XCEL ENERGY INC - 10-Q Quarterly Report

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.

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 June 30, 2002, and Dec. 31, 2001, the results of its operations and stockholders’ equity for the three months and six months ended June 30, 2002 and 2001, and its cash flows for the six months ended June 30, 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.

Certain items in the 2001 income statement and balance sheet have been reclassified 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 are being 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 goodwill of $108.0 million at June 30, 2002, which will not be amortized consisting of excess purchase price on the purchase of the minority shares of NRG Energy, Inc. (NRG) and project-related goodwill at NRG. During the first six months of 2002, Xcel Energy performed impairment tests of its intangible assets. Tests completed to date have concluded that no write-down of these intangible assets is necessary, although as discussed in Note 5, goodwill related to the NRG stock acquisition in 2002 is not yet final. Approximately $16 million of amounts previously reported as Goodwill at Dec. 31, 2001 were reclassified to Nonregulated Property and Other in 2002 to comply with the provisions of SFAS No. 142.

Aggregate amortization expense recognized in the three and six months ended June 30, 2002 was $1.6 million and $3.1 million, respectively. The annual aggregate amortization expense for each of the five succeeding years is expected to approximate $4.1 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 to 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. SFAS 144 will be applied to NRG’s sale of assets as they are reclassified to “held for sale” and discontinued operations (see Note 3).

2002 NRG Restructuring — In the second quarter of 2002, NRG expensed a pretax charge of $20 million, or 4 cents per share, for expected severance costs associated with the Xcel Energy’s plan to reduce or eliminate NRG expenses by combining certain NRG functions with those activities performed by Xcel Energy and other subsidiaries. Through June 30, 2002, severance costs have been recognized for employees who had been terminated as of that date. Additional charges are expected to be expensed in the future, as further actions are taken, but are not determinable at this time.

2002 NRG Charges — NEO Project — During the second quarter of 2002, NRG expensed a pretax charge of $36 million, or 6 cents per share, related to its NEO Corporation landfill gas operations. The charge was related largely to asset impairments based on a revised project outlook. It also reflects the accrued impact of a dispute settlement with Fortistar, a partner with NEO in the landfill gas operations.

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, which was approved by the state regulatory commission in May 2002. Based on the settlement agreement, SPS wrote off pretax restructuring costs of approximately $5 million, 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 an estimated 500 employees in several utility operating and corporate support areas of Xcel Energy. In the first quarter of 2002, the identification of affected employees was completed and additional pretax special charges of $9 million, or approximately 1 cent per share, were expensed for the final costs of the utility-related staff consolidations. As of June 30, 2002, all 564 of accrued staff terminations had occurred.

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


**	$14 million reported on the balance sheet in other current liabilities and $4 million reported in benefit obligations and other.

2001 Postemployment Benefits — Earnings for the second quarter of 2001 were reduced by 4 cents per share due to a Colorado Supreme Court decision that resulted in 2001 pretax write-off of $23 million of regulatory assets related to deferred postemployment benefit costs at Public Service Company of Colorado (PSCo), a wholly owed utility subsidiary of Xcel Energy.

As discussed in Note 6, NRG is in the process of marketing certain assets as part of its financial improvement and restructuring plan. As of June 30, 2002, two international projects of NRG, Bulo Bulo and Collinsville, had been classified as held for sale. The operating results and estimated losses on disposal for these projects have been separately classified and reported as discontinued operations in the accompanying financial statements. The following is a summary of the components of discontinued operations (in thousands):

At June 30, 2002, NRG applied the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets, to Net Assets Held for Sale,” to these entities. SFAS No. 144 requires that assets held for sale to be valued on an asset-by-asset basis at the lower of carrying amount or fair value less costs to sell. In applying those provisions NRG management considered primarily bids and offers related to those businesses. As a result, NRG recorded the estimated loss on disposal for assets held for sale. This amount is shown as Income (loss) from discontinued operations in the accompanying Consolidated Statements of Income. In accordance with the provisions of SFAS No. 144, the assets classified as assets held for sale will not be depreciated commencing July 1, 2002.

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 reduction in NRG’s capital spending for 2002. No incremental costs were incurred by NRG related to the termination of this agreement.

FirstEnergy Assets — In 2001, NRG had signed purchase agreements to acquire or lease a portfolio of generating assets from FirstEnergy Corporation. Under the terms of the agreements, NRG had agreed to finance approximately $1.6 billion for four primarily coal-fueled generating stations.

On July 2, 2002, the Federal Energy Regulatory Commission (FERC) issued an order approving the transfer of FirstEnergy generating assets to NRG; however, FERC conditioned approval on NRG’s assumption of FirstEnergy’s obligations under a separate agreement between FirstEnergy and the City of Cleveland. These conditions require FirstEnergy to protect the City of Cleveland in the event the generating assets are taken out of service. On July 16, 2002, FERC clarified that the condition requires NRG to provide notice to the City of Cleveland and FirstEnergy if the generating assets are taken out of service and that other obligations remain with FirstEnergy.

On Aug. 8, 2002, FirstEnergy notified NRG that the purchase agreements related to FirstEnergy generating assets had been cancelled. FirstEnergy cited the reason for canceling the agreements as an alleged anticipatory breach of certain obligations in the agreements by NRG. FirstEnergy also notified NRG that it is reserving the right to pursue legal action against NRG and Xcel Energy for damages, based on the alleged anticipatory breach. At this time, NRG cannot predict the effect on NRG of any legal action that might be brought. NRG continues to evaluate the implications of the cancellation and its potential exposure to FirstEnergy.

Energy Development Limited — On July 25, 2002, NRG announced it had agreed to the sale of its ownership interests in an Australian energy company, Energy Development Limited (EDL). EDL is an Australian energy company engaged in the development and management of an international portfolio of projects with a particular focus on renewable and waste fuels. NRG will receive proceeds of AUS $78.5 million, or approximately $43.9 million (USD), from the sale in exchange for its ownership interest in EDL. NRG expects to recognize an after-tax loss on the sale of approximately $14.7 million in the third quarter of 2002.

LSP Pike Energy, LLC — In response to its credit rating downgrade in July 2002, NRG has been evaluating its ability and willingness to meet capital requirements for projects under construction given potentially limited financing capabilities.

On Aug. 4, 2002, The Shaw Group and NRG tentatively entered into an agreement for the sale of NRG’s interest in LSP Pike Energy, LLC (Pike) in exchange for $43 million of cash and the forgiveness of approximately $75 million owed to The Shaw Group as contractor for Pike. In addition to the cash received, the sale of the Pike project would be expected to improve NRG’s liquidity position by reducing its ongoing construction funding needs by approximately $142 million in 2002 through 2003.

If all required consents and approvals are received, completion of the sale to Shaw would result in an estimated pretax loss of approximately $500 million. NRG is responsible for the repayment of the debt of $294 million and a turbine lease payment of approximately $50 million.

The Pike project is a 1,200-megawatt combined cycle gas turbine plant currently under construction in Mississippi, which is approximately one-third completed. The sale of the Pike project to Shaw will include all

assets, free of all liens, and will require the consent of all construction lenders and General Electric, which holds a lien against the turbines. In addition, the Xcel Energy board of directors must approve the transaction. As of Aug. 12, 2002, NRG’s construction lenders have been unwilling to provide the consent required to proceed with the sale. NRG has requested a 30-day extension under the terms of its tentative agreement in order to secure lender approval.

Discontinued Operations — See Note 3 for discussion of other NRG divestitures that are reported as discontinued operations as of June 30, 2002.

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, independent 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 May 2002, the partners formed TRANSLink Development Company, LLC., which is responsible for pursuing the actions necessary to complete the regulatory approval of TRANSLink Transmission Company, LLC.

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. TRANSLink Development Company anticipates making this filing during the third quarter of 2002. 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 2003.

During the second quarter of 2002, Xcel Energy acquired all of the 26 percent of NRG shares not then owned by Xcel Energy through a tender offer and merger involving a tax-free exchange of 0.50 shares of Xcel Energy common stock for each outstanding share of NRG common stock. The NRG board of directors, on the recommendation of its Special Committee, recommended that NRG’s stockholders tender their shares in the offer. SEC approval of the transaction was obtained on May 29, 2002. The transaction was effected on June 3, 2002.

The exchange of NRG common shares for Xcel common shares was accounted for as a purchase. The 25,764,852 shares of Xcel stock issued were valued at $25.14 per share, based on the average market price of Xcel Energy shares for 3 days before and after April 4, 2002, when the revised terms of the exchange were announced and recommended by independent members of the NRG Board. Including other costs of acquisition, this resulted in a total purchase price to acquire NRG’s shares of approximately $650 million as of June 30, 2002. Due to the acquisition occurring near quarter-end, some additional acquisition costs are expected to be recorded in the third quarter of 2002.

The process to allocate the purchase price to underlying interests in NRG assets, and to determine fair values for the interests in assets acquired, is not yet complete. Therefore, on a preliminary basis, the excess of the purchase price over the book value of minority shareholder interests in NRG has been recorded as goodwill on the June 30, 2002 balance sheet of Xcel Energy. The preliminary amount of goodwill (approximately $60 million) is subject to change as the final purchase price allocation and asset valuation process is completed.

In response to tightening credit standards experienced by NRG and the independent power production sector, as discussed in Note 7, on Feb. 15, 2002 Xcel Energy announced a financial improvement and restructuring plan for NRG. The announced plan included an initial step of acquiring 100 percent ownership of NRG through a tender offer and merger to exchange all outstanding shares of NRG common stock with Xcel Energy common shares. In addition, the plan included:


	•	financial support to NRG from Xcel Energy;

	•	marketing certain NRG generating assets for possible sale;

	•	canceling and deferring capital spending for NRG projects; and

	•	combining certain NRG functions with Xcel Energy’s system and organization in order to realize greater synergies and to reduce expenses.

In June 2002, Xcel Energy acquired 100 percent ownership of NRG through the acquisition of NRG minority common shares as discussed in Note 5. The following is an update on the status of the remaining elements of the NRG financial improvement and restructuring plan.

Financial Support — From January 2002 through June 30, 2002, Xcel Energy has provided NRG with cash equity infusions (which are eliminated in consolidated financial reporting) of $500 million. In May 2002, Xcel Energy and NRG entered into a Support and Capital Subscription Agreement pursuant to which Xcel Energy agreed under certain circumstances to provide up to $300 million to NRG. Xcel Energy has not, to date, provided funds to NRG under this agreement. Under limitations imposed by the Public Utility Holding Company Act of 1935 (PUHCA), Xcel Energy could invest an additional $400 million into NRG at June 30, 2002. Xcel Energy currently is evaluating the circumstances under which it would make any further investment in NRG.

Marketing of NRG Assets — In the first quarter of 2002, management identified NRG assets and groups of assets that could be potentially marketed for sale. The assets are being marketed in four regional bundles: Latin America, the United Kingdom, Continental Europe and Asia-Pacific. Xcel Energy is also marketing select North American assets, including those in the South Central U.S., for potential sale.

In the second quarter of 2002, invitations were sent to prospective bidders on such assets, with indicative bids due in June 2002. Xcel Energy management reviewed the results of the indicative bids received with the Xcel Energy board of directors in June 2002, and discussed the process by which assets would be considered,

recommended, and approved for sale. The board determined that its approval was necessary for material asset sales. Bidder due diligence was substantially completed in July.

The remaining asset-marketing timetable for 2002 and 2003 is generally as follows:


	•	Final bids are due in August;

	•	Negotiation of sale and purchase agreements is expected in August-September;

	•	Submission of projects to the board for approval of sale to coincide with negotiation process; and

	•	Financial close for those projects which are approved for sale to be completed in September-December, with financial close of some projects in the first half of 2003.

