related charges in the second quarter of 2003 resulted from planned disposals of the Loy Yang project in Australia and the McClain and Brazos Valley projects in the United States, and regulatory developments and changing circumstances throughout the second quarter that adversely affected NRG’s ability to recover the carrying value of certain Connecticut merchant generation units. As of the bankruptcy filing date (May 14, 2003), Xcel Energy had recognized $263 million of NRG’s impairments and related charges for the Connecticut facilities and Brazos Valley as these charges were recorded by NRG prior to May 14, 2003. Consequently, Xcel Energy recorded its equity in NRG results for the second quarter (including these impairments) in excess of its financial commitment to NRG under the settlement agreement reached in March 2003 among Xcel Energy, NRG and NRG’s creditors. These excess losses were reversed upon NRG’s emergence from bankruptcy in December 2003, as discussed previously.

In 2003, NRG’s operating results (excluding the unusual items discussed above) were affected by higher market prices due to higher natural gas prices and an increase in capacity revenues due to additional projects becoming operational in the later part of 2002. In addition, the sale of an NRG investment in 2002 resulted in a favorable impact in 2003 as the investment generated substantial equity losses in the prior years. The increase was offset by losses incurred on contracts in Connecticut due to increased market prices, increased operating expenses, contract terminations and liquidated damages triggered by NRG’s financial condition and additional restructuring charges.

During 2002, the tax filing status of NRG for 2002 and future years changed from being included as part of Xcel Energy’s consolidated federal income tax group to filing on a stand-alone basis. On a stand-alone basis, NRG did not have the ability to recognize all tax benefits that may ultimately accrue from its 2003 operating losses and is currently in a net operating loss carry forward position for tax purposes. Accordingly, NRG’s results for 2003 include no material tax effects.

2002 NRG Results Compared with 2001 NRG losses in 2002 were $3.4 billion, or $8.95 per share, due primarily to asset impairment charges and estimated disposal losses of more than $3 billion and other charges recorded in the third and fourth quarters of 2002 related to NRG’s financial restructuring. Also, NRG recorded other incremental costs related to its financial restructuring and business realignment.

During 2002, NRG’s operations, excluding impacts of asset impairments and disposals and restructuring costs, experienced significant losses compared with 2001. The 2002 losses are primarily attributable to NRG’s North American operations, which experienced significant reductions in domestic energy and capacity sales and an overall decrease in power pool prices and related spark spreads. In addition, increased administrative costs, depreciation and interest expense from completed construction contributed to the less-than-favorable results for NRG in 2002.

As discussed previously, on a stand-alone basis, NRG did not have the ability to recognize all tax benefits that may ultimately accrue from its losses incurred in 2002, thus increasing the overall loss from continuing operations. In addition to losing the ability to recognize all tax benefits for operating losses, NRG in 2002 also lost the ability to utilize tax credits generated by its energy projects. These lower tax credits account for a portion of the decreased earnings contribution of NRG compared with results in 2001, which included income related to recognition of tax credits.

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See Notes 3 and 4 to the Consolidated Financial Statements for further discussion of the 2003 change in accounting for NRG, Xcel Energy’s limitation for recognizing NRG’s losses due to its bankruptcy filing and further discussion of NRG’s results included in discontinued operations, including asset impairment charges.

Other Nonregulated Results — Discontinued Operations

During 2003, the board of directors of Xcel Energy approved management’s plan to exit the businesses conducted by its nonregulated subsidiaries, Xcel Energy International and e prime. Xcel Energy is in the process of marketing the assets and operations of these businesses to prospective buyers and expects to exit the businesses during 2004.

2003 Nonregulated Results Compared with 2002 — Results of discontinued nonregulated operations, other than NRG, include an after-tax loss of $59 million, or 14 cents per share, expected on the disposal of Xcel Energy International’s assets, based on the estimated fair value of such assets. Xcel Energy’s remaining investment in Xcel Energy International at Dec. 31, 2003, was approximately $39 million. These losses from discontinued nonregulated operations also include a charge of $16 million for costs of settling a Commodity Futures Trading Commission trading investigation of e prime.

2002 Nonregulated Results Compared with 2001 Nonregulated and holding company earnings for 2002 were reduced by impairment losses recorded by Xcel Energy International for Argentina assets and disposal losses for Yorkshire Power. In 2002, Xcel Energy International decided it would no longer fund one of its power projects in Argentina. This decision resulted in the shutdown of the Argentina plant facility, pending financing of a necessary maintenance outage. Updated cash flow projections for the plant were insufficient to provide recovery of Xcel Energy International’s investment. The write-down for this Argentina facility was approximately $13 million, or 3 cents per share.

In August 2002, Xcel Energy announced it had sold Xcel Energy International’s 5.25-percent interest in Yorkshire Power Group Limited for $33 million to CE Electric UK. Xcel Energy International and American Electric Power Co. each held a 50-percent interest in Yorkshire, a UK retail electricity and natural gas supplier and electricity distributor, before selling 94.75 percent of Yorkshire to Innogy Holdings plc in April 2001. The sale of the 5.25-percent interest resulted in an after-tax loss of $8.3 million, or 2 cents per share, in the third quarter of 2002.

Tax Benefits Related to Investment in NRG — With NRG’s emergence from bankruptcy in December 2003, Xcel Energy has divested its ownership interest in NRG and plans to take a loss deduction in 2003. These benefits, since related to Xcel Energy’s investment in discontinued NRG operations, are also reported as discontinued operations. During 2002, Xcel Energy recognized an initial estimate of the expected tax benefits of $706 million. This benefit was based on the estimated tax basis of Xcel Energy’s cash and stock investments already made in NRG, and their deductibility for federal income tax purposes.

Based on the results of a 2003 study, Xcel Energy recorded $105 million of additional tax benefits in the third quarter of 2003, reflecting an updated estimate of the tax basis of Xcel Energy’s investments in NRG and state tax deductibility. Upon NRG’s emergence from bankruptcy, an additional $288 million of tax benefit was recorded in the fourth quarter of 2003 to reflect the deductibility of expected settlement payments of $752 million, uncollectible receivables from NRG, other state tax benefits and further adjustments to the estimated tax basis in NRG. Another $11 million of state tax benefits were accrued earlier in 2003 based on projected impacts.

Based on current forecasts of taxable income and tax liabilities, Xcel Energy expects to realize approximately $1.1 billion of cash savings from these tax benefits through a refund of taxes paid in prior years and reduced taxes payable in future years. Xcel Energy used $130 million of these tax benefits in 2003 and expects to use $480 million in 2004. The remainder of the tax benefit carry forward is expected to be used over subsequent years.

Extraordinary Item — Electric Utility Restructuring

In 2001, SPS recorded extraordinary income of $18 million before tax, or 3 cents per share, related to the regulated utility business to reflect the impacts of industry restructuring developments for SPS. This represented a reversal of a portion of an extraordinary loss recorded in 2000 related to industry restructuring. For more information on this 2001 extraordinary item, see Note 14 to the Consolidated Financial Statements.

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Factors Affecting Results of Continuing Operations

Xcel Energy’s utility revenues depend on customer usage, which varies with weather conditions, general business conditions and the cost of energy services. Various regulatory agencies approve the prices for electric and natural gas service within their respective jurisdictions and affect our ability to recover our costs from customers. In addition, Xcel Energy’s nonregulated businesses have had an adverse impact on Xcel Energy’s earnings in 2003 and 2002. The historical and future trends of Xcel Energy’s operating results have been, and are expected to be, affected by a number of factors, including the following:

General Economic Conditions

Economic conditions may have a material impact on Xcel Energy’s operating results. The United States economy is showing recent signs of recovery as measured by growth in the gross domestic product. However, certain operating costs, such as insurance and security, have increased due to economic uncertainty, terrorist activity and war or the threat of war. Management cannot predict the impact of a future economic slowdown, fluctuating energy prices, war or the threat of war. However, Xcel Energy could experience a material adverse impact to its results of operations, future growth or ability to raise capital from a stalled economic recovery.

Sales Growth

In addition to the impact of weather, customer sales levels in Xcel Energy’s regulated utility businesses can vary with economic conditions, customer usage patterns and other factors. Weather-normalized sales growth for retail electric utility customers was estimated to be 1.5 percent in 2003 compared with 2002, and 1.8 percent in 2002 compared with 2001. Weather-normalized sales growth for firm gas utility customers was estimated to be approximately 1.6 percent in 2003 compared with 2002, and relatively flat in 2002 compared with 2001. Projections indicate that weather-normalized sales growth in 2004 compared with 2003 will be approximately 2.2 percent for retail electric utility customers and 2.4 percent for firm gas utility customers.

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 has 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 utilities were required to provide nondiscriminatory access to the use of their transmission systems in 1996. 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, established new standards of conduct rules for transmission providers and new code of conduct rules for utilities with market-based 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.

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.

Pension Plan Costs and Assumptions

Xcel Energy’s pension costs are based on an actuarial calculation that includes a number of key assumptions, most notably the annual return level that pension investment assets will earn in the future and the interest rate used to discount future pension benefit payments to a present value obligation for financial reporting. In addition, the actuarial calculation uses an asset-smoothing methodology to reduce the volatility of varying investment performance over time. Note 12 to the Consolidated Financial Statements discusses the rate of return and discount rate used in the calculation of pension costs and obligations in the accompanying financial statements.

Pension costs have been increasing in recent years, and are expected to increase further over the next several years, due to lower-than-expected investment returns experienced in 2000, 2001 and 2002 and decreases in interest rates used to discount benefit obligations. While investment returns exceeded the assumed level of 9.25 percent in 2003, investment returns in 2001 and 2002 were below the assumed level of 9.5 percent and discount rates have declined from the 7.25-percent to 8-percent levels used in 1999 through 2002 cost determinations to 6.75 percent used in 2003. Xcel Energy continually reviews its pension assumptions and, in 2004, expects to change the investment return assumption to 9.0 percent and the discount rate assumption to 6.25 percent.

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The investment gains or losses resulting from the difference between the expected pension returns assumed on smoothed or “market-related” asset levels and actual returns earned is deferred in the year the difference arises and recognized over the subsequent five-year period. This gain or loss recognition occurs by using a five-year, moving-average value of pension assets to measure expected asset returns in the cost determination process, and by amortizing deferred investment gains or losses over the subsequent five-year period. Based on the use of average market-related asset values, and considering the expected recognition of past investment gains and losses over the next five years, achieving the assumed rate of asset return of 9.0 percent in each future year and holding other assumptions constant, Xcel Energy currently projects that the pension costs recognized for financial reporting purposes in continuing operations will increase from a credit, or negative expense, of $51 million in 2003 to a credit of $25 million in 2004 and zero in 2005. Pension costs are currently a credit due to the recognized investment asset returns exceeding the other pension cost components, such as benefits earned for current service and interest costs for the effects of the passage of time on discounted obligations.

Xcel Energy bases its discount rate assumption on benchmark interest rates quoted by an established credit rating agency, Moody’s Investors Service (Moody’s), and has consistently benchmarked the interest rate used to derive the discount rate to the movements in the long-term corporate bond indices for bonds rated Aaa through Baa by Moody’s, which have a period to maturity comparable to our projected benefit obligations. At Dec. 31, 2003, the annualized Moody’s Aa index rate, roughly in the middle of the Aaa and Baa range, declined by about 0.5 percent from the prior year end, which resulted in a corresponding decrease from 6.75 percent at year-end 2002 to a 6.25-percent pension discount rate at year-end 2003. This rate was used to value the actuarial benefit obligations at that date, and will be used in 2004 pension cost determinations.

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

  a 100 basis point higher rate of return, 10.0 percent, would decrease 2004 pension costs by $18.4 million;
 
  a 100 basis point lower rate of return, 8.0 percent, would increase 2004 pension costs by $18.4 million;
 
  a 100 basis point higher discount rate, 7.25 percent, would decrease 2004 pension costs by $9.5 million; and
 
  a 100 basis point lower discount rate, 5.25 percent, would increase 2004 pension costs by $8.8 million.

Alternative Employee Retirement Income Security Act of 1974 (ERISA) funding assumptions would also change the expected future cash funding requirements for the pension plans. Cash funding requirements can be affected by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding in recent years for Xcel Energy’s pension plans, and do not require funding in 2004. Assuming that future asset return levels equal the actuarial assumption of 9.0 percent for the years 2004 and 2005, Xcel Energy projects, under current funding regulations, that cash funding would be required in the amount of approximately $0 million for 2005 and $15 million for 2006. Actual performance can affect these funding requirements significantly. Current funding regulations were under legislative review in 2004 and, if not retained in their current form, could change these funding requirements materially. To begin meeting these projected funding requirements, PSCo elected to make a voluntary contribution of $30 million to its pension plan for bargaining employees in 2003, and it plans to voluntarily contribute another $10 million to the plan in 2004.

Regulation

Xcel Energy, its utility subsidiaries and certain of its nonutility subsidiaries are subject to extensive regulation by the SEC under the PUHCA with respect to issuances and sales of securities, acquisitions and sales of certain utility properties and intra-system sales of certain goods and services. In addition, the PUHCA generally limits the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company. See further discussion of financing restrictions under Liquidity and Capital Resources.

Xcel Energy’s utility subsidiaries also are regulated by the FERC and state regulatory commissions. Decisions by these regulators can significantly impact Xcel Energy’s results of operations. Xcel Energy expects to periodically file for rate changes based on changing energy market and general economic conditions.

The electric and natural gas rates charged to customers of Xcel Energy’s utility subsidiaries are approved by the FERC and the regulatory commissions in the states in which they operate. The rates are generally designed to recover plant investment, operating costs and an allowed return on investment. Xcel Energy requests changes in rates for utility services through filings with the governing commissions. Because comprehensive rate changes are requested infrequently in some states, changes in operating costs can affect Xcel Energy’s financial results. In addition to changes in operating costs, other factors affecting rate filings are sales growth, conservation and demand-side management efforts and the cost of capital.

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Most of the retail rates for Xcel Energy’s utility subsidiaries provide for periodic adjustments to billings and revenues to allow for recovery of changes in the cost of fuel for electric generation, purchased energy, purchased natural gas and, in Minnesota and Colorado, conservation and energy-management program costs. In Minnesota and Colorado, changes in purchased electric capacity costs are not recovered through these rate-adjustment mechanisms. For Wisconsin electric operations, where automatic cost-of-energy adjustment clauses are not allowed, the biennial retail rate review process and an interim fuel-cost hearing process provide the opportunity for rate recovery of changes in electric fuel and purchased energy costs in lieu of a cost-of-energy adjustment clause. In Colorado, PSCo has an interim adjustment clause that allows for recovery of all prudently incurred electric fuel and purchased energy expenses in 2003. In 2004, PSCo generally is expected to recover all prudently incurred electric fuel and purchased energy costs through an electric commodity adjustment clause. Additionally, this fuel mechanism also has in place a sharing among customers and shareholders of certain fuel and energy costs, with an $11.25 million maximum on any cost sharing over or under an allowed electric commodity adjustment formula rate, and a sharing among shareholders and customers of certain gains and losses on trading margins.

Xcel Energy’s utility subsidiaries make substantial investments in plant additions to build and upgrade power plants, and expand and maintain the reliability of the energy distribution system. In addition to filing for increases in base rates charged to customers to recover the costs associated with such investments, in 2003 approval was obtained from Colorado and Minnesota regulators to recover, through a rate surcharge, certain costs to upgrade plants and lower emissions in the Denver and Minneapolis-St. Paul metropolitan areas. These rate recovery mechanisms are expected to provide significant cash flows to enable recovery of costs incurred on a timely basis.

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

At Dec. 31, 2003, Xcel Energy reported on its balance sheet regulatory assets of approximately $572 million and regulatory liabilities of approximately $1.2 billion that would be recognized in the statement of operations in the absence of regulation. In addition to a potential write-off of regulatory assets and liabilities, restructuring and competition may require recognition of certain stranded costs not recoverable under market pricing. See Notes 1 and 19 to the Consolidated Financial Statements for further discussion of regulatory deferrals.

PSCo 2002 General Rate Case In May 2002, PSCo filed a combined general retail electric, natural gas and thermal energy base rate case with the CPUC as required in the merger approval agreement with the CPUC to form Xcel Energy. On April 4, 2003, a comprehensive settlement agreement was reached, which addressed all significant issues in the rate case. In mid-2003, the CPUC approved the final settlement, which provided for:

    a decrease in annual base rates of approximately $33 million for natural gas and $230,000 for electricity, including an annual reduction to electric depreciation expense of approximately $20 million, effective July 1, 2003;
 
    an interim adjustment clause (IAC) that fully recovers prudently incurred 2003 electric fuel and purchased energy expense above the expense recovered through electric base rates during 2003;
 
    a new electric commodity adjustment clause (ECA) for 2004-2006, with an $11.25-million cap on any cost sharing over or under an allowed ECA formula rate; and
 
    an authorized return on equity of 10.75 percent for electric operations and 11.0 percent for natural gas and thermal energy operations.

PSCo Performance-Based Regulatory Plan (PBRP) The CPUC established an electric PBRP under which PSCo operates. The major components of this regulatory plan include:

  an annual electric earnings test with the sharing between customers and shareholders of earnings in excess of the following limits:

    all earnings above an 11-percent return on equity for 2001 and a 10.50-percent return on equity for 2002;
 
    no earnings sharing for 2003 as PSCo established new rates in its general rate case; and
 
    an annual electric earnings test with the sharing of earnings in excess of the return on equity for electric operations of 10.75 percent for 2004 through 2006;

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  an electric quality of service plan (QSP) that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to electric reliability and customer service through 2006; and
 
  a natural gas QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to natural gas leak repair time and customer service through 2007.

PSCo regularly monitors and records as necessary an estimated customer refund obligation under the PBRP. In April of each year following the measurement period, PSCo files its proposed rate adjustment under the PBRP. The CPUC conducts proceedings to review and approve these rate adjustments annually.

    In 2001, PSCo did not earn a return on equity in excess of 11 percent and met the electric and gas QSP benchmarks. The CPUC has accepted the QSP components of the PBRP filing and approved the earnings test.
 
    In 2002, PSCo did not earn a return on equity in excess of 10.5 percent, so no refund liability has been recorded. Both electric and gas QSP benchmarks were met. Therefore, no liability has been recorded for the earnings test. A CPUC decision is pending. The CPUC is considering whether PSCo’s cost of debt has been adversely affected by the financial difficulties of NRG, and if so, whether any adjustments to PSCo’s cost of capital should be made. A hearing has been set for August 2004.
 
    The 2003 QSP results will be filed in April 2004. An estimate of customer refund obligations under the electric QSP plan was recorded in 2003 relating to the electric service unavailability and customer complaint measures. No refund under the gas QSP is anticipated.

In 2003, PSCo filed an application to put into effect a purchased-capacity cost-adjustment mechanism that would allow it to recover 100 percent of its incremental purchased-capacity costs over the level of these costs in rates. As a part of this application, PSCo proposed to modify the PBRP for 2004 through 2006 to provide that 100 percent of any earnings in excess of a 10.75-percent return on equity for electric operations be returned to customers. The application is pending approval of the CPUC.

Tax Matters

The Internal Revenue Service (IRS) issued a notice of proposed adjustment proposing to disallow interest expense deductions taken in tax years 1993 through 1997 related to corporate-owned life insurance (COLI) policy loans of PSR Investments, Inc. (PSRI), a wholly owned subsidiary of PSCo. Late in 2001, Xcel Energy received a technical advice memorandum from the IRS national office, which communicated a position adverse to PSRI. Consequently, the IRS examination division has disallowed the interest expense deductions for the tax years 1993 through 1997. Xcel Energy plans to challenge the IRS determination, which could require several years to reach final resolution. Because it is Xcel Energy’s position that the IRS determination is not supported by tax law, Xcel Energy has not recorded any provision for income tax or interest expense related to this matter and continues to take deductions for interest expense related to policy loans on its income tax returns for subsequent years. However, defense of PSCo’s position may require significant cash outlays on a temporary basis if refund litigation is pursued in United States District Court.

The total disallowance of interest expense deductions for the period 1993 through 1997 is approximately $175 million. Additional interest expense deductions for the period 1998 through 2003 are estimated to total approximately $404 million. Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2003, would reduce earnings by an estimated $254 million, after tax. If COLI interest expense deductions were no longer available, annual earnings for 2004 would be reduced by an estimated $36 million, after tax, prospectively, which represents 9 cents per share using 2003 share levels.

Environmental Matters

Environmental costs include payments for nuclear plant decommissioning, storage and ultimate disposal of spent nuclear fuel, disposal of hazardous materials and wastes, remediation of contaminated sites and monitoring of discharges to the environment. A trend of greater environmental awareness and increasingly stringent regulation has caused, and may continue to cause, slightly higher operating expenses and capital expenditures for environmental compliance.

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In addition to nuclear decommissioning and spent nuclear fuel disposal expenses, costs charged to operating expenses for environmental monitoring and disposal of hazardous materials and wastes were approximately:

  $133 million in 2003;
 
  $138 million in 2002; and
 
  $130 million in 2001.

Xcel Energy expects to expense an average of approximately $155 million per year from 2004 through 2008 for similar costs. However, the precise timing and amount of environmental costs, including those for site remediation and disposal of hazardous materials, are currently unknown. Additionally, the extent to which environmental costs will be included in and recovered through rates is not certain.

Capital expenditures on environmental improvements at regulated facilities were approximately:

  $58.5 million in 2003;
 
  $107.8 million in 2002; and
 
  $135.7 million in 2001.

The regulated utilities expect to incur approximately $83.0 million in capital expenditures for compliance with environmental regulations in 2004 and approximately $1.1 billion for environmental improvements during the period from 2004 through 2008. Approximately $43 million and $988 million of these expenditures, respectively, are related to modifications to reduce the emissions of NSP-Minnesota’s generating plants located in the Minneapolis-St. Paul metropolitan area pursuant to the metropolitan emissions reduction project (MERP), which are recoverable from customers through cost recovery mechanisms. See Notes 17 and 18 to the Consolidated Financial Statements for further discussion of our environmental contingencies.

Impact of Nonregulated Investments

Xcel Energy’s investments in nonregulated operations have had a significant impact on its results of operations. As a result of the divestiture of NRG, Xcel Energy does not expect that its investments in nonregulated operations will continue to have such a significant impact on its results. Xcel Energy does not expect to make any material investments in nonregulated projects. Xcel Energy’s remaining nonregulated businesses may carry a higher level of risk than its traditional utility businesses.

Xcel Energy’s earnings from nonregulated subsidiaries include investments in broadband communications systems through Seren. Management currently intends to hold and operate the Seren broadband communications system investments. 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.

Xcel Energy has also invested in international projects, primarily in Argentina, through Xcel Energy International, but has designated Xcel Energy International as held for sale as of Dec. 31, 2003. An estimated after-tax loss from disposal of Xcel Argentina assets of $59 million has been recorded, but may change as the final impacts of the divestiture become known in 2004.

Inflation

Inflation at its current level is not expected to materially affect Xcel Energy’s prices or returns to shareholders.

Critical Accounting Policies and Estimates

Preparation of the Consolidated Financial Statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the Consolidated Financial Statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment also may have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the Consolidated

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Financial Statements and related disclosures, even if the nature of the accounting policies applied have not changed. The following is a list of accounting policies that are most significant to the portrayal of Xcel Energy’s financial condition and results, and that require management’s most difficult, subjective or complex judgments. Each of these has a higher potential likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been discussed with the audit committee of the Xcel Energy board of directors. Xcel Energy no longer considers NRG’s financial restructuring a critical accounting policy due to the divestiture resulting from NRG’s emergence from bankruptcy.

                 
Accounting Policy
  Judgments/Uncertainties Affecting Application
  See Additional Discussion At
Regulatory Mechanisms
    External regulatory decisions,   Management’s Discussion and Analysis:
and Cost Recovery
      requirements and regulatory environment   Factors Affecting Results of Continuing Operations
    Anticipated future regulatory decisions     Utility Industry Changes
      and their impact     Regulation
    Impact of deregulation and competition        
      on ratemaking process and ability to   Notes to Consolidated Financial Statements
      recover costs     Notes 1, 17 and 19
 
               
Nuclear Plant
    Costs of future decommissioning   Notes to Consolidated Financial Statements
Decommissioning and
    Availability of facilities for waste     Notes 1, 17 and 18
Cost Recovery
      disposal        
    Approved methods for waste disposal        
    Useful lives of nuclear power plants        
    Future recovery of plant investment and        
      decommissioning costs        
 
               
Income Tax Accruals
    Application of tax statutes and   Management’s Discussion and Analysis:
      regulations to transactions   Factors Affecting Results of Continuing Operations
    Anticipated future decisions of tax     Tax Matters
      authorities        
    Ability of tax authority   Notes to Consolidated Financial Statements
      decisions/positions to withstand legal     Notes 1, 10 and 17
      challenges and appeals        
    Ability to realize tax benefits through        
      carrybacks to prior periods or carryovers        
      to future periods        
 
               
Benefit Plan Accounting
    Future rate of return on pension and other   Management’s Discussion and Analysis:
      plan assets, including impacts of any   Factors Affecting Results of Continuing Operations
      changes to investment portfolio     Pension Plan Costs and Assumptions
      composition        
    Discount rates used in valuing benefit   Notes to Consolidated Financial Statements
      obligation     Notes 1 and 12
    Actuarial period selected to recognize        
      deferred investment gains and losses        
 
               
Asset Valuation
    Regional economic conditions affecting   Management’s Discussion and Analysis:
      asset operation, market prices and   Results of Operations
      related cash flows     Statement of Operations Analysis — Discontinued
    Foreign currency valuations changes       Operations
    Regulatory and political environments and   Factors Affecting Results of Continuing Operations
      requirements     Impact of Nonregulated Investments
    Levels of future market penetration and        
      customer growth   Notes to Consolidated Financial Statements
            Note 3

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Xcel Energy continually makes informed judgments and estimates related to these critical accounting policy areas, based on an evaluation of the varying assumptions and uncertainties for each area. For example:

    probable outcomes of regulatory proceedings are assessed in cases of requested cost recovery or other approvals from regulators;
 
    the ability to operate plant facilities and recover the related costs over their useful operating lives, or such other period designated by our regulators, is assumed;
 
    probable outcomes of reviews and challenges raised by tax authorities, including appeals and litigation where necessary, are assessed;
 
    returns are projected regarding earnings on pension investments, and the salary increases provided to employees over their periods of service; and
 
    future cash inflows of operations are projected in order to assess whether they will be sufficient to recover future cash outflows, including the impacts of product price changes and market penetration to customer groups.

The information and assumptions underlying many of these judgments and estimates will be affected by events beyond the control of Xcel Energy, or otherwise change over time. This may require adjustments to recorded results to better reflect the events and updated information that becomes available. The accompanying financial statements reflect management’s best estimates and judgments of the impacts of these factors as of Dec. 31, 2003.

Recently Implemented Accounting Changes

For a discussion of accounting changes implemented in 2003 and other significant accounting policies, see Notes 1, 16 and 18 to the Consolidated Financial Statements.

Pending Accounting Changes

FASB Interpretation No. 46 (FIN No. 46) In January 2003, the Financial Accounting Standards Board (FASB) issued FIN No. 46, requiring an enterprise’s consolidated financial statements to include subsidiaries in which the enterprise has a controlling financial interest. Historically, consolidation has been required only for subsidiaries in which an enterprise has a majority voting interest. Under FIN No. 46, an enterprise’s consolidated financial statements will include the consolidation of variable interest entities, which are entities in which the enterprise has a controlling financial interest. As a result, Xcel Energy expects that it will be required to consolidate all or a portion of its affordable housing investments made through Eloigne, which currently are accounted for under the equity method. The Xcel Energy utility subsidiaries are party to purchased power agreements, and based on the current guidance, these contracts are not expected to be considered variable interest arrangements under the provisions of FIN No. 46. However, Xcel Energy is still evaluating the issue. Additionally, Xcel Energy is evaluating other arrangements based on criteria in FIN No. 46, and it is likely that some arrangements will require consolidation.

As of Dec. 31, 2003, the assets of the affordable housing investments were approximately $142 million and long-term liabilities were approximately $78 million. Currently, investments of $56 million are reflected as a component of investments in unconsolidated affiliates in the Dec. 31, 2003, Consolidated Balance Sheet. FIN No. 46 requires that for entities to be consolidated, the entities’ assets be initially recorded at their carrying amounts at the date the new requirement first applies. If determining carrying amounts as required is impractical, the assets are to be measured at fair value as of the first date the new requirements apply. Any difference between the net consolidated amounts added to Xcel Energy’s balance sheet and the amount of any previously recognized interest in the newly consolidated entity should be recognized in earnings as the cumulative-effect adjustment of an accounting change. Xcel Energy plans to adopt FIN No. 46 in the first quarter of 2004. The impact of consolidating these entities is not expected to have a material impact on net income.

DERIVATIVES, RISK MANAGEMENT AND MARKET RISK

Business and Operational Risk Xcel Energy and its subsidiaries, including discontinued operations held for sale, are exposed to commodity price risk in their generation, retail distribution and energy trading operations. In certain jurisdictions, purchased energy expenses and natural gas costs are recovered on a dollar-for-dollar basis. However, in other jurisdictions, Xcel Energy and its subsidiaries are exposed to market price risk for the purchase and sale of electric energy and natural gas. In such jurisdictions, electric energy and natural gas expenses are recovered based on fixed-price limits or under established sharing mechanisms.

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Xcel Energy manages commodity price risk by entering into purchase and sales commitments for electric power and natural gas, long-term contracts for coal supplies and fuel oil, and derivative instruments. Xcel Energy’s risk management policy allows the company to manage the market price risk within each rate-regulated operation to the extent such exposure exists. Management is limited under the policy to enter into only transactions that manage market price risk where the rate regulation jurisdiction does not already provide for dollar-for-dollar recovery. One exception to this policy exists in which Xcel Energy uses various physical contracts and derivative instruments to reduce the volatility in the cost of natural gas and electricity provided to retail customers even though the regulatory jurisdiction may provide dollar-for-dollar recovery of actual costs. In these instances, the use of derivative instruments and physical contracts is done consistently with the local jurisdictional cost-recovery mechanism.

Xcel Energy and its subsidiaries have been exposed to market price risk for the sale of electric energy and the purchase of fuel resources, including coal, natural gas and fuel oil used to generate the electric energy within its nonregulated operations, primarily through NRG and Xcel Energy International. With the divestiture of NRG and expected sale of Xcel Energy International, the exposure to market price risk has greatly diminished. Xcel Energy managed this market price risk by entering into firm power sales agreements for approximately 55 percent to 75 percent of its electric capacity and energy from each generation facility, using contracts with terms ranging from one to 25 years. In addition, Xcel Energy managed the market price risk covering the fuel resource requirements to provide the electric energy by entering into purchase commitments and derivative instruments for coal, natural gas and fuel oil as needed to meet fixed-priced electric energy requirements. Xcel Energy’s risk management policy allows for the management of market price risks, and provides guidelines for the level of price risk exposure that is acceptable within the company’s operations.

Interest Rate Risk Xcel Energy and its subsidiaries are subject to the risk of fluctuating interest rates in the normal course of business. Xcel Energy’s policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.

Xcel Energy engages in hedges of cash flow exposure and hedges of fair value exposure. The fair value of interest rate swaps designated as cash flow hedges are initially recorded in Other Comprehensive Income. Reclassification of unrealized gains or losses on cash flow hedges of variable rate debt instruments from Other Comprehensive Income into earnings occurs as interest payments are accrued on the debt instrument and generally offsets the change in the interest accrued on the underlying variable rate debt. Hedges of fair value exposure are entered into to hedge the fair value of a recognized asset, liability or firm commitment. Changes in the derivative fair values that are designated as fair value hedges are recognized in earnings as offsets to the changes in fair values of related hedged assets, liabilities or firm commitments. In order to test the effectiveness of such swaps, a hypothetical swap is used to mirror all the critical terms of the underlying debt and regression analysis is utilized to assess the effectiveness of the actual swap at inception and on an ongoing basis. The assessment is done periodically to ensure the swaps continue to be effective. The fair value of interest rate swaps is determined through counterparty valuations, internal valuations and broker quotes. There have been no material changes in the techniques or models used in the valuation of interest rate swaps during the periods presented.

At Dec. 31, 2003 and 2002, a 100-basis-point change in the benchmark rate on Xcel Energy’s variable debt would impact net income by approximately $0.8 million and $12.6 million, respectively. See Note 15 to the Consolidated Financial Statements for a discussion of Xcel Energy and its subsidiaries’ interest rate swaps.

Currency Exchange Risk During 2003 and 2002, NRG and Xcel Energy International, both of which are included in discontinued operations, held certain investments in foreign countries, creating exposure to foreign currency exchange risk. The foreign currency exchange risk included the risk relative to the recovery of the net investment in a project, as well as the risk relative to the earnings and cash flows generated from such operations. These subsidiaries managed their exposure to changes in foreign currency by entering into derivative instruments as determined by management. Xcel Energy’s risk management policy provides for this risk management activity.

Trading Risk Xcel Energy’s subsidiaries conduct various trading operations and power marketing activities, including the purchase and sale of electric capacity and energy and, prior to December 2003, through e prime for natural gas. The trading operations are conducted in the United States with primary focus on specific market regions where trading knowledge and experience have been obtained. Xcel Energy’s risk management policy allows management to conduct the trading activity within approved guidelines and limitations as approved by the company’s risk management committee, which is made up of management personnel not involved in the trading operations.

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The fair value of the energy trading contracts of continuing operations as of Dec. 31, 2003 was as follows:

         
(Millions of dollars)        
Fair value of trading contracts outstanding at Jan. 1, 2003
  $ (0.1 )
Contracts realized or settled during the year
    (14.4 )
Fair value of trading contract additions and changes during the year
    18.7  
 
   
 
 
Fair value of contracts outstanding at Dec. 31, 2003
  $ 4.2  
 
   
 
 

As of Dec. 31, 2003, the sources of fair value of the energy trading and hedging net assets were as follows:

Trading Contracts

                                                 
    Futures/Forwards
  Source of   Maturity Less   Maturity   Maturity   Maturity Greater   Total Futures/
(Thousands of dollars)
  Fair Value
  than 1 Year
  1 to 3 Years
  4 to 5 Years
  than 5 Years
  Forwards Fair Value
NSP-Minnesota
    1     $ (143 )   $     $     $     $ (143 )
 
    2       3,163       486                   3,649  
PSCo
    1       (69 )                       (69 )
 
    2       693       36                   729  
 
           
 
     
 
     
 
     
 
     
 
 
Total futures/forwards fair value
          $ 3,644     $ 522     $     $     $ 4,166  
 
           
 
     
 
     
 
     
 
     
 
 

Discontinued operations trading contracts are not included in the above table. The fair value of these contracts is approximately $(2.0) million, as of Dec. 31, 2003. All of these contracts have maturities of less than one year.

Hedge Contracts

                                                 
    Futures/Forwards
  Source of   Maturity Less   Maturity   Maturity   Maturity Greater   Total Futures/
(Thousands of dollars)
  Fair Value
  than 1 Year
  1 to 3 Years
  4 to 5 Years
  than 5 Years
  Forwards Fair Value
NSP-Minnesota futures/forwards fair value
    2     $ 569     $     $     $     $ 569  

Discontinued operations hedging contracts are not included in the above table. As of Dec. 31, 2003, the fair value of these contracts is approximately $1.5 million. All of these contracts have maturities of less than one year.

                                                 
    Options
  Source of   Maturity Less   Maturity   Maturity   Maturity Greater    
(Thousands of dollars)
  Fair Value
  than 1 Year
  1 to 3 Years
  4 to 5 Years
  than 5 Years
  Total Options Fair Value
NSP-Minnesota
    2     $ (1,287 )   $     $     $     $ (1,287 )
NSP-Wisconsin
    2       168                         168  
PSCo
    2       (11,466 )     848                   (10,618 )
             
 
     
 
     
 
     
 
     
 
 
Total options fair value
          $ (12,585 )   $ 848     $     $     $ (11,737 )
             
 
     
 
     
 
     
 
     
 
 

1 — Prices actively quoted or based on actively quoted prices.

2 — Prices based on models and other valuation methods. These represent the fair value of positions calculated using internal models when directly and indirectly quoted external prices or prices derived from external sources are not available. Internal models incorporate the use of options pricing and estimates of the present value of cash flows based upon underlying contractual terms. The models reflect management’s estimates, taking into account observable market prices, estimated market prices in the absence of quoted market prices, the risk-free market discount rate, volatility factors, estimated correlations of energy commodity prices and contractual volumes. Market price uncertainty and other risks also are factored into the model.

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In the above tables, only hedge transactions are included for NSP-Minnesota, NSP-Wisconsin and PSCo. Normal purchases and sales transactions, as defined by SFAS No. 133, have been excluded.

At Dec. 31, 2003, a 10-percent fluctuation in market prices over the next 12 months for trading contracts would impact pretax income from continuing operations by approximately $1 million. Hedge contracts are accounted for as a component of Other Comprehensive Income and would not directly impact earnings.

