Xcel Energy, Inc.

Former name, former address and former fiscal year, if changed since last report

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. Yes þ No o

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

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

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, 2002, and Dec. 31, 2001, the results of its operations and stockholders’ equity for the three months ended March 31, 2002 and 2001, and its cash flows for the three months ended March 31, 2002 and 2001. Due to the seasonality of Xcel Energy’s electric and gas sales and variability of nonregulated operations, quarterly 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, 2001. The following notes should be read in conjunction with such policies and other disclosures in the Form 10-K.

Xcel Energy reclassified certain items in the 2001 income statement and balance sheet to conform to the year-end 2001 presentation. These reclassifications had no effect on stockholders’ equity, net income or earnings per share as previously reported.

Intangible Assets — During the first quarter of 2002, Xcel Energy adopted Statement of Financial Accounting Standard (SFAS) No. 142 — “Goodwill and Other Intangible Assets” (SFAS No. 142), which requires new accounting for intangible assets, including goodwill. Intangible assets with finite lives will be amortized over their economic useful lives and periodically reviewed for impairment. Goodwill is no longer being amortized, but will be 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 had intangible assets of $51.9 million at March 31, 2002, which will not be amortized and consist primarily of goodwill at NRG Energy, Inc. (NRG). During the first six months of 2002, Xcel Energy will perform impairment tests of its intangible assets. Tests completed to date have concluded that no write-down is necessary. Approximately $16 million of Goodwill was reclassified to Nonregulated Property and other to comply with the provisions of SFAS No. 142.

With respect to those intangible assets that will continue to be amortized, aggregate amortization expense recognized in the first quarter of 2002 was $1.5 million. The annual aggregate amortization expense for each of the five succeeding years is expected to approximate $3.8 million. Intangible assets consisted of the following:

The following table summarizes the pro forma impact of implementing SFAS No. 142 at Jan. 1, 2001, on the net income for the periods presented. The pro forma income adjustment to remove goodwill amortization is not material enough to affect earnings per share 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.

2002 Regulatory Recovery Adjustment — In late 2001, Southwestern Public Service (SPS), a wholly owned subsidiary of Xcel Energy, filed an application requesting recovery of costs incurred to comply with transition to retail competition legislation in Texas and New Mexico. During the first quarter of 2002, SPS entered into a settlement agreement with intervenors regarding the recovery of restructuring costs in Texas, subject to approval by the state regulatory commission. Based on the settlement agreement, SPS wrote off pretax restructuring costs of approximately $5 million, or approximately 1 cent per share.

2002/2001 Restaffing — During the fourth quarter of 2001, Xcel Energy expensed pretax special charges of $39 million, or 7 cents per share, for expected staff consolidation costs for 500 employees. In the first quarter of 2002, additional pretax special charges of $9 million, or approximately 1 cent per share, were expensed for additional staff consolidations. The charges related to severance costs for utility operations resulting from restaffing plans of several operating and corporate support areas of Xcel Energy. Staff terminations of 564 are now expected to occur. As of March 31, 2002, 551 of these terminations had occurred.

The following table summarizes the activity related to accrued special charges for the first three months of 2002, in millions of dollars.

Conectiv — In April 2002, NRG terminated its purchase agreement with a subsidiary of Conectiv to acquire 794 megawatts of generating capacity and other assets, including an additional 66 megawatts of the Conemaugh Generating Station and an additional 42 megawatts of the Keystone Generating Station.

Canceling the acquisition will result in a $230 million decrease in NRG’s capital obligations for 2002. No incremental costs were incurred by NRG related to the termination of this agreement.

FirstEnergy — In November 2001, NRG signed purchase agreements with subsidiaries of FirstEnergy Corp. to acquire a 2,535-megawatt portfolio of generating assets and two ash disposal sites for approximately $1.6 billion. The four coal-fueled generating stations are located along Lake Erie, near Cleveland and Toledo, Ohio. NRG is also acquiring all of the equity interests in Bay Shore Power Company, which is a subsidiary of FirstEnergy and the owner of a 136 MW petroleum coke-fired steam generating project currently undergoing testing and commissioning on the Bay Shore facility site. NRG is working to close these acquisitions in the second quarter of 2002. In connection with the acquisition of these facilities, NRG is entering into a Transition Power Purchase Agreement with FirstEnergy, pursuant to which NRG will supply to FirstEnergy approximately 95% of the output from the facilities through 2005.

Marketing of NRG Assets — NRG has retained financial advisors to market its international assets. The assets are being marketed in four regional bundles: Latin America, the United Kingdom, Europe and Asia-Pacific. Any future sales should improve liquidity and reduce debt. NRG also is evaluating the possible restructuring of its domestic portfolio, including the potential sale of a partial or entire interest in selected North American regions. NRG also is considering the sale of its interests in landfill gas assets.

West Coast Power — NRG has an investment in one company (West Coast Power LLC) that was considered significant as of Dec. 31, 2001, as defined by applicable SEC regulations, and accounts for its investment using the equity method. The following is summarized pretax financial information for West Coast Power, including interests owned by Xcel Energy and other parties for the periods ended:

TRANSLink Transmission Company, LLC (TRANSLink) — In September 2001, Xcel Energy and several other electric utilities applied to the Federal Energy Regulatory Commission (FERC) to integrate

operations of their electric transmission systems into a single system through the formation of TRANSLink, a for-profit, transmission-only company. The utilities will participate in TRANSLink through a combination of divestiture, leases and operating agreements. The applicants are: Alliant Energy’s Iowa company (Interstate Power and Light Co.), Corn Belt Power Cooperative, MidAmerican Energy Co., Nebraska Public Power District, Omaha Public Power District and Xcel Energy. The participants believe TRANSLink is the most cost-efficient option available to manage transmission and to comply with regulations issued by the FERC in 1999 (known as Order No. 2000) that require investor-owned electric utilities to transfer operational control of their transmission system to an independent regional transmission organization (RTO).

Under the proposal, TRANSLink will be responsible for planning, managing and operating both local and regional transmission assets. TRANSLink also will construct and own new transmission system additions. TRANSLink will collect the revenue for the use of Xcel Energy’s transmission assets through a FERC-approved, regulated cost-of-service tariff and will collect its administrative costs through transmission rate surcharges. Transmission service pricing will continue to be regulated by the FERC, but construction and permitting approvals will continue to rest with regulators in the states served by TRANSLink. The participants also have entered into a memorandum of understanding with the Midwest Independent Transmission Operator, Inc. (MISO) in which they agree that TRANSLink will contract with the MISO for certain other required RTO functions and services.

In April 2002, the FERC gave conditional approval for the applicants to transfer ownership or operations of their transmission systems to TRANSLink and to form TRANSLink as an Independent Transmission Company operating under the umbrella organization of MISO and a separate RTO in the West once it is formed for Public Service Company of Colorado (PSCo) assets. The FERC conditioned TRANSLink’s approval on the resubmission of its tariff as a separate schedule to be administered by the MISO. Several state approvals also would be required to implement the proposal, as well as SEC approval. Subject to receipt of required regulatory approvals, TRANSLink is expected to begin operations in early 2003.

In March 2002, Xcel Energy filed materials with the SEC and commenced the exchange offer under which Xcel Energy would acquire all of the publicly held outstanding common stock of NRG. Xcel Energy currently owns 74 percent of NRG’s outstanding common stock and class A common stock, representing 97 percent of the total voting power of such stock. Under the revised offer terms, each of NRG’s public stockholders would receive 0.50 of a share of Xcel Energy common stock in a tax-free exchange for each outstanding share of NRG common stock they hold.