Several projects have an accelerated schedule. At the June 2002 board meeting, one material NRG asset sale was approved. One additional project, which was not a material asset sale, was classified as held for sale in the second quarter of 2002. (See discussion of discontinued operations in Note 3.) In addition, it is expected that several other sales of small NRG assets may be initiated and/or completed in the third quarter of 2002, including EDL as discussed in Note 4.

Indicative bids received and discussed with the board in June 2002 for NRG’s international projects, if ultimately proceeding to a sale at the bid price, are currently expected to generate proceeds of approximately $800 million to $1.3 billion of cash, compared to book value (of equity investments in such projects) of approximately $1.5 billion resulting in material losses. Bids for certain NRG domestic projects were not presented in detail to the Xcel Energy board at their June meeting. However, management anticipates that bids on domestic projects could generate an additional $500 million to $900 million of cash from sale proceeds compared to book value of approximately $900 million to $1.1 billion. As a result, material losses could also result from the sale of NRG’s domestic projects. Proceeds from asset sales are expected to be used to pay down NRG debt.

Because it is not known at this time what projects the Xcel Energy board will approve for sale, nearly all NRG assets being marketed were not considered “held for sale” as of June 30, 2002. For projects ultimately determined to be held for sale, any excess of carrying value of project assets over fair value would need to be recognized as a loss at the time the board commits to a plan to sell.

Capital Spending — NRG has reviewed its construction program and significantly revised its capital expenditure forecast. The new forecast reflects a reduction in NRG construction spending of approximately $1.0 billion in 2003 and $1.3 billion in 2004, as discussed further in the Capital Requirements section of Management’s Discussion & Analysis.

In addition, NRG’s acquisition expenditures (not included in construction program amounts) are also expected to be reduced substantially. The Conectiv acquisition originally scheduled for 2002 has been canceled, and the First Energy acquisition planned for 2002 has been canceled by First Energy due to alleged anticipatory breach of the relevant contract by NRG, as discussed further in Note 4.

Other Activities — Management changes have occurred at NRG. Xcel Energy has begun to combine portions of NRG’s energy marketing and power plant management functions with corresponding Xcel Energy functions. In addition, NRG’s corporate and administrative support functions are also being combined into comparable areas of Xcel Energy. When completed, these processes are expected to reduce NRG’s operating cost structure by $75 million to $100 million on an annual basis.

The employee termination and other costs incurred through June 30, 2002 associated with NRG are reported as Special Charges in NRG’s second quarter results, as discussed further in Note 2 to the Financial Statements.

NRG Credit Rating — As previously reported in the 2001 Annual Report on Form 10-K, several credit rating agencies had placed NRG on credit watch for possible downgrade based on tightening credit standards for the independent power sector and other concerns unique to NRG’s financing requirements. Concerns were also raised for Xcel Energy’s corporate and utility credit ratings.

In December 2001, Moody’s placed NRG’s long-term senior unsecured debt rating on review for downgrade. As of June 30, 2002, NRG’s credit rating remained under review for potential downgrade. On July 26, 2002, Standard & Poor’s Ratings Services announced it had lowered NRG’s corporate credit rating to BB. The secured NRG Northeast Generating LLC bonds and the NRG South Central Generating LLC bonds were also lowered to BB. The senior unsecured bonds of NRG were lowered to B-plus. All of the NRG debt issues and the corporate credit rating were placed on “credit watch” with negative implications. On July 29, 2002, Moody’s Investors Service lowered NRG’s senior unsecured debt rating from Baa3 to B1 and assigned a Senior Implied rating of Ba3 to NRG. On Aug. 7, 2002, Standard & Poor’s Ratings Services lowered the corporate credit rating of NRG to B-plus from double BB, stating the rating now reflects NRG’s stand-alone credit quality. NRG’s rating remains on Credit Watch with negative implications pending the outcome of other negotiations, notably the construction facility banks concerning the required collateral (as discussed below) and with FirstEnergy Corp. concerning the acquisition of power generating plants. On July 30, 2002, Fitch Ratings lowered the outstanding ratings of Xcel Energy and its operating utility subsidiaries. Xcel Energy’s senior unsecured rating was lowered to BB+ from BBB+. Its commercial paper rating was lowered to B from F2 and withdrawn. The ratings of Xcel Energy’s operating utility subsidiaries; NSP-Minnesota, NSP-Wisconsin, PSCo and SPS; were also lowered but remain investment grade. All credit ratings are not a recommendation to buy, sell or hold securities, and each rating should be evaluated independently of any other rating.

Liquidity Issues — NRG has a great deal of debt and other obligations that currently require that they be supported with letters of credit or cash collateral within 5 to 30 days of a ratings downgrade by Moody’s or Standard & Poor’s.

As a result of the recent downgrades, NRG estimates that it will be required to post collateral ranging from $1.1 billion to $1.3 billion. Of the collateral to be posted, approximately $215 million is required to fund debt service reserve and other guarantees at the project level, $10 million is required to fund trading operations, $75 million is required to fund remaining equity commitments to complete construction of the Brazos Valley plant in Texas; and between $825 million and $975 million is required to fund equity guarantees associated with the $2 billion construction and acquisition revolver depending on various options being pursued. NRG is working with its lenders to obtain waivers to delay the posting of this collateral. Absent waiver of the collateral requirements, the largest portion of collateral must be posted no later than Aug. 19, 2002.

Since NRG is unable to post the required collateral, NRG is actively seeking waivers at this time. The failure to post the required collateral will result in defaults unless waivers are obtained. If NRG is unable to obtain waivers or modifications of these collateral requirements and the underlying obligations are accelerated, NRG would need to refinance or restructure its obligations and, if unsuccessful in these efforts, to consider all other options including a restructuring under the bankruptcy laws.

program may be unsustainable given the difficulties involved in raising cash through the capital markets and the uncertainties involved in obtaining additional equity funding from Xcel Energy. NRG and Xcel Energy have retained financial advisors to help work through these liquidity issues in an effort to avoid defaults on NRG debt and other obligations. Because only a short amount of time has passed since NRG was downgraded, NRG is unsure as to the resolution of all issues. NRG’s initial priorities are obtaining waivers or delay of its collateral calls and avoiding the acceleration of its debt obligations. Once these collateral issues are resolved and additional decisions relating to asset sales are made, NRG plans to finalize a revised business plan in respect of ongoing operations of NRG.

The following is a table outlining the current status of the projects that NRG has under construction and an estimate of the expected costs to be incurred through 2004 for such projects. As previously disclosed, NRG is reevaluating its commitments under these agreements and over the remainder of the third quarter will be making determinations as to which projects will be disposed of or abandoned.

Assuming the waiver of cash collateral requirements and no new liquidity sources, other than expected proceeds from near term asset sales, coupled with aggressive cost management and deferrals of certain payments, it is currently estimated that NRG could exhaust its existing liquidity resources during October 2002. Pending the resolution of NRG credit and liquidity contingencies and the timing of possible asset sales, a portion of NRG’s long-term debt obligations have been classified as a current liability on the accompanying balance sheet due to the possibility of lenders having the ability to call such debt within 12 months of the balance sheet date. If NRG is successful in executing the asset sales plan as currently contemplated, can avoid the need for posting significant amounts of cash collateral, and remains in compliance with its credit facilities, there should be sufficient proceeds to enable NRG to pay its debts as they come due.

At the present time and based on conversations with various lenders, Xcel Energy management does not believe the appropriate course of action would be filing by NRG to seek relief under the bankruptcy laws. Rather it believes that the implementation of its plans for NRG as discussed in Note 6, coupled with waivers from lenders is the appropriate course of action to restore NRG’s financial strength. In the event that NRG is unable to work through the issues as described above and is unable to obtain adequate financing on terms acceptable to NRG, there would be substantial doubt as to NRG’s ability to continue as a going concern.

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 subsidiaries and project affiliates. 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 June 30, 2002, six of NRG’s subsidiaries and project affiliates are restricted from making cash payments to NRG. Loy Yang, Killingholme, Energy Center Kladno, LSP Energy (Batesville) and Louisiana Generating do not currently meet the minimum debt service coverage ratios required for these projects to make payments to NRG; 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 do not permit the lenders to accelerate the project financings. The forced outage of one 500-megawatt 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. The unit has been repaired and, if insurance claims are paid and forecasted revenues and costs are achieved, default is expected to be avoided. If an event of default were to occur at one or more of the projects and any accelerated financings were not paid, the project lenders could foreclose on the projects in question and NRG could lose its equity investment in the projects. NRG’s equity investment in these six projects was approximately $1.1 billion at June 30, 2002.

Other Covenants and Compliance — The bankruptcy of Pacific Gas & Electric (PG&E) creates the potential for a covenant default that would result in the acceleration of the debt at Crockett if not resolved with the lenders. Management has engaged in active discussions with the lenders of Crockett since PG&E filed for bankruptcy in April 2001; additionally, Crockett is being paid each month by PG&E since the bankruptcy filing. PG&E and the Bankruptcy Court have affirmed the long-term power purchase agreement and PG&E is paying down the outstanding receivable over a 12-month period ending Dec. 1, 2002. Thus, NRG believes that an acceleration of the Crockett debt is unlikely. However, as of June 30, 2002 and Dec. 31, 2001, NRG has reflected the entire balance of the Crockett debt as a current obligation in the amounts of $228.7 million and $234.5 million, respectively.

In May 2002, NRG’s indirect wholly owned subsidiary, LSP-Kendall Energy, LLC received a notice of default from Societe Generale, the administrative agent under LSP-Kendall’s Credit and Reimbursement Agreement dated Nov. 12, 1999. The notice asserted that an event of default had occurred under the Credit and Reimbursement Agreement as a result of liens filed against the Kendall project by various subcontractors. In consideration of NRG’s indemnification of LSP-Kendall, the administrative agent and the lenders to the Kendall project from any claims or damages relating to these liens or any dispute or action involving the project’s EPC contractor pursuant to an Indemnity Agreement dated as of June 28, 2002, the administrative agent, with the consent of the required lenders under the Credit and Reimbursement Agreement, withdrew the notice of default and waived any default or event of default described therein.

As discussed in Management’s Discussion & Analysis, NRG’s subsidiary, NRG Peaker Finance Co. LLC. issued $325 million of long-term bonds in June 2002. The bond requirements included a number of provisions, restrictions, conditions and covenants.

Electric Wholesale Generator Approval — 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 the $2 billion construction and acquisition revolving credit facility and the $1 billion unsecured corporate revolving line of credit. Accordingly, NRG sought and has received from its construction and acquisition revolving credit 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 PUCHA, 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 under the construction and acquisition facility continues indefinitely unless a default arising out of any possible PUHCA violation relating to Big Cajun’s temporary failure to make these filings occurs.

Merger Agreements — 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 electric 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 of 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.

Incentive Cost Adjustment — 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.

General Rate Case — In May 2002, Xcel Energy filed a combined general rate case with the CPUC to address increased costs for providing energy to Colorado customers. The net impact of the filings would increase electric revenue by approximately $220 million annually and decrease gas revenue by approximately $13 million. The rates are expected to be effective in early 2003. Xcel Energy also asked to increase its authorized rate of return on equity set at 12 percent for electricity and 12.25 percent for natural gas.

The CPUC staff and the Office of Consumer Counsel (OCC) filed a joint motion requesting the CPUC permanently suspend PSCo’s rate case alleging PSCo did not show (in the form that Staff is familiar with) the

appropriate direct and indirect accounting for costs of non-regulated services. On Aug. 2, 2002, Xcel Energy, the CPUC and the OCC (the parties) filed a joint motion to request the CPUC delay their decision on the original motion for two weeks until August 19th. PSCo is currently working resolve the allegations. It is possible the parties could request the CPUC delay the effective date of the rate case.

