UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

     For the quarterly period ended March 31, 2004

or

     For the transition period from            to

Commission File Number: 1-3034

Xcel Energy Inc.

Registrant’s telephone number, including area code (612) 330-5500

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 [  ] No

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

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Table of Contents

PART I – FINANCIAL INFORMATION

XCEL ENERGY INC. AND SUBSIDIARIES

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly the financial position of Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) as of March 31, 2004, and Dec. 31, 2003; the results of its operations and stockholders’ equity for the three months ended March 31, 2004 and 2003; and its cash flows for the three months ended March 31, 2004 and 2003. Due to the seasonality of Xcel Energy’s electric and natural gas sales and variability of nonregulated operations, such interim results are not necessarily an appropriate base from which to project annual results.

The accounting policies followed by Xcel Energy are set forth in Note 1 to the consolidated financial statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2003. The following notes should be read in conjunction with such policies and other disclosures in the Annual Report on Form 10-K.

1. Accounting Policies

FASB Interpretation No. 46 (FIN No. 46) — On Jan. 1, 2004, Xcel Energy adopted FIN No. 46, which requires an enterprise’s consolidated financial statements to include variable interest entities for which the enterprise is determined to be the primary beneficiary. Historically, consolidation has been required only for entities in which an enterprise has a majority voting or controlling interest. As a result, Xcel Energy consolidated a portion of its affordable housing investments made primarily through Eloigne, which were previously accounted for under the equity method. The consolidation had no impact on net income or earnings per share. No other arrangements were determined to be material variable interests requiring disclosure or consolidation under FIN No. 46.

As of March 31, 2004, the assets of the affordable housing investments consolidated as a result of FIN No. 46 were approximately $144 million and long-term liabilities were approximately $78 million, including long-term debt of $77 million. Investments of $51 million, previously reflected as a component of investments in unconsolidated affiliates, have been consolidated with the entities’ assets initially recorded at their carrying amounts as of Jan. 1, 2004. The long-term debt is collateralized by the affordable housing projects and is nonrecourse to Xcel Energy.

Change in Accounting Principle - Inventory - Effective January 1, 2004, Public Service Company of Colorado (PSCo) changed its method of accounting for the cost of stored natural gas for its local distribution operations from the last-in-first-out (LIFO) pricing method to the average cost pricing method. This change in accounting was approved by the Colorado Public Utilities Commission (CPUC) and was accounted for as a cumulative effect as required by the CPUC authorization. The average cost method has historically been used for pricing stored natural gas by both Northern States Power Company, a Minnesota corporation, (NSP-Minnesota) and Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin), as well as by PSCo for natural gas stored for use in its electric utility operations.

The cumulative effect of this change in accounting principle resulted in an increase to gas storage inventory and a corresponding decrease to the deferred gas cost accounts of approximately $36 million as of January 1, 2004. Of this amount, $33 million related to current gas storage inventory and $3 million related to long-term gas storage inventory. As gas costs are 100 percent recoverable under PSCo’s gas cost adjustment mechanism, the cumulative effect of this change had no impact on net income or earnings per share. Prior period financial statements were not restated since the CPUC ordered this change effective Jan. 1, 2004. As ordered by the CPUC, the decrease in the cost of gas will reduce rates to retail gas customers in Colorado during 2004.

Reclassifications – Certain items in the statements of operations and balance sheets have been reclassified from prior period presentation to conform to the 2004 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 Energy, Inc. (NRG) and other discontinued operations.

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2. Discontinued Operations

A summary of the subsidiaries presented as discontinued operations is discussed below. Results of operations as well as assets and liabilities for the divested businesses and the businesses held for sale are reported on a net basis as a component of discontinued operations for all periods presented. Amounts previously reported for 2003 have been restated to conform to the 2004 discontinued operations presentation.

Regulated Utility Segments

During 2004, Xcel Energy reached an agreement to sell its regulated electric and natural gas subsidiary, Cheyenne Light, Fuel and Power Company (CLF&P). As a result of this agreement, CLF&P is classified as held for sale. The sale is pending regulatory approval and is expected to be completed during 2004.

During 2003, Xcel Energy completed the sale of two subsidiaries in its regulated natural gas utility segment, Black Mountain Gas Co. (BMG) and Viking Gas Transmission Co. (Viking), including its interest in Guardian Pipeline, LLC. As a result, a gain of 5 cents per share was recorded in the first quarter of 2003, related to the sale of Viking. The BMG sale was completed in the third quarter of 2003.