In April 2002, one of Xcel Energy’s shareholders asked the SEC to hold a hearing in connection with the exchange offer. The hearing was requested to consider issues related to the Public Utility Holding Company Act of 1935 (PUHCA). The SEC has not yet responded to the request. In order to complete the offer, Xcel Energy must receive SEC approval under the PUHCA. Management believes it is in compliance with the PUHCA requirements.

The SEC published a notice, in April 2002, extending the earliest date by which the SEC could enter an order authorizing Xcel Energy to consummate the exchange offer under the PUHCA to May 7, 2002. Xcel Energy has not received an order from the SEC under PUHCA and has extended the expiration of the offer to May 17, 2002.

In February 2002, NRG issued to Xcel Energy a $300-million subordinated convertible note. NRG issued two additional $150-million subordinated convertible notes to Xcel Energy in April 2002 and May 2002, respectively. Xcel Energy, at its option, may cause NRG to convert all of the notes into an aggregate number of shares of NRG’s common stock equal to the sum of the then outstanding principal amount of the notes and all accrued but unpaid interest divided by the price per share on the date specified in the notice to

convert. Xcel Energy will cancel this debt if the exchange offer is completed, thereby effectively making a capital contribution to NRG. If the exchange offer is not completed, Xcel Energy intends to convert the notes into NRG common stock.

NRG Credit Rating — NRG’s unsecured credit rating is BBB-from Standard & Poor’s and Baa3 from Moody’s Investor Service. In December 2001, Moody’s placed NRG’s credit rating on review for potential downgrade. NRG’s credit rating remains under review by Moody’s for potential downgrade.

As of March 31, 2002, and Dec. 31, 2001, NRG’s off-balance-sheet obligations pursuant to its guarantees of performance, equity and indebtedness obligations of its subsidiaries totaled approximately $736.8 million and $721.7 million, respectively. NRG is directly liable for the obligations of certain of its project affiliates and other subsidiaries pursuant to guarantees relating to certain of their indebtedness, equity and operating obligations. In addition, in connection with the purchase and sale of emission credits and power generation products to and from third parties with respect to the operation of some of NRG’s generation facilities in the United States, NRG may be required to guarantee a portion of the obligations of certain of its subsidiaries.

If Moody’s or Standard & Poor’s were to downgrade NRG, many of the corporate guarantees and commitments currently in place would need to be supported with letters of credit or cash collateral within five to 30 days.

As of March 31, 2002, and Dec. 31, 2001, the amount of collateral required, if NRG were downgraded, was approximately $1.02 billion and $960 million, respectively, to satisfy certain of the above-mentioned guarantees and certain obligations associated with the $2-billion construction/acquisition revolver. Of the $1.02 billion in collateral that could be required, approximately $200 million relates to NRG’s guarantees of debt service reserve accounts required by some of its project-level financings, approximately $400 million relates to NRG’s power marketing activities and $420 million would be required to support its Contingent Equity Guarantee associated with the $2-billion construction/ acquisition revolver.

In the event of a downgrade, NRG would expect to meet its collateral obligations with cash on hand, available credit lines provided under its revolving line of credit, potentially from liquidity support from Xcel Energy and the issuance of debt into capital markets.

FirstEnergy Acquisition — As discussed in Note 3 to the Financial Statements, NRG has signed purchase agreements to acquire a portfolio of generating assets from FirstEnergy. Under the terms of the agreements, NRG agreed to pay approximately $1.6 billion for four primarily coal-fueled generating stations.

NRG expects to fund the acquisition with an $825 million lease with limited recourse to NRG, the assumption of $145 million of municipal debt secured by the Bay Shore facility, and $640 million of capital raised directly by NRG through internal cash flows, proceeds from new project financings and capital contributions from Xcel Energy.

In April 2002, NRG discovered that filings with the Federal Energy Regulatory Commission (FERC) to exempt NRG’s Big Cajun Peaking facility in Louisiana from regulation by the SEC under the Public Utility Holding Company Act (PUHCA), and to sell power from the facility at market-based rates, had not been made. NRG has since made those filings and has discussed the situation with FERC and the SEC. While NRG does not expect any material legal or regulatory action to be taken by those agencies, the failure to have made these filings could be viewed as an event of default under certain of NRG’s debt facilities, including its $2 billion construction and acquisition revolving credit facility and $1 billion unsecured corporate revolving

line of credit. Accordingly, NRG sought and has received from its construction and acquisition facility lenders a waiver of any event of default occurring as a result of Big Cajun Peaking Power’s failure to file for exemption from regulation under PUHCA, and has sought and received from its corporate revolver lenders an amendment to its corporate revolving line of credit to provide that such failure to obtain or maintain exemption from regulation under PUHCA will not cause an event of default under that facility. While the construction and acquisition revolver waiver and the corporate revolver amendment were being discussed and finalized with its lenders, NRG did not borrow under either of these credit facilities. The waiver continues indefinitely unless a default arising out of any possible PUHCA violation occurs.

Project Debt Service — Substantially all of NRG’s operations are conducted by project subsidiaries and project affiliates, NRG’s cash flow and ability to service corporate-level indebtedness when due is dependent upon receipt of cash dividends and distributions or other transfers from NRG’s projects and other subsidiaries. The debt agreements of NRG’s subsidiaries and project affiliates generally restrict their ability to pay dividends, make distributions or otherwise transfer funds to NRG. As of March 31, 2002, six of NRG’s subsidiaries and project affiliates are restricted from making cash payments to NRG. Loy Yang, Killingholme, Energy Center Kladno and Louisiana Generating do not currently meet the minimum debt service coverage ratios required for these projects to make payments to NRG; LSP Energy (Batesville) is resolving equipment problems that will cause its debt service coverage ratio to fall below the minimum required for distribution, and Crockett Cogeneration is limited in its ability to make distributions to NRG and its other partners.

NRG believes the situations at Louisiana Generating, Energy Center Kladno, Batesville and Killingholme do not create an event of default and will not allow the lenders to accelerate the project financings. The forced outage of one 500 MW unit at Loy Yang combined with current market prices may lead to an event of default and the possible acceleration of the Loy Yang project debt in the fourth quarter of 2002, if insurance claims are paid and forecasted revenues and costs are achieved, along with replacement of the damaged unit as scheduled, default will be avoided.

Colorado Rate Proceedings — Incentive Cost Adjustment — Under the Stipulation and Agreement approved by the Colorado Public Utilities Commission (CPUC) in connection with the Xcel Energy merger, PSCo agreed to 1) file a combined electric, gas and steam rate case in 2002 with new rates effective in January 2003, 2) extend its incentive cost adjustment (ICA) mechanism for one more year through Dec. 31, 2002 with an increase in the ICA base rate from $12.78 per megawatt hour to a rate based on the 2001 actual costs, 3) continue the Performance-Based Regulatory Plan and the Quality Service Plan through 2006 with an electric department earnings cap of 10.5 percent return on equity for 2002, 4) reduce electric rates annually by $11 million for the period August 2000 to July 2002 and 5) cap merger costs associated with electric operations at $30 million and amortize such costs through 2002. The general rate case is being prepared and is expected to be filed by the end of May 2002.

In early 2002, PSCo filed to increase rates under the ICA to recover the undercollection of costs through the period ended Dec. 31, 2001 (approximately $14.5 million, which went into effect on April 15, 2002) and to increase the ICA base rate for the recovery of 2002 costs which are projected to be substantially higher than the $12.78 per megawatt hour currently being recovered. PSCo’s actual ICA base costs for 2001 were approximately $19 per megawatt hour. PSCo proposed to increase the ICA base in 2002 to avoid the significant deferral of costs and a large rate increase in 2003, although the Stipulation and Agreement provided for a rate recovery period of April 1, 2003, to March 31, 2004.