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. Hearings were held in July 2002. A decision is expected in late 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 costs related to transition to retail competition from the Texas retail customers. These costs were incurred to position SPS for retail competition, which was eventually delayed for SPS. The filing was amended in March 2002 to reduce the recoverable costs by $7.3 million, which were associated with over-earnings for the calendar year 1999. The PUCT approved SPS using the 1999 over-earnings to offset the claims for reimbursement of transition to competition costs. This reduced the requested net collection in Texas to $13.0 million. In April 2002, a unanimous settlement agreement was reached. Final approval by the PUCT was received in May 2002. The stipulation provides for the recovery of $5.9 million through an incremental cost recovery rider and the capitalization of $1.9 million for metering equipment. Based on the settlement agreement, SPS wrote off pretax restructuring costs of approximately $5 million in the first quarter of 2002. Recovery of the $5.9 million began in July 2002.

Metro Emissions Reduction Program — On July 26, 2002, 2002, NSP-Minnesota filed for approval by the Minnesota Public Utilities Commission (MPUC) a proposal to invest in existing NSP-Minnesota generation facilities (A S King, High Bridge, Riverside) to reduce emissions under the terms of legislation adopted by the 2001 Minnesota Legislature. The proposal includes the installation of state-of-the-area pollution control equipment at the AS King plant and conversion to natural gas at the High Bridge and Riverside plants. Under the terms of the statute, the filing concurrently seeks approval of a rate recovery mechanism for the costs of the proposal, estimated to be a total of $1.1 billion with major expenditures anticipated to begin in 2005 and continuing through 2009. The rate recovery would be through an annual automatic adjustment mechanism authorized by 2001 legislation, outside a general rate case, and is proposed to be effective at the expiration of the NSP-Minnesota merger rate freeze, which extends through 2005 unless certain exemptions are triggered. The rate recovery proposed by NSP-Minnesota would allow recovery of financing costs of capital expenditures prior to the in-service date of each plant. The proposal is pending comments by interested parties. Other regulatory approvals, such as environmental permitting, are needed before the proposal can be implemented.

Renewable Cost Recovery Tariff — In April 2002, NSP-Minnesota also filed for MPUC authorization to recover in retail rates the costs of electric transmission facilities constructed to provide transmission service for renewable energy. The rate recovery would be through an automatic adjustment mechanism authorized by 2001 legislation, outside a general rate case, and is proposed to be effective Jan. 1, 2003. In July 2002, the Minnesota Department of Commerce filed comments supporting approval of the tariff mechanism, subject to certain modifications that are generally acceptable to Xcel Energy.

Standard Market Design Rulemaking — In July 2002 the FERC issued a Notice of Proposed Rulemaking on Standard Market Design rulemaking for regulated utilities. If implemented as proposed, the

Rulemaking will substantially change how wholesale markets operate throughout the United States. The proposed rulemaking expands the FERC’s intent to unbundle transmission operations from integrated utilities and ensure robust competition in wholesale markets. The rule contemplates that all wholesale and retail customers will be on a single network transmission service tariff. The rule also contemplates the implementation of a bid based system for buying and selling energy in wholesale markets. The market will be administered by RTOs or Independent Transmission Providers. RTOs will also be responsible for putting together regional plans that identify opportunities to construct new transmission, generation or demand side programs to reduce transmission constraints and meet regional energy requirements. Finally, the Rule envisions the development of Regional Market Monitors responsible for ensuring that individual participants do not exercise unlawful market power. Comments to the rules are due in the fourth quarter of 2002. The FERC anticipates that the final rules will be in place in early 2003 and the contemplated market changes will take place in 2003 and 2004.

Cash Management Regulation — On Aug. 1, 2002, the FERC issued a Notice of Proposed Rulemaking proposing to adopt new rules governing corporate “money pools,” which include jurisdictional public utility or pipeline subsidiaries of nonregulated parent companies. The proposed rules would require documentation of transactions within such money pools, a proprietary capital account of the jurisdictional utility of 30 percent, and would require the nonregulated parent company to have an investment grade rating. Comments on the proposed rules are due Aug. 22, 2002. Xcel Energy is reviewing the proposed rules and their interaction with similar money pool regulations of the SEC.

Standards of Conduct Rulemaking — In October 2001, FERC issued a Notice of Proposed Rulemaking proposing to adopt new standards of conduct rules applicable to all jurisdictional electric and natural gas transmission providers. The proposed rules would replace the current rules governing the electric transmission and wholesale electric functions of the Xcel Energy utility subsidiaries and NRG, respectively; and the rules governing the natural gas transportation and wholesale gas supply functions of Viking Gas, e prime and the Xcel Energy utility subsidiaries, respectively. The proposed rules would expand the definition of “affiliate” and further limit communications between transmission functions and supply functions, and may materially increase operating costs of Xcel Energy. In April 2002, the FERC staff issued a reaction paper, generally rejecting the comments of parties opposed to the proposed rules. Final rules are expected by year-end 2002.

FERC Investigation — As discussed in Xcel Energy Current Report on Form 8-K filed May 24, 2002, 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. On May 22, 2002, Xcel Energy reported to the FERC that it had not engaged directly in any of the trading strategies identified in the May 8th inquiry. On May 22, 2002, NRG responded that it had not engaged in any trading activities outlined in the FERC request.

On May 13, 2002, Xcel Energy independently and not in direct response to any regulatory inquiry announced that PSCo had engaged in certain trading transactions, initiated by Reliant Resources, that had immaterial income effects in 1999 and 2000.

To supplement the May 8th request, on May 21, 2002, the FERC ordered all sellers of wholesale electricity and/or ancillary services in the United States portion of the Western Systems Coordinating Council during 2000 and 2001 to report whether they had engaged in activities referred to as “wash,” “round trip” or “sell/buyback” trading. On May 31, 2002, Xcel Energy reported to the FERC that it had not engaged in so-called round trip electricity trading identified in the May 21st inquiry.

Xcel Energy did report, as previously announced on May 13, 2002, that PSCo had engaged in a group of transactions in 1999 and 2000 with the trading arm of Reliant Resources in which PSCo bought a quantity of

power from Reliant and simultaneously sold the same quantity back to Reliant. For doing this, PSCo normally received a small profit. PSCo made a total pretax profit of approximately $110,000 on these transactions. Also, PSCo engaged in one trade with Reliant in which PSCo simultaneously bought and sold power at the same price without realizing any profit. The purpose of this nonprofit transaction was in consideration of future for-profit transactions. PSCo engaged in these transactions with Reliant for the proper commercial objective of making a profit. It did not enter into these transactions to inflate volumes or revenues.

Xcel Energy and PSCo have received subpoenas from the Commodity Futures Trading Commission for documents and other information concerning these so-called “round trip trades” and other trading in electricity and natural gas for the period Jan. 1, 1999 to the present involving Xcel Energy or any of its subsidiaries.

Xcel Energy also has received a subpoena from the SEC for documents concerning “round trip trades,” as defined in the SEC subpoena, in electricity and natural gas with Reliant Resources, Inc. for the period Jan. 1, 1999, to the present. The SEC subpoena is issued pursuant to a formal order of private investigation that does not name Xcel Energy. Based upon accounts in the public press, management believes that similar subpoenas in the same investigations have been served on other industry participants. Xcel Energy and PSCo are cooperating with the regulators and taking steps to assure satisfactory compliance with the subpoenas.

Connecticut Light & Power-NRG — On Dec. 5, 2001, NRG and Connecticut Light and Power (CL&P) filed a request with the Connecticut Department of Public Utility Control (DPUC) for an increase in the standard offer rate paid to energy suppliers. The increase was requested to cover higher costs related to recent environmental legislation and anticipated higher charges for transmission service. The increase would have contributed approximately $5 million of net income per month to NRG. On June 17, 2002, the DPUC ruled the parties were not entitled to the requested increase.

In July 2002, NRG reached a tentative agreement with CL&P that would result in increased compensation to NRG, a supplier of CL&P’s wholesale supply agreement. As a part of the agreement, NRG has committed to keeping power generation units in service at its Devon and Norwalk Harbor generating stations as well as at its Cos Cob remote jet sites for the remainder of the wholesale supply agreement. CL&P filed an emergency petition with the DPUC asking for approval of a shift of wholesale supply agreement revenues, effective Aug. 1, 2002, through Dec. 31, 2003, that would reallocate 0.7 cents per kilowatt-hour in the wholesale price paid to existing suppliers. On July 26, 2002, the DPUC denied the request of CL&P for an emergency letter ruling. NRG expects to continue negotiations for receipt of capacity payments for critical generating units in Connecticut.

On Aug. 9, 2002, NRG announced it had finalized an agreement with ISO-New England to keep three units at its Devon station in service. Under the terms of the agreement, units seven and eight will remain available until ISO-New England gives a 60-day notice that one or both are no longer needed for reliability. Unit 10 may be deactivated on or after Oct. 1, 2002. The agreement expires on Sept. 30, 2003. The agreement provides for increased capacity payments and notice of termination. It also allows NRG sufficient compensation to continue operating through the end of the agreement.

Temporary Modification of PUHCA Equity Ratio Limit — In accordance with an order of the SEC granting Xcel Energy authority to finance, Xcel Energy cannot currently issue any securities or guarantees if its common equity ratio is below 30 percent. On Aug. 2, 2002, Xcel Energy filed a proposal with the SEC, seeking authorization to engage in financing transactions at a time when Xcel Energy’s ratio of common equity to total capitalization is less than 30 percent. The proposal provided that the common equity of Xcel Energy,

as reflected on its most recent Form 10-K or Form 10-Q and as adjusted to reflect subsequent events that affect capitalization, be at least 24 percent of total capitalization. In addition, Xcel Energy proposed not to engage in any financing transactions after June 30, 2003, unless at such time Xcel Energy has an equity ratio of at least 30 percent. Xcel Energy expects that any reduction of its common equity ratio below 30 percent would be temporary pending equity offerings by Xcel Energy and the consummation of the NRG asset sales, as discussed below.

Xcel Energy is evaluating the business of NRG (as discussed in Note 6) and its other non-regulated businesses and is considering certain alternatives. Alternatives under consideration by Xcel Energy management will require approval of the board of directors and include the possible sale of selected generating assets of NRG and exiting other non-regulated businesses, which do not fit strategically with Xcel Energy. Xcel Energy may be required to record losses from such sales or divestitures as a result of future board actions prior to the period in which the asset sale occurs. Such losses may result in the common equity of Xcel Energy temporarily falling below 30 percent of its capitalization.

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 7 to the Financial Statements describes the current status of credit 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 discussed in the 2001 Annual Report on Form 10-K that are material to Xcel Energy’s financial position as of June 30, 2002:


	•	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, selected NRG assets, Argentina)

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

On July 1, 2002, Xcel Energy received a Notice of Violation (NOV) from the United States Environmental Protection Agency (EPA) alleging violations of the New Source Review (NSR) requirements

of the Clean Air Act at the Comanche and Pawnee Stations in Colorado. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process. Xcel Energy believes it acted in full compliance with the Clean Air Act and NSR process. It believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. Xcel Energy also believes that the projects would be expressly authorized under the EPA’s NSR policy announced by the EPA administrator on June 22, 2002. Xcel Energy disagrees with the assertions contained in the NOV and intends to vigorously defend its position.

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

Class Action Lawsuit — On July 31, 2002, a lawsuit purporting to be a class action on behalf of purchasers of Xcel Energy common stock between Jan. 31, 2001 and July 26, 2002, was filed in the United States District Court in Minnesota. The complaint named Xcel Energy; Wayne H. Brunetti, chairman, president and chief executive officer; Edward J. McIntyre, vice president and chief financial officer and former chairman, James J. Howard as defendants. Among other things, the complaint alleges violations of Section 10b of the Securities Exchange Act and Rule 10b-5 related to allegedly false and misleading disclosures concerning various issues, including “round trip” energy trades and the existence of cross-default provisions in Xcel Energy’s and its subsidiary, NRG Energy’s, credit agreements with lenders. Since the filing of the lawsuit on July 31, 2002, additional lawsuits have been filed with similar allegations. The defendants deny any liability and maintain they have made disclosures fully compliant with applicable laws and reporting requirements.