NRG

Until December 2003, NRG was a wholly owned subsidiary of Xcel Energy. 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.” In December 2003, NRG emerged from bankruptcy, and Xcel Energy relinquished its entire ownership interest in NRG. See additional discussion at Note 3.

Nonregulated Subsidiaries — All Other Segment

Xcel Energy International and e prime — During 2003, the board of directors of Xcel Energy approved management’s plan to exit businesses conducted by Xcel Energy International and e prime. Xcel Energy International primarily includes power generation projects in Argentina. e prime provided energy-related products and services, which included natural gas commodity trading and marketing and energy consulting. The 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. In accordance with the provisions of SFAS No. 144, assets held for sale will not be depreciated commencing with their classification as such.

Xcel Energy sold all of the contractual assets of e prime during the first quarter of 2004. During the first quarter of 2004, Xcel Energy closed the sale of one of its Argentina subsidiaries, Hidroelectrica del Sur S.A. (HDS). The sale price was immaterial and approximated the book value of Xcel Energy’s investment in HDS. Xcel Energy International is in the process of marketing its remaining assets and operations to prospective buyers and expects to exit the businesses during 2004.

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Summarized Financial Results of Discontinued Operations

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

3. NRG Bankruptcy Settlement

In May 2003, NRG filed for bankruptcy to restructure its debt. At the time of the filing, NRG was a subsidiary of Xcel Energy. NRG’s filing included its plan of reorganization and a settlement among NRG, Xcel Energy and members of NRG’s major creditor constituencies.

In December 2003, NRG emerged from bankruptcy. As part of the reorganization, Xcel Energy completely relinquished its ownership interest in NRG. As part of the overall settlement, Xcel Energy agreed to pay $752 million to NRG to settle all claims of NRG against Xcel Energy, and claims of NRG creditors against Xcel Energy. In return for such payments, Xcel Energy received, or was granted, voluntary and involuntary releases from NRG and its creditors.

On Feb. 20, 2004, Xcel Energy paid $400 million to NRG. On April 30, 2004, Xcel Energy paid $328.5 million of the remaining $352 million, based on tax refunds received by Xcel Energy in March 2004 from the carry back of its 2003 net operating loss that resulted from the write-off of its investment in NRG. Xcel Energy has met these cash requirements with cash on hand, including the tax refund proceeds, and/or borrowings under its revolving credit facility. The remaining $23.5 million payment is due on May 30, 2004.

4. Tax Matters — Corporate-Owned Life Insurance

PSCo’s wholly owned subsidiary PSR Investments, Inc. (PSRI) owns and manages permanent life insurance policies on some of 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 deductions taken on the interest expense on these borrowings. The IRS has challenged the deductibility of such interest expense deductions and has disallowed the deductions taken in tax years 1993 through 1997.

After consultation with tax counsel, Xcel Energy contends that the IRS determination is not supported by relevant 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 law. Accordingly, PSRI has not recorded any provision for income tax or related interest or penalties that may be imposed by the IRS and has continued to take deductions for interest expense related to policy loans on its income tax returns for subsequent years.

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In April 2004 Xcel Energy filed a lawsuit in U.S. District Court for the District of Minnesota against the IRS to establish its entitlement to deduct policy loan interest. The litigation could require several years to reach final resolution. Although the ultimate resolution of this matter is uncertain, it could have a material adverse effect on Xcel Energy’s financial position and results of operations. Defense of Xcel Energy’s position may require significant cash outlays, which may or may not be recoverable in a court proceeding.

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.

5. Rates and Regulation

Market Based Rate Authority Rule Proposal – On April 14, 2004, the Federal Energy Regulatory Commission (FERC) initiated a new rulemaking on future market-based rates authorizations and issued interim requirements for FERC jurisdictional electric utilities that have been granted authority to make wholesale sales at market-based rates. NSP-Minnesota, NSP-Wisconsin, PSCo and Southwestern Public Service Company (SPS) currently have wholesale market-based rate authorization from the FERC. The FERC adopted a new interim method to assess generation market power and modified measures to mitigate market power where it is found. The assessments will be made of all initial market-based rate applications and triennial reviews on an interim basis. The Xcel Energy regulated subsidiaries’ triennial review is pending. An assessment will be made of whether the utility is a pivotal supplier based on a control area’s annual peak demand or it complies with market share requirements on a seasonal basis. If an applicant is determined to have generation market power, the applicant has the opportunity to propose its own mitigation plan or may implement default mitigation established by the FERC. The default mitigation limits prices for sales of power to cost-based rates within areas where an applicant is found to have market power. Xcel Energy is reviewing the new requirements to determine what, if any, impact the new requirements will have on the wholesale market-based rate authority of the utility subsidiaries.