On May 10, 2002, the CPUC approved a Settlement Agreement between PSCo and other parties to increase the ICA base rate to $14.88 per megawatt hour, providing for recovery of the deferred 2001 costs and the projected higher 2002 costs over a 34-month period from June 1, 2002, to March 31, 2005. The review and approval of actual costs incurred and recoverable under the ICA for 2001 and 2002 will be conducted in future

rate proceedings by the CPUC for consideration of further increases in the ICA base rate to $19.00 per megawatt hour. PSCo is currently projecting its costs for 2002 to be approximately $38 million less than the ICA base allowed using the 2001 test year, resulting in an equal sharing of such lower costs between retail customers and PSCo. The mechanism for recovering fuel and energy costs for 2003 and later will be addressed in the 2002 rate case.

Colorado Rate Proceedings — Gas Cost Prudence Review — In May 2002, the staff of the CPUC filed testimony in PSCo’s gas cost prudence review case, recommending $6.1 million in disallowances of gas costs for the July 2000 through June 2001 gas purchase year. PSCo’s rebuttal testimony is scheduled to be filed on June 26, 2002. Hearings are scheduled for July 2002.

FERC Investigation — On May 8, 2002, the FERC ordered all sellers of wholesale electricity and/or ancillary services to the California Independent System Operator or Power Exchange, including Xcel Energy and NRG, to respond to data requests, including requests for admissions with respect to certain trading strategies in which the companies may have engaged. The investigation is in response to memoranda prepared by Enron Corporation that detail certain trading strategies engaged in 2000 and 2001, which may have violated market rules. On May 13, 2002, Xcel Energy announced that PSCo had engaged in certain trading transactions, initiated by Reliant Resources, that had immaterial income effects in 1999 and 2000. Xcel Energy is investigating these transactions and plans to address them in response to the FERC. Xcel Energy and NRG must respond to FERC’s request by May 22, 2002.

SPS Texas Transition to Competition Cost Recovery Application — In December 2001, SPS filed an application with the Public Utility Commission of Texas (PUCT) to recover $20.3 million in transition to retail competition costs from the Texas retail customers. These costs are associated with the SPS’ delayed transition to competition. The filing was amended in March 2002 to reduce the recoverable costs by $7.3 million, which were associated with over-earnings recognized in 2001 for the 1999 annual report to the PUCT. The PUCT approved SPS using the 1999 annual report over-earnings to offset the claims for reimbursement of transition to competition costs. This reduced the requested net collection in Texas to $13.0 million. In April 2002, a unanimous settlement agreement was reached. Final approval by the PUCT is expected May 23, 2002. The stipulation provides for the recovery of $5.9 million through an incremental cost recovery rider and the capitalization of $1.9 million for metering equipment. Based on the settlement agreement, SPS wrote off pretax restructuring costs of approximately $5 million in the first quarter of 2002. Recovery of the $5.9 million will begin in July 2002.

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.

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, Xcel Energy is pursuing or intends to pursue insurance claims and believe they will recover some portion of these costs through such claims. Additionally, where applicable, Xcel Energy 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.

Note 5 to the Financial Statements describes the current status of contingencies related to NRG and related financial impacts. The circumstances set forth in Notes 15 and 16 to Xcel Energy’s financial statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2001, 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:


	•	California Power Market — Collectibility of NRG receivables;

	•	Tax Matters — Tax deductibility of corporate owned life insurance loan interest; and

	•	Asset Valuation — Recoverability of investment in under-performing nonregulated projects (Seren, Loy Yang, Argentina)

At March 31, 2002, Xcel Energy and its subsidiaries had approximately $2.2 billion of short-term debt outstanding at a weighted average interest rate of 3.273 percent.

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. In February 2002, Xcel Energy issued 23 million shares of common stock under this registration statement.

In March 2002, NRG’s $500-million recourse revolving credit facility matured and was replaced with a $1.0-billion, 364-day revolving line of credit, which terminates on March 7, 2003. The facility is unsecured and provides for borrowings of “Base Rate Loans” and “Eurocurrency Loans.” The Base Rate Loans bear interest at the greater of the administrative agent’s prime rate or the sum of the prevailing per annum rates for overnight funds plus 0.5 percent per annum, plus an additional margin, which varies from 0.375 percent to 0.50 percent based upon NRG’s utilization of the facility and its then-current senior debt credit rating. The Eurocurrency loans bear interest at an adjusted rate based on the London Interbank Offered Rate plus an adjustment percentage, which varies depending on NRG’s senior debt credit rating and the amount outstanding under the facility. The credit agreement for this facility was amended in April 2002 to revise the interest coverage ratio covenant. As amended, the covenant requires NRG to maintain a minimum interest coverage ratio that varies throughout the year from 1.85 to 2.00 as determined at the end of each fiscal quarter. The facility contains additional covenants that, among other things, restrict the incurrence of liens and require NRG to maintain a net worth of at least $1.5 billion plus 25 percent of NRG’s consolidated net income from Jan. 1, 2002, through the determination date. In addition, NRG must maintain a debt to capitalization ratio of not more than 0.68 to 1.00. The failure to comply with any of these covenants would be an Event of Default under the terms of the credit agreement. At March 31, 2002, NRG had a $980-million outstanding balance under this credit facility. At March 31, 2002, the weighted average interest rate of such outstanding advances was 3.456 percent per year. See Note 5 to the Financial Statements for a description of Event of Default under this facility.

NRG’s $125-million syndicated letter of credit facility contains terms, conditions and covenants that are substantially the same as those in NRG’s $1.0-billion 364-day revolving line of credit. NRG is currently working with the agent bank to amend the letter of credit facility agreement to incorporate the same covenant revisions and other amendments that have been made to the terms and conditions of NRG’s $1.0-billion revolving credit facility, including the addition of an interest coverage ratio covenant, and revisions to clarify that the three subordinated convertible notes issued by NRG to Xcel Energy to evidence Xcel Energy’s provision of $600 million to NRG shall be treated as equity for purposes of NRG’s calculation of indebtedness under the agreement. Based on conversations with the agent bank, NRG does not anticipate any difficulty in finalizing this amendment.

As of Dec. 31, 2001, NRG, through its wholly owned subsidiary NRG South Central Generating LLC had outstanding approximately $40 million under a project level, non-recourse revolving credit agreement, which matured in March 2002. In March 2002, the facility was renewed for an additional 90 days, with

substantially similar terms and conditions. At March 31, 2002, the weighted average interest rate of such outstanding advances was 2.884 percent per year. The maximum available under this facility is $40 million. NRG intends to renew this facility with a facility having substantially similar terms and conditions.

NRG entered into a $2-billion revolving credit facility used to finance the acquisition, development and construction of power generating plants located in the United States and to finance the acquisition of turbines for such facilities. The facility is secured by the assets and financial instruments related to the projects financed under the facility. Provided that certain conditions are met that assure the lenders that sufficient security remains for the remaining outstanding loans, the borrower may repay loans relating to one project and have the liens relating to that project released. Loans that have been repaid may be re-borrowed, as permitted by the terms of the facility. The facility terminates on May 8, 2006. The facility is non-recourse to NRG other than its obligation to contribute equity at certain times in respect of projects and turbines financed under the facility. As of March 31, 2002, the aggregate amount outstanding under this facility was $806.8 million. At March 31, 2002, the weighted average interest rate of such outstanding advances was 3.399 percent. See Note 5 to the Financial Statements for a description of Event of Default under this facility.

As of March 31, 2002, Xcel Energy had several interest rate swaps with a notional amount of approximately $2.7 billion. The majority of these swaps were related to NRG. If the swaps were terminated at March 31, 2002, Xcel Energy would have had to pay the counterparties approximately $79 million.