Xcel Energy Short-Term Borrowings — At June 30, 2002, Xcel Energy and its subsidiaries had approximately $2.5 billion of short-term debt outstanding at a weighted average interest rate of approximately 3.32 percent.

Xcel Energy Bank Credit Agreements — On Aug. 5, 2002, Xcel Energy signed agreements with its lenders to eliminate certain cross-default provisions in its bank credit agreements that were tied to the performance by NRG of its credit agreements. Xcel Energy’s bank agreements consist of a 364-day credit facility in the amount of $400 million expiring in November 2002 and a five-year credit facility in the amount of $400 million expiring in November 2005. The agreements remove key provisions in Xcel Energy’s credit facilities that would have constrained Xcel Energy’s ability to access capital due to difficulties faced by its NRG subsidiary in complying with the terms of its own credit facilities. NRG’s debt was downgraded recently to below investment grade by two major rating agencies. Absent waivers or modifications, NRG’s inability to meet the cash collateral demands following the downgrade would result in defaults under various agreements and credit facilities at the NRG level, which, in turn, could have resulted in a cross-default under Xcel Energy’s $800 million bank facilities. The agreements reached with Xcel Energy’s lenders remove this linkage between NRG’s agreements and credit facilities. In particular, cross-default provisions of Xcel Energy’s credit facilities were amended such that default by NRG in respect of its indebtedness will not constitute an event of default under Xcel Energy’s credit agreements. As part of its agreements with its lenders, Xcel Energy has agreed that its board of directors will review its dividend policy. While the board could decide to alter the dividend, currently the board has made no decision.

NRG Short-Term Borrowings — 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 1.75 to 1.00 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, as defined in the credit agreement, 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 June 30, 2002, NRG had a $1-billion outstanding balance under this credit facility. Based on current forecasts, NRG believes that, unless the covenant is waived, it is likely that NRG will breach the minimum interest coverage ratio when the Sept. 30, 2002 calculation is performed. At June 30, 2002, the weighted average interest rate of such outstanding advances was 3.38 percent per year.

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. During second quarter of 2002, the letter of credit facility agreement was amended to incorporate the same covenant revisions and other amendments that had previously been made to the terms and conditions of NRG’s $1-billion revolving credit facility, including the addition of an interest coverage ratio covenant.

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. In June 2002, this facility was paid off and was not renewed.

NRG Revolving Credit — In May 2001, NRG’s wholly-owned subsidiary, NRG Finance Company I LLC, entered into a $2 billion revolving credit facility. The facility will be 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 provides for borrowings of base rate loans and Eurocurrency loans and is secured by mortgages and security agreements in respect of the assets of the projects financed under the facility, pledges of the equity interests in the subsidiaries or affiliates of the borrower that own such projects, and by guaranties from each such subsidiary or affiliate. 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 June 30, 2002, the aggregate amount outstanding under this facility was $1.1 billion. At June 30, 2002, the weighted average interest rate of such outstanding advances was 3.46 percent. Due to the lowering of NRG’s credit ratings to below investment grade, NRG is required to post approximately up to $975 million of collateral pursuant to this agreement on or before Aug. 16, 2002. NRG lacks the ability to post this collateral and is actively seeking a temporary waiver of its obligations to post collateral. See Note 7 for a description of possible consequences if the waiver is not obtained.

Financing Instruments — As of June 30, 2002, Xcel Energy had several interest rate swaps with a notional amount of approximately $2.6 billion. The majority of these swaps were related to NRG. If the swaps

were terminated at June 30, 2002, Xcel Energy or its subsidiaries would have had to pay the counterparties approximately $105 million.

Guarantees — Xcel Energy provides various guarantees and bond indemnities supporting its subsidiaries. As of July 31, 2002, Xcel Energy’s exposure under these guarantees totaled approximately $330 million.

Of the aggregate exposure of Xcel Energy under guarantees outstanding as of July 31, 2002, approximately $90 million relate to obligations of NRG’s power marketing subsidiary (which includes power marketing obligations, fuel purchasing transactions and hedging activities), approximately $130 million relate to obligations of e prime (relating to trading and hedging activities) and approximately $60 million relate to obligations of Viking Gas (relating to the Guardian pipeline project which terminates on the in-service of the project, which is expected to be March 2003). The remaining exposure of Xcel Energy under the guarantees is estimated to be approximately $50 million.

The guarantees issued by Xcel Energy guaranty 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. The majority of the guarantees issued by Xcel Energy limit the exposure of Xcel Energy to a maximum amount stated in the guarantees. The aggregate maximum liability of Xcel Energy under the guarantees is approximately $748 million as of July 31, 2002. Of this maximum, approximately $247 million support obligations of NRG’s power marketing subsidiary, approximately $329 million relate to e prime, and approximately $60 million relate to Viking Gas. Xcel Energy entered into the NRG guarantees after the NRG exchange offer, which was completed in the second quarter of 2002.

Xcel Energy may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy part or potentially all of these exposures, in the event that Standard and Poors or Moodys downgrade Xcel Energy’s credit rating below investment grade.

In the event of a downgrade, Xcel Energy would expect to meet its collateral obligations with some combination of cash on hand, availability under its credit facilities and the issuance of securities in the capital markets.

In addition, Xcel Energy provides indemnity protection for bonds issued by subsidiaries. The total amount of bonds with this indemnity outstanding as of July 31, 2002 was approximately $354 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 indemnification.

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 and six months ended June 30, 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.

Normal Purchases or Normal Sales — 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.

Cash Flow Hedges — 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 June 30, 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 June 2003 net losses from Other Comprehensive Income of approximately $27.9 million.

As required by SFAS No. 133, we recorded gains of $0.9 million and losses of $1.3 million related to ineffectiveness on commodity cash flow hedges during the three months ended June 30, 2002 and 2001, respectively, and gains of $1.0 million and losses of $1.0 million related to ineffectiveness on commodity cash flow hedges during the six months ended June 30, 2002 and 2001, respectively.

We recorded unrealized gains of $32.2 million and unrealized losses of $33.7 million associated with changes in the fair value of non-hedge, energy-related derivative instruments for the three months ended June 30, 2002 and June 30, 2001, respectively. We recorded unrealized gains of $33.6 million and unrealized losses of $13.5 million associated with changes in the fair value of non-hedge, energy-related derivative instruments for the six months ended June 30, 2002 and June 30, 2001, respectively.

Xcel Energy and its subsidiaries enter into interest rate swap instruments that effectively fix the interest payments on certain floating rate debt obligations. These derivative instruments are designated as cash flow hedges for accounting purposes and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income. Xcel Energy expects to reclassify into earnings through June 2003 net gains from Other Comprehensive Income of approximately $12.3 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 June 2003 from Other Comprehensive Income on foreign currency swaps accounted for as hedges.

We recorded unrealized losses of $0.3 million and unrealized gains of $0.9 million associated with changes in the fair value of non-hedge, foreign currency derivative instruments for the three months ended June 30, 2002 and June 30, 2001, respectively. We recorded unrealized losses of $0.2 million and unrealized gains of $2.2 million associated with changes in the fair value of non-hedge, foreign currency derivative instruments for the six months ended June 30, 2002 and June 30, 2001, respectively.

Derivatives Not Qualifying for Hedge Accounting — 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 the availability of credit, actions of rating agencies and 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;

	•	currency translation and transaction adjustments;

	•	realization of expectations regarding the NRG financial improvement plan;

	•	NRG’s ability to reach agreements with its lenders and creditors to restructure its debt and delay the funding of collateral required following NRG’s credit ratings downgrades;

	•	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 this Form 10-Q.

Xcel Energy’s earnings per share were $0.23 for the second quarter of 2002, compared with $0.49 for the second quarter of 2001. Xcel Energy’s earnings per share for the second quarter of 2002 were reduced by 10 cents per share primarily related to severance charges and NEO charges at NRG and discontinued operations of 4 cents per share reflecting two NRG projects held for sale as of June 30, 2002. Xcel Energy’s earnings were $0.52 for the six months ended June 30, 2002, compared with $1.10 for the six months ended June 30, 2001. In addition to the charges in the second quarter of 2002, Xcel Energy’s earnings per share for the six months ended 2002 were reduced by 1 cent per share for the write-off of Texas restructuring costs and 1 cent per share for staff consolidations. Earnings per share for the six month period ended June 30, 2001 were reduced by 4 cents per share due to a write-off of regulatory assets and increased by 7 cents per share due to the reversal of a regulatory decision regarding conservation incentives as discussed below. See discussion of other special charges at Note 2.

The following table details the earnings per share contribution of Xcel Energy’s regulated and nonregulated businesses.

Regulated Results — The 2002 regulated results declined largely due to lower short-term wholesale and trading margins and conservation adjustments, as discussed in the following section. This was partially offset by higher margins from other electric and gas sales, also discussed in detail in the following section. See discussion of special charges at Note 2.

2001 Conservation Incentive Recovery — Earnings in the second quarter of 2001 were increased by 7 cents per share due to the reversal of a Minnesota Public Utilities Commission (MPUC) decision.

In June 1999, the MPUC denied NSP-Minnesota recovery of 1998 incentives associated with state-mandated programs for electric energy conservation. Xcel Energy recorded a $35-million charge in 1999, which reduced earnings by 7 cents per share, based on this action. NSP-Minnesota appealed the MPUC decision and in December 2000, the Minnesota Court of Appeals reversed the MPUC decision. In January 2001, the MPUC appealed the lower court decision to the Minnesota Supreme Court. On Feb. 23, 2001, the Minnesota Supreme Court declined to hear the MPUC’s appeal. During the second quarter of 2001, NSP-Minnesota filed with the MPUC a plan that carried out, among other things, the court’s decision.

On June 28, 2001, the MPUC approved the plan and issued an order to that effect shortly thereafter. As a result, the previously recorded liabilities of approximately $41 million (including carrying charges) for potential refunds to customers were no longer required. The plan approved by the MPUC increased revenue by approximately $34 million and increased allowance for funds used during construction by approximately $7 million, increasing earnings by 7 cents per share for the second quarter of 2001.

Based on the new MPUC policy and less uncertainty regarding conservation incentives to be approved, conservation incentives are now being recorded on a current basis.

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 Operating Results — NRG’s earnings from ongoing operations decreased for 2002 due primarily to lower power prices in the Northeast and Central regions of the United States and favorably priced contracts in place for West Coast Power in 2001. In addition, higher operating, depreciation and interest costs have resulted from project acquisitions since the second quarter of 2001. The decrease for the second quarter was partially offset by a mark-to-market gain recorded under SFAS No. 133 in the second quarter of 2002 of 5 cents per share, compared with 3 cents per share in SFAS No. 133 losses in the comparable 2001 period. NRG’s special charges are discussed in Note 2 and discontinued operations are discussed in Note 3.

NRG’s earnings from ongoing operations decreased for the six months ended June 30, 2002 compared with the same period in 2001 due primarily to lower power pool prices and generation in the Northeast and Central regions of the United States, lower revenues from power marketing activities and favorably priced contracts for West Coast Power in 2001. In addition, higher operating, depreciation and interest costs have resulted from project acquisitions since the second quarter of 2001. See discussion of NRG’s special charges at Note 2 and discontinued operations at Note 3.

NRG Net Income by Region — NRG manages its generation portfolio on a geographical basis. The following table summarizes net income by region for the three months ended June 30, 2002 and 2001. The

“other” category includes operations that do not meet the threshold for separate disclosure and corporate charges (primarily interest expense) that have not been allocated to the operating segments.

NRG’s special charges and discontinued operations relate to severance, NEO impairments and the expected losses from project sales, see Note 2 for further discussion.

