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  As Of               Filer                 Filing     As/For/On Docs:Pgs              Issuer               Agent

 3/31/03  Xcel Energy Inc                   10-K       12/31/02   11:381                                    Bowne of Dallas I..01/FA

Document/Exhibit                   Description                      Pages   Size 

 1: 10-K        Annual Report                                       HTML  2,063K 
 2: EX-4.125    EX-4.125 Registration Rights Agreement                19    100K 
 3: EX-4.136    EX-4.136 Redemption Agreement                          9     50K 
 4: EX-4.137    EX-4.137 7.5 Percent Convertible Senior Notes         69    365K 
 5: EX-12.01    EX-12.01 Computation of Ratio of Earnings           HTML     22K 
 6: EX-21.01    EX-21.01 Subsidiaries of Xcel Energy Inc.           HTML     21K 
 7: EX-23.01    EX-23.01 Consent of Independent Accountants         HTML     12K 
 8: EX-23.02    EX-23.02 Consent of Independent Accountants         HTML     11K 
 9: EX-99.01    EX-99.01 Statement Pursuant to Private Securities   HTML     18K 
10: EX-99.02    EX-99.02 Description of Business of Nrg Energy Inc  HTML    131K 
11: EX-99.04    EX-99.04 Certification Pusuant to 18 Usc Sec. 1350  HTML     10K 

Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

Commission File Number 1-3034

Xcel Energy Inc.

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

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

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

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

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

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

As of June 28, 2002, the aggregate market value of the voting common stock held by non-affiliates of the Registrant was $6,649,735,234 and there were 396,940,044 shares of common stock outstanding.

As of March 15, 2003, there were 398,714,039 shares of common stock outstanding, $2.50 par value.

DOCUMENTS INCORPORATED BY REFERENCE

The Registrant’s Definitive Proxy Statement for its 2003 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

Table of Contents

Index

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Item 1. Business

COMPANY OVERVIEW

On Aug. 18, 2000, New Century Energies, Inc. (NCE) and Northern States Power Co. (NSP) merged and formed Xcel Energy Inc. (Xcel Energy). Xcel Energy, a Minnesota corporation, is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). As part of the merger, NSP transferred its existing utility operations that were being conducted directly by NSP at the parent company level to a newly formed subsidiary of Xcel Energy named Northern States Power Co. Each share of NCE common stock was exchanged for 1.55 shares of Xcel Energy common stock. NSP shares became Xcel Energy shares on a one-for-one basis. As a stock-for-stock exchange for shareholders of both companies, the merger was accounted for as a pooling-of-interests and, accordingly, amounts reported for periods prior to the merger have been restated for comparability with post-merger results.

Xcel Energy directly owns six utility subsidiaries that serve electric and natural gas customers in 12 states. These six utility subsidiaries are Northern States Power Co., a Minnesota corporation (NSP-Minnesota); Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin); Public Service Co. of Colorado, a Colorado corporation (PSCo); Southwestern Public Service Co., a New Mexico corporation (SPS); Black Mountain Gas Co., a Minnesota corporation (BMG), which has been sold pending regulatory approval; and Cheyenne Light, Fuel and Power Co., a Wyoming corporation (Cheyenne). Their service territories include portions of Arizona, Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas, Wisconsin and Wyoming. During 2002, Xcel Energy’s regulated businesses also included Viking Gas Transmission Co. (Viking) and its one-third interest in Guardian Pipeline, which was sold on Jan. 17, 2003, and WestGas InterState, Inc. (WGI), all interstate natural gas pipeline companies.

Xcel Energy also owns or has an interest in a number of nonregulated businesses, the largest of which is NRG Energy, Inc., a Delaware corporation (NRG), an independent power producer. Xcel Energy owned 100 percent of NRG at the beginning of 2000. About 18 percent of NRG was sold to the public in an Initial Public Offering in the second quarter of 2000, leaving Xcel Energy with an 82-percent interest at Dec. 31, 2000. In March 2001, another 8 percent of NRG was sold to the public, leaving Xcel Energy with an interest of about 74 percent at Dec. 31, 2001. On June 3, 2002, Xcel Energy acquired the 26 percent of NRG held by the public so that it again held 100 percent ownership at Dec. 31, 2002. NRG is facing extreme financial difficulties and, among other things, has missed numerous scheduled payments of principal and interest on its outstanding bank loans and bonds. NRG may seek, in the near future, protection under the bankruptcy laws. See Notes 2, 3, 4 and 7 to the Financial Statements. Xcel Energy recently reached a tentative agreement with various NRG creditors that, if implemented, would require Xcel Energy to pay NRG up to $752 million. See Nonregulated Subsidiaries under Item 1 for a further discussion of this matter.

In addition to NRG, Xcel Energy’s nonregulated subsidiaries include Utility Engineering Corp. (engineering, construction and design), Seren Innovations, Inc. (broadband telecommunications services), e prime inc. (natural gas marketing and trading), Planergy International, Inc. (enterprise energy management solutions), Eloigne Co. (investments in rental housing projects that qualify for low-income housing tax credits) and Xcel Energy International Inc. (an international independent power producer).

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

For information on the nonregulated subsidiaries of Xcel Energy, see Nonregulated Subsidiaries under Item 1. For information regarding Xcel Energy’s segments and foreign revenues, see Note 21 to the Consolidated Financial Statements.

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

Regulated Subsidiaries

NSP-Minnesota

NSP-Minnesota was incorporated in 2000 under the laws of Minnesota. NSP-Minnesota is an operating utility engaged in the generation, transmission and distribution of electricity and the transportation, storage and distribution of natural gas. NSP-Minnesota provides generation, transmission and distribution of electricity in Minnesota, North Dakota and South Dakota. NSP-Minnesota also purchases, distributes and sells natural gas to retail customers and transports customer-owned gas in Minnesota, North Dakota and South Dakota. NSP-Minnesota provides retail electric utility service to approximately 1.3 million customers and gas utility service to approximately 430,000 customers.

NSP-Minnesota owns the following direct subsidiaries: United Power and Land Co., which holds real estate; NSP Nuclear Corp., which holds NSP-Minnesota’s interest in the Nuclear Management Co.; and NSP Financing I, a consolidated special purpose financing trust.

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NSP-Wisconsin

NSP-Wisconsin was incorporated in 1901 under the laws of Wisconsin. NSP-Wisconsin is an operating utility engaged in the generation, transmission and distribution of electricity to approximately 230,000 retail customers in northwestern Wisconsin and in the western portion of the Upper Peninsula of Michigan. NSP-Wisconsin is also engaged in the distribution and sale of natural gas in the same service territory to approximately 90,000 customers.

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

PSCo

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

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

SPS

SPS was incorporated in 1921 under the laws of New Mexico. SPS is an operating utility engaged primarily in the generation, transmission, distribution and sale of electricity, which serves approximately 390,000 electric customers in portions of Texas, New Mexico, Oklahoma and Kansas. The wholesale customers served by SPS comprise approximately 36 percent of the total kilowatt-hour sales.

SPS owns a direct subsidiary, SPS Capital I, which is a consolidated special purpose financing trust.

Other Regulated Subsidiaries

Cheyenne was incorporated in 1900 under the laws of Wyoming. Cheyenne is an operating utility engaged in the purchase, transmission, distribution and sale of electricity and natural gas, primarily serving approximately 37,000 electric customers and 30,000 natural gas customers in and around Cheyenne, Wyo.

BMG was incorporated in 1999 under the laws of Minnesota. BMG is a natural gas and propane distribution company, located in Cave Creek, Ariz., with approximately 9,300 customers. We have entered into an agreement to sell BMG. The sale is subject to the receipt of several regulatory approvals.

Viking Gas is an interstate natural gas pipeline serving portions of Minnesota, Wisconsin and North Dakota. Viking operated exclusively as a transporter of natural gas for third-party shippers under authority granted by the Federal Energy Regulatory Commission (FERC). On Jan. 17, 2003, Xcel Energy completed the sale of its interest in Viking, including its ownership interest in Guardian Pipeline, LLC (Guardian).

WGI was incorporated in 1990 under the laws of Colorado. WGI is a natural gas transmission company engaged in transporting natural gas from Chalk Bluffs, Colo., to Cheyenne, Wyo.

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UTILITY REGULATION

Ratemaking Principles

The Xcel Energy system is subject to the regulatory oversight of the Securities and Exchange Commission (SEC) under PUHCA. The rules and regulations under PUHCA generally limit the operations of a registered holding company to a single integrated public utility system, plus additional energy-related businesses. PUHCA rules require that transactions between affiliated companies in a registered holding company system be performed at cost, with limited exceptions. See additional discussion of PUHCA requirements under Factors Affecting Results of Operations and Liquidity and Capital Resources in Management’s Discussion and Analysis under Item 7.

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

Xcel Energy is unable to predict the impact on its operating results from the future regulatory activities of any of these agencies. Xcel Energy's utility subsidiaries are responsible for compliance with all rules and regulations issued by the various agencies.

NSP-Minnesota

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

The Minnesota Environmental Quality Board (MEQB) is empowered to select and designate sites for new power plants with a capacity of 50 megawatts or more and wind energy conversion plants with a capacity of five megawatts or more. It also designates routes for electric transmission lines with a capacity of 100 kilovolts or more. No power plant or transmission line may be constructed in Minnesota except on a site or route designated by the MEQB.

NSP-Wisconsin

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

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

PSCo

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

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SPS

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

Cheyenne

Cheyenne is subject to the jurisdiction of the Wyoming Public Service Commission (WPSC) with respect to its facilities, rates, accounts, services and issuance of securities.

Other

Viking and WGI are subject to FERC jurisdiction and each holds a FERC certificate, which allows them to transport natural gas in interstate commerce pursuant to the provisions of the Natural Gas Act. BMG is subject to the regulation of the Arizona Corporation Commission (ACC).

Fuel, Purchased Gas and Resource Adjustment Clauses

NSP-Minnesota

NSP-Minnesota’s retail electric rate schedules provide for monthly adjustments to billings and revenues for current changes in the cost of fuel and purchased energy compared with the latest costs included in rates. NSP-Minnesota is permitted to recover the cost of financial instruments associated with fuel and purchased energy through a fuel clause adjustment. Changes in capacity charges are not recovered through the fuel clause. NSP-Minnesota’s electric wholesale customers do not have a fuel clause provision in their contracts. Instead, the contracts have an escalation factor.

Retail gas rate schedules for NSP-Minnesota include a purchased gas adjustment (PGA) clause that provides for rate adjustments for changes in the current unit cost of purchased gas compared with the latest costs included in rates. The PGA factors in Minnesota are calculated for the current month based on the estimated purchased gas costs for that month. The MPUC has the authority to disallow certain costs if it finds the utility was not prudent in its procurement activities.