Xcel Energy’s trading operations and power marketing activities measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as Value-at-Risk (VaR). VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time, with a given confidence interval under normal market conditions. Xcel Energy utilizes the variance/covariance approach in calculating VaR. The VaR model employs a 95-percent confidence interval level based on historical price movement, lognormal price distribution assumption, delta half-gamma approach for non-linear instruments and various holding periods varying from two to five days.

As of Dec. 31, 2003, the calculated VaRs were:

                                 
            During 2003
    Year ended            
(Millions of dollars)
  Dec. 31, 2003
  Average
  High
  Low
Electric commodity trading (a)
  $ 0.92     $ 0.70     $ 1.51     $ 0.29  
Natural gas commodity trading (b)
  $ 0.00     $ 0.06     $ 0.89     $ 0.00  
Natural gas retail marketing (b)
  $ 0.08     $ 0.32     $ 1.00     $ 0.02  
Other
  $ 0.00     $ 0.02     $ 0.15     $ 0.00  

  (a)   Comprises transactions for both NSP-Minnesota and PSCo.
       
  (b)   Conducted by e prime, which is a discontinued operation held for sale.

     As of Dec. 31, 2002, the calculated VaRs were:

                                 
            During 2002
    Year ended            
(Millions of dollars)
  Dec. 31, 2002
  Average
  High
  Low
Electric commodity trading (a)
  $ 0.29     $ 0.62     $ 3.39     $ 0.01  
Natural gas commodity trading (c)
  $ 0.11     $ 0.35     $ 1.09     $ 0.09  
Natural gas retail marketing (c)
  $ 0.54     $ 0.47     $ 0.92     $ 0.32  
NRG power marketing (b)
  $ 118.60     $ 76.20     $ 124.40     $ 42.00  

(a)   Comprises transactions for both NSP-Minnesota and PSCo.
 
(b)   NRG VaR was an undiversified VaR. NRG is presented as discontinued operations.
 
(c)   Conducted by e prime, which is a discontinued operation held for sale.

Credit Risk In addition to the risks discussed previously, Xcel Energy and its subsidiaries are exposed to credit risk in the company’s risk management activities. Credit risk relates to the risk of loss resulting from the nonperformance by a counterparty of its contractual obligations. Xcel Energy and its subsidiaries maintain credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.

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

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At Dec. 31, 2003, a 10 percent increase in prices would have resulted in a net mark-to-market increase in credit risk exposure of $3.6 million, while a decrease of 10 percent would have resulted in a decrease of $3.9 million.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

                         
(Millions of dollars)
  2003
  2002
  2001
Cash provided by operating activities:
                       
Continuing operations
  $ 1,135     $ 1,300     $ 1,388  
Discontinued operations
    243       415       196  
 
   
 
     
 
     
 
 
Total
  $ 1,378     $ 1,715     $ 1,584  

Cash provided by operating activities for continuing operations decreased during 2003 compared with 2002 primarily due to decreases in recovery of deferred fuel costs. Cash provided by operating activities for discontinued operations decreased during 2003 compared with 2002 due to the deconsolidation of NRG for 2003 reporting and the exclusion of any of its cash flows in that year. The decrease was partially offset by tax benefits received in connection with the divestiture of NRG in 2003.

Cash provided by operating activities for continuing operations decreased during 2002 compared with 2001 due to lower 2002 utility receivables and unbilled revenues, reflecting collections of higher year-end 2001 amounts. Cash provided by operating activities for discontinued operations increased during 2002 compared with 2001 primarily due to NRG’s efforts to conserve cash by deferring the payment of interest payments and managing its cash flows more closely. NRG’s accrued interest costs rose by nearly $200 million in 2002 compared with year-end 2001 levels.

                         
(Millions of dollars)
  2003
  2002
  2001
Cash used in investing activities
                       
Continuing operations
  $ (1,072 )   $ (1,056 )   $ (1,156 )
Discontinued operations
    146       (1,655 )     (4,017 )
 
   
 
     
 
     
 
 
Total
  $ (926 )   $ (2,711 )   $ (5,173 )

Cash used in investing activities for continuing operations was approximately the same during 2003 compared with 2002 due to comparable utility construction expenditures. Cash flows for investing activities related to discontinued operations increased during 2003 compared with 2002 due to the deconsolidation of NRG for 2003 reporting and the exclusion of any of its cash flows in that year. NRG had significant construction expenditures during 2002 prior to its financial difficulties.

Cash used in investing activities for continuing operations decreased slightly during 2002 compared with 2001 primarily due to lower utility construction expenditures in 2002. Cash used in investing activities for discontinued operations decreased during 2002 compared with 2001 primarily due to lower levels of nonregulated capital expenditures as a result of NRG terminating its acquisition program due to its financial difficulties. Such nonregulated expenditures decreased $2.8 billion in 2002 due mainly to NRG asset acquisitions in 2001 that did not recur in 2002.

                         
(Millions of dollars)
  2003
  2002
  2001
Cash (used in) provided by financing activities
                       
Continuing operations
  $ (367 )   $ 115     $ (435 )
Discontinued operations
          1,465       4,148  
 
   
 
     
 
     
 
 
Total
  $ (367 )   $ 1,580     $ 3,713  

Cash flows for financing activities related to continuing operations decreased during 2003 compared with 2002 due to refinancing activities in 2003 to better align Xcel Energy’s capital structure and manage the cost of capital given the improving credit quality of Xcel Energy and its subsidiaries. During 2003, Xcel Energy and its subsidiaries extinguished $1.3 billion of long-term debt and issued approximately $1.7 billion of long-term debt, as shown in the Consolidated Statement of Capitalization. Cash flows for financing activities related to discontinued operations decreased during 2003 compared with 2002 due to the deconsolidation of NRG for 2003 reporting and the exclusion of any of its cash flows in that year. NRG obtained financing in 2002 for its construction expenditures prior to experiencing its financial difficulties.

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Cash flow for financing activities related to continuing operations increased during 2002 compared with 2001 primarily due to refinancing activities in 2002, including the redemption of $867 million of short-term debt and the issuance of $1.4 billion of new debt. Cash flow provided by financing activities for discontinued operations decreased during 2002 compared with 2001 primarily due to lower NRG capital requirements and constraints on NRG’s ability to access the capital market due to its financial difficulties, as discussed previously. NRG’s cash provided from financing activities declined by $2.7 billion in 2002 compared with 2001.

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

Capital Requirements

Utility Capital Expenditures, Nonregulated Investments and Long-Term Debt Obligations — The estimated cost of the capital expenditure programs of Xcel Energy and its subsidiaries, excluding discontinued operations, and other capital requirements for the years 2004, 2005 and 2006 are shown in the table below.

                         
(Millions of dollars)
  2004
  2005
  2006
Electric utility
  $ 975     $ 975     $ 1,064  
Natural gas utility
    115       133       111  
Common utility
    101       112       106  
 
   
 
     
 
     
 
 
Total utility
    1,191       1,220       1,281  
Other nonregulated
    30       31       15  
 
   
 
     
 
     
 
 
Total capital expenditures
    1,221       1,251       1,296  
Sinking funds and debt maturities
    153       224       837  
 
   
 
     
 
     
 
 
Total capital requirements
  $ 1,374     $ 1,475     $ 2,133  
 
   
 
     
 
     
 
 

The capital expenditure forecast includes new steam generators at the Prairie Island nuclear plant, new combustion turbines in two NSP-Minnesota plants and costs related to a proposed coal-fired plant in Colorado. The capital expenditure forecast also includes the early stages of the costs related to the MERP modifications to reduce the emissions of NSP-Minnesota’s generating plants located in the Minneapolis-St. Paul metropolitan area. The MERP project is expected to cost approximately $1 billion, with major construction starting in 2005 and finishing in 2009. Xcel Energy expects to recover the costs of the emission-reduction project through customer rate increases beginning in 2006.

The capital expenditure programs of Xcel Energy are subject to continuing review and modification. Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting Xcel Energy’s long-term energy needs. In addition, Xcel Energy’s ongoing evaluation of restructuring requirements, compliance with future requirements to install emission-control equipment, and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements. For more information, see Note 17 to the Consolidated Financial Statements.

Xcel Energy’s investment in exempt wholesale generators and foreign utility companies is currently limited to 100 percent of consolidated retained earnings as a result of the PUHCA restrictions. At this time, Xcel Energy has no capacity to make additional investments in exempt wholesale generators and foreign utility companies without authorization from the SEC.

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Contractual Obligations and Other Commitments — Xcel Energy has contractual obligations and other commercial commitments that will need to be funded in the future, in addition to its capital expenditure programs. The following is a summarized table of contractual obligations and other commercial commitments at Dec. 31, 2003. See additional discussion in the Consolidated Statements of Capitalization and Notes 4, 5, 6, 8, 15 and 17 to the Consolidated Financial Statements.

                                         
                    Payments due by period    
            Less than 1                   After
(Thousands of dollars)
  Total
  year
  1 to 3 years
  4 to 5 years
  5 years
Long- term debt
  $ 6,635,158     $ 158,024     $ 1,058,169     $ 991,058     $ 4,427,907  
Capital lease obligations
    106,315       7,365       13,860       12,964       72,126  
Operating leases (a)
    272,211       48,567       95,826       81,772       46,046  
NRG bankruptcy settlement
    752,000       752,000                    
Unconditional purchase obligations (b)
    10,861,257       1,669,769       2,521,209       1,937,336       4,732,943  
Other long- term obligations
    180,112       39,976       49,654       37,439       53,043  
Payments to vendors in process
    96,887       96,887                    
Short-term debt
    58,563       58,563                    
 
   
 
     
 
     
 
     
 
     
 
 
Total contractual cash obligations (c)
  $ 18,962,503     $ 2,831,151     $ 3,738,718     $ 3,060,569     $ 9,332,065  
 
   
 
     
 
     
 
     
 
     
 
 

(a) Under some leases, Xcel Energy would have to sell or purchase the property that it leases if it chose to terminate before the scheduled lease expiration date. Most of Xcel Energy’s railcar, vehicle and equipment, and aircraft leases have these terms. At Dec. 31, 2003, the amount that Xcel Energy would have to pay if it chose to terminate these leases was approximately $142.9 million.

(b) Obligations to purchase fuel for electric generating plants, and electricity and natural gas for resale. Energy costs are largely recoverable from customers in rates. In addition, approximately $2 billion of the obligation is based on prices tied to a commodity index; as such the obligation will change as the commodity index changes.

(c) Xcel Energy also has outstanding authority under contracts and blanket purchase orders to purchase up to $600 million of goods and services through the year 2020, in addition to the amounts disclosed in this table and in the forecasted capital expenditures.

In addition, Xcel Energy’s board of directors approved the repurchase of 2.5 million shares of common stock to fulfill the requirements of the restricted stock unit exercise in 2004.

Common Stock Dividends Future dividend levels will be dependent upon the statutory limitations discussed below, as well as Xcel Energy’s results of operations, financial position, cash flows and other factors, and will be evaluated by the Xcel Energy board of directors. The ultimate dividend policy will balance:

    projected cash generation from utility operations;
 
    projected capital investment in the utility businesses;
 
    reasonable rate of return on shareholder investment; and
 
    impact on Xcel Energy’s capital structure and credit ratings.

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. Xcel Energy had $369 million of retained earnings at Dec. 31, 2003, and expects to declare dividends as scheduled. The cash to pay dividends to Xcel Energy shareholders is primarily derived from dividends received from the utility subsidiaries. The utility subsidiaries are generally limited in the amount of dividends allowed by state regulatory commissions to be paid to the holding company. The limitation is imposed through equity ratio limitations that range from 30 percent to 57 percent. All utility subsidiaries are required under PUHCA to pay dividends only from retained earnings, and some must comply with covenant restrictions under credit agreements for debt and interest coverage ratios.

The Articles of Incorporation of Xcel Energy place restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. Under the provisions, dividend payments may be restricted if Xcel Energy’s capitalization ratio (on a holding company basis only, i.e., not on a consolidated basis) is less than 25 percent. For these purposes, the capitalization ratio is equal to common stock plus surplus divided by the sum of common stock plus surplus plus long-term debt. Based on this definition, Xcel Energy’s capitalization ratio at Dec. 31, 2003, was 83 percent. Therefore, the restrictions do not place any effective limit on Xcel Energy’s ability to pay dividends because the restrictions are only triggered when the capitalization ratio is less than 25 percent or will be reduced to less than 25 percent through dividends (other than dividends payable in common stock), distributions or acquisitions of Xcel Energy common stock.

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Capital Sources

Xcel Energy expects to meet future financing requirements by periodically issuing long-term debt, short-term debt, common stock and preferred securities to maintain desired capitalization ratios.

Registered holding companies and certain of their subsidiaries, including Xcel Energy and its utility subsidiaries, are limited under PUHCA in their ability to issue securities. Such registered holding companies and their subsidiaries may not issue securities unless authorized by an exemptive rule or order of the SEC. Because Xcel Energy does not qualify for any of the main exemptive rules, it sought and received financing authority from the SEC under PUHCA for various financing arrangements. Xcel Energy’s current financing authority permits it, subject to satisfaction of certain conditions, to issue through June 30, 2005, up to $2.5 billion of common stock and long-term debt and $1.5 billion of short-term debt at the holding-company level. Xcel Energy has issued $2 billion of long-term debt and common stock, including the $400 million credit facility.

Xcel Energy’s ability to issue securities under the financing authority is subject to a number of conditions. One of the conditions of the financing authority is that Xcel Energy’s consolidated ratio of common equity to total capitalization be at least 30 percent. As of Dec. 31, 2003, the common equity ratio was approximately 43 percent. Additional conditions require that a security to be issued that is rated, be rated investment grade by at least one nationally recognized rating agency. Finally, all outstanding securities (except preferred stock) that are rated must be rated investment grade by at least one nationally recognized rating agency. On Feb. 20, 2004, Xcel Energy’s senior unsecured debt was considered investment grade by Standard & Poor’s Ratings Services (Standard & Poor’s) and Moody’s Investors Services, Inc. (Moody’s).

Short-Term Funding Sources — Historically, Xcel Energy has used a number of sources to fulfill short-term funding needs, including operating cash flow, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend in large part on financing needs for construction expenditures. Another significant short-term funding need is the dividend payment.

In 2003, Xcel Energy established a money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The money pool allows for short-term loans between the utility subsidiaries and from the holding company to the utility subsidiaries at market-based interest rates. The money pool arrangement does not allow loans from the utility subsidiaries to the holding company. State regulatory commission approval of the arrangement is pending.

As of Feb. 20, 2004, Xcel Energy had the following credit facilities available to meet its liquidity needs:

                                                 
Company
  Facility
  Drawn*
  Available
  Cash
  Liquidity
  Maturity
(Millions of dollars)                                        
NSP-Minnesota
  $ 275     $ 43     $ 232     $ 130     $ 362     May 2004
NSP-Wisconsin
                                     
PSCo
    350       1       349       171       520     May 2004
SPS
    125       40       85       21       106     February 2005**
Xcel Energy — holding company***
    400       89       311             311     November 2005
 
   
 
     
 
     
 
     
 
     
 
         
Total
  $ 1,150     $ 173     $ 977     $ 322     $ 1,299          
 
   
 
     
 
     
 
     
 
     
 
         

  *   Includes short-term borrowings and letters of credit.
 
  **   The SPS $100 million facility expired in February 2004 and was replaced with a $125 million unsecured, 364-day credit agreement.
 
  ***   Reflects the $400 million NRG payment made in February 2004.

Operating cash flow as a source of short-term funding is affected by such operating factors as weather; regulatory requirements, including rate recovery of costs; environmental regulation compliance and industry deregulation; changes in the trends for energy prices; and supply and operational uncertainties, which are difficult to predict. See further discussion of such factors under Statement of Operations Analysis.

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Short-term borrowing as a source of funding is affected by regulatory actions and access to reasonably priced capital markets. For additional information on Xcel Energy’s short-term borrowing arrangements, see Note 5 to the Consolidated Financial Statements. Access to reasonably priced capital markets is dependent in part on credit agency reviews and ratings. The following ratings reflect the views of Moody’s and Standard & Poor’s. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating company. As of Feb. 20, 2004, the following represents the credit ratings assigned to various Xcel Energy companies:

                 
Company
  Credit Type
  Moody's
  Standard & Poor's
Xcel Energy
  Senior Unsecured Debt   Baa3   BBB-
Xcel Energy
  Commercial Paper   NP   A2
NSP-Minnesota
  Senior Unsecured Debt   Baa1   BBB-
NSP-Minnesota
  Senior Secured Debt   A3   BBB+
NSP-Minnesota
  Commercial Paper   P2   A2
NSP-Wisconsin
  Senior Unsecured Debt   Baa1   BBB
NSP-Wisconsin
  Senior Secured Debt   A3   BBB+
PSCo
  Senior Unsecured Debt   Baa2   BBB-
PSCo
  Senior Secured Debt   Baa1   BBB+
PSCo
  Commercial Paper   P2   A2
SPS
  Senior Unsecured Debt   Baa1   BBB
SPS
  Commercial Paper   P2   A2

Note: Moody’s highest credit rating for debt is Aaa1 and lowest investment grade rating is Baa3. Standard & Poor’s highest credit rating for debt is AAA+ and lowest investment grade rating is BBB-. Moody’s prime ratings for commercial paper range from P1 to P3. NP denotes a nonprime rating. Standard & Poor’s ratings for commercial paper range from A1 to A3, B and C. As of Feb. 10, 2004, Moody’s had Xcel Energy and its operating utility subsidiaries “under review for possible upgrade.” Standard & Poor’s had Xcel Energy and its operating utility subsidiaries on “credit watch positive.”

In the event of a downgrade of its credit ratings below investment grade, Xcel Energy may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy all or a part of its exposures under guarantees outstanding. See a list of guarantees at Note 15 to the Consolidated Financial Statements. Xcel Energy has no explicit rating triggers in its debt agreements.

Registration Statements — Xcel Energy’s Articles of Incorporation authorize the issuance of one billion shares of common stock. As of Dec. 31, 2003, Xcel Energy had approximately 399 million shares of common stock outstanding. In addition, Xcel Energy’s Articles of Incorporation authorize the issuance of 7 million shares of $100 par value preferred stock. On Dec. 31, 2003, Xcel Energy had approximately 1 million shares of preferred stock outstanding. Xcel Energy and its subsidiaries have the following registration statements on file with the SEC, pursuant to which they may sell, from time to time, securities:

    In February 2002, Xcel Energy filed a $1 billion shelf registration with the SEC. Xcel Energy may issue debt securities, common stock and rights to purchase common stock under this shelf registration. Xcel Energy has approximately $482.5 million remaining under this registration.
 
    In April 2001, NSP-Minnesota filed a $600 million, long-term debt shelf registration with the SEC. NSP-Minnesota has approximately $40 million remaining under this registration.
 
    PSCo has an effective shelf registration statement with the SEC under which $800 million of secured first collateral trust bonds or unsecured senior debt securities were registered. PSCo has approximately $225 million remaining under this registration.

Future Financing Plans

Xcel Energy generally expects to fund its operations and capital investments through internally generated funds. Xcel Energy plans to renew its credit facilities at NSP-Minnesota, PSCo and SPS during 2004 and may refinance existing long-term debt with lower-rate debt, based on market conditions. See discussion of funding for the NRG settlement payments in the following section.

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Impact of Settlement Agreement with NRG

As discussed previously and in Note 4 to the Consolidated Financial Statements, NRG has completed its plan of reorganization through a bankruptcy proceeding, and the terms of a settlement among NRG, Xcel Energy and members of NRG’s major creditor constituencies was approved and put into effect.

As part of the reorganization, Xcel Energy completely divested its ownership interest in NRG, which in turn issued new common equity to its creditors. The financial terms of the settlement agreement included a provision that Xcel Energy will pay $752 million to NRG to settle all claims of NRG against Xcel Energy and claims of NRG creditors against Xcel Energy under the NRG plan of reorganization as follows:

    $400 million paid on Feb. 20, 2004, including $112 million to NRG’s bank lenders.
 
    $352 million will be paid on April 30, 2004, unless at such time Xcel Energy has not received tax refunds equal to at least $352 million associated with the loss on its investment in NRG. To the extent such refunds are less than the required payments, the difference between the required payments and those refunds would be due on May 30, 2004.
 
    In return for such payments, Xcel Energy received, or was granted, voluntary and involuntary releases from NRG and its creditors.

Xcel Energy intends to fund the payments required by the settlement agreement with cash received for tax benefits related to its investment in NRG, cash on hand and available Xcel Energy credit facilities.

Based on current forecasts of taxable income and tax liabilities, Xcel Energy expects to realize approximately $1.1 billion of cash savings from these tax benefits through a refund of taxes paid in prior years and reduced taxes payable in future years. Xcel Energy used $130 million of these tax benefits in 2003 and expects to use $480 million in 2004. The remainder of the tax benefit carry forward is expected to be used over subsequent years.

Off-Balance-Sheet Arrangements

Xcel Energy does not have any off-balance-sheet arrangements that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

Earnings Guidance

Xcel Energy’s 2004 earnings per share from continuing operations guidance and key assumptions are detailed in the following table.

         
    2004 Diluted EPS Range
Utility operations
  $ 1.25 - $1.33  
Holding company financing costs
    (0.08 )
Seren
    (0.03 )
Eloigne
    0.01  
Other nonregulated subsidiaries
    0.00 - 0.02  
 
   
 
 
Xcel Energy Continuing Operations — EPS
  $ 1.15 - $1. 25  

Key Assumptions for 2004:

    NRG has no impact on Xcel Energy’s financial results in 2004;
 
    normal weather patterns throughout 2004;
 
    weather-adjusted retail electric utility sales growth of 2.2 percent;
 
    weather-adjusted firm retail gas utility sales growth of approximately 2.4 percent;
 
    successful outcome of the requested capacity rider revenue increase in Colorado;
 
    2004 trading and short-term wholesale margins are expected to be slightly less than 2003 margins to reflect more normal market conditions;
 
    2004 utility operating and maintenance expense is expected be relatively flat, compared with 2003 levels;
 
    2004 depreciation expense is projected to increase by about 2 percent compared with 2003;
 
    2004 interest expense is projected to decline by approximately $15 million, compared with 2003 levels;
 
    an effective tax rate of approximately 31 percent; and
 
    average common stock and equivalents of approximately 425 million shares in 2004, based on the “If Converted” method for convertible notes.

Item 7A.  Quantitative and Qualitative Disclosures about Market Risk

See Management’s Discussion and Analysis under Item 7, incorporated by reference.

Item 8.  Financial Statements and Supplementary Data

See Item 15(a)-1 in Part IV for index of financial statements included herein.

See Note 21 of Notes to Consolidated Financial Statements for summarized quarterly financial data.

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INDEPENDENT AUDITORS’ REPORT

To Xcel Energy Inc.:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Xcel Energy Inc. (a Minnesota corporation) and subsidiaries (the Company) as of December 31, 2003 and 2002, and the related consolidated statements of operations, common stockholders’ equity and other comprehensive income and cash flows for the three years ended December 31, 2003. Our audit also included the financial statement schedules listed in the Index at Item 15. These consolidated financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We did not audit the consolidated balance sheet of NRG Energy, Inc. (a wholly owned subsidiary of Xcel Energy Inc.) for the year ended December 31, 2002, or the consolidated statements of operations, stockholder’s (deficit)/equity and cash flows for the two years ended December 31, 2002 included in the consolidated financial statements of the Company, which statements reflect total assets of $10.9 billion as of December 31, 2002 and losses from discontinued operations net of tax of $3.5 billion for the year ended December 31, 2002,and income from discontinued operations net of tax of $265 million for the year ended December 31, 2001. Those statements were audited by other auditors whose report has been furnished to us (which as to 2002 expresses an unqualified opinion and includes an explanatory paragraph describing conditions that raise substantial doubt about NRG Energy, Inc.’s ability to continue as a going concern and an emphasis of a matter paragraph related to the adoption of Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets” and SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” on January 1, 2002), and our opinion, insofar as it relates to the amounts included for NRG Energy, Inc. for the periods described above, is based solely on the report of the other auditors.

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

In our opinion, based on our audits and the report of other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Xcel Energy Inc. and subsidiaries as of December 31, 2003 and 2002 and the results of their operations and their cash flows for each of the three years ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2002, Xcel Energy Inc. and subsidiaries adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” and SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.”

As discussed in Note 18 to the consolidated financial statements, effective January 1, 2003, Xcel Energy Inc. and subsidiaries adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” and as discussed in Note 16, effective October 1, 2003, Derivatives Implementation Group Issue No. C20 “Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) Regarding Contracts with a Price Adjustment Feature.”

/s/ DELOITTE & TOUCHE LLP
Deloitte & Touche LLP

Minneapolis, Minnesota
February 27, 2004

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REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Stockholder
of NRG Energy, Inc.:

In our opinion, the consolidated balance sheets and the related consolidated statements of operations, cash flows and stockholder’s (deficit)/equity (not presented separately herein) present fairly, in all material respects, the financial position of NRG Energy, Inc. and its subsidiaries at December 31, 2002, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management and evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion.

The consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 and Note 29 to the consolidated financial statements, the Company is experiencing credit and liquidity constraints and has various credit arrangements that are in default. As a direct consequence, during 2002 the Company entered into discussions with its creditors to develop a comprehensive restructuring plan. In connection with its restructuring efforts, the Company and certain of its subsidiaries filed for Chapter 11 bankruptcy protection. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As discussed in Note 19 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” for the year ended December 31, 2002. As discussed in Notes 3 and 5 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” on January 1, 2002.

/S/ PRICEWATERHOUSECOOPERS LLP
PricewaterhouseCoopers LLP
Minneapolis, Minnesota
March 28, 2003, except as to Notes 29 and 30, which are as of December 3, 2003.

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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

(Thousands of dollars, except per share data)

                         
    Year ended Dec. 31
    2003
  2002
  2001
Operating revenues
                       
Electric utility
  $ 5,952,191     $ 5,435,377     $ 6,394,737  
Natural gas utility
    1,710,272       1,363,360       2,022,803  
Electric trading margin
    17,165       1,642       69,641  
Nonregulated and other
    257,888       234,749       236,846  
 
   
 
     
 
     
 
 
Total operating revenues
    7,937,516       7,035,128       8,724,027  
Operating expenses
                       
Electric fuel and purchased power — utility
    2,710,455       2,199,099       3,171,404  
Cost of natural gas sold and transported — utility
    1,208,274       852,813       1,521,236  
Cost of sales — nonregulated and other
    156,626       132,628       127,557  
Other operating and maintenance expenses — utility
    1,580,630       1,490,027       1,493,015  
Other operating and maintenance expenses — nonregulated
    101,723       110,172       89,726  
Depreciation and amortization
    756,000       771,265       726,795  
Taxes (other than income taxes)
    319,522       318,822       312,840  
Special charges (see Note 2)
    19,039       19,265       62,230  
 
   
 
     
 
     
 
 
Total operating expenses
    6,852,269       5,894,091       7,504,803  
 
   
 
     
 
     
 
 
Operating income
    1,085,247       1,141,037       1,219,224  
Interest and other income, net of nonoperating expenses (see Note 13)
    35,717       44,677       30,754  
Interest charges and financing costs
                       
Interest charges — net of amounts capitalized (includes other financing costs of $32,184, $34,884 and $11,211, respectively)
    429,571       384,063       327,636  
Distributions on redeemable preferred securities of subsidiary trusts
    22,731       38,344       38,800  
 
   
 
     
 
     
 
 
Total interest charges and financing costs
    452,302       422,407       366,436  
 
   
 
     
 
     
 
 
Income from continuing operations before income taxes
    668,662       763,307       883,542  
Income taxes
    158,642       235,614       304,342  
 
   
 
     
 
     
 
 
Income from continuing operations
    510,020       527,693       579,200  
Income (loss) from discontinued operations — net of tax (see Note 3)
    112,372       (2,745,684 )     203,945  
 
   
 
     
 
     
 
 
Income (loss) before extraordinary items
    622,392       (2,217,991 )     783,145  
Extraordinary items — net of tax of $5,747
                11,821  
 
   
 
     
 
     
 
 
Net income (loss)
    622,392       (2,217,991 )     794,966  
Dividend requirements on preferred stock
    4,241       4,241       4,241  
 
   
 
     
 
     
 
 
Earnings (loss) available to common shareholders
  $ 618,151     $ (2,222,232 )   $ 790,725  
 
   
 
     
 
     
 
 
Weighted average common shares outstanding (in thousands)
                       
Basic
    398,765       382,051       342,952  
Diluted
    418,912       384,646       343,742  
Earnings (loss) per share — basic
                       
Income from continuing operations
  $ 1.27     $ 1.37     $ 1.69  
Discontinued operations (see Note 3)
    0.28       (7.19 )     0.59  
Extraordinary items (see Note 14)
                0.03  
 
   
 
     
 
     
 
 
Earnings (loss) per share
  $ 1.55     $ (5.82 )   $ 2.31  
 
   
 
     
 
     
 
 
Earnings (loss) per share — diluted
                       
Income from continuing operations
  $ 1.23     $ 1.37     $ 1.68  
Discontinued operations (see Note 3)
    0.27       (7.14 )     0.59  
Extraordinary items (see Note 14)
                0.03  
 
   
 
     
 
     
 
 
Earnings (loss) per share
  $ 1.50     $ (5.77 )   $ 2.30  
 
   
 
     
 
     
 
 

See Notes to Consolidated Financial Statements.

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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of dollars)

                         
    Year ended Dec. 31
    2003
  2002
  2001
Operating activities
                       
Net (loss) income
  $ 622,392     $ (2,217,991 )   $ 794,966  
Remove (income) loss from discontinued operations
    (112,372 )     2,745,684       (203,945 )
Adjustments to reconcile net income to cash provided by operating activities:
                       
Depreciation and amortization
    786,532       792,954       767,445  
Nuclear fuel amortization
    43,401       48,675       41,928  
Deferred income taxes
    113,985       148,765       (9,653 )
Amortization of investment tax credits
    (12,499 )     (13,272 )     (12,867 )
Allowance for equity funds used during construction
    (25,338 )     (7,793 )     (6,739 )
Undistributed equity in earnings of unconsolidated affiliates
    (5,628 )     5,774       (5,275 )
Gain on sale of property
          (6,785 )      
Write-downs and losses from investments
    8,856       15,866        
Unrealized gain on derivative financial instruments
    (1,954 )     17,779       (6,237 )
Extraordinary items — net of tax (see Note 14)
                (11,821 )
Change in accounts receivable
    (129,971 )     28,155       126,110  
Change in inventories
    3,230       (21,313 )     (47,972 )
Change in other current assets
    (172,100 )     116,632       402,543  
Change in accounts payable
    102,734       (137,050 )     (346,352 )
Change in other current liabilities
    (4,070 )     (139,917 )     78,524  
Change in other noncurrent assets
    (133,364 )     (215,836 )     (299,162 )
Change in other noncurrent liabilities
    50,798       139,885       126,735  
Operating cash flows provided by discontinued operations
    243,354       414,899       195,784  
 
   
 
     
 
     
 
 
Net cash provided by operating activities
    1,377,986       1,715,111       1,584,012  
Investing activities
                       
Utility capital/construction expenditures
    (950,940 )     (908,878 )     (1,103,685 )
Allowance for equity funds used during construction
    25,338       7,793       6,739  
Investments in external decommissioning fund
    (80,581 )     (57,830 )     (54,996 )
Nonregulated capital expenditures and asset acquisitions
    (42,287 )     (64,117 )     (53,852 )
Equity investments, loans, deposits and sales of nonregulated projects
    13,300       (17,253 )     3,316  
Restricted cash
    (38,488 )     (23,000 )      
Other investments — net
    1,069       7,001       46,584  
Investing cash flows provided by (used in) discontinued operations
    146,493       (1,655,042 )     (4,016,631 )
 
   
 
     
 
     
 
 
Net cash used in investing activities
    (926,096 )     (2,711,326 )     (5,172,525 )
Financing activities
                       
Short-term borrowings — net
    (445,080 )     (867,466 )     85,921  
Proceeds from issuance of long-term debt
    1,689,317       1,442,172       307,058  
Repayment of long-term debt, including reacquisition premiums
    (1,311,012 )     (32,802 )     (437,692 )
Proceeds from issuance of common stock
    3,219       69,488       129,011  
Dividends paid
    (303,316 )     (496,375 )     (518,894 )
Financing cash flows provided by discontinued operations
          1,465,070       4,147,928  
 
   
 
     
 
     
 
 
Net cash (used in) provided by financing activities
    (366,872 )     1,580,087       3,713,332  
Net increase in cash and cash equivalents
    85,018       583,872       124,819  
Net increase (decrease) in cash and cash equivalents — discontinued operations
    3,521       (241,453 )     (98,092 )
Cash and cash equivalents at beginning of year
    484,700       142,281       115,554  
 
   
 
     
 
     
 
 
Cash and cash equivalents at end of year
  $ 573,239     $ 484,700     $ 142,281  
 
   
 
     
 
     
 
 
Supplemental disclosure of cash flow information
                       
Cash paid for interest (net of amounts capitalized)
  $ 402,506     $ 640,628     $ 708,560  
Cash paid for income taxes (net of refunds received)
  $ (6,379 )   $ 24,935     $ 327,018  

See Notes to Consolidated Financial Statements.

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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)

                 
    Dec. 31
    2003
  2002
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 573,239     $ 484,700  
Restricted cash
    37,363       23,000  
Accounts receivable — net of allowance for bad debts: $31,106 and $23,970, respectively
    658,936       536,476  
Accrued unbilled revenues
    368,374       390,984  
Materials and supplies inventories — at average cost
    168,204       191,041  
Fuel inventory — at average cost
    59,706       67,875  
Natural gas inventories — replacement cost in excess of LIFO: $73,197 and $20,502, respectively
    141,315       114,981  
Recoverable purchased natural gas and electric energy costs
    234,859       63,975  
Derivative instruments valuation — at market
    62,537       6,565  
Prepayments and other
    142,596       118,768  
Current assets held for sale and related to discontinued operations
    684,110       1,738,803  
 
   
 
     
 
 
Total current assets
    3,131,239       3,737,168  
 
   
 
     
 
 
Property, plant and equipment, at cost:
               
Electric utility plant
    17,320,268       16,516,790  
Natural gas utility plant
    2,484,874       2,384,051  
Nonregulated property and other
    1,553,391       1,534,449  
Construction work in progress: utility amounts of $908,256 and $855,842, respectively
    932,082       889,902  
 
   
 
     
 
 
Total property, plant and equipment
    22,290,615       21,325,192  
Less accumulated depreciation
    (8,703,788 )     (8,084,987 )
Nuclear fuel — net of accumulated amortization: $1,101,932 and $1,058,531, respectively
    80,289       74,139  
 
   
 
     
 
 
Net property, plant and equipment
    13,667,116       13,314,344  
 
   
 
     
 
 
Other assets:
               
Investments in unconsolidated affiliates
    124,462       116,094  
Nuclear decommissioning fund and other investments
    843,083       699,077  
Regulatory assets
    879,840       576,876  
Derivative instruments valuation — at market
    429,531       1,494  
Prepaid pension asset
    567,227       448,749  
Other
    209,256       211,738  
Noncurrent assets held for sale and related to discontinued operations
    353,626       10,330,897  
 
   
 
     
 
 
Total other assets
    3,407,025       12,384,925  
 
   
 
     
 
 
Total assets
  $ 20,205,380     $ 29,436,437  
 
   
 
     
 
 
LIABILITIES AND EQUITY
               
Current liabilities:
               
Current portion of long-term debt
  $ 159,955     $ 558,263  
Short-term debt
    58,563       503,643  
Accounts payable
    791,316       698,170  
Taxes accrued
    188,973       243,183  
Dividends payable
    75,866       75,814  
Derivative instruments valuation — at market
    153,467       11,520  
Other
    422,420       332,618  
Current liabilities held for sale and related to discontinued operations
    820,506       9,925,625  
 
   
 
     
 
 
Total current liabilities
    2,671,066       12,348,836  
 
   
 
     
 
 
Deferred credits and other liabilities:
               
Deferred income taxes
    2,014,414       1,894,153  
Deferred investment tax credits
    156,555       169,587  
Regulatory liabilities
    1,570,548       1,328,611  
Derivative instruments valuation — at market
    388,743       10,863  
Asset retirement obligations
    1,024,529       662,411  
Customer advances
    212,766       161,283  
Minimum pension liability
    55,528       106,897  
Benefit obligations and other
    313,206       334,151  
Noncurrent liabilities held for sale and related to discontinued operations
    7,471       1,836,088  
 
   
 
     
 
 
Total deferred credits and other liabilities
    5,743,760       6,504,044  
 
   
 
     
 
 
Minority interest in subsidiaries
    281       296  
Commitments and contingencies (see Note 17)
               
Capitalization (see Statements of Capitalization):
               
Long-term debt
    6,518,853       5,318,957  
Mandatorily redeemable preferred securities of subsidiary trusts (see Note 8)
          494,000  
Preferred stockholders’ equity
    104,980       105,320  
Common stockholders’ equity
    5,166,440       4,664,984  
 
   
 
     
 
 
Total liabilities and equity
  $ 20,205,380     $ 29,436,437  
 
   
 
     
 
 

See Notes to Consolidated Financial Statements.