Seren — Operations of its broadband communications network in Minnesota and California resulted in losses for the quarter and six month periods ended June 30, 2002 and 2001 for Seren. As of June 30, 2002, Xcel Energy’s investment in Seren was approximately $250 million. Seren had capitalized $247 million for plant in service and had incurred another $33 million for construction work in progress for these systems at June 30, 2002. Management is continuing to evaluate the strategic fit of Seren in Xcel Energy’s business portfolio.

E prime — e prime’s results for the three months and six months ended June 30, 2002 reflect less favorable market opportunities in the gas transmission and storage business compared with the same period in 2001.

Planergy International — During the second quarter of 2001, Planergy recorded a loss of 2 cents per share largely due to lower margins on performance contracts, higher project development expenses and final costs related to the consolidation of Planergy and EMI operations.

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 $58 million for the second quarter of 2002, compared with the second quarter of 2001. The decrease reflects lower power pool prices and other market conditions in 2002.

Electric utility revenues decreased approximately $164 million in the second quarter of 2002, compared with the same period in 2001, due largely to lower fuel and purchased power costs passed through rate recovery mechanisms. Electric utility margins increased approximately $4 million for the second quarter of 2002, compared with 2001. The higher electric margins in the second quarter reflect lower unrecovered costs, due in part to resetting the base-cost recovery at PSCo in January 2002. Warmer June temperatures and sales growth also contributed to the higher margins. The increase was partially offset by higher demand costs, lower capacity margins and Minnesota conservation adjustments. Electric utility revenues and margins were both lower in 2002 due to the 2001 reversal to the disallowed conservation incentive revenues at NSP-Minnesota discussed previously.

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 $164 million, or 41.0 percent, in the second quarter of 2002, compared with the same period in 2001, 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 increased by approximately $2 million or 1.8 percent, over the same periods, due largely to cooler April 2002 temperatures.

Nonregulated revenue and margin increased for the second quarter of 2002, largely due to NRG increases from a larger generation portfolio and decreased cost of goods sold reflecting favorable mark-to-market adjustments during second quarter of 2002 under SFAS No. 133 at NRG.

Earnings from equity investments decreased for the second quarter of 2002, due to a decrease in equity earnings from NRG projects reflecting lower power pool prices and a more competitive market in areas of NRG operations.

Regulated Other Operation and Maintenance Expenses for the second quarter of 2002 decreased by approximately $28 million, or 7.4 percent, compared with the second quarter of 2001. The decreased costs in the second quarter reflect lower incentive compensation and other employee benefit costs, partially offset by higher plant outage and property insurance costs.

Nonregulated Other Operation and Maintenance Expenses increased by approximately $37 million, or 23 percent, for the second quarter of 2002, compared with the second quarter of 2001, primarily due to the expansion of NRG’s operations during 2001.

Depreciation and amortization increased by approximately $51 million, or 23 percent, for the second quarter of 2002, compared with the second 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. Approximately 50 percent of the reduction in property taxes will be returned to NSP-Minnesota customers.

Special Charges in 2002 relate to NRG severance costs and NEO charges, as discussed in Note 2. Special charges in 2001 relate to a PSCo regulatory adjustment, also discussed in Note 2.

Interest expense increased by approximately $29 million, or 15.0 percent, for the second quarter of 2002, compared with the second 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.

Income tax expense decreased by approximately $32 million, or 46 percent, for the second quarter of 2002, compared with the second quarter of 2002. The decrease was primarily due to decreases in pretax income. The effective tax rate for continuing operations (excluding minority interest) was 28.2 percent for the second quarter of 2002 and 28.4 percent for the second quarter of 2001.

Discontinued Operations relate to NRG’s assets held for sale as of June 30, 2002, as discussed in Note 3. The losses in 2002 are due to estimated losses on disposal accrued in second quarter when the assets were classified as held for sale.

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 $186 million for the first six months of 2002, compared with the first six months of 2001. The decrease reflects lower power pool prices and other market conditions in 2002.

Electric utility revenues decreased approximately $234 million in the first six months of 2002, compared with the same period in 2001, due largely to lower fuel and power costs passed through rate recovery mechanisms. Electric utility margins increased approximately $69 million for the first six months of 2002, compared with 2001. The higher electric margins in the first six months of 2002 reflect lower unrecovered costs, due in part to resetting the base-cost recovery at PSCo in January 2002. Warmer June temperatures and sales growth also contributed to the higher margins. The increase was partially offset by higher demand costs, lower capacity margins and Minnesota conservation adjustments. Electric utility revenues and margins were both also lower in 2002 due to the 2001 reversal of the disallowed conservation incentive revenues at NSP-Minnesota discussed previously.

Gas revenue decreased by approximately $561 million, or 41.2 percent, in the first six months of 2002, compared with the same period in 2001, 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 increased approximately $2 million for the first six months of 2002, compared with 2001, due largely to a rate increase effective February 2001 at PSCO. Sales volume levels remained relatively unchanged due to the impact of warmer-than-normal weather offsetting customer growth.

Nonregulated revenue and margin increased for the first six months of 2002, largely due to NRG increases from a larger generation portfolio. Despite revenue growth, nonregulated cost of goods sold decreased due to favorable mark-to-market adjustments during the second quarter of 2002 under SFAS No. 133 at NRG.

Earnings from equity investments decreased for the six months of 2002, due to a decrease in equity earnings from NRG projects reflecting lower power pool prices and a more competitive market in areas of NRG operations.

Regulated Other Operation and Maintenance Expenses for the first six months of 2002 decreased by approximately $7 million, or 1.0 percent, compared with the first six months of 2001. The decreased costs reflect lower incentive compensation and other employee benefit costs, partially offset by higher plant outage and property insurance costs.

Nonregulated Other Operation and Maintenance Expenses increased by approximately $71 million, or 21.0 percent, for the first six months of 2002, compared with the first six months of 2001, primarily due to the expansion of NRG’s operations during 2001.

Depreciation and amortization increased by approximately $98 million, or 22.5 percent, for the first six months of 2002, compared with the first six months of 2001, primarily due to acquisitions of generating facilities by NRG and capital additions to NRG-owned generation facilities and utility plant additions.

Interest expense increased by approximately $57 million, or 14.9 percent, for the first six months of 2002, compared with the first six months 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.

Special Charges in 2002 included second quarter NRG items previously discussed and a first quarter restaffing charge, discussed in Note 2. Special Charges in 2001 relate to the second quarter PSCo regulatory adjustment, also discussed in Note 2.

Income tax expense decreased $105 million in 2002 compared with 2001 due to lower pretax income levels. Xcel Energy’s effective tax rate was 31.4 percent for the six months ended June 30, 2002, compared with 30.9 percent for the same period 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 costs under the new standard at that date would have been approximately $132 million. Management expects that the entire transition amount would be recoverable in rates over time 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. Adoption of SFAS No. 145 may affect the recognition of impacts from NRG’s financial improvement plan, if existing debt agreements are ultimately renegotiated. Other impacts of SFAS 145 are not expected to be material to Xcel Energy.

SFAS No. 146 — In July 2002, the FASB issued SFAS No. 146 — “Accounting for Exit or Disposal Activities,” addressing recognition, measurement and reporting of costs associated with exit and disposal activities, including restructuring activities. SFAS 146 may have an impact on the timing of recognition of

costs related to the implementation of the NRG financial improvement and restructuring plan, however such impact is not expected to be material.

EITF No. 02-3 — In June the Emerging Issues Task Force of the FASB (EITF) issued a consensus decision for EITF Issue No. 02-3 “Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issue No. 98-10, ‘Accounting for Contracts Involved in Energy Trading and Risk Management Activities’.” EITF No. 02-3 requires that all gains and losses related to energy trading activities within the scope of EITF No. 98-10 (whether or not settled physically) be shown net in the statement of income. The decision requires reclassification of comparable prior periods reported and is applicable for financial statement periods ending after July 15, 2002. Such energy trading activities recorded as a component of Electric and Gas Trading Costs that will be reclassified to Electric and Gas Trading Revenue in accordance with EITF No. 02-3 were $983 million and $1.1 billion for the six months ended June 30, 2002 and 2001, respectively. This reclassification will have an immaterial impact on trading margins and no impact on reported net income. Xcel Energy’s Utility Subsidiaries will continue to record gains and losses on energy trading contracts in accordance with SFAS No. 133.

Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles (GAAP) requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment also may have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied have not changed. Item 7, Management’s Discussion and Analysis, in Xcel Energy’s Annual Report on Form 10-K includes a list of accounting policies that are most significant to the portrayal of Xcel Energy’s financial condition and results, and that require management’s most difficult, subjective or complex judgments. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions.

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.

The energy market continues to evolve and change as market conditions and participants vary. Xcel Energy and its subsidiaries have responded to the change to the energy trading market environment and believe there has been no material change in its market risk exposures.

Reference is made to Notes 6 and 7 of the Notes to Consolidated Financial Statements for a description of the steps being taken to improve NRG’s financial situation and liquidity issues facing NRG. As explained in Note 7, Xcel Energy estimates that NRG will be required to post collateral ranging from $1.1 billion to $1.3 billion as a result of the recent lowering of NRG’s credit ratings to below investment grade. Of the collateral to be posted, approximately $215 million is required to fund debt service reserve and other guarantees at the project level, $10 million is required to fund trading operations, $75 million is required to fund remaining equity commitments to complete construction of the Brazos Valley plant in Texas; and between $825 million and $975 million is required to fund equity guarantees associated with the $2 billion

construction and acquisition revolver depending on various options being pursued. NRG is working with its lenders to obtain waivers to delay the posting of this collateral. Absent waiver of the collateral requirements, substantially all of the collateral must be posted no later than Aug. 19, 2002.

NRG does not have sufficient resources that enable it to post the required collateral in a timely manner. The failure to post the required collateral will result in defaults unless waivers are obtained. If NRG is unable to obtain waivers or modifications of these collateral requirements and the debt obligations are accelerated, NRG would need to refinance or restructure its obligations and, if unsuccessful in these efforts, to consider all other options including a restructuring under the bankruptcy laws.

In addition to the collateral requirements, NRG must continue to meet its ongoing operational and construction funding requirements. Since NRG’s downgrade, its cost of borrowing and access to the capital markets has deteriorated significantly. As a consequence, NRG is evaluating its options with respect to the continuation and funding of its ongoing construction projects. NRG is also continuously re-evaluating its asset sale program to maximize net proceeds, given current market conditions. NRG believes that its current funding requirements under its already reduced construction program may be unsustainable given the difficulties involved in raising cash through the capital markets and the uncertainties involved in obtaining additional equity funding from Xcel Energy. NRG and Xcel Energy have retained financial advisors to help work through these liquidity issues in an effort to avoid defaults on NRG debt and other obligators. Since only a short amount of time has passed since NRG was downgraded, NRG is unsure as to the resolution of all issues. NRG’s initial priorities are obtaining waivers or delays of its collateral calls and avoiding the acceleration of its debt obligations. Once these collateral issues are resolved and additional decisions relating to asset sales are made, NRG plans to develop a revised business plan.

As part of the process for developing a revised business plan, Zolfo Cooper, LLC (“Zolfo”) has been retained by NRG to assist management in assessing the liquidity of NRG and its subsidiaries and in identifying and implementing strategies to stabilize NRG’s liquidity situation. NRG’s retention of Zolfo is consistent with its goal of working through NRG’s challenging financial situation with the objective of maximizing value for its stakeholders. In that regard, Zolfo will initially be assisting management in developing a detailed short-term cash flow forecast, focusing on receipts and disbursements. The emphasis in that process will be on producing credible figures that can be used to (a) facilitate management decision-making during the restructuring process; and (b) assist in communicating on a regular, scheduled basis with NRG’s lenders as to its ongoing cash position and short-term liquidity expectations and needs. Zolfo will also be responsible for assisting NRG management in reporting actual performance versus that forecast.