Xcel Energy analyzes derivative financial instruments in accordance with SFAS No. 133 — “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). This statement requires that all derivative financial instruments be recorded on the balance sheet at fair value unless exempted. Changes in a derivative instrument’s fair value must be recognized currently in earnings unless the derivative has been designated in a qualifying hedging relationship. The application of hedge accounting allows a derivative instrument’s gains and losses to offset related results of the hedged item in the income statement, to the extent effective. SFAS No. 133 requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.

The components of SFAS No. 133 impacts on Xcel Energy’s Other Comprehensive Income, included in stockholders’ equity, are detailed in the following table:

The components of the gain for SFAS No. 133 impacts on Xcel Energy’s income statement for the three months ended March 31, 2002 and 2001, excluding gains and losses from trading activities, are detailed in the following table:

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

Xcel Energy and its subsidiaries enter into fixed price 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 as normal 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 into to determine if they are derivatives and, if so, if they qualify and meet the normal designation requirements under SFAS No. 133. None of the contracts entered into within the trading operations are considered normal under the provisions of SFAS No. 133.

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

Xcel Energy and its subsidiaries enter into derivative instruments to manage their exposure to changes in commodity prices. These derivative instruments take the form of fixed price, floating price or index sales or purchases and options, such as puts, calls and swaps. 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, 2002, Xcel Energy had various commodity related contracts extending through 2018. Earnings on these cash flow hedges are recorded as the hedged purchase or

sales transaction is completed. This could include the physical sale of electric energy or the usage of natural gas to generate electric energy. Xcel Energy expects to reclassify into earnings through March 2003 net gains from Other Comprehensive Income of approximately $7.3 million.

As required by SFAS No. 133, we recorded gains of $0.1 million and $0.3 million related to ineffectiveness on commodity cash flow hedges during the three months ended March 31, 2002 and 2001, respectively. During the first quarter of 2001, we recorded gains of $1.4 million related to derivative financial instruments excluded from the assessment of effectiveness and an immaterial amount related to cash flow hedges that were discontinued because the hedged transactions were no longer probable.

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 through March 2003 net losses from Other Comprehensive Income of approximately $4.5 million.

Xcel Energy records hedge effectiveness 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 and hedging transactions for interest rate swaps are recorded as a component of interest expense.

Fair Value Hedges and Hedges of Foreign Currency Exposure of a Net Investment in Foreign Operations

To preserve the U.S. dollar value of projected foreign currency cash flows, Xcel Energy, through NRG, may hedge, or protect, those cash flows if appropriate foreign hedging instruments are available. Xcel Energy does not expect to reclassify any significant amounts into earnings through March 2003 from Other Comprehensive Income on foreign currency swaps accounted for as hedges.

Xcel Energy and its subsidiaries have various trading operations that enter into derivative instruments. These derivative instruments are accounted for on a mark-to-market basis in our Consolidated Statements of Income. All derivative financial instruments are recorded at the amount of the gain or loss from the transaction within Operating Revenues on the Consolidated Statements of Income.

In order to preserve the U.S. dollar value of projected foreign currency cash flows from European trading operations, we enter into various foreign currency exchange contracts that are not designated as accounting hedges but are considered economic hedges. Accordingly, the changes in fair value of these derivatives are reported in Other Nonoperating Income in the Consolidated Statements of Income.

Xcel Energy has the following reportable segments: Electric Utility, Gas Utility and two of its nonregulated energy businesses, NRG and e prime. Trading operations performed by regulated operating

companies are not a reportable segment; electric trading results are included in the Electric Utility segment and gas trading results are presented as e prime.

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:


	•	general economic conditions, including their 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;

	•	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;

	•	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 gas markets;

	•	the higher risk associated with Xcel Energy’s nonregulated businesses compared with its regulated businesses;

	•	completion of the offer for NRG’s outstanding common stock and the realization of the expectations regarding the acquisition of the NRG common stock;

	•	currency translation and transaction adjustments;

	•	risks associated with the California power market; 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 this report on Form 10-Q for the quarter ended March 31, 2002.

Xcel Energy’s earnings per share were $0.29 for the first quarter of 2002, compared with $0.61 for the first quarter of 2001. Xcel Energy’s earnings per share for the first quarter of 2002 were reduced by 2 cents per share for a write-off related to the restructuring of SPS’ generation business and additional restaffing costs. The following table details the earnings per share contribution of Xcel Energy’s regulated and nonregulated businesses.

Regulated Results — In the first quarter of 2002, regulated earnings per share were reduced by 2 cents per share due to special charges for regulatory adjustments and restaffing costs, as discussed in Note 2 to the financial statements.

In addition, first quarter 2002 results declined largely due to lower short-term wholesale and trading margins, as discussed in the following section. Also, higher margins from other electric and gas sales were partially offset by higher operating costs, also discussed in detail in the following section.

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

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

NRG — NRG’s earnings decreased for the first quarter of 2002, due to mild weather in much of NRG’s operating territory in the United States, which reduces energy sales. In addition, lower power prices have lowered the profitability of NRG sales and higher operating, depreciation and interest costs have resulted from project acquisitions since the first quarter of 2001. The decrease also was due to a small mark-to-market gain recorded under SFAS No. 133 in the first quarter of 2002, compared with 3 cents per share in SFAS No. 133 gains in the comparable 2001 period. Historically, NRG’s first-quarter earnings have been lower than other quarters (first quarter 2001 represented 9 percent of NRG’s annual earnings, excluding SFAS No. 133 impacts).

At March 31, 2002, Xcel Energy owned approximately 74 percent of NRG. Xcel Energy owned 100 percent of NRG until the second quarter of 2000, when NRG completed its initial public offering, and 82 percent until a secondary offering was completed in March 2001. The NRG earnings for each of the quarters ended March 31, 2002 and 2001, exclude earnings of approximately 2 cents per share related to minority interests.

Seren — Seren is constructing a combination cable television, telephone and high-speed Internet access system in two locations: St. Cloud, Minn., and Contra Costa county in the East Bay area of northern California. As of March 31, 2002, Xcel Energy’s investment in Seren was approximately $241 million. Seren had capitalized $218 million for plant in service and had incurred another $47 million for construction work in progress for these systems at March 31, 2002. The majority of the system construction in St. Cloud is complete. Its broadband communications operations in Minnesota and California resulted in losses for the quarters ended March 31, 2002 and 2001 for Seren. Management is continuing to evaluate the strategic fit of Seren in Xcel Energy’s business portfolio.

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.

Xcel Energy’s commodity trading operations are conducted mainly by PSCo (electric) and e prime (gas), both wholly owned subsidiaries. Electric trading activity, initially recorded at PSCo, is partially redistributed to Northern States Power-Minnesota (NSP-Minnesota) and SPS pursuant to the Joint Operating Agreement (JOA) approved by the FERC. 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 revenue and costs associated with NRG’s operations are included in nonregulated margins. Margins from these generating assets for utility operations are included in short-term wholesale amounts, discussed later. Trading margins reflect the impact of sharing certain trading margins under the ICA. The following table details electric utility, short-term wholesale and electric and gas trading revenue and margin.

Table Note 1 — The wholesale and trading margins reflect the impact of the regulatory sharing of certain margins under the ICA in Colorado.

Electric and gas commodity trading margins and short-term wholesale margins decreased approximately $127 million for the first quarter of 2002, compared with the first quarter of 2001. The decrease reflects lower power and natural gas prices during the first quarter of 2002, compared with 2001.