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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY AND OTHER
COMPREHENSIVE INCOME
(Thousands)

                                                         
                                                 
    Common Stock Issued
                  Accumulated
Other
   
                            Retained           Comprehensive   Total
                    Capital in Excess   Earnings   Shares Held   Income   Stockholders'
    Shares
  Par Value
  of Par Value
  (Deficit)
  by ESOP
  (Loss)
  Equity
Balance at Dec. 31, 2000
    340,834     $ 852,085     $ 2,607,025     $ 2,284,220     $ (24,617 )   $ (156,929 )   $ 5,561,784  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
Net income
                            794,966                       794,966  
Currency translation adjustments
                                            (56,693 )     (56,693 )
Cumulative effect of accounting change — net unrealized transition loss upon adoption of SFAS No. 133 (see Note 16)
                                            (28,780 )     (28,780 )
After-tax net unrealized gains related to derivatives (see Note 16)
                                            63,023       63,023  
Unrealized loss — marketable securities
                                            (75 )     (75 )
 
                                                   
 
 
Comprehensive income for 2001
                                                    772,441  
Dividends declared:
                                                       
Cumulative preferred stock
                            (4,241 )                     (4,241 )
Common stock
                            (516,515 )                     (516,515 )
Issuances of common stock — net proceeds
    4,967       12,418       120,673                               133,091  
Other
                            (27 )                     (27 )
Gain from NRG stock offering
                    241,891                               241,891  
Repayment of ESOP loan
                                    6,053               6,053  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
Balance at Dec. 31, 2001
    345,801       864,503       2,969,589       2,558,403       (18,564 )     (179,454 )     6,194,477  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
Net loss
                            (2,217,991 )                     (2,217,991 )
Currency translation adjustments
                                            30,008       30,008  
Minimum pension liability
                                            (107,782 )     (107,782 )
After-tax net unrealized losses related to derivatives (see Note 16)
                                            (39,475 )     (39,475 )
Unrealized loss — marketable securities
                                            (457 )     (457 )
 
                                                   
 
 
Comprehensive loss for 2002
                                                    (2,335,697 )
Dividends declared:
                                                       
Cumulative preferred stock
                            (4,241 )                     (4,241 )
Common stock
                            (437,113 )                     (437,113 )
Issuances of common stock — net proceeds
    27,148       67,870       513,342                               581,212  
Acquisition of NRG minority common shares
    25,765       64,412       555,220                       28,150       647,782  
Repayment of ESOP loan
                                    18,564               18,564  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
Balance at Dec. 31, 2002
    398,714       996,785       4,038,151       (100,942 )           (269,010 )     4,664,984  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
Net income
                            622,392                       622,392  
Currency translation adjustments
                                            182,829       182,829  
Minimum pension liability
                                            9,710       9,710  
After-tax net unrealized losses related to derivatives (see Note 16)
                                            (14,005 )     (14,005 )
Unrealized gain — marketable securities
                                            340       340  
 
                                                   
 
 
Comprehensive income for 2003
                                                    801,266  
Dividends declared:
                                                       
Cumulative preferred stock
                    (720 )     (3,181 )                     (3,901 )
Common stock
                    (149,521 )     (149,606 )                     (299,127 )
Issuances of common stock — net proceeds
    251       627       2,591                               3,218  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
Balance at Dec. 31, 2003
    398,965     $ 997,412     $ 3,890,501     $ 368,663     $     $ (90,136 )   $ 5,166,440  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 

See Notes to Consolidated Financial Statements.

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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(Thousands of Dollars)

                 
    Dec. 31
Long-Term Debt
  2003
  2002
NSP-Minnesota Debt
               
First Mortgage Bonds, Series due:
               
Dec. 1, 2004-2006, 3.9% - 4.1%
  $ 6,990 (a)   $ 9,145 (a)
March 1, 2003, 5.875%
          100,000  
April 1, 2003, 6.375%
          80,000  
Dec. 1, 2005, 6.125%
    70,000       70,000  
Aug. 1, 2006, 2.875%
    200,000        
Aug. 1, 2010, 4.75%
    175,000        
Aug. 28, 2012, 8%
    450,000       450,000  
March 1, 2011, variable rate, 6.265% at Dec. 31, 2002
          13,700 (b)
March 1, 2019, 8.5%
    27,900 (b)     27,900 (b)
Sept. 1, 2019, 8.5%
    100,000 (b)     100,000 (b)
July 1, 2025, 7.125%
    250,000       250,000  
March 1, 2028, 6.5%
    150,000       150,000  
April 1, 2030, 8.5%
    69,000 (b)     69,000 (b)
Dec. 1, 2004 - 2008, 4.35% - 5%
    11,990 (a)     14,090 (a)
Guaranty Agreements, Series due Feb. 1, 2003 - May 1, 2003, 5.375% - 7.4%
          28,450 (b)
Senior Notes due Aug. 1, 2009, 6.875%
    250,000       250,000  
Retail Notes due July 1, 2042, 8%
    185,000       185,000  
Other
    399       427  
Unamortized discount-net
    (8,721 )     (8,931 )
 
   
 
     
 
 
Total
    1,937,558       1,788,781  
Less redeemable bonds classified as current (see Note 6)
          13,700  
Less current maturities
    4,502       212,762  
 
   
 
     
 
 
Total NSP-Minnesota long-term debt
  $ 1,933,056     $ 1,562,319  
 
   
 
     
 
 
PSCo Debt
               
First Mortgage Bonds, Series due:
               
April 15, 2003, 6%
  $     $ 250,000  
March 1, 2004, 8.125%
    100,000       100,000  
Nov. 1, 2005, 6.375%
    134,500       134,500  
June 1, 2006, 7.125%
    125,000       125,000  
April 1, 2008, 5.625%
    18,000 (b)     18,000 (b)
Oct. 1, 2008, 4.375%
    300,000        
June 1, 2012, 5.5%
    50,000 (b)     50,000 (b)
Oct. 1, 2012, 7.875%
    600,000       600,000  
March 1, 2013, 4.875%
    250,000        
April 1, 2014, 5.5%
    275,000        
April 1, 2014, 5.875%
    61,500 (b)     61,500 (b)
Jan. 1, 2019, 5.1%
    48,750 (b)     48,750 (b)
March 1, 2022, 8.75%
          146,340  
Jan. 1, 2024, 7.25%
    110,000       110,000  
Unsecured Senior A Notes, due July 15, 2009, 6.875%
    200,000       200,000  
Secured Medium-Term Notes, due Feb. 2, 2004 - March 5, 2007, 6.9% - 7.11%
    145,000       175,000  
Unamortized discount
    (6,835 )     (4,612 )
Capital lease obligations, 11.2% due in installments through May 31, 2025
    47,650       49,747  
 
   
 
     
 
 
Total
    2,458,565       2,064,225  
Less current maturities
    147,131       282,097  
 
   
 
     
 
 
Total PSCo long-term debt
  $ 2,311,434     $ 1,782,128  
 
   
 
     
 
 

See Notes to Consolidated Financial Statements.

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    Dec. 31
Long-Term Debt - continued (Thousands of dollars)
  2003
  2002
SPS Debt
               
Unsecured Senior A Notes, due March 1, 2009, 6.2%
  $ 100,000     $ 100,000  
Unsecured Senior B Notes, due Nov. 1, 2006, 5.125%
    500,000       500,000  
Unsecured Senior C Notes, due Oct. 1, 2033, 6%
    100,000        
Pollution control obligations, securing pollution control revenue bonds due:
               
July 1, 2011, 5.2%
    44,500       44,500  
July 1, 2016, 1.25% at Dec. 31, 2003, and 1.6% at Dec. 31, 2002
    25,000       25,000  
Sept. 1, 2016, 5.75% series
    57,300       57,300  
Unamortized discount
    (1,653 )     (1,138 )
 
   
 
     
 
 
Total SPS long-term debt
  $ 825,147     $ 725,662  
 
   
 
     
 
 
NSP-Wisconsin Debt
               
First Mortgage Bonds Series due:
               
Oct. 1, 2003, 5.75%
  $     $ 40,000  
Oct. 1, 2018, 5.25%
    150,000        
March 1, 2023, 7.25%
          110,000  
Dec. 1, 2026, 7.375%
    65,000       65,000  
City of La Crosse Resource Recovery Bond, Series due Nov. 1, 2021, 6%
    18,600 (a)     18,600 (a)
Fort McCoy System Acquisition, due Oct. 31, 2030, 7%
    895       930  
Senior Notes — due, Oct. 1, 2008, 7.64%
    80,000       80,000  
Unamortized discount
    (1,051 )     (1,388 )
 
   
 
     
 
 
Total
    313,444       313,142  
Less current maturities
    34       40,034  
 
   
 
     
 
 
Total NSP-Wisconsin long-term debt
  $ 313,410     $ 273,108  
 
   
 
     
 
 
Other Subsidiaries’ Debt
               
First Mortgage Bonds — Cheyenne:
               
Series due April 1, 2003 - Jan. 1, 2024, 7.5% - 7.875%
  $ 8,000     $ 12,000  
Industrial Development Revenue Bonds, due Sept. 1, 2021 - March 1, 2027, variable rate, 1.3% and 1.7% at Dec. 31, 2003 and 2002
    17,000       17,000  
Various Eloigne Co. Affordable Housing Project Notes, due 2004 - 2026, 0.3% - 9.91%
    39,139       41,353  
Other
    12,140       94,894  
 
   
 
     
 
 
Total
    76,279       165,247  
Less current maturities
    8,288       9,670  
 
   
 
     
 
 
Total other subsidiaries long-term debt
  $ 67,991     $ 155,577  
 
   
 
     
 
 
Xcel Energy Inc. Debt
               
Unsecured senior notes, Series due:
               
July 1, 2008, 3.4%
  $ 195,000     $  
Dec. 1, 2010, 7%
    600,000       600,000  
Convertible notes, Series due:
               
Nov. 21, 2007, 7.5%
    230,000       230,000  
Nov. 21, 2008, 7.5%
    57,500        
Fair value hedge, carrying value adjustment
    (6,298 )      
Unamortized discount
    (8,387 )     (9,837 )
 
   
 
     
 
 
Total Xcel Energy Inc. debt
  $ 1,067,815     $ 820,163  
 
   
 
     
 
 
Total long-term debt from continuing operations
  $ 6,518,853     $ 5,318,957  
 
   
 
     
 
 
Long-Term Debt from Discontinued Operations
               
Viking Gas Transmission Co. Senior Notes, Series due:
               
Oct. 31, 2008 - Sept. 30, 2014, 6.65% - 8.04%
  $     $ 40,421  
Black Mountain Gas notes, due June 1, 2004 - May 1, 2005, 6%
          3,000  
NRG long-term debt:
               
Remarketable or Redeemable Securities, due March 15, 2005, 7.97%
          257,552  
NRG Energy, Inc. Senior Notes, Series due:
               
Feb. 1, 2006, 7.625%
          125,000  
June 15, 2007, 7.5%
          250,000  
June 1, 2009, 7.5%
          300,000  
Nov. 1, 2013, 8%
          240,000  
Sept. 15, 2010, 8.25%
          350,000  
July 15, 2006, 6.75%
          340,000  
April 1, 2011, 7.75%
          350,000  
April 1, 2031, 8.625%
          500,000  
May 16, 2006, 6.5%
          285,728  
NRG Finance Co. LLC, due May 9, 2006, various rates
          1,081,000  

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    Dec. 31
Long-Term Debt - continued (Thousands of dollars)
  2003
  2002
NRG debt secured solely by project assets:
               
NRG Northeast Generating Senior Bonds, Series due:
               
Dec. 15, 2004, 8.065%
          126,500  
June 15, 2015, 8.842%
          130,000  
Dec. 15, 2024, 9.292%
          300,000  
South Central Generating Senior Bonds, Series due:
               
May 15, 2016, 8.962%
          450,750  
Sept. 15, 2024, 9.479%
          300,000  
MidAtlantic — various, due Oct. 1, 2005, 4.625%
          409,201  
Flinders Power Finance Pty, due September 2012, various rates of 6.14%-6.49% at Dec. 31, 2002
          99,175  
Brazos Valley, due June 30, 2008, 6.75%
          194,362  
Camas Power Boiler, due June 30, 2007, and Aug. 1, 2007, 3.65% and 3.38%
          17,861  
Sterling Luxembourg #3 Loan, due June 30, 2019, variable rate
          360,122  
Hsin Yu Energy Development, due November 2006-April 2012, 4%-6.475%
          85,607  
LSP Batesville, due Jan. 15, 2014, 7.164% and July 15, 2025, 8.16%
          314,300  
LSP Kendall Energy, due Sept. 1, 2005, 2.65%
          495,754  
McClain, due Dec. 31, 2005, 6.75%
          157,288  
NEO, due 2005-2008, 9.35%
          7,658  
NRG Energy Center, Inc. Senior Secured Notes, Series due June 15, 2013, 7.31%
          133,099  
NRG Peaking Finance LLC, due 2019, 6.67%
          319,362  
NRG Pike Energy LLC, due 2010, 4.92%
          155,477  
PERC, due 2017-2018, 5.2%
          28,695  
Audrain Capital Lease Obligation, due Dec. 31, 2023, 10%
          239,930  
Saale Energie GmbH Schkopau Capital Lease, due May 2021, various rates
          333,926  
Various debt, due 2003-2007, 0.0%-20.8%
          92,573  
Other
          677  
 
   
 
     
 
 
Total
          8,875,018  
Less current maturities
          7,643,654  
 
   
 
     
 
 
Total long-term debt from discontinued operations
  $     $ 1,231,364  
 
   
 
     
 
 
Mandatorily Redeemable Preferred Securities of Subsidiary Trusts holding as their sole asset the junior subordinated deferrable debentures of the following (see Note 8):
               
NSP-Minnesota, due 2037, 7.875%
  $     $ 200,000  
PSCo, due 2038, 7.6%
          194,000  
SPS, due 2036, 7.85%
          100,000  
 
   
 
     
 
 
Total mandatorily redeemable preferred securities of subsidiary trusts
  $     $ 494,000  
 
   
 
     
 
 
Cumulative Preferred Stock — authorized 7,000,000 shares of $100 par value; outstanding shares: 2003: 1,049,800; 2002: 1,049,800 $3.60 series, 275,000 shares
  $ 27,500     $ 27,500  
$4.08 series, 150,000 shares
    15,000       15,000  
$4.10 series, 175,000 shares
    17,500       17,500  
$4.11 series, 200,000 shares
    20,000       20,000  
$4.16 series, 99,800 shares
    9,980       9,980  
$4.56 series, 150,000 shares
    15,000       15,000  
 
   
 
     
 
 
Total
    104,980       104,980  
Capital in excess of par value on preferred stock
          340  
 
   
 
     
 
 
Total preferred stockholders’ equity
  $ 104,980     $ 105,320  
 
   
 
     
 
 
Common Stockholders’ Equity
               
Common stock — authorized 1,000,000,000 shares of $2.50 par value; outstanding shares: 2003:
               
398,964,724; 2002: 398,714,039
  $ 997,412     $ 996,785  
Capital in excess of par value on common stock
    3,890,501       4,038,151  
Retained earnings (deficit)
    368,663       (100,942 )
Accumulated other comprehensive income (loss)
    (90,136 )     (269,010 )
 
   
 
     
 
 
Total common stockholders’ equity
  $ 5,166,440     $ 4,664,984  
 
   
 
     
 
 


(a)   Resource recovery financing
(b)   Pollution control financing

See Notes to Consolidated Financial Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Business and System of Accounts — Xcel Energy’s utility subsidiaries are engaged principally in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. Xcel Energy and its subsidiaries are subject to the regulatory provisions of the PUHCA. The utility subsidiaries are subject to regulation by the FERC and state utility commissions. All of the utility companies’ accounting records conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.

Principles of Consolidation — Xcel Energy directly owns 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). Their service territories include portions of Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas, Wisconsin and Wyoming. Xcel Energy’s regulated subsidiaries also included WestGas Interstate Inc. (WGI), an interstate natural gas pipeline company. Also, until 2003, Xcel Energy’s regulated businesses included Viking Gas Transmission Co. (Viking), which was sold in January 2003, and Black Mountain Gas Co. (BMG), which was sold in October 2003. See Note 3 to the Consolidated Financial Statements for more information on the discontinued operations of Viking and BMG. In January 2004, Xcel Energy reached an agreement to sell Cheyenne, pending regulatory approval.

Xcel Energy’s nonregulated businesses 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). In December 2003, Xcel Energy’s board of directors approved management’s plan to exit the businesses conducted by the nonregulated subsidiaries Xcel Energy International Inc. (an international independent power producer) and e prime inc. (a natural gas marketing and trading company). Both of these businesses are presented as a component of discontinued operations, as discussed in Note 3 to the Consolidated Financial Statements.

Xcel Energy also divested its ownership interest in NRG Energy, Inc. (NRG), an independent power producer, in 2003. Xcel Energy owned 82 percent of NRG at the beginning of 2001. In March 2001, 8 percent of NRG was sold to the public, leaving Xcel Energy with an interest of about 74 percent at Dec. 31, 2001. On June 3, 2002, Xcel Energy acquired the 26 percent of NRG held by the public, resulting in 100-percent ownership interest at Dec. 31, 2002. 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, Xcel Energy divested its ownership interest in NRG. At Dec. 31, 2003, Xcel Energy reports NRG’s financial activity as a component of discontinued operations. See Note 3 to the Consolidated Financial Statements.

Xcel Energy owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries: Xcel Energy Wholesale Energy Group Inc., Xcel Energy Markets Holdings Inc., Xcel Energy Ventures Inc., Xcel Energy Retail Holdings Inc., Xcel Energy Communications Group Inc., Xcel Energy WYCO Inc. and Xcel Energy O&M Services Inc. Xcel Energy and its subsidiaries collectively are referred to as Xcel Energy.

Xcel Energy uses the equity method of accounting for its investments in partnerships, joint ventures and certain projects. Under this method, a proportionate share of pre-tax income is recorded as equity earnings from investments in affiliates. The portion of earnings from international investments is recorded after subtracting foreign income taxes, if applicable. In the consolidation process, all significant intercompany transactions and balances are eliminated. Xcel Energy has investments in several plants and transmission facilities jointly owned with other utilities. These projects are accounted for on a proportionate consolidation basis, consistent with industry practice. See Note 9 to the Consolidated Financial Statements.

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

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Xcel Energy’s utility subsidiaries have various rate-adjustment mechanisms in place that currently provide for the recovery of certain purchased natural gas and electric energy costs. These cost adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically, as prescribed by the appropriate regulatory agencies, for any difference between the total amount collected under the clauses and the recoverable costs incurred. In addition, Xcel Energy presents its revenue net of any excise or other fiduciary-type taxes or fees. A summary of significant rate-adjustment mechanisms follows:

    PSCo’s electric rates in Colorado permitted recovery of 100 percent of prudently incurred 2003 electric fuel and purchased energy expense. In 2002 and 2001, PSCo’s electric rates in Colorado were adjusted under an incentive cost-adjustment mechanism, which resulted in the sharing of cost increases and decreases with customers and sharing of trading margins, as discussed later.

    NSP-Minnesota’s rates include a cost-of-fuel-and-energy and a cost-of-gas recovery mechanism allowing dollar-for-dollar recovery of the respective costs, which are trued-up on a two-month and annual basis, respectively.

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

    In Colorado, PSCo operates under an electric performance-based regulatory plan, which provides for an annual earnings test. NSP-Minnesota and PSCo operate under various service standards, which could require customer refunds if certain criteria are not met. NSP-Minnesota and PSCo’s rates include monthly adjustments for the recovery of conservation and energy-management program costs, which are reviewed annually.

    SPS’ rates in Texas provide electric fuel and purchased energy cost recovery. In New Mexico, SPS also has a monthly fuel and purchased power cost-recovery factor.

    NSP-Minnesota, NSP-Wisconsin, PSCo and SPS sell firm power and energy in wholesale markets, which are regulated by the FERC. These rates include monthly wholesale fuel cost-recovery mechanisms.

Trading Operations — All applicable gains and losses related to energy trading activities, whether or not settled physically, are shown net in the statement of operations. Electric trading costs, including such gains and losses, are reported as an offset to Electric Trading Revenues to present Electric Trading Margin on a net basis.

Xcel Energy’s electric trading operations are conducted by NSP-Minnesota and PSCo. Pursuant to a joint operating agreement (JOA), approved by the FERC, some of the electric trading activity is apportioned to the other operating utilities of Xcel Energy. Trading revenue and costs do not include the revenue and production costs associated with energy produced from Xcel Energy’s generation assets or energy and capacity purchased to serve native load. Trading results are recorded using mark-to-market accounting. In addition, trading results include the impacts of any margin-sharing mechanisms. In 2003, Xcel Energy’s board of directors designated e prime as held for sale. e prime had conducted natural gas commodity trading activities. Consequently, e prime financial results are presented as discontinued operations. For more information, see Notes 3, 15 and 16 to the Consolidated Financial Statements.

Derivative Financial Instruments — Xcel Energy and its subsidiaries utilize a variety of derivatives, including interest rate swaps and locks, foreign currency hedges and energy contracts, to reduce exposure to corresponding risks. The energy contracts are both financial- and commodity-based. These contracts consist mainly of commodity futures and options, index or fixed price swaps and basis swaps. For further discussion of Xcel Energy’s risk management and derivative activities, see Notes 15 and 16 to the Consolidated Financial Statements.

Property, Plant, Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and applicable interest expense. The cost of plant retired, plus net removal cost, is charged to accumulated depreciation and amortization. Beginning in 2003, removal costs related to asset retirement obligations that are not legal obligations are reflected in regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance are charged to expense as incurred. Maintenance and replacement of items determined to be less than units of property are charged to operating expenses. Property, plant and equipment also includes costs associated with the engineering design of future generating stations and other property held for future use.

Xcel Energy determines the depreciation of its plant by using the straight-line method, which spreads the original cost equally over the plant’s useful life. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.0, 3.4 and 3.1 for the years ended Dec. 31, 2003, 2002 and 2001, respectively.

Allowance for Funds Used During Construction (AFDC) and Capitalized Interest AFDC, a noncash item, represents the cost of capital used to finance utility construction activity. AFDC is computed by applying a composite pretax rate to qualified construction work in progress. The amount of AFDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges

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(for debt capital). AFDC amounts capitalized are included in Xcel Energy’s rate base for establishing utility service rates. In addition to construction-related amounts, AFDC also is recorded to reflect returns on capital used to finance conservation programs in Minnesota. Interest capitalized for debt capital for all Xcel Energy entities (as AFDC for utility companies) was approximately $20 million in 2003, $18 million in 2002 and $29 million in 2001. AFDC recorded for equity capital for all Xcel Energy entities was $25 million in 2003, $8 million in 2002 and $7 million in 2001.

Decommissioning — Xcel Energy accounts for the future cost of decommissioning, or retirement, of its nuclear generating plants through annual depreciation accruals using an annuity approach designed to provide for full rate recovery of the future decommissioning costs. The decommissioning calculation covers all expenses, including decontamination and removal of radioactive material, and extends over the estimated lives of the plants. The calculation assumes that NSP-Minnesota and NSP-Wisconsin will recover those costs through rates. The fair value of external nuclear decommissioning fund investments are estimated based on quoted market prices for those or similar investments. Unrealized gains or losses are deferred as regulatory assets or liabilities. In 2003, NSP-Minnesota adopted Statement of Financial Accounting Standard (SFAS) No. 143, which changed the accounting methodology for nuclear decommissioning costs. For more information on nuclear decommissioning and the impacts of adopting SFAS No. 143, see Note 18 to the Consolidated Financial Statements.

PSCo also previously operated a nuclear generating plant, which has been decommissioned and repowered using natural gas. PSCo’s costs associated with decommissioning were deferred and are being amortized consistent with regulatory recovery.

Nuclear Fuel Expense — Nuclear fuel expense, which is recorded as our nuclear generating plants use fuel, includes the cost of fuel used in the current period, as well as future disposal costs of spent nuclear fuel. In addition, nuclear fuel expense includes fees assessed by the U.S. Department of Energy (DOE) for NSP-Minnesota’s portion of the cost of decommissioning the DOE’s fuel-enrichment facility.

Environmental Costs — Environmental costs are recorded when it is probable Xcel Energy is liable for the costs and the liability can reasonably be estimated. Costs may be deferred as a regulatory asset based on an expectation that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant, assuming the costs are recoverable in future rates or future cash flow.

Estimated remediation costs, excluding inflationary increases and possible reductions for insurance coverage and rate recovery, are recorded. The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and as remediation proceeds. If several designated responsible parties exist, only Xcel Energy’s expected share of the cost is estimated and recorded. Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for these estimated removal costs. However, as discussed further in Note 18 to the Consolidated Financial Statements, removal costs recovered in rates were reclassified to Regulatory Liabilities beginning in 2002.

Income Taxes — Xcel Energy and its domestic subsidiaries file consolidated federal income tax returns. NRG and its domestic subsidiaries were included in Xcel Energy’s consolidated federal income tax returns prior to NRG’s March 2001 public equity offering. Xcel Energy and its domestic subsidiaries file combined and separate state income tax returns. NRG and one or more of its domestic subsidiaries were included in some, but not all, of these combined returns in 2002 and will be included in these returns in 2003. NRG will not be consolidated or combined in any of Xcel Energy’s income tax returns after 2003.

Federal income taxes paid by Xcel Energy, as parent of the Xcel Energy consolidated group, are allocated to the Xcel Energy subsidiaries based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy in connection with combined state filings. In accordance with PUHCA requirements, the holding company also allocates its own net income tax benefits to its direct subsidiaries based on the positive tax liability of each company.

Xcel Energy defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. Xcel Energy uses the tax rates that are scheduled to be in effect when the temporary differences are expected to turn around, or reverse.

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded, the reversal of some temporary differences are accounted for as current income tax expense. Investment tax credits are deferred and their benefits amortized over the estimated lives of the related property. Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which are summarized in Note 19 to the Consolidated Financial Statements. See a discussion of the income tax policy for international operations in Note 10 to the Consolidated Financial Statements.

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Foreign Currency Translation — Xcel Energy’s foreign operations, which are limited to Xcel Energy International and NRG before divestiture, generally use the local currency as their functional currency in translating international operating results and balances to U.S. currency. Foreign-currency-denominated assets and liabilities are translated at the exchange rates in effect at the end of a reporting period. Revenue, expense and cash flows are translated at weighted-average exchange rates for the period. Xcel Energy accumulates the resulting currency translation adjustments and reports them as a component of Other Comprehensive Income in Common Stockholders’ Equity.

Use of Estimates — In recording transactions and balances resulting from business operations, Xcel Energy uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results. The depreciable lives of certain plant assets are reviewed or revised annually, if appropriate.

Cash and Cash Equivalents — Xcel Energy considers investments in certain debt instruments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. Those debt instruments are primarily commercial paper and money market funds.

Restricted cash in 2003 consists primarily of funds received from NRG to be used to collateralize in full existing agreements of Xcel Energy to indemnify NRG, which continued after the divestiture of NRG. Restricted cash in 2002 consists primarily of cash collateral for letters of credit and funds held in trust accounts to satisfy the requirements of certain debt agreements. Restricted cash is classified as a current asset as all restricted cash is designated for interest and principal payments due within one year.

Inventory — All inventory is recorded at average cost, with the exception of natural gas in underground storage at PSCo and Cheyenne, which is recorded using last-in-first-out pricing.

Regulatory Accounting — Our regulated utility subsidiaries account for certain income and expense items using SFAS No. 71 — “Accounting for the Effects of Certain Types of Regulation.” Under SFAS No. 71:

  certain costs, which would otherwise be charged to expense, are deferred as regulatory assets based on the expected ability to recover them in future rates; and

  certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation they will be returned to customers in future rates.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. See more discussion of regulatory assets and liabilities at Note 19 to the Consolidated Financial Statements.

Stock-Based Employee Compensation — Xcel Energy has several stock-based compensation plans. Those plans are accounted for using the intrinsic-value method. Compensation expense is not recorded for stock options because there is no difference between the market price and the purchase price at grant date. Compensation expense is recorded for restricted stock and stock units awarded to certain employees, which is held until the restriction lapses or the stock is forfeited. For more information on stock compensation impacts, see Note 11 to the Consolidated Financial Statements.

Intangible Assets — During 2002, Xcel Energy adopted SFAS No. 142 — “Goodwill and Other Intangible Assets” regarding the accounting for intangible assets and goodwill. Intangible assets with finite lives are amortized over their economic useful lives and periodically reviewed for impairment. Beginning in 2002, goodwill is no longer being amortized, but is tested for impairment annually and on an interim basis if an event occurs or a circumstance changes between annual tests that may reduce the fair value of a reporting unit below its carrying value.

Xcel Energy’s goodwill consisted primarily of project-related goodwill at Utility Engineering for 2003 and 2002. During 2003, impairment testing resulted in a $4.8 million write-down in this goodwill.

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Intangible assets with finite lives continue to be amortized, and the aggregate amortization expense recognized in both years ended Dec. 31, 2003 and 2002, were $0.3 million. The annual aggregate amortization expense for each of the five succeeding years is expected to approximate $0.2 million. Intangible assets consisted of the following:

                                 
    Dec. 31, 2003
  Dec. 31, 2002
    Gross Carrying   Accumulated   Gross Carrying   Accumulated
(Millions of dollars)
  Amount
  Amortization
  Amount
  Amortization
Not amortized:
                               
Goodwill
  $ 3.5     $ 0.6     $ 8.3     $ 0.6  
Amortized:
                               
Service contracts
  $     $     $ 5.2     $ 0.8  
Trademarks
  $ 5.1     $ 0.7     $ 5.1     $ 0.6  
Prior service costs
  $ 5.8     $     $ 6.9     $  
Other (primarily franchises)
  $ 2.3     $ 0.6     $ 2.0     $ 0.5  

The pro forma impact of implementing SFAS No. 142 at Jan. 1, 2001, on the net income and earnings per share for the year ended Dec. 31, 2001, was not material in relation to the amounts previously reported.

Asset Valuation On Jan. 1, 2002, Xcel Energy adopted SFAS No. 144 - “Accounting for the Impairment or Disposal of Long-Lived Assets,” which supercedes previous guidance for measurement of asset impairments. Xcel Energy did not recognize any asset impairments as a result of the adoption. The method used in determining fair value was based on a number of valuation techniques, including present value of future cash flows. See Note 3 to the Consolidated Financial Statements for discussion of impairment charges resulting from the application of SFAS No. 144 to NRG’s and Xcel Energy International’s discontinued operations.

Deferred Financing Costs Other assets also included deferred financing costs, net of amortization, of approximately $49 million at Dec. 31, 2003. Xcel Energy is amortizing these financing costs over the remaining maturity periods of the related debt.

2004 Changes in Consolidation Policy In January 2003, the FASB issued FIN No. 46, requiring an enterprise’s consolidated financial statements to include subsidiaries in which the enterprise has a controlling financial interest. Historically, consolidation has been required only for subsidiaries in which an enterprise has a majority voting interest. Under FIN No. 46, an enterprise’s consolidated financial statements will include the consolidation of variable-interest entities in which the enterprise has a controlling financial interest. As a result, Xcel Energy expects that it will be required to consolidate all or a portion of its affordable housing investments made through Eloigne, which currently are accounted for under the equity method. The Xcel Energy utility subsidiaries are party to purchased power agreements, and based on the current guidance, these contracts are not expected to be considered variable interest arrangements under the provisions of FIN No. 46. However, Xcel Energy is still evaluating the issue. Additionally, Xcel Energy is evaluating other arrangements based on criteria in FIN No. 46, and it is likely that some arrangements will require consolidation.

As of Dec. 31, 2003, the assets of the affordable housing investments were approximately $142 million and long-term liabilities were approximately $78 million. Currently, investments of $56 million are reflected as a component of investments in unconsolidated affiliates in the Consolidated Balance Sheet for Dec. 31, 2003. FIN No. 46 requires that for entities to be consolidated, the entities’ assets be initially recorded at their carrying amounts at the date the new requirement first applies. If determining carrying amounts as required is impractical, then the assets are to be measured at fair value as of the first date the new requirements apply. Any difference between the net consolidated amounts added to Xcel Energy’s balance sheet and the amount of any previously recognized interest in the newly consolidated entity should be recognized in earnings as the cumulative-effect adjustment of an accounting change. Xcel Energy plans to adopt FIN No. 46 in the first quarter of 2004. The impact of consolidating these entities is not expected to have a material impact on net income.

Reclassifications Certain items in the statements of operations and the balance sheets have been reclassified from prior period presentation to conform to the 2003 presentation. These reclassifications had no effect on net income or earnings per share. The reclassifications were primarily related to organizational changes, such as the divestiture of NRG, and the reclassification of asset retirement obligations from Accumulated Depreciation to a liability account.

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2. Special Charges

Special charges included in Operating Expenses for the years ended Dec. 31, 2003, 2002 and 2001, include the following:

                         
(Millions of dollars)
  2003
  2002
  2001
Regulated utility special charges:
                       
Regulatory recovery adjustment (SPS) (see Note 14)
  $     $ 5     $  
Restaffing (utility and service companies)
          9       39  
Post-employment benefits (PSCo)
                23  
 
   
 
     
 
     
 
 
Total regulated utility special charges
          14       62  
Other nonregulated special charges:
                       
Holding company NRG restructuring charges
    12       5        
TRANSLink Transmission Co.
    7              
 
   
 
     
 
     
 
 
Total nonregulated special charges
    19       5        
 
   
 
     
 
     
 
 
Total special charges
  $ 19     $ 19     $ 62  
 
   
 
     
 
     
 
 

2003 TRANSLink Transmission Co., LLC In 2003, Xcel Energy recorded a $7 million pretax charge in connection with the suspension of the activities related to the formation of TRANSLink Transmission Co., LLC (TRANSLink). The charge was recorded as a reserve against loans made by Xcel Energy Transco Inc., a subsidiary of Xcel Energy, to TRANSLink Development Company, LLC, an interim start-up company. TRANSLink was a for-profit independent transmission-only company proposed to be formed by Xcel Energy and several other utilities to integrate the operations of their electric transmission systems into a single system. The formation activity was suspended due to continued market and regulatory uncertainty.

2003 and 2002 Holding Company NRG Restructuring Charges In 2003 and 2002, the Xcel Energy holding company incurred approximately $12 million and $5 million, respectively, for charges related to NRG’s financial restructuring. Costs in 2003 included approximately $32 million of financial advisor fees, legal costs and consulting costs related to the NRG bankruptcy transaction. These charges were partially offset by a $20 million pension curtailment gain related to the termination of NRG employees from Xcel Energy’s pension plan, as discussed in Note 12 to the Consolidated Financial Statements.

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

2002 and 2001 — Utility Restaffing During 2001, Xcel Energy expensed pretax special charges of $39 million for expected staff consolidation costs for an estimated 500 employees in several utility-operating and corporate-support areas of Xcel Energy. In 2002, the identification of affected employees was completed and additional pretax special charges of $9 million were expensed for the final costs of staff consolidations. Approximately $6 million of these restaffing costs were allocated to Xcel Energy’s utility subsidiaries. All 564 of accrued staff terminations have occurred. See the summary of costs below.

2001 — Post-employment Benefits PSCo adopted accrual accounting for post-employment benefits under SFAS No. 112 — “Employers Accounting for Postemployment Benefits” in 1994. The costs of these benefits had been recorded on a pay-as-you-go basis and, accordingly, PSCo recorded a regulatory asset in anticipation of obtaining future rate recovery of these transition costs. PSCo recovered its FERC jurisdictional portion of these costs. PSCo requested approval to recover its Colorado retail natural gas jurisdictional portion in a 1996 retail-rate case, and its retail electric jurisdictional portion in the electric-earnings test filing for 1997. In the 1996 rate case, the CPUC allowed recovery of post-employment benefit costs on an accrual basis, but denied PSCo’s request to amortize the transition costs’ regulatory asset. Following various appeals, which proved unsuccessful, PSCo wrote off $23 million pretax of regulatory assets related to deferred post-employment benefit costs as of June 30, 2001.

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Accrued Special Charges — The following table summarizes activity related to accrued special charges in 2003, 2002 and 2001:

         
    Utility
(Millions of dollars)
  Severance *
Balance, Dec. 31, 2000
  $ 48  
2001 accruals recorded — restaffing
    39  
Cash payments made in 2001
    (50 )
 
   
 
 
Balance, Dec. 31, 2001
    37  
Adjustments/revisions to prior year accruals
    9  
Cash payments made in 2002
    (33 )
 
   
 
 
Balance, Dec. 31, 2002
    13  
Cash payments made in 2003
    (10 )
 
   
 
 
Balance, Dec. 31, 2003
  $ 3  
 
   
 
 


*   Reported on the balance sheet in Other Current Liabilities.