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

NSP-Wisconsin

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

NSP-Wisconsin has a monthly gas cost recovery mechanism in Wisconsin to recover the actual cost of natural gas.

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

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PSCo

PSCo currently has seven retail adjustment clauses that recover fuel, purchased energy and resource costs: the incentive-cost adjustment (ICA), the interim adjustment clause (IAC), the air-quality improvement rider (AQIR), the demand-side management cost adjustment (DSMCA), the qualifying facilities capacity cost adjustment (QFCCA), the gas cost adjustment (GCA) and the steam cost adjustment (SCA). These adjustment clauses allow certain costs to be recovered from retail customers. PSCo is required to file applications with the CPUC for approval in advance of the proposed effective dates.

The ICA allows for an equal sharing between retail electric customers and shareholders of certain fuel and purchased energy cost changes for such costs prior to Jan. 1, 2003. The IAC recovers fuel and energy costs incurred during 2003 until the conclusion of the 2002 general rate case, at which time the fuel and purchased energy cost recovery from Jan. 1, 2003, onward shall be recalculated in accordance with the mechanism approved by the CPUC in the 2002 general rate case. The AQIR recovers over a 15-year period the incremental cost (including fuel and purchased energy) incurred by PSCo as a result of voluntary investments to reduce emissions and improve air quality in the Denver metro area. The DSMCA clause currently permits PSCo to recover DSM costs over five years while non-labor incremental expenses and carrying costs associated with deferred DSM costs are recovered on an annual basis. PSCo also has implemented a low-income energy assistance program. The costs of this energy conservation and weatherization program for low-income customers are recovered through the DSMCA. The QFCCA provides for recovery of purchased capacity costs from certain qualified facilities not otherwise reflected in base electric rates. The QFCCA will expire at the conclusion of the 2002 general rate case. Through its GCA, PSCo is allowed to recover its actual costs of purchased gas. The GCA rate is revised at least annually to coincide with changes in purchased gas costs. Purchased gas costs and revenues received to recover gas costs are compared on a monthly basis and differences are deferred. In 2002, PSCo requested to modify the GCA to allow for monthly changes in gas rates. A final decision on this proceeding is expected in 2003. PSCo, through its SCA, is allowed to recover the difference between its actual cost of fuel and the amount of these costs recovered under its base steam service rates. The SCA rate is revised annually to coincide with changes in fuel costs.

SPS

Fuel and purchased power costs are recoverable in Texas through a fixed fuel factor, which is part of SPS’ retail electric rates. If it appears that SPS will materially over-recover or under-recover these costs, the factor may be revised upon application by SPS or action by the PUCT. The rule requires refunding and surcharging over- or under-recovery amounts, including interest, when they exceed 4 percent of the utility’s annual fuel and purchased power costs, as allowed by the PUCT, if this condition is expected to continue. PUCT regulations require periodic examination of SPS fuel and purchased power costs, the efficiency of the use of such fuel and purchased power, fuel acquisition and management policies and purchase power commitments. Under the PUCT’s regulations, SPS is required to file an application for the PUCT to retrospectively review at least every three years the operations of SPS’ electric generation and fuel management activities.

The NMPRC regulations provide for a fuel and purchased power cost adjustment clause for SPS’ New Mexico retail jurisdiction. SPS files monthly and annual reports of its fuel and purchased power costs with the NMPRC, which include the current over/under fuel collection calculation, plus interest. In January 2002, the NMPRC authorized SPS to implement a monthly adjustment factor on an interim basis beginning with the February 2002 billing cycle.

Cheyenne

All electric demand and purchased power costs are recoverable through an energy adjustment clause. All purchased gas costs are recoverable through a gas cost adjustment clause. Differences in costs incurred from costs recovered in rates are deferred and recovered through prospective adjustments to rates. However, rate changes for cost recovery require WPSC approval before going into effect. Historically, customers have been provided carrying costs on over-collected costs, but Cheyenne has not been allowed to collect carrying charges for under-recovered costs.

Other Regulatory Mechanisms and Requirements

NSP-Minnesota

In December 2000, the NDPSC approved Xcel Energy’s “PLUS” performance-based regulation proposal for its electric operations in the state. The plan established operating and service performance standards in the areas of system reliability, customer satisfaction, price and worker safety. NSP — Minnesota’s performance determines the range of allowed return on equity

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for its North Dakota electric operations. The plan will generate refunds or surcharges when earnings fall outside of the allowed return on equity range. The PLUS plan will remain in effect through 2005.

PSCo

The CPUC established an electric performance-based regulatory plan (PBRP) under which PSCo operates. See further discussion under Item 7, Management’s Discussion and Analysis.

SPS

Prior to June 2001, SPS operated under an earnings test in Texas, which required excess earnings to be returned to the customers. In May 2000, SPS filed its 1999 earnings report with the PUCT, indicating no excess earnings. In September 2000, the PUCT staff and the Office of Public Utility Counsel filed with the PUCT a notice of disagreement, indicating adjustments to SPS calculations, which would result in excess earnings. During 2000, SPS recorded an estimated obligation of approximately $11.4 million for 1999 and 2000. In February 2001, the PUCT ruled on the disputed issues in the 1999 report and found that SPS had excess earnings of $11.7 million. This decision was appealed by SPS to the District Court. On Dec. 11, 2001, SPS entered into an overall settlement of all earnings issues for 1999 through 2001, which reduced the excess earnings for 1999 to $7.3 million and found that there were no excess earnings for 2000 or through June 2001. The settlement also provided that the remaining excess earnings for 1999 could be used to offset approved transition costs that SPS was seeking to recover. The PUCT approved the overall settlement on Jan. 10, 2002.

Pending Regulatory Matters

Xcel Energy

FERC Investigation Against All Wholesale Electric Sellers — 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 PSCo 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 was in response to memoranda prepared by Enron Corp. that detailed certain trading strategies engaged in during 2000 and 2001 that may have violated market rules. On May 22, 2002, Xcel Energy and NRG reported to the FERC that they had not engaged directly in any of the trading strategies or activities outlined in the May 8, 2002, request.

However, Xcel Energy in that submission reported that at times during 2000 and 2001, PSCo did sell energy to another energy company that may then have resold the electricity for delivery into California as part of an overstated electricity load in schedules submitted to the California Independent System Operator. During that period, the regulated operations of PSCo made sales to the other electricity provider of approximately 8,000 megawatt-hours in the California intra-day market, which resulted in revenues to Xcel Energy of approximately $1.5 million. Xcel Energy cannot determine from its records what part of such sales was associated with such possible over-schedules. Subsequently, in the California Refund Proceeding, as discussed later, PSCo informed the FERC that evidence that was adduced by certain California litigants appears to indicate that the PSCo trader involved in these transactions did not believe that they involved overstated schedules, and that Xcel Energy accordingly may have over reported transactions in that submission.

To supplement the May 8, 2002, 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 PSCo had not engaged in so-called “round trip” electricity trading as identified in the May 21, 2002, inquiry.

On May 13, 2002, Xcel Energy reported 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. In this transaction, PSCo agreed to buy from Reliant 15,000 megawatts per hour, during the off-peak hours of the months of November and December 1999. Collectively, these sales with Reliant consisted of approximately 10 million megawatt hours in 1999 and 1.8 million megawatt hours in 2000 and represented approximately 55 percent of PSCo's trading volumes for 1999 and approximately 15 percent of PSCo's trading volumes in 2000. The purpose of the non-profit transaction was in consideration of future for-profit transactions, such as those discussed above. PSCo engaged in these transactions, such as those discussed above with Reliant for the proper commercial objective of making a profit. It did not enter into these transactions to inflate volumes or revenues, and at the time the transactions occurred, the transactions were reported net in our financial statements.

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On March 26, 2003, the FERC at its open meeting discussed this investigation and stated its intent to issue show cause orders to thirty identified market participants, requesting that these entities explain why their conduct did not constitute impermissible gaming under applicable tariffs and why they should not have to disgorge unjust profits or be subjected to other remedies. PSCo was not identified as one of these market participants. However, it was indicated that NRG would be asked to show cause why its prices from May to October, 2000, did not constitute economic withholding and inflated bidding and why it should not be required to disgorge unjust profits or be subjected to other remedies.

Section 206 Investigation Against All Wholesale Electric Sellers — In November 2001, the FERC issued an order under Section 206 of the Federal Power Act initiating a “generic” investigation proceeding against all jurisdictional electric suppliers making sales in interstate commerce at market-based rates. NSP-Minnesota, PSCo, SPS and certain NRG affiliates previously received FERC authorization to make wholesale sales at market-based rates, and have been engaged in such sales subject to rates on file at the FERC. The order proposed that all wholesale electric sales at market-based rates conducted starting 60 days after publication of the FERC order in the Federal Register would be subject to refund conditioned on factors determined by the FERC.

In December 2001, the FERC issued a supplemental order delaying the effective date of the subject to refund condition, but subject to further investigation and proceedings. Numerous parties filed comments in January 2002, and reply comments were filed in February of that year. Further, the FERC staff convened a conference in this proceeding in February 2002. The FERC has not yet acted on the matter.

California Refund Proceeding — A number of parties purchasing energy in markets operated by the California Independent System Operator (California ISO) or the California Power Exchange (PX) have asserted prices paid for such energy were unjust and unreasonable and that refunds should be made in connection with sales in those markets for the period Oct. 2, 2000 through June 20, 2001. PSCo and NRG supplied energy to these markets during the referenced period and have been an active participant in the proceedings. The FERC ordered an investigation into the California ISO and PX spot markets and concluded that the electric market structure and market rules for wholesale sales of energy in California were flawed and have caused unjust and unreasonable rates for short-term energy under certain conditions. The FERC ordered modifications to the market structure and rules in California and established an administrative law judge (ALJ) to make findings with respect to, among other things, the amount of refunds owed by each supplier based on the difference between what was charged and what would have been charged in a more functional market, i.e., the “market clearing price,” which in turn is based on the unit providing energy in an hour with the highest incremental cost. The initial proceeding related to California’s demand for $8.9 billion in refunds from power sellers. The ALJ subsequently stated that after assessing a refund of $1.8 billion for power prices, power suppliers were owed $1.2 billion because the State was holding funds owed to suppliers. Because of the low volume of sales that PSCo had into California after this date, PSCo’s exposure is estimated at approximately $1.2 million, which is offset by amounts owed by the California ISO to PSCo in excess of that amount. The purchasing parties have appealed this decision. They have also asserted that the refund effective date should be set at an earlier date. The FERC has allowed the purchasing parties to request additional information regarding the market participants’ uses of certain strategies and the effect those strategies may have had on the market. The purchasing parties have filed a pleading at the FERC in which they claim that use of these strategies justifies an earlier refund effective date. An earlier effective date could increase PSCo’s exposure to approximately $15 million.