Electric utility revenues decreased approximately $71 million in the first quarter of 2002, compared with the same period in 2001, due to lower fuel and power costs passed through rate recovery mechanisms. Electric utility margins increased approximately $64 million for the first quarter of 2002, compared with 2001. The higher electric margins in the first quarter reflect lower unrecovered costs, due in part to resetting the base-cost recovery at PSCo in January 2002. The increase was partially offset by the impact of decreased sales due to warmer weather in the first quarter of 2002, compared with the same period in 2001.

Short-term wholesale margins and electric commodity trading margins decreased in the first three months of 2002, compared with the first three months of 2001. The decrease is due to declines in energy prices. During 2001, in some Western markets, publicly available power prices ranged from $80 to more than

$350 per megawatt-hour on a monthly average. Forward price information for 2002 for these same areas ranges from $60 to $110 per megawatt-hour on a monthly average.

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

Gas revenue decreased by approximately $396 million, or 41.3 percent, in the first quarter of 2002, primarily due to decreases in the cost of natural gas, which are largely passed on to customers and recovered through various rate adjustment clauses in most of the jurisdictions in which Xcel Energy operates. Gas margin remained unchanged over the same periods due to rate recovery adjustment clauses. Sales volume levels remained relatively unchanged due to the impact of warmer-than-normal weather offsetting customer growth.

Nonregulated revenue increased for the first quarter of 2002, largely due to NRG increases from a larger generation portfolio. Nonregulated margin decreased for the first quarter of 2002, due to lower power pool prices and a more competitive market reducing NRG’s margin on sales.

Earnings from equity investments decreased for the first quarter of 2002, due to relatively consistent equity earnings from NRG projects and lower equity earnings from Yorkshire. As a result of a sales agreement to sell the majority of its investment in Yorkshire Power, Xcel Energy did not record any equity earnings from Yorkshire Power after January 2001.

Regulated Other Operation and Maintenance Expenses for the first quarter of 2002 increased by approximately $11 million, or 3.0 percent, compared with the first quarter of 2001. The increased costs in the first quarter reflect higher outage costs and higher property insurance premiums, partially offset by lower labor-related costs.

Nonregulated Other Operation and Maintenance Expenses increased by approximately $34 million, or 19.3 percent, for the first quarter of 2002, compared with the first quarter of 2001, primarily due to the expansion of NRG’s operations during the last nine months of 2001.

Depreciation and amortization increased by approximately $47 million, or 22.1 percent, for the first quarter of 2002, compared with the first quarter of 2001, primarily due to acquisitions of generating facilities by NRG and capital additions to NRG-owned generation facilities and utility plant additions.

Taxes (other than income taxes) declined largely due to a legislative change in Minnesota that reduced annual property taxes by approximately $30 million in September 2001 related proportionately to the first nine months of 2001. Approximately 70 percent of this reduction in property taxes will be returned to NSP-Minnesota customers.

Interest expense increased by approximately $27 million, or 15.6 percent, for the first quarter of 2002, compared with the first quarter of 2001, primarily due to increased debt levels to fund several asset acquisitions by NRG, partially offset by increased amounts of capitalized interest related to NRG’s ongoing construction projects.

Xcel Energy’s effective tax rate was 25.0 percent for the first quarter of 2002, compared with 32.8 percent for the first quarter of 2001. The change in the effective tax rate between years reflects the impact of tax credits, which represent a higher percentage of the lower pretax income levels in 2002, and also reflects the implementation of state tax planning strategies at NRG.

SFAS No. 143 — In 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143 — “Accounting for Asset Retirement Obligations.” This statement will require Xcel Energy to record its future nuclear plant decommissioning obligations as a liability at fair value with a corresponding increase to the carrying value of the related long-lived asset. The liability will be increased to its present value each period, and the capitalized cost will be depreciated over the useful life of the related long-lived asset. If at the end of the asset’s life the recorded liability differs from the actual obligations paid, SFAS No. 143 requires that a gain or loss be recognized at that time.

Xcel Energy currently follows industry practice by ratably accruing the costs for decommissioning over the approved cost recovery period and including the accruals in accumulated depreciation. At Dec. 31, 2001, Xcel Energy recorded and recovered in rates $623 million of decommissioning obligations and had estimated discounted decommissioning cost obligations of $878 million.

If Xcel Energy adopted the standard on Jan. 1, 2002, the initial value of the liability, including cumulative interest expense through that date, would have been approximately $757 million, with a corresponding increase to net plant assets of approximately $625 million. The resulting cumulative effect adjustment for unrecognized depreciation and other expenses under the new standard is approximately $132 million. Management expects that the entire transition amount would be recoverable in rates and, therefore, would recognize an additional regulatory asset upon adoption of SFAS No. 143 rather than incur a cumulative effect charge against earnings.

SFAS No. 143 also will affect Xcel Energy’s accrued plant removal costs for other generation, transmission and distribution facilities for its utility subsidiaries. Xcel Energy expects that these costs, which have yet to be estimated, will be reclassified from accumulated depreciation to regulatory liabilities based on the treatment of these costs in rates. Xcel Energy expects to adopt SFAS No. 143 as required on Jan. 1, 2003.

SFAS No. 145 — In April 2002, the FASB issued SFAS No. 145 — “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections,” which supercedes previous guidance for the reporting of gains and losses from extinguishment of debt and accounting for leases, among other things. The impact of SFAS No. 145 is not expected to be material to Xcel Energy.

Xcel Energy and its subsidiaries are exposed to market risks, including changes in commodity prices, interest rates and currency exchange rates as disclosed in Management’s Discussion and Analysis in its annual report on Form 10-K for the year ended Dec. 31, 2001. Commodity price and interest rate risks for Xcel

Energy’s regulated subsidiaries are mitigated in most jurisdictions due to cost-based rate regulation. There have been no material changes in the market risk exposures that affect the quantitative and qualitative disclosures presented as of Dec. 31, 2001, in Xcel Energy’s Annual Report on Form 10-K.

Cash provided by operating activities increased for the first three months of 2002, compared with the first three months of 2001. The increase was primarily due to improved working capital. Partially offsetting this increase was the effect of lower operating results in 2002, mainly at NRG.

Cash used in investing activities decreased for the first three months of 2002, compared with the first three months of 2001. The change is largely due to decreased levels of nonregulated capital expenditures and asset acquisitions, primarily at NRG.

Cash provided by financing activities decreased for the first three months of 2002, compared with the first three months of 2001. The change is largely due to decreased short-term and long-term borrowings primarily related to decreased acquisitions and capital expenditures of NRG.

In February 2002, Xcel Energy issued 23 million shares of common stock. The proceeds were used to fund a loan to NRG of $300 million. The remaining net proceeds were used to repay short-term debt.

Xcel Energy may issue additional shares of common stock during 2002. Proceeds may be used for general corporate purposes, to buy down short-term debt or to fund nonregulated subsidiaries, including NRG.

Short-term debt and financial instruments are discussed in Note 8 to the Financial Statements.

In the normal course of business, various lawsuits and claims have arisen against Xcel Energy. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters. See Notes 4 and 5 of the Financial Statements in this Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 of Xcel Energy’s 2001 Form 10-K for a description of certain legal proceedings presently pending. There are no new significant cases to report against Xcel Energy or its subsidiaries and there have been no notable changes in the previously reported proceedings, except as set forth below.