Department of Energy Blackout Report – On April 6, 2004, the U.S. Department of Energy issued its final report regarding the Aug. 14, 2003 electric blackout in the eastern United States, which did not affect the electric systems of the Xcel Energy regulated utilities. The report recommends 47 specific changes to current statutes, rules or practices in order to improve the reliability of the infrastructure used to transmit electric power. The recommendations include the establishment of mandatory reliability standards and financial penalties for noncompliance. On April 14, 2004, FERC issued a policy statement requiring electric utilities, including the Xcel Energy utility subsidiaries, to submit a report on vegetation management practices and indicating the FERC’s intent to make North American Electric Reliability Council (NERC) reliability standards mandatory. Xcel Energy is reviewing the final report and FERC policy statement. Implementation of the blackout report recommendations and the FERC policy statement could increase future transmission costs, but the extent of this effect cannot be determined at this time.

Midwest ISO Transmission and Energy Markets Tariff – On March 31, 2004, the Midwest Independent Transmission System Operator, Inc. (Midwest ISO) regional transmission organization filed its proposed transmission and energy markets tariff, which would establish regional wholesale energy markets using locational marginal cost pricing and financial transmission rights. NSP-Minnesota and NSP-Wisconsin are Midwest ISO members, and their generation plants and transmission systems would operate subject to the tariff if it is approved by the FERC. The Midwest ISO proposed a Dec. 1, 2004 effective date. Comments regarding the tariff must be filed with the FERC by May 7, 2004. Implementation of a wholesale regional market using the locational marginal cost pricing and financial transmission rights is expected to provide a benefit to NSP-Minnesota and NSP-Wisconsin through a reduction in overall power costs. However, Xcel Energy opposes certain aspects of the tariff as proposed, and believes the Midwest ISO should implement the new market mechanisms only after it demonstrates that it will protect reliability.

Minnesota Service Quality Investigation – 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. Among other provisions, the proposed service quality plan contains underperformance payments for the failure to meet certain reliability an customer service metrics. On March 10, 2004, the Minnesota Public Utilities Commission (MPUC) issued an order approving the settlement, but modifying it to include an annual independent audit of NSP-Minnesota’s service outage records and requiring additional under-performance payments for any future finding of inaccurate data by an independent auditor. Both state agencies and NSP-Minnesota have the option under the settlement to void the agreement in the event of a significant modification by the MPUC. On March 29, 2004, NSP-Minnesota submitted a Petition for Clarification of the MPUC’s March 10th order. Another party also submitted a Petition for Reconsideration on the same date. The MPUC has scheduled a hearing for May 13, 2004 to consider these petitions.

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PSCo Least Cost Resource Plan – On April 30, 2004, PSCo filed its 2003 least-cost resource plan (LCP) with the CPUC. The LCP identifies the resources necessary to meet the PSCo’s estimated load requirements for the period 2004 through 2013. PSCo has identified that it needs 3,600 megawatts of capacity to meet its customers requirements over this time period. Of this amount, PSCo believes that 2,000 megawatts will come from new resources, and that it will be able to enter into new contracts with existing suppliers whose contracts expire during the resource acquisition period for the remainder of its needs. As part of its resource plan, PSCo is seeking waiver of certain CPUC rules to allow it to build a new 750 megawatt coal-fired unit at its existing Comanche power plant site located in Pueblo, Colorado. PSCo plans to own 500 megawatts of this new facility. Two of PSCo’s wholesale customers have options to participate in the ownership of the remaining 250 megawatts, and PSCo is in discussions with them regarding the plant’s development. In addition to requesting a certificate of public convenience and necessity for the new coal unit, PSCo is requesting in a separate application for CPUC authorization to construct and own the transmission facilities necessary to tie the new facility into PSCo’s high voltage transmission network. PSCo is also filing a separate application for a specific regulatory plan to address the impacts of purchased capacity contracts on its capital structure and to expedite the recovery of the costs of financing the new power plant and related transmission.