3. Discontinued Operations

Pursuant to the requirements of SFAS No. 144, Xcel Energy classified and accounted for certain nonregulated assets as held for sale at Dec. 31, 2003 and 2002. SFAS No. 144 requires that assets held for sale are valued on an asset-by-asset basis at the lower of carrying amount or fair value less costs to sell. In applying those provisions, management considered cash flow analyses, bids and offers related to those assets and businesses. As a result, Xcel Energy recorded estimated after-tax losses on disposal of nonregulated assets held for sale, as discussed below, of $59 million for the year ended Dec. 31, 2003. In accordance with the provisions of SFAS No. 144, assets held for sale will not be depreciated commencing with their classification as such.

Due to NRG’s emergence from bankruptcy in December 2003 and Xcel Energy’s corresponding divestiture of its ownership interest in NRG, NRG is now reflected as a discontinued operation at Dec. 31, 2003. Two regulated businesses also were sold during 2003 and have no assets or liabilities remaining at Dec. 31, 2003. Results of operations for these divested businesses, and the results of businesses held for sale, are reported for all periods presented on a net basis as discontinued operations. In addition, the assets and liabilities of the businesses divested in 2003 have been reclassified to corresponding Assets and Liabilities Held for Sale and Related to Discontinued Operations at Dec. 31, 2002 in the accompanying Balance Sheet. The remaining assets and liabilities of businesses still held for sale at Dec. 31, 2003, have been reclassified to the same corresponding amounts for reporting at Dec. 31, 2003 and 2002.

Regulated Natural Gas Utility Segment

During 2003, Xcel Energy completed the sale of two subsidiaries in its regulated natural gas utility segment: Viking, including its interest in Guardian Pipeline, LLC; and BMG. After-tax disposal gains of $23.3 million, or 6 cents per share, were recorded for the natural gas utility segment, primarily related to the sale of Viking.

NRG Segment

Change in Accounting for NRG in 2003 Prior to NRG’s bankruptcy filing in May 2003, Xcel Energy accounted for NRG as a consolidated subsidiary. However, as a result of NRG’s bankruptcy filing, Xcel Energy no longer had the ability to control the operations of NRG. Accordingly, effective as of the bankruptcy filing date, Xcel Energy ceased the consolidation of NRG and began accounting for its investment in NRG using the equity method in accordance with Accounting Principles Board Opinion No. 18 — “The Equity Method of Accounting for Investments in Common Stock.” After changing to the equity method, Xcel Energy was limited in the amount of NRG’s losses subsequent to the bankruptcy date that it was required to record. In accordance with these limitations under the equity method, Xcel Energy stopped recognizing equity in the losses of NRG subsequent to the quarter ended June 30, 2003. These limitations provide for loss recognition by Xcel Energy until its investment in NRG is written off to zero, with further loss recognition to continue if its financial commitments to NRG exist beyond amounts already invested.

Prior to NRG entering bankruptcy, Xcel Energy recorded more losses than the limitations provide for as of June 30, 2003. Upon Xcel Energy’s divestiture of its interest in NRG in December 2003, the NRG losses recorded in excess of Xcel Energy’s investment in and financial commitment to NRG were reversed. This resulted in an adjustment of the total NRG losses recorded for the year 2003 to $251 million. Xcel Energy’s share of NRG’s results for all 2003 periods is reported in a single line item, Equity in Losses of NRG, as a component of discontinued operations. NRG’s 2003 results do reflect some effects of asset impairments and restructuring costs, as discussed below. Xcel Energy’s share of NRG results for 2002 was a loss of $3.4 billion, due primarily to asset impairments and other charges recorded in the third and fourth quarters of 2002 related to NRG’s financial restructuring.

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NRG Asset Impairments In 2002, NRG experienced credit-rating downgrades, defaults under numerous credit agreements, increased collateral requirements and reduced liquidity. These events resulted in impairment reviews of a number of NRG assets in 2002. NRG completed an analysis of the recoverability of the asset-carrying values of its projects each period, factoring in the probability weighting of different courses of action available to NRG, given its financial position and liquidity constraints at the time of each analysis. This approach was applied consistently to asset groups with similar uncertainties and cash flow streams. As a result, NRG determined that many of its construction projects and its operational projects became impaired during 2002 and 2003 and should be written down to fair market value. In applying those provisions, NRG management considered cash flow analyses, bids and offers related to those projects.

NRG’s continuing operations incurred $3.5 billion of asset impairments and estimated disposal losses related to projects and equity investments, respectively, with lower expected cash flows or fair values. These charges recorded by NRG in the third and fourth quarters of 2002 included write-downs of $2.3 billion and $983 million for projects in development and operating projects, respectively, and $196 million for impairment charges and disposal losses related to equity investments.

Approximately $2.5 billion of these NRG impairment charges in 2002 related to NRG assets considered held for use under SFAS No. 144 as of Dec. 31, 2002. For fair values determined by similar asset prices, the fair value represented NRG’s estimate of recoverability at that time, if the project assets were to be sold. For fair values determined by estimated market price, the fair value represented a market bid or appraisal received by NRG that NRG believed was best reflective of fair value at that time. For fair values determined by projected cash flows, the fair value represents a discounted cash flow amount over the remaining life of each project that reflected project-specific assumptions for long-term power pool prices, escalated future project operating costs and expected plant operation given assumed market conditions at that time.

NRG continued to incur asset impairments and related charges in 2003. Prior to its bankruptcy filing in May 2003, NRG recorded more than $500 million in impairment and related charges resulting from planned disposals of an international project and several projects in the United States, and to regulatory developments and changing circumstances throughout the second quarter that adversely affected NRG’s ability to recover the carrying value of certain merchant generation units in the Northeastern United States.

Nonregulated Subsidiaries — All Other Segment

Xcel Energy International and e prime In December 2003, the board of directors of Xcel Energy approved management’s plan to exit the businesses conducted by its nonregulated subsidiaries Xcel Energy International and e prime. 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.

Results of discontinued nonregulated operations in 2003, other than NRG, 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 represents 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. Losses from discontinued nonregulated operations in 2003 also include a charge of $16 million for costs of settling a Commodity Futures Trading Commission trading investigation of e prime.

Results of discontinued nonregulated operations in 2002 were reduced by impairment losses recorded by Xcel Energy International for certain Argentina assets. In 2002, Xcel Energy International decided it would no longer fund one of its power projects in Argentina. This decision resulted in the shutdown of the Argentina plant facility, pending financing of a necessary maintenance outage. Updated cash flow projections for the plant were insufficient to provide recovery of Xcel Energy International’s investment. The project was written down to estimated fair value, based on an appraisal received that is believed to best reflect the assets’ fair value at Dec. 31, 2002. The write-down for this Argentina facility was approximately $13 million.

Results of discontinued nonregulated operations in 2002 also were reduced by a loss on disposal of Xcel Energy International’s remaining investment in Yorkshire Power Group Limited.

Tax Benefits Related to Investment in NRG — With NRG’s emergence from bankruptcy in December 2003, Xcel Energy has divested its ownership interest in NRG and plans to take a tax deduction in 2003. These benefits are reported as discontinued operations.

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During 2002, Xcel Energy recognized tax benefits of $706 million. This benefit was based on the estimated tax basis of Xcel Energy’s cash and stock investments already made in NRG, and their deductibility for federal income tax purposes.

Based on the results of a 2003 study, Xcel Energy recorded $105 million of additional tax benefits in 2003, reflecting an updated estimate of the tax basis of Xcel Energy’s investments in NRG and state tax deductibility. Upon NRG’s emergence from bankruptcy in December 2003, an additional $288 million of tax benefit was recorded to reflect the deductibility of the settlement payment of $752 million, uncollectible receivables from NRG, other state tax benefits and further adjustments to the estimated tax basis in NRG. Another $11 million of state tax benefits were accrued earlier in 2003 based on projected impacts.

Summarized Financial Results of Discontinued Operations

                                 
    Natural Gas           All Other    
(Thousands of dollars)
  Utility Segment
  NRG Segment
  Segment
  Total
2003
                               
Operating revenue
  $ 9,292     $     $ 174,224     $ 183,516  
Operating and other expenses
    7,980             177,487       185,467  
Special charges and impairments
          (1,664 )     58,700       57,036  
Equity in NRG losses
          253,043             253,043  
 
   
 
     
 
     
 
     
 
 
Pretax income (loss) from operations of discontinued components
    1,312       (251,379 )     (61,963 )     (312,030 )
Income tax expense (benefit)
    354             (401,464 )     (401,110 )
 
   
 
     
 
     
 
     
 
 
Income (loss) from operations of discontinued components
    958       (251,379 )     339,501       89,080  
Estimated pretax gain on disposal of discontinued components
    40,072                   40,072  
Income tax expense
    16,780                   16,780  
 
   
 
     
 
     
 
     
 
 
Gain on disposal of discontinued components
    23,292                   23,292  
 
   
 
     
 
     
 
     
 
 
Net income (loss) from discontinued operations
  $ 24,250     $ (251,379 )   $ 339,501     $ 112,372  
 
   
 
     
 
     
 
     
 
 
2002
                               
Operating revenue and equity in project income
  $ 36,266     $ 3,010,557     $ 169,994     $ 3,216,817  
Operating and other expenses
    18,822       3,173,598       161,413       3,353,833  
Special charges and impairments (including net disposal losses)
          3,459,406       26,962       3,486,368  
 
   
 
     
 
     
 
     
 
 
Pretax income (loss) from operations of discontinued components
    17,444       (3,622,447 )     (18,381 )     (3,623,384 )
Income tax expense (benefit)
    7,004       (172,517 )     (706,381 )     (871,894 )
 
   
 
     
 
     
 
     
 
 
Income (loss) from operations of discontinued components
    10,440       (3,449,930 )     688,000       (2,751,490 )
Estimated pretax gain on disposal of discontinued components
          2,814             2,814  
Income tax benefit
          (2,992 )           (2,992 )
 
   
 
     
 
     
 
     
 
 
Gain on disposal of discontinued components
          5,806             5,806  
 
   
 
     
 
     
 
     
 
 
Net income (loss) from discontinued operations
  $ 10,440     $ (3,444,124 )   $ 688,000     $ (2,745,684 )
 
   
 
     
 
     
 
     
 
 
2001
                               
Operating revenue and equity in project income
  $ 31,889     $ 3,013,545     $ 154,113     $ 3,199,547  
Operating and other expenses
    22,392       2,784,978       156,790       2,964,160  
 
   
 
     
 
     
 
     
 
 
Pretax income (loss) from operations of discontinued components
    9,497       228,567       (2,677 )     235,387  
Income tax expense (benefit)
    3,490       33,477       (5,525 )     31,442  
 
   
 
     
 
     
 
     
 
 
Net income from discontinued operations
  $ 6,007     $ 195,090     $ 2,848     $ 203,945  
 
   
 
     
 
     
 
     
 
 

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The major classes of assets and liabilities held for sale and related to discontinued operations as of Dec. 31 are as follows:

                 
(Thousands of dollars)
  2003
  2002
Cash
  $ 35,039     $ 440,484  
Trade receivables — net
    42,759       452,804  
Derivative instruments valuation — at market
    2,957       85,436  
Deferred income tax benefits
    580,626        
Other current assets
    22,729       760,079  
 
   
 
     
 
 
Current assets held for sale
    684,110       1,738,803  
 
   
 
     
 
 
Property, plant and equipment — net
    27,983       7,248,589  
Derivative instruments valuation — at market
    102       179,534  
Deferred income tax benefits
    314,670       706,000  
Other noncurrent assets
    10,871       2,196,774  
 
   
 
     
 
 
Noncurrent assets held for sale
    353,626       10,330,897  
 
   
 
     
 
 
Current portion of long-term debt
          7,643,654  
Accounts payable — trade
    51,076       756,732  
NRG settlement payments
    752,000        
Derivative instruments valuation — at market
    3,372       27,247  
Other current liabilities
    14,058       1,497,992  
 
   
 
     
 
 
Current liabilities held for sale
    820,506       9,925,625  
 
   
 
     
 
 
Long-term debt
          1,231,364  
Deferred income tax
    800       225,154  
Derivative instruments valuation — at market
    77       104,218  
Minority interest
    5,363       34,466  
Other noncurrent liabilities
    1,231       240,886  
 
   
 
     
 
 
Noncurrent liabilities held for sale
  $ 7,471     $ 1,836,088  
 
   
 
     
 
 

4. NRG Restructuring, Bankruptcy and Reorganization

In December 2001, Moody’s placed NRG’s long-term senior unsecured debt rating on review for possible downgrade. In February 2002, in response to this threat to NRG’s investment grade rating, Xcel Energy announced a financial improvement plan for NRG, which included an initial step of acquiring 100 percent of NRG through a tender offer and merger involving a tax-free exchange of 0.50 shares of Xcel Energy common stock for each outstanding share of NRG common stock. The exchange transaction was completed on June 3, 2002. In addition, the initial plan included: financial support to NRG from Xcel Energy; marketing certain NRG generating assets for possible sale; canceling and deferring capital spending for NRG projects; and combining certain of NRG’s functions with Xcel Energy’s systems and organization. During 2002, Xcel Energy provided NRG with $500 million of cash infusions.

Xcel Energy’s reacquisition of all of the 26 percent of NRG shares not then owned by Xcel Energy was accounted for as a purchase. The 25,764,852 shares of Xcel Energy stock issued were valued at $25.14 per share, based on the average market price of Xcel Energy shares for three days before and after April 4, 2002, when the revised terms of the exchange were announced and recommended by the independent members of the NRG board of directors. Including other costs of acquisition, this resulted in a total purchase price to acquire NRG’s shares of approximately $656 million. The process to allocate the purchase price to underlying interests in NRG assets, and to determine fair values for the interests in assets acquired, resulted in approximately $62 million of amounts being allocated to fixed assets related to projects where the fair values were in excess of carrying values, to prepaid pension assets and to other assets.

The continued financial difficulties at NRG, resulting primarily from lower prices for power and declining credit ratings, culminated in NRG and certain of its affiliates filing, on May 14, 2003, 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. NRG’s filing included its plan of reorganization and the terms of the overall settlement among NRG, Xcel Energy and members of NRG’s major creditor constituencies that provided for payments by

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Xcel Energy to NRG and its creditors of $752 million. NRG’s creditors and the bankruptcy court approved the plan of reorganization, and on Dec. 5, 2003, NRG completed reorganization and emerged from bankruptcy. As part of the reorganization, Xcel Energy completely divested its ownership interest in NRG, which in turn issued new common equity to its creditors. The other principal terms of the overall settlement include the following:

    Xcel Energy will pay $752 million to NRG to settle all claims of NRG against Xcel Energy and claims of NRG creditors against Xcel Energy under the NRG plan of reorganization:

    —   $400 million paid on Feb. 20, 2004, including $112 million to NRG’s bank lenders.
 
    —   $352 million will be paid on April 30, 2004, unless at such time Xcel Energy has not received tax refunds equal to at least $352 million associated with the loss on its investment in NRG. To the extent such refunds are less than the required payments, the difference between the required payments and those refunds would be due on May 30, 2004.
 
    —   In return for such payments, Xcel Energy received, or was granted, voluntary and involuntary releases from NRG and its creditors.

    Xcel Energy’s exposure on any guarantees, indemnities or other credit-support obligations incurred by Xcel Energy for the benefit of NRG or any NRG subsidiary was terminated, or other arrangements satisfactory to Xcel Energy and NRG were made, such that Xcel Energy has no further exposure, and any cash collateral posted by Xcel Energy has been returned.
 
    As part of the settlement, any intercompany claims of Xcel Energy against NRG or any subsidiary arising from the provision of goods or services or the honoring of any guarantee were paid in full and in cash in the ordinary course, except that the agreed amount of certain intercompany claims arising or accrued as of Jan. 31, 2003 (approximately $50 million), were reduced to $10 million. The $10 million agreed amount has been satisfied with an unsecured promissory note of NRG in the principal amount of $10 million with a maturity of 30 months and an annual interest rate of 3 percent.
 
    NRG and its subsidiaries will not be reconsolidated with Xcel Energy or any of its other affiliates for tax purposes at any time after their March 2001 federal tax deconsolidation (except to the extent required by state or local tax law) or treated as a party to or otherwise entitled to the benefits of any existing tax-sharing agreement with Xcel Energy. However, NRG and certain subsidiaries would continue to be treated substantially as they were under the December 2000 tax allocation agreement to the extent they remain part of a consolidated or combined state tax group that includes Xcel Energy, and with respect to any adjustments to pre-March 2001 federal tax periods. Under the settlement agreement, NRG will not be entitled to any tax benefits associated with the tax loss Xcel Energy expects to recognize as a result of the cancellation of its stock in NRG on the effective date of the NRG plan of reorganization.

5. Short-Term Borrowings

Notes Payable At Dec. 31, 2003 and 2002, Xcel Energy and its continuing subsidiaries had approximately $59 million and $504 million, respectively, in notes payable to banks. The weighted average interest rate at Dec. 31, 2003, was 3.97 percent.

Credit Facilities As of Dec. 31, 2003, Xcel Energy had the following credit facilities available:

                 
                Credit Line
    Maturity
  Term
  Credit Line
  Available
Xcel Energy
  November 2005   5 years   $400 million   $381 million
NSP-Minnesota
  May 2004   364 days   $275 million   $175 million
PSCo
  May 2004   364 days   $350 million   $349 million
SPS
  February 2004   364 days   $100 million   $97 million
Other subsidiaries
  Various   Various   $65 million   $65 million

The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit, and, depending on credit ratings, support for commercial paper borrowings. Of the notes payable to banks, $58 million was drawn on the lines of credit at Dec. 31, 2003 and reduced the amounts available under these credit lines. Also, $95.5 million of letters of credit were outstanding at Dec. 31, 2003, as discussed in Note 15 to the Consolidated Financial Statements, of which approximately $65 million were outstanding under the various credit facilities, which further reduced amounts available under the lines. The credit facilities of NSP-Minnesota and PSCo are secured, while all other facilities are unsecured.

The SPS $100 million facility expired in February 2004 and was replaced with a $125 million unsecured, 364-day credit agreement.

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The borrowing rates under these lines of credit are based on either the bank’s published base rate or the applicable London Interbank Offered Rate (LIBOR) plus a euro dollar rate margin.

6. Long-Term Debt

Except for SPS and other minor exclusions, all property of the utility subsidiaries is subject to the liens of their first mortgage indentures, which are contracts between the companies and their bondholders. In addition, certain SPS payments under its pollution-control obligations are pledged to secure obligations of the Red River Authority of Texas.

The utility subsidiaries’ first mortgage bond indentures provide for the ability to have sinking-fund requirements. Annual sinking-fund requirements at Cheyenne are $0.2 million and must be satisfied with cash payments. NSP-Minnesota, NSP-Wisconsin, PSCo and SPS have no sinking-fund requirements for current bonds outstanding.

NSP-Minnesota’s 2011 series bonds were redeemable upon seven-days notice at the option of the bondholder. Because the terms allowed the holders to redeem these bonds on short notice, the bonds were classified as a current portion of long-term debt reported under current liabilities on the balance sheet for the year ended Dec. 31, 2002. The bonds were redeemed in October 2003.

Xcel Energy’s 2007 and 2008 series convertible senior notes are convertible into shares of Xcel Energy common stock at a conversion price of $12.33 per share. Conversion is at the option of the holder at any time prior to maturity.

Maturities of long-term debt are:

         
2004
  $160 million
2005
  $224 million
2006
  $838 million
2007
  $340 million
2008
  $655 million

7. Preferred Stock

At Dec. 31, 2003, Xcel Energy had six series of preferred stock outstanding, which were callable at its option at prices ranging from $102.00 to $103.75 per share plus accrued dividends. Xcel Energy can only pay dividends on its preferred stock from retained earnings absent approval of the SEC under PUHCA. See Note 11 to the Consolidated Financial Statements for a description of such restrictions.

The holders of the $3.60 series preferred stock are entitled to three votes for each share held. The holders of the other preferred stocks are entitled to one vote per share. In the event dividends payable on the preferred stock of any series outstanding is in arrears in an amount equal to four quarterly dividends, the holders of preferred stocks, voting as a class, are entitled to elect the smallest number of directors necessary to constitute a majority of the board of directors. The holders of common stock, voting as a class, are entitled to elect the remaining directors.

The charters of some of Xcel Energy’s subsidiaries also authorize the issuance of preferred shares. However, at Dec. 31, 2003, there are no such shares outstanding. This chart shows data for first- and second-tier subsidiaries:

                         
    Preferred Shares           Preferred Shares
    Authorized
  Par Value
  Outstanding
Cheyenne
    1,000,000     $ 100.00     None
SPS
    10,000,000     $ 1.00     None
PSCo
    10,000,000     $ 0.01     None

8. Mandatorily Redeemable Preferred Securities of Subsidiary Trusts

Southwestern Public Service Capital I, a wholly owned, special-purpose subsidiary trust of SPS, had $100 million of 7.85-percent trust preferred securities issued and outstanding that were originally scheduled to mature in 2036. Distributions paid by the subsidiary trust on the preferred securities were financed through interest payments on debentures issued by SPS and held by the subsidiary trust, which were eliminated in consolidation. Distributions and redemption payments were guaranteed by SPS. The securities were redeemable at the

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option of SPS after October 2001, at 100 percent of the principal amount plus accrued interest. On Oct. 15, 2003, SPS redeemed the $100 million of trust preferred securities. A certificate of cancellation was filed to dissolve SPS Capital I on Jan. 5, 2004.

NSP Financing I, a wholly owned, special-purpose subsidiary trust of NSP-Minnesota, had $200 million of 7.875-percent trust preferred securities issued and outstanding that were originally scheduled to mature in 2037. Distributions paid by the subsidiary trust on the preferred securities were financed through interest payments on debentures issued by NSP-Minnesota and held by the subsidiary trust, which were eliminated in consolidation. Distributions and redemption payments were guaranteed by NSP-Minnesota. The preferred securities were redeemable at NSP Financing I’s option at $25 per share, beginning in 2002. On July 31, 2003, NSP-Minnesota redeemed the $200 million of trust preferred securities. A certificate of cancellation was filed to dissolve NSP Financing I on Sept. 15, 2003.

PSCo Capital Trust I, a wholly owned, special-purpose subsidiary trust of PSCo, had $194 million of 7.60-percent trust preferred securities issued and outstanding that were originally scheduled to mature in 2038. Distributions paid by the subsidiary trust on the preferred securities were financed through interest payments on debentures issued by PSCo and held by the subsidiary trust, which were eliminated in consolidation. Distributions and redemption payments were guaranteed by PSCo. The securities were redeemable at the option of PSCo after May 2003, at 100 percent of the principal amount outstanding plus accrued interest. On June 30, 2003, PSCo redeemed the $194 million of trust preferred securities. A certificate of cancellation was filed to dissolve PSCo Capital Trust I on Dec. 29, 2003.

The mandatorily redeemable preferred securities of subsidiary trusts were consolidated in Xcel Energy’s Consolidated Balance Sheets. Distributions paid to preferred security holders were reflected as a financing cost in the Consolidated Statements of Operations, along with interest charges.

9. Joint Plant Ownership

Following are the investments by Xcel Energy’s subsidiaries in jointly owned plants and the related ownership percentages as of Dec. 31, 2003:

                                 
                    Construction    
  Plant in   Accumulated   Work in    
(Thousands of dollars)
  Service
  Depreciation
  Progress
  Ownership %
NSP-Minnesota
                               
Sherco Unit 3
  $ 617,343     $ 311,252     $ 500       59.0  
Transmission facilities, including substations
    2,761       843             59.0  
 
   
 
     
 
     
 
         
Total NSP-Minnesota
  $ 620,104     $ 312,095     $ 500          
 
   
 
     
 
     
 
         
PSCo
                               
Hayden Unit 1
  $ 85,828     $ 40,764     $       75.5  
Hayden Unit 2
    79,818       43,834       76       37.4  
Hayden Common Facilities
    27,614       4,010       1,017       53.1  
Craig Units 1 & 2
    58,224       30,876       80       9.7  
Craig Common Facilities Units 1, 2 & 3
    19,109       9,246       9,935       6.5-9.7  
Transmission facilities, including substations
    112,594       40,779       18,380       42.0-73.0  
 
   
 
     
 
     
 
         
Total PSCo
  $ 383,187     $ 169,509     $ 29,488          
 
   
 
     
 
     
 
         

NSP-Minnesota is part owner of Sherco 3, an 860-megawatt coal-fueled electric generating unit. NSP-Minnesota is the operating agent under the joint ownership agreement. NSP-Minnesota’s share of operating expenses and construction expenditures are included in the applicable utility components of operating expenses. PSCo’s assets include approximately 320 megawatts of jointly owned generating capacity. PSCo’s share of operating expenses and construction expenditures are included in the applicable utility components of operating expenses. Each of the respective owners is responsible for the issuance of its own securities to finance its portion of the construction costs.

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10. Income Taxes

Xcel Energy’s share of NRG results for current and prior periods is now shown as a component of discontinued operations, due to NRG’s emergence from bankruptcy in December 2003 and Xcel Energy’s corresponding divestiture of its ownership interest in NRG. Accordingly, Xcel Energy’s tax benefits related to its investment in NRG are reported in discontinued operations.

Xcel Energy’s federal net operating loss and tax credit carry forwards are estimated to be $742 million and $70 million, respectively, after considering a two-year carry back of the loss. The carry forward periods expire in 2023. Xcel Energy also has a net operating loss carry forward in some states. The state carry forward periods expire between 2018 and 2023.

Total income tax expense from continuing operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. Following is a table reconciling such differences:

                         
    2003
  2002
  2001
Federal statutory rate
    35.0 %     35.0 %     35.0 %
Increases (decreases) in tax from:
                       
State income taxes, net of federal income tax benefit
    2.2       3.2       3.6  
Life insurance policies
    (3.9 )     (3.3 )     (2.4 )
Tax credits recognized
    (4.2 )     (4.7 )     (2.9 )
Regulatory differences — utility plant items
    0.8       1.5       2.3  
Resolution of income tax audits
    (5.2 )            
Other — net
    (1.0 )     (0.8 )     (1.2 )
 
   
 
     
 
     
 
 
Total effective income tax rate
    23.7       30.9       34.4  
Extraordinary item
                (0.6 )
 
   
 
     
 
     
 
 
Effective income tax rate from continuing operations
    23.7 %     30.9 %     33.8 %
 
   
 
     
 
     
 
 

Income taxes comprise the following expense (benefit) items:

                         
(Thousands of dollars)
  2003
  2002
  2001
Current federal tax expense
  $ 107,770     $ 104,658     $ 305,709  
Current state tax expense
    (1,194 )     19,864       37,185  
Current tax credits
    (15,269 )     (19,079 )     (13,544 )
Deferred federal tax expense
    77,730       129,556       (25,547 )
Deferred state tax expense
    2,104       17,301       13,336  
Deferred investment tax credits
    (12,499 )     (16,686 )     (12,797 )
 
   
 
     
 
     
 
 
Income tax expense excluding extraordinary items
    158,642       235,614       304,342  
Tax expense on extraordinary items
                5,747  
 
   
 
     
 
     
 
 
Total income tax expense from continuing operations
  $ 158,642     $ 235,614     $ 310,089  
 
   
 
     
 
     
 
 

As of Dec. 31, 2002, Xcel Energy management intended to indefinitely reinvest the earnings of the Argentina operations of Xcel Energy International and, therefore, had not provided deferred taxes for the effects of currency devaluations. However, during 2003, the board of directors of Xcel Energy approved management’s plan to exit the business conducted by Xcel Energy International. Accordingly, any tax effects are recorded in discontinued operations.

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The components of Xcel Energy’s net deferred tax liability from continuing operations (current and noncurrent portions) at Dec. 31 were:

                 
(Thousands of dollars)
  2003
  2002
Deferred tax liabilities:
               
Differences between book and tax basis of property
  $ 1,845,091     $ 1,784,754  
Regulatory assets
    243,671       171,292  
Employee benefits and other accrued liabilities
    82,186       63,079  
Partnership income/loss
    23,551       26,778  
Service contracts
    18,757       20,794  
Tax benefit transfer leases
    5,330       10,993  
Other
    35,352       32,086  
 
   
 
     
 
 
Total deferred tax liabilities
  $ 2,253,938     $ 2,109,776  
 
   
 
     
 
 
Deferred tax assets:
               
Deferred investment tax credits
  $ 61,394     $ 66,472  
Other comprehensive income
    55,525       70,703  
Regulatory liabilities
    43,816       47,579  
Net operating loss carry forward
    35,890        
Tax credit carry forward
    11,668        
Other
    19,778       27,538  
 
   
 
     
 
 
Total deferred tax assets
  $ 228,071     $ 212,292  
 
   
 
     
 
 
Net deferred tax liability
  $ 2,025,867     $ 1,897,484  
 
   
 
     
 
 

11. Common Stock and Incentive Stock Plans

Common Stock and Equivalents Xcel Energy has common stock equivalents consisting of convertible senior notes and options, as discussed further.

The dilutive impacts of common stock equivalents affected earnings per share as follows for the years ending Dec. 31:

                                                                         
    2003   2002   2001
(Shares and dollars in thousands, except
per share amounts)
                  Per Share                   Per Share                   Per Share
    Income
  Shares
  Amount
  Income
  Shares
  Amount
  Income
  Shares
  Amount
Income from continuing operations
  $ 510,020                     $ 527,693                     $ 579,200                  
Less: Dividend requirements on preferred stock
    (4,241 )                     (4,241 )                     (4,241 )                
 
 
 
                   
 
                 
 
       
Basic earnings per share
                                                                       
Income from continuing operations
    505,779       398,765     $ 1.27       523,452       382,051     $ 1.37       574,959       342,952     $ 1.69  
Effect of dilutive securities:
                                                                       
$230 million convertible debt
    11,213       18,654               1,246       2,027                              
$100 million convertible debt
                              445                              
$57.5 million convertible debt
    311       507                                                  
Convertible debt option
          508                                                  
Restricted stock
          464                                                  
Options
          14                     123                     790          
Diluted earnings per share
                                                                       
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
 
Income from continuing operations and assumed conversions
  $ 517,303       418,912     $ 1.23     $ 524,698       384,646     $ 1.37     $ 574,959       343,742     $ 1.68  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
 

Incentive Stock Plans — Xcel Energy and some of its subsidiaries have incentive compensation plans under which stock options and other performance incentives are awarded to key employees. The weighted average number of common and potentially dilutive shares outstanding used to calculate Xcel Energy’s earnings per share include the dilutive effect of stock options and other stock awards

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based on the treasury stock method. The options normally have a term of 10 years and generally become exercisable from three to five years after grant date or upon specified circumstances. The tables below include awards made by Xcel Energy and some of its predecessor companies, adjusted for the merger stock exchange ratio, and are presented on an Xcel Energy share basis.

     Activity in stock options and performance awards was as follows for the years ended Dec. 31:

                                                 
    2003
  2002
  2001
            Average           Average           Average
(Awards in thousands)
  Awards
  Price
  Awards
  Price
  Awards
  Price
Outstanding beginning of year
    16,981     $ 26.29       15,214     $ 25.65       14,259     $ 25.35  
Granted
                            2,581     $ 25.98  
Options transferred from NRG acquisition
                3,328     $ 29.97              
Exercised
    (190 )   $ 12.21       (112 )   $ 20.27       (1,472 )   $ 23.00  
Forfeited
    (580 )   $ 28.48       (1,349 )   $ 28.43       (142 )   $ 27.08  
Expired
    (597 )   $ 23.41       (100 )   $ 28.87       (12 )   $ 24.07  
 
   
 
             
 
             
 
         
Outstanding at end of year
    15,614     $ 26.49       16,981     $ 26.29       15,214     $ 25.65  
 
   
 
             
 
             
 
         
Exercisable at end of year
    9,358     $ 25.59       8,993     $ 24.78       7,154     $ 24.78  
 
   
 
             
 
             
 
         
                         
    Range of Exercise Prices
    $11.50 to $25.50
  $25.51 to $27.00
  $27.01 to $51.25
Options outstanding:
                       
Number outstanding
    3,721,340       7,659,232       4,233,224  
Weighted average remaining contractual life (years)
    4.2       6.3       6.3  
Weighted average exercise price
  $ 20.49     $ 26.29     $ 32.13  
Options exercisable:
                       
Number exercisable
    3,594,809       3,794,565       1,968,619  
Weighted average exercise price
  $ 20.58     $ 26.34     $ 33.29  

Certain employees also may be awarded other restricted stock under Xcel Energy incentive plans. Xcel Energy holds restricted stock until restrictions lapse, generally from two to three years from the date of grant. Xcel Energy reinvests dividends on the shares it holds while restrictions are in place. Restrictions also apply to the additional shares acquired through dividend reinvestment. Restricted shares have a value equal to the market trading price of Xcel Energy’s stock at the grant date. Xcel Energy did not grant any restricted shares in 2003. Xcel Energy granted 50,083 restricted shares in 2002 when the grant-date market price was $22.83 and 21,774 restricted shares in 2001 when the grant-date market price was $26.06. Compensation expense related to these awards was immaterial.

On March 28, 2003, the compensation and nominating committee of Xcel Energy’s board of directors did grant restricted stock units and performance shares under the Xcel Energy omnibus incentive plan approved by the shareholders in 2000. No stock options were granted in 2003. Restrictions on the restricted stock units will lapse after one year from the date of grant, upon the achievement of a 27 percent total shareholder return (TSR) for 10 consecutive business days and other criteria relating to Xcel Energy’s common equity ratio. TSR is measured using the market price per share of Xcel Energy common stock, which at the grant date was $12.93, plus common dividends declared after grant date. The TSR was met in the fourth quarter of 2003, and approximately $31 million of compensation expense was recorded at Dec. 31, 2003, based on the expected vesting date (one year after award grant) of March 28, 2004. The remaining costs related to 2003 restricted stock unit awards vesting in 2004 of $10 million will be recorded in the first quarter of 2004. In January 2004, Xcel Energy’s board of directors approved the repurchase of 2.5 million shares of common stock to fulfill the requirements of the restricted stock unit exercise in 2004.

Xcel Energy applies Accounting Principles Board Opinion No. 25 — “Accounting for Stock Issued to Employees,” in accounting for stock-based compensation and, accordingly, no compensation cost is recognized for the issuance of stock options, as the exercise price of the options equals the fair-market value of Xcel Energy’s common stock at the date of grant. In December 2002, the FASB issued SFAS No. 148 — “Accounting for Stock-Based Compensation — Transition and Disclosure,” amending SFAS No. 123 to provide alternative methods of transition for a voluntary change to the fair-value-based method of accounting for stock-based employee compensation, and requiring disclosure in both annual and interim Consolidated Financial Statements about the method used and the effect of the method used on results. The pro forma impact of applying SFAS No. 148 is as follows at Dec. 31:

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(Thousands of dollars)
  2003
  2002
  2001
Net income (loss) — as reported
  $ 622,392     $ (2,217,991 )   $ 794,966  
Less: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects
    (6,223 )     (6,959 )     (3,455 )
 
   
 
     
 
     
 
 
Pro-forma net income
  $ 616,169     $ (2,224,950 )   $ 791,511  
Earnings (loss) per share:
                       
Basic — as reported
  $ 1.55     $ (5.82 )   $ 2.31  
Basic — pro-forma
  $ 1.54     $ (5.84 )   $ 2.30  
Diluted — as reported
  $ 1.50     $ (5.77 )   $ 2.30  
Diluted — pro forma
  $ 1.49     $ (5.79 )   $ 2.29  

The weighted-average fair value of options granted, and the assumptions used to estimate such fair value on the date of grant using the Black-Scholes Option Pricing Model were as follows:

                         
    2003*
  2002*
  2001
Weighted-average fair value per option share at grant date
              $ 2.13  
Expected option life
              3-5 years
Stock volatility
                18 %
Risk-free interest rate
                3.8-4.8 %
Dividend yield
                4.9-5.8 %

*   There were no options granted in 2003 or 2002.

Common Stock Dividends Per Share — Historically, Xcel Energy has paid quarterly dividends to its shareholders. For each of the four quarters of 2003, Xcel Energy paid dividends to its shareholders of $0.1875 per share. For each of the first two quarters of 2002, Xcel Energy paid dividends to its shareholders of $0.375 per share. In each of the third and fourth quarters of 2002, Xcel Energy paid dividends of $0.1875 per share. In making the decision to reduce the dividend, the board of directors considered several factors, including the goal of funding customer growth in the core business through internal cash flow and reducing reliance on debt and equity financings. The board of directors also compared the dividend to utility subsidiary earnings and to the dividend payout of comparable utilities. Dividends on common stock are paid as declared by the board of directors.