On March 26, 2003, FERC at its open meeting discussed and voted on a draft order in this proceeding. Based on the discussion of the draft order, it would appear that the FERC is going to use different gas costs to determine the applicable market clearing prices for the refund period. The effect of this change will be to increase PSCo's and other sellers' refund exposure. However, it does not appear from the discussion that the FERC will move back the applicable refund effective date. It may be expected that California litigants will request rehearing of this aspect of the order after it is issued.

Commodity Futures Trading Commission Investigation — Pursuant to a formal order of investigation, on June 17, 2002 the Commodity Futures Trading Commission (CFTC) issued broad subpoenas to Xcel Energy on behalf of its affiliates, including NRG, calling for production, among other things, of “all documents related to natural gas and electricity trading” (the “June 17, 2002 subpoenas”). Since that time, Xcel Energy has produced documents and other materials in response to numerous more specific requests under the June 17, 2002 subpoenas. Certain of these requests and Xcel Energy’s responses have concerned so-called “round-trip trades.” By a subpoena dated Jan. 29, 2003 and related letter requests (the “Jan. 29, 2003 subpoena”), the CFTC has requested that Xcel Energy produce all documents related to all data submittals and documents provided to energy industry publications. Xcel Energy has produced documents and other materials in response to the Jan. 29, 2003 subpoena, including a report identifying instances where Xcel Energy’s e prime subsidiary reported natural gas transactions to an industry publication in a manner inconsistent with the publication’s instructions. Xcel Energy believes this reporting did not affect the financial accounting treatment of any transaction recorded in e prime’s books and records. Also beginning on Jan. 29, 2003, the CFTC has sought testimony from two employees, and has notified Xcel Energy of its intention to seek additional testimony from numerous other employees and executives, concerning the reporting of energy transactions to industry publications. Xcel Energy and NRG are cooperating in the CFTC investigation, but cannot predict the outcome of any investigation.

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

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FERC Transmission Inquiry — The FERC has begun a formal, non-public inquiry relating to the treatment by public utility companies of affiliates in generator interconnection and other transmission matters. In connection with the inquiry, the FERC has asked Xcel Energy and its utility subsidiaries for certain information and documents. Xcel Energy and its utility subsidiaries are complying with the request.

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

NSP-Minnesota

Minnesota Emissions Reduction Program — In July 2002, NSP-Minnesota filed for approval by the MPUC of a proposal to invest in existing NSP-Minnesota generation facilities to reduce emissions under the terms of legislation adopted by the 2001 Minnesota Legislature. The NSP-Minnesota proposal includes the installation of state-of-the-art pollution control equipment at the A. S. King plant and conversion of the High Bridge and Riverside plants to use natural gas rather than coal. Under the proposal, major construction would start in 2005 and be completed in 2009. Under the terms of the statute, the filing concurrently seeks approval of a rate recovery mechanism for the costs of the proposal, estimated to total $1.1 billion. 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 equipment to be installed at 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. On Dec. 30, 2002, the Minnesota Pollution Control Agency issued a report to the MPUC in which it found that the NSP-Minnesota emission reduction proposal is appropriate and complies with the requirements of the 2001 legislation. The MPUC must now act on the proposal.

Renewable Cost Recovery Tariff — In April 2002, NSP-Minnesota 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. In January 2003, the MPUC issued an order approving the tariff subject to certain modifications.

Minnesota Financial and Service Quality Investigation — On Aug. 8, 2002, the MPUC asked for information related to the impact of the financial circumstances of NSP-Minnesota’s affiliate, NRG. Subsequent to that date, several newspaper articles alleged concerns about the reporting of service quality data and NSP-Minnesota’s overall maintenance practices. In an order dated Oct. 22, 2002, the MPUC directed the Minnesota Department of Commerce (DOC) and the Office of the Attorney General (OAG) to investigate the accuracy of NSP-Minnesota’s reliability records and to allow for further review of its maintenance and other service quality measures. In addition, the order requires NSP-Minnesota to report specified financial information and work with interested parties on various issues to ensure NSP-Minnesota’s commitments are fulfilled. The DOC and OAG have begun their investigation. There is no scheduled date for completion of this inquiry. The order references the NSP-Minnesota commitment, made at the time of the NSP/NCE merger, to not seek a rate increase until 2006 unless certain exceptions are met. In addition, among other requirements, the order imposes restrictions on NSP-Minnesota’s ability to encumber utility property, provide intercompany loans and the method by which NSP-Minnesota can calculate its cost of capital in present and future filings before the MPUC. On Jan. 3, 2003, the MPUC subsequently issued an order separating the financial aspect of this proceeding from the state agency’s inquiry into NSP-Minnesota’s service quality reporting and allowing the agencies to continue to investigate other allegations in existing dockets. As a result, these two matters will proceed under separate dockets. On March 10, 2003, the DOC and OAG submitted a progress report to the MPUC drafted by the state agencies auditor. The report documents alleged instances of record keeping inconsistencies and misstatements and concludes it would be nearly impossible to establish the magnitude of misstatements in the record keeping system. In submitting the progress report, the state agencies noted, however, that the total outage duration stated would need to increase by nearly 33 million minutes to violate state-imposed standards. NSP-Minnesota vigorously disputes the method, findings and conclusions of the report.

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

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unrecovered and appropriate costs, subject to a normal prudence review process. The OAG has argued that cost recovery should be denied for several reasons. An MPUC hearing on these issues is likely in the first half of 2003.

Electric Transmission Construction — In December 2001, NSP-Minnesota filed for certificates of need applications requesting authorization of construction of various high voltage transmission facilities to provide generator outlet for up to 825 megawatts of wind generation in southwest Minnesota. The projected cost is approximately $160 million. On March 11, 2003, the MPUC issued an order granting certificates of need supporting NSP-Minnesota’s preferred transmission construction plan. The certificates of need were issued with conditions that require NSP-Minnesota to purchase wind-powered electric generating capacity to match the increased transmission capacity created by the certified lines.

Filings will be made with the MEQB to decide routing issues associated with the transmission plan. MEQB decisions are expected by the end of 2003 and into 2004. Construction is expected to be complete in the spring of 2007.

NSP-Wisconsin

Retail Electric Fuel Rates — In August 2002, NSP-Wisconsin filed an application with the PSCW, requesting a decrease in Wisconsin retail electric rates for fuel costs. The amount of the proposed rate decrease was approximately $6.3 million on an annual basis. The reasons for the decrease include moderate weather, lower-than-forecast market power costs and optimal plant availability. On Aug. 7, 2002, the PSCW issued an order approving the fuel rate credit. The rate credit went into effect Aug. 12, 2002.

On Oct. 9, 2002, NSP-Wisconsin filed an application with the PSCW requesting another decrease in Wisconsin retail electric rates for fuel costs. The incremental amount of the second proposed rate decrease was approximately $5 million on an annual basis. The reasons for the additional decrease include continued moderate weather, lower-than-forecast market power costs and optimal plant availability. On Oct. 16, 2002, the PSCW issued an order approving the revised fuel rate credit, effective Oct. 19, 2002.

On Oct. 22, 2002, NSP-Wisconsin filed an application with the PSCW requesting the establishment of a new fuel monitoring range and fuel recovery factor for 2003. On Jan. 30, 2003, the PSCW issued an order authorizing a new fuel monitoring range for 2003 and a new fuel recovery factor effective Feb. 3, 2003. This results in an annual revenue increase of approximately $5 million from the fuel credit factor the PSCW approved Oct. 16, 2002.

Michigan Transfer Pricing — On Oct. 3, 2002, the MPSC denied NSP-Wisconsin’s request for a waiver of the section of the Michigan Electric Code of Conduct (Michigan Code) dealing with transfer pricing policy. The Michigan Code requires the price of goods and services provided by an affiliate of NSP-Wisconsin to be at the lower of market price or cost plus 10 percent, and the price of goods and services provided by NSP-Wisconsin to an affiliate be at the higher of cost or market price. NSP-Wisconsin requested the waiver based on its belief that the Michigan Code conflicts with SEC requirements to price goods and services provided between affiliates at cost. In November 2002, NSP-Wisconsin filed a request for reconsideration of the Oct. 3, 2003, order. On Jan. 31, 2003, the MPSC granted the NSP-Wisconsin’s request for a waiver from this section of the Michigan Code. In its decision, the MPSC indicated that it should grant the waiver to avoid placing NSP-Wisconsin in a position where it may be unable to comply with the Michigan Code and the pricing standards enforced by the SEC.

PSCo

Incentive Cost Adjustment — PSCo’s 2001 calendar year energy costs under the ICA were approximately $19 per megawatt-hour, compared with the $12.78 per megawatt-hour rate that was billed to customers. The sharing of certain energy wholesale trading margins mitigated the significant under-recovery of energy costs for 2001. In early 2002, PSCo filed to increase the ICA rate earlier than originally agreed in the merger stipulation and agreement to mitigate future cost deferrals and to recover the projected ICA energy costs of $148 million for calendar year 2002. On May 10, 2002, the CPUC approved a settlement agreement between PSCo and other parties to increase the recovery of energy costs to $14.88 per megawatt-hour ($12.78 through base electric rates and $2.10 through the ICA), providing for recovery of the deferred costs as of Dec. 31, 2001, and the projected 2002 costs over a 34-month period from June 1, 2002 through March 31, 2005. On March 5, 2003, PSCo filed to reduce the ICA rate to $2.07 per megawatt hour.

PSCo’s costs for 2002 were approximately $17 per megawatt-hour or approximately $56 million less than the energy costs for the 2001 test year. Under the ICA mechanism, retail customers and PSCo share this difference

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equally. A CPUC proceeding to review and approve the incurred and recoverable 2001 costs under the ICA is in process. A review of the 2002 recoverable ICA costs will be conducted in a separate future proceeding. The results of these rate proceedings could impact the cost recovery and sharing amounts recorded under the ICA for 2001 and 2002.

On May 31, 2002, PSCo filed with the CPUC seeking to change its electric base rates and increase the recovery of fuel and purchased power expense by $113 million annually through a mechanism called the electric commodity adjustment (ECA). The IAC, filed in January 2003, resulted in an annual increase in fuel and purchased power expense recovery revenue of $123 million predicated on calendar year 2003 forecasted retail sales for PSCo. Finally, on Feb. 12, 2003, PSCo filed supplemental rebuttal testimony revising its original ECA request made on May 31, 2002. In this filing, PSCo is seeking ECA rates that would increase the annual recovery of fuel and purchased energy expense by $186 million over the annual level of recovery at May 31, 2002. Since $123 million of the requested $186 million is already in effect, the net increase requested on Feb. 12, 2003, is $63 million.