PSCo Capacity Cost Adjustment - In October 2003, PSCo filed an application to recover incremental capacity costs through a purchased capacity cost adjustment (PCCA) rider. The PCCA is designed to recover purchased capacity payments to power suppliers that are not included in PSCo’s current base electric rates or other recovery mechanisms. Based on the current request, the capacity rider is expected to recover approximately $27 million in 2004, $44 million in 2005 and $38 million in 2006. In addition, PSCo has proposed to refund to its retail customers 100 percent of any electric earnings in excess of its authorized rate of return on equity, currently 10.75 percent, through 2006. The CPUC staff and the Office of Consumer Counsel (OCC) have proposed that only resources approved by the CPUC as a part of a 1999 resource plan and the resources in base rates should factor into the PCCA calculation. Over the period 2004 through 2006, the CPUC staff and OCC position would reduce the PCCA revenue requested by PSCo by approximately one third. Hearings were held in April 2004. Based on the current schedule, PSCo expects a final decision with new rates in effect in June 2004, if the CPUC approves the PCCA.

6. Commitments and Contingent Liabilities

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

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

Xcel Energy Inc. Shareholder Derivative Action — Edith Gottlieb vs. Xcel Energy, Inc. et al; Essmacher vs. Brunetti; McLain vs. Brunetti — In August 2002, a shareholder derivative action was filed in the U.S. District Court for the District of Minnesota (Gottlieb), 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 similar securities class actions and an amended complaint was filed. Two additional derivative actions were filed in the state trial court in Hennepin County, Minn. (Essmacher and McLain), 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. In March 2004, plaintiffs filed notices of appeal related to this decision. In April 2004, plaintiffs withdrew their appeals. Discovery is proceeding in conjunction with other securities litigation.

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Other Contingencies – The circumstances set forth in Notes 15, 17 and 18 to the consolidated financial statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2003, appropriately represent, in all material respects, the current status of other commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident, and are incorporated herein by reference. The following are unresolved contingencies that are material to Xcel Energy’s financial position:

•		Tax Matters — See Note 4 to the accompanying consolidated financial statements for discussion of exposures regarding the tax deductibility of corporate-owned life insurance loan interest; and
•		Guarantees — See Note 7 to the accompanying consolidated financial statements for discussion of exposures under various guarantees.

7. Short-Term Borrowings and Other Financing Instruments

Short-Term Borrowings

At March 31, 2004, Xcel Energy and its subsidiaries had approximately $91 million of short-term debt outstanding at a weighted average interest rate of 1.93 percent.

Guarantees

Xcel Energy provides various 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 guarantees. On March 31, 2004, Xcel Energy had issued guarantees of up to $89 million with no exposure under these guarantees. In addition, Xcel Energy provides indemnity protection for bonds issued by subsidiaries. The total amount of bonds with this indemnity outstanding as of March 31, 2004, was approximately $29 million. The total exposure of this indemnification cannot be determined at this time. Xcel Energy believes the exposure to be significantly less than the total amount of bonds outstanding.

8. Derivative Valuation and Financial Impacts

Xcel Energy records 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. Statement of Financial Accounting Standard (SFAS) No. 133, as amended, (SFAS No. 133) requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.

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

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.

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Cash Flow Hedges

Xcel Energy and its subsidiaries enter into derivative instruments to manage variability of future cash flows from changes in commodity prices and interest rates. 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 March 31, 2004, Xcel Energy and its utility subsidiaries had various commodity-related contracts designated as cash flow hedges extending through 2009. The fair value of these cash flow hedges is recorded in either Other Comprehensive Income or deferred as a regulatory asset or liability. This classification is based on the regulatory recovery mechanisms in place. Amounts deferred in these accounts 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 March 31, 2004, Xcel Energy had net losses of $0.1 million accumulated in Other Comprehensive Income related to commodity cash flow hedge contracts that are expected to be recognized in earnings during the next 12 months as the hedged transactions settle. However, due to the volatility of commodities markets, the value in Other Comprehensive Income will likely change prior to its recognition in earnings.

Xcel Energy and its subsidiaries enter into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate 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 recognize earnings during the next 12 months net losses from Other Comprehensive Income related to interest cash flow hedge contracts of approximately $0.1 million.

Gains or losses on 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 interest rate hedging transactions 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. There was no hedge ineffectiveness in the first quarter of 2004.

Fair Value Hedges

Xcel Energy enters into interest rate swap instruments that effectively hedge the fair value of fixed rate debt. Changes in the fair value of hedges 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.