Furthermore, in connection with this assignment, NRG has requested that Zolfo provide advice to management regarding potential opportunities for, and the general benefits and risks associated with: (a) reducing NRG’s cost structure; (b) improving liquidity and cash flow in the short, medium and long-term; (c) mitigating the short-term impact on liquidity and cash flow of certain demands and obligations; and (d) liquidating or monetizing certain assets, including contractual relationships that have net present value based on current market prices. One of the specific areas where NRG management has asked for Zolfo’s assistance is in relation to cash collateral requests. In addition to the approximate $1.1 billion to $1.3 billion of collateral requirements under the loan documents described above, cash collateral requests have been made of NRG by various contract counterparties as a result of the ratings downgrade at NRG. In the aggregate, the gross amount of those requests to date have exceeded $200 million. However, not all of the contract counterparties with the contractual right to request cash collateral under the current circumstances have yet make such a request or demand. Zolfo will be working with NRG management to assess the nature and benefit of each such contractual relationship and to identify and evaluate potential strategies for reducing, mitigating or eliminating each cash collateral request. There are no assurances that NRG can be successful in its efforts to mitigate the cash collateral request issue in a manner that preserves sufficient liquidity to operate its businesses effectively.

Other areas where Zolfo has been asked to assist management include, but are not limited to: (a) managing the working capital impact of certain vendors who previously sold product or provided services to NRG on reasonable, market credit terms, but who are now requiring NRG to pay cash in advance for such

product or services; and (b) controlling the general disbursement and commitment process so as to ensure that cash is utilized in a manner that maximizes value for stakeholders.

As explained in Note 10, Xcel Energy had guaranteed at July 31, 2002, approximately $247 million of power market contracts, primarily of the power marketing subsidiary of NRG. Exposure under these guarantees is approximately $90 million.

At the present time and based on conversations with various lenders, Xcel Energy management does not believe that the appropriate course of action for NRG is filing to seek relief under the bankruptcy laws. Rather, it believes that the implementation of its plans for NRG as discussed in Note 6, coupled with waivers from lenders is the correct course of action to restore NRG’s financial strength. In the event that NRG is unable to work through the issues as described above and is unable to obtain adequate financing on terms acceptable to NRG, there would be substantial doubt as to NRG’s ability to continue as a going concern.

Access by Xcel Energy and its significant regulated subsidiaries, NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, to the short-term and long-term debt markets has been adversely affected by the recent downgrades of their respective credit agencies. This has resulted in less favorable terms under existing credit facilities and upon renewal and replacement of prior credit facilities. Both NSP-Minnesota and PSCo are in the process of replacing existing credit facilities. Lenders under these facilities have requested additional security. It is anticipated that the security will be in the form of first mortgage bonds issued by NSP-Minnesota or PSCo, as the case may be. Both NSP-Minnesota and PSCo are in the process of obtaining additional credit facilities to meet short-term liquidity needs and expect to issue long-term debt later this year to further enhance their cash positions.

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

Updated Capital Expenditure Forecast — Xcel Energy has reviewed its construction program and significantly revised its capital expenditure forecast. The new forecast reflects a reduction in capital expenditures of approximately $1.0 billion in 2003 and $1.3 billion in 2004 at NRG and approximately

$200 million per year in 2003 and 2004 for Xcel Energy’s utility operations. The capital expenditure forecast is detailed in the following table ($ in millions).

NRG has an ownership interest in U.S. projects currently under construction, which remain in the capital expenditure forecast and are scheduled for operation before the end of 2004. Any projects with commercial operation dates beyond 2004 are not listed. The projects are as follows:

The capital expenditure forecast assumes NRG maintains 100-percent ownership of all domestic projects. The potential sale of any domestic project would result in further capital reductions. The capital expenditure forecast does not reflect acquisitions of generation assets, including FirstEnergy, or net proceeds from asset sales. The capital expenditure programs of Xcel Energy are subject to continuing review and modification. Actual construction expenditures may vary from the estimates due to changes in market conditions. See discussion of the current status of NRG acquisitions and divestitures at Note 3.

Common Stock Dividends — Dividends since the Xcel Energy merger have been declared each quarter at an annual level of $1.50 per share. Future dividend levels will be dependent upon the evaluation of the Xcel Energy board of directors, considering results of operations, financial position, cash flows and other factors. As part of reaching new credit agreements to remove cross-default provisions in July 2002, Xcel Energy has agreed that its board of directors will review its dividend policy. While the board could decide to alter the dividend from current levels, currently the board has made no decision.

Short-Term Funding Sources — In 2002, Xcel Energy has been experiencing some volatility in its funding sources due largely to the credit issues being faced by NRG, as described in Note 7.

NRG’s operating cash flows have experienced lower operating margins as a result of low power pool prices since mid-2001. Seasonal variations in demand and market volatility in prices are not unusual in the independent power sector, and NRG does normally experience higher margins in peak summer periods and lower margins in non-peak periods. NRG has also incurred significant amounts of debt to finance its acquisitions in the past several years, and the servicing of interest and principal repayments from such financing is largely dependent on domestic project cash flows. With a successful financial improvement plan for NRG (see Note 6), management expects to improve operating cash flow by lowering financing costs (due to reduction in NRG’s debt levels from application of asset sale proceeds) and lowering operating costs (due to cost reductions from combining portions of NRG’s business activities with Xcel Energy’s). However, asset sales may have a partially mitigating effect on operating cash flows as the projects are sold. In addition, the credit contingencies being faced by NRG may limit the ability to distribute project cash flows and use such funds to service NRG corporate debt. (see Note 7).

Short-term borrowings as a source of short-term funding is affected by access to reasonably priced capital markets. This access is dependent in part on credit agency reviews. In the past year, credit ratings for all of Xcel Energy have been adversely affected by NRG’s credit contingencies, despite what management believes

is a reasonable separation of NRG’s operations and credit risk from Xcel Energy’s utility operations and corporate financing activities. As of August 9, 2002, the following represents the credit ratings assigned to various Xcel Energy companies:

Since December 2001, NRG’s access to short-term capital has been limited due to tightening credit standards for the independent power sector as a whole. The downgrade of NRG’s credit ratings below investment grade in July 2002 has resulted in cash collateral requirements as discussed above and in Note 7. In addition, lower credit ratings will increase the relative cost of NRG’s capital financing compared to historical levels.

In June 2002, Xcel Energy’s access to commercial paper markets was reduced due to lowered credit ratings (shown above). Management believes these lower credit ratings for entities other than NRG are unwarranted given the separation of NRG’s operations and credit risk from Xcel Energy’s utility operations and corporate financing activities. However, until the ratings are raised, Xcel Energy and its utility subsidiaries continue to seek sources of financing (both short- and long-term) other than commercial paper. Xcel Energy and its utility subsidiaries used cash or existing credit facilities to repay approximately $723 million of commercial paper in July 2002.

As of July 31, 2002, Xcel Energy and its subsidiaries collectively had access to approximately $1.1 billion of cash (including available capacity under existing credit lines), consisting of: $288 million at Xcel Energy; $279 million at Southwestern Public Service Company; $150 million at Public Service Company of Colorado; $95 million at Northern States Power Company-MN; and $270 million at NRG. Xcel Energy and its subsidiaries intend to continue taking steps to enhance their liquidity position.

NSP-Minnesota recently terminated its $70 million bridge facility listed above and is in the process of replacing this facility.

On Aug. 5, 2002 Xcel Energy signed agreements with its lenders to eliminate cross-default provisions in its bank credit agreements with respect to NRG. Xcel Energy’s bank agreements consist of a 364-day credit facility in the amount of $400 million expiring in November 2002 and a five-year credit facility in the amount of $400 million expiring in November 2005. The revised agreements remove key provisions in Xcel Energy’s credit facilities that would have constrained Xcel Energy’s ability to access capital due to difficulties faced by NRG in complying with the terms of NRG’s credit facilities. The agreements reached with Xcel Energy’s lenders remove the linkage between NRG’s agreements and credit facilities and those at Xcel Energy by removing the cross-default provisions.

On Aug. 14, 2002 NSP-Minnesota obtained a commitment for an amended and restated credit facility that will replace its $300-million, 364-day fully drawn credit facility scheduled to expire Aug. 15, 2002. This credit line will be structured as a senior revolving facility and will be secured by a new series on bonds issued under its First Mortgage Trust Indenture. The new bonds will be secured with all other bonds outstanding under the Trust Agreement. The facility renewal is scheduled to be completed Aug. 15, 2002.

Xcel Energy Registration Statements — In September 2000, Xcel Energy filed a $1 billion shelf registration with the SEC to issue debt securities. Xcel Energy has approximately $400 million remaining available under this registration.

In February 2002, Xcel Energy filed a $1-billion shelf registration with the SEC. Xcel Energy may issue debt securities, common stock and rights to purchase common stock under this shelf registration. Xcel Energy has approximately $482.5 million remaining available under this registration.

In June 2002, Xcel Energy filed a registration statement with the SEC that described the adjusted terms of the outstanding NRG options governed by the 2000 Long-Term Incentive Compensation Plan. Upon the exercise of the NRG options, the holders thereof will receive shares of Xcel Energy common stock, and the associated share purchase rights, applying the an exchange ratio of .5 shares of Xcel Energy common stock for each share of NRG common stock, instead of shares of NRG common stock. See further discussion of the NRG exchange offer in Note 5.

Xcel Energy Common Stock Issuance — In February 2002, Xcel Energy issued 23 million shares of common stock at $22.50 per share. The proceeds were used to fund NRG and to repay short-term debt.

In June 2002, Xcel Energy issued 25.7 million shares of common stock to complete its exchange offer with minority NRG shareholders and acquire 100 percent ownership of NRG (see Note 5).

NSP-MN Debt Issuance — In July 2002, NSP-MN issued $185 million of 8 percent Public Income Notes due in 2042. The proceeds were used to repay short-term indebtedness incurred for general working capital purposes and to meet long-term debt maturity requirements.

NRG Peaker Finance Company LLC — During the second quarter, NRG Peaker Finance Company LLC, an indirect wholly owned subsidiary of NRG, issued $325 million of floating rate senior secured bonds. This issue, rated triple-A by Moody’s Investors Service and Standard & Poor’s Ratings Services and due in 2019, provided net proceeds of $250 million. XL Capital Assurance Inc. (XLCA), rated triple-A by Moody’s Investors Service, Standard & Poor’s Ratings Services and Fitch Ratings, will guarantee scheduled principal and interest payments on the bonds. The XLCA guarantee is secured by five peaker power plants totaling approximately 1,318 megawatts.

NRG Energy Center, Inc. — In July 2002, NRG Energy Center, an indirect wholly owned subsidiary of NRG, entered into an agreement allowing it to issue senior secured promissory notes in the aggregate principal amount of up to $150 million. In July 2002, under this agreement, NRG Energy Center, Inc. issued $75 million of bonds in a private placement. Two series of notes were issued in July 2002, the $55 million Series A-Notes dated July 3, 2002, which matures on Aug. 1, 2017 and bears an interest rate of 7.25 percent per annum. The $20 million Series B-Notes dated July 3, 2002, which matures on Aug. 1, 2017 and bears an interest rate of 7.12 percent per annum. NRG Thermal Corporation, a wholly owned subsidiary of NRG, which owns 100 percent of NRG Energy Center, pledged its interests in all of its district heating and cooling investments throughout the United States as collateral.

See further discussion of NRG credit collateral calls, defaults and debt covenants at Notes 7 and 10.

Financing Plans — The following table details Xcel Energy’s financing plan (in millions of dollars) for debt issuances in August through December 2002, subject to favorable market conditions. The proceeds may be used to replace a portion of the balance outstanding under credit facilities at the respective company with permanent debt.

Xcel Energy may issue additional shares of common stock during 2002. Proceeds would be used for general corporate purposes, to repay short-term debt or to fund Xcel Energy’s subsidiaries, including NRG. Xcel Energy continues to assess its potential financing plans.