There are four factors accounting for the change from $113 million requested in the May 31, 2002, filing and the $186 million requested in the Feb. 12, 2003, filing. Specifically, the Feb. 12, 2003, filing contains: a revision in ECA costs caused by a renegotiated purchased power contract; a revised 2003 sales forecast; an updated forecast of natural gas costs used as a fuel source in electric generating stations; and a correction for transformation and line losses made to the level of kilowatt-hours used in deriving the proposed level of annual ECA costs.

2002 General Rate Case — In May 2002, PSCo filed a combined general retail electric, gas and thermal energy base rate case with the CPUC to address increased costs for providing services to Colorado customers. This filing was required as part of the Xcel Energy Merger Stipulation and Agreement previously approved by the CPUC. See additional discussion under Item 7, Management’s Discussion and Analysis.

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 before an ALJ in July 2002. On Feb. 10, 2003, the ALJ issued a recommended decision rejecting the proposed disallowances and approving PSCo’s gas costs for the subject gas purchase year as prudently incurred. The decision is subject to CPUC review.

Gas Rate Requests — In September 2002, PSCo filed a request with the CPUC for a $65-million annual reduction in the natural gas cost component of rates in Colorado. The CPUC approved the requested decrease by order issued Sept. 27, 2002, with the new rates effective Oct. 1, 2002.

In March 2003, PSCo filed a request with the CPUC for a $95.6 million increase in the natural gas cost component of rates in Colorado for the period March 21, 2003 through Sept. 30, 2003. The CPUC approved the requested increase by order issued March 20, 2003. The cost adjustment will not result in any additional gas margin for PSCo, as the increase reflects additional costs for purchasing natural gas on behalf of its customers. Natural gas costs are passed on to customers on a dollar-per-dollar basis.

PSCo Fuel Clause Investigation — Certain wholesale power customers of PSCo have filed complaints with the FERC alleging PSCo has been improperly collecting certain fuel and purchased energy costs through the wholesale fuel cost adjustment clause included in their rates. The FERC consolidated the complaints and set them for hearing and settlement judge procedures. In November 2002, the Chief Judge terminated settlement procedures after settlement was not reached. The investigation is currently in the discovery process and hearings are set for August 2003.

Home Builders Association of Metropolitan Denver — Home Builders Association of Metropolitan Denver (HBA) filed a formal complaint with the CPUC on Feb. 23, 2001, requesting an award of reparations for excessive charges related to construction payments under PSCo’s gas extension tariff as a result of PSCo’s alleged failure to file revisions to its published construction allowances since 1996. HBA seeks an award of $13.6 million, including interest on behalf of all of PSCo’s gas extension applicants since Oct. 1, 1996. HBA also seeks recovery of its attorney’s fees.

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Hearings were held before an ALJ on Aug. 29, 2001, and Sept. 24, 2001. On Jan. 15, 2002, the ALJ issued a recommended decision dismissing HBA’s complaint. The ALJ found that HBA failed to show that there have been any “excessive charges,” as required under the reparations statute, resulting from PSCo’s failure to comply with its tariff. The ALJ held that HBA’s claim for reparations: (i) was barred by the filed rate doctrine (since PSCo at all times applied the approved construction allowances set forth in its tariff), (ii) would require the CPUC to violate the prohibition against retroactive ratemaking and (iii) was based on speculation as to what the CPUC would do had PSCo made the filings in prior years to change its construction allowances. The ALJ also denied HBA’s request for costs and attorney’s fees. HBA filed exceptions to the ALJ’s recommended decision. On June 19, 2002, the CPUC issued an order granting in part HBA’s exceptions to the ALJ’s recommended decision and remanding the case back to the ALJ for further proceedings. The CPUC reversed the ALJ’s legal conclusion that the filed rate doctrine and prohibition against retroactive ratemaking bars HBA’s claim for reparations under the circumstances of this case. The CPUC remanded the case back to the ALJ for a determination of whether and to what extent reparations should be awarded, considering certain enumerated issues.

A full-day hearing on remand was held on Jan. 10, 2003. Simultaneous briefs were filed on Feb. 5, 2003. Reply briefs were filed on Feb. 12, 2003. The ALJ decision on remand is pending.

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

On March 26, 2003, the FERC at its open meeting discussed this proceeding. While the action that the FERC plans to take cannot be definitively ascertained from that discussion, it appears that the FERC may conduct further proceedings to determine whether spot-market bilateral sales in the Pacific Northwest should be subject to refund.

SPS

Texas Fuel Reconciliation, Fuel Factor and Fuel Surcharge Application — In June 2002, SPS filed an application for the PUCT to retrospectively review the operations of the utility’s electric generation and fuel management activities. In this application, SPS filed its reconciliation for electric generation and fuel management activities, totaling approximately $608 million, for the period from January 2000 through December 2001. This proceeding is ongoing, and intervenor and PUCT staff filed testimony. Intervenors proposed that revenues from certain wholesale transactions be credited to Texas retail customers. SPS opposed this proposed revenue treatment. Hearings were scheduled for March 2003. On March 14, the parties submitted to the Administrative Law Judges a stipulation settling the proceeding. The stipulation resolves all issues regarding SPS’s fuel costs and wholesale trading activities through December 2001. SPS will withdraw, without prejudice, its request to share in 10 percent of margins from certain wholesale non-firm sales. SPS had proposed to recover $1.1 million from Texas customers for the proposed sharing of wholesale non-firm sales margins. The company had not recorded these proposed revenues pending the outcome in this proceeding. The parties agreed that SPS would reduce its December 2001 fuel under-recovery balances by $5.8 million. Taking into account the withdrawal of proposed margin sharing of wholesale non-firm sales, the net impacts to SPS’s deferred fuel expense balances, before tax, is $4.7 million. The stipulation will be considered by the PUCT during an open meeting in the next several months.

SPS has reported to the PUCT that it has under-collected its fuel costs under the current Texas retail fixed fuel factors. Taking into account the stipulation in the fuel cost reconciliation proceeding, SPS has under-collected through February 2003 by $16.2 million. In March 2003, SPS filed an application seeking to surcharge Texas retail customer bills from June 2003 through January 2004 to collect the $16.2 million in deferred expenses. SPS is in the process of preparing a filing with the PUCT to recover in customer rates current fuel costs under its fixed fuel cost recovery factors in accordance with state statutes and PUCT regulations. The filing is expected to be completed in May 2003. Recovery amounts would depend on future fuel rates once the filing is approved.

New Mexico Fuel Factor — On Dec. 17, 2001, SPS filed an application with the NMPRC seeking approval of continued use of its fuel and purchased power cost adjustment using a monthly adjustment factor, authorization to implement the proposed monthly factor on an interim basis and approval of the reconciliation of its fuel and purchase power adjustment clause collections for the period October 1999 through September 2001. In January 2002, the NMPRC authorized SPS to implement a monthly adjustment factor on an interim basis beginning with the February 2002 billing cycle. Hearings were completed in May 2002. SPS’ continuation and reconciliation portion of the file is still pending before the NMPRC.

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New Mexico Renewable Energy Requirements — In December 2002, the NMPRC adopted new regulations requiring investor-owned utilities operating in New Mexico to promote the use of renewable energy technologies by procuring at least 10 percent of their New Mexico retail energy requirements from renewable resources by no later than 2011.

Golden Spread Electric Cooperative, Inc. — In October 2001, Golden Spread Electric Cooperative, Inc. (Golden Spread) filed a complaint and request for investigation against SPS before the FERC. Golden Spread alleges SPS has violated provisions of a commitment and dispatch service agreement pursuant to which SPS conducts joint dispatch of SPS and Golden Spread resources. Golden Spread seeks damages in excess of $10 million. SPS denies all of Golden Spread’s allegations. SPS has filed a complaint against Golden Spread in which it has alleged that Golden Spread has failed to adhere to certain requirements of the commitment and dispatch service agreement. Both complaints are presently pending before the FERC and settlement procedures have been ordered by the Commission. Settlement discussions are ongoing. Even if SPS is required to pay more to Golden Spread for power purchased under this agreement, it believes that the amounts will likely be recoverable from customers.

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

Cheyenne

Cheyenne Purchased Power Costs — On May 25, 2001, the WPSC approved a stipulation agreement between Cheyenne and intervenors in connection with a proposed increase in rates charged to Cheyenne’s retail customers to recover increased power costs.

The stipulation provides for an ECA rate structure with a fixed energy supply rate for Cheyenne’s customers through 2003; the continuation of the ECA with certain modifications, including the amortization through December 2005 of unrecovered costs incurred during 2001 up to the agreed-upon fixed supply rates; and an agreement that Cheyenne’s energy supply needs will be provided, in whole or in part, by PSCo in accordance with wholesale tariff rates to be approved by the FERC. The estimated retail rate increases under the stipulation provide recovery of an additional $18 million, compared with prior rate levels, through 2001 and a total of $28 million for each of the years 2002 and 2003. In 2004 and 2005, Cheyenne will return to requesting recovery of its actual costs incurred plus the outstanding balance of any deferral from earlier years.

ELECTRIC UTILITY OPERATIONS

Competition and Industry Restructuring

Retail competition and the unbundling of regulated energy service could have a significant financial impact on Xcel Energy and its utility subsidiaries, due to an impairment of assets, a loss of retail customers, lower profit margins and increased costs of capital. The total impacts of restructuring may have a significant financial impact on the financial position, results of operation and cash flows of Xcel Energy. Xcel Energy and its subsidiaries cannot predict when they will be subject to changes in legislation or regulation, nor can they predict the impacts of such changes on their financial position, results of operation or cash flows. Xcel Energy believes that the prices its utility subsidiaries charge for electricity and the quality and reliability of their service currently place them in a position to compete effectively in the energy market. For more information on the delay of restructuring for SPS in Texas and New Mexico, see Note 15 to the Consolidated Financial Statements.

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

Wholesale Business Competition — The wholesale electric business faces competition in the supply of bulk power, due to federal and state initiatives to provide open access to utility transmission systems. Under current FERC rules, utilities are required to provide wholesale open access transmission services and to unbundle wholesale merchant and transmission

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operations. Xcel Energy’s utility subsidiaries are operating under a joint tariff in compliance with these rules. To date, these provisions have not had a material impact on the operations of Xcel Energy’s utility subsidiaries.