The fair value of all 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.

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 normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that meet the requirements of normal are documented and exempted from the accounting and reporting requirements of SFAS No. 133.

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.

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

9. Detail of Interest and Other Income (Expense), net

Interest and other income (expense), net is comprised of the following:

10. Common Stock and Equivalents

Xcel Energy has common stock equivalents consisting of convertible senior notes and options. The dilutive impacts of common stock equivalents affected earnings per share as follows for the three months ending March 31, 2004 and 2003:

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11. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

Employer Contributions

In its Annual Report on Form 10-K for the year ending Dec. 31, 2003, Xcel Energy disclosed that it expected to contribute $10 million to one of its pension plans in 2004. This contribution has not yet been made, but Xcel Energy anticipates that it will be made before year end 2004.

12. Segment Information

Xcel Energy has the following reportable segments: Regulated Electric Utility, Regulated Natural Gas Utility and All Other. Trading operations performed by regulated operating companies are not a reportable segment. Electric trading results are included in the Regulated Electric Utility segment.

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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

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

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,” “estimate,” “expect,” “objective,” “outlook,” “projected,” “possible,” “potential” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to:

•		Economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures;
•		The risk of a significant slowdown in growth or decline in the U.S. economy, the risk of delay in growth recovery in the U.S. economy or the risk of increased cost for insurance premiums, security and other items as a consequence of the Sept. 11, 2001, terrorist attacks;
•		Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where Xcel Energy has a financial interest;
•		Customer business conditions, including demand for their products or services and supply of labor and materials used in creating their products and services;
•		Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the SEC, the Federal Energy Regulatory Commission and similar entities with regulatory oversight;
•		Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, Xcel Energy or any of its subsidiaries; or security ratings;
•		Factors affecting utility and nonutility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel, nuclear fuel or natural gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; nuclear or environmental incidents; or electric transmission or gas pipeline constraints;
•		Employee workforce factors, including loss or retirement of key executives, collective bargaining agreements with union employees, or work stoppages;
•		Increased competition in the utility industry or additional competition in the markets served by Xcel Energy and its subsidiaries;
•		State, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and natural gas markets; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;
•		Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options;
•		Nuclear regulatory policies and procedures, including operating regulations and spent nuclear fuel storage;
•		Social attitudes regarding the utility and power industries;
•		Risks associated with the California power and other western markets;
•		Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;
•		Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;
•		Risks associated with implementations of new technologies;
•		Other business or investment considerations that may be disclosed from time to time in Xcel Energy’s SEC filings or in other publicly disseminated written documents; and
•		The other risk factors listed from time to time by Xcel Energy in reports filed with the SEC, including Exhibit 99.01 to this report on Form 10-Q for the quarter ended March 31, 2004.

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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 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;
•		the regulated utility business of CLF&P for which a sale agreement was entered into in early 2004;
•		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 2 to the consolidated financial statements for a further discussion of discontinued operations.

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(a) Not a reportable segment. Included in All Other segment results in Note 12 to the consolidated financial statements. Other utility results included in the earnings contribution table above includes certain subsidiaries of the utility operating companies that conduct non-utility activities. The largest of these other utility businesses is PSRI, a subsidiary of PSCo that owns and manages life insurance policies for PSCo employees and retirees.

The following table summarizes significant components contributing to the changes in the first quarter of 2004 earnings per share compared with the same period in 2003, which are discussed in more detail later.

Utility Segment Results

For the first quarter of 2004, net income from utility operations increased largely due to strong short-term wholesale margins, sales growth and lower depreciation expense in 2004, partially offset by higher purchased capacity costs and higher operating and maintenance expenses. See below for additional discussion of specific margin and cost items affecting utility operating results.

The following summarizes the estimated impact of weather on regulated utility earnings per share, based on estimated temperature variations from historical averages (excluding the impact on energy trading operations):

Other Results — Nonregulated Subsidiaries and Holding Company Costs

The following table summarizes the earnings-per-share contributions of Xcel Energy’s nonregulated businesses and holding company results:

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Seren – 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. On March 31, 2004, Xcel Energy’s investment in Seren was approximately $260 million.

Financing Costs and Preferred Dividends – Nonregulated and holding company results include interest expense and preferred dividend costs, which are incurred at the Xcel Energy and intermediate holding company levels and are not directly assigned to individual subsidiaries.