Dividend and Other Capital-Related Restrictions Under the PUHCA, unless there is an order from the SEC, a holding company or any subsidiary may declare and pay dividends only out of retained earnings. In May 2003, Xcel Energy received authorization from the SEC to pay an aggregate amount of $152 million of common and preferred dividends out of capital and unearned surplus. Xcel Energy used this authorization to declare and pay approximately $150 million for its first and second quarter dividends in 2003. At Dec. 31, 2003, Xcel Energy’s retained earnings were approximately $369 million, after declaring the third and fourth quarter dividends.

The Articles of Incorporation of Xcel Energy place restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. Under the provisions, dividend payments may be restricted if Xcel Energy’s capitalization ratio (on a holding company basis only and not on a consolidated basis) is less than 25 percent. For these purposes, the capitalization ratio is equal to (i) common stock plus surplus divided by (ii) the sum of common stock plus surplus plus long-term debt. Based on this definition, the capitalization ratio at Dec. 31, 2003, was 83 percent. Therefore, the restrictions do not place any effective limit on Xcel Energy’s ability to pay dividends because the restrictions are only triggered when the capitalization ratio is less than 25 percent or will be reduced to less than 25 percent through dividends (other than dividends payable in common stock), distributions or acquisitions of Xcel Energy common stock.

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In addition, NSP-Minnesota’s first mortgage indenture places certain restrictions on the amount of cash dividends it can pay to Xcel Energy, the holder of its common stock. Even with these restrictions, NSP-Minnesota could have paid more than $815 million in additional cash dividends on common stock at Dec. 31, 2003.

Registered holding companies and certain of their subsidiaries, including Xcel Energy and its utility subsidiaries, are limited, under PUHCA, in their ability to issue securities. Such registered holding companies and their subsidiaries may not issue securities unless authorized by an exemptive rule or order of the SEC. Because Xcel Energy does not qualify for any of the main exemptive rules, it sought and received financing authority from the SEC under PUHCA for various financing arrangements. Xcel Energy’s current financing authority permits it, subject to satisfaction of certain conditions, to issue through June 30, 2005, up to $2.5 billion of common stock and long-term debt and $1.5 billion of short-term debt at the holding company level. Xcel Energy has $2 billion of long-term debt outstanding and common stock, including the $400 million credit facility.

Xcel Energy’s ability to issue securities under the financing authority is subject to a number of conditions. One of the conditions of the financing authority is that Xcel Energy’s ratio of common equity to total capitalization, on a consolidated basis, be at least 30 percent. As of Dec. 31, 2003, such common equity ratio was approximately 43 percent. Additional conditions require that a security to be issued that is rated, be rated investment grade by at least one nationally recognized rating agency. Finally, all outstanding securities (except preferred stock) that are rated must be rated investment grade by at least one nationally recognized rating agency. As of Dec. 31, 2003, Xcel Energy’s senior unsecured debt was considered investment grade by at least one nationally recognized rating agency.

Stockholder Protection Rights Agreement In June 2001, Xcel Energy adopted a Stockholder Protection Rights Agreement. Each share of Xcel Energy’s common stock includes one shareholder protection right. Under the agreement’s principal provision, if any person or group acquires 15 percent or more of Xcel Energy’s outstanding common stock, all other shareholders of Xcel Energy would be entitled to buy, for the exercise price of $95 per right, common stock of Xcel Energy having a market value equal to twice the exercise price, thereby substantially diluting the acquiring person’s or group’s investment. The rights may cause substantial dilution to a person or group that acquires 15 percent or more of Xcel Energy’s common stock. The rights should not interfere with a transaction that is in the best interests of Xcel Energy and its shareholders because the rights can be redeemed prior to a triggering event for $0.01 per right.

12. Benefit Plans and Other Postretirement Benefits

Xcel Energy offers various benefit plans to its benefit employees. Approximately 51 percent of benefiting employees are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2003, NSP-Minnesota had 2,244 and NSP-Wisconsin had 427 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2004 but has been tentatively settled to extend until Dec. 31, 2007. PSCo had 2,167 bargaining employees covered under a collective-bargaining agreement, which expires in May 2006. SPS had 739 bargaining employees covered under a collective-bargaining agreement, which expires in October 2005.

Pension Benefits

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

Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.

Pension Plan Assets Plan assets principally consist of the common stock of public companies, corporate bonds and U.S. government securities. The target range for our pension asset allocation is 75 percent to 80 percent in equity investments, 5 percent to 10 percent in fixed income investments, no cash investments and 10 percent to 15 percent in nontraditional investments, such as real estate, timber ventures, private equity and venture capital.

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The actual composition of pension plan assets at Dec. 31 was:

                 
    2003
  2002
Equity securities
    75 %     68 %
Debt securities
    14       16  
Real estate
    3        
Cash
          4  
Nontraditional investments
    8       12  
 
   
 
     
 
 
 
    100 %     100 %

During 2003, Xcel Energy entered into a number of hedging arrangements within the pension trust designed to provide protection from a loss of asset value in the event of a broad decline in equity prices. These arrangements are expected to expire at the end of 2004. At Dec. 31, 2003, the mark-to-market value of these arrangements was not material to the value of pension trust assets.

Xcel Energy bases its investment-return assumption on expected long-term performance for each of the investment types included in its pension asset portfolio. Xcel Energy considers the actual historical returns achieved by its asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. The historical weighted average annual return for the past 20 years for the Xcel Energy portfolio of pension investments is 12.7 percent, which is in excess of the current assumption level. The pension cost determinations assume the continued current mix of investment types over the long-term. The Xcel Energy portfolio is heavily weighted toward equity securities, includes nontraditional investments that can provide a higher-than-average return, and in 2003 includes derivative financial instruments intended to hedge the risk of potentially volatile performance of other investments. As is the experience in recent years, a higher weighting in equity investments can increase the volatility in the return levels actually achieved by pension assets in any year. Investment returns in 2001 and 2002 were below the assumed level of 9.5 percent, but in 2003 investment returns exceeded the assumed level of 9.25 percent. Xcel Energy continually reviews its pension assumptions. In 2004, Xcel Energy has changed the investment-return assumption to 9.0 percent to reflect the changing expectations of investment experts in the marketplace.

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Benefit Obligations A comparison of the actuarially computed pension-benefit obligation and plan assets, on a combined basis, is presented in the following table:

                 
(Thousands of dollars)   2003
  2002
Accumulated Benefit Obligation at Dec. 31
  $ 2,512,138     $ 2,381,214  
Change in Projected Benefit Obligation
               
Obligation at Jan. 1
  $ 2,505,576     $ 2,409,186  
Service cost
    67,449       65,649  
Interest cost
    170,731       172,377  
Acquisitions
          7,848  
Plan amendments
    85,937       3,903  
Actuarial loss
    82,197       65,763  
Settlements
    (9,546 )     (994 )
Special termination benefits
          4,445  
Curtailment gain
    (26,407 )      
Benefit payments
    (243,446 )     (222,601 )
 
   
 
     
 
 
Obligation at Dec. 31
  $ 2,632,491     $ 2,505,576  
 
   
 
     
 
 
Change in Fair Value of Plan Assets
               
Fair value of plan assets at Jan. 1
  $ 2,639,963     $ 3,267,586  
Actual return on plan assets
    605,978       (404,940 )
Employer contributions
    31,712       912  
Settlements
    (9,546 )     (994 )
Benefit payments
    (243,446 )     (222,601 )
 
   
 
     
 
 
Fair value of plan assets at Dec. 31
  $ 3,024,661     $ 2,639,963  
 
   
 
     
 
 
Funded Status of Plans at Dec. 31
               
Net asset
  $ 392,170     $ 134,387  
Unrecognized transition asset
    (7 )     (2,003 )
Unrecognized prior service cost
    273,725       224,651  
Unrecognized (gain) loss
    9,710       182,927  
 
   
 
     
 
 
Net pension amounts recognized on Consolidated Balance Sheets
  $ 675,598     $ 539,962  
 
   
 
     
 
 
Prepaid pension asset recorded (a)
  $ 567,227     $ 466,229  
Intangible asset recorded — prior service costs
    5,816       6,943  
Minimum pension liability recorded
    (55,528 )     (106,897 )
Accumulated other comprehensive income recorded — pretax
    158,083       173,687  
Measurement Date
  Dec. 31, 2003   Dec. 31, 2002
Significant Assumptions Used to Measure Benefit Obligations
               
Discount rate for year-end valuation
    6.25 %     6.75 %
Expected average long-term increase in compensation level
    3.50 %     4.00 %

(a)   $19.9 million of the 2003 prepaid pension asset relates to Xcel Energy’s remaining obligation for companies that are now classified as discontinued operations, and $17.5 million of the 2002 prepaid pension asset relates to such discontinued operations.

During 2002, one of Xcel Energy’s pension plans became under-funded, and at Dec. 31, 2003, had projected benefit obligations of $653.1 million, which exceeds plan assets of $563.8 million. All other Xcel Energy plans in the aggregate had plan assets of $2.5 billion and projected benefit obligations of $2.0 billion on Dec. 31, 2003. A minimum pension liability of $55.5 million was recorded related to the under-funded plan as of that date. A corresponding reduction in Accumulated Other Comprehensive Income, a component of Stockholders’ Equity, also was recorded, as previously recorded prepaid pension assets were reduced to record the minimum liability.

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Net of the related deferred income tax effects of the adjustments, total Stockholders’ Equity was reduced by $98.1 million at Dec. 31, 2003, due to the minimum pension liability for the under-funded plan.

A retirement spending account and Social Security supplement for former New Century Energies, Inc. nonbargaining employees was added July 1, 2003, to align it with the Xcel Energy plan formula. Also, the Normal Retirement Age for Xcel Energy’s traditional, account balance, and “pension equity” programs was changed to age 65 with one year of service.

Cash Flows Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other pertinent calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding in the years 2001 through 2003 for Xcel Energy’s pension plans, and is not expected to require cash funding in 2004. PSCo elected to make a voluntary contribution of $30 million to its pension plan for bargaining employees in 2003, and it plans to voluntarily contribute another $10 million to the plan in 2004.

Benefit Costs — The components of net periodic pension cost (credit) are:

                         
(Thousands of dollars)
  2003
  2002
  2001
Service cost
  $ 67,449     $ 65,649     $ 57,521  
Interest cost
    170,731       172,377       172,159  
Expected return on plan assets
    (322,011 )     (339,932 )     (325,635 )
Curtailment (gain) loss
    (17,363 )           1,121  
Settlement (gain) loss
    (1,135 )            
Amortization of transition asset
    (1,996 )     (7,314 )     (7,314 )
Amortization of prior service cost
    28,230       22,663       20,835  
Amortization of net gain
    (44,825 )     (69,264 )     (72,413 )
 
   
 
     
 
     
 
 
Net periodic pension cost (credit) under SFAS No. 87 (a)
    (120,920 )     (155,821 )     (153,726 )
Credits not recognized due to effects of regulation
    51,311       71,928       76,509  
 
   
 
     
 
     
 
 
Net benefit cost (credit) recognized for financial reporting
  $ (69,609 )   $ (83,893 )   $ (77,217 )
 
   
 
     
 
     
 
 
Significant Assumptions Used to Measure Costs
                       
Discount rate
    6.75 %     7.25 %     7.75 %
Expected average long-term increase in compensation level
    4.00 %     4.50 %     4.50 %
Expected average long-term rate of return on assets
    9.25 %     9.50 %     9.50 %

(a)     Includes pension credits related to discontinued operations of $18.7 million for 2003, $9.6 million for 2002, and $8.2 million for 2001. The 2003 credit is largely due to a $20.0 million curtailment gain related to termination of NRG employees as a result of the divestiture of NRG in December 2003.

Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2004 pension cost calculations will be 9.0 percent. The cost calculation uses a market-related valuation of pension assets, which reduces year-to-year volatility by recognizing the differences between assumed and actual investment returns over a five-year period.

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

Defined Contribution Plans

Xcel Energy maintains 401(k) and other defined contribution plans that cover substantially all employees. Total contributions to these plans were approximately $15.9 million in 2003, $18.3 million in 2002, and $29.0 million in 2001.

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

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In May 2002, the ESOP was terminated and its assets were combined into the Xcel Energy retirement savings 401(k) Plan. The ESOP component of the 401(k) plan is no longer leveraged.

Xcel Energy’s leveraged ESOP held 10.7 million shares of Xcel Energy common stock at May 6, 2002, and 10.5 million shares of Xcel Energy common stock at the end of 2001. Xcel Energy excluded an average of 0.7 million in 2002 and 0.9 million in 2001 of uncommitted leveraged ESOP shares from earnings-per-share calculations. On Nov. 19, 2002, Xcel Energy paid off all of the ESOP loans. All uncommitted ESOP shares were released and were used by Xcel Energy for the 2002 employer matching contribution to its 401(k) plan.

Postretirement Health Care Benefits

Xcel Energy has contributory health and welfare benefit plans that provide health care and death benefits to most Xcel Energy retirees. The former NSP discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees of NSP-Minnesota and NSP-Wisconsin who retired after 1999. Xcel Energy discontinued contributing toward health care benefits for former NCE nonbargaining employees retiring after June 30, 2003. Employees of the former NCE who retired in 2002 continue to receive employer-subsidized health care benefits. Nonbargaining employees of the former NSP who retired after 1998; bargaining employees of the former NSP who retired after 1999; and nonbargaining employees of the former NCE who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy.

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

Regulatory agencies for nearly all of Xcel Energy’s retail and wholesale utility customers have allowed rate recovery of accrued benefit costs under SFAS No. 106. PSCo transitioned to full accrual accounting for SFAS No. 106 costs between 1993 and 1997, consistent with the accounting requirements for rate-regulated enterprises. The Colorado jurisdictional SFAS No. 106 costs deferred during the transition period are being amortized to expense on a straight-line basis over the 15-year period from 1998 to 2012. NSP-Minnesota also transitioned to full accrual accounting for SFAS No. 106 costs, with regulatory differences fully amortized prior to 1997.

Plan Assets Certain state agencies that regulate Xcel Energy’s utility subsidiaries also have issued guidelines related to the funding of SFAS No. 106 costs. SPS is required to fund SFAS No. 106 costs for Texas and New Mexico jurisdictional amounts collected in rates, and PSCo is required to fund SFAS No. 106 costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. Minnesota and Wisconsin retail regulators required external funding of accrued SFAS No. 106 costs to the extent such funding was tax advantaged. The investment strategy for the postretirement health care fund assets is fairly conservative, with minimal exposure to equity markets and a focus on fixed income and cash equivalents to preserve investment capital while earning modest income.

The actual composition of postretirement benefit plan assets at Dec. 31 was:

                 
    2003
  2002
Fixed income/debt securities.
    2 %     2 %
Equity mutual fund securities
    14       12  
Cash equivalents
    84       85  
Other
          1  
     
     
 
 
    100 %     100 %

Xcel Energy bases its investment-return assumption for the postretirement health care fund assets on expected long-term performance for each of the investment types included in its postretirement health care asset portfolio. Given the fairly short time period in which funding has been required, Xcel Energy does not consider the actual historical returns achieved by its postretirement health care fund asset portfolio to be significant in establishing long-term return assumptions. Instead, Xcel Energy considers the long-term return levels projected and recommended by investment experts, weighted for the target mix of asset categories in our portfolio. Investment-return volatility is not considered to be a material factor in postretirement health care costs.

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

                 
(Thousands of dollars)
  2003
  2002
Change in Benefit Obligation
               
Obligation at Jan. 1
  $ 767,975     $ 687,455  
Service cost
    5,893       7,173  
Interest cost
    52,426       50,135  
Acquisitions/(divestitures)
    (31,584 )     773  
Plan amendments
    (33,304 )      
Plan participants’ contributions
    16,577       5,755  
Actuarial loss
    122,864       61,276  
Special termination benefits
          (173 )
Curtailments
    (249 )      
Benefit payments
    (60,754 )     (44,419 )
Impact of Medicare Prescription Drug, Improvement and Modernization Act of 2003
    (64,614 )      
 
   
 
     
 
 
Obligation at Dec. 31
  $ 775,230     $ 767,975  
 
   
 
     
 
 
Change in Fair Value of Plan Assets
               
Fair value of plan assets at Jan. 1
  $ 250,983     $ 242,803  
Actual return on plan assets
    11,045       (13,632 )
Plan participants’ contributions
    16,577       5,755  
Employer contributions
    68,010       60,476  
Benefit payments
    (60,754 )     (44,419 )
 
   
 
     
 
 
Fair value of plan assets at Dec. 31
  $ 285,861     $ 250,983  
 
   
 
     
 
 
Funded Status at Dec. 31
               
Net obligation
  $ 489,369     $ 516,992  
Unrecognized transition asset (obligation)
    (69,164 )     (169,328 )
Unrecognized prior service cost
    20,093       10,904  
Unrecognized gain (loss)
    (319,788 )     (206,601 )
 
   
 
     
 
 
Accrued benefit liability recorded (a)
  $ 120,510     $ 151,967  
 
   
 
     
 
 
Measurement Date
  Dec. 31, 2003   Dec. 31, 2002
Significant Assumptions Used to Measure Benefit Obligations
               
Discount rate for year-end valuation
    6.25 %     6.75 %

(a)   ($0.6) million of the 2003 accrued benefit liability relates to Xcel Energy’s remaining obligation for companies that are now classified as discontinued operations, and $28.3 million of the 2002 accrued benefit liability relates to such discontinued operations.

The assumed health care cost trend rate for 2003 for most Xcel Energy plans is approximately 7.5 percent, decreasing gradually to 5.5 percent in 2007 and remaining level thereafter. A 1-percent change in the assumed health care cost trend rate would have the following effects:

         
(Thousands of dollars)        
1-percent increase in APBO components at Dec. 31, 2003
  $ 95.8  
1-percent decrease in APBO components at Dec. 31, 2003
    (79.4 )
1-percent increase in service and interest components of the net periodic cost
    7.3  
1-percent decrease in service and interest components of the net periodic cost
    (6.0 )

The employer subsidy for retiree medical coverage was eliminated for former New Century Energies, Inc. non-bargaining employees who retire after July 1, 2003.

Xcel Energy’s subsidiary Viking Gas Transmission Co. was sold on Jan. 17, 2003. The sale created a one-time curtailment gain of $0.8 million. NRG participants withdrew from the retiree life plan, resulting in a $1.3 million one-time curtailment gain in 2003.

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NRG employees’ participation in the Xcel Energy postretirement health care plan ended when NRG emerged from bankruptcy on Dec. 5, 2003. A settlement gain of $0.9 million was recognized.

Cash Flows The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy expects to contribute approximately $51.4 million during 2004.

Benefit Costs The components of net periodic postretirement benefit cost are:

                         
(Thousands of dollars)
  2003
  2002
  2001
Service cost
  $ 5,893     $ 7,173     $ 6,160  
Interest cost
    52,426       50,135       46,579  
Expected return on plan assets
    (22,185 )     (21,030 )     (18,920 )
Curtailment (gain) loss
    (2,128 )            
Settlement (gain) loss
    (916 )            
Amortization of transition obligation
    15,426       16,771       16,771  
Amortization of prior service cost (credit)
    (1,533 )     (1,130 )     (1,235 )
Amortization of net loss (gain)
    15,409       5,380       1,457  
 
   
 
     
 
     
 
 
Net periodic postretirement benefit cost (credit) under SFAS No. 106 (a)
    62,392       57,299       50,812  
Additional cost recognized due to effects of regulation
    3,883       4,043       3,738  
 
   
 
     
 
     
 
 
Net cost recognized for financial reporting
  $ 66,275     $ 61,342     $ 54,550  
 
   
 
     
 
     
 
 
Significant assumptions used to measure costs (income)
                       
Discount rate
    6.75 %     7.25 %     7.75 %
Expected average long-term rate of return on assets (pretax)
    8.0%-9.0 %     9.0 %     8.0%-9.5 %

(a)   Includes amounts related to discontinued operations of ($3.0) million of credit in 2003, $2.7 million of cost in 2002, and $2.0 million of cost in 2001.

Impact of 2003 Medicare Legislation On Dec. 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act expanded Medicare to include, for the first time, coverage for prescription drugs. This new coverage is generally effective Jan. 1, 2006. Many of Xcel Energy’s retiree medical programs provide prescription drug coverage for retirees over age 65 with coverage at least equivalent to the benefit to be provided under Medicare. While retirees remain in Xcel Energy’s postretirement health care plan without participating in the new Medicare prescription drug coverage, Medicare will share the cost of Xcel Energy’s plan. This legislation has therefore reduced Xcel Energy’s share of the obligation for future retiree medical benefits.

The postretirement health care benefit obligation shown in the chart previously is the actuarial present value, as of Dec. 31, 2003, of Xcel Energy’s share of future retiree medical benefits attributable to service through the current year. This obligation has been reduced to reflect the effects of this legislation. The FASB has not yet issued authoritative guidance on the method it prefers to reflect the Act in these calculations. In addition, regulations implementing this legislation have not yet been issued by Medicare agencies. As a result, when guidance and regulations are issued, the estimates of future costs and obligations could change and previously estimated information may require revision.

As of Dec. 31, 2003, Xcel Energy had reduced the postretirement health care benefit obligation by $64.6 million due to the expected sharing of the cost of the program by Medicare under the new legislation. Also, beginning in 2004, it is expected that the annual net periodic postretirement benefit cost will be reduced by approximately $10 million as a result of the expected sharing of the cost of the program by Medicare, with similar savings in subsequent years. This reduction includes both the decrease in the cost of future benefits being earned during this year, and an amortization of the benefit obligation reduction, previously noted, over approximately nine years. These estimated reductions do not reflect any changes that may result in future levels of participation in the plan or the associated per capita claims cost due to the availability of prescription drug coverage for Medicare-eligible retirees. Also, in reflecting this legislation, Medicare cost sharing for a plan has been assumed only if Xcel Energy’s projected contribution to the plan is expected to be at least equal to the Medicare Part D basic benefit.

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13. Detail of Interest and Other Income, Net of Nonoperating Expenses

Interest and other income, net of nonoperating expenses, for the years ended Dec. 31, comprises the following:

                         
(Thousands of dollars)
  2003
  2002
  2001
Interest income
  $ 16,589     $ 29,559     $ 21,589  
Equity income in unconsolidated affiliates
    5,628       1,835       7,029  
Gain on disposal of assets
    9,365       10,076       14,696  
Allowance for funds used during construction
    25,338       7,793       6,739  
Other nonoperating income
    3,169       13,937       817  
Interest expense on corporate-owned life insurance
    (24,372 )     (18,523 )     (20,116 )
 
   
 
     
 
     
 
 
Total interest and other income, net of nonoperating expenses
  $ 35,717     $ 44,677     $ 30,754  
 
   
 
     
 
     
 
 

14. Extraordinary Items

SPS In April 2003, New Mexico enacted legislation that repealed its Electric Utility Restructuring Act of 1999, as amended. The implementation of restructuring had been delayed in 2001. The legislation provides that a public utility be entitled to an opportunity to recover its transition costs. Utilities, including SPS, may retain the transition costs as a regulatory asset on their books pending recovery, which shall be completed by January 2010.

In June 2001, the governor of Texas signed legislation postponing the retail competition and restructuring for SPS until at least 2007. This legislation amended the 1999 legislation, Senate Bill No. 7 (SB-7), which provided for retail electric competition beginning in Texas in January 2002. Under the amended legislation, prior PUCT orders issued in connection with the restructuring of SPS are considered null and void. In addition, under the new legislation, SPS is entitled to recover all reasonable and necessary expenditures made or incurred before Sept. 1, 2001, to comply with SB-7.

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

During the fourth quarter of 2001, SPS completed a $500 million, medium-term debt financing. The proceeds were used to reduce short-term borrowings that had resulted from the 2000 defeasance of first mortgage bonds. In its regulatory filings and communications, SPS proposed to amortize its defeasance costs over the five-year life of the refinancing, consistent with historical ratemaking, and has requested incremental rate recovery of $25 million of other restructuring costs in Texas and New Mexico. These nonfinancing restructuring costs have been deferred and are being amortized consistent with rate recovery. Based on these 2001 events, management’s expectation of rate recovery of prudently incurred costs and the corresponding reduced uncertainty surrounding the financial impacts of the delay in restructuring, SPS restored certain regulatory assets totaling $17.6 million as of Dec. 31, 2001, and reported related after-tax extraordinary income of $11.8 million, or 3 cents per share. Regulatory assets previously written off in 2000 were restored only for items currently being recovered in rates and items where future rate recovery is considered probable.

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15. Financial Instruments

Fair Values

The estimated Dec. 31 fair values of Xcel Energy’s recorded financial instruments, separately identifying amounts that are within continuing operations and amounts included related to discontinued operations, are as follows:

                                 
    2003
  2002
    Carrying           Carrying    
(Thousands of dollars)
  Amount
  Fair Value
  Amount
  Fair Value
Continuing Operations:
                               
Mandatorily redeemable preferred securities of subsidiary trust
  $     $     $ 494,000     $ 463,348  
Long-term investments
  $ 828,802     $ 827,375     $ 649,160     $ 647,395  
Notes receivable, including current portion
  $ 12,643     $ 12,643     $ 5,352     $ 5,352  
Long-term debt, including current portion
  $ 6,678,808     $ 7,363,457     $ 5,877,220     $ 6,123,173  
Discontinued Operations:
                               
Long-term investments
  $     $     $ 4,048     $ 4,048  
Notes receivable, including current portion
  $ 826     $ 826     $ 990,815     $ 990,815  
Long-term debt, including current portion
  $     $     $ 8,875,018     $ 6,048,886  

The carrying amount of cash, cash equivalents and short-term investments approximates fair value because of the short maturity of those instruments. The fair values of Xcel Energy’s long-term investments, mainly debt securities in an external nuclear decommissioning fund, are estimated based on quoted market prices for those or similar investments. The fair value of notes receivable is based on expected future cash flows discounted at market interest rates. The balance in notes receivable is primarily a $10 million unsecured note from NRG to Xcel Energy that was part of the NRG bankruptcy settlement for intercompany claims Xcel Energy had against NRG. The term of the note is 30 months and the interest rate is 3 percent. The fair values of Xcel Energy’s long-term debt and mandatorily redeemable preferred securities are estimated based on the quoted market prices for the same or similar issues, or the current rates for debt of the same remaining maturities and credit quality.

The fair value estimates presented are based on information available to management as of Dec. 31, 2003 and 2002. These fair value estimates have not been comprehensively revalued for purposes of these Consolidated Financial Statements since that date, and current estimates of fair values may differ significantly.

Guarantees

Xcel Energy provides guarantees and bond indemnities supporting certain of its subsidiaries. The guarantees issued by Xcel Energy guarantee payment or performance by its subsidiaries under specified agreements or transactions. As a result, Xcel Energy’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees issued by Xcel Energy limit the exposure of Xcel Energy to a maximum amount stated in the guarantee. Unless otherwise indicated below, the guarantees require no liability to be recorded, contain no recourse provisions and require no collateral. On Dec. 31, 2003, Xcel Energy had the following amount of guarantees and exposure under these guarantees, including those related to e prime, which is a component of discontinued operations:

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(Millions of dollars)

                                                 
                                    Triggering    
                            Term or   Event    
            Guarantee   Current   Expiration   Requiring   Assets Held as
Nature of Guarantee
  Guarantor
  Amount
  Exposure
  Date
  Performance
  Collateral
 
                            2004, 2005,                  
Guarantee performance and payment of surety bonds for itself and its
                            2007, 2012, 2014, 2015,                  
subsidiaries (d) (f) (i)
  Xcel Energy   $ 32.3     $ 4.1     and 2022     (e )     N/A  
 
                                           
Guarantee performance and payment of surety bonds for those subsidiaries
  Various subsidiaries (a)(i)   $ 550.8     $ 47.3     2004 and 2005     (e )   $ 20.0  
Guarantees made to facilitate e prime’s natural gas acquisition, marketing and trading operations
  Xcel Energy   $ 47.0     $ 5.0     Continuing     (b )     N/A  
Two guarantees benefiting Cheyenne to guarantee the payment obligations under gas and power purchase agreements
  Xcel Energy   $ 26.5     $     2011 and 2013     (b )     N/A  
Guarantee the indemnification obligations of Xcel Energy Markets Holdings Inc. under a purchase agreement with Border Viking Co.
  Xcel Energy   $ 30.7     $     Continuing     (c )     N/A  
Guarantees for e prime Energy Marketing Inc. and e prime Florida Inc.’s guaranteeing payments of energy, capacity and financial transactions
  Xcel Energy   $ 13.0     $ 0.1     Continuing     (b )     N/A  
Guarantee for payments related to energy or financial transactions for XERS Inc., a nonregulated subsidiary of Xcel Energy
  Xcel Energy   $ 10.0     $ 0.5     Continuing     (b )     N/A  
Guarantee of customer loans to encourage business growth and expansion
  NSP-Wisconsin   $ 0.7     $ 0.2     Latest expiration in 2006     (g )     N/A  
Guarantee of collection of receivables sold to a third party
  NSP-Minnesota   $ 2.1     $ 2.1     Latest expiration in 2007     (b )     (h )
Combination of guarantees benefiting various Xcel Energy subsidiaries
  Xcel Energy   $ 5.9     $     Continuing     (b )     N/A  


(a)   The $47.3 million exposure is related to $550.1 million of performance bonds associated with six construction projects in which Utility Engineering is participating. An estimate of exposure for the remaining bonds cannot be determined as these are largely bonds posted for the benefit of various municipalities relating to the normal course of business activities. Xcel Energy is not obligated under these agreements.
 
(b)   Nonperformance and/or nonpayment.
 
(c)   Losses caused by default in performance of covenants or breach of any warranty or representation in the purchase agreement.
 
(d)   Includes two performance bonds with a notional amount of $13.3 million that guarantee the performance of Planergy Housing Inc., a subsidiary of Xcel Energy that was sold to Ameresco Inc. on Dec. 12, 2003. Ameresco Inc. has agreed to indemnify Xcel Energy for any liability arising out of any surety bond.
 
(e)   Failure of Xcel Energy or one of its subsidiaries to perform under the agreement that is the subject of the relevant bond. In addition, per the indemnity agreement between Xcel Energy and the various surety companies, the surety companies have the discretion to demand that collateral be posted.
 
(f)   Xcel Energy provides indemnity protection for bonds issued for itself and its subsidiaries. There were approximately $32.3 million of bonds with this indemnity outstanding on Dec. 31, 2003, including $4.2 million related to NRG. However, under the NRG bankruptcy settlement, NRG deposited cash with Xcel Energy that, on Feb. 6, 2004, was replaced with a letter of credit such that Xcel Energy has no further exposure under these indemnities.
 
(g)   Non-timely payment of the obligations or at the time the Debtor becomes the subject of bankruptcy or other insolvency proceedings.
 
(h)   Security interest in underlying receivable agreements.
 
(i)   On Jan. 19, 2004, Xcel Energy entered into an agreement with an insurance company for the purpose of indemnifying that insurance company in connection with surety bonds they may issue or have issued for Utility Engineering up to an amount of $80 million. The Xcel Energy indemnification will only be triggered in the event that Utility Engineering has failed to meet its obligations to the surety company.

Fair Value of Derivative Instruments

The following discussion briefly describes the derivatives of Xcel Energy and its subsidiaries and discloses the respective fair values at Dec. 31, 2003 and 2002. For more detailed information regarding derivative financial instruments and the related risks, see Note 16 to the Consolidated Financial Statements.

Interest Rate Swaps Subsidiaries of Xcel Energy had interest rate swaps outstanding with a notional amount of approximately $256 million, and a fair value that was a liability of approximately $18 million, at Dec. 31, 2003. On Dec. 31, 2002, subsidiaries of Xcel Energy had interest rate swaps outstanding with a notional amount of approximately $100 million, and a fair value that was a liability of approximately $12 million.

Electric Trading Operations — Xcel Energy participates in the trading of electricity as a commodity. This trading includes forward contracts, futures and options. Xcel Energy makes purchases and sales at existing market points or combines purchases with available transmission to make sales at other market points. Options and hedges are used to either minimize the risks associated with market prices, or to profit from price volatility related to our purchase and sale commitments.

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Beginning with the third quarter of 2002, Xcel Energy has presented the results of its electric trading activity using the net accounting method. The Consolidated Statement of Operations for 2001 has been reclassified to be consistent. In earlier presentations, the gross accounting method was used. All financial derivative contracts are recorded at the amount of the gain or loss received from the contract. The mark-to-market adjustments for these transactions are reported in the Consolidated Statements of Operations in Electric and Gas Trading Margin.

Regulated Operations — Xcel Energy’s regulated utility energy marketing operations use a combination of electricity and natural gas purchase for resale futures and forward contracts, along with physical supply, to hedge market risks in the energy market. At Dec. 31, 2003, the notional amount of these contracts was approximately 56 million MMBtu of natural gas and 62,400 megawatt-hours of electricity. The fair value of these contracts as of Dec. 31, 2003, was approximately $(11.2) million.

Nonregulated Operations — Xcel Energy’s nonregulated operations use a combination of energy futures and forward contracts, along with physical supply, to hedge market risks in the energy market. At Dec. 31, 2003, the notional amount of these contracts was approximately 6.6 million MMBtu of natural gas. The fair value of these contracts as of Dec. 31, 2003, was approximately $1.5 million. The value of hedges related to nonregulated operations is included in discontinued operations.

Foreign Currency — Xcel Energy and its subsidiaries have no foreign currency swaps to hedge or protect foreign currency denominated cash flows at Dec. 31, 2003.

Letters of Credit

Xcel Energy and its subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2003, there was $95.5 million of letters of credit outstanding. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

16.     Derivative Valuation and Financial Impacts

Use of Derivatives to Manage Risk

Business and Operational Risk — Xcel Energy and its subsidiaries, including discontinued operations held for sale, are exposed to commodity price risk in their generation, retail distribution and energy trading operations. In certain jurisdictions, purchased power expenses and natural gas costs are recovered on a dollar-for-dollar basis. However, in other jurisdictions, Xcel Energy and its subsidiaries are exposed to market price risk for the purchase and sale of electric energy and natural gas. In such jurisdictions, Xcel Energy recovers purchased power expenses and natural gas costs based on fixed price limits or under established sharing mechanisms.

Commodity price risk is managed by entering into purchase and sales commitments for electric power and natural gas, long-term contracts for coal supplies and fuel oil, and derivative financial instruments. Xcel Energy’s risk management policy allows it to manage the market price risk within each rate-regulated operation to the extent such exposure exists. Management is limited under the policy to enter into only transactions that manage market price risk where the rate regulation jurisdiction does not already provide for dollar-for-dollar recovery. One exception to this policy exists in which Xcel Energy and its subsidiaries use various physical contracts and derivative instruments to reduce the volatility in the cost of natural gas and electricity provided to retail customers even though the regulatory jurisdiction provides dollar-for-dollar recovery of actual costs. In these instances, the use of derivative instruments and physical contracts is done consistently with the local jurisdictional cost recovery mechanism.

Xcel Energy and its subsidiaries have been exposed to market price risk for the sale of electric energy and the purchase of fuel resources, including coal, natural gas and fuel oil used to generate the electric energy within its nonregulated operations, primarily through NRG and Xcel Energy International. With the divestiture of NRG and the expected sale of Xcel Energy International, the exposure to market price risk has greatly decreased. Xcel Energy managed this market price risk by entering into firm power sales agreements for approximately 55 percent to

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75 percent of its electric capacity and energy from each generation facility, using contracts with terms ranging from one to 25 years. In addition, Xcel Energy managed the market price risk covering the fuel resource requirements to provide the electric energy by entering into purchase commitments and derivative instruments for coal, natural gas and fuel oil as needed to meet fixed-priced electric energy requirements. Xcel Energy’s risk management policy allows the management of market price risks, and provides guidelines for the level of price risk exposure that is acceptable within the company’s operations.

Interest Rate Risk Xcel Energy and its subsidiaries are subject to the risk of fluctuating interest rates in the normal course of business. Xcel Energy’s policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.

Xcel Energy engages in hedges of cash flow exposure and hedges of fair value exposure. The fair value of interest rate swaps designated as cash flow hedges are initially recorded in Other Comprehensive Income. Reclassification of unrealized gains or losses on cash flow hedges of variable rate debt instruments from Other Comprehensive Income into earnings occurs as interest payments are accrued on the debt instrument and generally offsets the change in the interest accrued on the underlying variable rate debt. Hedges of fair value exposure are entered into to hedge the fair value of a recognized asset, liability or firm commitment. Changes in the derivative fair values that are designated as fair value hedges are recognized in earnings as offsets to the changes in fair values of related hedged assets, liabilities or firm commitments. In order to test the effectiveness of such swaps, a hypothetical swap is used to mirror all the critical terms of the underlying debt and regression analysis is utilized to assess the effectiveness of the actual swap at inception and on an ongoing basis. The assessment is done periodically to ensure the swaps continue to be effective. The fair value of interest rate swaps is determined through counterparty valuations, internal valuations and broker quotes. There have been no material changes in the techniques or models used in the valuation of interest rate swaps during the periods presented.