FERC Restructuring — During 2001 and 2002, the FERC issued several industry wide orders affecting, or potentially affecting, the Xcel Energy operating companies and NRG. In addition, the Xcel Energy utility subsidiaries submitted proposals to the FERC that could impact future operations, costs and revenues.

Midwest ISO Operations — In compliance with a condition in the January 2000 FERC order approving the Xcel Energy merger, NSP-Minnesota and NSP-Wisconsin entered into agreements to join the Midwest Independent Transmission System Operator, Inc. (Midwest ISO) in August 2000. In December 2001, the FERC approved the Midwest ISO as the first approved regional transmission organization (RTO) in the United States, pursuant to FERC Order 2000. On Feb. 1, 2002, the Midwest ISO began interim operations, including regional transmission tariff administration services for the NSP-Minnesota and NSP-Wisconsin electric transmission systems. NSP-Minnesota and NSP-Wisconsin have received all required regulatory approvals to transfer functional control of their high voltage (100 kilovolts and above) transmission systems to the Midwest ISO when the Midwest ISO is fully operational. The Midwest ISO will then control the operations of these facilities and the facilities of neighboring electric utilities.

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

The Midwest ISO also submitted an application to the FERC for approval of the business combination of the Midwest ISO and the Southwestern Power Pool (SPP), of which SPS is a member. The FERC issued an order in December 2002 conditionally approving the proposed business combination, however in March 2003, the Midwest ISO and the SPP announced the have mutually agreed to terminate the consolidation of their two organizations.

TRANSLink Transmission Co., LLC (TRANSLink) — In September 2001, Xcel Energy and several other electric utilities applied to the FERC to integrate operations of their electric transmission systems into a single system through the formation of TRANSLink, a for-profit, independent transmission-only company. The utilities will participate in TRANSLink through a combination of divestiture, leases and operating agreements. The initial applicants were: 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, on behalf of its operating utilities. In addition, in late 2002, several other companies stated their intent to join TRANSLink. They are Great River Energy power cooperative, Dairyland Electric Power Cooperative, Southern Minnesota Public Power Association and a group of 119 municipal utilities known as the Midwest Municipal Transmission Group. Rochester Public Utilities joined in early 2003. The participants believe TRANSLink is the most cost-effective option available to manage transmission and to comply with regulations issued by 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 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 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 ISO in which they agree that TRANSLink will contract with the Midwest ISO for certain other required RTO functions and services. In May 2002, the partners formed TRANSLink Development Co., LLC, which is responsible for pursuing the actions necessary to complete the regulatory approval of TRANSLink Transmission Co., 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 RTO organization of the Midwest ISO and a separate RTO in the West, once it is formed, for PSCo assets. The FERC conditioned TRANSLink’s approval on the resubmission of its tariff as a separate rate schedule to be administered by the Midwest ISO. TRANSLink Development Co. made this rate filing in October 2002. Eleven interveners had requested that the FERC clarify or reconsider elements of the TRANSLink decision. On Nov. 1, 2002, the FERC issued its order supporting the approval of the formation of TRANSLink. The FERC also clarified several issues covered in its April 2002 order. In December 2002, the

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FERC approved the TRANSLink rate schedules to the Midwest ISO tariff subject to refund, and required TRANSLink to engage in settlement discussions on several items. TRANSLink anticipates resolving these issues during the second quarter of 2003. In January 2003, the FERC also approved TRANSLink’s contractual relationship with the Midwest ISO. This contract delineates the role that TRANSLink will have within the RTO. Finally, in January 2003, TRANSLink Development Co. also identified its nine-member independent board of directors. The establishment of an independent board is required to satisfy Order 2000 obligations. Several state approvals would be required to implement the proposal, as well as SEC approval. State applications were made in late 2002 and early 2003. Subject to receipt of required regulatory approvals, TRANSLink is expected to begin operations in the third quarter of 2003.

Standards of Conduct Rulemaking — In October 2001, the 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 utility subsidiaries and the rules governing natural gas transportation and wholesale gas supply functions. The proposed rules would expand the definition of “affiliate” and further limit communications between transmission functions and supply functions, and could materially increase operating costs of the utility subsidiaries. In May 2002, the FERC staff issued a reaction paper, generally rejecting the comments of parties opposed to the proposed rules. No final rule has been issued.

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 electric supply markets operate throughout the United States. The proposed rulemaking expands the FERC’s intent to unbundle transmission operations from integrated utilities and ensure robust competition in wholesale markets. The rule contemplates that all wholesale and retail customers will be on a single network transmission service tariff. The rule also contemplates the implementation of a bid-based system for buying and selling energy in wholesale electric markets. RTOs or independent transmission providers will administer the market. RTOs will also be responsible for regional plans that identify opportunities to construct new transmission, generation or demand-side programs to reduce transmission constraints and meet regional energy requirements. Finally, the rule envisions the development of regional market monitors responsible for ensuring that individual participants do not exercise unlawful market power. The FERC recently extended the comment period, but anticipates that the final rules will be in place in 2003 and the contemplated market changes will take place in 2003 and 2004. However, recent FERC actions indicate the schedule for the final rules may be delayed.

NSP-Minnesota

Minnesota Restructuring — In 2001, the Minnesota Legislature passed an energy security bill that included provisions intended to streamline the siting process of new generation and transmission facilities. It also included voluntary benchmarks for achieving renewable energy as a portion of the utility supply portfolio. There was no further action on restructuring in 2002. There is unlikely to be any further action on restructuring in 2003.

North Dakota Restructuring — In 1997, the North Dakota Legislature established, by statute, an electric utility competition committee (EUC). To date, the committee has focused on the study of the state’s current tax treatment of the electric utility industry, primarily in the transmission and distribution functions. However, the Legislature, without recommendation from the EUC, modified the coal severance and coal conversion taxes primarily to improve the competitive status of North Dakota lignite for generation. During 2002, the committee continued its review and presented legislation to the legislative assembly in January 2003. No legislation resulted from the review.

TRANSLink — In December 2002, NSP-Minnesota filed for MPUC approval to transfer functional control of its electric transmission system to TRANSLink, of which NSP-Minnesota would be a participant, and related approvals. The proposal would allow NSP-Minnesota to more cost-effectively comply with 1999 FERC rules regarding independent transmission operations, known as Order No. 2000. NSP-Minnesota requested approval by early second quarter 2003 so TRANSLink could commence operations in third quarter 2003. A similar filing was submitted to the NDPSC in early January 2003. MPUC and NDPSC action is pending. No similar filing is required in the South Dakota jurisdiction.

NSP-Wisconsin

Wisconsin Restructuring — The state of Wisconsin passed legislation in 2001 that reduced the wholesale gross receipts tax on the sale of electricity by 50 percent starting in 2003. This legislation eliminates the double taxation on wholesale sales from non-utility generators. Additional legislation was passed that enables regulated utilities to enter into leased generation contracts with unregulated generation affiliates. The new legislation provides utilities a new financing mechanism and option to meet

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their customers’ energy needs. In 2002, the PSCW approved the first power plan proposal utilizing the new leased generation contract arrangement. While industry-restructuring changes continue in Wisconsin, the movement towards retail customer choice has virtually stopped.

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

TRANSLink — In November 2002, NSP-Wisconsin filed for PSCW approval to transfer functional control of its electric transmission system to the TRANSLink, of which NSP-Wisconsin would be a participant, and related approvals. The proposal would allow NSP-Wisconsin to more cost-effectively comply with FERC Order No. 2000 and Wisconsin statutes mandating independent transmission operations. NSP-Wisconsin requested approval by the end of first quarter 2003 so TRANSLink could commence operations in third quarter 2003. PSCW action is pending after submission of supportive comments by intervenors. No similar filing is required in the Michigan jurisdiction.

PSCo

Colorado Restructuring — There was no legislative action with respect to restructuring in Colorado during the 2000, 2001 or 2002 legislative sessions. None is expected in 2003.

SPS

New Mexico Restructuring — In March 2001, the state of New Mexico enacted legislation that delayed customer choice until 2007 and amended the Electric Utility Restructuring Act of 1999. In 2001, SPS requested recovery of its costs of approximately $5.1 million incurred to prepare for customer choice in New Mexico. A decision on this and other matters is pending before the NMPRC. SPS expects to receive future regulatory recovery of these costs.

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

In December 2001, SPS filed an application with the PUCT to recover $20.3 million in costs related to transition to retail competition from the Texas retail customers. 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. An order was received from the PUCT in May 2002 that stipulates recovery of $5.9 million through an incremental cost recovery rider and the capitalization of $1.9 million for metering equipment. Based on the order, 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.

For more information on restructuring in Texas and New Mexico, see Note 15 to the Consolidated Financial Statements.

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

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

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TRANSLink — In November and December 2002, SPS filed for PUCT and NMPRC approval to transfer functional control of its electric transmission system to the TRANSLink, of which SPS would be a participant, and related approvals. The proposal would allow SPS to more cost-effectively comply with FERC Order No. 2000. SPS requested approval by early second quarter 2003 so TRANSLink could commence operations in third quarter 2003. PUCT and NMPRC action is pending. No similar filings are required in the Kansas and Oklahoma jurisdictions.

Other

Wyoming Restructuring — There were no electric industry restructuring legislation proposals introduced in the Legislature during 2001 or 2002. No action with respect to electric restructuring is anticipated in 2003.

Capacity and Demand

Assuming normal weather during 2003, system peak demand and the net dependable system capacity for Xcel Energy’s electric utility subsidiaries are projected below. The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin are managed as an integrated system (referred to as the NSP System). The system peak demand for each of the last three years and the forecast for 2003 are listed below.

The peak demand for all systems typically occurs in the summer. The 2002 system peak demand for the NSP System occurred on July 30, 2002. The 2002 system peak demand for PSCo occurred on July 18, 2002. The 2002 system peak demand for SPS occurred on Aug. 1, 2002.

Energy Sources

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

Purchased Power

Xcel Energy’s electric utility subsidiaries have contractual arrangements to purchase power from other utilities and nonregulated energy suppliers. Capacity, typically measured in kilowatts or megawatts, is the measure of the rate at which a particular generating source produces electricity. Energy, typically measured in kilowatt-hours or megawatt-hours, is a measure of the amount of electricity produced from a particular generating source over a period of time. Purchased power contracts typically require a periodic payment to secure the capacity from a particular generating source and a charge for the associated energy actually purchased from such generating source.

The utility subsidiaries of Xcel Energy also make short-term and non-firm purchases to replace generation from company-owned units that are unavailable due to maintenance and unplanned outages, to provide each utility’s reserve obligation, to obtain energy at a lower cost than that which could be produced by other resource options, including company-owned generation and/or long-term purchase power contracts, and for various other operating requirements.