Light Rail Lawsuit — In February 2001, NSP-Minnesota filed a lawsuit in the federal district court in Minneapolis seeking reimbursement of costs for relocating electric utility lines to allow for construction of a light rail transit (LRT) line in downtown Minneapolis. In May 2001, the Minnesota Department of Transportation and the Metropolitan Council (Defendants) obtained a preliminary injunction requiring NSP-Minnesota to move certain facilities. NSP-Minnesota has complied with the preliminary injunction and utility line relocation has commenced. NSP-Minnesota is capitalizing its costs incurred as construction work in progress. In April 2002, Defendants brought motions for summary judgment before the federal district court. The court has not yet ruled on these motions and no trial date will be established until such ruling is made. The decision as to who must pay the cost of relocation will be made after trial. In collateral matters regarding LRT construction, NSP-Minnesota has commenced a mandamus action in state court seeking an order requiring Defendants to commence condemnation proceedings concerning an underground substation, access to which is blocked by LRT. NSP-Minnesota also has commenced an action in state court alleging that LRT construction violates the Minnesota Environmental Rights Act and a separate action in federal district court alleging that the Federal Transit Administration’s failure to evaluate certain environmental effects of LRT violates the National Environmental Policy Act.

Fortistar Litigation — In July 1999, Fortistar Capital, Inc., a Delaware corporation, filed a complaint in District Court (Fourth Judicial District, Hennepin County) in Minnesota against NRG asserting claims for injunctive relief and for damages as a result of NRG’s alleged breach of a confidentiality letter agreement with Fortistar relating to the Oswego facility in New York. NRG disputed Fortistar’s allegations and asserted numerous counterclaims. In October 1999, NRG, through a wholly owned subsidiary, closed on the acquisition of the Oswego facility. In April and December 2000, NRG filed summary judgment motions to dispose of the litigation. A hearing on these motions was held in February 2001 and certain of Fortistar’s claims were dismissed. On May 8, 2002, the parties resolved the litigation, pending final agreement on the terms of settlement. The settlement encompasses litigation with respect to the Oswego facility, as well as litigation between the parties with respect to Minnesota Methane LLC.

NRG Litigation — In February 2002, individual stockholders of NRG filed nine separate, but similar, class action complaints in the Delaware Court of Chancery against Xcel Energy, NRG and the nine members of NRG’s board of directors. A similar class action lawsuit was filed in a Minnesota state court. Each of the actions challenged the offer and merger, which is discussed in Note 4 to the Financial Statement contained in Part 1, Item 1 of this quarterly report on Form 10-Q, and contained various allegations of wrongdoing on the part of the defendants in connection with the offer and the merger. As of April 3, 2002, counsel for the parties to the consolidated action in the Delaware Court of Chancery and the Minnesota action entered into a memorandum of understanding setting forth an agreement in principle to settle the actions based on the increase by Xcel Energy of the exchange ratio in the offer and merger to 0.5000.

Xcel Energy’s Annual Meeting of Shareholders was held on April 18, 2002, for the purpose of voting on the matters listed below. Proxies for the meeting were solicited pursuant to Section 14(a) of the Securities Exchange Act of 1934 and there were no solicitations in opposition to management’s solicitations. All of

management’s nominees for directors as listed in the proxy statement were elected. The voting results were as follows:

1. A proposal to elect four directors to Class I until the 2005 Annual Meeting of Shareholders:

The following reports on Form 8-K were filed either during the three months ended March 31, 2002, or between March 31, 2002, and the date of this report:


	Jan. 14, 2002, (filed Jan. 14, 2002) Item 5. Other Events. Re: Disclosure of Xcel Energy’s position concerning an IRS Notice of Proposed Adjustment concerning loans of PSR Investments, Inc., a wholly owned subsidiary of PSCo.

	Feb. 8, 2002, (filed Feb. 8, 2002) Item 5 and 7. Other Events and Exhibits. Re: Disclosure by Xcel Energy officials that recent published reports of merger talks naming specific companies were untrue.

	Feb. 15, 2002, (filed Feb. 15, 2002) Item 5 and 7. Other Events and Exhibits. Re: Disclosure of Board approval of plans to commence and exchange offer by which Xcel Energy would acquire all of the outstanding publicly held shares of its subsidiary, NRG.

	Feb. 15, 2002, (filed Feb. 19, 2002) Item 5 and 7. Other Events and Exhibits. Re: Disclosure that Xcel Energy informed the Board of its subsidiary, NRG, of its plans to commence the exchange offer to acquire all of NRG’s publicly held shares.

	Feb. 20, 2002, (filed Feb. 20, 2002) Item 5 and 7. Other Events and Exhibits. Re: Disclosure of Board approval of plans to commence the exchange offer with NRG.

	Feb. 22, 2002, (filed Feb. 22, 2002) Item 5. Other Events. Re: Disclosure of Xcel Energy’s response to the inquiries regarding the possible downgrade of NRG’s unsecured credit rating to below investment grade.

	Feb. 25, 2002, (filed Feb. 25, 2002) Item 5. Other Events. Re: Disclosure of the audited financial statements of Xcel Energy and its subsidiaries for the year ended Dec. 31, 2001.

	Feb. 25, 2002, (filed Feb. 27, 2002) Item 5 and 7. Other Events and Exhibits. Re: Disclosure of Xcel Energy’s offering of 20,000,000 shares of the company’s common stock and its registration with the SEC regarding these shares.


	March 12, 2002, (filed March 12, 2002) Item 5. Other Events. Re: Disclosure of the SEC’s approval for Xcel Energy to use proceeds of securities issuances to invest an amount up to 100 percent of its consolidated returned earnings in EWGs and FUCOs.

	March 13, 2002, (filed March 13, 2002) Item 5 and 7. Other Events and Exhibits. Re: Disclosure to update description of Xcel Energy’s common stock contained on Exhibit 99.05 to its Annual Report on Form 10-K for the year ended December 31, 1999.

	March 26, 2002, (filed March 26, 2002) Item 5. Other Events. Re: Disclosure of Xcel Energy’s expectation for first quarter and annual earnings for 2002.

	April 4, 2002, (filed April 5, 2002) Item 5 and 7. Other Events and Exhibits. Re: Disclosure that Xcel Energy revised the exchange offer for all of the publicly held shares of NRG.

	April 16, 2002, (filed April 16, 2002) Item 5 and 7. Other Events and Exhibits. Re: Disclosure of Xcel Energy’s extension of its exchange offer with NRG to May 8, 2002.

	April 24, 2002, (filed April 29, 2002) Item 5 and 7. Other Events and Exhibits. Re: Disclosure of Xcel Energy’s first quarter 2002 earnings.

	May 7, 2002, (filed May 7, 2002) Item 5 and 7. Other Events and Exhibits. Re: Disclosure of Xcel Energy’s extension of the expiration of the exchange offer with NRG to May 17, 2002.

	May 13, 2002, (filed May 13, 2002) Item 5. Other Events. Re: Xcel Energy transactions with Reliant Energy.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	XCEL ENERGY INC.
	(Registrant)

	/s/ DAVID E. RIPKA

	David E. Ripka
	Vice President and Controller

	/s/ EDWARD J. MCINTYRE

	Edward J. McIntyre
	Vice President and Chief Financial Officer

26 EX-99.01 3 c69613ex99-01.htm EX-99.01 STATEMENT PURSUANT TO PRIVATE SECURITIES ex99-01

The Private Securities Litigation Reform Act provides a “safe harbor” for forward-looking statements to encourage disclosures without the threat of litigation, providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Forward-looking statements are made in written documents and oral presentations of Xcel Energy. These statements are based on management’s beliefs as well as assumptions and information currently available to management. When used in Xcel Energy’s documents or oral presentations, the words “anticipate,” “estimate,” “expect,” “projected,” objective,” “outlook,” “forecast,” “possible,” “potential” and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause Xcel Energy’s actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

•		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 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 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 and other western power 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;

•		Factors associated with nonregulated investments, including risks associated with timely completion of projects, including obtaining competitive contracts and construction delays, foreign government actions, foreign economic and currency risks, political instability in foreign countries, partnership actions, competition, operating risks, dependence on certain suppliers and customers, domestic and foreign environmental and energy regulations;

•		Many of the project investments made by Xcel Energy’s subsidiary NRG Energy, Inc. consist of minority interests, and a substantial portion of future investments may take the form of minority interests, which limits NRG’s ability to control the development or operation of the project;

•		The completion of the offer for NRG’s outstanding common stock, and the realization of the expectations regarding the acquisition of the NRG common stock, which may be affected by the satisfaction of conditions to the offer, actual results of Xcel Energy following completion of the transaction, the ability to defer or terminate projects, to reduce expenses and to realize synergies, cash levels and similar matters; and

•		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.