Currency Exchange Risk During 2003 and 2002, NRG and Xcel Energy International, both of which are included in discontinued operations, held certain investments in foreign countries, exposing them to foreign currency exchange risk. The foreign currency exchange risk included the risk relative to the recovery of net investment in a project, as well as the risk relative to the earnings and cash flows generated from such operations. These subsidiaries managed their exposure to changes in foreign currency by entering into derivative instruments as determined by management. Xcel Energy’s risk management policy provided for this risk management activity.

Trading Risk Xcel Energy’s subsidiaries conduct various trading operations and power marketing activities, including the purchase and sale of electric capacity and energy and, prior to December 2003 through e prime for natural gas. The trading operations are conducted in the United States with primary focus on specific market regions where trading knowledge and experience have been obtained. Xcel Energy’s risk management policy allows management to conduct the trading activity within approved guidelines and limitations as approved by our risk management committee comprising management personnel not involved in the trading operations.

Derivatives as Hedges

Xcel Energy and its subsidiaries record all derivative instruments on the balance sheet at fair value unless exempted, as a normal purchase or sale. Changes in non-exempt derivative instrument’s fair value are recognized currently in earnings unless the derivative has been designated in a qualifying hedging relationship. The application of hedge accounting allows a derivative instrument’s gains and losses to offset related results of the hedged item in the statement of operations, to the extent effective. SFAS No. 133, as amended, requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.

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

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

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Financial Impacts of Derivatives

The impact of the components of hedges, on Xcel Energy’s Other Comprehensive Income, included in the Consolidated Statements of Stockholders’ Equity, are detailed in the following table:

         
(Millions of dollars)
       
Net unrealized transition loss at adoption, Jan. 1, 2001
  $ (28.8 )
After-tax net unrealized gains related to derivatives accounted for as hedges
    43.6  
After-tax net realized losses on derivative transactions reclassified into earnings
    19.4  
 
   
 
 
Accumulated other comprehensive income related to hedges at Dec. 31, 2001
  $ 34.2  
After-tax net unrealized losses related to derivatives accounted for as hedges
    (68.3 )
After-tax net realized losses on derivative transactions reclassified into earnings
    28.8  
Acquisition of NRG minority interest
    27.4  
 
   
 
 
Accumulated other comprehensive income related to hedges at Dec. 31, 2002
  $ 22.1  
After-tax net unrealized gains related to derivatives accounted for as hedges
    24.1  
After-tax net realized gains on derivative transactions reclassified into earnings
    (38.1 )
 
   
 
 
Accumulated other comprehensive income related to hedges at Dec. 31, 2003
  $ 8.1  
 
   
 
 

Xcel Energy records the fair value of its derivative instruments in its Consolidated Balance Sheet as a separate line item identified as Derivative Instruments Valuation for assets and liabilities, as well as current and noncurrent.

Cash Flow Hedges — Xcel Energy and its subsidiaries enter into derivative instruments to manage variability of future cash flows from changes in commodity prices. These derivative instruments are designated as cash flow hedges for accounting purposes, and the changes in the fair value of these instruments are recorded as a component of Other Comprehensive Income. At Dec. 31, 2003, Xcel Energy had various commodity-related contracts deemed as cash flow hedges extending through 2009. Amounts deferred are recorded in earnings as the hedged purchase or sales transaction is settled. This could include the physical purchase or sale of electric energy, the use of natural gas to generate electric energy or gas purchased for resale. As of Dec. 31, 2003, Xcel Energy had net losses of $0.7 million accumulated in Other Comprehensive Income that are expected to be recognized in earnings or deferred as a regulatory liability during the next 12 months as the hedged transactions settle. However, due to the volatility of commodities markets, the value in Other Comprehensive Income will likely change prior to its recognition in earnings or deferral as a regulatory liability.

Xcel Energy recorded gains of $0 and $0.4 million related to ineffectiveness on commodity cash flow hedges during the years ended Dec. 31, 2003 and 2002, respectively.

Xcel Energy and its subsidiaries enter into interest rate swap instruments that effectively fix the interest payments on certain floating rate debt obligations. These derivative instruments are designated as cash flow hedges for accounting purposes, and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. Xcel Energy expects to reclassify into earnings during the next 12 months net losses from Other Comprehensive Income of approximately $1.6 million.

Xcel Energy and its subsidiaries also enter into interest rate lock agreements that effectively fix the yield or price on a specified treasury security for a specific period. These derivative instruments are designated as cash flow hedges for accounting purposes, and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. Xcel Energy expects to reclassify into earnings during the next 12 months net gains from Other Comprehensive Income of approximately $1.4 million.

Hedge effectiveness is recorded based on the nature of the item being hedged. Hedging transactions for the sales of electric energy are recorded as a component of revenue; hedging transactions for fuel used in energy generation are recorded as a component of fuel costs; hedging transactions for gas purchased for resale are recorded as a component of gas costs; and hedging transactions for interest rate swaps and interest rate lock agreements are recorded as a component of interest expense. Certain Xcel Energy utility subsidiaries are allowed to recover in electric or gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.

Fair Value Hedges — Xcel Energy and its subsidiaries enter into interest rate swap instruments that effectively hedge the fair value of fixed rate debt. In June 2003, Xcel Energy entered into two five-year swaps, with a $97.5 million notional value each, against Xcel Energy’s $195 million 3.40 percent senior notes due 2008. Xcel Energy entered into the swaps to obtain greater access to the lower borrowing costs normally available on floating-rate debt. These swap agreements involve the exchange of amounts based on a variable rate of six-month London Interbank Offered Rate (LIBOR) plus an adder rate over the life of the agreement. The difference to be paid or received as interest rates change is accrued and recognized as an adjustment of interest expense related to the debt. The fair market value of Xcel Energy’s interest rate swaps at Dec. 31, 2003, was $(6.3) million.

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Hedges of Foreign Currency Exposure of a Net Investment in Foreign Operations — Due to the discontinuance of NRG and Xcel Energy International’s operations in 2003, as discussed in Notes 3 and 4 to the Consolidated Financial Statements, Xcel Energy no longer has foreign currency exposure.

During 2002, to preserve the U.S. dollar value of projected foreign currency cash flows, Xcel Energy, through NRG, hedged those cash flows if appropriate foreign hedging instruments were available. Xcel Energy recorded unrealized losses of $0.8 million associated with changes in the fair value of non-hedge, foreign currency derivative instruments for the year ended Dec. 31, 2002. In addition, Xcel Energy recorded losses of $2.3 million related to the discontinuance of hedge accounting for the year ended Dec. 31, 2002.

Derivatives Not Qualifying for Hedge Accounting — Xcel Energy and its subsidiaries have trading operations that enter into derivative instruments. These derivative instruments are accounted for on a mark-to-market basis in the Consolidated Statements of Operations. The results of these transactions are recorded within Operating Revenues on the Consolidated Statements of Operations.

Normal Purchases or Normal Sales Contracts — Xcel Energy’s utility subsidiaries enter into contracts for the purchase and sale of various commodities for use in their business operations. SFAS No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that literally meet the definition of a derivative may be exempted from SFAS No. 133, as amended, as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. In addition, normal purchase and normal sales contracts must have a price based on an underlying that is clearly and closely related to the asset being sold or purchased. An underlying is a specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event such as a scheduled payment under a contract. Contracts that meet the requirements of normal are documented and exempted from the accounting and reporting requirements of SFAS No. 133. In June 2003, the Derivatives Implementation Group of FASB issued Implementation Issue No. C20 (C20) to clarify the circumstances when an underlying is not clearly and closely related to the asset being sold or purchased. Xcel Energy’s implementation of C20 in 2003 had no impact on earnings. However, certain contracts did require a one-time fair value adjustment as of Oct. 1, 2003. The result of this adjustment was the creation of a derivative liability with an offsetting regulatory asset to reflect expected recovery of the amounts from customers. The derivative asset and related regulatory liability will be amortized over the respective lives of the contracts. See Note 19 to the Consolidated Financial Statements.

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

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

17.     Commitments and Contingencies

Commitments

Legislative Resource Commitments — In 1994 and 2003, NSP-Minnesota received Minnesota legislative approval for additional on-site temporary spent-fuel storage facilities at its Prairie Island nuclear power plant, provided NSP-Minnesota satisfies certain requirements. The use of 29 dry cask containers has been approved. As of Dec. 31, 2003, NSP-Minnesota had loaded 17 of the containers.

In 1994, as a condition of approving 17 dry cask storage containers, the Minnesota Legislature established several energy resource and other commitments for NSP-Minnesota to obtain the Prairie Island temporary nuclear-fuel storage facility approval. These commitments can be met by building, purchasing or, in the case of biomass, converting generation resources. Other commitments established by the Legislature included a discount for low-income electric customers, required conservation improvement expenditures and various study and reporting requirements to a legislative electric energy task force. NSP-Minnesota has implemented programs to meet the legislative commitments. NSP-Minnesota’s capital commitments include the known effects of the Prairie Island legislation.

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On May 29, 2003, the Minnesota Legislature enacted additional legislation, which will enable NSP-Minnesota to store at least 12 more casks of spent fuel outside the Prairie Island nuclear generating plant. This will allow NSP-Minnesota to continue to operate the facility and store spent fuel there until its licenses with the Nuclear Regulatory Commission (NRC) expire in 2013 and 2014. 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. The legislation requires NSP-Minnesota to add at least 300 megawatts of additional wind power by 2010 with an option to own 100 megawatts of this power.

The legislation also requires payments during the remaining operating life of the Prairie Island plant. These payments include: $2.25 million per year to the Prairie Island Tribal Community beginning in 2004; 5 percent of NSP-Minnesota’s conservation program expenditures (estimated at $2 million per year) to the University of Minnesota for renewable energy research; and an increase in funding commitments to the previously established Renewable Development Fund from $8.5 million in 2002 to $16 million per year beginning in 2003. The legislation also designated $10 million in one-time grants to the University of Minnesota for additional renewable energy research, which is to be funded from commitments already made to the Renewable Development Fund. All of the cost increases to NSP-Minnesota from these required payments and funding commitments are expected to be recoverable in Minnesota retail customer rates, mainly through existing cost recovery mechanisms. Funding commitments to the Renewable Development Fund would terminate after the Prairie Island plant discontinues operation unless the MPUC determines that NSP-Minnesota failed to make a good faith effort to move the waste, in which case NSP-Minnesota would have to make payments in the amount of $7.5 million per year.

Reliability Commitments 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 and annual basis, subject to penalty for not meeting threshold requirements, under the terms of the merger settlement agreements.

In 2003, NSP-Minnesota and the state agencies announced that they had reached a settlement agreement, which was approved with modifications by the MPUC in January 2004. Initially, the settlement requires NSP-Minnesota to refund $1 million to customers in Minnesota, which has been accrued. In addition, it requires NSP-Minnesota to incur at least $15 million of costs for actions to improve system reliability above amounts being currently recovered in rates by Jan. 1, 2005. The MPUC modified the settlement to include an additional under-performance payment for any future finding of inaccurate reliability data. The final order has not yet been issued by the MPUC, and all parties to the settlement have the option to void the settlement in the event of a significant modification to the settlement.

Capital Commitments — As discussed in Liquidity and Capital Resources under Management’s Discussion and Analysis, the estimated cost, as of Dec. 31, 2003, of the capital expenditure programs and other capital requirements of Xcel Energy and its subsidiaries is approximately $1.4 billion in 2004, $1.5 billion in 2005 and $2.1 billion in 2006.

The capital expenditure programs of Xcel Energy are subject to continuing review and modification. Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting Xcel Energy’s long-term energy needs. In addition, Xcel Energy’s ongoing evaluation of restructuring requirements, compliance with future requirements to install emission-control equipment, and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements.

Leases — Xcel Energy and its subsidiaries lease a variety of equipment and facilities used in the normal course of business. Some of these leases qualify as capital leases and are accounted for accordingly. The capital leases expire in 2024 and 2025. The net book value of property under capital leases was approximately $48 million and $50 million at Dec. 31, 2003 and 2002, respectively. Assets acquired under capital leases are recorded as property at the lower of fair market value or the present value of future lease payments, and are amortized over their actual contract term in accordance with practices allowed by regulators. The related obligation is classified as long-term debt. Executory costs are excluded from the minimum lease payments.

The remainder of the leases, primarily real estate leases and leases of coal-hauling railcars, trucks, cars and power-operated equipment are accounted for as operating leases. Rental expense under operating lease obligations for continuing operations was approximately $66 million, $69 million and $49 million for 2003, 2002 and 2001, respectively.

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Future commitments under operating and capital leases for continuing operations are:

                 
(Millions of dollars)
  Operating Leases
  Capital Leases
2004
  $ 49     $ 7  
2005
    49       7  
2006
    47       7  
2007
    42       7  
2008
    40       6  
Thereafter
    46       72  
 
           
 
 
Total minimum obligation
          $ 106  
Interest
            (58 )
 
           
 
 
Present value of minimum obligation
          $ 48  
 
           
 
 

Technology Agreement — Xcel Energy has a contract that extends through 2011 with International Business Machines Corp. (IBM) for information technology services. The contract is cancelable at our option, although there are financial penalties for early termination. In 2003, Xcel Energy paid IBM $114.2 million under the contract and $19.4 million for other project business. The contract also has a committed minimum payment each year from 2004 through 2011.

Fuel Contracts — Xcel Energy and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2004 and 2025. In total, Xcel Energy is committed to the minimum purchase of approximately $2.7 billion of coal, $93.3 million of nuclear fuel and $1.9 billion of natural gas, including $790.8 million of natural gas storage and transportation, or to make payments in lieu thereof, under these contracts. Of these minimum purchase commitments, approximately $2 billion are based on indexed prices. In addition, Xcel Energy is required to pay additional amounts depending on actual quantities shipped under these agreements. Xcel Energy’s risk of loss, in the form of increased costs, from market price changes in fuel is mitigated through the use of natural gas and energy cost adjustment mechanisms of the ratemaking process, which provide for pass through of most fuel costs to customers.

Purchased Power Agreements — The utility and nonregulated subsidiaries of Xcel Energy have entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. NSP-Minnesota, PSCo, SPS and certain nonregulated subsidiaries have various pay-for-performance contracts with expiration dates through the year 2033. In general, these contracts provide for capacity payments, subject to meeting certain contract obligations, and energy payments based on actual power taken under the contracts. Most of the capacity and energy costs are recovered through base rates and other cost-recovery mechanisms.

At Dec. 31, 2003, the estimated future payments for capacity that the utility and nonregulated subsidiaries of Xcel Energy are obligated to purchase, subject to availability, are as follows:

         
(Thousands of dollars)        
2004
  $ 552,651  
2005
    554,603  
2006
    547,987  
2007
    562,917  
2008 and thereafter
    3,958,416  
 
   
 
 
Total
  $ 6,176,574  
 
   
 
 

Environmental Contingencies

Xcel Energy is subject to regulations covering air and water quality, land use, the storage of natural gas and the storage and disposal of hazardous or toxic wastes. Compliance is continually assessed. Regulations, interpretations and enforcement policies can change, which may impact the cost of building and operating facilities.

Site Remediation Xcel Energy must pay all or a portion of the cost to remediate sites where past activities of our subsidiaries and some other parties have caused environmental contamination. At Dec. 31, 2003, there were three categories of sites:

    third-party sites, such as landfills, to which Xcel Energy is alleged to be a potentially responsible party (PRP) that sent hazardous materials and wastes;
 
    the site of a former federal uranium enrichment facility; and
 
    sites of former manufactured gas plants (MGPs) operated by our subsidiaries or predecessors.

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Xcel Energy records a liability when enough information is obtained to develop an estimate of the cost of environmental remediation and revise the estimate as information is received. The estimated remediation cost may vary materially.

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

Estimates are revised as facts become known. At Dec. 31, 2003, the liability for the cost of remediating these sites was estimated to be $43.2 million, of which $12.5 million was considered to be a current liability. Some of the cost of remediation may be recovered from:

    insurance coverage;
 
    other parties that have contributed to the contamination; and
 
    customers.

Neither the total remediation cost nor the final method of cost allocation among all PRPs of the unremediated sites has been determined. Estimates have been recorded for Xcel Energy’s share of future costs for these sites. Management is not aware of any other parties’ inability to pay, or responsibility for any of the sites that is in dispute.

Approximately $10.1 million of the long-term liability and $4.5 million of the current liability relate to a U.S. Department of Energy assessment to NSP-Minnesota and PSCo for decommissioning a federal uranium enrichment facility. These environmental liabilities do not include accruals recorded and collected from customers in rates for future nuclear fuel disposal costs or decommissioning costs related to NSP-Minnesota’s nuclear generating plants. See Note 18 to the Consolidated Financial Statements for further discussion of nuclear obligations.

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

The Wisconsin Department of Natural Resources (WDNR) and NSP-Wisconsin have each developed several estimates of the ultimate cost to remediate the Ashland site. The estimates vary significantly, between $4.0 million and $93.0 million, because different methods of remediation and different results are assumed in each. The Environmental Protection Agency (EPA) and WDNR have not yet selected the method of remediation to use at the site. Until the EPA and the WDNR select a remediation strategy for all operable units at the site and determine the level of responsibility of each PRP, NSP-Wisconsin’s share of the ultimate cost of remediating the Ashland site is not determinable.

In the interim, NSP-Wisconsin has recorded a liability of $18.5 million for its estimate of its share of the cost of remediating the Ashland site, using information available to date and reasonably effective remedial methods. NSP-Wisconsin has deferred, as a regulatory asset, the remediation costs accrued for the Ashland site based on an expectation that the Public Service Commission of Wisconsin (PSCW) will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized recovery in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site, and has authorized recovery of similar remediation costs for other Wisconsin utilities. External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed as part of the Wisconsin biennial retail rate case process for prudence. Once approved by the PSCW, deferred MGP remediation costs, less carrying costs, are historically amortized over four or six years. In addition, the Wisconsin Supreme Court rendered a ruling that reopens the possibility that NSP-Wisconsin may be able to recover a portion of the remediation costs from its insurance carriers.

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

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On Sept. 5, 2002, the Ashland site was placed on the National Priorities List (NPL). The NPL is intended primarily to guide the EPA in determining which sites require further investigation. On Nov. 14, 2003, the EPA and NSP-Wisconsin signed an administrative order on consent requiring NSP-Wisconsin to complete the remedial investigation and feasibility study for the site. Resolution of Ashland remediation issues is not expected until 2006 or 2007. NSP-Wisconsin continues to work with the WDNR to access state and federal funds to apply to the ultimate remediation cost of the entire site.

Fort Collins Manufactured Gas Plant Site Prior to 1926, Poudre Valley Gas Co., a predecessor of PSCo, operated a manufactured gas plant in Fort Collins, Colo. not far from the Cache la Poudre River. In 1926, after acquiring the Poudre Valley Gas Co., PSCo shut down the gas site and, years later, sold most of the property. In the mid-1990s, contamination associated with MGP operations was discovered on the gas plant site, and PSCo paid for a portion of a partial cleanup. Recently, an oily substance similar to MGP by-products has been discovered in the Cache la Poudre River. The source of this substance has not yet been identified. PSCo is working with the EPA, the Colorado Department of Public Health and Environment, the current site owner and the City of Fort Collins (owner of a former landfill property between the river and the plant site) to address the substance found in the river as well as other environmental issues found on the property. The scope of the investigation has expanded as a result of negotiations with the EPA, and PSCo estimates that the cost of initial removal and investigation activities will be approximately $1.6 million, although the actual cost will vary depending on site conditions. While PSCo has recorded this cost estimate at Dec. 31, 2003, it lacks sufficient information at this time to estimate its ultimate liability, if different, for this site. PSCo has deferred the costs recorded to date as a regulatory asset and believes that they will be recovered through future rates. Any costs that are not recoverable from customers will be expensed.

Other MGP Sites NSP-Minnesota has investigated and remediated MGP sites in Minnesota and North Dakota. The MPUC allowed NSP-Minnesota to defer, rather than immediately expense, certain remediation costs of four active remediation sites in 1994. This deferral accounting treatment may be used to accumulate costs that regulators are expected to allow to be recovered from customers. The costs are deferred as a regulatory asset until recovery is approved, and then the regulatory asset is expensed over the same period as the regulators have allowed the related revenue to be collected from customers. In September 1998, the MPUC allowed the recovery of a portion of these MGP site remediation costs in natural gas rates. Accordingly, NSP-Minnesota has been amortizing the related deferred remediation costs to expense. In 2001, the North Dakota Public Service Commission allowed the recovery of a portion of the cost of remediating another former MGP site in Grand Forks, N.D. The $2.9 million of deferred cost of remediating that site was accumulated in a regulatory asset that is now being expensed evenly over eight years commensurate with cost recovery. NSP-Minnesota may request recovery of costs to remediate other sites following the completion of preliminary investigations. NSP-Wisconsin has investigated and remediated MGP sites in Wisconsin. As discussed above, external MGP costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed as part of the Wisconsin biennial retail rate case process for prudence. Once approved by the PSCW, deferred MGP amounts, less carrying costs, are historically amortized over four or six years.

Asbestos Removal Some of our facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated. Since the intent is to operate most of these facilities indefinitely, Xcel Energy cannot estimate the amount or timing of payments for final removal of the asbestos. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects; capital expenditures for construction projects; or removal costs for demolition projects.

Leyden Gas Storage Facility In February 2001, the CPUC approved PSCo’s plan to abandon the Leyden natural gas storage facility (Leyden) after 40 years of operation. In July 2001, the CPUC decided that the recovery of all Leyden costs would be addressed in a future rate proceeding when all costs were known. In 2003, PSCo began flooding the facility with water, as part of an overall plan to convert Leyden into a municipal water storage facility owned and operated by the city of Arvada, Colo. In August 2003, the Colorado Oil and Gas Conservation Commission approved the closure plan, the last formal regulatory approval necessary before conversion. Leyden is expected to close by Dec. 31, 2005, and the city of Arvada will take over the site. PSCo is obligated to monitor the site for two years after closure. As of Dec. 31, 2003, PSCo has incurred approximately $4.7 million of costs associated with engineering buffer studies, damage claims paid to landowners and other initial closure costs. PSCo has accrued an additional $4.7 million of costs expected to be incurred through 2006 to complete the decommissioning and closure of the facility. PSCo has deferred these costs as a regulatory asset and believes that these costs will be recovered through future rates. Any costs that are not recoverable from customers will be expensed.

PSCo Notice of Violation On Nov. 3, 1999, the U.S. Department of Justice filed suit against a number of electric utilities for alleged violations of the Clean Air Act’s New Source Review (NSR) requirements. The suit is related to alleged modifications of electric generating stations located in the South and Midwest. Subsequently, the EPA also issued requests for information pursuant to the Clean Air Act to numerous electric utilities, including Xcel Energy, seeking to determine whether these utilities engaged in activities that may have been in violation of the NSR requirements. In 2001, Xcel Energy responded to EPA’s initial information requests related to PSCo plants in Colorado.

On July 1, 2002, PSCo received a Notice of Violation (NOV) from the EPA alleging violations of the NSR requirements of the Clean Air Act at the Comanche and Pawnee stations in Colorado. The NOV specifically alleges that various maintenance, repair and replacement projects

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undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process. PSCo believes it acted in full compliance with the Clean Air Act and NSR process. It believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations, or are otherwise not subject to the NSR requirements. PSCo also believes that the projects would be expressly authorized under the EPA’s NSR equipment-replacement rulemaking promulgated in October 2003. On Dec. 24, 2003, the U.S. Court of Appeals for the District of Columbia Circuit stayed this rule while it considers challenges to it. PSCo disagrees with the assertions contained in the NOV and intends to vigorously defend its position. As required by the Clean Air Act, the EPA met with PSCo in September 2002 to discuss the NOV.

If the EPA is successful in any subsequent litigation regarding the issues set forth in the NOV or any matter arising as a result of its information requests, it could require PSCo to install additional emission-control equipment at the facilities and pay civil penalties. Civil penalties are limited to not more than $25,000 to $27,500 per day for each violation, commencing from the date the violation began. The ultimate financial impact to PSCo is not determinable at this time.

NSP-Minnesota NSR Information Request On Nov. 3, 1999, the U. S. Department of Justice filed suit, related to alleged modifications of electric generating stations located in the South and Midwest, against a number of electric utilities for alleged violations of the Clean Air Act’s NSR requirements. Subsequently, the EPA also issued requests for information pursuant to the Clean Air Act to numerous other electric utilities, including Xcel Energy, seeking to determine whether these utilities engaged in activities that may have been in violation of the NSR requirements. In 2001, Xcel Energy responded to the EPA’s initial information requests related to NSP-Minnesota plants in Minnesota. On May 22, 2002, the EPA issued a follow-up information request to Xcel Energy seeking additional information regarding NSR compliance at its plants in Minnesota. Xcel Energy completed its response to the follow-up information request during the fall of 2002.

NSP-Minnesota Notice of Violation On Dec. 10, 2001, the Minnesota Pollution Control Agency issued a notice of violation to NSP-Minnesota alleging air quality violations related to the replacement of a coal conveyor and violations of an opacity limitation at the A.S. King generating plant. NSP-Minnesota has responded to the notice of violation and is working to resolve the allegations.

Nuclear Insurance — NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $10.9 billion under the 1988 Price-Anderson amendment to the Atomic Energy Act of 1954. NSP-Minnesota has secured $300 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $10.6 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. NSP-Minnesota is subject to assessments of up to $100.6 million for each of its three licensed reactors, to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $10 million per reactor during any one year.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL). The coverage limits are $2.0 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $7.5 million for business interruption insurance and $25.6 million for property damage insurance if losses exceed accumulated reserve funds.

Legal Contingencies

In the normal course of business, Xcel Energy is subject to claims and litigation arising from prior and current operations. Xcel Energy is actively defending these matters and has recorded an estimate of the probable cost of settlement or other disposition.

The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution of these matters could have a material adverse effect on Xcel Energy’s financial position and results of operations.

Department of Labor Audit — In 2001, Xcel Energy received notice from the Department of Labor (DOL) Employee Benefit Security Administration that it intended to audit the Xcel Energy pension plan. After multiple on-site meetings and interviews with Xcel Energy personnel, the DOL indicated on Sept. 18, 2003, that it is prepared to take the position that Xcel Energy, as plan sponsor and through its delegate, the Pension Trust Administration Committee, breached its fiduciary duties under the Employee Retirement Income Security Act of 1974 (ERISA) with respect to certain investments made in limited partnerships and hedge funds in 1997 and 1998.

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All discussions related to potential ERISA fiduciary violations have been preliminary and unofficial. The DOL has offered to conclude the audit at this time if Xcel Energy is willing to contribute to the plan the full amount of losses from each of these questioned investments, or approximately $13 million. Xcel Energy has responded with a letter to the DOL asserting that no fiduciary violations have occurred, and extended an offer to meet to discuss the matter further. In December 2003, the DOL requested, and Xcel Energy agreed, to toll the statute of limitations under ERISA with respect to this claim. The DOL now has until Dec. 5, 2004, to assert a claim. If the DOL offer is put into effect, the requested contribution would affect cash flows only and not the net income of Xcel Energy.

Xcel Energy Inc. Securities Litigation — On July 31, 2002, a lawsuit purporting to be a class action on behalf of purchasers of Xcel Energy’s common stock between Jan. 31, 2001 and July 26, 2002, was filed in the U.S. District Court for the District of Minnesota. The complaint named Xcel Energy; Wayne H. Brunetti, chairman and chief executive officer; Edward J. McIntyre, former vice president and chief financial officer; and former chairman James J. Howard as defendants. Among other things, the complaint alleged violations of Section 10(b) of the Securities Exchange Act and Rule 10(b-5) related to allegedly false and misleading disclosures concerning various issues including but not limited to “round trip” energy trades; the nature, extent and seriousness of liquidity and credit difficulties at NRG; and the existence of cross-default provisions (with NRG credit agreements) in certain of Xcel Energy’s credit agreements. After filing the lawsuit, several additional lawsuits were filed with similar allegations, one of which added claims on behalf of a purported class of purchasers of two series of Senior Notes issued by NRG in January 2001. The cases have all been consolidated, and a consolidated amended complaint has been filed. The amended complaint charges false and misleading disclosures concerning “round trip” energy trades and the existence of provisions in Xcel Energy’s credit agreements for cross-defaults in the event of a default by NRG in one or more of NRG’s credit agreements; it adds as additional defendants Gary R. Johnson, general counsel; Richard C. Kelly, then president of Xcel Energy Enterprises; two former executive officers and one current executive officer of NRG, David H. Peterson, Leonard A. Bluhm, and William T. Pieper; and a former independent director of NRG, Luella G. Goldberg; and it adds claims of false and misleading disclosures, also regarding “round trip” trades and the cross-default provisions, as well as the extent to which the “fortunes” of NRG were tied to Xcel Energy, especially in the event of a buyback of NRG’s publicly owned shares under Section 11 of the Securities Act, with respect to issuance of the senior notes by NRG. The amended complaint seeks compensatory and rescissionary damages, interest and an award of fees and expenses. On Sept. 30, 2003, in response to the defendants’ motion to dismiss, the court issued an order dismissing the claims brought by purchasers of the NRG senior notes against defendants James Howard, Gary R. Johnson, Richard C. Kelly, David H. Peterson, Leonard A. Bluhm, William T. Pieper and Luella Goldberg. The court, however, denied the motion related to claims brought by Xcel Energy shareholders against Xcel Energy, James Howard, Wayne Brunetti and Edward McIntyre. Subsequently, following a pre-trial conference in December 2003, this matter was ordered to be ready for trial by Feb. 1, 2006. Presently the parties are in the preliminary stages of discovery.

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 essentially the same circumstances as the securities class actions described immediately preceding and asserting breach of fiduciary duty. This action has been consolidated for pre-trial purposes with the securities class actions 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. 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 have filed motions to dismiss the complaints upon which no rulings have yet been made. 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.

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SchlumbergerSema, Inc. vs. Xcel Energy Inc. Under a 1996 data services agreement, SchlumbergerSema, Inc. (SLB) provides automated meter reading, distribution automation, and other data services to NSP-Minnesota. In September 2002, NSP-Minnesota issued written notice that SLB committed events of default under the agreement, including SLB’s nonpayment of approximately $7.4 million for distribution automation assets. In November 2002, SLB demanded arbitration and asserted various claims against NSP-Minnesota totaling $24 million for alleged breach of an expansion contract and a meter purchasing contract. In the arbitration, NSP-Minnesota asserts counterclaims against SLB including those related to SLB’s failure to meet performance criteria, improper billing, failure to pay for use of NSP-Minnesota owned property and failure to pay $7.4 million for NSP-Minnesota distribution automation assets, for total claims of approximately $41 million. NSP-Minnesota also seeks a declaratory judgment from the arbitrators that would terminate SLB’s rights under the data services agreement. The arbitration panel is scheduled to hear dispositive motions in March 2004. In the event the matter is not disposed of on the motions, a hearing to arbitrate the dispute will likely occur in second quarter 2004.

Cornerstone Propane Partners, L.P., et al., vs. e prime, inc., et al. In February 2004, a purported class action complaint was filed in the U.S. District Court for the Southern District of New York against e prime and three other defendants, by Cornerstone Propane Partners, L.P., Robert Calle Gracey and Dominick Viola on behalf of a class who purchased or sold one or more New York Mercantile Exchange natural gas futures and/or options contracts during the period from Jan. 1, 2000 to Dec. 31, 2002. The complaint alleges that defendants manipulated the price of natural gas futures and options and/or the price of natural gas underlying those contracts in violation of the Commodities Exchange Act. On Feb. 2, 2004, the plaintiff requested that this action be consolidated with a similar suit involving Reliant Energy Services. Xcel Energy is in the process of reviewing this recently filed complaint and intends to vigorously defend itself in the lawsuit.

Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al. On Nov. 19, 2003, a class action complaint filed in the U.S. District Court for the Eastern District of California by Texas-Ohio Energy, Inc. was served on the Xcel Energy naming e prime as a defendant. The lawsuit, filed on behalf of a purported class of large wholesale natural gas purchasers, alleges that e prime falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California. The case has been conditionally transferred to U.S. District Judge Pro in Nevada who is supervising western areas wholesale natural gas marketing litigation. A motion is currently pending to transfer the case back to the Eastern District of California. e prime has not yet responded to the complaint. The case is in the early stages, there has been no discovery, and Xcel Energy intends to vigorously defend against these claims.

Other Contingencies

Tax Matters — PSCo’s wholly owned subsidiary PSR Investments, Inc. (PSRI) owns and manages permanent life insurance policies on PSCo employees, known as corporate-owned life insurance (COLI). At various times, borrowings have been made against the cash values of these COLI policies and the interest expense on these borrowings has been deducted. The IRS had issued a Notice of Proposed Adjustment proposing to disallow interest expense deductions taken in tax years 1993 through 1997 related to COLI policy loans. A request for technical advice from the IRS National Office with respect to the proposed adjustment had been pending. Late in 2001, Xcel Energy received a technical advice memorandum from the IRS National Office, which communicated a position adverse to PSRI. Consequently, the IRS examination division has disallowed interest expense deductions for the tax years 1993 through 1997.

After consultation with tax counsel, it is Xcel Energy’s position that the IRS determination is not supported by the tax law. Based upon this assessment, management continues to believe that the tax deduction of interest expense on the COLI policy loans is in full compliance with the tax law. Therefore, Xcel Energy intends to challenge the IRS determination, which could require several years to reach final resolution. Although the ultimate resolution of this matter is uncertain, management continues to believe the resolution of this matter will not have a material adverse impact on Xcel Energy’s financial position, results of operations or cash flows. For these reasons, PSRI has not recorded any provision for income tax or interest expense related to this matter, and has continued to take deductions for interest expense related to policy loans on its income tax returns for subsequent years. However, defense of Xcel Energy’s position may require significant cash outlays on a temporary basis, if refund litigation is pursued in U.S. District Court.

The total disallowance of interest expense deductions for the period of 1993 through 1997, as proposed by the IRS, is approximately $175 million. Additional interest expense deductions for the period 1998 through 2003 are estimated to total approximately $404 million. Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2003, would reduce earnings by an estimated $254 million after tax.

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18.      Nuclear Obligations

Fuel Disposal — NSP-Minnesota is responsible for temporarily storing used or spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from NSP-Minnesota’s nuclear plants as well as from other U.S. nuclear plants. NSP-Minnesota has funded its portion of the DOE’s permanent disposal program since 1981. The fuel disposal fees are based on a charge of 0.1 cent per kilowatt-hour sold to customers from nuclear generation. Fuel expense includes DOE fuel disposal assessments of approximately $13 million in 2003, $13 million in 2002 and $11 million in 2001. In total, NSP-Minnesota had paid approximately $321 million to the DOE through Dec. 31, 2003. However, it is not determinable whether the amount and method of the DOE’s assessments to all utilities will be sufficient to fully fund the DOE’s permanent storage or disposal facility.

The Nuclear Waste Policy Act required the DOE to begin accepting spent nuclear fuel no later than Jan. 31, 1998. In 1996, the DOE notified commercial spent-fuel owners of an anticipated delay in accepting spent nuclear fuel by the required date and conceded that a permanent storage or disposal facility will not be available until at least 2010. NSP-Minnesota and other utilities have commenced lawsuits against the DOE to recover damages caused by the DOE’s failure to meet its statutory and contractual obligations.

NSP-Minnesota has its own temporary, on-site storage facilities for spent fuel at its Monticello and Prairie Island nuclear plants, which consist of storage pools and a dry cask facility. With the dry cask storage facility licensed by the NRC approved in 1994 and again in 2003, management believes it has adequate storage capacity to continue operation of its Prairie Island nuclear plant until at least the end of its license terms in 2013 and 2014. The Monticello nuclear plant has storage capacity in the pool to continue operations until 2010. Storage availability to permit operation beyond these dates is not known at this time. All of the alternatives for spent-fuel storage are being investigated until a DOE facility is available, including pursuing the establishment of a private facility for interim storage of spent nuclear fuel as part of a consortium of electric utilities.

Nuclear fuel expense includes payments to the DOE for the decommissioning and decontamination of the DOE’s uranium-enrichment facilities. In 1993, NSP-Minnesota recorded the DOE’s initial assessment of $46 million, which is payable in annual installments from 1993 to 2008. NSP-Minnesota is amortizing each installment to expense on a monthly basis. The most recent installment paid in 2003 was $4.5 million; future installments are subject to inflation adjustments under DOE rules. NSP-Minnesota is obtaining rate recovery of these DOE assessments through the cost-of-energy adjustment clause as the assessments are amortized. Accordingly, the unamortized assessment of $16.8 million at Dec. 31, 2003, is deferred as a regulatory asset.