Other Nonregulated Results – Other nonregulated results for the first quarter of 2003 include losses from Utility Engineering related to fixed costs in excess of project income and project write downs, which did not recur.

Discontinued Operations

Discontinued - - Utility Segments – During 2004, Xcel Energy reached an agreement to sell its regulated electric and natural gas subsidiary, CLF&P. As a result of this agreement, Xcel Energy considers CLF&P held for sale and reports its results as a component of discontinued operations for all periods presented. The sale is pending regulatory approval and is expected to be completed during 2004. CLF&P contributed approximately $789,000 to net income, which is less than 1 cent of earnings per share, for the three months ended March 31, 2004.

During 2003, Xcel Energy completed the sale of two subsidiaries in its regulated natural gas utility segment, Black Mountain Gas Co. and Viking Gas Transmission Co, including its interest in Guardian Pipeline, LLC. As a result, a gain of 5 cents per share was recorded in the first quarter of 2003 related to the sale of Viking Gas.

Discontinued - - NRG - 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.

Discontinued – All Other – During 2003, the board of directors of Xcel Energy approved management’s plan to exit businesses conducted by Xcel Energy International and e prime. Xcel Energy International primarily includes power generation projects in Argentina. e prime provided energy-related products and services, which included natural gas commodity trading and marketing and energy consulting.

Xcel Energy sold all of the contractual assets of e prime during the first quarter of 2004. During the first quarter of 2004, Xcel Energy completed the sale of one of its Argentina subsidiaries, Hidroelectrica del Sur S.A. (HDS). The sale price was immaterial and approximated the book value of Xcel Energy’s investment in HDS. Xcel Energy International is in the process of marketing its remaining assets and operations to prospective buyers and expects to exit the businesses during 2004.

During the first quarter of 2004, Xcel Energy recorded earnings from discontinued operations of 1 cent per share related to ongoing activity at the remaining businesses of Xcel Energy International and a tax benefit true up related to NRG.

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Income Statement Analysis — First Quarter 2004 vs. First Quarter 2003

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.

Xcel Energy has two distinct forms of 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 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 commodity 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 approved by the FERC. PSCo’s short-term wholesale margins and electric trading margins reflect the estimated impacts of regulatory sharing, if applicable, of certain margins with Colorado retail customers. Trading revenues are reported net of related costs (i.e., on a margin basis) in the Consolidated Statements of Operations. The NRG and e prime trading activity for 2003 is presented in discontinued operations and is not reflected in the following table.

The following table details the revenue and margin for base electric utility, short-term wholesale and electric trading activities.

The following summarizes the components of the changes in base electric utility revenue and base electric utility margin for the three months ended March 31:

Base Electric Utility Revenue

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Base Electric Utility Margin

Base electric utility revenues and margins increased largely due to weather-normalized retail sales growth of approximately 1.6 percent and higher capacity sales in Texas. Also increasing revenues was higher fuel and purchased power costs, which are largely passed through to customers. Partially offsetting the higher revenues and margins were lower retail sales volumes related to warmer than normal winter temperatures, mainly in Colorado. In addition, base electric utility margin was adversely affected by higher purchased capacity costs, primarily at PSCo. As discussed previously, a rate proceeding is currently pending before the CPUC to address the recovery of incremental purchased power capacity costs from retail customers in Colorado.

Short-term wholesale and electric commodity trading sales margins increased approximately $21 million for the first quarter of 2004. First quarter of 2004 short-term wholesale results reflect the impact of high market prices and a pre-existing contract, which expired in the first quarter of 2004. The 2004 trading and short-term wholesale margins are expected to be slightly less than 2003 margins.

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 natural gas purchases. However, due to purchased natural gas cost recovery mechanisms for sales to retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin.

The following summarizes the components of the changes in natural gas revenue and margin for the three months ended March 31:

Natural Gas Revenue

Natural gas revenue increased mainly due to higher natural gas costs in 2004, which are passed through to customers.

Natural Gas Margin

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Natural gas margin decreased mainly due to base rate decreases effective July 1, 2003 resulting from the final settlement of the PSCo 2002 general rate case and the impact of warmer winter temperatures in 2004 compared with 2003. In addition, weather-adjusted natural gas sales declined for the first quarter, as customers reduced their usage to offset the impact of higher natural gas prices. The negative sales growth reduced both natural gas revenue and margin.

Nonregulated Operating Margins

The following table details the change in nonregulated revenue and margin, included in continuing operations.