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

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Minnesota		41-0448030
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

800 Nicollet Mall, Minneapolis, Minn.		55402
(Address of principal executive offices)		(Zip Code)


Class		Outstanding at April 30, 2002

Common Stock, $2.50 par value		370,880,454 shares


PART 1. FINANCIAL INFORMATION
CONSOLIDATED STATEMENTS OF INCOME
CONSOLIDATED STATEMENTS OF CASH FLOWS
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PART II. OTHER INFORMATION
SIGNATURES
EX-99.01 Statement pursuant to Private Securities



			Three Months Ended
			March 31

			2002			2001


			(Unaudited)
			(Thousands of dollars,
			except per share data)
Operating revenues:
	Electric utility		$	1,231,657		$	1,547,512
	Gas utility			563,911			960,165
	Electric and gas trading			755,412			966,891
	Nonregulated and other			750,127			732,538
	Equity earnings from investments in affiliates			16,480			23,462

		Total operating revenues		3,317,587			4,230,568
Operating expenses:
	Electric fuel and purchased power — utility			488,114			787,565
	Cost of gas sold and transported — utility			375,615			772,052
	Electric and gas trading costs			752,662			917,364
	Cost of sales — nonregulated and other			411,484			394,809
	Other operating and maintenance expenses — utility			391,491			380,148
	Other operating and maintenance expenses — nonregulated			212,749			178,266
	Depreciation and amortization			260,544			213,310
	Taxes (other than income taxes)			82,897			94,748
	Special charges (see Note 2)			14,113			—

		Total operating expenses		2,989,669			3,738,262

Operating income				327,918			492,306
Interest income and other nonoperating income — net of other expenses				17,923			17,486
Interest charges and financing costs:
	Interest charges — net of amounts capitalized			203,232			175,849
	Distributions on redeemable preferred securities of subsidiary trusts			9,700			9,700

		Total interest charges and financing costs		212,932			185,549

Income before income taxes and minority interest				132,909			324,243
Income taxes				33,277			106,281
Minority interest				(3,872	)		8,652

Net income				103,504			209,310
Dividend requirements on preferred stock				1,060			1,060

Earnings available for common shareholders			$	102,444		$	208,250

Weighted average common shares outstanding (in thousands):
	Basic			353,827			340,780
	Diluted			354,172			341,472
Earnings per share — basic and diluted				$0.29		$	0.61



				Three Months Ended
				March 31

				2002			2001


				(Unaudited)
				(Thousands of dollars)
Operating activities:
	Net income			$	103,504		$	209,310
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			256,482			226,117
		Nuclear fuel amortization			12,037			9,441
		Deferred income taxes			4,060			(5,924	)
		Amortization of investment tax credits			(3,380	)		(3,251	)
		Allowance for equity funds used during construction			(1,881	)		(59	)
		Undistributed equity in earnings of unconsolidated affiliates			7,590			(22,090	)
		Unrealized gain on derivative financial instruments			(551	)		(21,210	)
		Gain on sale of property			(6,785	)		—
		Change in accounts receivable			(148,676	)		(39,293	)
		Change in inventories			70,011			(8,250	)
		Change in other current assets			(44,437	)		78,507
		Change in accounts payable			(45,108	)		(354,465	)
		Change in other current liabilities			126,781			68,525
		Change in other assets and liabilities			(4,347	)		122,948

			Net cash provided by operating activities		325,300			260,306
Investing activities:
	Nonregulated capital expenditures and asset acquisitions				(416,584	)		(1,389,493	)
	Utility capital/construction expenditures				(185,918	)		(180,874	)
	Allowance for equity funds used during construction				1,881			59
	Investments in external decommissioning fund				(14,259	)		(14,426	)
	Equity investments, loans and deposits				(94,010	)		(129,707	)
	Proceeds from sale of property				11,152			—
	Collection of loans made to nonregulated projects				7,410			308
	Other investments — net				4,744			(3,822	)

			Net cash used in investing activities		(685,584	)		(1,717,955	)
Financing activities:
	Short-term borrowings (payments) — net				(31,673	)		741,001
	Proceeds from issuance of long-term debt				104,799			763,572
	Repayment of long-term debt, including reacquisition premiums				(24,902	)		(300,986	)
	Proceeds from issuance of common stock				534,565			40,366
	Proceeds from NRG stock offering				—			474,348
	Dividends paid				(130,819	)		(128,873	)

			Net cash provided by financing activities		451,970			1,589,428

Effect of exchange rate changes on cash					(3,555	)		(4,386	)
	Net increase in cash and cash equivalents				88,131			127,393
	Cash and cash equivalents at beginning of period				341,310			216,491

	Cash and cash equivalents at end of period			$	429,441		$	343,884

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þ		Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

or

o		Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934


			March 31,			Dec. 31,
			2002			2001


			(Unaudited)
			(Thousands of dollars)
ASSETS
Current assets:
	Cash and cash equivalents		$	429,441		$	341,310
	Restricted cash			193,025			161,842
	Accounts receivable — net of allowance for bad debts of $54,898 and $57,815, respectively			1,306,243			1,174,828
	Accrued unbilled revenues			417,223			495,994
	Materials and supplies inventories — at average cost			333,902			330,363
	Fuel inventory — at average cost			254,938			250,043
	Gas inventories — replacement cost in excess of LIFO: $807 and $11,331, respectively			48,132			126,563
	Recoverable purchased gas and electric energy costs			89,498			52,583
	Derivative instruments valuation — at market			69,624			59,790
	Prepayments and other			385,587			318,046

		Total current assets		3,527,613			3,311,362

Property, plant and equipment, at cost:
	Electric utility plant			16,144,688			16,099,655
	Nonregulated property and other			8,938,368			8,388,261
	Gas utility plant			2,502,210			2,493,028
	Construction work in progress (utility amounts of $715,638 and $669,895, respectively)			3,588,470			3,682,633

		Total property, plant and equipment		31,173,736			30,663,577
	Less: accumulated depreciation			(9,822,757	)		(9,594,775	)
	Nuclear fuel — net of accumulated amortization of $1,021,892 and $1,009,855, respectively			119,189			96,315

		Net property, plant and equipment		21,470,168			21,165,117

Other assets:
	Investments in unconsolidated affiliates			1,259,392			1,209,017
	Notes receivable, including amounts from affiliates of $205,062 and $202,411, respectively			792,848			779,186
	Nuclear decommissioning fund and other investments			709,945			695,070
	Regulatory assets			485,829			502,442
	Derivative instruments valuation — at market			181,910			179,683
	Prepaid pension asset			417,415			378,825
	Goodwill-net (see Note 1)			47,287			63,925
	Intangible assets-net (see Note 1)			83,567			77,276
	Other			357,652			373,159

		Total other assets		4,335,845			4,258,583

		Total assets	$	29,333,626		$	28,735,062

LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	671,917		$	682,207
	Short-term debt			2,182,658			2,224,812
	Accounts payable			1,333,015			1,378,211
	Taxes accrued			384,439			246,152
	Dividends payable			139,920			130,845
	Derivative instruments valuation — at market			43,496			83,122
	Other			689,561			704,679