Plant Decommissioning — Decommissioning of NSP-Minnesota’s nuclear facilities is planned for the years 2010 through 2048, using the prompt dismantlement method. NSP-Minnesota is currently following industry practice by accruing the costs for decommissioning over the approved cost-recovery period and including the accruals in Accumulated Depreciation. Upon implementation of SFAS No. 143, the decommissioning costs in Accumulated Depreciation and ongoing accruals are reclassified to a regulatory liability account. The total decommissioning cost obligation is recorded as an asset retirement obligation in accordance with SFAS No. 143. See Accounting Change — SFAS No. 143 for additional information.

Monticello began operation in 1971 and is licensed to operate until 2010. Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively, and are licensed to operate until 2013 and 2014, respectively. In 2003, the Minnesota Legislature changed a law that had limited expansion of on-site storage. NSP-Minnesota will make a decision on whether to pursue license renewal for the Monticello and Prairie Island plants. Applications for license renewal must be submitted to the NRC at least five years prior to license expiration. Preliminary scoping efforts for license renewal of the Monticello plant have begun, including data collection and review. The Prairie Island license renewal process has not yet begun. NSP-Minnesota’s decision whether to apply for license renewal approval could be contingent on incremental plant maintenance or capital expenditures, recovery of which would be expected from customers through the respective rate-recovery mechanisms. Management cannot predict the specific impact of such future requirements, if any, on its results of operations.

Consistent with cost recovery in utility customer rates, NSP-Minnesota records annual decommissioning accruals based on periodic site-specific cost studies and a presumed level of dedicated funding. Cost studies quantify decommissioning costs in current dollars. Funding presumes that current costs will escalate in the future at a rate of 4.19 percent per year. The total estimated decommissioning costs that will ultimately be paid, net of income earned by external trust funds, is currently being accrued using an annuity approach over the approved plant-recovery period. This annuity approach uses an assumed rate of return on funding, which is currently 5.5 percent, net of tax, for external funding and approximately 8 percent, net of tax, for internal funding. Unrealized gains on nuclear decommissioning investments are deferred as Regulatory Liabilities based on the assumed offsetting against decommissioning costs in current ratemaking treatment.

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The MPUC last approved NSP-Minnesota’s nuclear decommissioning study request in December 2003, using 2002 cost data. An original filing was submitted to the MPUC in October 2002 and updated in August 2003; final approval was received in December 2003. The most recent cost estimate represents an annual increase in external fund accruals, along with the extension of Prairie Island cost recovery to the end of license life in 2014. The MPUC also approved the Department of Commerce recommendation to accelerate the internal fund transfer to the external funds effective July 1, 2003, ending on Dec. 31, 2005. These approvals increased the fund cash contribution by approximately $29 million in 2003, but may not have a statement of operations impact. Expecting to operate Prairie Island through the end of each unit’s licensed life, the approved capital recovery will allow for the plant to be fully depreciated, including the accrual and recovery of decommissioning costs, in 2014. Xcel Energy believes future decommissioning cost accruals will continue to be recovered in customer rates.

The total obligation for decommissioning currently is expected to be funded 100 percent by external funds, as approved by the MPUC. Contributions to the external fund started in 1990 and are expected to continue until plant decommissioning begins. The assets held in trusts as of Dec. 31, 2003, primarily consisted of investments in fixed income securities, such as tax-exempt municipal bonds and U.S. government securities that mature in one to 20 years, and common stock of public companies. NSP-Minnesota plans to reinvest matured securities until decommissioning begins.

At Dec. 31, 2003, NSP-Minnesota had recorded and recovered in rates cumulative decommissioning accruals of $722 million. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation at Dec. 31, 2003:

         
(Thousands of dollars)
  2003
Estimated decommissioning cost obligation from most recently approved study (2002 dollars)
  $ 1,716,618  
Effect of escalating costs to 2003 dollars (at 4.19 percent per year)
    71,926  
 
   
 
 
Estimated decommissioning cost obligation in current dollars
    1,788,544  
Effect of escalating costs to payment date (at 4.19 percent per year)
    2,004,821  
 
   
 
 
Estimated future decommissioning costs (undiscounted)
    3,793,365  
Effect of discounting obligation (using risk-free interest rate)
    (2,274,469 )
 
   
 
 
Discounted decommissioning cost obligation
    1,518,896  
Assets held in external decommissioning trust
    779,382  
 
   
 
 
Discounted decommissioning obligation in excess of assets currently held in external trust
  $ 739,514  
 
   
 
 

Decommissioning expenses recognized include the following components:

                         
(Thousands of dollars)
  2003
  2002
  2001
Annual decommissioning cost accrual reported as depreciation expense:
                       
Externally funded
  $ 80,582     $ 51,433     $ 51,433  
Internally funded (including interest costs)
    (35,906 )     (18,797 )     (17,396 )
Interest cost on externally funded decommissioning obligation
    (14,952 )     (32 )     4,535  
Earnings (losses) from external trust funds
    14,952       32       (4,535 )
 
   
 
     
 
     
 
 
Net decommissioning accruals recorded
  $ 44,676     $ 32,636     $ 34,037  
 
   
 
     
 
     
 
 

Decommissioning and interest accruals are included with Regulatory Liabilities on the Consolidated Balance Sheet. Interest costs and trust earnings associated with externally funded obligations are reported in Other Nonoperating Income on the Consolidated Statement of Operations.

Negative accruals for internally funded portions in 2001, 2002 and 2003 reflect the impacts of the 1999 and 2002 decommissioning studies, which have approved an assumption of 100-percent external funding of future costs. Previous studies assumed a portion was funded internally; beginning in 2000, accruals are reversing the previously accrued internal portion and increasing the external portion prospectively.

Accounting Change — SFAS No. 143 — Xcel Energy adopted Statement of Financial Accounting Standard (SFAS) No. 143 — “Accounting for Asset Retirement Obligations” effective Jan. 1, 2003. As required by SFAS No. 143, future plant decommissioning obligations were recorded as a liability at fair value as of Jan. 1, 2003, with a corresponding increase to the carrying values of the related long-lived assets. This liability will be increased over time by applying the interest method of accretion to the liability, and the capitalized costs will be depreciated over the useful life of the related long-lived assets.

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The impact of the adoption of SFAS No. 143 for Xcel Energy’s utility subsidiaries is described below. The adoption had no income statement impact due to the deferral of the cumulative effect adjustments required under SFAS No. 143, through the establishment of a regulatory asset pursuant to SFAS No. 71.

Asset retirement obligations were recorded for the decommissioning of two NSP-Minnesota nuclear generating plants, the Monticello plant and the Prairie Island plant. A liability was also recorded for the decommissioning of an NSP-Minnesota steam production plant, the Pathfinder plant. Monticello began operation in 1971 and is licensed to operate until 2010. Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively, and are licensed to operate until 2013 and 2014, respectively. Pathfinder operated as a steam production peaking facility from 1969 until its retirement.

A summary of the accounting for the initial adoption of SFAS No. 143, as of Jan. 1, 2003, is as follows:

                         
    Increase (decrease) in:
    Plant   Regulatory   Long-Term
(Thousands of dollars)
  Assets
  Assets
  Liabilities
Reflect retirement obligation when liability incurred
  $ 130,659     $     $ 130,659  
Record accretion of liability to adoption date
          731,709       731,709  
Record depreciation of plant to adoption date
    (110,573 )     110,573        
Recharacterize previously recorded decommissioning accruals
          (662,411 )     (662,411 )
 
   
 
     
 
     
 
 
Net impact of SFAS No. 143 on balance sheet
  $ 20,086     $ 179,871     $ 199,957  
 
   
 
     
 
     
 
 

A reconciliation of the beginning and ending aggregate carrying amounts of NSP-Minnesota’s asset retirement obligations recorded under SFAS No. 143 are shown in the table below for the twelve months ended Dec. 31, 2003:

                                                 
    Beginning                           Revisions   Ending
    Balance   Liabilities   Liabilities           To Prior   Balance
(Thousands of dollars)
  Jan. 1, 2003
  Incurred
  Settled
  Accretion
  Estimates
  Dec. 31, 2003
Steam plant retirement
  $ 2,725     $     $     $ 135     $     $ 2,860  
Nuclear plant decommissioning
    859,643                   58,341       103,685       1,021,669  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Total liability
  $ 862,368     $     $     $ 58,476     $ 103,685     $ 1,024,529  
 
   
 
     
 
     
 
     
 
     
 
     
 
 

The adoption of SFAS No. 143 resulted in the recording of a capitalized plant asset of $131 million for the discounted cost of asset retirement as of the date the liability was incurred. Accumulated depreciation on this additional capitalized cost through the date of adoption of SFAS No. 143 was $111 million. A regulatory asset of $842 million was recognized for the accumulated SFAS No. 143 costs for accretion of the initial liability and depreciation of the additional capitalized cost through adoption date. This regulatory asset was partially offset by $662 million for the reversal of the decommissioning costs previously accrued for these plants prior to the implementation of SFAS No. 143. The net regulatory asset of $180 million at Jan. 1, 2003, reflects the excess of costs that would have been recorded in expense under SFAS No. 143 over the amount of costs recorded consistent with ratemaking cost recovery for NSP-Minnesota. This regulatory asset is expected to reverse over time since the costs to be accrued under SFAS No. 143 are expected to be the same as the costs to be recovered through current NSP-Minnesota ratemaking. Consequently, no cumulative effect adjustment to earnings or shareholders’ equity has been recorded for the adoption of SFAS No. 143 in 2003, as all such effects have been deferred as a regulatory asset.

In August 2003, prior estimates for the nuclear plant decommissioning obligations were revised to incorporate the assumptions made in NSP-Minnesota’s updated 2002 nuclear decommissioning filing with the MPUC. The revised estimates resulted in an increase of $104 million to both the regulatory asset and the long-term liability, as discussed previously. The revised estimates reflected changes in cost estimates due to changes in the escalation factor, changes in the estimated start date for decommissioning and changes in assumptions for storage of spent nuclear fuel. The changes in assumptions for the estimated start date for decommissioning and changes in the assumptions for storage of spent nuclear fuel are a result of recent Minnesota legislation that authorized additional spent nuclear fuel storage.

The pro forma liability to reflect amounts as if SFAS No. 143 had been applied as of Dec. 31, 2002, was $862 million, the same as the Jan. 1, 2003, amounts discussed previously. The pro forma liability to reflect adoption of SFAS No. 143 as of Jan. 1, 2002, the beginning of the earliest period presented, was $810 million.

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Pro forma net income and earnings per share have not been presented for the year ended Dec. 31, 2002, because the pro forma application of SFAS No. 143 to prior periods would not have changed net income or earnings per share of Xcel Energy or NSP-Minnesota due to the regulatory deferral of any differences of past cost recognition and SFAS No. 143 methodology, as discussed previously.

The fair value of NSP-Minnesota assets legally restricted for purposes of settling the nuclear asset retirement obligations is $900 million as of Dec. 31, 2003, including external nuclear decommissioning investment funds and internally funded amounts.

Removal Costs The adoption of SFAS No. 143 in 2003 also affects Xcel Energy’s accrued plant removal costs for other generation, transmission and distribution facilities for its utility subsidiaries. Although SFAS No. 143 does not recognize the future accrual of removal costs as a liability, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long periods over which the amounts were accrued and the changing of rates through time, the utility subsidiaries have estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates.

Accordingly, the recorded amounts of estimated future removal costs, which are considered Regulatory Liabilities under SFAS No. 71. Removal costs by entity are as follows at Dec. 31:

                 
(Millions of dollars)
  2003
  2002
NSP-Minnesota
  $ 324     $ 304  
NSP-Wisconsin
    75       70  
PSCo
    351       329  
SPS
    102       97  
Cheyenne Light, Fuel & Power Co.
    10       10  
 
   
 
     
 
 
Total Xcel Energy
  $ 862     $ 810  
 
   
 
     
 
 

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19.     Regulatory Assets and Liabilities

Xcel Energy's regulated businesses prepare their Consolidated Financial Statements in accordance with the provisions of SFAS No. 71, as discussed in Note 1 to the Consolidated Financial Statements. Under SFAS No. 71, regulatory assets and liabilities can be created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates. Any portion of Xcel Energy's business that is not regulated cannot use SFAS No. 71 accounting. The components of unamortized regulatory assets and liabilities of continuing operations shown on the balance sheet at Dec. 31 were:

                                 
            Remaining        
(Thousands of dollars)
  See Note
  Amortization Period
  2003
  2002
Regulatory Assets
                               
Net nuclear asset retirement obligations
    1, 18     End of licensed life   $ 186,989     $  
Power purchase contract valuation adjustments
    16     Term of related contract     154,260        
AFDC recorded in plant (a)
          Plant lives     153,491       154,158  
Losses on reacquired debt
    1     Term of related debt     101,616       85,888  
Conservation programs (a)
          Five to 10 years     76,087       53,860  
Nuclear decommissioning costs (b)
          Up to four years     37,654       53,567  
Employees’ postretirement benefits other than pension
    12     Nine years     35,015       38,899  
Renewable resource costs
          To be determined     25,972       26,000  
Environmental costs
    17, 18     To be determined     29,195       30,974  
State commission accounting adjustments (a)
          Plant lives     17,301       19,157  
Plant asset recovery (Pawnee II and Metro Ash)
          Four years     17,162        
Unrecovered natural gas costs (c)
    1     One to two years     16,008       12,296  
Unrecovered electric production costs (d)
    1     15 months     13,779       67,709  
Other
          Various     15,311       15,630  
Deferred income tax adjustments
    1     Mainly plant lives           18,738  
 
                   
 
     
 
 
Total regulatory assets
                  $ 879,840     $ 576,876  
 
                   
 
     
 
 
Regulatory Liabilities
                               
Plant removal costs
    1, 18             $ 862,406     $ 810,184  
Pension costs — regulatory differences
    12               338,926       287,615  
Power purchase contract valuation adjustments
    16               126,884        
Unrealized gains from decommissioning investments
    18               105,518       112,145  
Investment tax credit deferrals
                    101,073       109,571  
Deferred income tax adjustments
    1               25,906        
Interest on income tax refunds
                    7,369       6,569  
Fuel costs, refunds and other
                    2,466       2,527  
 
                   
 
     
 
 
Total regulatory liabilities
                  $ 1,570,548     $ 1,328,611  
 
                   
 
     
 
 

  (a)   Earns a return on investment in the ratemaking process. These amounts are amortized consistent with recovery in rates.
 
  (b)   These costs do not relate to NSP-Minnesota’s nuclear plants. They relate to DOE assessments, as discussed previously, and unamortized costs for PSCo’s Fort St. Vrain nuclear plant decommissioning.
 
  (c)   Excludes current portion expected to be returned to customers within 12 months of $3.1 million for 2003, and the 2002 current portion expected to be recovered from customers of $12.1 million.
 
  (d)   Excludes current portion expected to be recovered within the next 12 months of $55.8 and $54.2 million for 2003 and 2002, respectively.

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20.     Segments and Related Information

Xcel Energy has the following reportable segments: Regulated Electric Utility, Regulated Natural Gas Utility and All Other.

    Xcel Energy’s Regulated Electric Utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas, New Mexico, Wyoming, Kansas and Oklahoma. It also makes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated Electric Utility also includes electric trading.
 
    Xcel Energy’s Regulated Natural Gas Utility segment transports, stores and distributes natural gas and propane primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan, Colorado and Wyoming.

To report income from continuing operations for Regulated Electric and Regulated Natural Gas Utility segments, Xcel Energy must assign or allocate all costs and certain other income. In general, costs are:

    directly assigned wherever applicable;
 
    allocated based on cost causation allocators wherever applicable; and
 
    allocated based on a general allocator for all other costs not assigned by the above two methods.

The accounting policies of the segments are the same as those described in Note 1 to the Consolidated Financial Statements. Xcel Energy evaluates performance by each legal entity based on profit or loss generated from the product or service provided.

                                         
    Regulated   Regulated            
    Electric   Natural Gas   All   Reconciling   Consolidated
(Thousands of dollars)
  Utility
  Utility
  Other
  Eliminations
  Total
2003
                                       
Operating revenues from external customers
  $ 5,969,356     $ 1,710,272     $ 257,888     $     $ 7,937,516  
Intersegment revenues
    1,123       10,868       53,866       (65,857 )      
 
   
 
     
 
     
 
     
 
     
 
 
Total revenues
  $ 5,970,479     $ 1,721,140     $ 311,754     $ (65,857 )   $ 7,937,516  
 
   
 
     
 
     
 
     
 
     
 
 
Depreciation and amortization
  $ 628,108     $ 81,794     $ 46,098     $     $ 756,000  
Financing costs, mainly interest expense
    313,456       58,259       104,022       (23,435 )     452,302  
Income tax expense (benefit)
    240,186       31,928       (113,472 )           158,642  
Income (loss) from continuing operations
  $ 462,528     $ 94,873     $ (10,142 )   $ (37,239 )   $ 510,020  
 
   
 
     
 
     
 
     
 
     
 
 
2002
                                       
Operating revenues from external customers
  $ 5,437,017     $ 1,363,359     $ 234,749     $     $ 7,035,125  
Intersegment revenues
    987       5,396       94,304       (100,684 )     3  
 
   
 
     
 
     
 
     
 
     
 
 
Total revenues
  $ 5,438,004     $ 1,368,755     $ 329,053     $ (100,684 )   $ 7,035,128  
 
   
 
     
 
     
 
     
 
     
 
 
Depreciation and amortization
  $ 649,020     $ 87,259     $ 34,986     $     $ 771,265  
Financing costs, mainly interest expense
    286,872       49,075       125,667       (39,207 )     422,407  
Income tax expense (benefit)
    297,420       44,789       (106,595 )           235,614  
Income (loss) from continuing operations
  $ 486,811     $ 89,026     $ (2,067 )   $ (46,077 )   $ 527,693  
 
   
 
     
 
     
 
     
 
     
 
 
2001
                                       
Operating revenues from external customers
  $ 6,463,411     $ 2,020,530     $ 236,846     $     $ 8,720,787  
Intersegment revenues
    1,189       9,932       85,891       (93,772 )     3,240  
 
   
 
     
 
     
 
     
 
     
 
 
Total revenues
  $ 6,464,600     $ 2,030,462     $ 322,737     $ (93,772 )   $ 8,724,027  
 
   
 
     
 
     
 
     
 
     
 
 
Depreciation and amortization
  $ 616,283     $ 87,906     $ 22,606     $     $ 726,795  
Financing costs, mainly interest expense
    265,999       45,723       101,318       (46,604 )     366,436  
Income tax expense (benefit)
    343,488       39,509       (78,655 )           304,342  
Income (loss) from continuing operations
  $ 555,976     $ 63,051     $ 4,813     $ (44,640 )   $ 579,200  
 
   
 
     
 
     
 
     
 
     
 
 

In 2003, the process to allocate common costs of the Regulated Electric and Natural Gas Utility segments was revised. Segment results for 2002 and 2001 have been restated to reflect the revised cost allocation process.

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Prior to its divestiture in 2003, NRG was previously considered a reportable segment of Xcel Energy. NRG is now reported as a discontinued operation, as discussed in Note 3 to the Consolidated Financial Statements. See Note 3 for summarized financial information regarding NRG.

21.     Summarized Quarterly Financial Data (Unaudited)

     Summarized quarterly unaudited financial data is as follows:

                                 
    Quarter ended
    March 31, 2003   June 30, 2003   Sept. 30, 2003   Dec. 31, 2003
(Thousands of dollars, except per share amounts)
  (a)
  (a)
  (a)
  (a)
Revenue
  $ 2,086,107     $ 1,721,754     $ 2,019,853     $ 2,109,802  
Operating income (loss)
    304,022       162,624       358,658       259,943  
Income (loss) from continuing operations
    126,778       54,982       180,039       148,221  
Discontinued operations — income (loss)
    13,234       (337,544 )     107,456       329,226  
Net income (loss)
    140,012       (282,562 )     287,495       477,447  
Earnings (loss) available for common shareholders
    138,952       (283,622 )     286,435       476,386  
Earnings (loss) per share from continuing operations — basic
  $ 0.32     $ 0.14     $ 0.45     $ 0.37  
Earnings (loss) per share from continuing operations — diluted
  $ 0.31     $ 0.14     $ 0.43     $ 0.36  
Earnings (loss) per share from discontinued operations — basic
  $ 0.03     $ (0.85 )   $ 0.27     $ 0.83  
Earnings (loss) per share from discontinued operations — diluted
  $ 0.03     $ (0.85 )   $ 0.26     $ 0.78  
Earnings (loss) per share total — basic
  $ 0.35     $ (0.71 )   $ 0.72     $ 1.20  
Earnings (loss) per share total — diluted
  $ 0.34     $ (0.71 )   $ 0.69     $ 1.14  

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    Quarter Ended
    March 31, 2002   June 30, 2002   Sept. 30, 2002   Dec. 31, 2002
(Thousands of dollars, except per share amounts)
  (b)
  (b)
  (b)
  (b)
Revenue
  $ 1,834,811     $ 1,598,832     $ 1,726,436     $ 1,875,049  
Operating income (loss)
    253,498       262,513       373,188       251,838  
Income (loss) from continuing operations
    121,578       117,242       178,002       110,871  
Discontinued operations — income (loss)
    (18,074 )     (29,940 )     (2,382,042 )     (315,628 )
Net income (loss)
    103,504       87,302       (2,204,040 )     (204,757 )
Earnings (loss) available for common shareholders
    102,444       86,242       (2,205,100 )     (205,818 )
Earnings (loss) per share from continuing operations — basic
  $ 0.34     $ 0.31     $ 0.44     $ 0.27  
Earnings (loss) per share from continuing operations — diluted
  $ 0.34     $ 0.31     $ 0.44     $ 0.27  
Earnings (loss) per share from discontinued operations — basic
  $ (0.05 )   $ (0.08 )   $ (5.99 )   $ (0.79 )
Earnings (loss) per share from discontinued operations — diluted
  $ (0.05 )   $ (0.08 )   $ (5.99 )   $ (0.77 )
Earnings (loss) per share total — basic
  $ 0.29     $ 0.23     $ (5.55 )   $ (0.52 )
Earnings (loss) per share total — diluted
  $ 0.29     $ 0.23     $ (5.55 )   $ (0.50 )

(a)   2003 results include special charges in certain quarters, as discussed in Note 2 to the Consolidated Financial Statements, and unusual items as follows:

    Results from continuing operations were decreased for NRG-related restructuring costs incurred by the holding company in the amount of $1.4 million in the first quarter, $7.3 million in the second quarter and $3.0 million in the third quarter.
 
    Fourth-quarter results from continuing operations were increased by $22 million, or 3 cents per share, for adjustments made to depreciation accruals for the year, due to a regulatory decision approving the extension of NSP-Minnesota’s Prairie Island nuclear plant to operate over the license term.
 
    Fourth-quarter results from continuing operations were increased by $30 million, or 7 cents per share, for adjustments made to income tax accruals to reflect the successful resolution of various outstanding tax issues.
 
    Fourth-quarter results from continuing operations were decreased by $7 million pretax, or 1 cent per share, for charges recorded related to the TRANSLink project due to regulatory and operating uncertainties.
 
    Fourth-quarter results from discontinued operations were increased by $111 million, or 26 cents per share, for reversal of equity in prior NRG losses due to the divestiture of NRG in December 2003, and increased by $288 million, or 68 cents per share, due to revisions to the estimated tax benefits related to Xcel Energy’s investment in NRG. See Note 3 to the Consolidated Financial Statements for further discussion of these items.
 
    Fourth-quarter results from discontinued operations were decreased by $59 million, or 14 cents per share, due to the estimated impairment expected to result from the disposal of Xcel Energy International’s Argentina assets, as discussed in Note 3 to the Consolidated Financial Statements, and by $16 million, or 4 cents per share, due to the accrual of e prime’s cost to settle an investigation by the Commodity Futures Trading Commission.

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(b)   2002 results include special charges in certain quarters, as discussed in Note 2 to the Consolidated Financial Statements, and unusual items as follows:

    First-quarter results from continuing operations were decreased by $9 million, or 1 cent per share, for a special charge related to utility/service company employee restaffing costs, and by $5 million, or 1 cent per share, for regulatory recovery adjustments at SPS included in special charges.
 
    Results from continuing operations were decreased in the amount of $1.2 million in the third quarter and $3.6 million in the fourth quarter for NRG-related restructuring costs incurred by the holding company.
 
    Fourth-quarter results from discontinued operations were decreased by $95 million, or 23 cents per share, for NRG charges related to asset impairments and financial restructuring costs, and increased by $30 million, or 7 cents per share, due to revisions to the estimated tax benefits related to Xcel Energy’s investment in NRG.

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Item 9 — Changes In and Disagreements with Accountants on Accounting and Financial Disclosure

During 2002 and 2003, and through the date of this report, there were no disagreements with the independent public accountants on accounting principles or practices, financial statement disclosures, or auditing scope or procedures.

Item 9A — Controls and Procedures

Xcel Energy maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in Securities and Exchange Commission rules and forms. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the chief executive officer (CEO) and chief financial officer (CFO), of the effectiveness of Xcel Energy’s disclosure controls and procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures are effective.

No changes in Xcel Energy’s internal control over financial reporting have occurred during the most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, Xcel Energy’s internal control over financial reporting.

PART III

Item 10 — Directors and Executive Officers of the Registrant

Information required under this Item with respect to directors is set forth in the Registrant’s Proxy Statement for its 2004 Annual Meeting of Shareholders’ under the caption “Section 16(a) Beneficial Ownership Reporting Compliance,” “Code of Ethics” and “Election of Directors,” which is incorporated by reference. Information with respect to Executive Officers is included in Item 1 to this report.

Item 11 — Executive Compensation

Information required under this Item is set forth in the Registrants Proxy Statement for its 2004 Annual Meeting of Shareholders under the caption “Executive Compensation,” which is incorporated by reference.

Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information concerning the security ownership of the directors and officers of Xcel Energy is contained under the caption “Common Stock Ownership of Directors and Executive Officers” in the Xcel Energy Proxy Statement for its 2004 Annual Meeting of Shareholders which is incorporated by reference. Information concerning securities authorized for issuance under equity compensation plans is contained under the caption “Securities Authorized for Issuance under Equity Compensation Plans” in Xcel Energy’s Proxy Statement for its 2004 Annual Meeting of Shareholders, which is incorporated by reference.

Item 13 — Certain Relationships and Related Transactions

Information concerning relationships and related transactions of the directors and officers of Xcel Energy is contained in the Xcel Energy Proxy Statement for its 2004 Annual Meeting of Shareholders, which is incorporated by reference.

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Item 14 — Principal Accountant Fees and Services

Information concerning fees paid to the principal accountant for each of the last two years is contained in the Xcel Energy Proxy Statement for its 2004 Annual Meeting of Shareholders, which is incorporated by reference.

Item 15 — Exhibits, Financial Statement Schedules and Reports on Form 8-K

     
(a) 1.
  Consolidated Financial Statements and Schedules
 
   
  Reports of Independent Auditors for the years ended Dec. 31, 2003, 2002 and 2001.
 
   
  Consolidated Statements of Operations for the three years ended Dec. 31, 2003.
 
   
  Consolidated Statements of Cash Flows for the three years ended Dec. 31, 2003.
 
   
  Consolidated Balance Sheets, Dec. 31, 2003 and 2002.
 
   
 
  Schedule I — Condensed Financial Information of Registrant

Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2003, 2002 and 2001 Notes to Consolidated Financial Statements
 
2.
  Exhibits
 
   
  * Indicates incorporation by reference
 
   
  + Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
 
   
Xcel Energy
 
   
2.01*
  Agreement and Plan of Merger, dated as of March 24, 1999, by and between Northern States Power Co. and New Century Energies, Inc. (Exhibit 2.1 to New Century Energies, Inc. Form 8-K (file no. 001-12907) dated March 24, 1999).
 
   
2.02*
  Order confirming NRG plan of reorganization dated Nov. 24, 2003 (Exhibit 99.b.10 to Form POS AMC (file no. 070-10152) dated Dec. 1, 2003).
 
   
2.03
  Release-Based Amount Agreement dated Dec. 5, 2003 between Xcel Energy Inc. and NRG Energy, Inc.
 
   
2.04
  Settlement Agreement dated Dec. 5, 2003 between Xcel Energy Inc. and NRG Energy, Inc.
 
   
2.05
  Employee Matters Agreement dated Dec. 5, 2003 between Xcel Energy Inc. and NRG Energy, Inc.
 
   
2.06
  Tax Matters Agreement dated Dec. 5, 2003 between Xcel Energy Inc. and NRG Energy, Inc.
 
   
Xcel Energy
 
   
3.01*
  Restated Articles of Incorporation of Xcel Energy (Exhibit 4.01 to Form 8-K (file no. 001-03034) filed Aug. 21, 2000).
 
   
3.02*
  By-Laws of Xcel Energy (Exhibit 4.3 to Form S-8 (file no. 333-48590) filed Oct. 25, 2000).
 
   
Xcel Energy
 
   
4.01*
  Trust Indenture dated Dec. 1, 2000, between Xcel Energy Inc. and Wells Fargo Bank Minnesota, National Association, as Trustee. (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Dec. 18, 2000).
 
   
4.02*
  Supplemental Trust Indenture dated Dec. 15, 2000, between Xcel Energy Inc. and Wells Fargo Bank Minnesota, National Association, as Trustee, creating $600 million principal amount of 7 percent Senior Notes, Series due 2010. (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Dec. 18, 2000).
 
   
4.03*
  Stockholder Protection Rights Agreement dated Dec. 13, 2000, between Xcel Energy Inc. and Wells Fargo Bank Minnesota, N.A., as Rights Agent. (Exhibit 1 to Form 8-K (file no. 001-03034) dated Jan. 4, 2001).
 
   
4.04*
  $400 million Five-Year Credit Agreement. (Exhibit 99.02 to Form 8-K (file no. 001-03034) dated Aug. 6, 2002).
 
   
4.05*
  Registration Rights Agreement dated Nov. 21, 2002 by and among Xcel Energy Inc. and Merrill Lynch, Pierce, Fenner & Smith Inc. and Lazard Freres & Co. LLC. (Exhibit 4.125 to Form 10-K (file no. 001-03034) dated March 31, 2003).
 
   
4.06*
  Redemption Agreement dated Nov. 25, 2002 by and among Xcel Energy Inc. and the Buyers listed on Exhibit A thereto. (Exhibit 4.136 to Form 10-K (file no. 001-03034) dated March 31, 2003).
 
   
4.07*
  Indenture dated Nov. 21, 2002 between Xcel Energy Inc. and Wells Fargo Bank NA, 7.5 percent convertible senior notes due 2007 (Exhibit 4.137 to Form 10-K (file no. 001-03034) dated March 31, 2003).

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4.08*
  Supplemental Trust Indenture No. 2 dated June 15, 2003 between Xcel Energy Inc. and Wells Fargo Bank NA, supplementing trust indenture dated Dec. 1, 2000 (Exhibit 4.01 to Form 10-Q (file no. 001-03034) dated Aug. 15, 2003).
 
   
4.09*
  Credit Agreement dated Jan. 22, 2003 between Xcel Energy Inc. and various lenders, creating a $100 million senior unsecured term loan facility (Exhibit 99.02 to Form 8-K (file no. 001-03034) dated Jan 23, 2003).
 
   
4.10
  Indenture dated Nov. 15, 2003 between Xcel Energy Inc. and Wells Fargo Bank Minnesota NA, 7.5 percent convertible senior notes due 2008.
 
   
4.11*
  Registration Rights Agreement dated June 24, 2003 among Xcel Energy Inc. and Credit Suisse First Boston LLC, McDonald Investments Inc. and UBS Securities LLC (Exhibit 4.10 to Form S-4 (file no. 001-03034) dated Oct. 9, 2003).
 
   
4.12
  Registration Rights Agreement dated Nov. 21, 2003 among Xcel Energy Inc., Citadel Equity Fund Ltd., Citadel Credit Trading Ltd., and Citadel Jackson Investment Fund Ltd.
 
   
NSP-Minnesota
 
   
4.13*
  Trust Indenture, dated Feb. 1, 1937, from Northern States Power Co. (a Minnesota corporation) to Harris Trust and Savings Bank, as Trustee. (Exhibit B-7 to file no. 2-5290).
 
   
4.14*
  Supplemental and Restated Trust Indenture, dated May 1, 1988, from Northern States Power Co. (a Minnesota corporation) to Harris Trust and Savings Bank, as Trustee. (Exhibit 4.02 to Form 10-K of NSP-Minnesota for the year 1988, file no. 001-03034).
 
   
  Supplemental Indentures between NSP-Minnesota and said Trustee, supplemental to Exhibit 4.13, dated as follows:
 
   
4.15*
  June 1, 1942 (Exhibit B-8 to file no. 2-97667).
 
   
4.16*
  Feb. 1, 1944 (Exhibit B-9 to file no. 2-5290).
 
   
4.17*
  Oct. 1, 1945 (Exhibit 7.09 to file no. 2-5924).
 
   
4.18*
  July 1, 1948 (Exhibit 7.05 to file no. 2-7549).
 
   
4.19*
  Aug. 1, 1949 (Exhibit 7.06 to file no. 2-8047).
 
   
4.20*
  June 1, 1952 (Exhibit 4.08 to file no. 2-9631).
 
   
4.21*
  Oct. 1, 1954 (Exhibit 4.10 to file no. 2-12216).
 
   
4.22*
  Sept. 1, 1956 (Exhibit 2.09 to file no. 2-13463).
 
   
4.23*
  Aug. 1, 1957 (Exhibit 2.10 to file no. 2-14156).
 
   
4.24*
  July 1, 1958 (Exhibit 4.12 to file no. 2-15220).
 
   
4.25*
  Dec. 1, 1960 (Exhibit 2.12 to file no. 2-18355).
 
   
4.26*
  Aug. 1, 1961 (Exhibit 2.13 to file no. 2-20282).
 
   
4.27*
  June 1, 1962 (Exhibit 2.14 to file no. 2-21601).
 
   
4.28*
  Sept. 1, 1963 (Exhibit 4.16 to file no. 2-22476).
 
   
4.29*
  Aug. 1, 1966 (Exhibit 2.16 to file no. 2-26338).
 
   
4.30*
  June 1, 1967 (Exhibit 2.17 to file no. 2-27117).
 
   
4.31*
  Oct. 1, 1967 (Exhibit 2.01R to file no. 2-28447).
 
   
4.32*
  May 1, 1968 (Exhibit 2.01S to file no. 2-34250).
 
   
4.33*
  Oct. 1, 1969 (Exhibit 2.01T to file no. 2-36693).
 
   
4.34*
  Feb. 1, 1971 (Exhibit 2.01U to file no. 2-39144).
 
   
4.35*
  May 1, 1971 (Exhibit 2.01V to file no. 2-39815).
 
   
4.36*
  Feb. 1, 1972 (Exhibit 2.01W to file no. 2-42598).
 
   
4.37*
  Jan. 1, 1973 (Exhibit 2.01X to file no. 2-46434).
 
   
4.38*
  Jan. 1, 1974 (Exhibit 2.01Y to file no. 2-53235).
 
   
4.39*
  Sept. 1, 1974 (Exhibit 2.01Z to file no. 2-53235).
 
   
4.40*
  April 1, 1975 (Exhibit 4.01AA to file no. 2-71259).

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4.41*
  May 1, 1975 (Exhibit 4.01BB to file no. 2-71259).
 
   
4.42*
  March 1, 1976 (Exhibit 4.01CC to file no. 2-71259).
 
   
4.43*
  June 1, 1981 (Exhibit 4.01DD to file no. 2-71259).
 
   
4.44*
  Dec. 1, 1981 (Exhibit 4.01EE to file no. 2-83364).
 
   
4.45*
  May 1, 1983 (Exhibit 4.01FF to file no. 2-97667).
 
   
4.46*
  Dec. 1, 1983 (Exhibit 4.01GG to file no. 2-97667).
 
   
4.47*
  Sept. 1, 1984 (Exhibit 4.01HH to file no. 2-97667).
 
   
4.48*
  Dec. 1, 1984 (Exhibit 4.01II to file no. 2-97667).
 
   
4.49*
  May 1, 1985 (Exhibit 4.36 to Form 10-K (file no. 001-03034) for the year 1985).
 
   
4.50*
  Sept. 1, 1985 (Exhibit 4.37 to Form 10-K (file no. 001-03034) for the year 1985).
 
   
4.51*
  July 1, 1989 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated July 7, 1989).
 
   
4.52*
  June 1, 1990 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated June 1, 1990).
 
   
4.53*
  Oct. 1, 1992 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Oct. 13, 1992).
 
   
4.54*
  April 1, 1993 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated March 30, 1993).
 
   
4.55*
  Dec. 1, 1993 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Dec. 7, 1993).
 
   
4.56*
  Feb. 1, 1994 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Feb. 10, 1994).
 
   
4.57*
  Oct. 1, 1994 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Oct. 5, 1994).
 
   
4.58*
  June 1, 1995 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated June 28, 1995).
 
   
4.59*
  April 1, 1997 (Exhibit 4.47 to Form 10-K (file no. 001-03034) for the year 1997).
 
   
4.60*
  March 1, 1998 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated March 11, 1998).
 