In accordance with an SEC order under PUHCA granting Xcel Energy general financing authority, Xcel Energy must maintain its common stockholders’ equity at a level at least equal to 30 percent of total capitalization in order to issue securities or guarantees. Xcel Energy has filed a proposal with the SEC requesting temporary authorization to allow common equity to be 24 percent of total capitalization, based on possible sales of assets by NRG at a loss as discussed in Note 8. Pending SEC action on the proposal, Xcel Energy either will postpone designating assets for sale or cease issuing securities and guarantees when and if its ratio falls below 30 percent.

Short-term debt and financial instruments are discussed in Note 10 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, 7, 8 and 9 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 and Item 1 of Part II of Xcel Energy’s Form 10-Q for the quarter ended March 31, 2002 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.

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

On July 1, 2002, Xcel Energy received a Notice of Violation (NOV) from the United States Environmental Protection Agency (EPA) alleging violations of the New Source Review (NSR) requirements of the Clean Air Act at PSCo’s Comanche and Pawnee Stations in Colorado. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process. Xcel Energy believes it acted in full compliance with the Clean Air Act and NSR process. It believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. Xcel Energy also believes that the projects would be expressly authorized under the EPA’s NSR policy announced by the EPA administrator on June 22, 2002. Xcel Energy disagrees with the assertions contained in the NOV and intends to vigorously defend its position.

Class Action Lawsuit — On July 31, 2002, a lawsuit purporting to be a class action on behalf of purchasers of Xcel Energy common stock between Jan. 31, 2001 and July 26, 2002, was filed in the United States District Court in Minnesota. The complaint named Xcel Energy; Wayne H. Brunetti, chairman, president and chief executive officer; Edward J. McIntyre, vice president and chief financial officer and former chairman, James J. Howard as defendants. Among other things, the complaint alleges violations of Section 10b of the Securities Exchange Act and Rule 10b-5 related to allegedly false and misleading disclosures concerning various issues, including “round trip” energy trades and the existence of cross-default provisions in Xcel Energy’s and its subsidiary, NRG Energy’s, credit agreements with lenders. Since the filing of the lawsuit on July 31, 2002, additional lawsuits have been filed with similar allegations. The defendants deny any liability and maintain they have made disclosures fully compliant with applicable laws and reporting requirements.

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.

Threatened FirstEnergy Litigation — As discussed in Note 4, FirstEnergy terminated the purchase agreements pursuant to which NRG had agreed to purchase four generating stations for approximately $1.6 billion. FirstEnergy’s cited rationale for terminating the agreements was an alleged anticipatory breach by NRG. FirstEnergy notified NRG that it is reserving the right to pursue legal action against NRG and Xcel Energy for damages.

The following reports on Form 8-K were filed either during the three months ended June 30, 2002, or between June 30, 2002, and the date of this report:

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.

May 16, 2002, (filed May 16, 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 31, 2002.

May 22, 2002, (filed May 24, 2002) Item 5 and 7. Other Events and Exhibits. Re: Xcel Energy response to Federal Energy Regulatory Commission general inquiry.

June 3, 2002, (filed June 6, 2002) Item 5 and 7. Other Events and Exhibits. Re: Disclosure of successful completion of the exchange of Xcel Energy shares for publicly held shares of NRG.

June 17, 2002, (filed June 18, 2002) Item 5. Other Events. Re: Connecticut Department of Public Utility Control denial of Connecticut Light and Power rate increase request.

July 1, 2002, (filed July 8, 2002) Item 5. Other Events. Re: Disclosure of Notice of Violation received from the Environmental Protection Agency regarding PSCo generation plants, Comanche and Pawnee Stations.

July 25, 2002, (filed Aug. 1, 2002) Item 5 and 7. Other Events and Exhibits. Re: Xcel Energy and NRG credit rating downgrade and second quarter 2002 earnings release.

July 31, 2002, (filed Aug. 6, 2002) Item 5 and 7. Other Events and Exhibits. Re: Disclosure of Xcel Energy lender renegotiation, class action lawsuit and Xcel Energy liquidity update.

Aug. 12, 2002, (filed Aug. 13, 2002) Item 5 and 7. Other Events and Exhibits. Re: Xcel Energy chief executive officer and chief financial officer SEC certification.

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

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. In addition each of the undersigned hereby certifies in his capacity as an officer of Xcel Energy that the Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 fully complies with the requirements of section 13(a) of the Securities Exchange Act of 1934 and that information contained in such report fairly presents, in all material respects, the financial condition and results of operations of the issuer.


	XCEL ENERGY INC.
	(Registrant)

	/s/ EDWARD J. MCINTYRE

	Edward J. McIntyre
	Vice President and Chief Financial Officer

	/s/ WAYNE H. BRUNETTI

	Wayne H. Brunetti
	Chairman, President and Chief Executive Officer


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 July 31, 2002

Common Stock, $2.50 par value		398,035,892 shares


CONSOLIDATED STATEMENTS OF INCOME
CONSOLIDATED STATEMENTS OF CASH FLOWS
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
PART II. OTHER INFORMATION
SIGNATURES
EX-99.1 Statement pursuant to Private Securites



			Three Months Ended June 30					Six Months Ended June 30

			2002			2001		2002			2001


			(Unaudited)
			(Thousands of Dollars, Except Per Share Data)
Operating revenues:
	Electric utility		$	1,328,898		$	1,643,877	$	2,560,555		$	3,191,389
	Gas utility			235,635			400,405		799,546			1,360,570
	Electric and gas trading			1,039,684			869,425		1,795,096			1,836,316
	Nonregulated and other			795,282			721,975		1,542,564			1,454,428
	Equity earnings from investments in affiliates			28,468			61,672		44,642			84,934

		Total operating revenues		3,427,967			3,697,354		6,742,403			7,927,637
Operating expenses:
	Electric fuel and purchased power — utility			544,405			836,977		1,032,519			1,624,542
	Cost of gas sold and transported — utility			125,617			292,102		501,232			1,064,154
	Electric and gas trading costs			1,040,089			836,960		1,792,751			1,754,324
	Cost of sales — nonregulated and other			417,725			434,297		827,400			838,154
	Other operating and maintenance expenses — utility			343,983			371,572		735,474			742,672
	Other operating and maintenance expenses — nonregulated			197,015			160,351		409,554			338,608
	Depreciation and amortization			272,496			221,075		532,354			434,385
	Taxes (other than income taxes)			84,708			87,753		167,605			182,501
	Special charges (see Note 2)			56,368			23,018		70,481			23,018

		Total operating expenses		3,082,406			3,264,105		6,069,370			7,002,358

Operating income				345,561			433,249		673,033			925,279
Interest income and other nonoperating income — net of other expenses				13,698			10,365		31,763			27,851
Interest charges and financing costs:
	Interest charges — net of amounts capitalized			216,118			186,460		419,403			362,304
	Distributions on redeemable preferred securities of subsidiary trusts			9,472			9,700		19,172			19,400

		Total interest charges and financing costs		225,590			196,160		438,575			381,704

Income from continuing operations before income taxes and minority interest				133,669			247,454		266,221			571,426
Income taxes				37,707			70,156		70,968			176,409
Minority interest				(4,851	)		9,794		(8,730	)		18,446

Income from continuing operations				100,813			167,504		203,983			376,571
Income (loss) from discontinued operations, net of tax				(13,511	)		353		(13,177	)		596

Net income				87,302			167,857		190,806			377,167
Dividend requirements on preferred stock				1,060			1,060		2,120			2,120

Earnings available for common shareholders			$	86,242		$	166,797	$	188,686		$	375,047

Weighted average common shares outstanding (in thousands):
	Basic			377,983			342,553		365,972			341,670
	Diluted			378,129			343,688		366,211			342,591
Earnings per share — basic and diluted
Income from continuing operations			$	0.27		$	0.49	$	0.56		$	1.10
	Discontinued Operations			(0.04	)		—		(0.04	)		—

Earnings per share — basic and diluted			$	0.23		$	0.49	$	0.52		$	1.10



				Six Months Ended June 30

				2002			2001


				(Unaudited)

				(Thousands of Dollars)
Operating activities:
	Net income			$	190,806		$	377,167
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation and amortization			528,758			461,508
		Nuclear fuel amortization			24,586			21,059
		Deferred income taxes			18,650			800
		Amortization of investment tax credits			(6,958	)		(6,482	)
		Allowance for equity funds used during construction			(4,188	)		(5,769	)
		Undistributed equity in earnings of unconsolidated affiliates			(321	)		(73,319	)
		Estimated loss on disposal of discontinued operations			13,842			—
		Investment write-downs			25,103			—
		Gain on sale of property			(6,785	)		—
		Unrealized (gain) loss on derivative financial instruments			(18,531	)		2,432
		Change in accounts receivable			18,597			54,411
		Change in inventories			20,615			(67,511	)
		Change in other current assets			(113,370	)		256,128
		Change in accounts payable			(125,631	)		(567,981	)
		Change in other current liabilities			(2,803	)		47,344
		Change in other assets and liabilities			35,080			29,670

			Net cash provided by operating activities		597,450			529,457
Investing activities:
	Nonregulated capital expenditures and asset acquisitions				(883,125	)		(2,831,627	)
	Utility capital/construction expenditures				(451,674	)		(452,775	)
	Proceeds from sale of property				11,152			—
	Allowance for equity funds used during construction				4,188			5,769
	Investments in external decommissioning fund				(29,383	)		(28,446	)
	Equity investments, loans, deposits and sales of nonregulated projects				(286,251	)		290,319
	Collection of loans made to nonregulated projects				13,540			3,750
	Other investments — net				(10,941	)		3,844

			Net cash used in investing activities		(1,632,494	)		(3,009,166	)
Financing activities:
	Short-term borrowings — net				296,776			786,576
	Proceeds from issuance of long-term debt				1,054,201			1,888,167
	Repayment of long-term debt, including reacquisition premiums				(449,880	)		(361,042	)
	Proceeds from issuance of common stock				558,191			83,638
	Proceeds from NRG stock offering				—			474,348
	Dividends paid				(270,630	)		(258,389	)

			Net cash provided by financing activities		1,188,658			2,613,298
Effect of exchange rates on cash and cash equivalents					688			(3,457	)
Net increase in cash and cash equivalents					154,302			130,132
Cash and cash equivalents at beginning of year					341,310			216,491

Cash and cash equivalents at end of period				$	495,612		$	346,623


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


			June 30,			Dec. 31,
			2002			2001


			(Unaudited)
			(Thousands of Dollars)
ASSETS
Current assets:
	Cash and cash equivalents		$	495,612		$	341,310
	Restricted cash			233,135			161,842
	Accounts receivable — net of allowance for bad debts of $53,097 and $57,815, respectively			1,135,109			1,174,828
	Accrued unbilled revenues			448,840			495,994
	Materials and supplies inventories — at average cost			337,980			330,363
	Fuel inventory — at average cost			240,938			250,043
	Gas inventories — replacement cost in excess of (below) LIFO: $(33,069) and $11,331, respectively			108,977			126,563
	Recoverable purchased gas and electric energy costs			117,781			52,583
	Derivative instruments valuation — at market			72,479			59,790
	Prepayments and other			366,323			318,046
	Current assets held for sale			14,325			—

		Total current assets		3,571,499			3,311,362

Property, plant and equipment, at cost:
	Electric utility plant			16,276,543			16,099,655
	Nonregulated property and other			9,576,653			8,388,261
	Gas utility plant			2,523,445			2,493,028
	Construction work in progress (utility amounts of $807,266 and $669,895, respectively)			3,607,017			3,682,633

		Total property, plant and equipment		31,983,658			30,663,577
	Less: accumulated depreciation			(10,042,067	)		(9,594,775	)
	Nuclear fuel — net of accumulated amortization of $1,034,441 and $1,009,855, respectively			69,428			96,315