		Total current liabilities		5,445,006			5,450,028

Deferred credits and other liabilities:
	Deferred income taxes			2,267,869			2,289,550
	Deferred investment tax credits			180,605			184,148
	Regulatory liabilities			501,234			483,942
	Derivative instruments valuation — at market			60,587			57,575
	Benefit obligations and other			726,061			703,836

		Total deferred credits and other liabilities		3,736,356			3,719,051

Minority interest in subsidiaries				652,227			654,670
Capitalization:
	Long-term debt			12,205,551			12,117,516
	Mandatorily redeemable preferred securities of subsidiary trusts			494,000			494,000
	Preferred stockholders’ equity — authorized 7,000,000 shares of $100 par value; outstanding shares: 1,049,800			105,320			105,320
	Common stockholders’ equity — authorized 1,000,000,000 shares of $2.50 par value; outstanding shares: 2002, 370,188,999; 2001, 345,801,028			6,695,166			6,194,477
Commitments and Contingent Liabilities (see Note 5)

		Total Liabilities and Equity	$	29,333,626		$	28,735,062


												Accumulated
												Other			Total
						Retained			Shares Held			Comprehensive			Stockholders’
		Par Value		Premium		Earnings			by ESOP			Income			Equity


		(Unaudited)
		(Thousands of dollars)
Three Months Ended March 31, 2002 and 2001
Balance at Dec. 31, 2000		$	852,085	$	2,607,025	$	2,284,220		$	(24,617	)	$	(156,929	)	$	5,561,784

Net income							209,310									209,310
Currency translation adjustments													(62,633	)		(62,633	)
Cumulative effect of accounting change-net unrealized transition loss upon adoption of SFAS No. 133													(28,780	)		(28,780	)
After-tax net unrealized losses related to derivatives accounted for as hedges (see Note 9)													29,492			29,492
After-tax net realized losses on derivative transactions reclassified into earnings (see Note 9)													(5,861	)		(5,861	)

Comprehensive income for the period																141,528
Dividends declared:
	Cumulative preferred stock of Xcel Energy						(1,060	)								(1,060	)
	Common stock						(128,456	)								(128,456	)
Issuances of common stock — net			3,970		36,396											40,366
Other							(42	)								(42	)
Gain recognized from NRG stock offering					241,891											241,891
Repayment of ESOP loans(a)										1,696						1,696

Balance at March 31, 2001		$	856,055	$	2,885,312	$	2,363,972		$	(22,921	)	$	(224,711	)	$	5,857,707

Balance at Dec. 31, 2001		$	864,503	$	2,969,589	$	2,558,403		$	(18,564	)	$	(179,454	)	$	6,194,477

Net income							103,504									103,504
Currency translation adjustments													(24,666	)		(24,666	)
After-tax net unrealized gains related to derivatives accounted for as hedges (see Note 9)													25,186			25,186
After-tax net unrealized losses on derivative transactions reclassified into earnings (see Note 9)													441			441
Unrealized loss-marketable securities													(30	)		(30	)

Comprehensive income for the period																104,435
Dividends declared:
	Cumulative preferred stock of Xcel Energy						(1,060	)								(1,060	)
	Common stock						(138,834	)								(138,834	)
Issuances of common stock — net			60,806		473,759											534,565
Other							83						22			105
Repayment of ESOP loans(a)										1,478						1,478

Balance at March 31, 2002		$	925,309	$	3,443,348	$	2,522,096		$	(17,086	)	$	(178,501	)	$	6,695,166



		March 31, 2002				Dec. 31, 2001

		Gross Carrying		Accumulated		Gross Carrying		Accumulated
Class of Intangible Asset		Amount		Amortization		Amount		Amortization


		(Thousands of dollars)
Not Amortized:
	Goodwill	$	58,135	$	10,848	$	74,773	$	10,848
	Trademarks	$	5,065	$	443	$	5,065	$	443
Amortized:
	Service contracts	$	98,664	$	21,243	$	90,854	$	19,786
	Other (primarily franchises)	$	1,895	$	371	$	1,904	$	318



	Three Months Ended

	March 31, 2002		March 31, 2001


	(Thousands of dollars)
Reported net income	$	103,504	$	209,310
Add back: Goodwill amortization (after tax)		—		852

Adjusted net income	$	103,504	$	210,162


		Dec. 31, 2001		Accrual Adjustments		Payments			March 31, 2002
		Liability*		Expensed		Against Liability			Liability*

Employee severance and related costs		$	37		9		(7	)	$	39

	Total accrued special charges	$	37		9		(7	)	$	39


*	Reported on the balance sheet in other current liabilities.



	Year Ended Dec. 31

	2001		2000		1999


	(Millions of dollars)
Operating revenues	$	1,562	$	875	$	279
Operating income	$	345	$	278	$	43
Net income	$	326	$	245	$	29



		Dec. 31

		2001		2000


		(Millions of dollars)
Current assets		$	401	$	322
Other assets			659		526

	Total assets	$	1,060	$	848

Current liabilities		$	138	$	230
Other liabilities			269		194
Equity			653		424

	Total liabilities and equity	$	1,060	$	848


		Electric		Gas										Reconciling			Consolidated
		Utility		Utility		NRG			e prime			All Other		Eliminations			Total


		(Thousands of dollars)
Three months ended March 31, 2002
Operating revenues from external customers		$	1,548,309	$	563,479	$	662,440		$	438,501		$	87,687		—		$	3,300,416
Intersegment revenues			259		432		—			16,775			18,850		(35,625	)		691
Equity in earnings of unconsolidated affiliates			—		—		14,670			492			1,318		—			16,480

	Total revenues	$	1,548,568	$	563,911	$	677,110		$	455,768		$	107,855	$	(35,625	)	$	3,317,587

Segment net income (loss)		$	103,084	$	30,859	$	(26,463	)	$	(838	)	$	4,062	$	(7,200	)	$	103,504



	Earnings per Share Increase (Decrease)

Earnings per share for the period ended March 31:	2002 vs. Normal			2001 vs. Normal		2002 vs. 2001

Quarter Ended	$	(0.01	)	$	0.02	$	(0.03	)


Election of Director	Shares Voted For		Withheld Authority

C. Coney Burgess		290,038,728		7,321,042
A. Barry Hirschfeld		289,931,626		7,428,144
Allan L. Schuman		288,456,466		8,903,304
Albert F. Moreno		290,041,814		7,317,956


Shares Voted For	Shares Voted Against	Shares Abstained

16,875,863	187,999,087	12,557,999



	Three Months Ended:

Earnings per share (EPS)	March 31, 2002			March 31, 2001

Regulated EPS	$	0.38		$	0.56
Nonregulated EPS		(0.09	)		0.05

Total Xcel Energy EPS	$	0.29		$	0.61



		Three Months Ended:

Earning per share (EPS)		March 31, 2002			March 31, 2001

NRG Energy Inc.		$	(0.06	)	$	0.08
Seren Innovations Inc.			(0.02	)		(0.02	)
e prime			0.00			0.00
Planergy International			(0.01	)		(0.01	)
Financing costs and preferred dividends			(0.02	)		(0.04	)
Other			0.02			0.04

	Total nonregulated EPS	$	(0.09	)	$	0.05



	Three Months Ended:

	3/31/02			3/31/01


	(Millions of dollars)
Nonregulated and other revenue	$	750		$	733
Earnings from equity investments		16			23
Nonregulated cost of goods sold		(411	)		(395	)

Nonregulated margin	$	355		$	361