   
4.61*
  May 1, 1999 (Exhibit 4.49 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
 
   
4.62*
  June 1, 2000 (Exhibit 4.50 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
 
   
4.63*
  Aug. 1, 2000 (Assignment and Assumption of Trust Indenture) (Exhibit 4.51 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
 
   
4.64*
  Trust Indenture, dated July 1, 1999, between Northern States Power Co. (a Minnesota corporation) and Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-03034) dated July 21, 1999).
 
   
4.65*
  Supplemental Trust Indenture, dated July 15, 1999, between Northern States Power Co. (a Minnesota corporation) and Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.02 to NSP-Minnesota Form 8-K (file no. 001-03034) dated July 21, 1999).
 
   
4.66*
  Supplemental Trust Indenture, dated Aug. 18, 2000, supplemental to the Indenture dated July 1, 1999, among Xcel Energy, Northern States Power Co. (a Minnesota corporation) and Wells Fargo Bank Minnesota, National Association, as Trustee. (Exhibit 4.63 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
 
   
4.67*
  Supplemental Trust Indenture dated June 1, 2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between Northern States Power Co. (a Minnesota Corporation) and BNY Midwest Trust Co., as successor trustee (Exhibit 4.05 to Form 10-Q (file no. 000-31709) dated Sept. 30, 2002).
 
   
4.68*
  Supplemental Trust Indenture dated July 1, 2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between Northern States Power Co. (a Minnesota Corporation) and BNY Midwest Trust Co., as successor trustee (Exhibit 4.06 to Form 10-Q (file no. 000-31709) dated Sept. 30, 2002).
 
   
4.69*
  Supplemental Trust Indenture dated July 1, 2002, supplemental to the Indenture dated July 1, 1999, between Northern States Power Co. (a Minnesota Corporation) and Wells Fargo Bank Minnesota, National Association, as trustee (Exhibit 4.01 to Form 8-K (file no. 000-31709) dated July 8, 2002).
 
   
4.70*
  Supplemental Trust Indenture dated Aug. 1, 2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between Northern States Power Co. (a Minnesota Corporation) and BNY Midwest Trust Co., as successor trustee (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 22, 2002).
 
   
4.71*
  Credit Agreement between Northern States Power Co. (a Minnesota corporation), Bank One NA and Wells Fargo Bank Minnesota NA and other financial institutions party thereto dated May 16, 2003 (Exhibit 4.01 to NSP-Minnesota Form 10-Q (file no. 001-031387) dated Aug. 14, 2003).

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4.72*
  Supplemental Trust Indenture dated Aug. 1, 2003 between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1, 1988 (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 6, 2003).
 
   
4.73
  Supplemental Trust Indenture dated May 1, 2003 between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1, 1988.
 
   
NSP-Wisconsin
 
   
4.74*
  Trust Indenture, dated April 1, 1947, From Northern States Power Co. (a Wisconsin corporation) to Firstar Trust Co. (formerly First Wisconsin Trust Co.). (Exhibit 7.01 to Registration Statement 2-6982).
 
   
4.75*
  Supplemental Trust Indenture, dated March 1, 1949. (Exhibit 7.02 to Registration Statement 2-7825).
 
   
4.76*
  Supplemental Trust Indenture, dated June 1, 1957. (Exhibit 2.13 to Registration Statement 2-13463).
 
   
4.77*
  Supplemental Trust Indenture, dated Aug. 1, 1964. (Exhibit 4.20 to Registration Statement 2-23726).
 
   
4.78*
  Supplemental Trust Indenture, dated Dec. 1, 1969. (Exhibit 2.03E to Registration Statement 2-36693).
 
   
4.79*
  Supplemental Trust Indenture, dated Sept. 1, 1973. (Exhibit 2.03F to Registration Statement 2-49757).
 
   
4.80*
  Supplemental Trust Indenture, dated Feb. 1, 1982. (Exhibit 4.01G to Registration Statement 2-76146).
 
   
4.81*
  Supplemental Trust Indenture, dated March 1, 1982. (Exhibit 4.08 to Form 10-K (file no. 001-03140) for the year 1982).
 
   
4.82*
  Supplemental Trust Indenture, dated June 1, 1986. (Exhibit 4.09 to Form 10-K (file no. 001-03140) for the year 1986).
 
   
4.83*
  Supplemental Trust Indenture, dated March 1, 1988. (Exhibit 4.10 to Form 10-K (file no. 001-03140) for the year 1988).
 
   
4.84*
  Supplemental and Restated Trust Indenture, dated March 1, 1991. (Exhibit 4.01K to Registration Statement 33-39831).
 
   
4.85*
  Supplemental Trust Indenture, dated April 1, 1991. (Exhibit 4.01 to Form 10-Q (file no. 001-03140) for the quarter ended March 31, 1991).
 
   
4.86*
  Supplemental Trust Indenture, dated March 1, 1993. (Exhibit to Form 8-K (file no. 001-03140) dated March 3, 1993).
 
   
4.87*
  Supplemental Trust Indenture, dated Oct. 1, 1993. (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Sept. 21, 1993).
 
   
4.88*
  Supplemental Trust Indenture, dated Dec. 1, 1996. (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Dec. 12, 1996).
 
   
4.89*
  Trust Indenture dated Sept. 1, 2000, between Northern States Power Co. (a Wisconsin corporation) and Firstar Bank, N.A. as Trustee. (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Sept. 25, 2000).
 
   
4.90*
  Supplemental Trust Indenture dated Sept. 15, 2000, between Northern States Power Co. (a Wisconsin corporation) and Firstar Bank, N.A. as Trustee, creating $80 million principal amount of 7.64 percent Senior Notes, Series due 2008. (Exhibit 4.02 to Form 8-K (file no 001-03140) dated Sept. 25, 2000).
 
   
4.91*
  Supplemental Trust Indenture dated Sept. 1, 2003 between Northern States Power Co. (a Wisconsin corporation) and US Bank NA, supplementing indentures dated April 1, 1947 and March 1, 1991 (Exhibit 4.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated Nov. 13, 2003).
 
   
4.92
  Exchange and Registration Rights Agreement dated Oct. 2, 2003 among Northern States Power Co. (a Wisconsin corporation) and Goldman, Sachs & Co. and BNY Capital Markets, Inc.
 
   
PSCo
   
 
   
4.93*
  Indenture, dated as of Dec. 1, 1939, providing for the issuance of First Mortgage Bonds (Form 10 for 1946- Exhibit (B-1)).
 
   
4.94*
  Indentures supplemental to Indenture dated as of Dec. 1, 1939:

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    Previous Filing:           Previous Filing:    
    Form; Date or   Exhibit       Form; Date or   Exhibit
Dated as of
     file no.
     No.
     Dated as of
     file no.
     No.
March 14, 1941
  10, 1946   B-2   March 1, 1974   8-K, April 1974   2
May 14, 1941
  10, 1946   B-3   Dec. 1, 1974   8-K, December 1974   1
April 28, 1942
  10, 1946   B-4   Oct. 1, 1975   S-7, (2-60082)   2(b)(3)
April 14, 1943
  10, 1946   B-5   April 28, 1976   S-7, (2-60082)   2(b)(4)
April 27, 1944
  10, 1946   B-6   April 28, 1977   S-7, (2-60082)   2(b)(5)
April 18, 1945
  10, 1946   B-7   Nov. 1, 1977   S-7, (2-62415)   2(b)(3)
April 23, 1946
  10-K, 1946   B-8   April 28, 1978   S-7, (2-62415)   2(b)(4)
April 9, 1947
  10-K, 1946   B-9   Oct. 1, 1978   10-K, 1978   D(1)
June 1, 1947
  S-1, (2-7075)   7(b)   Oct. 1, 1979   S-7, (2-66484)   2(b)(3)
April 1, 1948
  S-1, (2-7671)   7(b)(1)   March 1, 1980   10-K, 1980   4(c)
May 20, 1948
  S-1, (2-7671)   7(b)(2)   April 28, 1981   S-16, (2-74923)   4(c)
Oct. 1, 1948
  10-K, 1948   4   Nov. 1, 1981   S-16, (2-74923)   4(c)
April 20, 1949
  10-K, 1949   1   Dec. 1, 1981   10-K, 1981   4(c)
April 24, 1950
  8-K, April 1950   1   April 29, 1982   10-K, 1982   4(c)
April 18, 1951
  8-K, April 1951   1   May 1, 1983   10-K, 1983   4(c)
Oct. 1, 1951
  8-K, November 1951   1   April 30, 1984   S-3, (2-95814)   4(c)
April 21, 1952
  8-K, April 1952   1   March 1, 1985   10-K, 1985   4(c)
Dec. 1, 1952
  S-9, (2-11120)   2(b)(9)   Nov. 1, 1986   10-K, 1986   4(c)
April 15, 1953
  8-K, April 1953   2   May 1, 1987   10-K, 1987   4(c)
April 19, 1954
  8-K, April 1954   1   July 1, 1990   S-3, (33-37431)   4(c)
Oct. 1, 1954
  8-K, October 1954   1   Dec. 1, 1990   10-K, 1990   4(c)
April 18, 1955
  8-K, April 1955   1   March 1, 1992   10-K, 1992   4(d)
April 24, 1956
  10-K, 1956   1   April 1, 1993   10-Q, June 30, 1993   4(a)
May 1, 1957
  S-9, (2-13260)   2(b)(15)   June 1, 1993   10-Q, June 30, 1993   4(b)
April 10, 1958
  8-K, April 1958   1   Nov. 1, 1993   S-3, (33-51167)   4(a)(3)
May 1, 1959
  8-K, May 1959   2   Jan. 1, 1994   10-K, 1993   4(a)(3)
April 18, 1960
  8-K, April 1960   1   Sept. 2, 1994   8-K, September 1994   4(a)
April 19, 1961
  8-K, April 1961   1   May 1, 1996   10-Q, June 30, 1996   4(a)
Oct. 1, 1961
  8-K, October 1961   2   Nov. 1, 1996   10-K, 1996   4(a)(3)
March 1, 1962
  8-K, March 1962   3(a)   Feb. 1, 1997   10-Q, March 31, 1997   4(a)
June 1, 1964
  8-K, June 1964   1   April 1, 1998   10-Q, March 31, 1998   4(a)
May 1, 1966
  8-K, May 1966   2   Aug. 15, 2002   10-Q, Sept. 30, 2002   4.01
July 1, 1967
  8-K, July 1967   2   Sept. 15, 2002   10-Q, Sept. 30, 2002   4.02
July 1, 1968
  8-K, July 1968   2   Sept. 1, 2002   8-K, Sept. 18, 2002   4.02
April 25, 1969
  8-K, April 1969   1   March 1, 2003   S-3, April 14, 2003 (333-104504)   4(a)(3)
April 21, 1970
  8-K, April 1970   1   April 1, 2003   10-Q, May 15, 2003 (001-03280)   4.01
Sept. 1, 1970
  8-K, September 1970   2   May 1, 2003   S-4, June 11, 2003 (333-106011)   4.4
Feb. 1, 1971
  8-K, February 1971   2   Sept. 1, 2003   8-K, Sept. 2, 2003 (001-03280)   4.01
Aug. 1, 1972
  8-K, August 1972   2            
June 1, 1973
  8-K, June 1973   1            
     
4.95*
  Indenture, dated as of Oct. 1, 1993, providing for the issuance of First Collateral Trust Bonds (Form 10-Q, Sept. 30, 1993 — Exhibit 4(a)).
 
   
4.96*
  Indentures supplemental to Indenture dated as of Oct. 1, 1993:
                     
    Previous Filing:           Previous Filing:    
    Form; Date or   Exhibit       Form; Date or   Exhibit
Dated as of
     file no.
     No.
     Dated as of
     file no.
     No.
Nov. 1, 1993
  S-3, (33-51167)   4(b)(2)   Aug. 15, 2002   10-Q, Sept. 30, 2002   4.03
Jan. 1, 1994
  10-K, 1993   4(b)(3)   Sept. 1, 2002   8-K, Sept. 18, 2002   4.01
Sept. 2, 1994
  8-K, September 1994   4(b)   Sept. 15, 2002   10-Q, Sept. 30, 2002   4.04
May 1, 1996
  10-Q, June 30, 1996   4(b)   March 1, 2003   S-3, April 14, 2003 (333-104504)   4(b)(3)
Nov. 1, 1996
  10-K, 1996   4(b)(3)   April 1, 2003   10-Q May 15, 2003 (001-03280)   4.02
Feb. 1, 1997
  10-Q, March 31, 1997   4(b)   May 1, 2003   S-4, June 11, 2003 (333-106011)   4.9
April 1, 1998
  10-Q, March 31, 1998   4(b)   Sept. 1, 2003   8-K, Sept. 2, 2003 (001-02380)   4.02
     
4.97*
  Indenture dated July 1, 1999, between PSCo and The Bank of New York, providing for the issuance of Senior Debt Securities and Supplemental Indenture dated July 15, 1999, between PSCo and The Bank of New York (Exhibits 4.1 and 4.2 to Form 8-K (file no. 001-03280) dated July 13, 1999).
 
   
4.98*
  Credit Agreement between Public Service Co. of Colorado, Bank One NA and Wells Fargo Bank Minnesota NA and other financial institutions party thereto dated May 16, 2003 (Exhibit 4.02 to PSCo Form 10-Q (file no. 001-03280) dated Aug. 14, 2003).

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4.99
  Supplemental Indenture dated Sept. 15, 2003 between Public Service Co. of Colorado and U.S. Bank Trust National Association, supplementing the indenture dated Dec. 1, 1939, creating $250 million principal amount of First Mortgage Bonds, Collateral Series L due 2013.
 
   
4.100
  Supplemental Indenture dated Sept. 15, 2003 between Public Service Co. of Colorado and U.S. Bank Trust National Association, supplementing the indenture dated Oct. 1, 1993, creating $250 million principal amount of First Collateral Trust Bonds, Series 12 due 2013.
 
   
4.101*
  Registration Rights Agreement dated March 14, 2003 among Public Service Co. of Colorado , Bank One Capital Markets, Inc. and UBS Warburg LLC (Exhibit 4.1 to Form S-4 (file no. 333-106011) dated June 11, 2003).

SPS

     
4.102*
  Indenture dated Feb. 1, 1999 between Southwestern Public Service Co. and The Chase Manhattan Bank (Exhibit B to Form 8-K (file no. 001-03789) dated Feb. 25, 1999).
 
   
4.103*
  First Supplemental Indenture dated March 1, 1999, between Southwestern Public Service Co. and The Chase Manhattan Bank (Exhibit C to Form 8-K (file no. 001-03789) dated Feb. 25, 1999).
 
   
4.104*
  Second Supplemental Indenture dated Oct. 1, 2001, between Southwestern Public Service Co. and The Chase Manhattan Bank (Exhibit 4.01 to Form 8-K (file no. 001-03789) dated Oct. 23, 2001).
 
   
4.105*
  Third Supplemental Indenture dated Oct 1, 2003 to the indenture dated Feb. 1, 1999 between Southwestern Public Service Co. and JPMorgan Chase Bank (Exhibit 4.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated Nov. 13, 2003).
 
   
4.106*
  Red River Authority for Texas Indenture of Trust dated July 1, 1991 (Form 10-K, Aug. 31, 1991 -Exhibit 4(b)).
 
   
4.107
  Credit Agreement between Southwestern Public Service Co., Bank One NA, Wells Fargo Bank NA, Bank of Montreal and The Bank of New York dated Feb. 17, 2004.
 
   
4.108
  Registration Rights Agreement dated Oct. 6, 2003 among Southwestern Public Service Co., Citigroup Global Markets Inc. and Credit Suisse First Boston LLC.
 
   
Xcel Energy
 
   
10.01*+
  Xcel Energy Omnibus Incentive Plan (Exhibit A to Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).
 
   
10.02*+
  Xcel Energy Executive Annual Incentive Award Plan (Exhibit B to Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).
 
   
10.03*+
  Employment Agreement, effective Dec. 15, 1997, between company and Mr. Paul J. Bonavia (Exhibit 10(a) to New Century Energies, Inc. Form 10-Q, (file no. 001-12927) dated Sept. 30, 1998).
 
   
10.04*+
  Employment Agreement, dated March 24, 1999, among Northern States Power Co. (a Minnesota corporation), New Century Energies, Inc. and Wayne H. Brunetti (Exhibit 10(b) to New Century Energies, Inc. Form 10-Q, (file no. 001-12927) dated Sept. 30, 1998).
 
   
10.05*+
  Amended and Restated Executive Long-Term Incentive Award Stock Plan. (Exhibit 10.02 to NSP-Minnesota Form 10-Q (file no. 001-03034) for the quarter ended March 31, 1998).
 
   
10.06*+
  Stock Equivalent Plan for Non-Employee Directors of Xcel Energy As Amended and Restated Effective Oct. 1, 1997. (Exhibit 10.15 to NSP-Minnesota Form 10-K (file no. 001-03034) for the year 1997).
 
   
10.07*+
  Senior Executive Severance Policy, effective March 24, 1999, between New Century Energies, Inc. and Senior Executives (Exhibit 10(a)(2) to New Century Energies, Inc. Form 10-Q, (file no. 001-12927) dated March 31, 1999).
 
   
10.08*+
  New Century Energies Omnibus Incentive Plan, effective Aug. 1, 1997 (Exhibit A to New Century Energies, Inc. Form DEF 14A (file no. 001-12927) dated Dec. 31, 1997).
 
   
10.09*+
  Directors’ Voluntary Deferral Plan (Exhibit 10(d) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).
 
   
10.10*+
  Supplemental Executive Retirement Plan (Exhibit 10(e) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).
 
   
10.11*+
  Salary Deferral and Supplemental Savings Plan for Executive Officers (Exhibit 10(f) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).
 
   
10.12*+
  Salary Deferral and Supplemental Savings Plan for Key Managers (Exhibit 10(g) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).
 
   
10.13*+
  Supplemental Executive Retirement Plan for Key Management Employees, as amended and restated March 26, 1991 (Exhibit 10(e)(2) to PSCo Form 10-K (file no. 001-3280) dated Dec. 31, 1991).
 
   
10.14*+
  Form of Key Executive Severance Agreement, as amended on Aug. 22, and Nov. 27, 1995. (Exhibit 10(3)(4) to PSCo Form 10-K (file no. 001-3280) dated Dec. 31, 1995).
 
   
10.15*+
  Southwestern Public Service Co. 1989 Stock Incentive Plan as amended April 23, 1996 (Exhibit 10(b) to SPS Form

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  10-K (file no. 001-03789) dated Aug. 31, 1996).
 
   
10.16*+
  Director’s Deferred Compensation Plan as amended Jan. 10, 1990 (Exhibit 10(c) to SPS Form 10-K (file no. 001-03789) dated Aug. 31, 1996).
 
   
10.17*+
  Supplemental Retirement Income Plan as amended July 23, 1991 (Exhibit 10(e) to SPS Form 10-K, (file no. 001-03789) dated Aug. 31, 1996).
 
   
10.18*+
  EPS Performance Unit Plan dated Oct. 27, 1992 (Exhibit 10(a) to SPS Form 10-K, (file no. 001-03789) dated Aug. 31, 1996).
 
   
10.19*+
  Xcel Energy Senior Executive Severance and Change-in-Control Policy dated Oct. 22, 2003 (Exhibit 10.10 to SPS Form S-4, (file no. 333-112032) dated Jan. 21, 2004)
 
   
10.20*+
  Separation Agreement and Release of All Claims between James T. Petillo and Xcel Energy dated Aug. 21, 2003 (Exhibit 10.52 to Form S-4 (file no. 333-109601) dated Oct. 9, 2003).
 
   
10.21*+
  Stock Equivalent Plan for Non-employee Directors of Xcel Energy as amended and restated Jan. 1, 2001 (Exhibit 10.01 to Form 10-Q (file no. 001-03034) dated Aug. 15, 2003).
 
   
10.22*+
  Separation agreement between Benjamin G.S. Fowke, III and Xcel Energy dated Oct. 26, 2001 (Exhibit 10.02 to Form 10-Q (file no. 001-03034) dated Aug. 15, 2003).
 
   
10.23+
  Xcel Energy Nonqualified Deferred Compensation Plan (2002 restatement).
 
   
10.24+
  Northern States Power Co. Non-employee Directors’ Deferred Compensation Plan.
 
   
10.25*+
  Xcel Energy 401(k) Savings Plan , amended and restated as of Jan. 1, 2002 (Exhibit 10.19 to SPS Form S-4 (file no. 333-112032) dated Jan. 21, 2004).
 
   
10.26*+
  New Century Energies, Inc. Employee Investment Plan for Bargaining Unit Employees and Former Non-bargaining Unit Employees, as amended and restated effective Jan. 1, 2002 but with certain retroactive amendments (Exhibit 10.20 to SPS Form S-4 (file no. 333-112032) dated Jan. 21, 2004).
 
   
10.27*
  Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Form U5B (file no. 001-03034) dated Nov. 16, 2000).
 
   
NSP-Minnesota
 
   
10.28*
  Facilities Agreement, dated July 21, 1976, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 kilovolt (kv) line. (Exhibit 5.06I to file no. 2-54310).
 
   
10.29*
  Transactions Agreement, dated July 21, 1976, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 kv line. (Exhibit 5.06J to file no. 2-54310).
 
   
10.30*
  Coordinating Agreement, dated July 21, 1976, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 kv line. (Exhibit 5.06K to file no. 2-54310).
 
   
10.31*
  Ownership and Operating Agreement, dated March 11, 1982, between Northern States Power Co. (a Minnesota corporation), Southern Minnesota Municipal Power Agency and United Minnesota Municipal Power Agency concerning Sherburne County Generating Unit No. 3. (Exhibit 10.01 to Form 10-Q for the quarter ended Sept. 30, 1994, file no. 001-03034).
 
   
10.32*
  Power Agreement, dated June 14, 1984, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board, extending the agreement scheduled to terminate on April 30, 1993, to April 30, 2005. (Exhibit 10.03 to Form 10-Q for the quarter ended Sept. 30, 1994, file no. 001-03034).
 
   
10.33*
  Power Agreement, dated August 1988, between Northern States Power Co. (a Minnesota corporation) and Minnkota Power Co. (Exhibit 10.08 to Form 10-K for the year 1988, file no. 001-03034).
 
   
10.34*
  Assignment and Assumption Agreement, dated Aug. 18, 2000 between Northern States Power Co. (a Minnesota corporation) and Xcel Energy Inc. (Exhibit 10.08 to Form 10 of NSP-Minnesota, file no. 000-31709).
 
   
10.35*
  Amended agreement for the sale of thermal energy dated Jan. 1, 1983 between NRG Energy (formerly known as Norenco Corp.) and Northern States Power Co. (a Minnesota corporation) and Norenco Corp. (Incorporated by reference to NRG’s Registration on Form S-1, file no. 333-35096).
 
   
10.36*
  Operations and maintenance agreement dated Nov. 1, 1996 between NRG Energy and Northern States Power Co.

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  (a Minnesota corporation) . (Incorporated by reference to NRG’s Registration on Form S-1, file no. 333-35096).
 
   
10.37*
  Amended Agreement for the sale of thermal energy and wood byproduct dated Dec. 1, 1986 between Northern States Power Co. (a Minnesota corporation) and Norenco Corp. (Incorporated by reference to NRG’s Registration on Form S-1, file no. 333-35096).
 
   
10.38*
  Restated Interchange Agreement dated Jan. 16, 2001 between Northern States Power Co. (a Wisconsin corporation) and Northern States Power Co. (a Minnesota corporation) (Exhibit 10.01 to NSP-Wisconsin Form S-4 (file no. 333-112033) dated Jan. 21, 2004).
 
   
10.39*
  500 megawatt System Participation Power Sale Agreement dated July 30, 2002 between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board (Exhibit 99.01 to NSP-Minnesota Form 8-K (file no. 001-31387) dated March 25, 2003).
 
   
NSP-Wisconsin
 
   
10.40*
  Restated Interchange Agreement dated Jan. 16, 2001 between Northern States Power Co. (a Wisconsin corporation) and Northern States Power Co. (a Minnesota corporation) (Exhibit 10.01 to Form S-4 (file no. 333-112033) dated Jan. 21, 2004.
 
   
PSCo
   
 
   
10.41*
  Amended and Restated Coal Supply Agreement entered into Oct. 1, 1984 but made effective as of Jan. 1, 1976 between Public Service Co. of Colorado and Amax Inc. on behalf of its division, Amax Coal Co. (Form 10-K, (file no. 001-03280) Dec. 31, 1984 — Exhibit 10(c)(1)).
 
   
10.42*
  First Amendment to Amended and Restated Coal Supply Agreement entered into May 27, 1988 but made effective Jan. 1, 1988 between Public Service Co. of Colorado and Amax Coal Co. (Form 10-K, (file no. 001-03280) Dec. 31, 1988-Exhibit 10(c)(2).
 
   
SPS
   
 
   
10.43*
  Coal Supply Agreement (Harrington Station) between Southwestern Public Service Co. and TUCO, dated May 1, 1979 (Form 8-K (file no. 001-03789), May 14, 1979 — Exhibit 3).
 
   
10.44*
  Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO, dated July 1, 1978 (Form 8-K, (file no. 001-03789) May 14, 1979 — Exhibit 5(A)).
 
   
10.45*
  Guaranty of Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO (Form 8-K, (file no. 3789) May 14, 1979 — Exhibit 5(B)).
 
   
10.46*
  Coal Supply Agreement (Tolk Station) between Southwestern Public Service Co. and TUCO dated April 30, 1979, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, (file no. 3789) Feb. 28, 1982 — Exhibit 10(b)).
 
   
10.47*
  Master Coal Service Agreement between Wheelabrator Coal Services Co. and TUCO dated Dec. 30, 1981, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, (file no. 3789) Feb. 28, 1982 — Exhibit 10(c)).
 
   
10.48
  Power Purchase Agreement dated May 23, 1997 between Borger Energy Associates, L.P, and Southwestern Public Service Co.
 
   
Xcel Energy
 
   
12.01
  Statement of Computation of Ratio of Earnings to Fixed Charges.
 
   
16.01*
  Letter Regarding Change in Accountant. (Exhibit 16.01 to Form 10-K (file no. 001-03034) for the year 2001).
 
   
21.01
  Subsidiaries of Xcel Energy Inc.
 
   
23.01
  Consent of Independent Auditors.
 
   
23.02
  Consent of Independent Accountants.
 
   
24.01
  Written Consent Resolution of the Board of Directors of Xcel Energy Inc., adopting Power of Attorney.
 
   
31.01
  Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
31.02
  Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
32.01
  Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
   
99.01
  Statement pursuant to Private Securities Litigation Reform Act of 1995.
 
   
99.02*
  Exhibit regarding the use of Arthur Andersen Audit Firm. (Exhibit 99.03 to Form 10-K (file no. 001-03034) for the year 2001).

(b)   Reports on Form 8-K — The following reports on Form 8-K were filed either during the three months ended Dec. 31, 2003, or between Dec. 31, 2003, and the date of this report.

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March 1, 2004 (filed March 1, 2004) — Item 5 and 7, Other Events and Financial Statements and Exhibits — Audited financial statements of Xcel Energy Inc. and its subsidiaries for the year ended Dec. 31, 2003 and the management’s discussion and analysis.

Feb. 11, 2004 (filed Feb. 11, 2004) — Item 7 and 12, Financial Statements and Exhibits and Results of Operations and Financial Condition — Feb. 16, 2004 presentation to Edison Electric Institute International Financial Conference.

Jan. 28, 2004 (filed Jan. 28, 2004) — Item 7 and 12, Financial Statements and Exhibits and Results of Operations and Financial Condition — Earnings release for fourth quarter 2003.

Jan. 28, 2004 (filed Jan. 28, 2004) — Item 5 and 7, Other Events and Financial Statements and Exhibits — Commodity Futures Trading Commission settlement regarding e prime.

Jan. 13, 2004 (filed Jan. 14, 2004) — Item 5 and 7, Other Events and Financial Statements and Exhibits — Xcel Energy enters into an agreement for the sale of Cheyenne Light Fuel and Power Co.

Dec. 5, 2003 (filed Dec. 13, 2003) — Item 2 and 7, Acquisition or Disposition of Assets and Financial Statements and Exhibits — NRG disposition disclosure and related pro-forma financial information.

Nov. 14, 2003 (filed Nov. 17, 2003) — Item 7 and 12, Financial Statements and Exhibits and Results of Operations and Financial Condition — Nov. 17, 2004 financial presentation to Banc of America.

Oct. 24, 2003 (filed Oct. 24, 2003) — Item 7 and 12, Financial Statements and Exhibits and Results of Operations and Financial Condition — Xcel Energy presentation to the Edison Electric Institute Financial Conference on Oct. 28, 2003.

Oct. 23, 2003 (filed Oct. 23, 2003) — Item 7 and 12, Financial Statements and Exhibits and Results of Operations and Financial Condition — Earnings release for third quarter 2003.

Oct. 22, 2003 (filed Oct. 22, 2003) — Item 5 and 7, Other Events and Financial Statements and Exhibits — R. Kelly promoted to president and chief operating officer, and B. Fowke promoted to chief financial officer.

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SCHEDULE I

CONDENSED FINANCIAL STATEMENTS OF XCEL ENERGY INC.
STATEMENTS OF OPERATIONS

                         
    Year ended Dec. 31,
    2003
  2002
  2001
    (Thousands of dollars)
Income:
                       
Equity in income of subsidiaries
  $ 547,258     $ 573,770     $  625,145  
 
   
 
     
 
     
 
 
Total income
    547,258       573,770       625,145  
Expenses and other deductions:
                       
Operating expenses
    22,004       30,715       10,629  
Other (income) expense
    (8,292 )     (10,706 )     (10,741 )
Interest charges and financing costs
    73,444       77,786       51,970  
 
   
 
     
 
     
 
 
Total expenses and other deductions
    87,156       97,795       51,858  
 
   
 
     
 
     
 
 
Income from continuing operations before taxes
    460,102       475,975       573,287  
Income taxes (benefit)
    (49,918 )     (51,718 )     (17,734 )
 
   
 
     
 
     
 
 
Income from continuing operations
    510,020       527,693       591,021  
Income from discontinued operations, net of tax
    112,372       (2,745,684 )     203,945  
 
   
 
     
 
     
 
 
Net income (loss)
    622,392       (2,217,991 )     794,966  
Preferred dividend requirements
    4,241       4,241       4,241  
 
   
 
     
 
     
 
 
Earnings available to common
  $ 618,151     $ (2,222,232 )   $ 790,725  
 
   
 
     
 
     
 
 

See Xcel Energy Inc. Notes to Consolidated Financial Statements in Part II, Item 8.

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SCHEDULE I

CONDENSED FINANCIAL STATEMENTS OF XCEL ENERGY INC.
STATEMENTS OF CASH FLOWS
                             
        Years Ended Dec. 31  
       
 
        2003          2002          2001  
       
   
   
 
                (in thousands)          
OPERATING ACTIVITIES:
                       
   
Net cash flows provided by operating activities
    772,709       484,447       313,885  
 
 
   
   
 
INVESTING ACTIVITIES:
                       
 
Capital contributions to subsidiaries
    (227,403 )     (164,250 )     (480,389 )
 
Restricted cash
    (37,213 )            
 
Investing cash flows provided by discontinued operations
    120,768       (511,724 )     371,718  
 
 
   
   
 
   
Net cash used in investing activities
    (143,848 )     (675,974 )     (108,671 )
 
 
   
   
 
FINANCING ACTIVITIES:
                       
 
Short-term borrowings — net
    (399,000 )     (47,550 )     180,247  
 
Proceeds from issuance of long-term debt
    250,348       318,600        
 
Repayment of long-term debt
          (107,373 )      
 
Proceeds from issuance of common stock
    3,219       69,488       129,011  
 
Dividends paid
    (303,316 )     (496,375 )     (518,894 )
 
Financing cash flows related to discontinued operations
          511,724          
 
 
   
   
 
   
Net cash used in financing activities
    (448,749 )     248,514       (209,636 )
 
 
   
   
 
Net increase (decrease) in cash
    180,112       56,987       (4,422 )
Cash at beginning of year
    57,368       381       4,803  
 
 
   
   
 
Cash at end of year
  $ 237,480     $ 57,368     $ 381  
 
 
   
   
 

See Xcel Energy Inc. Notes to Consolidated Financial Statements in Part II, Item 8.

 


Table of Contents

SCHEDULE I

CONDENSED FINANCIAL STATEMENTS OF XCEL ENERGY INC.
BALANCE SHEETS
                   
      2003     2002
     
   
Assets
               
 
Cash and cash equivalents
  $ 237,480     $ 57,368  
Restricted cash
    37,213        
Accounts receivable from subsidiaries
    208,946       414,333  
Current asset related to discontinued operations
    280,230        
Other current assets
    1,885        
 
 
   
 
 
Total Current Assets
    765,754       471,701  
 
Investment in subsidiaries
    6,370,079       5,576,825  
Other assets
    97,850       28,990  
 
 
   
 
 
Total Other Assets
    6,467,929       5,605,815  
 
 
Total Assets
  $ 7,233,683     $ 6,077,516  
 
 
   
 
Liabilities and Equity
               
 
Current liability related to discontinued operations
    752,000        
Short-term debt
  $     $ 399,000  
Dividends payable
    75,866       75,814  
Other current liabilities
    53,368       8,916  
 
 
   
 
 
Total Current Liabilities
    881,234       483,730  
 
Other liabilities
    13,213       3,319  
 
 
   
 
 
Total Other Liabilities
    13,213       3,319  
 
Long-term debt
    1,067,816       820,163  
Preferred stockholders’ equity
    104,980       105,320  
Common stockholders’ equity
    5,166,440       4,664,984  
 
 
   
 
 
Total Capitalization
    6,339,236       5,590,467  
 
 
Total Liabilities and Equity
  $ 7,233,683     $ 6,077,516  
 
 
   

See Xcel Energy Inc. Notes to Consolidated Financial Statements in Part II, Item 8.

 


Table of Contents

SCHEDULE I

CONDENSED FINANCIAL STATEMENTS OF XCEL ENERGY INC.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
AND OTHER COMPREHENSIVE INCOME

Incorporated by reference is Xcel Energy Inc. and Subsidiaries Consolidated Statements of Common Stockholders’ Equity and Other Comprehensive Income in Part II, Item 8.

See Xcel Energy Inc. Notes to Consolidated Financial Statements in Part II, Item 8.

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SCHEDULE II

XCEL ENERGY INC.
AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

Years Ended Dec. 31, 2003, 2002 and 2001

                                         
            Additions
       
    Balance at   Charged to   Charged to   Deductions   Balance at
    beginning of   costs &   other   from   end of
    period
  expenses
  accounts
  reserves(1)
  period
    (Thousands of dollars)
Xcel Energy
                                       
Reserve deducted from related assets:
                                       
Provision for uncollectible accounts:
                                       
2003
  $ 23,970     $ 35,746     $ 14,550     $ 43,160     $ 31,106  
 
   
 
     
 
     
 
     
 
     
 
 
2002
  $ 23,006     $ 24,770     $ 9,690     $ 33,496     $ 23,970  
 
   
 
     
 
     
 
     
 
     
 
 
2001
  $ 18,877     $ 24,582     $ 6,215     $ 26,668     $ 23,006  
 
   
 
     
 
     
 
     
 
     
 
 

(1)   Uncollectible accounts written off or transferred to other parties.

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Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.

     
  Xcel Energy Inc.
 
   
March 15, 2004
  /s/ Benjamin G.S. Fowke III
 
 
  Benjamin G.S. Fowke III
Vice President, Chief Financial Officer and Treasurer

     Pursuant to the requirements of the Securities Exchange Act of 1934, this report signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

     
/s/ Wayne H. Brunetti
  /s/ Richard C. Kelly

 
 
 
Wayne H. Brunetti
Chief Executive Officer and Chairman of the Board
(Principal Executive Officer)
  Richard C. Kelly
President and Chief Operating Officer
(Principal Operating Officer)
 
   
/s/ Benjamin G.S. Fowke III
  /s/ Teresa S. Madden

 
 
 
Benjamin G.S. Fowke III
Vice President, Chief Financial Officer and Treasurer
(Chief Financial Officer)
  Teresa S. Madden
Vice President and Controller
(Principal Accounting Officer)
 
   
*
  *

 
 
 
David A. Christensen
Director
  C. Coney Burgess
Director
 
   
*
  *

 
 
 
A. Barry Hirschfeld
Director
  Roger R. Hemminghaus
Director
 
   
*
  *

 
 
 
Albert F. Moreno
Director
  Douglas W. Leatherdale
Director
 
   
*
  *

 
 
 
A. Patricia Sampson
Director
  Margaret R. Preska
Director
 
   
*
  *

 
 
 
Rodney E. Slifer
Director
  Allan L. Schuman
Director
 
   
*/s/ Teresa S. Madden
  *

 
 
 
Teresa S. Madden
Attorney-in-Fact
  W. Thomas Stephens
Director

139