NSP System Resource Plan

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

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

The MPUC will receive comments on the plan in the coming months and act to approve, modify or reject the plan late in the year. NSP-Minnesota has requested that the Minnesota Legislature address the issue of spent nuclear fuel storage limitation and its effect on the future of nuclear generation in Minnesota in the 2003 legislative session. See Nuclear Power Operations and Waste Disposal-High-Level Radioactive Waste Disposal under Item 1. The MPUC has suspended the procedure schedule pending the completion of the legislative session.

PSCo Resource Plan

PSCo estimates it will purchase approximately 31 percent of its total electric system energy input for 2003. Approximately 44 percent of the total system capacity for the summer 2003 system peak demand for PSCo will be provided by purchased power.

To meet the demand and energy needs of the rapidly growing economy in Colorado, PSCo completed a solicitation process that will add approximately 1,800 megawatts of resources to its system over the 2002 to 2005 time period.

Purchased Transmission Services

Xcel Energy’s electric utility subsidiaries have contractual arrangements with regional transmission service providers to deliver power and energy to the subsidiaries’ native load customers, which are retail and wholesale load obligations with terms of more than one year. Point-to-point transmission services typically include a charge for the specific amount of transmission capacity being reserved, although some agreements may base charges on the amount of metered energy delivered. Network transmission services include a charge for the metered demand at the delivery point at the time of the provider’s monthly transmission system peak, usually calculated as a 12-month rolling average.

Fuel Supply and Costs

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

*

Includes refuse-derived fuel and wood

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NSP-Minnesota and NSP-Wisconsin

NSP-Minnesota and NSP-Wisconsin normally maintain between 30 and 45 days of coal inventory at each plant site. Estimated coal requirements at NSP-Minnesota’s major coal-fired generating plants are approximately 12 million tons per year. NSP-Minnesota and NSP-Wisconsin have long-term contracts providing for the delivery of up to 100 percent of 2003 coal requirements and up to 58 percent of their 2004 requirements. Coal delivery may be subject to short-term interruptions or reductions due to transportation problems, weather and availability of equipment.

NSP-Minnesota and NSP-Wisconsin expect that all of the coal they burn in 2003 will have a sulfur content of less than 1 percent. NSP-Minnesota and NSP-Wisconsin have contracts for a maximum of 38.4 million tons of low-sulfur coal for the next five years. The contracts are with two Montana coal suppliers and three Wyoming suppliers with expiration dates ranging between 2003 and 2007. NSP-Minnesota and NSP-Wisconsin could purchase approximately 42 percent of coal requirements in the spot market in 2004 if spot prices are more favorable than contracted prices.

NSP-Minnesota and NSP-Wisconsin’s current fuel oil inventory is adequate to meet anticipated 2003 requirements, and they also have access to the spot market to buy more oil, if needed. NSP-Minnesota and NSP-Wisconsin use both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas supplies for power plants are procured under short- and intermediate-term contracts to provide an adequate supply of fuel.

To operate NSP-Minnesota’s nuclear generating plants, NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication. The contract strategy involves a portfolio of spot purchases and medium- and long-term contracts for uranium, conversion and enrichment. Current contracts are flexible and cover 100 percent of uranium, conversion and enrichment requirements through the year 2005. These contracts expire at varying times between 2003 and 2006. The overlapping nature of contract commitments will allow NSP-Minnesota to maintain 50 percent to 100 percent coverage beyond 2002. NSP-Minnesota expects sufficient uranium, conversion and enrichment to be available for the total fuel requirements of its nuclear generating plants. Fuel fabrication is 100 percent committed through 2004 and 30 percent through 2010.

PSCo

PSCo’s primary fuel for its steam electric generating stations is low-sulfur western coal. PSCo’s coal requirements are purchased primarily under long-term contracts with suppliers operating in Colorado and Wyoming. During 2002, PSCo’s coal requirements for existing plants were approximately 10.1 million tons, a substantial portion of which was supplied pursuant to long-term supply contracts. Coal supply inventories at Dec. 31, 2002, were approximately 47 days usage, based on the average burn rate for all of PSCo’s coal-fired plants.

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

PSCo has secured more than 75 percent of Cameo station’s coal requirements for 2003. Any remaining requirements may be purchased from this contract or the spot market. PSCo has contracted for coal supplies to supply approximately 100 percent of the Cherokee and Valmont stations’ projected requirements in 2003.

PSCo has long-term coal supply agreements for the Pawnee and Comanche stations’ projected requirements. Under the long-term agreements, the supplier has dedicated specific coal reserves at the contractually defined mines to meet the contract quantity obligations. In addition, PSCo has a coal supply agreement to supply approximately 85 percent of Arapahoe station’s projected requirements for 2003. Any remaining Arapahoe station requirements will be procured via spot market purchases.

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

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SPS

SPS purchases all of its coal requirements for Harrington and Tolk electric generating stations from TUCO, Inc. in the form of crushed, ready-to-burn coal delivered to SPS’ plant bunkers. For the Harrington station, the coal supply contract expires in 2016 and the coal handling agreement expires in 2004. For the Tolk station, the coal supply contract expires in 2017 and the coal handling agreement expires in 2005. At Dec. 31, 2002, coal supplies at the Harrington and Tolk sites were approximately 44 and 53 days supply, respectively. TUCO has coal supply agreements to supply 100 percent of the projected requirements for 2003 for Harrington station and Tolk station. TUCO has long-term contracts for supply of coal in sufficient quantities to meet the primary needs of the Tolk station.

SPS has a number of short- and intermediate-term contracts with natural gas suppliers operating in gas fields with long life expectancies in or near its service area. SPS also utilizes firm and interruptible transportation to minimize fuel costs during volatile market conditions and to provide reliability of supply. SPS maintains sufficient gas supplies under short- and intermediate-term contracts to meet all power plant requirements; however, due to flexible contract terms, approximately 50 percent of SPS’ gas requirements during 2002 were purchased under spot agreements.

Trading Operations

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

Nuclear Power Operations and Waste Disposal

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. See additional discussion regarding the nuclear generating plants at Note 19 to the Consolidated Financial Statements.

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

Low-Level Radioactive Waste Disposal — Federal law places responsibility on each state for disposal of its low-level radioactive substance. Low-level radioactive substance from NSP-Minnesota’s Monticello and Prairie Island nuclear plants is currently disposed of at the Barnwell facility located in South Carolina (all classes of low-level substance) and the Clive facility located in Utah (class A low-level substance only). Chem Nuclear is the owner and operator of the Barnwell facility, which has been given authorization by South Carolina to accept low-level radioactive substance from out of state. Envirocare, Inc. operates the Clive facility. NSP-Minnesota and Barnwell currently operate under an annual contract, while NSP-Minnesota uses the Envirocare facility through various low-level substance processors. NSP-Minnesota has low-level storage capacity available on-site at Prairie Island and Monticello that would allow both plants to continue to operate until the end of their licensed lives, if off-site low-level disposal facilities were not available to NSP-Minnesota.

High-Level Radioactive Waste Disposal — The federal government has the responsibility to dispose of, or permanently store, domestic spent nuclear fuel and other high-level radioactive substances. The Nuclear Waste Policy Act requires the Department of Energy (DOE) to implement a program for nuclear substance management. This includes the siting, licensing, construction and operation of a repository for domestically produced spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive substances at a permanent storage or disposal facility by 1998. The DOE has accepted none of NSP-Minnesota’s spent nuclear fuel. See Item 3 — Legal Proceedings and Note 19 to the Consolidated Financial Statements for further discussion of this matter.

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NSP-Minnesota has on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear plants. The Prairie Island plant is licensed by the federal Nuclear Regulatory Commission (NRC) to store up to 48 casks of spent fuel at the plant. In 1994, the Minnesota Legislature adopted a limit on dry cask storage of 17 casks for the entire state. The 17 casks, which stand outside the Prairie Island plant, are now full, and under the current configuration the storage pool within the plant would be full by 2007. Prairie Island cannot operate beyond 2007 unless the existing spent fuel is moved or the storage capacity is increased. Because the 17-cask limit is a statewide limit, the Monticello plant cannot, under current state law, store spent fuel in dry casks. Monticello’s on-site storage pool is expected to be full in 2010. Monticello cannot operate beyond 2010 unless the existing spent fuel is moved or the storage capacity is increased.

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

If the Prairie Island plant is to continue operating beyond 2007, legislative authorization of additional storage space is needed. If additional storage space for continued operations is not authorized, legislation may be needed to ensure timely implementation of a replacement alternative.

NSP-Minnesota has developed viable replacement power options, including purchasing new coal or natural gas generation, and also reviewed the feasibility of supplementing new natural gas generation with additional wind turbines. These options have been presented to the 2003 Legislature. Each option involves trade-offs between cost, emissions and operational impacts.

Due to the investment decisions required to be made in conjunction with the continued efficient operation of the nuclear plants, as well as the time and cost involved to develop alternatives to the existing nuclear power generation, NSP-Minnesota believes a decision is necessary in 2003 by the Minnesota Legislature whether the state will allow the continued use of nuclear power in the future. Prairie Island will only be able to continue operating beyond 2007 with legislative authorization of additional storage space.

In February 2001, NSP-Minnesota signed a contract with Steam Generating Team, Ltd. to perform engineering and construction services for the installation of replacement steam generators at the Prairie Island nuclear power plant. NSP-Minnesota is evaluating the economics of replacing two steam generators on unit 1 at the plant. NSP-Minnesota is taking steps to preserve the replacement option for as early as 2004. The total cost of replacing the steam generators is estimated to be approximately $132 million.

The NRC is engaged in various ongoing studies and rulemaking activities that may impose additional requirements upon commercial nuclear power plants. Management is unable to predict any new requirements or their impact on NSP-Minnesota’s facilities and operations.

Nuclear Management Co. (NMC)

During 1999, NSP-Minnesota, Wisconsin Electric Power Co., Wisconsin Public Service Corp. and Alliant Energy Corp. established NMC. The Consumers Power subsidiary of CMS Energy Corp. joined NMC during 2000, and transferred operating authority for the Palisades nuclear plant to NMC in 2001. The five affiliated companies own eight nuclear units on six sites, with total generation capacity exceeding 4,500 megawatts.