		Net property, plant and equipment		22,011,019			21,165,117

Other assets:
	Investments in unconsolidated affiliates			1,309,326			1,209,017
	Notes receivable, including amounts from affiliates of $220,745 and $202,411, respectively			998,235			779,186
	Nuclear decommissioning fund and other investments			707,960			695,070
	Regulatory assets			501,760			502,442
	Derivative instruments valuation — at market			227,791			179,683
	Prepaid pension asset			457,485			378,825
	Goodwill — net (See Note 1)			108,020			63,925
	Intangible assets — net (See Note 1)			73,680			77,276
	Other			408,339			373,159
	Noncurrent assets held for sale			29,822			—

		Total other assets		4,822,418			4,258,583

		Total assets	$	30,404,936		$	28,735,062


LIABILITIES AND EQUITY
Current liabilities:
	Current portion of long-term debt		$	890,419		$	682,207
	Short-term debt			2,512,412			2,224,812
	NRG long-term obligations potentially callable (See Note 7)			4,394,440			—
	Accounts payable			1,257,032			1,378,211
	Taxes accrued			247,566			246,152
	Dividends payable			150,040			130,845
	Derivative instruments valuation — at market			46,317			83,122
	Other			676,398			704,679
	Current liabilities held for sale			2,765			—

		Total current liabilities		10,177,389			5,450,028

Deferred credits and other liabilities:
	Deferred income taxes			2,283,631			2,289,550
	Deferred investment tax credits			176,919			184,148
	Regulatory liabilities			504,339			483,942
	Derivative instruments valuation — at market			69,923			57,575
	Benefit obligations and other			784,665			703,836
	Noncurrent liabilities held for sale			22,438			—

		Total deferred credits and other liabilities		3,841,915			3,719,051

Minority interest in subsidiaries				77,628			654,670
Capitalization:
	Long-term debt			8,336,398			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, 396,940,044; 2001, 345,801,028			7,372,286			6,194,477

Commitments and Contingent Liabilities (see Note 9)
		Total Liabilities and Equity	$	30,404,936		$	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 June 30, 2002 and 2001
Balance at March 31, 2001		$	856,055	$	2,885,312	$	2,363,972		$	(22,921	)	$	(224,711	)	$	5,857,707

Net income							167,857									167,857
Currency translation adjustments													41,171			41,171
Net gains or (losses) on derivatives (see Note 11)													42,540			42,540

Comprehensive income for the period																251,568
Dividends declared:
	Cumulative preferred stock of Xcel Energy						(1,060	)								(1,060	)
	Common stock						(129,041	)								(129,041	)
Issuances of common stock — net			4,156		39,117											43,273
Other							(1	)								(1	)
Repayment of ESOP loan(a)										1,419						1,419

Balance at June 30, 2001		$	860,211	$	2,924,429	$	2,401,727		$	(21,502	)	$	(141,000	)	$	6,023,865

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

Net income							87,302									87,302
Currency translation adjustments													73,163			73,163
After-tax net unrealized losses related to derivatives accounted for as hedges (see Note 11)													(10,284	)		(10,284	)
After-tax net unrealized losses on derivative transactions reclassified into earnings (see Note 11)													5,345			5,345
Unrealized gain-marketable securities													2			2

Comprehensive income for the period																155,528
Dividends declared:
	Cumulative preferred stock of Xcel Energy						(1,060	)								(1,060	)
	Common stock						(148,954	)								(148,954	)
Issuances of common stock — net			2,465		21,162											23,627
Acquisition of NRG minority common shares			64,412		555,222								28,150			647,784
Other							(10	)								(10	)
Repayment of ESOP loan(a)										205						205

Balance at June 30, 2002		$	992,186	$	4,019,732	$	2,459,374		$	(16,881	)	$	(82,125	)	$	7,372,286



		June 30, 2002				Dec. 31, 2001

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


		(Millions of dollars)
Not Amortized:
	Goodwill	$	117.6	$	9.6	$	74.7	$	10.8
Amortized:
	Service contracts	$	89.8	$	22.2	$	90.9	$	19.8
	Trademarks	$	5.1	$	0.5	$	5.0	$	0.4
	Other (primarily franchises)	$	1.9	$	0.4	$	1.9	$	0.3



	Three Months Ended				Six Months Ended

	June 30, 2002		June 30, 2001		June 30, 2002		June 30, 2001


	(Millions of dollars)
Reported net income	$	87.3	$	167.9	$	190.8	$	377.2
Add back: Goodwill amortization (after tax)		—		0.7		—		1.5

Adjusted net income	$	87.3	$	168.6	$	190.8	$	378.7

Diluted earnings per share	$	0.23	$	0.49	$	0.52	$	1.11


		Dec. 31, 2001		Accrued					June 30, 2002
		Liability		Special Charges		Payments			Liability

Utility and corporate employee severance*		$	37	$	9	$	(21	)	$	25
NRG employee severance**			—		18		—		$	18

	Total accrued special charges	$	37	$	27	$	(21	)	$	43


*	Reported on the balance sheet in other current liabilities.


		July-Dec. 2002		2003 Forecasted		2004 Forecasted
		Forecasted		Capital		Capital
		Expenditures		Expenditures		Expenditures
Project		(in millions)		(in millions)		(in millions)		Status

Bayou Cove		$	15					3 of 4 Units Complete
Brazos Valley		$	48	$	32			In Construction
Itiquira		$	26					In Construction
Flinders		$	24					In Construction
Nelson		$	132	$	154			In Construction
Pike		$	76					Assumed Sold
Rockford II		$	11					Substantially Completed
Meriden		$	50	$	36	$	35	Suspended
Kendall		$	35					Substantially Completed
Other Construction and Turbine Expenditures		$	127	$	143	$	85

	Total	$	544	$	365	$	120



	Six months ended
	June 30

	2002		2001


	(Millions of dollars)
Balance at Jan. 1	$	34.2	$	—
Net unrealized transition loss at adoption, Jan. 1, 2001		—		(28.8	)
After-tax net unrealized gains related to derivatives accounted for as hedges		14.9		46.3
After-tax net realized losses on derivative transactions reclassified into earnings		5.8		19.9
Acquisition of NRG minority interest		27.4		—

Accumulated other comprehensive income related to SFAS
No. 133	$	82.3	$	37.4


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


		(Thousands of dollars)
Three months ended June 30, 2002
Operating revenues from external customers		$	1,822,653	$	235,311	$	716,372		$	545,687	$	78,910		—		$	3,398,933
Intersegment revenues			242		324		—			20,564		24,097		(44,661	)		566
Equity in earnings of unconsolidated affiliates			—		—		27,306			215		947		—			28,468

	Total revenues	$	1,822,895	$	235,635	$	743,678		$	566,466	$	103,954	$	(44,661	)	$	3,427,967

Segment net income (loss)		$	106,364	$	17,979	$	(41,352	)	$	137	$	12,725	$	(8,551	)	$	87,302


	*NRG Acquisitions and Divestitures*


	*Other Developments*


	*Colorado*


	*Texas*



	Three months ended:					Six months ended:

Earnings per share (EPS)	June 30, 2002			June 30, 2001		June 30, 2002			June 30, 2001

Regulated EPS	$	0.35		$	0.43	$	0.73		$	0.99
Nonregulated EPS		(0.12	)		0.06		(0.21	)		0.11

Total Xcel Energy EPS	$	0.23		$	0.49	$	0.52		$	1.10



	Earnings per Share Increase (Decrease)

Earnings per Share for the Period Ended June 30:	2002 vs. Normal		2001 vs. Normal		2002 vs. 2001

Quarter Ended	$	0.03	$	0.00	$	0.03
Six Months Ended	$	0.02	$	0.02	$	0.00



			Three months ended:						Six months ended:

Earning per share (EPS)			June 30, 2002			June 30, 2001			June 30, 2002			June 30, 2001

NRG Energy, Inc.:
	Ongoing operations		$	0.05		$	0.11		$	(0.01	)	$	0.19
	Special Charges			(0.10	)		0.00			(0.10	)		0.00
	Discontinued operations			(0.04	)		0.00			(0.04	)		0.00

		Total NRG Energy, Inc.		(0.09	)		0.11			(0.15	)		0.19
Xcel International, including Yorkshire Power				0.00			(0.01	)		0.00			(0.01	)
Eloigne Company				0.01			0.01			0.02			0.02
Seren Innovations Inc.				(0.02	)		(0.02	)		(0.04	)		(0.04	)
e prime				0.00			0.02			0.00			0.02
Planergy International				0.00			(0.02	)		(0.01	)		(0.02	)
Financing costs and preferred dividends				(0.03	)		(0.02	)		(0.05	)		(0.06	)
Other				0.01			(0.01	)		0.02			0.01

		Total nonregulated and holding company EPS	$	(0.12	)	$	0.06		$	(0.21	)	$	0.11


Quarter Ended June 30:		2002			2001			Change


		(Thousands of dollars)
North America (generation)		$	9,170		$	69,552		$	(60,382	)
Europe			10,519			8,769			1,750
Asia Pacific			799			2,311			(1,512	)
Latin America			2,065			702			1,363
North America (other)			9,867			13,608			(3,741	)
Interest and other expense			(39,449	)		(29,904	)		(9,545	)
SFAS No. 133			17,303			(16,277	)		33,580

	Income from ongoing operations		10,274			48,761			(38,487	)
Special charges — net of tax			(38,115	)		—			(38,115	)
Discontinued operations — net of tax			(13,511	)		353			(13,864	)

	Net income (loss)	$	(41,352	)	$	49,114		$	(90,466	)


Six Months Ended June 30:		2002			2001			Change


		(Thousands of dollars)
North America (generation)		$	4,222		$	105,482		$	(101,260	)
Europe			28,564			16,529			12,035
Asia Pacific			6,171			11,941			(5,770	)
Latin America			2,535			1,737			798
North America (other)			16,065			19,021			(2,956	)
Interest and other expense			(91,871	)		(67,137	)		(24,734	)
SFAS No. 133			17,943			(3,493	)		21,436

	Income from ongoing operations		(16,371	)		84,080			(100,451	)
Special charges			(38,115	)		—			(38,115	)
Discontinued operations — net of tax			(13,329	)		212			(13,541	)

	Net income (loss)	$	(67,815	)	$	84,292		$	(152,107	)


	*Income Statement Analysis — Second Quarter 2002 vs. Second Quarter 2001*



	Three months ended:

	6/30/02			6/30/01


	(Millions of dollars)
Nonregulated and other revenue	$	795		$	722
Earnings from equity investments		28			62
Nonregulated cost of goods sold		(418	)		(434	)

Nonregulated margin	$	405		$	350


	*Income Statement Analysis — First Six Months of 2002 vs. First Six Months of 2001*


	2002		2003		2004

Total utility	$	1,017	$	922	$	930
NRG		1,436		548		257
Other nonregulated		66		27		30

Total capital expenditures	$	2,519	$	1,497	$	1,217


Name	Location	Megawatt capacity		Expected operation dates

Bayou Cove	Jennings, LA		320		October 2002
Brazos Valley	Thompsons, TX		633		June 2003
Meriden	Meriden, CT		540		April 2004
Nelson	Nelson Township, IL		1,168		September 2003
Pike	Holmesville, MS		1,192		December 2003


Company	Amount

PSCo	$	400-$600
Xcel Energy Holding Company	$	300-$400
NSP-Minnesota	$	300-$450


99.01		Statement pursuant to Private Securities Litigation Reform Act.
99.02		$400 Million Five-Year Credit Agreement dated Nov. 10, 2000, as amended. (Incorporated by reference to Xcel Energy’s Current Report on Form 8-K, dated July 31, 2002.)
99.03		$400 Million 364-Day Credit Agreement dated Nov. 10, 2000, as amended. (Incorporated by reference to Xcel Energy’s Current Report on Form 8-K, dated July 31, 2002.)