The NRC has approved requests by NMC’s affiliated utilities to transfer operating authority for their nuclear plants to NMC, formally establishing NMC as an operating company. NMC manages the operations and maintenance at the plants, and is responsible for physical security. NMC’s responsibilities also include oversight of on-site dry storage facilities for used nuclear fuel at the Prairie Island nuclear plant. Utility plant owners, including Xcel Energy, continue to own the plants, control all energy produced by the plants, and retain responsibility for nuclear liability insurance and decommissioning costs. Existing

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personnel continue to provide day-to-day plant operations, with the additional benefit of sharing ideas and operating experience from all NMC-operated plants for improved safety, reliability and operational performance.

For further discussion of nuclear issues, see Notes 18 and 19 to the Consolidated Financial Statements.

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Electric Operating Statistics (Xcel Energy)

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GAS UTILITY OPERATIONS

Competition and Industry Restructuring

In the early 1990’s, the FERC issued Order No. 636, which mandated the unbundling of interstate natural gas pipeline services, including sales, transportation, storage and ancillary services. The implementation of Order No. 636 has resulted in additional pressure on all local distribution companies (LDCs) to keep gas supply and transmission prices for their large customers competitive. Customers have greater ability to buy gas directly from suppliers and arrange their own pipeline and LDC transportation service. Changes in regulatory policies and market forces have shifted the industry from traditional bundled gas sales service to an unbundled transportation and market-based commodity service.

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

As LDCs, NSP-Minnesota, NSP-Wisconsin and PSCo provide transportation service to large customers. Transportation service does not have an adverse effect on earnings because the sales and transportation rates have been designed to produce the same profit margin. However, some transportation customers may have greater opportunities or incentives to physically bypass the LDCs distribution system.

The Colorado Legislature passed legislation in 1999 that provides the CPUC the authority and responsibility to approve voluntary unbundling plans submitted by Colorado gas utilities in the future. PSCo has not filed a plan to further unbundle its gas service to all residential and commercial customers and continues to evaluate its business opportunities for doing so.

Capability and Demand

NSP-Minnesota and NSP-Wisconsin

Xcel Energy categorizes its gas supply requirements as firm or interruptible, which are customers with an alternate energy supply. The maximum daily send-out of firm and interruptible for the combined system of NSP-Minnesota and NSP-Wisconsin was 650,641 million British thermal units (MMBtu) for 2002, which occurred on Jan. 2, 2002.

NSP-Minnesota and NSP-Wisconsin purchase gas from independent suppliers. The gas is delivered under gas transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 604,000 MMBtu/day. In addition, NSP-Minnesota and NSP-Wisconsin have contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 15 percent of winter season and 23 percent of peak daily, firm requirements of NSP-Minnesota and NSP-Wisconsin.

NSP-Minnesota and NSP-Wisconsin also own and operate two liquefied natural gas (LNG) plants with a storage capacity of 2.5 billion cubic feet (Bcf) equivalent and four propane-air plants with a storage capacity of 1.4 Bcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 246,000 MMBtu of natural gas per day, or approximately 32 percent of peak day firm requirements. LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days and can be used to minimize daily imbalance fees on interstate pipelines.

NSP-Minnesota and NSP-Wisconsin are required to file for a change in gas supply contract levels to meet peak demand, to redistribute demand costs among classes or to exchange one form of demand for another. In October 2001, the MPUC approved NSP-Minnesota’s 2000-2001 entitlement levels. NSP-Minnesota’s 2001-2002 entitlement levels were approved on April 3, 2002, which allow NSP-Minnesota to recover the demand entitlement costs associated with the increase in transportation and storage levels in its monthly PGA. The 2002-2003 entitlement levels are pending MPUC action. NSP-Wisconsin’s winter 2002-2003 supply plan was approved by the PSCW in October 2002.

PSCo and Cheyenne

PSCo and Cheyenne project peak day gas supply requirements for firm sales and backup transportation, which include transportation customers contracting for firm supply backup, to be approximately 1,756,000 MMBtu. In addition, firm transportation customers hold 451,000 MMBtu of capacity without supply backup. Total firm delivery obligation for PSCo and

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Cheyenne are 2,206,870 MMBtu per day. The maximum daily deliveries for both companies in 2002 for firm and interruptible services were 1,652,459 MMBtu on Feb. 25, 2002.

PSCo and Cheyenne purchase gas from independent suppliers. The gas supplies are delivered to the respective delivery systems through a combination of transportation agreements, with interstate pipelines and deliveries by suppliers directly to each company. These agreements provide for firm deliverable pipeline capacity of approximately 1,220,000 MMBtu/day, which includes 797,000 MMBtu of supplies held under third-party underground storage agreements. In addition, PSCo operates three company-owned underground storage facilities, which provide about 38,000 MMBtu of gas supplies on a peak day. The balance of the quantities required to meet firm peak day sales obligations are primarily purchased at the companies’ city gate meter stations and a small amount is received directly from wellhead sources.

PSCo has received approval to close one of its three storage facilities, Leyden Storage Field. The field’s 110,000 MMBtu peak day capacity was replaced with additional third-party storage and transportation capacity. See further discussion at Note 18 to the Consolidated Financial Statements.

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

Gas Supply and Costs

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

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

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

NSP-Minnesota and NSP-Wisconsin

NSP-Minnesota and NSP-Wisconsin have firm gas transportation contracts with several pipelines, which expire in various years from 2003 through 2014. Approximately 80 percent of NSP-Minnesota and NSP-Wisconsin’s retail gas customers’ needs are supplied from the Northern Natural Gas pipeline system.

NSP-Minnesota and NSP-Wisconsin have certain gas supply and transportation agreements that include obligations for the purchase and/or delivery of specified volumes of gas or to make payments in lieu of delivery. At Dec. 31, 2002, NSP-Minnesota and NSP-Wisconsin were committed to approximately $267.7 million in such obligations under these contracts, which expire in various years from 2003 through 2014.

NSP-Minnesota and NSP-Wisconsin purchase firm gas supply utilizing long-term and short-term agreements from approximately 37 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Minnesota and NSP-Wisconsin to maintain competition from suppliers and minimize supply costs.

PSCo and Cheyenne

PSCo and Cheyenne have certain gas supply and transportation agreements that include obligations for the purchase and/or delivery of specified volumes of gas or to make payments in lieu of delivery. At Dec. 31, 2002, PSCo and Cheyenne were

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committed to approximately $906.3 million in such obligations under these contracts, which expire in various years from 2003 through 2025.

PSCo and Cheyenne have attempted to maintain low-cost, reliable natural gas supplies by optimizing a balance of long-term and short-term gas purchases, firm transportation and gas storage contracts. PSCo and Cheyenne also utilize a mixture of fixed-price purchases and index-related purchases to provide a less volatile, yet market-sensitive, price to its customers. During 2002, PSCo and Cheyenne purchased natural gas from approximately 44 suppliers.

Viking

On Nov. 7, 2002, Xcel Energy reached an agreement to sell Viking and Viking’s one-third share of Guardian Pipeline to Border Viking Company, whose ultimate parent is Northern Border Partners L. P. The sale was completed on Jan. 17, 2003, and Xcel Energy received net proceeds of $124 million.

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Gas Operating Statistics (Xcel Energy)

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NONREGULATED SUBSIDIARIES

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

NRG Energy, Inc.

NRG is an energy company primarily engaged in the ownership and operation of power generation facilities and the sale of energy, capacity and related products in the United States and internationally. For additional information see Item 1 of NRG’s Annual Report on Form 10-K, incorporated herein by reference at Exhibit 99.02.

Xcel Energy owned 100 percent of NRG Energy at the beginning of 2000. About 18 percent of NRG Energy was sold to the public in an initial public offering in the second quarter of 2000, leaving Xcel Energy with an 82-percent interest at Dec. 31, 2000. In March 2001, another 8 percent of NRG Energy was sold to the public, leaving Xcel Energy with an interest of about 74 percent at Dec. 31, 2001. On June 3, 2002, Xcel Energy purchased the 26 percent of NRG Energy held by the public so that it again held 100 percent ownership at Dec. 31, 2002. See Note 4 to the Consolidated Financial Statements for discussion of potential changes in NRG ownership.

Since the early 1990’s, NRG has pursued a strategy of rapid growth through acquisitions. Starting in 2000, NRG Energy added new construction to this strategy. This strategy required significant capital, much of which was satisfied primarily with debt. As of Dec. 31, 2002 NRG had approximately $9.4 billion of debt on its balance sheet at the corporate and project levels. Due to a number of reasons, including the overall downturn in the energy industry, NRG’s financial condition has deteriorated significantly and NRG is facing severe financial difficulties. NRG has failed to make scheduled payments of interest and principal on its outstanding bank loans and bonds. As a consequence, NRG may seek protection under the bankruptcy laws in the future. See Notes 2, 3, 4 and 7 to the Consolidated Financial Statements.

NRG is restructuring its operations to become a domestic-based owner-operator of a fuel-diverse portfolio of electric generation facilities engaged in the sale of energy, capacity and related products. NRG is working toward this goal by selective divestiture of non-core assets, realignment of management, reorganization of power marketing activities and an overall financial restructuring that will improve liquidity and reduce debt. NRG does not anticipate any new significant development, and, instead, will focus on operational performance and asset management. NRG has already made significant reductions in expenditures, business development activities and personnel. Power sales and fuel procurement will remain a key strategic element of NRG’s operations. NRG’s objective will be to optimize the fuel input and the energy output of its facilities within an appropriate risk and liquidity profile.

The entire independent power industry in the United States is in turmoil. Many of NRG’s competitors have announced plans to scale back their growth, sell assets, and restructure their finances. Bankruptcy filings are likely by several of NRG’s competitors. The results of the wholesale restructuring of the independent power industry are impossible to predict, but they may include consolidation within the industry, the sale or liquidation of certain competitors, the re-regulation of certain markets, and the long-term reduction in new investment into the industry. Under any scenario, however, NRG anticipates that it will continue to face competition from numerous companies in the industry, some of which may have more extensive operating experience, larger staffs, and greater financial resources than NRG presently possesses.

Many companies in the regulated utility industry, with which the independent power industry is closely linked, are also restructuring or reviewing their strategies. Several of these companies are discontinuing going forward with unregulated investments, seeking to divest of their unregulated subsidiaries or attempting to have their regulated subsidiaries acquire their unregulated subsidiaries. This may lead to an increased competition between the regulated utilities and the unregulated power producers within certain markets. In such instances, NRG may compete with regulated utilities in the influence of market designs and rulemaking.

On March 26, 2003, Xcel Energy’s board of directors approved a tentative settlement with holders of most of NRG’s long-term notes and the steering committee representing NRG’s bank lenders regarding alleged claims of such creditors against Xcel Energy, including claims related to the support and capital subscription agreement between Xcel Energy and NRG dated May 29, 2002 (the “Support Agreement”). The settlement is subject to a variety of conditions as set forth below, including definitive documentation. The principal terms of the settlement as of the date of this report were as follows:

Xcel Energy would pay up to $752 million to NRG to settle all claims of NRG, and the claims of NRG against Xcel Energy, including all claims under the Support Agreement.

$350 million would be paid at or shortly following the consummation of a restructuring of NRG’s debt through a bankruptcy proceeding. It is expected that this payment would be made prior to year-end 2003. $50 million would be paid on Jan. 1, 2004, and all or any part of such payment could be made, at Xcel Energy’s election, in Xcel Energy common stock. Up to $352 million would be paid on April 30, 2004, except to the extent that Xcel Energy had not received at such time tax refunds equal to $352 million associated with the loss on its investment in NRG. To the extent Xcel Energy had not received such refunds, the April 30 payment would be due on May 30, 2004.

$390 million of the Xcel Energy payments are contingent on receiving releases from NRG creditors. To the extent Xcel Energy does not receive a release from an NRG creditor. Xcel Energy’s obligation to make $390 million of the payments would be reduced based on the amount of the creditor’s claim against NRG. As noted below, however, the entire settlement is contingent upon Xcel Energy receiving releases from at least 85 percent of the claims in various NRG creditor groups. As a result, it is not expected that Xcel Energy’s payment obligations would be reduced by more than approximately $60 million. Any reduction would come from the Xcel Energy payment due on April 30, 2004.

Upon the consummation of NRG’s debt restructuring through a bankruptcy proceeding, Xcel Energy’s exposure on any guaranties or other credit support obligations incurred by Xcel Energy for the benefit of NRG or any subsidiary would be terminated and any cash collateral posted by Xcel Energy would be returned to it. The current amount of such cash collateral is approximately $11.5 million.

As part of the settlement with Xcel Energy, any intercompany claims of Xcel Energy against NRG or any subsidiary arising from the provision of intercompany goods or services or the honoring of any guaranty will be paid in full in cash in the ordinary course except that the agreed amount of such intercompany claims arising or accrued as of Jan. 31, 2003 will be reduced from approximately $55 million as asserted by Xcel Energy to $13 million. The $13 million agreed amount is to be paid upon the consummation of NRG’s debt restructuring with $3 million in cash and an unsecured promissory note of NRG on market terms in the principal amount of $10 million.

NRG and its direct and indirect subsidiaries would not be reconsolidated with Xcel Energy or any of its other affiliates for tax purposes at any time after their June 2002 re-affiliation or treated as a party to or otherwise entitled to the benefits of any tax sharing agreement with Xcel Energy. Likewise, NRG would not be entitled to any tax benefits associated with the tax loss Xcel Energy expects to incur in connection with the write down of its investment in NRG.

Xcel Energy’s obligations under the tentative settlement, including its obligations to make the payments set forth above, are contingent upon, among other things, the following:

	(1)		Definitive documentation, in form and substance satisfactory to the parties;
	(2)		Between 50 percent and 100 percent of the claims represented by various NRG facilities or creditor groups (the “NRG Credit Facilities”) having executed an agreement, in form and substance satisfactory to Xcel Energy, to support the settlement;
	(3)		Various stages of the implementation of the settlement occurring by dates currently being negotiated, with the consummation of the settlement to occur by Sept. 30, 2003;
	(4)		The receipt of releases in favor of Xcel Energy by at least 85 percent of the claims represented by the NRG Credit Facilities;
	(5)		The receipt by Xcel Energy of all necessary regulatory approvals; and
	(6)		No downgrade prior to consummation of the settlement of any Xcel Energy credit rating from the level of such rating as of March 25, 2003.

Since many of these conditions are not within Xcel Energy’s control, Xcel Energy cannot state with certainty that the settlement will be effectuated. Nevertheless, the Xcel Energy management is optimistic at this time that the settlement will be implemented.

Additional information regarding NRG’s operations is included in Item 1 of Part I of NRG’s Form 10-K for the year ended Dec. 31, 2002, which is incorporated as Exhibit 99.02 to this 10-K report and incorporated by reference herein.

e prime, inc.

e prime was incorporated in 1995 under the laws of Colorado. e prime provides energy related products and services, which include natural gas marketing and trading and energy consulting. In 1996, e prime received authorization from the FERC to act as a power marketer. Additionally, e prime owns Young Gas Storage Company, which owns a 47.5 percent general partnership interest in an underground gas storage facility in northeastern Colorado.

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e prime’s gas trading operations acquire assets and commodities and subsequently trade around those assets or commodity positions. e prime captures trading opportunities through price volatility driven by factors such as asset utilization, locational price differentials, weather, available supplies, credit and customer actions. Trading margins are captured through the utilization of transmission, transportation and storage assets, capture of regional price differences and other factors.

Other Subsidiaries

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

Xcel Energy International

Xcel Energy International (Xcel International) was formed in 1997 to manage the international operations of Xcel Energy, outside of NRG.

In August 2002, Xcel International sold a 5-percent interest in Yorkshire Power for $33 million to CE Electric UK. Xcel Energy and American Electric Power Co. each held a 50-percent interest in Yorkshire, a UK retail electricity and gas supplier and electric distributor, before selling 95 percent of Yorkshire to Innogy Holdings plc in April 2001.

Xcel Energy Argentina’s primary investment consists of the ownership and operation of three independent power production facilities in Argentina. At Dec. 31, 2002, Xcel Argentina had approximately $112 million invested in these facilities.

Utility Engineering Corp. (UE)

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

Planergy International Inc.

Planergy provides energy management, consulting, on-site generation, load curtailment, demand-side management, energy conservation and optimization, distributed generation and power quality services, as well as information management solutions to industrial, commercial and utility customers.

Seren Innovations, Inc.

Seren is constructing a combination cable television, telephone and high-speed internet access system in two locations: St. Cloud, Minn., and Contra Costa County in the East Bay area of northern California. As of Dec. 31, 2002, Xcel Energy’s investment in Seren was approximately $255 million. Seren projects improvement in its operating results with positive cash flow anticipated in 2005, upon completion of its build-out program, and earnings contribution in 2008. See further discussion in Note 18 to the Consolidated Financial Statements.

Eloigne Company

Eloigne was established in 1993 and its principal business is the acquisition of rental housing projects that qualify for low-income housing tax credits under current federal tax law. As of Dec. 31, 2002, approximately $83 million had been invested in Eloigne projects, including approximately $23 million in wholly owned properties and approximately $60 million in equity interests in jointly owned projects. Completed and committed Eloigne projects as of Dec. 31, 2002, are expected to generate tax credits of $76 million over the time period of 2003 through 2011.

ENVIRONMENTAL MATTERS

Certain of Xcel Energy’s subsidiary facilities are regulated by federal and state environmental agencies. These agencies have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. Xcel Energy has received all

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necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Company facilities have been designed and constructed to operate in compliance with applicable environmental standards.

Xcel Energy and its subsidiaries strive to comply with all environmental regulations applicable to its operations. However, it is not possible at this time to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or, generally, what effect future laws or regulations may have upon Xcel Energy’s operations. For more information on environmental contingencies, see Notes 18 and 19 to the Consolidated Financial Statements and environmental matters in Management’s Discussion and Analysis under Item 7.

CAPITAL SPENDING AND FINANCING

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

EMPLOYEES

The number of Xcel Energy employees at Dec. 31, 2002, is presented in the table below. Of the employees listed below, 7,449, or 51 percent, are covered under collective bargaining agreements.

EXECUTIVE OFFICERS

Wayne H. Brunetti, 60, Chairman of the Board, August 2001 to present, President and Chief Executive Officer, August 2000 to present. Previously, Vice Chairman, President, Chief Operating Officer and Director of NCE since 1997 and President and Director of PSCo since 1994.

Paul J. Bonavia, 51, President — Energy Markets, Xcel Energy, August 2000 to present. Previously, Senior Vice President and General Counsel of NCE since 1997.

Benjamin G.S. Fowke III, 44, Vice President and Treasurer, Xcel Energy, November 2002 to present. Previously, Vice President and Chief Financial Officer - Energy Markets, Xcel Energy from August 2000 to November 2002, Vice President - Retail Services and Energy Markets, NCE from January 1999 to July 2000 and Vice President — Finance/Accounting, e prime from May 1997 to December 1998.

Raymond E. Gogel, 52, Vice President and CIO, Xcel Energy, April 2002 to present. Previously, Vice President and Senior Client Services Principal for IBM Global Services since June 2001 and Senior Project Executive for IBM Global Services since January 1998.

Cathy J. Hart, 53, Vice President and Corporate Secretary, Xcel Energy, August 2000 to present. Previously, Secretary of NCE since 1998 and Manager of Corporate Communications of PSCo from 1993 to 1996. From June 1996 to June 1998, Cathy J. Hart was not employed. For family reasons, she resigned as Manager of Corporate Communications at PSCo in June 1996 to move to Australia. She was re-employed by NCE as Corporate Secretary in June 1998.

Gary R. Johnson, 56, Vice President and General Counsel, Xcel Energy, August 2000 to present. Previously, Vice President and General Counsel of NSP since 1991.

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Richard C. Kelly, 56, Vice President and Chief Financial Officer, Xcel Energy, August 2002 to present. Previously, President — Enterprises, Xcel Energy, since August 2000, Executive Vice President and Chief Financial Officer for NCE from 1997 to August 2000 and Senior Vice President of PSCo from 1990 to 1997.

Cynthia L. Lesher, 54, Chief Administrative Officer, Xcel Energy, August 2000 to present. Chief Human Resources Officer, Xcel Energy, July 2001 to present. Previously, President of NSP-Gas since July 1997 and prior was Vice President-Human Resources of NSP.

Tom Petillo, 58, President — Delivery, Xcel Energy, March 2001 to present. Previously, President — Delivery, Xcel Energy from August 2000 to March 2001, Executive Vice President of New Century Services from 1998 to August 2000 and President and Director of New Century International from 1997 to 1998.

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

Patricia K. Vincent, 44, President — Retail, Xcel Energy, March 2001 to present. Previously, Vice President of Marketing and Sales of Xcel Energy from August 2000 to March 2001, Vice President of Marketing & Sales of NCE from January 1999 to August 2000 and Manager, Director and Vice President of Marketing and Sales at Arizona Public Service Company from 1992 to January 1999.

David M. Wilks, 56, President — Energy Supply, Xcel Energy, August 2000 to present. Previously, Executive Vice President and Director of PSCo and New Century Services from 1997 to August 2000 and President, Chief Operating Officer and Director of SPS from 1995 to August 2000.

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Item 2. Properties

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

Electric utility generating stations:
NSP — Minnesota

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